The information in this prospectus is not complete and may be changed. We may
not sell these securities until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell these securities and it is not soliciting an offer to buy these
securities in any state where the offer or sale is not permitted.




                                                 PROSPECTUS DATED SEPTEMBER 13, 2004

                                                ATLAS AMERICA PUBLIC #14-2004 PROGRAM

     Up to 11,875 Investor General Partner Units and 11,875 converted Limited Partner Units and up to 625 Limited
                 Partner Units, which are collectively referred to as the "Units," at $10,000 per Unit
                                $2 Million (200 Units) Minimum Aggregate Subscriptions
                              $125 Million (12,500 Units) Maximum Aggregate Subscriptions

Atlas America Public #14-2004 Program is a series        The Offering: In addition to the information in the table below
of up to three limited partnerships which will           for not less than 95% (11,875) of the units, up to 5% (625) of the
drill primarily natural gas development wells.           units, in the aggregate, may be sold at $8,950 per unit to the
See "Terms of the Offering -- Subscription               managing general partner, its officers, directors and affiliates,
to a Partnership," beginning on page 31                  and investors who buy units through the officers and directors of
for a detailed description of the offering               the managing general partner; or at $9,300 per unit to registered
of these limited partnerships. They will be              investment advisors and their clients, and selling agents and
managed by Atlas Resources, Inc. of Pittsburgh,          their registered representatives and principals. These discounted
Pennsylvania.                                            prices reflect certain fees, sales commissions and reimbursements
If you invest in a partnership, then you will not        which will not be paid for these sales. (See "Plan of
have any interest in any of the other partnerships       Distribution.") To the extent that units are sold at discounted
unless you also make a separate investment in the        prices, a partnership's subscription proceeds will be reduced.
other partnerships.                                      (See "Risk Factors - Risks Related to an Investment In a
The units will be offered on a "best efforts"            Partnership - Spreading the Risks of Drilling Among a Number of
"minimum-maximum" basis. This means the                  Wells Will be Reduced if Less than the Maximum Subscription
broker/dealers must sell at least 200 units and          Proceeds are Received and Fewer Wells are Drilled.")
receive subscription proceeds of at least $2
million in order for a partnership to close, and                                                   Total          Total
they must use only their best efforts to sell the                                  Per Unit       Minimum        Maximum
remaining units in the partnership.                                                --------       -------        -------
Subscription proceeds for each partnership will be       Public Price              $ 10,000     $2,000,000    $125,000,000
held in an interest bearing escrow account until $2
million has been received. The offering of the           Dealer-manager fee,
partnership designated Atlas America Public                sales commissions,
#14-2004 L.P. will not extend beyond December 31,          accountable
2004, and the offering of any partnership                  reimbursements for
designated Atlas America #14-2005(___) L.P. will           permissible non-cash
not extend beyond December 31, 2005. If the minimum        compensation, and
subscription proceeds are not received by a                accountable due
partnership's offering termination date, then your         diligence
subscription will be promptly returned to you from         reimbursements (1)      $  1,050     $  210,000    $ 13,125,000
the escrow account with interest and without
deduction for any fees.                                  Proceeds to partnership   $ 10,000     $2,000,000    $125,000,000

                                                         --------
                                                         (1) These fees, sales commissions and reimbursements will be paid by
                                                             the managing general partner as a part of its capital
                                                             contribution and not from subscription proceeds.

o   A partnership's drilling operations involve the possibility of a substantial
    or partial loss of your investment because of wells which are productive,
    but do not produce enough revenue to return the investment made and dry
    holes.
o   A partnership's revenues are directly related to the ability to market the
    natural gas and natural gas and oil prices, which are volatile and
    uncertain. If natural gas and oil prices decrease, then your investment
    return will decrease.
o   Unlimited joint and several liability for partnership obligations if you
    choose to invest as an investor general partner until you are converted to a
    limited partner.
o   Lack of liquidity or a market for the units.
o   Lack of conflict of interest resolution procedures.
o   Total reliance on the managing general partner and its affiliates.
o   Authorization of substantial fees to the managing general partner and its
    affiliates.
o   You and the managing general partner will share in costs disproportionately
    to your sharing of revenues.
o   Possible allocation of taxable income to you in excess of your cash
    distributions from your partnership.
o   No guaranty of cash distributions every quarter.

THESE SECURITIES ARE SPECULATIVE AND ARE SUBJECT TO CERTAIN RISKS. YOU SHOULD
PURCHASE THESE SECURITIES ONLY IF YOU CAN AFFORD A COMPLETE LOSS OF YOUR
INVESTMENT. (SEE "RISK FACTORS," PAGE 8.)

Neither the SEC nor any state securities commission has approved or disapproved
of these securities or determined if this prospectus is truthful or complete.
Any representation to the contrary is a criminal offense.

                    ANTHEM SECURITIES, INC. - DEALER-MANAGER
       BRYAN FUNDING, INC. - DEALER-MANAGER IN MINNESOTA AND NEW HAMPSHIRE




                                TABLE OF CONTENTS



SUMMARY OF THE OFFERING....................................................1
    Business of the Partnerships and the Managing General
       Partner ............................................................1
    Risk Factors...........................................................1
    Terms of the Offering..................................................2
    Description of Units...................................................3
       Investor General Partner Units......................................3
       Limited Partner Units...............................................4
    Use of Proceeds........................................................5
    Subordination, Participation in Costs and Revenues, and
       Distributions ......................................................5
    Compensation...........................................................7

RISK FACTORS...............................................................8
    Risks Related To The Partnerships' Oil and Gas
       Operations .........................................................8
       No Guarantee of Return of Investment or Rate of
          Return on Investment Because of Speculative
          Nature of Drilling Natural Gas and Oil Wells.....................8
       Because Some Wells May Not Return Their Drilling
          and Completion Costs, It May Take Many Years
          to Return Your Investment in Cash, If Ever.......................8
       Nonproductive Wells May be Drilled Even Though
          the Partnerships' Operations are Primarily Limited
          to Development Drilling..........................................8
       Partnership Distributions May be Reduced if There is
          a Decrease in the Price of Natural Gas and Oil ..................8
       Adverse Events in Marketing a Partnership's Natural
          Gas Could Reduce Partnership Distributions ......................9
       Possible Leasehold Defects..........................................9
       Transfer of the Leases Will Not Be Made Until Well
          is Completed ...................................................10
       Participation with Third-Parties in Drilling Wells
          May Require the Partnerships to Pay Additional
          Costs ..........................................................10
    Risks Related to an Investment In a Partnership.......................10
       If You Choose to Invest as a General Partner, Then
          You Have Greater Risk Than a Limited Partner ...................10
       The Managing General Partner May Not
          Meet Its Capital Contributions, Indemnification
          and Purchase Obligations If Its Liquid Net Worth
          Is Not Sufficient...............................................11
       An Investment in a Partnership Must be for the
          Long-Term Because the Units Are Illiquid and Not
          Readily Transferable............................................11
       Spreading the Risks of Drilling Among a Number of
          Wells Will be Reduced if Less than the Maximum
          Subscription Proceeds are Received and Fewer
          Wells are Drilled ..............................................12
       The Partnerships Do Not Own Any Prospects, the
          Managing General Partner Has Complete
          Discretion to Select Which Prospects Are
          Acquired By a Partnership, and The Possible Lack
          of Information for a Majority of the Prospects
          Decreases Your Ability to Evaluate the Feasibility
          of a Partnership ...............................................12
       Drilling Prospects in One Area May Increase Risk ..................13
       Lack of Production Information Increases Your Risk
          and Decreases Your Ability to Evaluate the
          Feasibility of a Partnership's Drilling Program ................13
       The Partnerships Composing This Program and
          Other Partnerships Sponsored by the Managing
          General Partner May Compete With Each Other
          for Prospects, Equipment, Contractors, and
          Personnel ......................................................13








       Managing General Partner's Subordination is Not
          a Guarantee of the Return of Any of Your
          Investment .....................................................13
       Borrowings by the Managing General Partner
          Could Reduce Funds Available for Its
          Subordination Obligation........................................14
       Compensation and Fees to the Managing General
          Partner Regardless of Success of a
          Partnership's Activities Will Reduce Cash
          Distributions...................................................14
       The Intended Quarterly Distributions to Investors
          May be Reduced or Delayed ......................................14
       There Are Conflicts of Interest Between the
          Managing General Partner and the Investors .....................14
       The Presentment Obligation May Not Be Funded
          and the Presentment Price May Not Reflect
          Full Value .....................................................15
       The Managing General Partner May Not Devote
          the Necessary Time to the Partnerships
          Because Its Management Obligations Are Not
          Exclusive.......................................................16
       Prepaying Subscription Proceeds to the Managing
          General Partner May Expose the Subscription
          Proceeds to Claims of the Managing General
          Partner's Creditors ............................................16
       Lack of Independent Underwriter May Reduce
          Due Diligence Investigation of the
          Partnerships and the Managing General
          Partner.........................................................16
       A Lengthy Offering Period May Result in Delays
          in the Investment of Your Subscription and
          Any Cash Distributions From the Partnership
          to You..........................................................16
    Tax Risks.............................................................16
       Changes in the Law May Reduce to Some Degree
          Your Tax Benefits From an Investment in a
          Partnership ....................................................16
       You May Owe Taxes in Excess of Your Cash
          Distributions from a Partnership ...............................16
       Your Deduction for Intangible Drilling Costs May
          Be Limited for Purposes of the Alternative
          Minimum Tax ....................................................17
       Investment Interest Deductions of Investor
          General Partners May Be Limited.................................17
       Lack of Tax Shelter Registration Could Result in
          Penalties to You ...............................................17

ADDITIONAL INFORMATION....................................................17

FORWARD LOOKING STATEMENTS AND
ASSOCIATED RISKS..........................................................17

INVESTMENT OBJECTIVES.....................................................18

ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS ....................................19

CAPITALIZATION AND SOURCE OF FUNDS
AND USE OF PROCEEDS.......................................................21
    Source of Funds.......................................................21
    Use of Proceeds.......................................................22

COMPENSATION..............................................................25
    Natural Gas and Oil Revenues..........................................25
    Lease Costs...........................................................26
    Drilling Contracts....................................................26
    Per Well Charges......................................................28




                                       ii


                                TABLE OF CONTENTS


    Gathering Fees........................................................28

    Dealer-Manager Fees...................................................30
    Interest and Other Compensation.......................................30
    Estimate of Administrative Costs and Direct Costs to be
       Borne by the Partnerships .........................................30

TERMS OF THE OFFERING.....................................................31
    Subscription to a Partnership.........................................31
    Partnership Closings and Escrow.......................................32
    Acceptance of Subscriptions...........................................33
    Activation of the Partnerships........................................34
    Suitability Standards.................................................34
       In General.........................................................34
       General Suitability Requirements for Purchasers of
          Limited Partner Units ..........................................34

       Special Suitability Requirements for Purchasers of
          Limited Partner Units in California, Michigan,
          New Hampshire, New Jersey and North Carolina....................35

       General Suitability Requirements for Purchasers of
          Investor General Partner Units .................................36

       Special Suitability Requirements for Purchasers of
          Investor General Partner Units in either: (i)
          Alabama, Arkansas, Maine, Massachusetts,
          Minnesota, North Carolina, Ohio, Oklahoma,
          Pennsylvania, Tennessee, Texas, or Washington;
          or (ii) Arizona, Indiana, Iowa, Kansas, Kentucky,
          Michigan, Mississippi, Missouri, New Mexico,
          Oregon, South Dakota, or Vermont .............................. 37

       Special Suitability Requirements for Purchasers of
          Investor General Partner Units in
          California, New Hampshire or New Jersey ........................38

       Fiduciary Accounts and Confirmations...............................38

PRIOR ACTIVITIES..........................................................39

MANAGEMENT................................................................49
    Managing General Partner and Operator.................................49
    Officers, Directors and Other Key Personnel...........................50
    Atlas America, Inc., a Delaware Holding Company.......................53
    Organizational Diagram and Security Ownership of
       Beneficial Owners .................................................54
    Remuneration..........................................................55
    Code of Business Conduct and Ethics...................................55
    Transactions with Management and Affiliates...........................55

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION, RESULTS OF OPERATIONS,
LIQUIDITY AND CAPITAL RESOURCES ..........................................55

PROPOSED ACTIVITIES.......................................................57
    Overview of Drilling Activities.......................................57
    Primary Areas of Operations...........................................58
       Mississippian/Upper Devonian Sandstone
          Reservoirs, Fayette County, Pennsylvania........................59
       Clinton/Medina Geological Formation in Western
          Pennsylvania ...................................................59
       Upper Devonian Sandstone Reservoirs, Armstrong
          County, Pennsylvania ...........................................60
       Upper Devonian Sandstone Reservoirs in McKean
          County, Pennsylvania .......................................... 60
    Secondary Areas of Operations.........................................61
       Clinton/Medina Geological Formation
          in Western New York.............................................61
       Clinton/Medina Geological Formation
          in Southern Ohio................................................61








    Acquisition of Leases.................................................61

       Deep Drilling Rights Retained by Managing
          General Partner ................................................63
    Interests of Parties..................................................63
    Primary Areas.........................................................64
       Clinton/Medina Geological Formation
          in Western Pennsylvania and
          Mississippian/Upper Devonian Sandstone
          Reservoirs in Fayette and Greene Counties,
          Pennsylvania and Upper Devonian Sandstone
          Reservoirs in McKean County, Pennsylvania ......................64
       Upper Devonian Sandstone Reservoirs in
          Armstrong County, Pennsylvania .................................64
    Secondary Areas.......................................................64
    Title to Properties...................................................65
    Drilling and Completion Activities; Operation
       of Producing Wells.................................................65
    Sale of Natural Gas and Oil Production................................66
       Policy of Treating All Wells Equally in a
          Geographic Area.................................................66
       Gathering of Natural Gas...........................................67
       Natural Gas Contracts..............................................67
    Marketing of Natural Gas Production from Wells in
       Other Areas of the United States ..................................69
    Crude Oil.............................................................70
    Insurance.............................................................70
    Use of Consultants and Subcontractors.................................70

COMPETITION, MARKETS AND REGULATION.......................................70
    Natural Gas Regulation................................................70
    Crude Oil Regulation..................................................71
    Competition and Markets...............................................71
    State Regulations.....................................................73
    Environmental Regulation..............................................73
    Proposed Regulation...................................................74

PARTICIPATION IN COSTS AND REVENUES.......................................74
    In General............................................................74
    Costs.................................................................74
    Revenues..............................................................76
    Subordination of Portion of Managing General
       Partner's Net Revenue Share........................................77
    Table of Participation in Costs and Revenues..........................78
    Allocation and Adjustment Among Investors.............................79

    Distributions.........................................................79

    Liquidation...........................................................80

CONFLICTS OF INTEREST.....................................................80
    In General............................................................80

    Conflicts Regarding Transactions with the Managing
       General Partner and its Affiliates ................................81

    Conflict Regarding the Drilling and Operating
       Agreement..........................................................81
    Conflicts Regarding Sharing of Costs and Revenues ....................81

    Conflicts Regarding Tax Matters Partner...............................82

    Conflicts Regarding Other Activities of the Managing
       General Partner, the Operator and Their Affiliates ................82

    Conflicts Involving the Acquisition of Leases.........................83
    Conflicts Between Investors and the Managing
       General Partner as an Investor ....................................87

    Lack of Independent Underwriter and Due Diligence
       Investigation .....................................................87

    Conflicts Concerning Legal Counsel....................................88
    Conflicts Regarding Presentment Feature...............................88
    Conflicts Regarding Managing General Partner
       Withdrawing an Interest ...........................................88




                                       iii

                                TABLE OF CONTENTS



    Conflicts Regarding Order of Pipeline Construction and
       Gathering Fees ....................................................88

    Procedures to Reduce Conflicts of Interest............................89
    Policy Regarding Roll-Ups.............................................90

FIDUCIARY RESPONSIBILITY OF THE
MANAGING GENERAL PARTNER..................................................91
    In General............................................................91
    Limitations on Managing General Partner Liability as
       Fiduciary .........................................................92

MATERIAL FEDERAL INCOME TAX CONSEQUENCES..................................92
    Summary of Tax Opinion................................................92
    Summary Discussion of the Material Federal Income
       Tax Consequences of an Investment in a Partnership ................95
    In General............................................................95

    Partnership Classification............................................96
    Limitations on Passive Activities.....................................96

       Publicly Traded Partnership Rules..................................96

       Conversion from Investor General Partner to Limited
          Partner.........................................................97
    Taxable Year and Method of Accounting.................................97

    2004 and 2005 Expenditures............................................97
    Availability of Certain Deductions....................................97

    Intangible Drilling Costs.............................................98

    Drilling Contracts....................................................98
    Depletion Allowance..................................................100

    Depreciation - Modified Accelerated Cost Recovery
       System ("MACRS")..................................................101

    Lease Acquisition Costs and Abandonment..............................101
    Tax Basis of Units...................................................101
    "At Risk" Limitation for Losses......................................101
    Distributions from a Partnership.....................................102
    Sale of the Properties...............................................102
    Disposition of Units.................................................102
    Alternative Minimum Tax..............................................103
    Limitations on Deduction of Investment Interest......................104

    Allocations..........................................................106

    Partnership Borrowings...............................................106
    Partnership Organization and Offering Costs..........................106
    Tax Elections........................................................106

    Termination of a Partnership.........................................107

    Lack of Registration as a Tax Shelter................................107
       Investor Lists....................................................107

    Tax Returns and IRS Audits...........................................108
       In General........................................................108
       Tax Returns.......................................................108
    Penalties and Interest...............................................108
       In General........................................................108

       Penalty for Negligence or Disregard of Rules or
          Regulations....................................................108
       Valuation Misstatement Penalty....................................108

       Substantial Understatement Penalty................................109
       Profit Motive, IRS Anti-Abuse Rule and Judicial
          Doctrines .....................................................109

    State and Local Taxes................................................109

    Severance and Ad Valorem (Real Estate) Taxes.........................110
    Social Security Benefits and Self-Employment Tax.....................110
    Farmouts.............................................................110

    Foreign Partners.....................................................110
    Estate and Gift Taxation.............................................110

    Changes in the Law...................................................111

SUMMARY OF PARTNERSHIP AGREEMENT.........................................111
    Liability of Limited Partners........................................111







    Amendments...........................................................111

    Notice...............................................................111

    Voting Rights........................................................112

    Access to Records....................................................112

    Withdrawal of Managing General Partner...............................113
    Return of Subscription Proceeds if Funds Are Not
       Invested in Twelve Months ........................................113

SUMMARY OF DRILLING AND OPERATING AGREEMENT..............................113

REPORTS TO INVESTORS.....................................................114

PRESENTMENT FEATURE......................................................115

TRANSFERABILITY OF UNITS.................................................117
    Restrictions on Transfer Imposed by the Securities
       Laws, the Tax Laws and the Partnership
       Agreement.........................................................117

    Conditions to Becoming a Substitute Partner..........................117


PLAN OF DISTRIBUTION.....................................................118
    Commissions..........................................................118
    Indemnification......................................................121

SALES MATERIAL...........................................................121

LEGAL OPINIONS...........................................................122

EXPERTS..................................................................122

LITIGATION...............................................................122

FINANCIAL INFORMATION CONCERNING THE
    MANAGING GENERAL PARTNER AND ATLAS
    AMERICA PUBLIC #14-2004 L.P..........................................123

Exhibits

Appendix A      Information Regarding Currently
                Proposed Prospects for Atlas America
                Public #14-2004 L.P.

Exhibit (A)      Form of Amended and Restated Certificate
                 and Agreement of Limited Partnership for
                 Atlas America Public #14-2004 L.P. [Form
                 of Amended and Restated Certificate and
                 Agreement of Limited Partnership for
                 Atlas America Public #14-2005(_____)
                 L.P.]

Exhibit (I-A)    Form of Managing General Partner
                 Signature Page

Exhibit (I-B)    Form of Subscription Agreement

Exhibit (II)     Form of Drilling and Operating Agreement
                 for Atlas America Public #14-2004 L.P.
                 [Atlas America Public #14-2005(_____)
                 L.P.]

Exhibit (B)      Special Suitability Requirements and
                            Disclosures to Investors





                                       iv






                             SUMMARY OF THE OFFERING

This is a summary and does not include all of the information which may be
important to you. You should read the entire prospectus and the attached
exhibits and appendix before you decide to invest. Throughout this prospectus
when there is a reference to you it is a reference to you as a potential
investor or participant in a partnership.

BUSINESS OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER
Atlas America Public #14-2004 Program, which is sometimes referred to in this
prospectus as the "program," consists of up to three Delaware limited
partnerships. These limited partnerships are sometimes referred to in this
prospectus in the singular as a "partnership" or in the plural as the
"partnerships." Units of the various partnerships will be offered and sold in a
series during a portion of 2004 and 2005. See "Terms of the Offering" for a
discussion of the terms and conditions involved in making an investment in a
partnership.

Each of the program's partnerships will be a separate business entity from the
other partnerships. A limited partnership agreement will govern the rights and
obligations of the partners of each partnership. A form of the limited
partnership agreement is attached to this prospectus as Exhibit (A). For a
summary of the material provisions of the limited partnership agreement which
are not covered elsewhere in this prospectus see "Summary of Partnership
Agreement." You will be a partner only in the partnership in which you invest.
You will have no interest in the business, assets or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the partnership in which you invest.

The offering proceeds of each partnership will be used to drill primarily
natural gas development wells in the Appalachian Basin located in western
Pennsylvania, eastern and southern Ohio and western New York as described in
"Proposed Activities." A development well means a well drilled within the proved
area of a natural gas or oil reservoir to the depth of a stratigraphic horizon
known to be productive. Currently, the partnerships do not hold any interests in
any properties or prospects on which the wells will be drilled.

The managing general partner of each partnership is or will be Atlas Resources,
Inc., a Pennsylvania corporation, which was incorporated in 1979, and is
sometimes referred to in this prospectus as "Atlas Resources." As set forth in
"Prior Activities," the managing general partner has sponsored and serves as
managing general partner of 34 private drilling partnerships which raised a
total of $195,300,802, and 12 public drilling partnerships which raised a total
of $167,610,898. Atlas Resources also will serve as each partnership's general
drilling contractor and operator and supervise the drilling, completing and
operating of the wells to be drilled. As of March 1, 2004, the managing general
partner and its affiliates operated approximately 4,653 natural gas and oil
wells located in Ohio, Pennsylvania and New York.

The address and telephone number of the partnerships and the managing general
partner are 311 Rouser Road, Moon Township, Pennsylvania 15108, (412) 262-2830.

RISK FACTORS
This offering involves numerous risks, including risks related to each
partnership's oil and gas operations, risks related to a partnership investment,
and tax risks. You should carefully consider a number of significant risk
factors inherent in and affecting the business of a partnership and this
offering, including the following.

         o        Each partnership's drilling operations involve the possibility
                  of a substantial or partial loss of your investment because of
                  wells which are productive, but do not produce enough revenue
                  to return the investment made and from time to time dry holes.

         o        Each partnership's revenues are directly related to the
                  ability to market the natural gas and natural gas and oil
                  prices, which are volatile and uncertain, and if natural gas
                  and oil prices decrease then your investment return will
                  decrease.

                                       1

         o        Unlimited joint and several liability for partnership
                  obligations if you choose to invest as an investor general
                  partner until you are converted to a limited partner.

         o        Lack of liquidity or a market for the units, necessitating a
                  long-term commitment.

         o        Total reliance on the managing general partner and its
                  affiliates.

         o        Authorization of substantial fees to the managing general
                  partner and its affiliates.

         o        Possible allocation of taxable income to investors in excess
                  of their cash distributions from a partnership.

         o        Each partnership must receive minimum subscriptions of $2
                  million to close, and the subscription proceeds of all
                  partnerships, in the aggregate, may not exceed $125 million.
                  There are no other requirements regarding the size of a
                  partnership, and the subscription proceeds of one partnership
                  may be substantially more or less than the subscription
                  proceeds of the other partnerships. If only the minimum
                  subscriptions are received in a partnership, the partnership's
                  ability to spread the risks of drilling will be greatly
                  reduced as described in "Compensation - Drilling Contracts."

         o        Certain conflicts of interest between the managing general
                  partner and you and the other investors and lack of procedures
                  to resolve the conflicts.

         o        You and the other investors and the managing general partner
                  will share in costs disproportionately to the sharing of
                  revenues.

         o        Currently, the partnerships do not hold any interests in any
                  properties or prospects on which the wells will be drilled.
                  Although the managing general partner has absolute discretion
                  in determining which properties or prospects will be drilled
                  by a partnership, the managing general partner intends that
                  Atlas America Public #14-2004 L.P., which must close on or
                  before December 31, 2004, will drill the prospects described
                  in "Appendix A - Information Regarding Currently Proposed
                  Prospects for Atlas America Public #14-2004 L.P." These
                  prospects represent a portion of the wells to be drilled if
                  the nonbinding targeted subscription proceeds described in
                  "Terms of the Offering - Subscription to a Partnership" are
                  received. If there are adverse events with respect to any of
                  the currently proposed prospects, the managing general partner
                  will substitute the partnership's prospects. The managing
                  general partner also anticipates that it will designate a
                  portion of the prospects in each partnership designated Atlas
                  America Public #14-2005(_____) L.P. by a supplement or an
                  amendment to the registration statement of which this
                  prospectus is a part.

         o        In each partnership the managing general partner may
                  subordinate a portion of its share of that partnership's net
                  production revenues. This subordination is not a guaranty by
                  the managing general partner, and if the wells in that
                  partnership produce small volumes of natural gas and oil
                  and/or natural gas and oil prices decrease, then even with
                  subordination your cash flow from the partnership may not
                  return your entire investment.

         o        In each partnership quarterly cash distributions to investors
                  may be deferred if revenues are used for partnership
                  operations or reserves.

TERMS OF THE OFFERING
The offering period will begin on the date of this prospectus. Each partnership
will offer a minimum of 200 units, which is $2 million, and all partnerships, in
the aggregate, will offer a maximum of 12,500 units which is $125 million. The
maximum subscription proceeds for each partnership will be the lesser of:

                                       2

         o        the registered amount of $125 million; or

         o        the number of units which remain unsold from the $125 million
                  aggregate registration.

The targeted subscription proceeds and closing date for each partnership, which
are not binding on the managing general partner, are set forth in a table in
"Terms of the Offering - Subscription to a Partnership."

Units are offered at a subscription price of $10,000 per unit, provided that up
to 5% of the units sold, in the aggregate, may be sold to certain investors at
discounts as described in "Plan of Distribution." All subscriptions must be paid
100% in cash at the time of subscribing. Your minimum subscription in a
partnership is one unit; however, the managing general partner, in its
discretion, may accept one-half unit subscriptions from you at any time. Larger
fractional subscriptions will be accepted in $1,000 increments, beginning, for
example, with either $11,000, $12,000, etc. if you pay $10,000 for a full unit,
or $6,000, $7,000, etc. if you pay $5,000 for a one-half unit.

You will have the election to purchase units as either an investor general
partner or a limited partner as described in "- Description of Units," below.
Under the partnership agreement no investor, including investor general
partners, may participate in the management of a partnership's business. The
managing general partner will have exclusive management authority for the
partnerships.

Subscription proceeds for a partnership will be held in a separate interest
bearing escrow account at National City Bank of Pennsylvania until receipt of
the minimum subscription proceeds. Each partnership is or will be formed as a
limited partnership under the Delaware Revised Uniform Limited Partnership Act
before breaking escrow. In addition, a partnership may not break escrow as
described in "Terms of the Offering - Partnership Closings and Escrow," unless
the partnership is in receipt of the minimum subscription proceeds after the
discounts described in "Plan of Distribution" and excluding any subscriptions by
the managing general partner or its affiliates. However, on receipt of the
minimum subscription proceeds, the managing general partner on behalf of a
partnership may break escrow, transfer the escrowed funds to a partnership
account, and begin its activities, including drilling to the extent the
prospects have been identified in this prospectus or by a supplement or an
amendment to the registration statement. After breaking escrow additional
subscription proceeds may be paid directly to the partnership account for that
partnership and will continue to earn interest until the offering closes. (See
"Terms of the Offering.")

DESCRIPTION OF UNITS
In the partnership being offered at the time you subscribe you may buy either:

         o        investor general partner units; or

         o        limited partner units.

The first partnership, Atlas America Public #14-2004 L.P., has been formed as a
Delaware limited partnership. However, the other partnerships have not yet been
formed. The units offered in those partnerships in 2005 may be preformation
investor general partner interests and preformation limited partner interests
which will become units of investor general partner interests or limited partner
interests, respectively, in the particular partnership if it has not been formed
at the time you subscribe.

The type of unit you buy will not affect the allocation of costs, revenues, and
cash distributions among you and the other investors. There are, however,
material differences in the federal income tax effects and liability associated
with each type of unit.

INVESTOR GENERAL PARTNER UNITS.

         o        TAX EFFECT. If you invest in a partnership as an investor
                  general partner, then your share of the partnership's
                  deduction for intangible drilling costs will not be subject to
                  the passive activity limitation on losses because your
                  investor general partner units will not be converted to
                  limited partner units until after all the wells have been
                  drilled and completed. For example, if you pay $10,000 for a
                  unit, then generally you may deduct approximately 90% of your
                  subscription, $9,000, in the year in which you invest, which
                  includes your deduction for intangible drilling costs for all
                  of the wells to be drilled by the partnership. (See "Material
                  Federal Income Tax Consequences - Limitations on Passive
                  Activities.")

                                       3

                  o        Intangible drilling costs generally means those costs
                           of drilling and completing a well that are currently
                           deductible, as compared to lease costs which must be
                           recovered through the depletion allowance and costs
                           for equipment in the well which must be recovered
                           through depreciation deductions.

         o        LIABILITY. If you invest in a partnership as an investor
                  general partner, then you will have unlimited liability
                  regarding the partnership's activities. This means if:

                  o        the insurance proceeds;

                  o        the managing general partner's indemnification; and

                  o        the partnership's assets

                  were not sufficient to satisfy a partnership liability for
                  which you and the other investor general partners were also
                  liable, then the managing general partner would require you
                  and the other investor general partners to make additional
                  capital contributions to the partnership to satisfy the
                  liability. In addition, you and the other investor general
                  partners have joint and several liability, which means
                  generally that a person with a claim against the partnership
                  may sue all or any one or more of the partnership's general
                  partners, including you, for the entire amount of the
                  liability. (See "Actions To Be Taken By Managing General
                  Partner To Reduce Risks of Additional Payments by Investor
                  General Partners" and "Proposed Activities - Insurance.")

         Although past performance is no guarantee of future results, the
         investor general partners in the managing general partner's prior
         partnerships have not had to make additional capital contributions to
         their partnerships because of their status as investor general
         partners.

         Your investor general partner units in a partnership will be
         automatically converted by the managing general partner to limited
         partner units after all of the partnership wells have been drilled and
         completed. The conversion will not create any tax liability to you or
         the other investors.

         Once your units are converted you will have the lesser liability of a
         limited partner under Delaware law for obligations and liabilities
         arising after the conversion. However, you will continue to have the
         responsibilities of a general partner for partnership liabilities and
         obligations incurred before the effective date of the conversion. For
         example, you might become liable for partnership liabilities in excess
         of your subscription during the time the partnership is engaged in
         drilling activities and for environmental claims that arose during
         drilling activities, but were not discovered until after conversion.

LIMITED PARTNER UNITS.

         o        TAX EFFECT. If you invest in a partnership as a limited
                  partner, then the use of your share of the partnership's
                  deduction for intangible drilling costs will be limited to net
                  passive income from "passive" trade or business activities.
                  Passive trade or business activities generally include the
                  partnership and other limited partner investments, but passive
                  income does not include dividends and interest. This means
                  that you will not be able to deduct your share of the
                  partnership's intangible drilling costs in the year in which
                  you invest unless you have passive income from investments
                  other than the partnership. (See "Material Federal Income Tax
                  Consequences - Limitations on Passive Activities.")

                                       4

         o        LIABILITY. If you invest in a partnership as a limited
                  partner, then you will have limited liability. This means you
                  will not be liable for amounts beyond your initial investment
                  and share of undistributed net profits, subject to certain
                  exceptions set forth in "Summary of Partnership Agreement -
                  Liability of Limited Partners."

USE OF PROCEEDS
Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of all partnerships, in the aggregate, may
not exceed $125 million. The subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other
partnerships. The subscription proceeds of each partnership, regardless of
whether the number of units sold to you and the other investors in a partnership
is the minimum or up to the maximum, will be used to pay:

         o        100% of the intangible drilling costs, which is defined above
                  in "- Description of Units"; and

         o        34% of the equipment costs of drilling and completing the
                  partnership's wells, but not to exceed 10% of the
                  partnership's subscription proceeds.

The managing general partner will contribute all of the leases to each
partnership covering the acreage on which each partnership's wells will be
drilled and pay:

         o        66% of the equipment costs of drilling and completing the
                  partnership's wells; and

         o        any equipment costs that exceed 10% of the partnership's
                  subscription proceeds that would otherwise be charged to you
                  and the other investors.

The managing general partner also will be charged with 100% of the organization
and offering costs for each partnership. A portion of these contributions to
each partnership will be in the form of payments to itself, its affiliates and
third-parties and the remainder will be in the form of services related to
organizing this offering. The managing general partner will receive a credit
towards its required capital contribution to each partnership for these payments
and services as discussed in "Participation in Costs and Revenues."

(See "Capitalization and Source of Funds and Use of Proceeds" and "Material
Federal Income Tax Consequences - Intangible Drilling Costs.")

SUBORDINATION, PARTICIPATION IN COSTS AND REVENUES, AND DISTRIBUTIONS
Each partnership will be a separate business entity from the other partnerships,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest. Each partnership is
structured to provide you and the other investors with cash distributions equal
to a minimum of 10% per unit, based on $10,000 per unit regardless of the actual
subscription price for your units, in each of the first five 12-month periods
beginning with the partnership's first cash distributions from operations. To
help achieve this investment feature the managing general partner will
subordinate up to 50% of its share of partnership net production revenues during
this subordination period.

                                       5

Each partnership's 60-month subordination period will begin with the
partnership's first cash distribution from operations to you and the other
investors. However, no subordination distributions to you and the other
investors will be required until the partnership's first cash distribution after
substantially all of the partnership wells have been drilled, completed, and
begun producing into a sales line. Subordination distributions will be
determined by debiting or crediting current period partnership revenues to the
managing general partner as may be necessary to provide the distributions to you
and the other investors. At any time during the subordination period, but not
after, the managing general partner is entitled to an additional share of
partnership revenues to recoup previous subordination distributions to the
extent your cash distributions from the partnership exceed the 10% return of
capital described above. The specific formula is set forth in Section
5.01(b)(4)(a) of the partnership agreement.

The following table sets forth the partnership costs and revenues charged and
credited between the managing general partner and you and the other investors
for each partnership after deducting from the partnership's gross revenues the
landowner royalties and any other lease burdens.



                                                                                 MANAGING
                                                                                 GENERAL
                                                                                 PARTNER             INVESTORS
PARTNERSHIP COSTS                                                                --------            ---------

Organization and offering costs.....................................................100%                   0%
Lease costs.........................................................................100%                   0%
Intangible drilling costs.............................................................0%                 100%
Equipment costs (1)..................................................................66%                  34%
Operating costs, administrative costs, direct costs, and all
     other costs.....................................................................(2)                  (2)

PARTNERSHIP REVENUES
Interest income......................................................................(3)                  (3)
Equipment proceeds (1)...............................................................66%                  34%
All other revenues including production revenues..................................(4)(5)               (4)(5)


- ----------------
(1)    These percentages may vary. If the total equipment costs for all of a
       partnership's wells that would be charged to you and the other investors
       exceeds an amount equal to 10% of the subscription proceeds of you and
       the other investors in the partnership, then the excess will be charged
       to the managing general partner. Equipment proceeds, if any, will be
       credited in the same percentage in which the equipment costs were
       charged.
(2)    These costs will be charged to the parties in the same ratio as the
       related production revenues are being credited. These costs also include
       the plugging and abandonment costs of the wells as described in
       "Participation in Costs and Revenues."
(3)    Interest earned on your subscription proceeds before the final closing of
       the partnership to which you subscribed will be credited to your account
       and paid not later than the partnership's first cash distributions from
       operations. After each closing of a partnership and until the
       subscription proceeds from the closing are invested in the partnership's
       natural gas and oil operations any interest income from temporary
       investments will be allocated pro rata to the investors providing the
       subscription proceeds. All other interest income, including interest
       earned on the deposit of operating revenues, will be credited as natural
       gas and oil production revenues are credited.
(4)    The managing general partner and the investors in a partnership will
       share in all of that partnership's other revenues in the same percentage
       as their respective capital contributions bears to the total partnership
       capital contributions except that the managing general partner will
       receive an additional 7% of the partnership revenues. However, the
       managing general partner's total revenue share may not exceed 35% of
       partnership revenues.
(5)    The actual allocation of partnership revenues between the managing
       general partner and the investors will vary from the allocation described
       in (4) above if a portion of the managing general partner's partnership
       net production revenues is subordinated as described above.

                                       6

The managing general partner will review a partnership's accounts at least
quarterly to determine whether cash distributions are appropriate and the amount
to be distributed, if any. The partnership in which you invest will distribute
funds to you and the other investors that the managing general partner does not
believe are necessary for the partnership to retain. (See "Participation in
Costs and Revenues.")

COMPENSATION
The items of compensation paid to the managing general partner and its
affiliates from each partnership are as follows:

         o        The managing general partner will receive a share of each
                  partnership's revenues. The managing general partner's revenue
                  share will be in the same percentage as its capital
                  contribution bears to that partnership's total capital
                  contributions plus an additional 7% of partnership revenues,
                  but not to exceed a total of 35% of partnership revenues,
                  regardless of the amount of the managing general partner's
                  capital contribution, subject to the managing general
                  partner's subordination obligation.

         o        The managing general partner will receive a credit to its
                  capital account equal to the cost of the leases or the fair
                  market value of the leases if the managing general partner has
                  reason to believe that cost is materially more than the fair
                  market value.

         o        Each partnership will enter into the drilling and operating
                  agreement with the managing general partner to drill and
                  complete the partnership wells at cost plus 15%. The cost of
                  the well includes reimbursement from the investors to the
                  managing general partner of its general and administrative
                  overhead which cannot exceed $12,781 per well.

         o        When the wells for a partnership begin producing the managing
                  general partner, as operator of the wells, will receive:

                  o        reimbursement at actual cost for all direct expenses
                           incurred on behalf of the partnership; and

                  o        well supervision fees for operating and maintaining
                           the wells during producing operations at a
                           competitive rate.

         o        The managing general partner will receive gathering fees at
                  competitive rates.

         o        Subject to certain exceptions described in "Plan of
                  Distribution," Anthem Securities, Inc., the dealer-manager and
                  an affiliate of the managing general partner, which is
                  sometimes referred to in this prospectus as "Anthem
                  Securities," will receive on each unit sold to an investor a
                  2.5% dealer-manager fee, a 7% sales commission, a .5%
                  accountable reimbursement for permissible non-cash
                  compensation, and up to a .5% reimbursement of the selling
                  agents' bona fide accountable due diligence expenses.

         o        The managing general partner or an affiliate will have the
                  right to charge a competitive rate of interest on any loan it
                  may make to or on behalf of a partnership. If the managing
                  general partner provides equipment, supplies, and other
                  services to a partnership, then it may do so at competitive
                  industry rates.

         o        The managing general partner and its affiliates will receive
                  an unaccountable, fixed payment reimbursement for their
                  administrative costs, which has been determined by the
                  managing general partner to be $75 per well per month. The
                  managing general partner may not increase this fee during the
                  term of the partnership.

(See "Compensation.")


                                       7

                                  RISK FACTORS

An investment in a partnership involves a high degree of risk and is suitable
only if you have substantial financial means and no need of liquidity in your
investment.

RISKS RELATED TO THE PARTNERSHIPS' OIL AND GAS OPERATIONS
NO GUARANTEE OF RETURN OF INVESTMENT OR RATE OF RETURN ON INVESTMENT BECAUSE OF
SPECULATIVE NATURE OF DRILLING NATURAL GAS AND OIL WELLS. Natural gas and oil
exploration is an inherently speculative activity. Before the drilling of a well
the managing general partner cannot predict with absolute certainty:

         o        the volume of natural gas and oil recoverable from the well;
                  or

         o        the time it will take to recover the natural gas and oil.

You may not recover all of your investment in a partnership, or if you do
recover your investment in a partnership you may not receive a rate of return on
your investment which is competitive with other types of investment. You will be
able to recover your investment only through the partnership's distributions of
the sales proceeds from the production of natural gas and oil from productive
wells. The quantity of natural gas and oil in a well, which is referred to as
its reserves, decreases over time as the natural gas and oil is produced until
the well is no longer economical to operate. All of these distributions to you
will be considered a return of capital until you have received 100% of your
investment. This means that you are not receiving a return on your investment in
a partnership, excluding tax benefits, until your total cash distributions from
the partnership exceed 100% of your investment. (See "Prior Activities.")

BECAUSE SOME WELLS MAY NOT RETURN THEIR DRILLING AND COMPLETION COSTS, IT MAY
TAKE MANY YEARS TO RETURN YOUR INVESTMENT IN CASH, IF EVER. Even if a well is
completed in a partnership and produces natural gas and oil in commercial
quantities, it may not produce enough natural gas and oil to pay for the costs
of drilling and completing the well, even if tax benefits are considered. For
example, the managing general partner has formed 46 partnerships since 1985,
however, 36 of the 46 partnerships have not yet returned to the investor 100% of
his capital contributions without taking tax savings into account. Thus, it may
take many years to return your investment in cash, if ever. (See "Prior
Activities.")

NONPRODUCTIVE WELLS MAY BE DRILLED EVEN THOUGH THE PARTNERSHIPS' OPERATIONS ARE
PRIMARILY LIMITED TO DEVELOPMENT DRILLING. Each partnership may drill some
development wells which are nonproductive, which is referred to as a "dry hole,"
and must be plugged and abandoned. If one or more of the partnership's wells are
nonproductive, then the partnership's productive wells may not produce enough
revenues to offset the loss of investment in the nonproductive wells. (See
"Prior Activities" and "Proposed Activities.")

PARTNERSHIP DISTRIBUTIONS MAY BE REDUCED IF THERE IS A DECREASE IN THE PRICE OF
NATURAL GAS AND OIL. The prices at which a partnership's natural gas and oil
will be sold are uncertain and as discussed in "- Adverse Events in Marketing a
Partnership's Natural Gas Could Reduce Partnership Distributions," the
partnerships are not guaranteed a specific natural gas price for the sale of
their natural gas production. Historically, natural gas and oil prices have been
volatile and will likely continue to be volatile in the future. Prices for
natural gas and oil will depend on supply and demand factors largely beyond the
control of the partnership. For example, the demand for natural gas is usually
greater in the winter months because of residential heating requirements than in
the summer months, and generally results in lower natural gas prices in the
summer months than in the winter months. See "Competition, Markets and
Regulation - Competition and Markets" for other factors affecting the supply and
demand of natural gas and oil. These factors make it extremely difficult to
predict natural gas and oil price movements with any certainty.

If natural gas and oil prices decrease in the future, then your partnership
distributions will decrease accordingly. Also, natural gas and oil prices may
decrease during the first years of production from your partnership's wells
which is when the wells typically achieve their greatest level of production.
This would have a greater adverse effect on your partnership distributions than
price decreases in later years when the wells have a lower level of production.
(See "Appendix A - Information Regarding Currently Proposed Prospects for Atlas
America Public #14-2004 L.P." for a discussion of flush production and "Proposed
Activities - Sale of Natural Gas and Oil Production.")

                                       8

ADVERSE EVENTS IN MARKETING A PARTNERSHIP'S NATURAL GAS COULD REDUCE PARTNERSHIP
DISTRIBUTIONS. In addition to the risk of decreased natural gas and oil prices
described above, there are risks associated with marketing natural gas which
could reduce a partnership's distributions to you and the other investors. These
risks are set forth below.

         o        Competition from other natural gas producers and marketers in
                  the Appalachian Basin as well as competition from alternative
                  energy sources may make it more difficult to market each
                  partnership's natural gas.


         o        The majority of each partnership's natural gas production will
                  be sold to a limited number of different natural gas
                  purchasers as described in "Proposed Activities - Sale of
                  Natural Gas and Oil Production." One of the natural gas
                  purchasers has a 10-year agreement, which began on April 11,
                  1999, to buy all of the managing general partner's and its
                  affiliates', which includes the partnerships, natural gas
                  production, subject to various exceptions. The most
                  significant exception from this agreement for the partnerships
                  is for natural gas produced from Fayette County, which is
                  where the managing general partner anticipates that the
                  majority of the prospects which will be drilled by each
                  partnership will be situated, and natural gas produced from
                  McKean County and Armstrong County. The majority, if not all,
                  of the natural gas produced from Fayette County will be sold
                  to one purchaser under a natural gas contract which ends March
                  31, 2006. These contracts, including the contracts for natural
                  gas in McKean County and Armstrong County, provide that the
                  price may be adjusted upward or downward in accordance with
                  the spot market price and market conditions as described in
                  "Proposed Activities - Sale of Natural Gas and Oil
                  Production." Thus, the partnerships will depend primarily on a
                  limited number of natural gas purchasers and will not be
                  guaranteed a specific natural gas price, other than through
                  hedging. The price for each partnership's natural gas may
                  decrease in the future because of market conditions. Also,
                  even though hedging provides the partnerships some protection
                  against falling natural gas prices, hedging also could reduce
                  the potential benefits of price increases if at the time the
                  natural gas is to be delivered the spot market natural gas
                  price is higher than the price paid under the hedging
                  arrangement.


         o        There is a credit risk associated with a natural gas
                  purchaser's ability to pay. Each partnership may not be paid
                  or may experience delays in receiving payment for natural gas
                  that has already been delivered. In accordance with industry
                  practice, a partnership typically will deliver natural gas to
                  a purchaser for a period of up to 60 to 90 days before it
                  receives payment. Thus, it is possible that the partnership
                  may not be paid for natural gas that already has been
                  delivered if the natural gas purchaser fails to pay for any
                  reason, including bankruptcy. This ongoing credit risk also
                  may delay or interrupt the sale of the partnership's natural
                  gas or its negotiation of different terms and arrangements for
                  selling its natural gas to other purchasers. Finally, this
                  credit risk may reduce the price benefit derived by the
                  partnerships from the managing general partner's natural gas
                  hedging as described in "Proposed Activities - Sale of Natural
                  Gas and Oil Production - Natural Gas Contracts," since the
                  majority of the managing general partner's natural gas hedges
                  are implemented through the natural gas purchasers.

         o        Partnership revenues may be less the farther the natural gas
                  is transported because of increased transportation costs.

         o        Production from wells drilled in certain areas, such as the
                  wells in Crawford County, Pennsylvania and to a lesser extent,
                  Fayette County, Pennsylvania, may be delayed until
                  construction of the necessary gathering lines and production
                  facilities is completed. (See "Proposed Activities - Sale of
                  Natural Gas and Oil Production.")

POSSIBLE LEASEHOLD DEFECTS. There may be defects in a partnership's title to its
leases. Although the managing general partner will obtain a favorable formal
title opinion for the leases before each well is drilled, it will not obtain a
division order title opinion after the well is completed. A partnership may
experience losses from title defects which arose during drilling that would have
been disclosed by a division order title opinion, such as liens that may arise
during drilling or transfers made after drilling begins. Also, the managing
general partner may use its own judgment in waiving title requirements and will
not be liable for any failure of title of leases transferred to the partnership.
(See "Proposed Activities - Title to Properties.")

                                       9

TRANSFER OF THE LEASES WILL NOT BE MADE UNTIL WELL IS COMPLETED. Because the
leases will not be transferred from the managing general partner to a
partnership until after the wells are drilled and completed, the transfer could
be set aside by a creditor of the managing general partner, or the trustee in
the event of the voluntary or involuntary bankruptcy of the managing general
partner, if it were determined that the managing general partner received less
than a reasonably equivalent value for the leases. In this event, the leases and
the wells would revert to the creditors or trustee, and the partnership would
either recover nothing or only the amount paid for the leases and the cost of
drilling the wells. Assigning the leases to a partnership after the wells are
drilled and completed, however, will not affect the availability of the tax
deductions for intangible drilling costs since the partnership will have an
economic interest in the wells under the drilling and operating agreement before
the wells are drilled. (See "Proposed Activities - Title to Properties.")

PARTICIPATION WITH THIRD-PARTIES IN DRILLING WELLS MAY REQUIRE THE PARTNERSHIPS
TO PAY ADDITIONAL COSTS. Third-parties will participate with each partnership in
drilling some of the wells. Financial risks exist when the cost of drilling,
equipping, completing, and operating wells is shared by more than one person. If
a partnership pays its share of the costs, but another interest owner does not
pay its share of the costs, then the partnership would have to pay the costs of
the defaulting party. In this event, the partnership would receive the
defaulting party's revenues from the well, if any, under penalty arrangements
set forth in the operating agreement.

If the managing general partner is not the actual operator of the well, then
there is a risk that the managing general partner cannot supervise the
third-party operator closely enough. For example, decisions related to the
following would be made by the third-party operator and may not be in the best
interests of the partnerships and you and the other investors:

         o        how the well is operated;

         o        expenditures related to the well; and

         o        possibly the marketing of the natural gas and oil production.

Further, the third-party operator may have financial difficulties and fail to
pay for materials or services on the wells it drills or operates, which would
cause the partnership to incur extra costs in discharging materialmen's and
workmen's liens. The managing general partner may not be the operator of the
well if the partnership owns less than a 50% working interest in the well, or if
the managing general partner acquired the working interest in the well from a
third-party which required that the third-party be named operator as one of the
terms of the acquisition.

RISKS RELATED TO AN INVESTMENT IN A PARTNERSHIP
IF YOU CHOOSE TO INVEST AS A GENERAL PARTNER, THEN YOU HAVE GREATER RISK THAN A
LIMITED PARTNER. If you invest as an investor general partner for the tax
benefits instead of as a limited partner, then under Delaware law you will have
unlimited liability for your partnership's activities until converted to limited
partner status subject to certain exceptions as described in "Actions To Be
Taken by Managing General Partner To Reduce Risks of Additional Payments By
Investor General Partners - Conversion of Investor General Partner Units to
Limited Partner Units." This could result in you being required to make
payments, in addition to your original investment, in amounts that are
impossible to predict because of their uncertain nature. Under the terms of the
partnership agreement, if you are an investor general partner you agree to pay
only your proportionate share of your partnership's obligations and liabilities.
This agreement, however, does not eliminate your liability to third-parties if
another investor general partner does not pay his proportionate share of your
partnership's obligations and liabilities.

Also, each partnership will own less than 100% of the working interest in some
of its wells. If a court holds you and the other third-party working interest
owners of the well liable for the development and operation of a well and the
third-party working interest owners do not pay their proportionate share of the
costs and liabilities associated with the well, then the partnership and you and
the other investor general partners also would be liable for those costs and
liabilities.

As an investor general partner you may become subject to the following:

         o        contract liability, which is not covered by insurance;

                                       10

         o        liability for pollution, abuses of the environment, and other
                  environmental damages such as the release of toxic gas, spills
                  or uncontrollable flows of natural gas, oil or fluids, against
                  which the managing general partner cannot insure because
                  coverage is not available or against which it may elect not to
                  insure because of high premium costs or other reasons; and

         o        liability for drilling hazards which result in property
                  damage, personal injury, or death to third-parties in amounts
                  greater than the insurance coverage. The drilling hazards
                  include, but are not limited to well blowouts, fires, and
                  explosions.

If your partnership's insurance proceeds and assets, the managing general
partner's indemnification of you and the other investor general partners, and
the liability coverage provided by major subcontractors were not sufficient to
satisfy the liability, then the managing general partner would call for
additional funds from you and the other investor general partners to satisfy the
liability. (See "Actions To Be Taken By Managing General Partner To Reduce Risks
of Additional Payments by Investor General Partners.")

THE MANAGING GENERAL PARTNER MAY NOT MEET ITS CAPITAL CONTRIBUTIONS,
INDEMNIFICATION AND PURCHASE OBLIGATIONS IF ITS LIQUID NET WORTH IS NOT
SUFFICIENT. The managing general partner has made commitments to you and the
other investors in each partnership regarding the following:

         o        the payment of organization and offering costs and the
                  majority of equipment costs;

         o        indemnification of the investor general partners for
                  liabilities in excess of their pro rata share of partnership
                  assets and insurance proceeds; and

         o        purchasing units presented by an investor, although this may
                  be suspended by the managing general partner if it determines,
                  in its sole discretion, that it does not have the necessary
                  cash flow or cannot borrow funds for this purpose on
                  reasonable terms.

A significant financial reversal for the managing general partner could
adversely affect its ability to honor these obligations.

The managing general partner's net worth is based primarily on the estimated
value of its producing natural gas properties and is not available in cash
without borrowings or a sale of the properties. Also, if natural gas prices
decrease, then the estimated value of the properties and the managing general
partner's net worth will be reduced. Further, price decreases will reduce the
managing general partner's revenues, and may make some reserves uneconomic to
produce. This would reduce the managing general partner's reserves and cash
flow, and could cause the lenders of the managing general partner and its
affiliates to reduce the borrowing base for the managing general partner and its
affiliates. Also, because approximately 92% of the managing general partner's
proved reserves are currently natural gas reserves, the managing general
partner's net worth is more susceptible to movements in natural gas prices than
in oil prices.

The managing general partner's net worth may not be sufficient, either currently
or in the future, to meet its financial commitments under the partnership
agreement. These risks are increased because the managing general partner has
made similar financial commitments in 41 other partnerships and will make this
same commitment in future partnerships. (See "Financial Information Concerning
the Managing General Partner and Atlas America Public #14-2004 L.P.")

AN INVESTMENT IN A PARTNERSHIP MUST BE FOR THE LONG-TERM BECAUSE THE UNITS ARE
ILLIQUID AND NOT READILY TRANSFERABLE. If you invest in a partnership, then you
must assume the risks of an illiquid investment. The transferability of the
units is limited by the federal securities laws, the tax laws, and the
partnership agreement. The units generally cannot be liquidated since there is
not a readily available market for the sale of the units. Further, the
partnerships do not intend to register the units and list the units on any
exchange.

                                       11

Finally, a sale of your units could create adverse tax and economic consequences
for you. The sale or exchange of all or part of your units held for more than 12
months generally will result in a recognition of long-term capital gain or loss.
However, previous deductions for depreciation, depletion and IDCs may be
recaptured as ordinary income rather than capital gain regardless of how long
you have owned the units. If the units are held for 12 months or less, then the
gain or loss generally will be short-term gain or loss. Your pro rata share of a
partnership's liabilities, if any, as of the date of the sale or exchange must
be included in the amount realized by you. Thus, the gain recognized by you may
result in a tax liability greater than the cash proceeds, if any, received by
you from the sale or other taxable disposition of your units. (See "Material
Federal Income Tax Consequences-Disposition of Units" and "Presentment
Feature.")


SPREADING THE RISKS OF DRILLING AMONG A NUMBER OF WELLS WILL BE REDUCED IF LESS
THAN THE MAXIMUM SUBSCRIPTION PROCEEDS ARE RECEIVED AND FEWER WELLS ARE DRILLED.
Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of all of the partnerships, in the
aggregate, may not exceed $125 million. There are no other requirements
regarding the size of a partnership other than the nonbinding targeted amounts
described in "Terms of the Offering - Subscription to a Partnership," and the
subscription proceeds of one partnership may be substantially more or less than
the subscription proceeds of another partnership. A partnership with a smaller
amount of subscription proceeds will drill fewer wells which decreases the
partnership's ability to spread the risks of drilling. For example, the managing
general partner anticipates that a partnership will drill approximately 10 net
wells if the minimum subscriptions of $2 million are received, which is compared
with 722 net wells if subscription proceeds of $125 million are received by a
partnership. A gross well is a well in which a partnership owns a working
interest. This is compared with a net well which is the sum of the fractional
working interests owned in the gross wells. For example, a 50% working interest
owned in three wells is three gross wells, but 1.5 net wells.


On the other hand, to the extent more than the minimum subscriptions are
received by a partnership and the number of wells drilled increases, the
partnership's overall investment return may decrease if the managing general
partner is unable to find enough suitable wells to be drilled. Also, in a large
partnership greater demands will be placed on the managing general partner's
management capabilities.

Finally, the cost of drilling and completing a well is often uncertain and there
may be cost overruns in drilling and completing the wells because the wells will
not be drilled and completed on a turnkey basis for a fixed price, which would
shift the risk of loss to the managing general partner as drilling contractor.
The majority of the equipment costs of a partnership's wells, including any
equipment costs in excess of 10% of the partnership's subscription proceeds,
will be paid by the managing general partner. However, all of the intangible
drilling costs will be charged to you and the other investors. If there is a
cost overrun for the intangible drilling costs of a well or wells, then the
managing general partner anticipates that it would use the subscription
proceeds, if available, to pay the cost overrun or advance the necessary funds
to the partnership. Using subscription proceeds to pay cost overruns will result
in a partnership drilling fewer wells. Also, unanticipated costs can adversely
affect the economics of a well. For example, the managing general partner and
its affiliates have experienced an increase in the cost of tubular steel as a
result of rising steel prices which may increase well costs.

THE PARTNERSHIPS DO NOT OWN ANY PROSPECTS, THE MANAGING GENERAL PARTNER HAS
COMPLETE DISCRETION TO SELECT WHICH PROSPECTS ARE ACQUIRED BY A PARTNERSHIP, AND
THE POSSIBLE LACK OF INFORMATION FOR A MAJORITY OF THE PROSPECTS DECREASES YOUR
ABILITY TO EVALUATE THE FEASIBILITY OF A PARTNERSHIP. The partnerships do not
currently hold any interests in any prospects on which the wells will be
drilled, and the managing general partner has absolute discretion in determining
which prospects will be acquired to be drilled.

The managing general partner has identified in "Proposed Activities" the general
areas where each partnership will drill wells and the managing general partner
intends that Atlas America Public #14-2004 L.P., which must close on or before
December 31, 2004, will drill the prospects described in "Appendix A -
Information Regarding Currently Proposed Prospects for Atlas America Public
#14-2004 L.P." These prospects represent the wells currently proposed to be
drilled if a portion of the targeted nonbinding amount of subscription proceeds
is received as described in "Terms of the Offering - Subscription to a
Partnership." If there are adverse events with respect to any of the currently
proposed prospects, the managing general partner will substitute the
partnership's prospects. The managing general partner also anticipates that it
will designate a portion of the prospects in each partnership designated Atlas
America Public #14-2005(_____) L.P. by a supplement or an amendment to the
registration statement of which this prospectus is a part. With respect to the
identified prospects for a partnership, the managing general partner has the
right on behalf of the partnership to:

                                       12

         o        substitute prospects;

         o        take a lesser working interest in the prospects;

         o        drill in other areas; or

         o        do any combination of the foregoing.

Thus, you do not have any geological or production information to evaluate any
additional and/or substituted prospects and wells. Also, if the subscription
proceeds received in a partnership are insufficient to drill all of the
identified prospects, then the managing general partner will choose those
prospects which it believes are most suitable for the partnership. You must rely
entirely on the managing general partner to select the prospects and wells for a
partnership.

Finally, the partnerships do not have the right of first refusal in the
selection of prospects from the inventory of the managing general partner and
its affiliates, and they may sell their prospects to other partnerships,
companies, joint ventures, or other persons at any time.

DRILLING PROSPECTS IN ONE AREA MAY INCREASE RISK. To the extent that the
prospects are drilled in one area at the same time, this may increase the risk
of loss. For example, if multiple wells in one area are drilled at approximately
the same time, then there is a greater risk of loss if the wells are marginal or
nonproductive since the managing general partner will not be using the drilling
results of one or more of those wells to decide whether or not to continue
drilling prospects in that area or to substitute other prospects in other areas.
This is compared with the situation in which the managing general partner drills
one well and assesses the drilling results before it decides to drill a second
well in the same area or to substitute a different prospect in another area.

This risk is further increased with wells which are prepaid because of the 90
day time constraint and potential adverse weather conditions where the managing
general partner is required to drill many wells at the same time. For example,
"frost laws" prohibit drilling rigs and other heavy equipment from using certain
roads during the winter, which may delay drilling and completing wells within
the 90 day time constraint. Also, there could be shortages of drilling rigs,
equipment, supplies and personnel during this time period. (See "Material
Federal Income Tax Consequences - Drilling Contracts.")

LACK OF PRODUCTION INFORMATION INCREASES YOUR RISK AND DECREASES YOUR ABILITY TO
EVALUATE THE FEASIBILITY OF A PARTNERSHIP'S DRILLING PROGRAM. Production
information from surrounding wells in the area is an important indicator in
evaluating the economic potential of a proposed well to be drilled. However, the
data set forth in "Appendix A - Information Concerning Currently Proposed Wells
for Atlas America Public #14-2004 L.P." for the proposed wells in Pennsylvania
may not show all of the wells drilled and/or production from those wells because
there was a third-party operator and the Pennsylvania Department of
Environmental Resources keeps production data confidential for the first five
years from the time a well starts producing. If the managing general partner is
the operator and no production data is shown, it is because the wells are not
yet completed, on-line to sell production, or have been producing for only a
short period of time. This lack of production information from surrounding wells
results in greater uncertainty to you and the other investors.

THE PARTNERSHIPS COMPOSING THIS PROGRAM AND OTHER PARTNERSHIPS SPONSORED BY THE
MANAGING GENERAL PARTNER MAY COMPETE WITH EACH OTHER FOR PROSPECTS, EQUIPMENT,
CONTRACTORS, AND PERSONNEL. One or more partnerships in this program or other
partnerships sponsored by the managing general partner may have unexpended
capital funds at the same time. Thus, these partnerships may compete for
suitable prospects and the availability of equipment, contractors, and the
managing general partner's personnel. For example, a partnership previously
organized by the managing general partner may still be acquiring prospects to
drill when the partnerships composing this program are attempting to acquire
prospects. This may make it more difficult to complete the prospect acquisition
activities for the partnerships composing this program and may make each
partnership less profitable.

MANAGING GENERAL PARTNER'S SUBORDINATION IS NOT A GUARANTEE OF THE RETURN OF ANY
OF YOUR INVESTMENT. If your cash distributions from the partnership in which you
invest are less than a 10% return of capital for each of the first five 12-month
periods beginning with the partnership's first cash distributions from
operations, then the managing general partner has agreed to subordinate a
portion of its share of the partnership's net production revenues. However, if
the wells produce only small natural gas and oil volumes, and/or natural gas and
oil prices decrease, then even with subordination you may not receive the 10%
return of capital for each of the first five years as described above, or a
return of your capital during the term of the partnership. Also, at any time
during the subordination period the managing general partner is entitled to an
additional share of partnership revenues to recoup previous subordination
distributions to the extent your cash distributions from the partnership exceed
the 10% return of capital described above. (See "Participation in Costs and
Revenues - Subordination of Portion of the Managing General Partner's Net
Revenue Share.")

                                       13

BORROWINGS BY THE MANAGING GENERAL PARTNER COULD REDUCE FUNDS AVAILABLE FOR ITS
SUBORDINATION OBLIGATION. With respect to each partnership, the managing general
partner has or will pledge either its partnership interest and/or an undivided
interest in the partnership's assets equal to or less than its revenue interest,
which will range from 32% to 35% depending on the amount of its capital
contribution, to secure borrowings for its and its affiliates' corporate
purposes. (See "Participation in Costs and Revenues.") Under agreements
previously entered into as described in "Management's Discussion and Analysis of
Financial Condition, Results of Operations, Liquidity and Capital Resources,"
the managing general partner's lenders have required a first lien in the
property and will have priority over the managing general partner's
subordination obligation under each partnership agreement. Thus, if there was a
default to the lenders under this pledge arrangement, this would reduce or
eliminate the amount of each partnership's net production revenues available to
the managing general partner for its subordination obligation to you and the
other investors. Also, under certain circumstances, if the managing general
partner made a subordination distribution to you and the other investors after a
default to its lenders, then the lenders may be able to recoup that
subordination distribution from you and the other investors.

COMPENSATION AND FEES TO THE MANAGING GENERAL PARTNER REGARDLESS OF SUCCESS OF A
PARTNERSHIP'S ACTIVITIES WILL REDUCE CASH DISTRIBUTIONS. The managing general
partner and its affiliates will profit from their services in drilling,
completing, and operating each partnership's wells, and will receive the other
fees and reimbursement of direct costs described in "Compensation" regardless of
the success of the partnership's wells. These fees and direct costs will reduce
the amount of cash distributions to you and the other investors. The amount of
the fees is subject to the complete discretion of the managing general partner
other than the fees must not exceed competitive fees charged by unaffiliated
third-parties in the same geographic area engaged in similar businesses and any
other restrictions set forth in "Compensation." With respect to direct costs,
the managing general partner has sole discretion on behalf of each partnership
to select the provider of the services or goods and the provider's compensation
as discussed in "Compensation."

THE INTENDED QUARTERLY DISTRIBUTIONS TO INVESTORS MAY BE REDUCED OR DELAYED.
Cash distributions to you and the other investors may not be paid each quarter.
Distributions may be reduced or deferred, in the discretion of the managing
general partner, to the extent a partnership's revenues are used for any of the
following:

         o        repayment of borrowings;

         o        cost overruns;

         o        remedial work to improve a well's producing capability;

         o        direct costs and general and administrative expenses of the
                  partnership;

         o        reserves, including a reserve for the estimated costs of
                  eventually plugging and abandoning the wells; or

         o        indemnification of the managing general partner and its
                  affiliates by the partnership for losses or liabilities
                  incurred in connection with the partnership's activities. (See
                  "Participation in Costs and Revenues - Distributions.")

THERE ARE CONFLICTS OF INTEREST BETWEEN THE MANAGING GENERAL PARTNER AND THE
INVESTORS. There are conflicts of interest between you and the managing general
partner and its affiliates. These conflicts of interest, which are not otherwise
discussed in this "Risk Factors" section, include the following:

         o        the managing general partner has determined the compensation
                  and reimbursement that it and its affiliates will receive in
                  connection with the partnerships without any unaffiliated
                  third-party dealing at arms' length on behalf of the
                  investors;

                                       14

         o        the managing general partner must monitor and enforce, on
                  behalf of the partnerships, its own compliance with the
                  drilling and operating agreement;

         o        because the managing general partner will receive a percentage
                  of revenues greater than the percentage of costs that it pays,
                  there may be a conflict of interest concerning which wells
                  will be drilled based on the wells' risk and profit potential;

         o        the allocation of all intangible drilling costs to you and the
                  other investors and the majority of the equipment costs to the
                  managing general partner may create a conflict of interest
                  concerning whether to complete a well;

         o        if the managing general partner, as tax matters partner,
                  represents a partnership before the IRS, potential conflicts
                  include whether or not to expend partnership funds to contest
                  a proposed adjustment by the IRS, if any, to the amount of
                  your deduction for intangible drilling costs, or the credit to
                  the managing general partner's capital account for
                  contributing the leases to the partnership;

         o        which wells will be drilled by the managing general partner's
                  and its affiliates' other affiliated partnerships or
                  third-party programs in which they serve as driller/operator
                  and which wells will be drilled by the partnerships, and the
                  terms on which the partnerships' leases will be acquired;

         o        the terms on which the managing general partner or affiliated
                  limited partnerships may purchase producing wells from each
                  partnership;

         o        the possible purchase of units by the managing general
                  partner, its officers, directors, and affiliates for a reduced
                  price which would dilute the voting rights of you and the
                  other investors on certain matters;

         o        the representation of the managing general partner and each
                  partnership by the same legal counsel;

         o        the right of Atlas Pipeline Partners to determine the order of
                  priority for constructing gathering lines;

         o        the benefits to Atlas Pipeline Partners of the managing
                  general partner causing the partnerships to drill wells that
                  will connect to the gathering system owned by Atlas Pipeline
                  Partners; and

         o        the obligation of the managing general partner's affiliates,
                  which does not include the partnerships for this purpose, to
                  pay Atlas Pipeline Partners the difference between the
                  gathering fees to be paid by each partnership to the managing
                  general partner and the greater of $.35 per mcf or 16% of the
                  gross sales price for the gas as described in "Proposed
                  Activities - Sale of Natural Gas and Oil Production -
                  Gathering of Natural Gas."

Other than certain guidelines set forth in "Conflicts of Interest," the managing
general partner has no established procedures to resolve a conflict of interest.

THE PRESENTMENT OBLIGATION MAY NOT BE FUNDED AND THE PRESENTMENT PRICE MAY NOT
REFLECT FULL VALUE. Subject to certain conditions, beginning with the fifth
calendar year after your partnership closes you may present your units to the
managing general partner for purchase. However, the managing general partner may
determine, in its sole discretion, that it does not have the necessary cash flow
or cannot borrow funds for this purpose on reasonable terms. In either event the
managing general partner may suspend the presentment feature. This risk is
increased because the managing general partner has and will incur similar
presentment obligations in other partnerships.

Further, the presentment price may not reflect the full value of a partnership's
property or your units because of the difficulty in accurately estimating
natural gas and oil reserves. 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 the reserve estimate is a function
of the quality of the available data and of engineering and geological
interpretation and judgment. Also, the reserves and future net revenues are
based on various assumptions as to natural gas and oil prices, taxes,
development expenses, capital expenses, operating expenses and availability of
funds. Any significant variance in these assumptions could materially affect the
estimated quantity of the reserves. As a result, the managing general partner's
estimates are inherently imprecise and may not correspond to realizable value.
The presentment price paid for your units and any revenues received by you
before the presentment may not be equal to the purchase price of the units.
Conversely, because the presentment price is a contractual price it is not
reduced by discounts such as minority interests and lack of marketability that
generally are used to value partnership interests for tax and other purposes.
(See "Presentment Feature.")

                                       15

Finally, see "- An Investment in a Partnership Must be for the Long-Term Because
the Units Are Illiquid and Not Readily Transferable," above, concerning the tax
effects of presenting your units for purchase.

THE MANAGING GENERAL PARTNER MAY NOT DEVOTE THE NECESSARY TIME TO THE
PARTNERSHIPS BECAUSE ITS MANAGEMENT OBLIGATIONS ARE NOT EXCLUSIVE. The managing
general partner may not devote the necessary time to the partnerships. The
managing general partner and its affiliates will be engaged in other oil and gas
activities, including other partnerships and unrelated business ventures for
their own account or for the account of others, during the term of each
partnership. (See "Management.")

PREPAYING SUBSCRIPTION PROCEEDS TO THE MANAGING GENERAL PARTNER MAY EXPOSE THE
SUBSCRIPTION PROCEEDS TO CLAIMS OF THE MANAGING GENERAL PARTNER'S CREDITORS.
Under the drilling and operating agreement each partnership will be required to
immediately pay the managing general partner the investors' share of the entire
estimated price for drilling and completing the partnership's wells. Thus, these
funds could be subject to claims of the managing general partner's creditors.
(See "Financial Information Concerning the Managing General Partner and Atlas
America Public #14-2004 L.P.")

LACK OF INDEPENDENT UNDERWRITER MAY REDUCE DUE DILIGENCE INVESTIGATION OF THE
PARTNERSHIPS AND THE MANAGING GENERAL PARTNER. There has not been an extensive
in-depth "due diligence" investigation of the existing and proposed business
activities of the partnerships and the managing general partner that would be
provided by independent underwriters. Anthem Securities, which is affiliated
with the managing general partner, serves as dealer-manager and will receive
reimbursement of accountable due diligence expenses for certain due diligence
investigations conducted by the selling agents which it will reallow to the
selling agents. However, its due diligence examination concerning the
partnerships cannot be considered to be independent or as comprehensive as an
investigation that would be conducted by an independent broker/dealer. (See
"Conflicts of Interest.")

A LENGTHY OFFERING PERIOD MAY RESULT IN DELAYS IN THE INVESTMENT OF YOUR
SUBSCRIPTION AND ANY CASH DISTRIBUTIONS FROM THE PARTNERSHIP TO YOU. Because the
offering period for a particular partnership can extend for many months, it is
likely that there will be a delay in the investment of your subscription
proceeds. This may create a delay in the partnership's cash distributions to you
which will be paid only after payment of the managing general partner's fees and
expenses and only if there is sufficient cash available. See "Terms of the
Offering" for a discussion of the procedures involved in the offering of the
units and the formation of a partnership.

TAX RISKS
CHANGES IN THE LAW MAY REDUCE TO SOME DEGREE YOUR TAX BENEFITS FROM AN
INVESTMENT IN A PARTNERSHIP. Your investment in a partnership may be affected by
changes in the tax laws. For example, in 2003 the top four federal income tax
brackets for individuals were reduced, including reducing the top bracket to 35%
from 38.6%, until December 31, 2010. The lower federal income tax rates will
reduce to some degree the amount of taxes you save by virtue of your share of
your partnership's deductions for intangible drilling costs, depletion, and
depreciation. Also, the federal income tax rates described above may be changed
again before January 1, 2011.

YOU MAY OWE TAXES IN EXCESS OF YOUR CASH DISTRIBUTIONS FROM A PARTNERSHIP. You
may become subject to income tax liability for partnership income in excess of
the cash you actually receive from a partnership in which you invest. For
example:

         o        if a partnership borrows money your share of partnership
                  revenues used to pay principal on the loan will be included in
                  your taxable income from the partnership and will not be
                  deductible;

                                       16

         o        income from sales of natural gas and oil may be accrued by a
                  partnership in one tax year, although payment is not actually
                  received by the partnership until the next tax year;

         o        taxable income or gain may be allocated to you if there is a
                  deficit in your capital account even though you do not receive
                  a corresponding distribution of partnership revenues;

         o        partnership revenues may be expended by the managing general
                  partner for non-deductible costs or retained to establish a
                  reserve for future estimated costs, including a reserve for
                  the estimated costs of eventually plugging and abandoning the
                  wells; and

         o        the taxable disposition of partnership property or your units
                  may result in income tax liability in excess of cash
                  distributions.

YOUR DEDUCTION FOR INTANGIBLE DRILLING COSTS MAY BE LIMITED FOR PURPOSES OF THE
ALTERNATIVE MINIMUM TAX. You will be allocated a share of your partnership's
deduction for intangible drilling costs. However, under current tax law your
alternative minimum taxable income cannot be reduced by more than 40% by the
deduction for intangible drilling costs. Also, if you invest as a limited
partner you may not have enough passive income to use your share of a
partnership's deduction for intangible drilling costs.

INVESTMENT INTEREST DEDUCTIONS OF INVESTOR GENERAL PARTNERS MAY BE LIMITED. An
investor general partner's share of a partnership's deduction for intangible
drilling costs will reduce his investment income and may adversely affect the
deductibility of his investment interest expense, if any.

LACK OF TAX SHELTER REGISTRATION COULD RESULT IN PENALTIES TO YOU. The managing
general partner has determined that the partnerships are not tax shelters
required to register with the IRS. If it is subsequently determined by the IRS
or the courts that the partnerships were required to be registered with the IRS
as tax shelters, then you would be liable for a $250 penalty for failure to
include a tax registration number for your partnership on your individual
federal income tax return, unless this failure was due to reasonable cause.

                             ADDITIONAL INFORMATION

The program and the partnerships composing the program currently are not
required to file reports with the SEC. However, a registration statement on Form
S-1 has been filed on behalf of the program with the SEC. Certain portions of
the registration statement have been deleted from this prospectus under SEC
rules and regulations. You are urged to refer to the registration statement and
exhibits for further information concerning the provisions of certain documents
referred to in this prospectus.

You may read and copy any materials filed as a part of the registration
statement, including the tax opinion included as Exhibit 8, at the SEC's Public
Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The SEC
maintains an internet world wide web site that contains registration statements,
reports, proxy statements, and other information about issuers who file
electronically with the SEC, including the program. The address of that site is
http://www.sec.gov. Also, you may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, a copy
of the tax opinion may be obtained by you or your advisors from the managing
general partner at no cost. The delivery of this prospectus does not imply that
its information is correct as of any time after its date.

                 FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS

Statements, other than statements of historical facts, included in this
prospectus and its exhibits address activities, events or developments that the
managing general partner and the partnerships anticipate will or may occur in
the future. For example, the words "believes," "anticipates," and "expects" are
intended to identify forward-looking statements. These forward-looking
statements include such things as:

         o        investment objectives;

                                       17

         o        references to future success;

         o        business strategy;

         o        estimated future capital expenditures;

         o        competitive strengths and goals; and

         o        other similar matters.

These statements are based on certain assumptions and analyses made by the
partnerships and the managing general partner in light of their experience and
their perception of historical trends, current conditions, and expected future
developments. However, whether actual results will conform with these
expectations is subject to a number of risks and uncertainties, many of which
are beyond the control of the partnerships, including, but not limited to:

         o        general economic, market, or business conditions;

         o        changes in laws or regulations;

         o        the risk that the wells are productive, but do not produce
                  enough revenue to return the investment made;

         o        the risk that the wells are dry holes; and

         o        uncertainties concerning natural gas and oil prices, which
                  could decrease in the future.

Thus, all of the forward-looking statements made in this prospectus and its
exhibits are qualified by these cautionary statements. There can be no assurance
that actual results will conform with the managing general partner's and the
partnerships' expectations.

                              INVESTMENT OBJECTIVES

Each partnership's principal investment objectives are to invest its
subscription proceeds in natural gas development wells which will:

         o        Provide quarterly cash distributions to you from the
                  partnership in which you invest until the wells are depleted
                  with a minimum annual cash flow of 10% during the first five
                  years beginning with your partnership's first revenue
                  distribution based on $10,000 per unit for all units sold.
                  These distributions of a 10% return of capital during the
                  first five years are not guaranteed, but are subject to the
                  managing general partner's subordination obligation. The
                  managing general partner anticipates that investors in a
                  partnership will begin to receive quarterly cash distributions
                  approximately seven months after the offering period for the
                  partnership ends. (See "Participation in Costs and Revenues -
                  Subordination of Portion of Managing General Partner's Net
                  Revenue Share.") The partnerships do not currently hold any
                  interests in any prospects on which the wells will be drilled.

         o        Obtain income tax deductions from the partnership in which you
                  invest, in the year that you invest, from intangible drilling
                  costs to offset a portion of your taxable income from sources
                  other than the partnership, subject to the passive activity
                  rules if you invest as a limited partner. For example, if you
                  pay $10,000 for a unit your investment will produce an income
                  tax deduction of approximately $9,000 per unit, 90%, in the
                  year you invest against:

                  o        ordinary income, or capital gain in some situations,
                           if you invest as an investor general partner in a
                           partnership; and

                  o        passive income if you invest as a limited partner in
                           a partnership.

                                       18

                  In 2003, the top four tax brackets for individual taxpayers
                  were reduced from 38.6% to 35%, 35% to 33%, 30% to 28%, and
                  27% to 25%. These changes are scheduled to expire December 31,
                  2010. If you are in either the 35% or 33% tax bracket, you
                  will save approximately $3,150 or $2,970, respectively, per
                  $10,000 unit, in federal income taxes in the year that you
                  invest. Most states also allow this type of a deduction
                  against the state income tax. If the partnership in which you
                  invest begins selling natural gas and oil production from its
                  wells in the year in which you invest, however, then you may
                  be allocated a share of partnership income in that year which
                  will be offset by a portion of your intangible drilling cost
                  deduction and your share of the other partnership deductions
                  discussed below.

         o        Offset a portion of any gross production income generated by
                  your partnership with tax deductions from percentage
                  depletion, which is 15% in 2004. The percentage depletion rate
                  may fluctuate from year to year depending on the price of oil,
                  but under current tax law it will not be less than the
                  statutory rate of 15% nor more than 25%.

         o        Obtain income tax deductions of the remaining 10% of your
                  investment over a seven-year cost recovery period, beginning
                  in the year the wells are drilled, completed and placed in
                  service for production of natural gas or oil. For example, if
                  you pay $10,000 for a unit, you will receive additional income
                  tax deductions which total approximately $1,000 per unit, in
                  the aggregate, over the seven-year cost recovery period for
                  depreciation of your partnership's equipment costs for its
                  productive wells.

         o        If you are self-employed and invest in a partnership as an
                  investor general partner, then you may use your share of the
                  partnership's deduction for intangible drilling costs to
                  offset a portion of your net earnings from self-employment in
                  the year you invest.

Attainment of these investment objectives by a partnership will depend on many
factors, including the ability of the managing general partner to select
suitable wells that will be productive and produce enough revenue to return the
investment made. The success of each partnership depends largely on future
economic conditions, especially the future price of natural gas which is
volatile and may decrease. Also, the extent to which each partnership attains
the foregoing investment objectives will be different, because each partnership
is a separate business entity which:

         o        generally will drill different wells;

         o        will likely receive a different amount of subscription
                  proceeds, which generally will be the primary factor in
                  determining the number of wells that can be drilled by each
                  partnership; and

         o        may drill wells situated in different geographical areas,
                  where the wells will be drilled to different formations,
                  reservoirs or depths, which will affect the cost of the wells
                  and, thus, will also affect the number of wells that can be
                  drilled by each partnership.

There can be no guarantee that the foregoing objectives will be attained.

                     ACTIONS TO BE TAKEN BY MANAGING GENERAL
                      PARTNER TO REDUCE RISKS OF ADDITIONAL
                      PAYMENTS BY INVESTOR GENERAL PARTNERS

You may choose to invest in a partnership as an investor general partner so that
you can receive an immediate tax deduction against any type of income. To help
reduce the risk that you and other investor general partners could be required
to make additional payments to the partnership, the managing general partner
will take the actions set forth below.

                                       19

         o        INSURANCE. The managing general partner will obtain and
                  maintain insurance coverage in amounts and for purposes which
                  would be carried by a reasonable, prudent general contractor
                  and operator in accordance with industry standards. Each
                  partnership will be included as an insured under these
                  general, umbrella, and excess liability policies. In addition,
                  the managing general partner requires all of its
                  subcontractors to certify that they have acceptable insurance
                  coverage for worker's compensation and general, auto, and
                  excess liability coverage. Major subcontractors are required
                  to carry general and auto liability insurance with a minimum
                  of $1 million combined single limit for bodily injury and
                  property damage in any one occurrence or accident. In the
                  event of a loss caused by a major subcontractor, the managing
                  general partner or partnership may attempt to draw on the
                  insurance policy of the particular subcontractor before the
                  insurance of the managing general partner or that of the
                  partnership, but currently would be unable to do so since none
                  of its major subcontractors have insurance which would allow
                  this. Also, even if a major subcontractor's insurance was
                  initially available, the managing general partner or
                  partnership may choose to draw on its own insurance coverage
                  before that of the major subcontractor so that its insurance
                  carrier will control the payment of claims.

                  The managing general partner's current insurance coverage
                  satisfies the following specifications:

         o        worker's compensation insurance in full compliance with the
                  laws of the Commonwealth of Pennsylvania and any other
                  applicable state laws where the wells will be drilled;

         o        commercial general liability covering bodily injury and
                  property damage third party liability, including
                  products/completed operations, blow out, cratering, and
                  explosion with limits of $1 million per occurrence/$2 million
                  general aggregate; and $1 million products/completed
                  operations aggregate;

         o        underground resources and equipment property damages liability
                  to others with a limit of $1 million;

         o        automobile liability with a $1 million combined single limit;

         o        employer's liability with a $500,000 policy limit;

         o        pollution liability resulting from a "pollution incident,"
                  which is defined as the discharge, dispersal, seepage,
                  migration, release or escape of one or more pollutants
                  directly from a well site, with a limit of $1 million for
                  bodily injury and property damage and a limit of $100,000 for
                  clean-up for third-parties; however, coverage does not apply
                  to pollution damage to the well site itself or the property of
                  the insured;

         o        commercial umbrella liability composed of:

                  o        primary umbrella limit of $25 million over general
                           liability, automobile liability, and employer's
                           liability and a $10 million sublimit for pollution
                           liability; and

                  o        excess liability providing excess limits of $24
                           million over the $25 million provided in the
                           commercial umbrella, but excluding pollution
                           liability.

                  Because the managing general partner is driller and operator
                  of other partnerships, the insurance available to each
                  partnership could be substantially less if insurance claims
                  are made in the other partnerships.

                  This insurance has deductibles, which would first have to be
                  paid by a partnership, of:

         o        $2,500 per occurrence for bodily injury and property damage;
                  and

         o        $10,000 per pollution incident for pollution damage.

                                       20

                  The insurance has terms, including exclusions, which are
                  standard for the natural gas and oil industry. On request the
                  managing general partner will provide you or your
                  representative a copy of its insurance policies. The managing
                  general partner will use its best efforts to maintain
                  insurance coverage that meets its current coverage, but may be
                  unsuccessful if the coverage becomes unavailable or too
                  expensive.

                  If you are an investor general partner and there is going to
                  be an adverse material change in a partnership's insurance
                  coverage, which the managing general partner does not
                  anticipate, then the managing general partner must notify you
                  at least 30 days before the effective date of the change. You
                  will have the right to convert your units into limited partner
                  units before the change by giving written notice to the
                  managing general partner.

         o        CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED
                  PARTNER UNITS. Your investor general partner units will be
                  automatically converted by the managing general partner to
                  limited partner units after all of the wells in your
                  partnership have been drilled and completed. In each
                  partnership, the managing general partner anticipates that the
                  wells will be placed in service and conversion will occur no
                  more than 12 months after a partnership closes.

                  Once your units are converted, which is a nontaxable event,
                  you will have the lesser liability of a limited partner in
                  your partnership under Delaware law for obligations and
                  liabilities arising after the conversion. However, you will
                  continue to have the responsibilities of a general partner for
                  partnership liabilities and obligations incurred before the
                  effective date of the conversion. For example, you might
                  become liable for partnership liabilities in excess of your
                  subscription during the time the partnership is engaged in
                  drilling activities and for environmental claims that arose
                  during drilling activities, but were not discovered until
                  after conversion.

         o        NONRECOURSE DEBT. The partnerships do not anticipate that they
                  will borrow funds. However, if borrowings are required, then
                  the partnerships will be permitted to borrow funds only from
                  the managing general partner or its affiliates without
                  recourse against non-partnership assets. Thus, if there is a
                  default under this loan arrangement you cannot be required to
                  contribute funds to the partnership. Any borrowings by a
                  partnership will be repaid from that partnership's revenues.

                  The amount that may be borrowed at any one time by a
                  partnership may not exceed an amount equal to 5% of the
                  investors' subscriptions in the partnership. However, because
                  you do not bear the risk of repaying these borrowings with
                  non-partnership assets, the borrowings will not increase the
                  extent to which you are allowed to deduct your individual
                  share of partnership losses.

         o        INDEMNIFICATION. The managing general partner will indemnify
                  you from any liability incurred in connection with your
                  partnership that is in excess of your interest in the
                  partnership's:

                  o        undistributed net assets; and

                  o        insurance proceeds, if any, from all potential
                           sources.

                  The managing general partner's indemnification obligation,
                  however, will not eliminate your potential liability if the
                  managing general partner's assets are insufficient to satisfy
                  its indemnification obligation. There can be no assurance that
                  the managing general partner's assets, including its liquid
                  assets, will be sufficient to satisfy its indemnification
                  obligation.

             CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS

SOURCE OF FUNDS
Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of all partnerships, in the aggregate, may

                                       21

not exceed $125 million. There are no other requirements regarding the size of a
partnership, and the subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other
partnerships. However, see "Terms of the Offering - Subscription to a
Partnership" regarding the targeted nonbinding amount of subscription proceeds
for each partnership.

On completion of an offering for a partnership, the partnership's source of
funds will be as follows assuming each unit is sold for $10,000:

         o        the subscription proceeds of you and the other investors,
                  which will be:

                  o        $2 million if 200 units are sold; and

                  o        $125 million if 12,500 units are sold; and

         o        the managing general partner's capital contribution, which
                  must be at least 25% of all capital contributions, and
                  includes its credit for organization and offering costs and
                  contributing the leases, which will be:

                  o        not less than $887,320 if 200 units are sold; and

                  o        not less than $53,033,261 if 12,500 units are sold.

Thus, the total amount available to a partnership will be not less than
$2,887,320 if 200 units are sold ranging to not less than $178,033,261 if 12,500
units are sold.

The managing general partner has made the largest single capital contribution in
each of its prior partnerships and no individual investor has contributed more,
although the total investor contributions in each partnership have exceeded the
managing general partner's contribution. The managing general partner expects to
make the largest single capital contribution in each of the partnerships.

USE OF PROCEEDS
The subscription proceeds received from you and the other investors for a
partnership will be used to pay:

         o        100% of the intangible drilling costs of drilling and
                  completing that partnership's wells; and

         o        34% of the equipment costs of drilling and completing that
                  partnership's wells, but not to exceed 10% of that
                  partnership's subscription proceeds.

The managing general partner will contribute all of the leases to each
partnership covering the acreage on which the wells will be drilled, and pay:

         o        66% of the equipment costs of drilling and completing the
                  partnership's wells; and

         o        any equipment costs that exceed 10% of the partnership's
                  subscription proceeds which would otherwise be charged to you
                  and the other investors.

The managing general partner also will be charged with 100% of the organization
and offering costs for each partnership. A portion of these contributions to
each partnership will be in the form of payments to itself, its affiliates and
third-parties and the remainder will be in the form of services related to
organizing this offering. The managing general partner will receive a credit
towards its required capital contribution to each partnership for these payments
and services as discussed in "Participation in Costs and Revenues."

                                       22

The following tables present information concerning each partnership's use of
the proceeds provided by both you and the other investors and the managing
general partner. The tables are based on the managing general partner's required
capital contribution of at least 25% of all capital contributions for each
partnership, which includes its credit for organization and offering costs and
contributing the leases. Anthem Securities, an affiliate of the managing general
partner, will be the dealer-manager and it will receive the dealer-manager fee,
the sales commissions, the .5% accountable reimbursement for permissible
non-cash compensation, and the .5% reimbursement for bona fide accountable due
diligence expenses. A portion of these payments and reimbursements, including
all of the sales commissions and the .5% reimbursement for bona fide accountable
due diligence expenses, will be reallowed by the dealer-manager to the
broker/dealers, which are referred to as selling agents, as discussed in "Plan
of Distribution." Subject to the above, the organizational costs will be paid to
the managing general partner, its affiliates and various third-parties, and the
intangible drilling costs and tangible costs will be paid to the managing
general partner as general drilling contractor and operator under the drilling
and operating agreement.

The tables are presented based on:

         o        the sale of 200 units, which is the minimum number of units
                  for each partnership; and

         o        the sale of 12,500 units, which is the maximum number of
                  units, in the aggregate, for all partnerships in the program.

Substantially all of the proceeds available to each partnership will be expended
for the following purposes and in the following manner:

                                INVESTOR CAPITAL



                                                                             200                        12,500
                                                                             UNITS                       UNITS
NATURE OF PAYMENT                                                            SOLD          % (1)         SOLD        % (1)
- -----------------                                                            ----          -----         ----        -----
ORGANIZATION AND OFFERING EXPENSES

Dealer-manager fee, sales commissions, .5% accountable reimbursement
for permissible non-cash compensation, and up to .5% reimbursement for
bona fide accountable due diligence expenses...........................   $      0           0%     $         0        0%

Organization costs.....................................................        - 0 -       - 0 -            - 0 -    - 0 -

AMOUNT AVAILABLE FOR INVESTMENT:

Intangible drilling costs (2)..........................................   $1,800,000         90%     $112,500,000      90%

Equipment costs (2)....................................................   $  200,000         10%     $ 12,500,000      10%

Leases.................................................................        - 0 -       - 0 -            - 0 -    - 0 -
                                                                          ----------       -----     ------------    -----

TOTAL INVESTOR CAPITAL.................................................   $2,000,000        100%     $125,000,000     100%
                                                                          ==========       =====     ============    =====

- -----------------
(1)    The percentage is based on total investor subscription proceeds and
       excludes the managing general partner's capital contribution.
(2)    These costs will vary depending on the actual cost of drilling and
       completing the wells, but not less than 90% of the subscription proceeds
       provided by you and the other investors will be used to pay intangible
       drilling costs. Equipment costs will be charged 34% to the investors and
       66% to the managing general partner, however the investors' share of
       these costs may not exceed 10% of the investors' subscription proceeds as
       discussed in "Participation in Costs and Revenues." Because the actual
       costs are not known, this table assumes that the maximum 10% of the
       investors' subscription proceeds is used to pay equipment costs in order
       to avoid the possibility of overstating the amount of currently
       deductible intangible drilling costs charged to the investors. In
       contrast, the managing general partner's share of equipment costs in the
       "- Managing General Partner Capital" and the "- Total Partnership
       Capital" tables below is based on the managing general partner's estimate
       of the average cost of drilling and completing wells in the partnership's
       primary areas as discussed in "Compensation - Drilling Contracts." In
       making this estimate, the managing general partner determined that the
       investors' share of the equipment costs would exceed the 10% limit set
       forth above if all of the equipment costs were charged 34% to the
       investors and 66% to the managing general partner. Thus, in the "-
       Managing General Partner Capital" Table and the "-Total Partnership
       Capital" Table below, the managing general partner was allocated more
       than 66% of the total estimated equipment costs and the investors' share
       of the total estimated equipment costs was limited to 10% of the
       investors' subscription proceeds.

                                       23

                        MANAGING GENERAL PARTNER CAPITAL



                                                                              200                       12,500
                                                                              UNITS                      UNITS
NATURE OF PAYMENT                                                             SOLD         % (1)         SOLD        % (1)
- -----------------                                                             ----         -----         ----        -----
ORGANIZATION AND OFFERING EXPENSES

Dealer-manager fee, sales commissions, .5% accountable reimbursement        $210,000      23.67%     $12,970,000    24.46%
for permissible non-cash compensation, and up to .5% reimbursement for
bona fide accountable due diligence expenses (2).......................

Organization costs (2).................................................     $ 90,000      10.14%     $ 2,119,403     4.00%

AMOUNT AVAILABLE FOR INVESTMENT:

Intangible drilling costs..............................................        - 0 -       - 0 -           - 0 -     - 0 -

Equipment costs (3)....................................................     $535,000      60.29%     $34,166,354    64.42%

Leases (4).............................................................     $ 52,320       5.90%     $ 3,777,504     7.12%
                                                                            --------       -----     -----------     -----

TOTAL MANAGING GENERAL PARTNER CAPITAL.................................     $887,320        100%     $53,033,261      100%
                                                                            ========       =====     ===========     =====


- ------------------
(1)    The percentage is based on the managing general partner's capital
       contribution and excludes the investors' subscription proceeds.
(2)    As discussed in "Participation in Costs and Revenues," if these fees,
       sales commissions, reimbursements and organization costs exceed 15% of
       the investors' subscription proceeds in a partnership, then the excess
       will be charged to the managing general partner, but will not be included
       as part of its capital contribution.
(3)    The managing general partner's share of equipment costs is described in
       "Compensation - Drilling Contracts." However, these costs will vary
       depending on the actual costs of drilling and completing the wells. Also,
       see footnote (2) to the "- Investor Capital" table above.
(4)    Instead of contributing cash for the leases, the managing general partner
       will assign to each partnership the leases covering the acreage on which
       the partnership's wells will be drilled. Generally, as described in
       "Compensation - Lease Costs," the managing general partner's lease cost
       is approximately $5,232 per prospect and for purposes of this table the
       managing general partner's lease costs have been quantified using this
       amount based on its estimate of the number of net wells that will be
       drilled. However, the managing general partner's lease costs on a
       prospect may be significantly higher than the above-referenced amount,
       and its credit for the leases contributed will equal its cost, unless it
       has a reason to believe that cost is materially more than fair market
       value of the property, in which case its credit for its lease
       contribution must not exceed fair market value.

                            TOTAL PARTNERSHIP CAPITAL



                                                                              200                       12,500
                                                                              UNITS                      UNITS
NATURE OF PAYMENT                                                             SOLD         % (1)         SOLD        % (1)
- -----------------                                                             ----         -----         ----        -----
ORGANIZATION AND OFFERING EXPENSES

Dealer-manager fee, sales commissions, .5% accountable reimbursement        $  210,000     7.27%     $ 12,970,000    7.29%
for permissible non-cash compensation, and up to .5% reimbursement for
bona fide accountable due diligence expenses (2).......................

Organization costs (2).................................................     $   90,000     3.12%     $  2,119,403    1.19%

AMOUNT AVAILABLE FOR INVESTMENT:

Intangible drilling costs (3)..........................................     $1,800,000    62.34%     $112,500,000   63.19%

Equipment costs (3)....................................................     $  735,000    25.46%     $ 46,666,354   26.21%

Leases (4).............................................................     $   52,320     1.81%     $  3,777,504    2.12%
                                                                            ----------     -----     ------------    -----

TOTAL PARTNERSHIP CAPITAL..............................................     $2,887,320      100%     $178,033,261     100%
                                                                            ==========     =====     ============    =====



                                       24

- ----------------
(1)    The percentage is based on total investor subscription proceeds and the
       managing general partner's estimate of its capital contributions.
(2)    As discussed in "Participation in Costs and Revenues," if these fees,
       sales commissions, reimbursements and organization costs exceed 15% of
       the investors' subscription proceeds in a partnership, then the excess
       will be charged to the managing general partner, but will not be included
       as part of its capital contribution.
(3)    The managing general partner's share of equipment costs is described in
       "Compensation - Drilling Contracts." However, these costs will vary
       depending on the actual cost of drilling and completing the wells, but
       not less than 90% of the subscription proceeds provided by you and the
       other investors will be used to pay intangible drilling costs. Also, see
       footnote (2) to the "- Investor Capital" table, above.
(4)    Instead of contributing cash for the leases, the managing general partner
       will assign to each partnership the leases covering the acreage on which
       the partnership's wells will be drilled. Generally, as described in
       "Compensation - Lease Costs," the managing general partner's lease cost
       is approximately $5,232 per prospect and for purposes of this table the
       managing general partner's lease costs have been quantified using this
       amount based on its estimate of the number of net wells that will be
       drilled. However, the managing general partner's lease costs on a
       prospect may be significantly higher than the above-referenced amount,
       and its credit for the leases contributed will equal its cost, unless it
       has a reason to believe that cost is materially more than fair market
       value of the property, in which case its credit for its lease
       contribution must not exceed fair market value.

                                  COMPENSATION

The items of compensation to be paid to the managing general partner and its
affiliates from each partnership are set forth below. Most of these items of
compensation depend on how many wells a partnership drills and how much of the
working interest in each of the wells is owned by the partnership. In this
regard, the managing general partner estimates that approximately 10 gross and
net wells will be drilled if the minimum required subscription proceeds of $2
million are received by a partnership, and approximately 761 gross wells, which
will be 722 net wells, will be drilled, in the aggregate, if subscription
proceeds of $125 million are received by the partnerships. A gross well is a
well in which a partnership owns a working interest. This is compared with a net
well which is the sum of the fractional working interests owned in the gross
wells. For example, a 50% working interest owned in three wells is three gross
wells, but 1.5 net wells. However, the managing general partner's estimate set
forth above of the number of wells to be drilled is subject to risks which can
cause actual results to vary. (See "Risk Factors - Risks Related to an
Investment in a Partnership - The Partnerships Do Not Own Any Prospects, the
Managing General Partner Has Complete Discretion to Select Which Prospects are
Acquired By a Partnership, and The Possible Lack of Information for a Majority
of the Prospects Decreases Your Ability to Evaluate the Feasibility of a
Partnership.")

NATURAL GAS AND OIL REVENUES
Subject to the managing general partner's subordination obligation, the
investors and the managing general partner will share in each partnership's
revenues in the same percentages as their respective capital contributions bear
to the total partnership capital contributions for that partnership except that
the managing general partner will receive an additional 7% of that partnership's
revenues. However, the managing general partner's total revenue share may not
exceed 35% of that partnership's revenues regardless of the amount of its
capital contribution. For example, if the managing general partner contributes
the minimum of 25% of the total partnership capital contributions and the
investors contribute 75% of the total partnership capital contributions, then
the managing general partner will receive 32% of the partnership revenues and
the investors will receive 68% of the partnership revenues. On the other hand,
if the managing general partner contributes 30% of the total partnership capital
contributions and the investors contribute 70% of the total partnership capital
contributions, then the managing general partner will receive 35% of the
partnership revenues, not 37%, because its revenue share cannot exceed 35% of
partnership revenues, and the investors will receive 65% of partnership
revenues.

As noted above, the managing general partner's revenue share from each
partnership is subject to its subordination obligation as described in
"Participation in Costs and Revenues - Subordination of Portion of the Managing
General Partner's Net Revenue Share" and the accompanying tables. For example,
if the managing general partner's revenue share is 35% of the partnership
revenues, then up to 17.5% of the managing general partner's partnership net
revenues could be used for its subordination obligation.

                                       25

LEASE COSTS
Under the partnership agreement the managing general partner will contribute to
each partnership all the undeveloped leases necessary to cover each of the
partnership's prospects. The managing general partner will receive a credit to
its capital account equal to:

         o        the cost of the leases; or

         o        the fair market value of the leases if the managing general
                  partner has reason to believe that cost is materially more
                  than the fair market value.

The cost of the leases will include a portion of the managing general partner's
reasonable, necessary, and actual expenses for services allocated to a
partnership's leases by it using industry guidelines.

In the primary areas of interest, the managing general partner's lease cost is
approximately $5,232 per prospect assuming a partnership acquires 100% of the
working interest in the prospect, although from time to time the managing
general partner's lease costs on a prospect may be significantly higher than
this amount. The managing general partner's credit for lease costs will be
proportionally reduced to the extent a partnership acquires less than 100% of
the working interest in the prospect. In this regard, a working interest
generally means an interest in the lease under which the owner of the working
interest must pay some portion of the cost of development, operation, or
maintenance of the well. Assuming all the leases are situated in these areas,
the managing general partner estimates that its credit for lease costs will be:

         o        $52,320 if $2 million is received, which is 10 net wells
                  times $5,232 per prospect; and

         o        $3,777,504 if $125 million is received, which is 722 net
                  wells times $5,232 per prospect.

Drilling a partnership's wells may also provide the managing general partner
with offset prospects to be drilled by allowing it to determine at the
partnership's expense the value of adjacent acreage in which the partnership
would not have any interest.

DRILLING CONTRACTS
Each partnership will enter into the drilling and operating agreement with the
managing general partner to drill and complete each partnership's wells at cost
plus 15%. The managing general partner has determined that this is a competitive
rate based on:

         o        information it has concerning drilling rates of third-party
                  drilling companies in the Appalachian Basin;

         o        the estimated costs of non-affiliated persons to drill and
                  equip wells in the Appalachian Basin as reported for 2002 by
                  an independent industry association which surveyed other
                  non-affiliated operators in the area; and

         o        information it has concerning increases in drilling costs in
                  the area since 2002.

If this rate subsequently exceeds competitive rates available from other
non-affiliated persons in the area engaged in the business of rendering or
providing comparable services or equipment, then the rate will be adjusted to
the competitive rate. However, the 15% premium may not be increased by the
managing general partner during the term of the partnership.

The managing general partner expects to subcontract some of the actual drilling
and completion of each partnership's wells to third-parties selected by it.
However, the managing general partner may not benefit by interpositioning itself
between the partnership and the actual provider of drilling contractor services,
and may not profit by drilling in contravention of its fiduciary obligations to
the partnership.

                                       26

Cost, when used with respect to services, generally means the reasonable,
necessary, and actual expense incurred in providing the services, determined in
accordance with generally accepted accounting principles. The cost of the well
includes reimbursement to the managing general partner of its general and
administrative overhead as discussed below. This amount will be proportionately
reduced to the extent a partnership acquires less than 100% of the working
interest in the prospect. The cost of the well also includes all ordinary costs
of drilling, testing and completing the well. This includes the cost of the
following for a natural gas well, which will be the classification of the
majority of the wells:

         o        multiple completions, which means, in general, treating
                  separately all potentially productive geological formations in
                  an attempt to enhance the gas production from the well;

         o        installing gathering lines for the natural gas of up to 2,500
                  feet; and

         o        the necessary facilities for the production of natural gas.

The amount of compensation that the managing general partner could earn as a
result of these arrangements depends on many factors, including where the wells
are drilled and their depths, the method used to complete the well, and the
number of wells drilled.

Assuming the maximum subscription proceeds of $125 million, the managing general
partner anticipates that the partnerships' weighted average cost of drilling and
completing approximately 722 net wells, excluding lease costs, will be
approximately $220,260 per net well, which includes reimbursement to the
managing general partner of the investors' share of its general and
administrative overhead of approximately $12,722, as described below. This
estimate was based on:

         o        the number of wells that the managing general partner
                  estimates will be drilled in each area;

         o        the percentage of working interest that the managing general
                  partner anticipates the partnerships will acquire in the
                  prospects in each area; and

         o        the associated estimated drilling and completion costs, which
                  are different for each area based primarily on different
                  depths and completion methods.

Thus, the managing general partner's estimated weighted average cost of drilling
and completing one net well as set forth above, in all likelihood, will vary
from the actual average cost of the wells in each of the primary areas.

Based on the assumptions and the estimated weighted average cost for one net
well as set forth above, the managing general partner expects that its 15%
profit will be approximately $22,558 per net well with respect to the intangible
drilling costs and the portion of equipment costs paid by you and the other
investors. In making this estimate, the managing general partner further assumed
that the investors' 34% share of the equipment costs would be reduced so that it
would not exceed the limit of 10% of investor subscription proceeds as discussed
in footnote (2) to the "- Investor Capital" table in "Capitalization and Source
of Funds and Use of Proceeds." For this reason and because the managing general
partner anticipates that the partnerships will not acquire 100% of the working
interest in all of their respective prospects, the managing general partner
estimates that the investors' share of its reimbursement for general and
administrative overhead will be a weighted average of approximately $12,722 for
one net well, rather than the maximum of $12,781 per well assuming a 34% share
of the equipment costs and a 100% working interest in the well. The actual
compensation received by the managing general partner as a result of each
partnership's drilling operations will vary from these estimates, but the
managing general partner's profit will not in any event exceed 15% of the costs
of drilling and completing the wells. Also, to the extent that a partnership
acquires less than a 100% working interest in a well, its drilling and
completion costs of that well will be proportionately decreased.

Subject to the foregoing, the managing general partner estimates that its
general and administrative overhead reimbursement of approximately $12,722 and
profit of 15% (approximately $22,558) for one net well, which totals $35,280,
will be:


         o        $352,800 if $2 million is received, which is 10 net wells
                  times $35,280; and

         o        $25,472,160 if $125 million is received, which is 722 net
                  wells times $35,280.

                                       27

The managing general partner's estimated weighted average cost of $220,260 for
one net well as discussed above consists of:

         o        intangible drilling costs of approximately $155,790 (70.7%);
                  and

         o        equipment costs of approximately $64,470 (29.3%).

In this regard, the managing general partner further anticipates that a
partnership's cost of drilling and completing any given well in the
partnerships' primary areas as described in "Proposed Activities," excluding
lease costs, may range from as low as approximately $120,000 to as high as
$285,000 or more, depending on the area.

PER WELL CHARGES
Under the drilling and operating agreement the managing general partner, as
operator of the wells, will receive the following from each partnership when the
wells begin producing:

         o        reimbursement at actual cost for all direct expenses incurred
                  on behalf of the partnership; and

         o        well supervision fees for operating and maintaining the wells
                  during producing operations at a competitive rate.

Currently the competitive rate for well supervision fees is $285 per well per
month in the primary and secondary areas. The well supervision fees will be
proportionately reduced to the extent the partnership acquires less than 100% of
the working interest in the well, and may be adjusted for inflation annually
beginning with the second calendar year after a partnership closes. If in the
future the foregoing rate exceeds competitive rates available from other
non-affiliated persons in the area engaged in the business of providing
comparable services or equipment, then the rate will be adjusted to the
competitive rate. The managing general partner may not benefit by
interpositioning itself between the partnership and the actual provider of
operator services. In no event will any consideration received for operator
services be duplicative of any consideration or reimbursement received under the
partnership agreement.

The well supervision fees cover all normal and regularly recurring operating
expenses for the production, delivery, and sale of natural gas and oil, such as:

         o        well tending, routine maintenance, and adjustment;

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

         o        preparing reports to the partnership and government agencies.

The well supervision fees do not include costs and expenses related to:

         o        the purchase of equipment, materials, or third-party services;

         o        brine disposal; and

         o        rebuilding of access roads.

These costs will be charged at the invoice cost of the materials purchased or
the third-party services performed.

The managing general partner estimates that it will receive well supervision
fees for a partnership's first 12 months of operation after all of the wells
have been placed in production of:

         o        $34,200 if $2 million is received, which is 10 net wells at
                  $285 per well per month; and

         o        $2,469,240 if $125 million is received, which is 722 net
                  wells at $285 per well per month.

GATHERING FEES
Under the partnership agreement the managing general partner will be responsible
for gathering and transporting the natural gas produced by the partnerships to

                                       28

interstate pipeline systems, local distribution companies, and/or end-users in
the area. The managing general partner anticipates that it will use the
gathering system owned by Atlas Pipeline Partners for the majority of the
natural gas as described in "Proposed Activities - Sale of Natural Gas and Oil
Production - Gathering of Natural Gas." The managing general partner's
affiliate, Atlas America, Inc., which is sometimes referred to in this
prospectus as "Atlas America," or another affiliate controls and manages the
pipeline for Atlas Pipeline Partners. Also, Atlas America and the managing
general partner's affiliates, Resource Energy, Inc., sometimes referred to in
this prospectus as "Resource Energy," and Viking Resources Corporation,
sometimes referred to in this prospectus as "Viking Resources," (the "Resource
Entities"), which do not include the partnerships, have an agreement with Atlas
Pipeline Partners which provides that generally all of the gas produced by their
affiliated partnerships, which includes each partnership composing the program,
will be gathered and transported through Atlas Pipeline Partners and that the
Resource Entities must pay the greater of $.35 per mcf or 16% of the gross sales
price for each mcf transported by these affiliated partnerships. Each
partnership will pay a gathering fee directly to the managing general partner at
competitive rates. If the gathering system owned by Atlas Pipeline Partners is
used by the partnership, the managing general partner will apply the gathering
fee it receives towards the payments owed by the Resource Entities under their
agreement with Atlas Pipeline Partners. If a third-party gathering system is
used, the managing general partner will pay a portion or all of its gathering
fee to the third-party gathering the natural gas.

The current rates for gathering fees, which have been determined by the managing
general partner for each partnership's primary and secondary drilling areas, are
set forth in the chart below. Although the gathering fee paid by each
partnership to the managing general partner may be increased by the managing
general partner, in its sole discretion, from those set forth in the chart
below, the managing general partner may not increase the gathering fees beyond
those charged by unaffiliated third-parties in the same geographic area engaged
in similar businesses. The gathering fees have not been increased by the
managing general partner in several years.



                                                                                CURRENT AMOUNT OF GATHERING FEES TO
EACH PARTNERSHIP'S PRIMARY AND                                                  BE PAID BY EACH PARTNERSHIP TO
SECONDARY DRILLING AREAS                                                        MANAGING GENERAL PARTNER (1)
- ------------------------                                                        ----------------------------
 Clinton/Medina Geological Formation in Western Pennsylvania in
     Crawford, Mercer, Lawrence, Warren, and Venango Counties, and
     Eastern Ohio primarily in Stark, Mahoning, Trumbull and
     Portage Counties ......................................................................$.29 per mcf
 Mississippian/Upper Devonian Sandstone Reservoirs in
     Fayette and Greene Counties, Pennsylvania..............................................$.35 per mcf
 Upper Devonian Sandstone Reservoirs in
     Armstrong County, Pennsylvania..................................................................(2)
 Upper Devonian Sandstone Reservoirs in
     McKean County, Pennsylvania........................................................$.70 per mcf (3)
 Clinton/Medina Geological Formation in New York............................................$.35 per mcf
 Clinton/Medina Geological Formation in Southern Ohio.......................................$.35 per mcf

- --------------
(1)   The gathering fee paid by each partnership must not exceed a competitive
      rate as determined by the managing general partner, and the managing
      general partner may increase or decrease the gathering fee to a
      competitive rate from time to time if conditions in the industry change.
(2)   Each partnership will use a gathering system provided by a third-party
      joint venture partner which will not charge the partnership a gathering
      fee if it markets the gas. If the managing general partner markets the gas
      for the partnership, then the partnership will pay a gathering fee to the
      managing general partner equal to that charged by the third-party, which
      the managing general partner anticipates will be $.20 per mcf.
(3)   In this area, a partnership will deliver gas into a gathering system a
      segment of which will be provided by Atlas Pipeline Partners and a segment
      of which will be provided by a third-party. The third-party will receive
      fees of $.25 per mcf for transportation and $.10 per mcf for compression.
      From the gathering fees charged the partnership by the managing general
      partner, the managing general partner will pay $.35 per mcf to the
      third-party and $.35 per mcf to Atlas Pipeline Partners.

                                       29

The actual amount of gathering fees to be paid by a partnership to the managing
general partner cannot be quantified because the volume of natural gas that will
be produced and transported from the partnership's wells cannot be predicted.

DEALER-MANAGER FEES
Subject to certain exceptions described in "Plan of Distribution," Anthem
Securities, the dealer-manager and an affiliate of the managing general partner,
will receive on each unit sold to an investor:

         o        a 2.5% dealer-manager fee;

         o        a 7% sales commission;

         o        a .5% reimbursement for accountable permissible non-cash
                  compensation; and

         o        an up to .5% reimbursement of the selling agents' bona fide
                  accountable due diligence expenses.

Assuming the above amounts are paid for all units sold, the dealer-manager will
receive:

         o        $210,000 if $2 million is received by a partnership; and

         o        $13,125,000 if $125 million is received by the partnerships.

All of the reimbursement of the selling agents' bona fide accountable due
diligence expenses, and generally all of the accountable permissible non-cash
compensation reimbursement and sales commissions, will be reallowed to the
selling agents. Most of the 2.5% dealer-manager fee will be reallowed to the
wholesalers who are associated with the managing general partner and registered
through Anthem Securities for subscriptions obtained through their efforts. The
dealer-manager will retain any of the compensation which is not reallowed.

See "Management" for the ownership of Anthem Securities.

INTEREST AND OTHER COMPENSATION
The managing general partner or an affiliate will have the right to charge a
competitive rate of interest on any loan it may make to or on behalf of a
partnership. If the managing general partner provides equipment, supplies, and
other services to a partnership, then it may do so at competitive industry
rates. The managing general partner will determine a competitive rate of
interest and competitive industry rates for equipment, supplies and other
services by conducting a survey of the interest and/or fees charged by
unaffiliated third-parties in the same geographic area engaged in similar
businesses. If possible, the managing general partner will contact at least two
unaffiliated third-parties, however, the managing general partner will have sole
discretion in determining the amount to be charged a partnership.

ESTIMATE OF ADMINISTRATIVE COSTS AND DIRECT COSTS TO BE BORNE BY THE
PARTNERSHIPS
The managing general partner and its affiliates will receive from each
partnership an unaccountable, fixed payment reimbursement for their
administrative costs, which has been determined by the managing general partner
to be $75 per well per month. This payment per well is subject to the following:

         o        it will not be increased in amount during the term of the
                  partnership;

         o        it will be proportionately reduced to the extent the
                  partnership acquires less than 100% of the working interest in
                  the well;

         o        it will be the entire payment to reimburse the managing
                  general partner for the partnership's administrative costs;
                  and

                                       30

         o        it will not be received for plugged or abandoned wells.

The managing general partner estimates that the unaccountable, fixed payment
reimbursement for administrative costs allocable to a partnership's first 12
months of operation after all of its wells have been placed into production will
not exceed approximately:

         o        $9,000 if $2 million is received, which is 10 net wells at
                  $75 per well per month; and

         o        $649,800 if $125 million is received, which is 722 net wells
                  at $75 per well per month.

Direct costs will be determined by the managing general partner, in its sole
discretion, including the provider of the services or goods and the amount of
the provider's compensation. Direct costs will be billed directly to and paid by
each partnership to the extent practicable. The anticipated direct costs set
forth below for a partnership's first 12 months of operation after all of its
wells have been placed into production may vary from the estimates shown for
numerous reasons which cannot accurately be predicted. These reasons include:

         o        the number of investors;

         o        the number of wells drilled;

         o        the partnership's degree of success in its activities;

         o        the extent of any production problems;

         o        inflation; and

         o        various other factors involving the administration of the
                  partnership.



                                                                             Minimum                 Maximum
                                                                          Subscriptions           Subscriptions
                                                                          of $2 million        of $125 million (1)
                                                                          -------------        -------------------
DIRECT COSTS
     External Legal....................................................      $ 6,000                $ 18,000
     Accounting Fees for Audit and Tax Preparation.....................       42,000                 126,000
     Independent Engineering Reports...................................        1,500                  40,000
                                                                             -------                --------
     TOTAL ............................................................      $49,500                $184,000
                                                                             =======                ========

- ---------
(1)      This assumes three partnerships are formed as described below in "Terms
         of the Offering - Subscription to a Partnership" and the targeted
         nonbinding subscriptions of each partnership are received.

                              TERMS OF THE OFFERING

SUBSCRIPTION TO A PARTNERSHIP
Atlas America Public #14-2004 Program will offer for sale an aggregate of $125
million of units in a series of up to three limited partnerships to be formed
under the Delaware Revised Uniform Limited Partnership Act. You may purchase
units only if you meet the suitability standards set forth below. The units will
be offered for sale over a period which may extend from the date of this
prospectus up to December 31, 2005, but may end earlier.

The minimum required aggregate subscription proceeds for the offering of units
in each partnership will be $2 million after the discounts described in "Plan of
Distribution" and excluding any subscriptions by the managing general partner or
its affiliates. If this minimum amount of aggregate subscriptions is not
received in the offering of units of any partnership by its offering termination
date, then the partnership will not be funded, and the escrow agent will
promptly return all subscription proceeds for that partnership to the respective
subscribers in full with any interest earned on the escrowed funds and without
deduction for any fees from the escrowed funds.

                                       31

Set forth below are the targeted subscriptions for each partnership, although
these targeted amounts are not mandatory and the managing general partner may
determine the subscription amount for each partnership in its sole discretion.
The maximum subscription of any partnership must be the lesser of:

         o        the registered amount of $125 million; or

         o        the number of units remaining unsold in any prior partnership
                  from the $125 million aggregate registration.

Also, the targeted ending dates for each partnership, which are not binding on
the partnerships except that the units in each partnership may not be offered
beyond that partnership's offering termination date, are set forth below.
Otherwise the managing general partner may close the offering of units in a
partnership before its targeted ending date or withdraw the offering of units in
the partnership at any time.


                                    REQUIRED         TARGETED          TARGETED         OFFERING
   PARTNERSHIP                      MINIMUM          SUBSCRIPTION      ENDING           TERMINATION
   NAME                             SUBSCRIPTION     PROCEEDS (2)      DATE (1)(2)      DATE (2)
   -----------                      ------------     ------------      -----------      -----------
 Atlas America Public #14-2004      $2 million       $50 million       12/31/04         12/31/04


         o        The units in the above partnership will be sold only during
                  2004.



 Atlas America Public #14-2005(A)   $2 million       $35 million       05/31/05         05/31/05
 Atlas America Public #14-2005(B)   $2 million       $40 million       08/31/05         12/31/05


         o        The units in the above partnerships will be sold only during
                  2005.

- ------------
(1)      The partnerships will conduct the offering of their respective units in
         a series. Thus, the offering of units in the partnerships designated
         Atlas America Public #14-2005(___) L.P. will not begin until the
         subscriptions for units in the prior partnership, if any, have reached
         the minimum subscriptions or that prior offering has ended.
(2)      The managing general partner may close the subscription period of any
         partnership at any time once the partnership is in receipt of the
         minimum required subscription proceeds.

Units are offered at a subscription price of $10,000 per unit, subject to
certain exceptions which are described in "Plan of Distribution," and must be
paid 100% in cash at the time of subscribing. The subscription price of the
units has been arbitrarily determined by the managing general partner because
the partnerships do not have any prior operations, assets, earnings, liabilities
or present value. Your minimum subscription is one unit; however, the managing
general partner, in its discretion, may accept one-half unit ($5,000)
subscriptions from you at any time in each partnership. Larger fractional
subscriptions will be accepted in $1,000 increments, beginning with either
$11,000, $12,000, etc. if you pay $10,000 for a full unit or $6,000, $7,000,
etc. if you pay $5,000 for a one-half unit.

You will have the election to purchase units in a partnership as either an
investor general partner or a limited partner. However, the managing general
partner will have exclusive management authority for each partnership. Each
partnership will be a separate business entity from the other partnerships.
Thus, as an investor, you will be a partner only in the partnership in which you
invest. You will have no interest in the business, assets or tax benefits of the
other partnerships unless you also invest in the other partnerships. Your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest.

PARTNERSHIP CLOSINGS AND ESCROW
Subscription proceeds for each partnership will be held in a separate interest
bearing escrow account at National City Bank of Pennsylvania until receipt of

                                       32

the minimum subscription proceeds. A partnership may not break escrow unless the
partnership is in receipt of subscription proceeds of $2 million after the
discounts described in "Plan of Distribution" and excluding any subscriptions by
the managing general partner or its affiliates. However, on receipt of the
minimum subscription proceeds and written instructions to the escrow agent from
the managing general partner and the dealer-manager, the managing general
partner on behalf of a partnership may:

         o        break escrow; and

         o        transfer the escrowed funds to a partnership account and begin
                  drilling operations as set forth in "- Activation of the
                  Partnerships," below.

At or about the time of the initial closing of a particular partnership, the
managing general partner anticipates it will supplement this prospectus to
reflect the results of the initial closing of that partnership.

If the minimum subscription proceeds are not received by the offering
termination date of a partnership, then the sums deposited in the escrow account
will be promptly returned to you and the other subscribers in that partnership
with interest and without deduction for any fees. In this regard, the latest
offering termination date is December 31, 2004, for Atlas America Public
#14-2004 L.P., May 31, 2005 for Atlas America Public #14-2005(A) L.P., and
December 31, 2005, for Atlas America Public #14-2005(B) L.P. Although the
managing general partner and its affiliates may buy up to 5% of the units, they
do not currently anticipate purchasing any units. If they do buy units, then
those units will not be applied towards the minimum subscription proceeds
required for a partnership to break escrow and begin operations.

You will receive interest on your subscription proceeds from the time they are
deposited in the escrow account, or the partnership account if you subscribe
after the minimum subscription proceeds have been received and escrow has been
broken, until the final closing of the partnership to which you subscribed. The
interest will be paid to you not later than your partnership's first cash
distribution from operations.

During each partnership's escrow period its subscription proceeds will be
invested only in institutional investments comprised of or secured by securities
of the United States government. After the funds are transferred to the
partnership account and before their use in partnership operations, they may be
temporarily invested in income producing short-term, highly liquid investments,
in which there is appropriate safety of principal, such as U.S. Treasury Bills.
If the managing general partner determines that a partnership may be deemed an
investment company under the Investment Company Act of 1940, then the investment
activity will cease. Subscription proceeds will not be commingled with the funds
of the managing general partner or its affiliates, nor will subscription
proceeds be subject to their creditors' claims before they are paid to the
managing general partner under the drilling and operating agreement.

ACCEPTANCE OF SUBSCRIPTIONS
You and the other investors should make your checks for units payable to "Atlas
America Public #14-2004 L.P., Escrow Agent, National City Bank of PA," or "Atlas
America Public #14-2005(___) L.P., Escrow Agent, National City Bank of PA," as
appropriate, and give your check to your broker/dealer for submission to the
dealer-manager and escrow agent. The managing general partner will place all
subscription proceeds of each partnership in an escrow account, or the
partnership account if you subscribe after the minimum subscription proceeds
have been received and escrow has been broken, until the final closing of the
partnership to which you subscribed.

Your execution of the subscription agreement constitutes your offer to buy units
in the partnership then being offered and to hold the offer open until either:

         o        your subscription is accepted or rejected by the managing
                  general partner; or

         o        you withdraw your offer.

To withdraw your offer, you must give written notice to the managing general
partner before your offer is accepted by the managing general partner. Your
subscription will be accepted or rejected by the partnership within 30 days of
its receipt. The managing general partner's acceptance of your subscription is
discretionary, and the managing general partner may reject your subscription for
any reason without incurring any liability to you for this decision. If your
subscription is rejected, then all of your funds will be promptly returned to
you together with any interest earned on your subscription proceeds.

                                       33

When you will be admitted to a partnership depends on whether your subscription
is accepted before or after breaking escrow. If your subscription is accepted:

         o        before breaking escrow, then you will be admitted to the
                  partnership to which you subscribed not later than 15 days
                  after the release from escrow of the investors' funds to that
                  partnership; and

         o        after breaking escrow, then you will be admitted to the
                  partnership to which you subscribed not later than the last
                  day of the calendar month in which your subscription was
                  accepted by that partnership.

Your execution of the subscription agreement and the managing general partner's
acceptance also constitutes your:

         o        execution of the partnership agreement and agreement to be
                  bound by its terms as a partner; and

         o        grant of a special power of attorney to the managing general
                  partner to file amended certificates of limited partnership
                  and governmental reports, and perform certain other actions on
                  behalf of you and the other investors.

ACTIVATION OF THE PARTNERSHIPS
The managing general partner will organize each partnership under the Delaware
Revised Uniform Limited Partnership Act before the initial closing of the
partnership and breaking escrow. In this regard, the first partnership in the
program, Atlas America Public #14-2004 L.P., has been formed as a Delaware
limited partnership. (See "Financial Information Concerning the Managing General
Partner and Atlas America Public #14-2004 L.P.") However, the other partnerships
have not yet been formed. The units offered in those partnerships in 2005 may be
preformation investor general partner interests and preformation limited partner
interests which will become units of investor general partner interests or
limited partner interests, respectively, in the particular partnership if it has
not been formed at the time you subscribe. After the initial closing of a
partnership and the transfer of the escrowed funds to a partnership account, the
managing general partner on behalf of a partnership may:

         o        enter into the drilling and operating agreement with itself or
                  an affiliate as operator; and

         o        begin drilling to the extent the prospects have been
                  identified in this prospectus or by a supplement or an
                  amendment to the registration statement of which this
                  prospectus is a part.

SUITABILITY STANDARDS
IN GENERAL. It is the obligation of persons selling the units to make every
reasonable effort to assure that the units are suitable for you based on your
investment objectives and financial situation, regardless of your income or net
worth. However, you should invest in a partnership only if you are willing to
assume the risk of a speculative, illiquid, and long-term investment. Also,
subscriptions to a partnership will not be accepted from IRAs, Keogh plans and
qualified retirement plans because the partnership's income would be
characterized as unrelated business taxable income, which is subject to federal
income tax.

The decision to accept or reject your subscription will be made by the managing
general partner, in its sole discretion, and is final. The managing general
partner will not accept your subscription until it has reviewed your apparent
qualifications, and the suitability determination must be maintained by the
managing general partner during the partnership's term and for at least six
years thereafter.

GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS. If you
are a resident of any of the following states or jurisdictions:


                                       34




o        ALABAMA,                     o        KENTUCKY,            o        OREGON,

o        ALASKA,                      o        LOUISIANA,           o        PENNSYLVANIA,

o        ARIZONA,                     o        MAINE,               o        RHODE ISLAND,

o        ARKANSAS,                    o        MARYLAND,            o        SOUTH CAROLINA,

o        COLORADO,                    o        MASSACHUSETTS,       o        SOUTH DAKOTA,

o        CONNECTICUT,                 o        MINNESOTA,           o        TENNESSEE,

o        DELAWARE,                    o        MISSISSIPPI,         o        TEXAS,

o        DISTRICT OF COLUMBIA,        o        MISSOURI,            o        UTAH,

o        FLORIDA,                     o        MONTANA,             o        VERMONT,

o        GEORGIA,                     o        NEBRASKA,            o        VIRGINIA,

o        HAWAII,                      o        NEVADA,              o        WASHINGTON,

o        IDAHO,                       o        NEW MEXICO,          o        WEST VIRGINIA,

o        ILLINOIS,                    o        NEW YORK,            o        WISCONSIN, OR

o        INDIANA,                     o        NORTH DAKOTA,        o        WYOMING,

o        IOWA,                        o        OHIO,

o        KANSAS,                      o        OKLAHOMA,


then units will be sold to you if you meet either of the following requirements:

         o        a minimum net worth of $225,000, exclusive of home, home
                  furnishings, and automobiles; or

         o        a minimum net worth of $60,000, exclusive of home, home
                  furnishings, and automobiles, and had during the last tax year
                  or estimate that you will have during the current tax year
                  "taxable income" as defined in Section 63 of the Internal
                  Revenue Code of at least $60,000, without regard to an
                  investment in the partnership.




In addition, if you are a resident of OHIO, or PENNSYLVANIA, then you must not
make an investment in a partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings and automobiles. Finally, if you are a
resident of KANSAS, it is recommended by the Office of the Kansas Securities
Commissioner that Kansas investors should limit their investment in the Program
and substantially similar programs to no more than 10% of their net worth,
excluding home, furnishings and automobiles.

However, if you are a resident of the states set forth below, then additional
suitability requirements apply to you.

SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS IN
CALIFORNIA, MICHIGAN, NEW HAMPSHIRE, NEW JERSEY AND NORTH CAROLINA.

         o        If you are a resident of CALIFORNIA or NEW JERSEY and you
                  purchase limited partner units, then you must meet any one of
                  the following special suitability requirements:

                  o        a net worth of not less than $250,000, exclusive of
                           home, home furnishings, and automobiles, and expect
                           to have gross income in the current tax year of
                           $65,000 or more; or

                  o        a net worth of not less than $500,000, exclusive of
                           home, home furnishings, and automobiles; or

                  o        a net worth of not less than $1 million; or

                  o        expected gross income in the current tax year of not
                           less than $200,000.

         o        If you are a resident of MICHIGAN or NORTH CAROLINA and you
                  purchase limited partner units, then you must meet either of
                  the following special suitability requirements:

                  o        a net worth of not less than $225,000, exclusive of
                           home, home furnishings, and automobiles; or

                  o        a net worth of not less than $60,000, exclusive of
                           home, home furnishings, and automobiles, and
                           estimated current tax year taxable income as defined
                           in Section 63 of the Internal Revenue Code of $60,000
                           or more without regard to an investment in the
                           partnership.

                  Additionally, if you are a resident of MICHIGAN, then you must
                  not make an investment in a partnership which is in excess of
                  10% of your net worth, exclusive of home, home furnishings and
                  automobiles.

         o        If you are a resident of NEW HAMPSHIRE and you purchase
                  limited partner units, then you must meet either of the
                  following special suitability requirements:

                  o        a net worth of not less than $250,000, exclusive of
                           home, home furnishings, and automobiles; or

                  o        a net worth of not less than $125,000, exclusive of
                           home, home furnishings, and automobiles and $50,000
                           of taxable income.







GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS. If you are a resident of any of the following states or jurisdictions:




o        ALASKA,                    o        ILLINOIS,            o        SOUTH CAROLINA,

o        COLORADO,                  o        LOUISIANA,           o        UTAH,

o        CONNECTICUT,               o        MARYLAND,            o        VIRGINIA,

o        DELAWARE,                  o        MONTANA,             o        WEST VIRGINIA,

o        DISTRICT OF COLUMBIA,      o        NEBRASKA,            o        WISCONSIN, OR

o        FLORIDA,                   o        NEVADA,              o        WYOMING,

o        GEORGIA,                   o        NEW YORK,

o        HAWAII,                    o        NORTH DAKOTA,

o        IDAHO,                     o        RHODE ISLAND,


then units will be sold to you if you meet either of the following requirements:

         o        a minimum net worth of $225,000, exclusive of home, home
                  furnishings, and automobiles; or

         o        a minimum net worth of $60,000, exclusive of home, home
                  furnishings, and automobiles, and had during the last tax year
                  or estimate that you will have during the current tax year
                  "taxable income" as defined in Section 63 of the Internal
                  Revenue Code of at least $60,000, without regard to an
                  investment in the partnership.

However, if you are a resident of the states set forth below, then additional
suitability requirements apply to you.

SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS IN EITHER: (I) ALABAMA, ARKANSAS, MAINE, MASSACHUSETTS, MINNESOTA, NORTH
CAROLINA, OHIO, OKLAHOMA, PENNSYLVANIA, TENNESSEE, TEXAS, OR WASHINGTON; OR (II)
ARIZONA, INDIANA, IOWA, KANSAS, KENTUCKY, MICHIGAN, MISSISSIPPI, MISSOURI, NEW
MEXICO, OREGON, SOUTH DAKOTA, OR VERMONT.

         o        If you are a resident of any of the following states:

                                       36





                     o        ALABAMA,            o        MINNESOTA,             o        PENNSYLVANIA,

                     o        ARKANSAS,           o        NORTH CAROLINA,        o        TENNESSEE,

                     o        MAINE,              o        OHIO,                  o        TEXAS, OR

                     o        MASSACHUSETTS,      o        OKLAHOMA,              o        WASHINGTON


                  and you purchase investor general partner units, then you must
                  meet any one of the following special suitability
                  requirements:

                  o        an individual or joint net worth with your spouse of
                           $225,000 or more, without regard to the investment in
                           the partnership, exclusive of home, home furnishings,
                           and automobiles, and A COMBINED GROSS INCOME OF
                           $100,000 OR MORE FOR THE CURRENT YEAR AND FOR THE TWO
                           PREVIOUS YEARS; or

                  o        an individual or joint net worth with your spouse in
                           excess of $1 million, inclusive of home, home
                           furnishings, and automobiles; or

                  o        an individual or joint net worth with your spouse in
                           excess of $500,000, exclusive of home, home
                           furnishings, and automobiles; or

                  o        a combined "gross income" as defined in Internal
                           Revenue Code Section 61 in excess of $200,000 in the
                           current year and the two previous years.

         o        In addition, if you are a resident of OHIO or PENNSYLVANIA,
                  then you must not make an investment in a partnership which is
                  in excess of 10% of your net worth, exclusive of home, home
                  furnishings, and automobiles.

         o        If you are a resident of any of the following states:





                     o        ARIZONA,        o        KENTUCKY,          o        NEW MEXICO,

                     o        INDIANA,        o        MICHIGAN,          o        OREGON,

                     o        IOWA,           o        MISSISSIPPI,       o        SOUTH DAKOTA, OR

                     o        KANSAS,         o        MISSOURI,          o        VERMONT


                  and you purchase investor general partner units, then you must
                  meet any one of the following special suitability
                  requirements:

                  o        an individual or joint net worth with your spouse of
                           $225,000 or more, without regard to the investment in
                           the partnership, exclusive of home, home furnishings,
                           and automobiles, and A COMBINED "TAXABLE INCOME" OF
                           $60,000 OR MORE FOR THE PREVIOUS YEAR AND EXPECT TO
                           HAVE A COMBINED "TAXABLE INCOME" OF $60,000 OR MORE
                           FOR THE CURRENT YEAR AND FOR THE SUCCEEDING YEAR; or

                  o        an individual or joint net worth with your spouse in
                           excess of $1 million, inclusive of home, home
                           furnishings, and automobiles; or

                  o        an individual or joint net worth with your spouse in
                           excess of $500,000, exclusive of home, home
                           furnishings, and automobiles; or

                  o        a combined "gross income" as defined in Internal
                           Revenue Code Section 61 in excess of $200,000 in the
                           current year and the two previous years.

                                       37

         o        In addition, if you are a resident of IOWA OR MICHIGAN, then
                  you must not make an investment in a partnership which is in
                  excess of 10% of your net worth, exclusive of home, home
                  furnishings, and automobiles.

         o        Finally, if you are a resident of Kansas, it is recommended by
                  the Office of the Kansas Securities Commissioner that Kansas
                  investors should limit their investment in the Program and
                  substantially similar programs to no more than 10% of their
                  net worth, excluding home, furnishings and automobiles.


SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS IN CALIFORNIA, NEW HAMPSHIRE OR NEW JERSEY.

         o        If you are a resident of CALIFORNIA and you purchase investor
                  general partner units, then you must meet any one of the
                  following special suitability requirements:

                  o        a net worth of not less than $250,000, exclusive of
                           home, home furnishings, and automobiles, and expect
                           to have gross income in the current tax year of
                           $120,000 or more; or

                  o        a net worth of not less than $500,000, exclusive of
                           home, home furnishings, and automobiles; or

                  o        a net worth of not less than $1 million; or

                  o        expected gross income in the current tax year of not
                           less than $200,000.

         o        If you are a resident of NEW HAMPSHIRE and you purchase
                  investor general partner units, then you must meet either of
                  the following special suitability requirements:

                  o        a net worth of not less than $250,000, exclusive of
                           home, home furnishings, and automobiles, of $250,000;
                           or

                  o        a net worth of not less than $125,000, exclusive of
                           home, home furnishings, and automobiles, of $125,000
                           and $50,000 of taxable income.

FIDUCIARY ACCOUNTS AND CONFIRMATIONS. If there is a sale of a unit to a
fiduciary account, then all the suitability standards set forth above must be
met by:

         o        the beneficiary;

         o        the fiduciary account; or

         o        the donor or grantor who directly or indirectly supplies the
                  funds to purchase the units if the donor or grantor is the
                  fiduciary.

Generally, you are required to execute your own subscription agreement, and the
managing general partner will not accept any subscription agreement that has
been executed by someone other than you. The only exception is if you have given
someone else the legal power of attorney to sign on your behalf and you meet all
of the conditions in this prospectus. Also, the managing general partner will:

         o        not complete a sale of units to you until at least five
                  business days after the date you receive a final prospectus;
                  and

         o        send you a confirmation of purchase.

                                       38

                                PRIOR ACTIVITIES


The following tables reflect certain historical data with respect to 34 private
drilling partnerships which raised a total of $195,300,802, and 12 public
drilling partnerships which raised a total of $167,610,898, that the managing
general partner has sponsored. The tables also reflect certain historical data
with respect to 1999 Viking Resources LP, a private drilling program which
raised $4,555,210, and is the only drilling program sponsored by Viking
Resources after it was acquired by Resource America, Inc. in August 1999.
Information concerning other programs sponsored by Viking Resources before it
was acquired by Resource America will be provided to you on written request to
the managing general partner. Additional information concerning this program
will be provided on written request to the managing general partner. The tables
also do not include information concerning wells acquired by Atlas Resources
through merger or other form of acquisition and this information also will be
available on written request.


Although past performance is no guarantee of future results, the investor
general partners in the managing general partner's prior partnerships have not
had to make additional capital contributions to their partnerships because of
their status as investor general partners.

IT SHOULD NOT BE ASSUMED THAT YOU AND THE OTHER INVESTORS WILL EXPERIENCE
RETURNS, IF ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS IN THE PRIOR
DRILLING PARTNERSHIPS FOR SEVERAL REASONS, INCLUDING, BUT NOT LIMITED TO,
DIFFERENCES IN:

         o        PARTNERSHIP TERMS;

         o        PROPERTY LOCATIONS;

         o        PARTNERSHIP SIZE; AND

         o        ECONOMIC CONSIDERATIONS.

THE RESULTS OF THE PRIOR DRILLING PARTNERSHIPS SHOULD BE VIEWED ONLY AS A
MEASURE OF THE LEVEL OF ACTIVITY AND EXPERIENCE OF THE MANAGING GENERAL PARTNER
WITH RESPECT TO DRILLING PARTNERSHIPS.


                                       39



Table 1 sets forth certain sales information of previous development drilling
partnerships sponsored by the managing general partner and its affiliates.

                                     TABLE 1
                           EXPERIENCE IN RAISING FUNDS
                               AS OF JULY 15, 2004



                                                                             Managing
                                               Number                         General
                                                 of             Investor      Partner
       Partnership                           Investors           Capital      Capital
       -----------                          -----------       -----------    ---------
1.     Atlas L.P. #1 - 1985                      19             $600,000       $114,800
2.     A.E. Partners 1986                        24              631,250        120,400
3.     A.E. Partners 1987                        17              721,000        158,269
4.     A.E. Partners 1988                        21              617,050        135,450
5.     A.E. Partners 1989                        21              550,000        120,731
6.     A.E. Partners 1990                        27              887,500        244,622
7.     A.E. Nineties-10                          60            2,200,000        484,380
8.     A.E. Nineties-11                          25              750,000        268,003
9.     A.E. Partners 1991                        26              868,750        318,063
10.    A.E. Nineties-12                          87            2,212,500        791,833
11.    A.E. Nineties-JV 92                      155            4,004,813      1,414,917
12.    A.E. Partners 1992                        21              600,000        176,100
13.    A.E. Nineties-Public #1                  221            2,988,960        528,934
14.    A.E. Nineties-1993 Ltd.                  125            3,753,937      1,264,183
15.    A.E. Partners 1993                        21              700,000        219,600
16.    A.E. Nineties-Public #2                  269            3,323,920        587,340
17.    A.E. Nineties-14                         263            9,940,045      3,584,027
18.    A.E. Partners 1994                        23              892,500        231,500
19.    A.E. Nineties-Public #3                  391            5,800,990        928,546
20.    A.E. Nineties-15                         244           10,954,715      3,435,936
21.    A.E. Partners 1995                        23              600,000        244,725
22.    A.E. Nineties-Public #4                  324            6,991,350      1,287,752
23.    A.E. Nineties-16                         274           10,955,465      1,643,320
24.    A.E. Partners 1996                        21              800,000        367,416
25.    A.E. Nineties-Public #5                  378            7,992,240      1,654,740
26.    A.E. Nineties-17                         217            8,813,488      2,113,947
27.    A.E. Nineties-Public #6                  393            9,901,025      1,950,345
28.    A.E. Partners 1997                        13              506,250        231,050
29.    A.E. Nineties-18                         225           11,391,673      3,448,751
30.    A.E. Nineties-Public #7                  366           11,988,350      3,812,150
31.    A.E. Partners 1998                        26            1,740,000        756,360
32.    A.E. Nineties-19                         288           15,720,450      4,776,598
33.    A.E. Nineties-Public #8                  380           11,088,975      3,148,181
34.    A.E. Partners 1999                        8               450,000        196,500
35.    1999 Viking Resources LP                 131            4,555,210      1,678,038
36.    Atlas America-Series 20                  361           18,809,150      6,297,945
37.    Atlas America - Public #9                530           14,905,465      5,563,527
38.    Atlas America - Series 21-A              282           12,510,713      4,535,799
39.    Atlas America - Series 21-B              360           17,411,825      6,442,761
40.    Atlas America - Public #10               818           21,281,170      7,227,432
41.    Atlas America - Series 22                258           10,156,375      3,481,591
42.    Atlas America - Series 23                246            9,644,550      3,214,850
43.    Atlas America - Public #11               1017          31,178,145     11,757,568
44.    Atlas America - Series #24-2003 (A)      325           14,363,955      4,949,143
45.    Atlas America - Series #24-2003 (B)      422           20,542,850      7,300,020
46.    Atlas America - Public #12-2003          1102          40,170,308     13,708,076
47.    Atlas America Series # 25-2004 (A)       635           27,601,053     10,266,771




[RESTUBBED TABLE]



                                                                                           Years
                                                              Date         Date of         Wells     Previous
                                                 Total     Operations        First           In       Assess-
       Partnership                              Capital      Began       Distributions   Production    ments
       -----------                             ---------    ---------    --------------  -----------  -------
1.     Atlas L.P. #1 - 1985                      $714,800     12/31/85       07/02/86        18.55     -0-
2.     A.E. Partners 1986                         751,650     12/31/86       04/02/87        17.55     -0-
3.     A.E. Partners 1987                         879,269     12/31/87       04/02/88        16.55     -0-
4.     A.E. Partners 1988                         752,500     12/31/88       04/02/89        15.55     -0-
5.     A.E. Partners 1989                         670,731     12/31/89       04/02/90        14.55     -0-
6.     A.E. Partners 1990                       1,132,122     12/31/90       04/02/91        13.55     -0-
7.     A.E. Nineties-10                         2,684,380     12/31/90       03/31/91        13.33     -0-
8.     A.E. Nineties-11                         1,018,003     09/30/91       01/31/92        12.50     -0-
9.     A.E. Partners 1991                       1,186,813     12/31/91       04/02/92        12.33     -0-
10.    A.E. Nineties-12                         3,004,333     12/31/91       04/30/92        12.25     -0-
11.    A.E. Nineties-JV 92                      5,419,730     10/28/92       04/05/93        11.58     -0-
12.    A.E. Partners 1992                         776,100     12/14/92       07/02/93        11.08     -0-
13.    A.E. Nineties-Public #1                  3,517,894     12/31/92       07/15/93        10.83     -0-
14.    A.E. Nineties-1993 Ltd.                  5,018,120     10/08/93       02/10/94        10.50     -0-
15.    A.E. Partners 1993                         919,600     12/31/93       07/02/94        10.25     -0-
16.    A.E. Nineties-Public #2                  3,911,260     12/31/93       06/15/94        10.00     -0-
17.    A.E. Nineties-14                        13,524,072     08/11/94       01/10/95         9.50     -0-
18.    A.E. Partners 1994                       1,124,000     12/31/94       07/02/95         9.25     -0-
19.    A.E. Nineties-Public #3                  6,729,536     12/31/94       06/05/95         9.25     -0-
20.    A.E. Nineties-15                        14,390,651     09/12/95       02/07/96         8.42     -0-
21.    A.E. Partners 1995                         844,725     12/31/95       10/02/96         8.00     -0-
22.    A.E. Nineties-Public #4                  8,279,102     12/31/95       07/08/96         8.25     -0-
23.    A.E. Nineties-16                        12,598,785     07/31/96       01/12/97         7.58     -0-
24.    A.E. Partners 1996                       1,167,416     12/31/96       07/02/97         7.25     -0-
25.    A.E. Nineties-Public #5                  9,646,980     12/31/96       06/08/97         7.25     -0-
26.    A.E. Nineties-17                        10,927,435     08/29/97       12/12/97         6.67     -0-
27.    A.E. Nineties-Public #6                 11,851,370     12/31/97       06/08/98         6.25     -0-
28.    A.E. Partners 1997                         737,300     12/31/97       07/02/98         6.08     -0-
29.    A.E. Nineties-18                        14,840,424     07/31/98       01/07/99         5.33     -0-
30.    A.E. Nineties-Public #7                 15,800,500     12/31/98       07/10/99         5.00     -0-
31.    A.E. Partners 1998                       2,496,360     12/31/98       07/02/99         5.00     -0-
32.    A.E. Nineties-19                        20,497,048     09/30/99       01/14/00         4.50     -0-
33.    A.E. Nineties-Public #8                 14,237,156     12/31/99       06/09/00         4.00     -0-
34.    A.E. Partners 1999                         646,500     12/31/99       10/02/00         4.00     -0-
35.    1999 Viking Resources LP                 6,233,248     12/31/99       06/01/00         4.00     -0-
36.    Atlas America-Series 20                 25,107,095     09/30/00       01/30/01         3.75     -0-
37.    Atlas America - Public #9               20,468,992     12/31/00       07/13/01         3.35     -0-
38.    Atlas America - Series 21-A             17,046,512     05/15/01       11/16/01         3.10     -0-
39.    Atlas America - Series 21-B             23,854,586     09/19/01       03/02/02         2.50     -0-
40.    Atlas America - Public #10              28,508,602     12/31/01       06/20/02         2.25     -0-
41.    Atlas America - Series 22               13,637,966     05/31/02       11/12/02         1.75     -0-
42.    Atlas America - Series 23               12,859,400     09/30/02       02/18/03          1.5     -0-
43.    Atlas America - Public #11              42,935,713     12/31/02      7/15/2003         1.25     -0-
44.    Atlas America - Series #24-2003 (A)     19,313,098     05/31/03       12/05/03          .75     -0-
45.    Atlas America - Series #24-2003 (B)     27,842,870     08/29/03       02/05/04           .5     -0-
46.    Atlas America - Public #12-2003         53,878,384     12/31/03        6/15/04          .25     -0-
47.    Atlas America Series # 25-2004 (A)      37,867,824     05/31/04             (1)          (1)    -0-


- ---------
(1)   This program closed May 31, 2003, and its first distribution is
      expected in the late Fall 2004.

                                       40



Table 2 reflects the drilling activity of previous development drilling
partnerships sponsored by the managing general partner and its affiliates. All
the wells were development wells. You should not assume that the past
performance of prior partnerships is indicative of the future results of the
partnerships.



                                     TABLE 2
                       WELL STATISTICS - DEVELOPMENT WELLS
                               AS OF JULY 15, 2004



                                                             GROSS WELLS (1)                           NET WELLS (2)
                                                -----------------------------------          ------------------------------------
      Partnership                                  Oil           Gas        Dry (3)           Oil           Gas           Dry (3)
      -----------                               --------       -------     --------          -----        -------         -------
1.    Atlas L.P. #1 - 1985                           0             6          1                0            2.83            0.50
2.    A.E. Partners 1986                             0             8          0                0            3.50            0.00
3.    A.E. Partners 1987                             0             9          0                0            4.10            0.00
4.    A.E. Partners 1988                             0             9          0                0            3.80            0.00
5.    A.E. Partners 1989                             0            10          0                0            3.30            0.00
6.    A.E. Partners 1990                             0            12          0                0            5.00            0.00
7.    A.E. Nineties-10                               0            12          0                0           11.50            0.00
8.    A.E. Nineties-11                               0            14          0                0            4.30            0.00
9.    A.E. Partners 1991                             0            12          0                0            4.95            0.00
10.   A.E. Nineties-12                               0            14          0                0           12.50            0.00
11.   A.E. Nineties-JV 92                            0            52          0                0           24.44            0.00
12.   A.E. Partners 1992                             0             7          0                0            3.50            0.00
13.   A.E. Nineties-Public #1                        0            14          0                0           14.00            0.00
14.   A.E. Nineties-1993 Ltd.                        0            20          1                0           19.40            1.00
15.   A.E. Partners 1993                             0             8          0                0            4.00            0.00
16.   A.E. Nineties-Public #2                        0            16          0                0           15.31            0.00
17.   A.E. Nineties-14                               0            53          2                0           53.00            2.00
18.   A.E. Partners 1994                             0            12          0                0            5.00            0.00
19.   A.E. Nineties-Public #3                        0            26          1                0           25.50            1.00
20.   A.E. Nineties-15                               0            61          1                0           55.50            1.00
21.   A.E. Partners 1995                             0             6          0                0            3.00            0.00
22.   A.E. Nineties-Public #4                        0            32          0                0           30.50            0.00
23.   A.E. Nineties-16                               0            51          6                0           40.50            4.50
24.   A.E. Partners 1996                             0            13          0                0            4.84            0.00
25.   A.E. Nineties-Public #5                        0            36          0                0           35.91            0.00
26.   A.E. Nineties-17                               0            47          5                0           42.00            3.50
27.   A.E. Nineties-Public #6                        0            55          0                0           44.45            0.00
28.   A.E. Partners 1997                             0             6          0                0            2.81            0.00
29.   A.E. Nineties-18                               0            63          0                0           58.00            0.00
30.   A.E. Nineties-Public #7                        0            64          0                0           57.50            0.00
31.   A.E. Partners 1998                             0            19          0                0            9.50            0.00
32.   A.E. Nineties-19                               0            82          4                0           75.75            4.00
33.   A.E. Nineties-Public #8                        0            58          0                0           54.66            0.00
34.   A.E. Partners 1999                             0             5          0                0            2.50            0.00
35.   1999 Viking Resources LP                       0            23          2                0           23.00            2.00
36.   Atlas America - Series 20                      0           106          1                0          100.25            1.00
37.   Atlas America - Public #9                      0            83          2                0           78.75            2.00
38.   Atlas America - Series 21-A                    0            68          0                0           62.50            0.00
39.   Atlas America - Series 21-B                    0            89          2                0           84.05            1.00
40.   Atlas America - Public #10                     0           107          3                0          100.15            3.00
41.   Atlas America - Series 22                      0            51          1                0           49.55            1.00
42.   Atlas America - Series 23                      0            47          1                0           47.00            1.00
43.   Atlas America - Public #11                     0           167          0                0          160.50            0.00
44.   Atlas America-Series #24-A (2003)              0            76          0                0           69.50            0.00
45.   Atlas America-Series #24-B (2003)              0           121          1                0          113.00            1.00
46.   Atlas America-Public #12-2003                  0           226          1                0          214.25            1.00
47.   Atlas America Series # 25-2004 (A)             0            77          1                0           75.70            1.00
                                                -------       -------       -------       -------       ---------        --------
                                                     0          2153          36               0         1915.55           31.50
                                                -------       -------       -------       -------       ---------        --------

- ----------------
(1)   A "gross well" is one in which a leasehold interest is owned.
(2)   A "net well" equals the actual leasehold interest owned in one gross well
      divided by one hundred. For example, a 50% leasehold interest in a well is
      one gross well, but a .50 net well. (3) For purposes of this Table only, a
      "Dry Hole" means a well which is plugged and abandoned with or without a
      completion attempt because the operator has determined that it will not be
      productive of gas and/or oil in commercial quantities.


                                       41


Table 3 provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates. You should not assume that the past performance of prior
partnerships is indicative of the future results of the partnerships.

                                     TABLE 3
                 INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
                               AS OF JULY 15, 2004




                                                                          TOTAL COSTS
                                                 Investor    -------------------------------------      Cash               Cash
        Partnership                              Capital (1) Operating (6)     Admin.      Direct  Distributions (2)(4)  Return (4)
        -----------                            ------------  -------------   ---------   --------   -------------------   ----------
1.      Atlas L.P. #1 - 1985                       $600,000     $219,393      $44,927     $12,862      $1,583,604           264%
2.      A.E. Partners 1986                          631,250      173,662       71,795      11,835         748,389           119%
3.      A.E. Partners 1987                          721,000      173,980       61,301      11,954         758,653           105%
4.      A.E. Partners 1988                          617,050      145,219       58,515      10,855         696,790           113%
5.      A.E. Partners 1989                          550,000      140,916       62,870      10,591         876,019           159%
6.      A.E. Partners 1990                          887,500      212,728       90,050      14,402       1,264,697           143%
7.      A.E. Nineties - 10                        2,200,000      448,433       99,264      36,765       1,901,458            86%
8.      A.E. Nineties - 11                          750,000      171,050       99,319      65,543       1,075,969           143%
9.      A.E. Partners 1991                          868,750      190,710      116,618      24,544       1,360,117           157%
10.     A.E. Nineties - 12                        2,212,500      450,940       98,125     130,895       2,070,134            94%
11.     A.E. Nineties - JV 92                     4,004,813      756,667      156,297     223,310       4,374,546 (3)       109%
12.     A.E. Partners 1992                          600,000      108,184       58,013      12,429         910,621           152%
13.     A.E. Nineties - Public  #1                2,988,960      478,821       99,124     121,049       2,377,919            80%
14.     A.E. Nineties - 1993 Ltd.                 3,753,937      543,136      107,273      58,313       2,218,614            59%
15.     A.E. Partners 1993                          700,000      141,061       42,788      11,742       1,065,550           152%
16.     A.E. Nineties - Public  #2                3,323,920      469,324       86,152      80,248       2,227,259            67%
17.     A.E. Nineties - 14                        9,940,045    1,431,200      275,902      75,223       5,963,056            60%
18.     A.E. Partners 1994                          892,500      141,868       51,768      14,629       1,118,789           125%
19.     A.E. Nineties - Public  #3                5,800,990      754,292      145,325      90,215       3,872,384            67%
20.     A.E. Nineties - 15                       10,954,715    1,427,770      275,355      71,906       7,511,889            69%
21.     A.E. Partners 1995                          600,000       82,485       19,983       8,759         381,116            64%
22.     A.E. Nineties - Public  #4                6,991,350      880,305      161,965      83,793       3,275,803            47%
23.     A.E. Nineties - 16                       10,955,465    1,224,443      207,069      89,343       5,356,626            49%
24.     A.E. Partners 1996                          800,000      114,768       25,901      45,937         532,552            67%
25.     A.E. Nineties - Public  #5                7,992,240      852,608      154,624      82,934       3,814,292            48%
26.     A.E. Nineties - 17                        8,813,488      925,198      155,534     146,200       4,930,512            56%
27.     A.E. Nineties - Public  #6                9,901,025    1,057,680      175,401      95,987       5,434,682            55%
28.     A.E. Partners 1997                          506,250       66,354       14,703      30,880         365,500            72%
29.     A.E. Nineties - 18                       11,391,673    1,171,622      185,869     266,519       5,620,222            49%
30.     A.E. Nineties - Public  #7               11,988,350    1,056,969      157,619      62,178       4,346,410            36%
31.     A.E. Partners 1998                        1,740,000      201,490       25,625      55,078       1,087,124            62%
32.     A.E. Nineties - 19                       15,720,450    1,354,713      196,064      15,313       6,126,043            39%
33.     A.E. Nineties - Public  #8               11,088,975      863,865      129,049      73,103       4,503,089            41%
34.     A.E. Partners 1999                          450,000       32,843        4,116      10,781         339,680            75%
35.     1999 Viking Resources LP                  4,555,210    1,252,002            0     170,741       6,154,960           135%
36.     Atlas America - Series 20                18,809,150    2,300,646      205,022     124,066      11,861,486            63%
37.     Atlas America - Public  #9               14,905,465    1,459,500      143,069      57,359       6,701,589            45%
38.     Atlas America - Series 21-A              12,510,713      868,689       97,217      10,216       4,413,615            35%
39.     Atlas America - Series 21-B              17,411,825    1,055,171      112,679      10,092       5,133,933            29%
40.     Atlas America - Public #10               21,281,170    1,197,608      126,167      46,632       6,799,837            32%
41.     Atlas America - Series 22                10,156,375      482,482       50,997       7,463       3,363,268            33%

42.     Atlas America - Series 23                 9,644,550      421,707       42,636       7,182       2,576,570            27%
43.     Atlas America - Public #11               31,178,145      896,661       91,591      25,806       5,850,986            19%

44.     Atlas America - Series 24-2003 (A) (5)   14,363,955      236,682       26,262       4,188       1,365,277            10%
45.     Atlas America - Series 24-2003 (B) (5)   20,542,850      213,651       25,280       4,090       1,650,218             8%
46.     Atlas America - Public #12-2003 (5)      40,170,308       50,446        8,069      13,178         281,957             1%
47.     Atlas America Series # 25-2004 (A) (5)   27,601,053            0            0           0               0             0%





[RESTUBBED TABLE]


                                                                           Estimated Future          Present Value of Estimated
                                               Latest Quarterly          Net Cash Flows from      Future Net Cash Flows from Proved
                                               Cash Distribution        Proved Reserves as of      Reserves Discounted at 10% as of
        Partnership                            As of Date of Table      January 1, 2004 (8) (9)        January 1, 2004 (8) (10)
- ------------------------------------------------------------------------------------------------------------------------------------
1.      Atlas L.P. #1 - 1985                          $14,419                        (7)                             (7)
2.      A.E. Partners 1986                              6,953                        (7)                             (7)
3.      A.E. Partners 1987                              7,343                        (7)                             (7)
4.      A.E. Partners 1988                              6,715                        (7)                             (7)
5.      A.E. Partners 1989                              9,336                        (7)                             (7)
6.      A.E. Partners 1990                             15,504                        (7)                             (7)
7.      A.E. Nineties - 10                             31,196                 2,177,542                       1,036,946
8.      A.E. Nineties - 11                             11,129                   674,653                         342,924
9.      A.E. Partners 1991                             16,554                        (7)                             (7)
10.     A.E. Nineties - 12                            109,584                 1,532,203                         784,424
11.     A.E. Nineties - JV 92                          73,423                 3,376,157                       1,658,496
12.     A.E. Partners 1992                              9,630                        (7)                             (7)
13.     A.E. Nineties - Public  #1                     29,691                 2,069,313                       1,036,487
14.     A.E. Nineties - 1993 Ltd.                      15,698                   972,192                         543,842
15.     A.E. Partners 1993                             12,945                        (7)                             (7)
16.     A.E. Nineties - Public  #2                     41,126                 2,657,838                       1,246,663
17.     A.E. Nineties - 14                             83,384                 5,020,367                       2,588,203
18.     A.E. Partners 1994                             21,417                        (7)                             (7)
19.     A.E. Nineties - Public  #3                     66,511                 3,949,556                       1,932,637
20.     A.E. Nineties - 15                            198,421                 8,315,478                       4,140,949
21.     A.E. Partners 1995                              5,284                        (7)                             (7)
22.     A.E. Nineties - Public  #4                     67,519                 4,030,938                       2,012,399
23.     A.E. Nineties - 16                            189,251                 7,786,397                       3,820,440
24.     A.E. Partners 1996                             15,973                        (7)                             (7)
25.     A.E. Nineties - Public  #5                     90,849                 5,467,002                       2,706,277
26.     A.E. Nineties - 17                            157,613                 8,402,544                       4,103,870
27.     A.E. Nineties - Public  #6                    171,696                 9,352,853                       4,606,067
28.     A.E. Partners 1997                             12,825                        (7)                             (7)
29.     A.E. Nineties - 18                            251,932                 8,951,046                       4,645,657
30.     A.E. Nineties - Public  #7                    140,488                 6,113,949                       3,231,862
31.     A.E. Partners 1998                             37,907                        (7)                             (7)
32.     A.E. Nineties - 19                            280,524                 9,972,011                       5,241,372
33.     A.E. Nineties - Public  #8                    194,973                 7,121,442                       3,873,011
34.     A.E. Partners 1999                              9,126                        (7)                             (7)
35.     1999 Viking Resources LP                      233,535                        (7)                             (7)
36.     Atlas America - Series 20                     521,308                18,847,947                      10,051,213
37.     Atlas America - Public  #9                    398,024                14,747,539                       7,686,704
38.     Atlas America - Series 21-A                   391,543                13,220,267                       7,099,896
39.     Atlas America - Series 21-B                   526,361                17,525,890                       9,467,539
40.     Atlas America - Public #10                    737,453                21,608,356                      11,856,286
41.     Atlas America - Series 22                     444,995                14,439,110                       7,669,447

42.     Atlas America - Series 23                     497,373                 8,753,542                       5,324,954
43.     Atlas America - Public #11                  1,541,662                31,239,303                      18,758,873

44.     Atlas America - Series 24-2003 (A) (5)        648,385                        (7)                             (7)
45.     Atlas America - Series 24-2003 (B) (5)      1,134,939                        (7)                             (7)
46.     Atlas America - Public #12-2003 (5)           281,957                20,203,301                      12,219,333
47.     Atlas America Series # 25-2004 (A) (5)              0                        (7)                             (7)


                                       42


- ---------
(1)   There have been no partnership borrowings other than from the managing
      general partner. The approximate principal amounts of such borrowings are
      as follows:

        o   A.E. Nineties-10 - $330,000; and
        o   A.E. Nineties-11 - $125,000; and
        o   A.E. Nineties-12 - $365,500.

        A portion of each partnership's cash distributions was used to repay
that partnership's loan.

(2)   All cash distributions were from the sale of gas, and not sales of
      properties.
(3)   A portion of the cash distributions was used to drill three reinvestment
      wells at a cost of $307,434 in accordance with the terms of the offering.
(4)   This column reflects total cash distributions beginning with the first
      production from the program as a percentage of the total amount invested
      in the program and includes the return of the investors' capital.
(5)   As of the date of this table there is not twelve months of production
      and/or not all of the wells are drilled or on-line to sell production.
(6)   Operating costs consist of gathering fees, water hauling fees, meter
      reading fees, repairs and maintenance, insurance and severance tax.
(7)   Current reserve information is either not available for these partnerships
      or has been prepared more than 15 months before this prospectus. Also,
      reserve information for Public # 12-2003 which closed at 12/31/03 is
      incomplete since not all of its wells were drilled at 1/1/04.
(8)   The information presented in this column has been prepared in conformity
      with SEC guidelines by making the standardized estimates of future net
      cash flow from proved reserves using natural gas and oil prices in effect
      as of the date of the estimates, which was a weighted average price of
      $6.69 per mcf for the natural gas, and which are held constant throughout
      the life of the properties. The information presented for future net cash
      flows based on estimated proved reserves has been prepared by the managing
      general partner's petroleum engineers and reviewed by an independent
      petroleum consultant, Wright & Company, Inc., as noted below with respect
      to the managing general partner's prior public partnerships: Atlas-Energy
      for the Nineties-Public #1 Ltd., Atlas-Energy for the Nineties-Public #2
      Ltd., Atlas-Energy for the Nineties-Public #3 Ltd., Atlas-Energy for the
      Nineties-Public #4 Ltd., Atlas-Energy for the Nineties-Public #5 Ltd.,
      Atlas-Energy for the Nineties-Public #6 Ltd., Atlas-Energy for the
      Nineties-Public #7 Ltd., Atlas-Energy for the Nineties-Public #8 Ltd.,
      Atlas America Public #9 Ltd., Atlas America Public #10 Ltd., Atlas America
      Public #11-2002 Ltd. and Atlas America Public #12-2003 Limited
      Partnership. The other partnerships have not been reviewed by Wright &
      Company, Inc. You should understand that reserve estimates are imprecise
      and may change. There are inherent uncertainties in interpreting the
      engineering data and the projection of future rates of production. Also,
      prices received from the sale of natural gas and oil may be different from
      those estimated in preparing the reports, and the amounts and timing of
      future operating and development costs may also differ from those used.
      The cash flow information based on estimated proved reserves shown for a
      partnership does not include this information for the managing general
      partner.
(9)   This column represents a partnership's estimate of future net cash flows
      from its proved reserves using natural gas sales prices in effect as of
      the dates of the estimates which are held constant throughout the life of
      the partnership's properties. As natural gas prices change, these
      estimates will change. The information in this column has not been
      discounted.
(10)  This column represents a partnership's estimate of future net cash flows
      from its proved reserves using natural gas sales prices in effect as of
      the dates of the estimates which are held constant throughout the life of
      the partnership's properties. As natural gas prices change, these
      estimates will change. The present value of estimated future net cash
      flows is calculated by discounting estimated future net cash flows by 10%
      annually in accordance with SEC guidelines. You should not construe the
      estimated PV-10 values as representative of the fair market value of a
      partnership's properties.

                                       43







Table 3A provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates.

                                    TABLE 3A
                            MANAGING GENERAL PARTNER
                     OPERATING RESULTS - INCLUDING EXPENSES
                               AS OF JULY 15, 2004



                                                                                     Total Costs
                                                   Managing General   --------------------------------------------
      Partnership                                   Partner Capital   Operating (3)      Admin.          Direct
      -----------                                 -----------------   --------------    ---------        --------
1.    Atlas L.P. #1 - 1985                             $114,800            $41,789          $8,557         $2,450
2.    A.E. Partners 1986                                120,400             33,078          13,675          2,254
3.    A.E. Partners 1987                                158,269             50,163          17,675          3,447
4.    A.E. Partners 1988                                135,450             46,768          18,845          3,496
5.    A.E. Partners 1989                                120,731             30,933          13,801          2,325
6.    A.E. Partners 1990                                244,622             70,909               0              0
7.    A.E. Nineties - 10                                484,380            149,478               0              0
8.    A.E. Nineties - 11                                268,003             73,307          42,565         23,032
9.    A.E. Partners 1991                                318,063             63,570               0              0
10.   A.E. Nineties - 12                                791,833            193,260          42,054         30,591
11.   A.E. Nineties - JV 92                           1,414,917            372,687          76,982         28,449
12.   A.E. Partners 1992                                176,100             36,061               0              0
13.   A.E. Nineties - Public  #1                        528,934            151,207          31,302         26,419
14.   A.E. Nineties - 1993 Ltd.                       1,264,183            232,773          45,974         21,409
15.   A.E. Partners 1993                                219,600             47,020               0              0
16.   A.E. Nineties - Public  #2                        587,340            148,208          27,206         25,342
17.   A.E. Nineties - 14                              3,584,027            704,919         135,892         29,871
18.   A.E. Partners 1994                                231,500             47,289               0              0
19.   A.E. Nineties - Public  #3                        928,546            251,431          48,442         30,072
20.   A.E. Nineties - 15                              3,435,936            611,901         118,009         30,817
21.   A.E. Partners 1995                                244,725             27,495               0              0
22.   A.E. Nineties - Public  #4                      1,287,752            293,435          53,988         27,931
23.   A.E. Nineties - 16                              1,643,320            335,357          56,713         19,664
24.   A.E. Partners 1996                                367,416             38,256               0              0
25.   A.E. Nineties - Public  #5                      1,654,740            284,203          51,541         27,645
26.   A.E. Nineties - 17                              2,113,947            333,575          56,077         23,367
27.   A.E. Nineties - Public  #6                      1,950,345            352,560          58,467         31,996
28.   A.E. Partners 1997                                231,050             22,118               0              0
29.   A.E. Nineties - 18                              3,448,751            538,775          85,473          9,689
30.   A.E. Nineties - Public  #7                      3,812,150            474,870          70,814         27,935
31.   A.E. Partners 1998                                756,360             67,163               0              0
32.   A.E. Nineties - 19                              4,776,598            622,970          90,161          7,042
33.   A.E. Nineties - Public  #8                      3,148,181            352,846          52,710         29,859
34.   A.E. Partners 1999                                196,500             10,948               0              0
35.   1999 Viking Resources LP                        1,678,038            417,334               0         56,914
36.   Atlas America - Series 20                       6,297,945            850,924          75,830         45,888
37.   Atlas America - Public  #9                      5,563,527            596,134          58,437         23,429
38.   Atlas America - Series 21-A                     4,535,799            444,196          49,711          5,224
39.   Atlas America - Series 21-B                     6,442,761            543,573          58,047          5,199
40.   Atlas America - Public #10                      7,227,432            563,583          59,372         21,945
41.   Atlas America - Series 22                       3,481,591            232,625          23,999          3,598

42.   Atlas America - Series 23                       3,214,850            198,454          20,064          3,380
43.   Atlas America - Public #11                     11,757,568            461,916          47,183         13,294

44.   Atlas America - Series 24-2003(A) (2)           4,949,143            114,635          12,720          2,028
45.   Atlas America - Series 24-2003(B) (2)          $7,300,020            106,282          12,576          2,034
46.   Atlas America - Public #12-2003 (2)            13,708,076             24,223           3,875          6,327
47.   Atlas America Series # 25-2004 (A) (2)         10,266,771                  0               0              0




[RESTUBBED TABLE]



                                                                                Latest Quarterly Cash
                                                        Cash                      Distribution As of
      Partnership                                Distributions (1) Cash Return       Date of Table
      -----------                                ----------------  -----------   ----------------------
1.    Atlas L.P. #1 - 1985                            $287,802          251%              $2,746
2.    A.E. Partners 1986                               142,781          119%               1,324
3.    A.E. Partners 1987                               161,657          102%               2,117
4.    A.E. Partners 1988                               146,224          108%               2,163
5.    A.E. Partners 1989                               172,254          143%               2,049
6.    A.E. Partners 1990                               408,325          167%               6,187
7.    A.E. Nineties - 10                               675,422          139%              11,762
8.    A.E. Nineties - 11                               339,661          127%               4,769
9.    A.E. Partners 1991                               466,091          147%               6,866
10.   A.E. Nineties - 12                               887,201          112%              11,929
11.   A.E. Nineties - JV 92                          1,226,436           87%              27,972
12.   A.E. Partners 1992                               352,135          200%               3,994
13.   A.E. Nineties - Public  #1                       696,375          132%               9,376
14.   A.E. Nineties - 1993 Ltd.                        477,189           38%               6,728
15.   A.E. Partners 1993                               367,200          167%               4,966
16.   A.E. Nineties - Public  #2                       538,313           92%              12,987
17.   A.E. Nineties - 14                             1,769,699           49%              41,070
18.   A.E. Partners 1994                               389,975          168%               8,278
19.   A.E. Nineties - Public  #3                     1,229,607          132%              22,170
20.   A.E. Nineties - 15                             2,300,218           67%              64,366
21.   A.E. Partners 1995                               135,724           55%               2,285
22.   A.E. Nineties - Public  #4                       909,344           71%              22,506
23.   A.E. Nineties - 16                             1,070,049           65%              39,797
24.   A.E. Partners 1996                               188,768           51%               6,099
25.   A.E. Nineties - Public  #5                       926,522           56%              30,283
26.   A.E. Nineties - 17                             1,630,622           77%              56,827
27.   A.E. Nineties - Public  #6                     1,714,338           88%              57,232
28.   A.E. Partners 1997                               123,988           54%               4,815
29.   A.E. Nineties - 18                             2,378,596           69%              88,559
30.   A.E. Nineties - Public  #7                     1,033,208           27%              63,118
31.   A.E. Partners 1998                               376,037           50%              14,016
32.   A.E. Nineties - 19                             2,433,489           51%              71,893
33.   A.E. Nineties - Public  #8                     1,731,280           55%              41,072
34.   A.E. Partners 1999                               118,145           60%               3,760
35.   1999 Viking Resources LP                       2,051,653          122%              58,384
36.   Atlas America - Series 20                      4,390,031           70%             195,633
37.   Atlas America - Public  #9                     2,896,596           52%             162,573
38.   Atlas America - Series 21-A                    2,256,863           50%             200,212
39.   Atlas America - Series 21-B                    2,644,754           41%             271,156
40.   Atlas America - Public #10                     3,199,937           44%             347,038
41.   Atlas America - Series 22                      1,621,571           47%             214,550

42.   Atlas America - Series 23                      1,212,529           38%             174,192
43.   Atlas America - Public #11                     3,014,080           26%             794,173

44.   Atlas America - Series 24-2003(A) (2)            661,252           13%             314,036
45.   Atlas America - Series 24-2003(B) (2)            820,905           11%             564,578
46.   Atlas America - Public #12-2003 (2)              135,386            1%             135,386
47.   Atlas America Series # 25-2004 (A) (2)                 0            0%                   0



                                       44




- ---------
(1)   All cash distributions were from the sale of gas and not sales of
      properties.
(2)   As of the date of this table there is not twelve months of production
      and/or not all wells are drilled or on-line to sell production.
(3)   Operating costs consist of gathering fees, water hauling fees, meter
      reading fees, repairs and maintenance, insurance and severance tax.

                                       45


Table 4 sets forth the managing general partner's estimate of the federal tax
savings to investors in the managing general partner's prior development
drilling partnerships, based on the maximum marginal tax rate in each year, the
share of tax deductions as a percentage of their subscriptions, and the
aggregate cash distributions. You are urged to consult with your own tax
advisors concerning your specific tax situation and should not assume that the
past performance of prior partnerships is indicative of the future results of
the partnerships.

                                    TABLE 4
         SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
                               AS OF JULY 15, 2004



                                                                                      Estimated Federal Tax Savings From (1):
                                                        1st Year     Eff  ----------------------------------------------------------
                                              Investor     Tax       Tax  1st Year I.D.C    Depletion                   Section 29
    Partnership                               Capital   Deduct.(2)  Rate     Deduct.(3)   Allowance(3) Depreciation(3) Tax Credit(4)
    -----------                             ----------  ----------  -----  ------------- ------------  --------------- -------------
1.  Atlas L.P. #1 - 1985                      $600,000      99%     50.0%     $298,337     $126,232         N/A           $55,915
2.  A.E. Partners 1986                         631,250      99%     50.0%      312,889       71,097         N/A           13,507
3.  A.E. Partners 1987                         721,000      99%     38.5%      356,895       54,110         N/A             N/A
4.  A.E. Partners 1988                         617,050      99%     33.0%      244,351       48,831         N/A             N/A
5.  A.E. Partners 1989                         550,000      99%     33.0%      179,685       67,943         N/A             N/A
6.  A.E. Partners 1990                         887,500      99%     33.0%      275,125       96,201         N/A           281,660
7.  A.E. Nineties - 10                       2,200,000     100%     33.0%      726,000      160,070         N/A           521,602
8.  A.E. Nineties - 11                         750,000     100%     31.0%      232,500       99,280         N/A           329,800
9.  A.E. Partners 1991                         868,750     100%     31.0%      269,313      108,953         N/A           315,893
10. A.E. Nineties - 12                       2,212,500     100%     31.0%      685,875      201,228         N/A           617,285
11. A.E. Nineties - JV 92                    4,004,813    92.5%     31.0%    1,322,905      349,531         N/A          1,002,109
12. A.E. Partners 1992                         600,000     100%     31.0%      186,000       78,318         N/A           224,631
13. A.E. Nineties - Public  #1               2,988,960    80.5%     36.0%      877,511      219,356       254,729           N/A
14. A.E. Nineties - 1993 Ltd.                3,753,937    92.5%     39.6%    1,378,377      208,066         N/A             N/A
15. A.E. Partners 1993                         700,000     100%     39.6%      273,216       84,756         N/A             N/A
16. A.E. Nineties - Public  #2               3,323,920    78.7%     39.6%    1,036,343      192,901       279,039           N/A
17. A.E. Nineties - 14                       9,940,045      95%     39.6%    3,739,445      506,883         N/A             N/A
18. A.E. Partners 1994                         892,500     100%     39.6%      353,430       80,838         N/A             N/A
19. A.E. Nineties - Public  #3               5,800,990    76.2%     39.6%    1,752,761      334,224       521,115           N/A
20. A.E. Nineties - 15                      10,954,715    90.0%     39.6%    3,904,261      599,582         N/A             N/A
21. A.E. Partners 1995                         600,000     100%     39.6%      237,600       25,627         N/A             N/A
22. A.E. Nineties - Public  #4               6,991,350    80.0%     39.6%    2,214,860      290,353       537,551           N/A
23. A.E. Nineties - 16                      10,955,465    86.8%     39.6%    3,361,289      410,746       868,417           N/A
24. A.E. Partners 1996                         800,000     100%     39.6%      316,800       40,363         N/A             N/A
25. A.E. Nineties - Public  #5               7,992,240    84.9%     39.6%    2,530,954      301,268       578,516           N/A
26. A.E. Nineties - 17                       8,813,488    85.2%     39.6%    2,966,366      383,214       415,744           N/A
27. A.E. Nineties - Public  #6               9,901,025    80.0%     39.6%    3,166,406      431,114       639,248           N/A
28. A.E. Partners 1997                         506,250     100%     39.6%      200,475       27,393         N/A             N/A
29. A.E. Nineties - 18                      11,391,673    90.0%     39.6%    4,030,884      289,916       380,121           N/A
30. A.E. Nineties - Public  #7              11,988,350    85.0%     39.6%    4,043,670      294,269       517,298           N/A
31. A.E. Partners 1998                       1,740,000   100.0%     39.6%      689,040       80,129         N/A             N/A
32. A.E. Nineties - 19                      15,720,450    90.0%     39.6%    5,602,767      424,685       426,553           N/A
33. A.E. Nineties - Public  #8              11,088,975    85.0%     39.6%    3,734,654      328,084       437,497           N/A
34. A.E. Partners 1999                         450,000   100.0%     39.6%      178,200       20,939         N/A             N/A
35. 1999 Viking Resources LP                 4,555,210    92.0%     39.6%    1,678,038      419,915         N/A             N/A
36. Atlas America - Series 20               18,809,150    90.0%     39.6%    6,712,802      720,855       405,737           N/A
37. Atlas America - Public  #9              14,905,465    90.0%     39.6%    5,349,744      438,302         N/A             N/A
38. Atlas America - Series 21-A             12,510,713    91.0%     39.1%    4,468,617      255,134       198,934           N/A
39. Atlas America - Series 21-B             17,411,825    91.0%     39.1%    6,197,907      289,680       246,390           N/A
40. Atlas America - Public #10              21,281,170    91.0%     39.1%    7,550,729      371,759       419,544           N/A
41. Atlas America - Series 22               10,156,375    91.0%     38.6%    3,564,312      162,808       191,168           N/A
42. Atlas America - Series 23                9,644,550    91.0%     38.6%    3,404,803      121,594       164,846           N/A
43. Atlas America - Public #11              31,178,145    91.0%     38.6%   11,003,503      259,394       384,143           N/A
44. Atlas America - Series 24-2003(A) (8)   14,363,955    91.0%     35.0%    4,578,250       17,862       185,944           N/A
45. Atlas America - Series 24-2003(B) (8)   20,542,850    91.0%     35.0%    6,514,764        4,978       365,751           N/A
46. Atlas America - Public #12-2003 (8)     40,170,308    91.0%     35.0%   12,879,332            0          0              N/A
47. Atlas America Series # 25-2004 (A) (8)  27,601,053    91.0%     37.6%            0            0          0              N/A





[RESTUBBED TABLE]



                                                                                          Total               Cumulative
                                                            Cash Distribution          Cash Dist.           Percent of Cash
                                                                  As of                 And Tax            Dist. And Tax
      Partnership                                  Total     Date of Table (5) (6)  Savings (5) (6)    Savings to Date (5)(6)(7)
      -----------                              ------------ ----------------------  ----------------   -------------------------
1.    Atlas L.P. #1 - 1985                        $480,484        $1,583,604             $2,064,088              344%
2.    A.E. Partners 1986                           397,493           748,389              1,145,882              182%
3.    A.E. Partners 1987                           411,005           758,653              1,169,658              162%
4.    A.E. Partners 1988                           293,182           696,790                989,972              160%
5.    A.E. Partners 1989                           247,628           876,019              1,123,647              204%
6.    A.E. Partners 1990                           652,986         1,264,697              1,917,683              216%
7.    A.E. Nineties - 10                         1,407,672         1,901,458              3,309,130              150%
8.    A.E. Nineties - 11                           661,580         1,075,969              1,737,548              232%
9.    A.E. Partners 1991                           694,159         1,360,117              2,054,276              236%
10.   A.E. Nineties - 12                         1,504,388         2,070,134              3,574,522              162%
11.   A.E. Nineties - JV 92                      2,674,545         4,374,546              7,049,091              176%
12.   A.E. Partners 1992                           488,950           910,621              1,399,570              233%
13.   A.E. Nineties - Public  #1                 1,351,596         2,377,919              3,729,515              125%
14.   A.E. Nineties - 1993 Ltd.                  1,586,443         2,218,614              3,805,057              101%
15.   A.E. Partners 1993                           357,972         1,065,550              1,423,522              203%
16.   A.E. Nineties - Public  #2                 1,508,282         2,227,259              3,735,542              112%
17.   A.E. Nineties - 14                         4,246,328         5,963,056             10,209,384              103%
18.   A.E. Partners 1994                           434,268         1,118,789              1,553,057              174%
19.   A.E. Nineties - Public  #3                 2,608,101         3,872,384              6,480,484              112%
20.   A.E. Nineties - 15                         4,503,843         7,511,889             12,015,732              110%
21.   A.E. Partners 1995                           263,227           381,116                644,343              107%
22.   A.E. Nineties - Public  #4                 3,042,764         3,275,803              6,318,567               90%
23.   A.E. Nineties - 16                         4,640,451         5,356,626              9,997,078               91%
24.   A.E. Partners 1996                           357,163           532,552                889,715              111%
25.   A.E. Nineties - Public  #5                 3,410,738         3,814,292              7,225,029               90%
26.   A.E. Nineties - 17                         3,765,325         4,930,512              8,695,837               99%
27.   A.E. Nineties - Public  #6                 4,236,768         5,434,682              9,671,450               98%
28.   A.E. Partners 1997                           227,868           365,500                593,368              117%
29.   A.E. Nineties - 18                         4,700,921         5,620,222             10,321,142               91%
30.   A.E. Nineties - Public  #7                 4,855,237         4,346,410              9,201,647               77%
31.   A.E. Partners 1998                           769,169         1,087,124              1,856,293              107%
32.   A.E. Nineties - 19                         6,454,005         6,384,464             12,838,469               82%
33.   A.E. Nineties - Public  #8                 4,500,235         4,503,089              9,003,323               81%
34.   A.E. Partners 1999                           199,139           339,680                538,818              120%
35.   1999 Viking Resources LP                   2,097,953         6,154,960              8,252,913              181%
36.   Atlas America - Series 20                  7,839,394        11,861,486             19,700,880              105%
37.   Atlas America - Public  #9                 5,788,046         6,701,589             12,489,634               84%
38.   Atlas America - Series 21-A                4,922,685         4,413,615              9,336,300               75%
39.   Atlas America - Series 21-B                6,733,978         5,133,933             11,867,911               68%
40.   Atlas America - Public #10                 8,342,032         6,799,837             15,141,869               71%
41.   Atlas America - Series 22                  3,918,288         3,363,268              7,281,556               72%
42.   Atlas America - Series 23                  3,691,243         2,576,570              6,267,813               65%
43.   Atlas America - Public #11                11,647,040         5,850,986             17,498,026               56%
44.   Atlas America - Series 24-2003(A) (8)      4,782,056         1,365,277              6,147,332               43%
45.   Atlas America - Series 24-2003(B) (8)      6,885,493         1,650,218              8,535,711               42%
46.   Atlas America - Public #12-2003 (8)       12,879,332           281,957             13,161,289               33%
47.   Atlas America Series # 25-2004 (A) (8)             0                 0                      0                0%



                                       46




- ---------
1.    These columns reflect the savings in taxes which would have been paid by
      an investor, assuming full use of deductions available to the investor.
2.    Atlas Resources, Inc. anticipates that approximately 90% of an investor
      general partner's subscription to a partnership will be deductible in the
      year in which he invests.
3.    The I.D.C. Deductions, Depletion Allowance and MACRS depreciation
      deductions have been reduced to credit equivalents.
4.    The Section 29 tax credit is not available with respect to wells drilled
      after December 31, 1992. N/A means not applicable.
5.    These distributions were all from production revenues.
6.    This column reflects total cash distributions beginning with the first
      production from the program and includes the return of investor's capital.
7.    These percentages are calculated by dividing the entry for each
      partnership in the "Total Cash Dist. And Tax Savings" column by that
      partnership's entry in the "Investor Capital" column.
8.    As of the date of this table there is not twelve months of production
      and/or not all wells are drilled or on-line to sell production.



                                       47




Table 5 sets forth payments made to the managing general partners and its
affiliates from its previous partnerships.

                                     TABLE 5
       SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES
                             FROM PRIOR PARTNERSHIPS
                               AS OF JULY 15, 2004



                                                                                                                     Cumulative
                                                                                      Leasehold                     Reimbursement
                                                                    Cumulative      Drilling and        Cumulative  of General and
                                                     Investor       Gathering        Completion         Operator's  Administrative
         Partnership                                  Capital        Fees (1)         Costs (2)          Charges       Overhead
         -----------                               -----------      ----------     --------------      ------------  --------------

1.       Atlas L.P. #1 - 1985                        $600,000             (1)         $600,000          $261,183         $53,484
2.       A.E. Partners 1986                           631,250             (1)          631,250           206,426          85,471
3.       A.E. Partners 1987                           721,000             (1)          721,000           224,144          78,976
4.       A.E. Partners 1988                           617,050             (1)          617,050           191,987          77,360
5.       A.E. Partners 1989                           550,000             (1)          550,000           171,849          76,670
6.       A.E. Partners 1990                           887,500             (1)          887,500           283,637          90,050
7.       A.E. Nineties-10                           2,200,000             (1)        2,200,000           597,911          99,264
8.       A.E. Nineties-11                             750,000             (1)          761,802 (3)       244,357         141,884
9.       A.E. Partners 1991                           868,750             (1)          867,500           254,281         116,618
10.      A.E. Nineties-12                           2,212,500             (1)        2,272,017 (3)       644,201         140,179
11.      A.E. Nineties-JV 92                        4,004,813             (1)        4,157,700         1,129,353         233,279
12.      A.E. Partners 1992                           600,000             (1)          600,000           144,246          58,013
13.      A.E. Nineties-Public #1                    2,988,960             (1)        3,026,348 (3)       630,028         130,426
14.      A.E. Nineties-1993 Ltd.                    3,753,937             (1)        3,480,656 (3)       775,909         153,248
15.      A.E. Partners 1993                           700,000             (1)          689,940           188,082          42,788
16.      A.E. Nineties-Public #2                    3,323,920             (1)        3,324,668  (3)      617,532         113,358
17.      A.E. Nineties-14                           9,940,045             (1)        9,512,015 (3)     2,136,119         411,794
18.      A.E. Partners 1994                           892,500             (1)          892,500           189,157          51,768
19.      A.E. Nineties-Public #3                    5,800,990             (1)        5,800,990         1,005,723         193,767
20.      A.E. Nineties-15                          10,954,715             (1)        9,859,244 (3)     2,039,671         393,364
21.      A.E. Partners 1995                           600,000             (1)          600,000           109,980          19,983
22.      A.E. Nineties-Public #4                    6,991,350             (1)        6,991,350         1,173,740         215,954
23.      A.E. Nineties-16                          10,955,465             (1)       10,955,465         1,559,800         263,783
24.      A.E. Partners 1996                           800,000             (1)          800,000           153,024          25,901
25.      A.E. Nineties-Public #5                    7,992,240             (1)        7,992,240         1,136,811         206,166
26.      A.E. Nineties-17                           8,813,488             (1)        8,813,488         1,258,773         211,611
27.      A.E. Nineties-Public #6                    9,901,025             (1)        9,901,025         1,410,241         233,868
28.      A.E. Partners 1997                           506,250             (1)          506,250            88,471          14,703
29.      A.E. Nineties-18                          11,391,673             (1)       11,391,673         1,710,397         271,342
30.      A.E. Nineties-Public #7                   11,988,350             (1)       11,988,350         1,531,839         228,433
31.      A.E. Partners 1998                         1,740,000             (1)        1,740,000           268,653          25,625
32.      A.E. Nineties-19                          15,720,450             (1)       15,720,450         1,977,683         286,224
33.      A.E. Nineties-Public #8                   11,088,975             (1)       11,088,975         1,216,711         181,759
34.      A.E. Partners 1999                           450,000             (1)          450,000            43,791           4,116
35.      1999 Viking Resources LP                   4,555,210             (1)        4,555,210         1,669,336               0
36.      Atlas America-Series 20                   18,809,150             (1)       18,809,150         3,151,569         280,853
37.      Atlas America-Public #9                   14,905,465        739,027        14,905,465         1,316,606         201,506
38.      Atlas America-Series 21-A                 12,510,713        472,265        12,510,713           840,619         146,929
39.      Atlas America-Series 21-B                 17,411,825        587,632        17,411,825         1,011,113         170,726
40.      Atlas America-Public #10                  21,281,170        798,448        21,281,170           962,743         185,539
41.      Atlas America-Series 22                   10,156,375        327,932        10,156,375           387,175          74,996
42.      Atlas America-Series 23                    9,644,550        294,941         9,644,550           325,220          62,700
43.      Atlas America-Public #11                  31,178,145        671,246        31,178,145           687,331         138,774
44.      Atlas America - Series 24-2003 (A)        14,363,955        138,786        14,363,955           212,531          38,981
45.      Atlas America - Series 24-2003 (B)        20,542,850        130,259        20,542,850           189,673          37,856
46.      Atlas America - Public 12-2003            40,170,308         28,932        40,170,308            45,737          11,944
47.      Atlas America Series # 25-2004 (A)        27,601,053              0        27,601,053                 0               0



- ---------
(1)   The amount of gathering fees paid to the managing general partner and its
      affiliates from 2001 to the date of this table are shown for those
      partnerships which began operations on or after December 31, 2000. The
      books and records of the earlier partnerships do not separately allocate
      all of the gathering fees paid by them. Additional information concerning
      the gathering fees paid by those partnerships will be provided to you on
      written request to the managing general partner.
(2)   Excluding the managing general partner's capital contributions.
(3)   Includes additional drilling costs paid with production revenues.




                                       48






                                   MANAGEMENT

MANAGING GENERAL PARTNER AND OPERATOR
The partnerships will have no officers or directors. Instead, Atlas Resources,
Inc., a Pennsylvania corporation which was incorporated in 1979, will serve as
the managing general partner of each partnership. Atlas Resources' affiliate
Atlas Energy Group, Inc., an Ohio corporation which was the first of the Atlas
group of companies, was incorporated in 1973. Atlas Energy Group, Inc. will
serve as the partnership's general drilling contractor and operator in Ohio. As
of March 1, 2004, the managing general partner and its affiliates operated
approximately 4,653 natural gas and oil wells located in Ohio, Pennsylvania and
New York.

Since 1985 the managing general partner has sponsored 12 public and 35 private
partnerships to conduct natural gas drilling and development activities in
Pennsylvania, Ohio, and New York. In these partnerships the managing general
partner and its affiliates acted as the operator and the general drilling
contractor and were responsible for drilling, completing, and operating the
wells. Atlas Resources has a 97% completion rate for wells drilled by its
development partnerships.

In September 1998, Atlas Energy Group, Inc., the former parent company of the
managing general partner, merged into Atlas America, Inc., a Delaware holding
company. Atlas America is a subsidiary of Resource America, Inc., a
publicly-traded company, which is sometimes referred to in this prospectus as
Resource America. Resource America, Inc. recently conducted an offering of a
portion of its common stock (the "shares") in Atlas America, the Delaware
holding company. The Atlas America public offering of 2,300,000 shares was
priced on May 10, 2004 at $15.50 per share and raised $33.2 million of net
proceeds. The shares began trading on NASDAQ on May 11, 2004 under the symbol
"ATLS." On June 1, 2004, the underwriters announced their exercise in full of
their over-allotment option related to the offering of 345,000 shares. The
exercise of the over-allotment generated additional net offering proceeds of
approximately $5 million, bringing the total net proceeds for the offering to
approximately $38.2 million and the total number of shares sold to 2,645,000,
thus reducing Resource America's ownership of Atlas America to approximately
80.2%. The net proceeds of the offering, after deducting underwriting discounts,
was or will be distributed to Resource America in the form of a repayment of
inter-company debt and a non-taxable dividend. Also, on May 14, 2004, in
connection with the Atlas America offering, the following officers and key
employees of the managing general partner and Atlas America set forth in "-
Officers, Directors and Other Key Personnel," below, resigned their positions
with Resource America and all of its subsidiaries which are not also
subsidiaries of Atlas America: Mr. Freddie M. Kotek, Mr. Frank P. Carolas, Mr.
Jeffrey C. Simmons, Ms. Nancy J. McGurk, Mr. Michael L. Staines, and Ms. Marci
Bleichmar.

Resource America has advised the managing general partner that it intends to
distribute its remaining ownership interest in Atlas America to its common
stockholders. Resource America expects the distribution to take the form of a
spin-off by means of a special dividend to Resource America common stockholders
of all of Atlas America's common stock owned by Resource America. Resource
America further has advised the managing general partner that it anticipates
that the distribution will occur by the end of 2004. Resource America has sole
discretion if and when to complete the distribution and its terms. Resource
America does not intend to complete the distribution unless it receives a ruling
from the Internal Revenue Service and/or an opinion from its tax counsel as to
the tax-free nature of the distribution to Resource America and its stockholders
for U.S. federal income tax purposes. The Internal Revenue Service requirements
for tax-free distributions of this nature are complex and the Internal Revenue
Service has broad discretion, so there is significant uncertainty as to whether
Resource America will be able to obtain such a ruling. Because of this
uncertainty and the fact that the timing and completion of the distribution is
in Resource America's sole discretion, the distribution may not occur by the
contemplated time or may not occur at all.

If the distribution occurs, the managing general partner believes the principal
effect on Atlas America will be that Resource America will no longer own any of
Atlas America's common stock and, thus, will no longer be in a position to
determine the outcome of corporate actions requiring stockholder approval such
as:

         o        the election and removal of directors;

         o        mergers or other business combinations involving Atlas
                  America;

                                       49

         o        future issuances of Atlas America's common stock or other
                  securities; and

         o        amendments to Atlas America's certificate of incorporation and
                  bylaws.

These actions will be passed on by Atlas America's stockholders existing at the
record dates for such matters. Resource America's rights following the
distribution will be defined by agreements between Resource America and Atlas
America.

Atlas America is headquartered at 311 Rouser Road, Moon Township, Pennsylvania
15108, near the Pittsburgh International Airport, which is also the managing
general partner's primary office.

OFFICERS, DIRECTORS AND OTHER KEY PERSONNEL
The officers and directors of the managing general partner will serve until
their successors are elected. The officers, directors, and key personnel of the
managing general partner are as follows:


NAME                         AGE      POSITION OR OFFICE
- ----                         ---      ------------------
Freddie M. Kotek             48       Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas             44       Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons           45       Executive Vice President - Operations and a Director
Jack L. Hollander            48       Senior Vice President - Direct Participation Programs
Nancy J. McGurk              48       Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines           54       Senior Vice President, Secretary and a Director
Michael G. Hartzell          48       Vice President - Land Administration
Donald R. Laughlin           56       Vice President - Drilling and Production
Marci F. Bleichmar           33       Vice President of Marketing
Sherwood S. Lutz             53       Senior Geologist/Manager of Geology
Michael W. Brecko            46       Director of Energy Sales
Karen A. Black               43       Vice President - Partnership Administration
Justin T. Atkinson           31       Director of Due Diligence
Winifred C. Loncar           63       Director of Investor Services

With respect to the biographical information set forth below:

         o        the approximate amount of an individual's professional time
                  devoted to the business and affairs of the managing general
                  partner and Atlas America have been aggregated because there
                  is no reasonable method for them to distinguish their
                  activities between the two companies; and

         o        for those individuals who also hold senior positions with
                  other affiliates of the managing general partner, if it is
                  stated that they devote approximately 100% of their
                  professional time to the managing general partner and Atlas
                  America, 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 the managing general
                  partner and Atlas America as compared with the other
                  affiliates of the 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 since
February 2004 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 will devote
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.

                                       50

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 the 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.

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 will devote 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.

                                       51

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
will devote 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.

MICHAEL G. HARTZELL. Vice President - Land Administration since September 2001.
Mr. Hartzell has been Vice President - Land Administration of Atlas America
since January 2002, and before that served as Senior Land Coordinator from
January 1999 to January 2002. Mr. Hartzell has been with the managing general
partner and its affiliates since 1980 when he began his career as a land
department representative. Mr. Hartzell manages all Land Department functions.
Mr. Hartzell serves on the Environmental Committee of the Independent Oil and
Gas Association of Pennsylvania and is a past Chairman of the Committee. Mr.
Hartzell devotes approximately 100% of his professional time to the business and
affairs of the managing general partner and Atlas America.

DONALD R. LAUGHLIN. Vice President-Drilling and Production since September 2001.
Mr. Laughlin also serves as Vice President - Drilling and Production for Atlas
America since January 2002, and before that served as Senior Drilling Engineer
since May 2001 when he joined Atlas America. Mr. Laughlin has over thirty years
of experience as a petroleum engineer in the Appalachian Basin, having been
employed by Columbia Gas Transmission Corporation from October 1995 to May 2001
as a senior gas storage engineer and team leader, Cabot Oil & Gas Corporation
from 1989 to 1995 as Manager of Drilling Operations and Technical Services,
Doran & Associates, Inc. (an industrial engineering firm) from 1977 until 1989
as Vice President--Operations, and Columbia Gas from 1970 to 1977 as Drilling
Engineer and Gas Storage Engineer. Mr. Laughlin received his Petroleum
Engineering degree from the University of Pittsburgh in 1970. He is a member of
the Society of Petroleum Engineers. Mr. Laughlin devotes approximately 100% of
his professional time to the business and affairs of the managing general
partner and Atlas America.

MARCI F. BLEICHMAR. Vice President of Marketing since February 2001. Ms.
Bleichmar also serves as Vice President of Marketing for Atlas America since
February 2001 and was with Resource America from February 2001 until May 2004
when she resigned from Resource America. From March 2000 until February 2001,
Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a
mutual fund manager), and from March 1998 until March 2000, she was an account
executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms.
Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms.
Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in
1992. Ms. Bleichmar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.

SHERWOOD S. LUTZ. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined
Viking Resources, which was purchased by Resource America in 1999 as senior
geologist. Since 1999 Mr. Lutz has been a senior geologist for the managing
general partner and Atlas America. Mr. Lutz received his Bachelor of Science
degree in Geological Sciences from the Pennsylvania State University in 1973.
Mr. Lutz is a certified petroleum geologist with the American Association of
Petroleum Geologists as well as a licensed professional geologist in
Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to
the business and affairs of the managing general partner and Atlas America.

MICHAEL W. BRECKO. Director of Energy Sales since November 2002. Mr. Brecko has
over 16 years of natural gas marketing experience in the oil and natural gas
industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University
with a Bachelor of Science degree in Civil Engineering. His career in natural
gas marketing began when he joined Equitable Gas Company, a local distribution
company, as a marketing representative in the commercial/ industrial marketing
division from May 1986 to August 1992. He subsequently joined O&R Energy, a
subsidiary of Orange and Rockland Utilities, as regional marketing manager from
August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr.
Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and
natural gas producer, as an account executive and he was promoted in August 1998
to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a
multi-energy sourced company, as a regional account manager before joining Atlas
America in 2002. Mr. Brecko devotes approximately 100% of his professional time
to the business and affairs of the managing general partner and Atlas America.

                                       52

KAREN A. BLACK. Vice President - Partnership Administration since February 2003.
Ms. Black is also Vice President and Financial and Operations Principal of
Anthem Securities since October 2002. Ms. Black joined the managing general
partner and Atlas America in July 2000 and served as manager of production,
revenue and partnership accounting from July 2000 through October 2001, after
which she served as manager and financial analyst until her appointment as Vice
President - Partnership Administration. Before joining the managing general
partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as
controller from April 1997 through June 2000. Ms. Black was employed as a tax
accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997.
Ms. Black received a Bachelor of Arts degree from the University of Pittsburgh,
Johnstown in 1982. Ms. Black devotes approximately 50% 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 Anthem
Securities.

JUSTIN T. ATKINSON. Director of Due Diligence since February 2003. Mr. Atkinson
also serves as President of Anthem Securities since February 2004 and as Chief
Compliance Officer since October 2002. Before that Mr. Atkinson served as
assistant compliance officer of Anthem Securities from December 2001 until
October 2002 and Vice President from October 2002 until February 2004. Before
his employment with the managing general partner, Mr. Atkinson was a manager of
investor and broker/dealer relations with Viking Resources Corporation from 1996
until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business
Management in 1995 from Walsh University in North Canton, Ohio. Mr. Atkinson
devotes approximately 25% 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 Anthem Securities.

WINIFRED C. LONCAR, Director of Investor Services since February 2003. Ms.
Loncar previously held the position of manager of investor services from the
inception of the investor service department in 1990 to February 2003. Before
that she was executive secretary to the managing general partner. Ms. Loncar
received a Bachelor of Science degree in Business from Point Park University in
1998. Ms. Loncar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.

ATLAS AMERICA, INC., A DELAWARE HOLDING COMPANY
As of February 2004, the officers and directors for Atlas America include the
following:


         NAME                 AGE                          POSITION
         ----                 ---                          --------
Edward E. Cohen               65           Chairman, Chief Executive Officer and President
Frank P. Carolas              44           Executive Vice President
Freddie M. Kotek              48           Executive Vice President and Chief Financial Officer
Jeffrey C. Simmons            45           Executive Vice President
Michael L. Staines            54           Executive Vice President and Secretary
Nancy J. McGurk               48           Senior Vice President and Chief Accounting Officer
Jonathan Z. Cohen             33           Vice Chairman
Carlton M. Arrendell          42           Director
William R. Bagnell            41           Director
Donald W. Delson              53           Director
Nicholas DiNubile             51           Director
Dennis A. Holtz               63           Director


                                       53

See "- Officers, Directors and Other Key Personnel," above, for biographical
information on certain of these individuals who are also officers of the
managing general partner. Biographical information on the other officers and
directors will be provided by the managing general partner on request.


As of June 1, 2004, the managing general partner and its affiliates under Atlas
America employ a total of approximately 205 persons.


At December 31, 2003 Atlas America and its affiliates had more than $514 million
of energy assets under management.

ORGANIZATIONAL DIAGRAM AND SECURITY OWNERSHIP OF BENEFICIAL OWNERS

See "- Managing General Partner and Operator" above for a discussion of Atlas
America's stock offering and the percentage of stock owned by Resource America
in Atlas America, the Delaware holding company, which owns 100% of the common
stock of AIC, Inc., which owns 100% of the common stock of the managing general
partner. The directors of AIC, Inc. are Jonathan Z. Cohen, Michael L. Staines,
and Jeffrey C. Simmons. The biographies of Messrs. Staines, and Simmons are set
forth above.

This organizational diagram does not include all of the subsidiaries of Resource
America, as discussed above.


                                    ------------------------------------------
                                              Resource America, Inc.
                                    ------------------------------------------
                                                       |
                                    ------------------------------------------
                                           Atlas Energy Holdings, Inc.
                                    ------------------------------------------
                                                       |
                                    ------------------------------------------
                                         Atlas America, Inc. (Delaware)
                                             (holding company) (1)
                                    ------------------------------------------
                                                       |
  ---------------------------------------------------------------------------------------------------------------
  |                              |                        |                           |                         |
- --------------------    --------------------    -------------------------    ---------------------    --------------------
      Viking                  AIC, Inc.             Atlas America, Inc.          Resource Energy,           Atlas Noble
    Resources                                         (Pennsylvania)                 Inc. (2)             Corporation (2)
  Corporation (2)                                  (operating company)
- --------------------    --------------------    -------------------------    ---------------------    --------------------
                                 |
     --------------------------------------------------------------------------------------------------------------
     |                              |                        |                         |                          |
- -----------------------     --------------------     --------------------      --------------------      -------------------
Atlas Resources, Inc.,      Atlas Energy             Pennsylvania              Anthem Securities,        Atlas Energy
managing general            Corporation,             Industrial Energy,        Inc., registered          Group, Inc.,
partner of Atlas            managing general         Inc.                      broker/dealer and         driller and
America Public              partner of                                         dealer-manager            operator in Ohio
#14-2004 Program,           exploratory
driller and operator        drilling
in Pennsylvania             partnerships and
                            driller and operator
- -----------------------     --------------------     --------------------      --------------------      -------------------
    |                                                                                                             |
- -----------------------                                                                                  -------------------
ARD Investments,                                                                                            AED Investments,
Inc.                                                                                                        Inc.
- -----------------------                                                                                  -------------------

- -----------------

(1) See "- Managing General Partner and Operator," above, for the discussion of
    Atlas America's stock offering.

(2) Viking Resources, Resource Energy, and Atlas Noble Corporation are also
    engaged in the oil and gas business. Resource Energy has been an energy
    subsidiary of Resource America since 1993. Resource America acquired Viking
    Resources in August 1999, and Atlas Noble Corporation was formed in October
    2000 after Resource America acquired all of the assets of Kingston Oil
    Corporation. Atlas America manages their assets and employees including
    sharing common employees. Also, many of the officers and directors of the
    managing general partner serve as officers and directors of those entities.

                                       54

REMUNERATION
No officer or director of the managing general partner will receive any direct
remuneration or other compensation from the partnerships. These persons will
receive compensation solely from affiliated companies of the managing general
partner.

CODE OF BUSINESS CONDUCT AND ETHICS

Because the partnerships do not directly employ any persons, the managing
general partner has determined that the partnerships will rely on a Code of
Business Conduct and Ethics adopted by Atlas America, Inc. that applies to
the principal executive officer, principal financial officer and principal
accounting officer of the managing general partner, as well as to persons
performing services for the managing general partner generally. You may obtain a
copy of this code of ethics by a request to the managing general partner at
Atlas Resources, Inc., 311 Rouser Road, Moon Township, Pennsylvania 15108.

TRANSACTIONS WITH MANAGEMENT AND AFFILIATES
The managing general partner depends on its parent company, Atlas America, for
management and administrative functions and financing for capital expenditures.
The managing general partner pays a management fee to Atlas America for
management and administrative services, which amounted to $13.1 million, $10.5
million and $6.4 million for the years ended September 30, 2003, 2002 and 2001,
respectively. (See "Financial Information Concerning the Managing General
Partner and Atlas America Public #14-2004 L.P.")

The managing general partner and its officers, directors and affiliates have in
the past invested, and may in the future invest, in partnerships sponsored by
the managing general partner. They may also subscribe for units in each
partnership as described in "Plan of Distribution."

                MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
            CONDITION, RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL
                                   RESOURCES

None of the partnerships composing the program have been formed other than the
first partnership, Atlas America Public #14-2004 L.P. Each partnership will be
formed as a limited partnership under the Delaware Revised Uniform Limited
Partnership Act before the initial closing of the partnership and breaking
escrow as discussed in "Terms of the Offering - Activation of the Partnerships."
Thus, the partnerships formed or to be formed have not included any historical
information in this prospectus since they:

         o        have no net worth;

         o        do not own any properties on which wells will be drilled;

         o        have no third-party investors; and

         o        have not conducted any operations.

(See "Capitalization and Source of Funds and Use of Proceeds," "Proposed
Activities," "Competition, Markets and Regulation," and "Financial Information
Concerning the Managing General Partner and Atlas America Public #14-2004 L.P.")

Each partnership will depend on the proceeds of this offering and the managing
general partner's capital contributions to carry out its proposed activities.
Each partnership intends to use its subscription proceeds to pay the intangible
drilling costs, the investors' share of equipment costs, and the investors'
share of any cost overruns of drilling and completing the partnership's wells.

                                       55

The managing general partner believes that each partnership's liquidity
requirements will be satisfied from the following:

         o        the subscription proceeds of this offering;

         o        the managing general partner's capital contributions;

         o        the cash flow from future operations; and

         o        partnership borrowings, if necessary.

The managing general partner also anticipates that no additional funds will be
required for operating costs before a partnership begins receiving production
revenues from its wells.

Substantially all of the subscription proceeds of you and the other investors in
a partnership will be committed or expended after the offering of the
partnership closes. If a partnership requires additional funds for cost overruns
or additional development or remedial work after a well begins producing, then
these funds may be provided by:

         o        subscription proceeds, if available, drilling fewer wells, or
                  acquiring a lesser working interest in one or more wells;

         o        borrowings from the managing general partner or its
                  affiliates; or

         o        retaining partnership revenues.

There will be no borrowings from third-parties. The amount that may be borrowed
by a partnership from the managing general partner and its affiliates may not at
any time exceed 5% of the partnership's subscription proceeds from you and the
other investors and must be without recourse to you and the other investors. The
partnership's repayment of any borrowings would be from partnership production
revenues and would reduce or delay your cash distributions.

If the managing general partner loans money to a partnership, which it is not
required to do, then:

         o        the interest charged to the partnership must not exceed the
                  managing general partner's interest cost or the interest that
                  would be charged to the partnership without reference to the
                  managing general partner's financial abilities or guarantees
                  by unrelated lenders, on comparable loans for the same
                  purpose; and

         o        the managing general partner may not receive points or other
                  financing charges or fees, although the actual amount of the
                  charges incurred from third-party lenders may be reimbursed to
                  the managing general partner.

Currently, Atlas America (the "borrower") has a $75 million revolving credit
facility with a group of banks with Wachovia Bank, N.A. as the agent and issuing
bank. The managing general partner, Resource America and various energy
subsidiaries of Atlas America are guarantors of the credit agreement. As of
March 2004, this facility has a borrowing base of $65 million, which may be
increased to $75 million subject to growth in the oil and gas reserves of the
borrower and the guarantors. Borrowings under the facility are collateralized by
substantially all of the assets of Atlas America, the managing general partner
and the other guarantors. This includes the managing general partner's interests
in its partnerships, but does not include any investor's interest in a
partnership. A breach of the credit agreement by the borrower constitutes a
default under the loan. The credit facility has a term ending in July 2005. At
December 31, 2003, the borrower had an outstanding balance of approximately $19
million and also had a $1.7 million letter of credit issued under the facility.

The managing general partner depends on its parent company, Atlas America, for
management and administrative functions and financing for capital expenditures.
The managing general partner pays a management fee to Atlas America for
management and administrative services, as described in "Management -
Transactions with Management and Affiliates." See the footnotes to the managing
general partner's audited financial statements and the footnotes to the managing
general partner's unaudited financial statements for more details concerning the
credit facility and inter-company borrowings in "Financial Information
Concerning the Managing General Partner and Atlas America Public #14-2004 L.P."

                                       56

                               PROPOSED ACTIVITIES

OVERVIEW OF DRILLING ACTIVITIES
The managing general partner anticipates that the subscription proceeds of each
partnership will be used to drill primarily natural gas development wells, which
means a well drilled within the proved area of a natural gas or oil reservoir to
the depth of a stratigraphic horizon known to be productive. Stratigraphic means
a layer of rock which has characteristics that differentiate it from the rocks
above and below it. Stratigraphic horizon generally means that part of a
formation or layer of rock with sufficient porosity and permeability to form a
petroleum reservoir. Currently, the partnerships do not hold any interests in
any properties or prospects on which the wells will be drilled.

Although the majority of the wells will be classified as natural gas wells,
which may produce a small amount of oil, some of the wells, such as those in
McKean County, Pennsylvania, may be classified as oil or combination oil and
natural gas wells.

Each partnership will be a separate business entity from the other partnerships,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest.

Each partnership generally will drill different wells, but they may own working
interests and participate in drilling and completing one or more of the same
wells. The number of wells to be drilled by a partnership cannot be determined
precisely before the funding of a partnership and is determined primarily by:

         o        the amount of subscription proceeds raised for that
                  partnership;

         o        the geographical areas in which wells are drilled by that
                  partnership;

         o        the partnership's percentage of working interest owned in the
                  wells, which could range from 25% to 100%; and

         o        the cost of the wells, including if there are any cost
                  overruns for intangible drilling costs of the wells which are
                  paid 100% by you and the other investors in that partnership.

For the estimated number of wells to be drilled at the minimum subscription
proceeds of $2 million and the maximum subscription proceeds of $125 million See
"Risk Factors - Risks Related to an Investment in a Partnership - Spreading the
Risks of Drilling Among a Number of Wells Will be Reduced if Less than the
Maximum Subscription Proceeds are Received and Fewer Wells are Drilled."

Before the managing general partner selects a prospect on which a well will be
drilled by a partnership, it will review all available geologic and production
data for wells located in the vicinity of the proposed well including, but not
limited to:

         o        various well logs;

         o        completion reports;

         o        plugging reports; and

         o        production reports.

                                       57

For example, production information from surrounding wells in the area is an
important indicator in evaluating the economic potential of a proposed well to
be drilled. It has been the managing general partner's experience that natural
gas production from wells drilled to the formations or the reservoirs in the
primary areas is reasonably consistent with nearby wells, although from time to
time there can be great differences in the natural gas volumes and performance
of wells located on contiguous prospects. However, production information is
only one factor and the managing general partner may propose a well to be
drilled by a partnership because geologic trends in the immediate area, such as
sand thickness, porosities and water saturations, lead the managing general
partner to believe that the proposed well locations will be productive.

PRIMARY AREAS OF OPERATIONS
The managing general partner will not decide on the majority of the specific
wells to be drilled in any partnership until the offering of units in that
partnership has ended. However, the managing general partner intends that Atlas
America Public #14-2004 L.P., which must close on or before December 31, 2004,
will drill the prospects described in "Appendix A - Information Regarding
Currently Proposed Prospects for Atlas America Public #14-2004 L.P." These
prospects represent the wells to be drilled if a portion of the nonbinding
targeted subscription proceeds as described in "Terms of the Offering -
Subscription to a Partnership" are received. If there are adverse events with
respect to any of the currently proposed prospects, the managing general partner
will substitute the partnership's prospects as discussed below in "- Interests
of Parties." The managing general partner also anticipates that it will
designate a portion of the prospects in each partnership designated Atlas
America Public #14-2005(_____) L.P. by a supplement or an amendment to the
registration statement of which this prospectus is a part.

Because only a portion of the prospects for a partnership will be specified, you
will not be able to evaluate the majority of the specific prospects that will be
drilled by your partnership. However, by waiting as long as possible before
selecting all of the specific prospects to be drilled by a partnership, the
managing general partner may acquire additional information to help it select
better prospects for the partnership, and it may be able to include prospects
which were not available when this prospectus was written or even when the
offering of units in the partnership was closed.

This section includes a general description of the areas where the managing
general partner anticipates partnership wells may be drilled. If additional
areas are added, then this information will be supplemented. As discussed below,
the four primary areas for the partnerships' drilling activities are:

         o        the Mississippian/Upper Devonian Sandstone reservoirs in
                  Fayette and Greene Counties, Pennsylvania;

         o        the Clinton/Medina Geological Formation in western
                  Pennsylvania that also covers an area in eastern Ohio
                  primarily in Stark, Mahoning, Trumbull and Portage Counties;

         o        the Upper Devonian Sandstone Reservoirs in Armstrong County,
                  Pennsylvania; and

         o        the Upper Devonian Sandstone Reservoirs in McKean County,
                  Pennsylvania.

Fayette County, Greene County, Armstrong County and McKean County are in western
Pennsylvania. The Clinton/Medina geological formation in Pennsylvania and Ohio
is the same geological formation, although in Pennsylvania it is often referred
to as the Medina/Whirlpool geological formation. For purposes of this
prospectus, the term Clinton/Medina geological formation is used for both Ohio
and Pennsylvania. The wells drilled to the Clinton/Medina geological formation,
regardless of whether they are situated in western Pennsylvania, eastern Ohio,
western New York, or southern Ohio, and the Mississippian and/or Upper Devonian
Sandstone reservoirs have the following similarities:

         o        geological features such as structure and faulting are not
                  generally factors used in finding commercial production from a
                  well drilled to this formation or these reservoirs and the
                  governing factors appear to be sand quality in terms of net
                  pay zone thickness, porosity, and the effectiveness of
                  fracture stimulation;

         o        a well drilled to this formation or these reservoirs usually
                  requires hydraulic fracturing of the formation to stimulate
                  productive capacity;

                                       58

         o        generally, natural gas from a well drilled to this formation
                  or these reservoirs is produced at rates which decline rapidly
                  during the first few years of operations, and although the
                  well can produce for many years, a proportionately larger
                  amount of production can be expected within the first several
                  years; and

         o        it has been the managing general partner's experience that
                  natural gas production from wells drilled to this formation or
                  these reservoirs is reasonably consistent with nearby wells,
                  although from time to time there can be great differences in
                  the natural gas volumes and performance of wells on contiguous
                  prospects.


The managing general partner anticipates that the majority of the subscription
proceeds of each partnership will be expended in the primary areas, although
some of the subscription proceeds of each partnership may be expended in the
secondary areas or in areas which are not currently known. In the primary areas,
the managing general partner anticipates that more prospects will be drilled in
Fayette County than the other areas in each partnership.


MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS, FAYETTE COUNTY, PENNSYLVANIA.
The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous
lens-shaped accumulations found throughout most of the Appalachian Basin. These
reservoirs have porosities ranging from 5% to 20% with attendant permeabilities.
Porosity is the percentage of void space between sand grains that is available
for occupancy by either liquids or gases; and permeability is the property of
porous rock that allows fluids or gas to flow through it. See the geologic
evaluation prepared by United Energy Development Consultants, Inc., an
independent geological and engineering firm, for a discussion of the development
of the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and Greene
Counties, Pennsylvania.

The wells in the Mississippian/Upper Devonian Sandstone reservoirs will be:

         o        situated on approximately 20 acres, subject to adjustment to
                  take into account lease boundaries;

         o        drilled at least 1,000 feet from a producing well, although a
                  partnership may drill a new well or re-enter an existing well
                  which is closer than 1,000 feet to a plugged and abandoned
                  well;

         o        drilled from approximately 1,900 to 5,500 feet in depth;

         o        classified as natural gas wells which may produce a small
                  amount of oil; and

         o        primarily connected to the gathering system owned by Atlas
                  Pipeline Partners and have their natural gas production
                  primarily marketed to UGI Energy Services as described below
                  in "- Sale of Natural Gas and Oil Production" for the period
                  from November 1, 2004 through March 31, 2006.

CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA. The Clinton/Medina
geological formation is a blanket sandstone found throughout most of the
northwestern edge of the Appalachian Basin. The Clinton/Medina is described in
petroleum industry terms as a "tight" sandstone with porosity ranging from 6% to
12% and with very low permeability. Based on the managing general partner's
experience, it anticipates that all of the natural gas wells drilled to the
Clinton/Medina will be completed and fraced in two different zones of the
Clinton/Medina geological feature. See the geologic evaluation and the model
decline curve prepared by United Energy Development Consultants, Inc. in
"Appendix A - Information Regarding Currently Proposed Prospects for Atlas
America Public #14-2004 L.P." for a discussion of the development of the
Clinton/Medina Geological Formation in western Pennsylvania, which also covers
an area in eastern Ohio primarily in Stark, Mahoning, Trumbull, and Portage
Counties.

The wells in the Clinton/Medina geological formation in western Pennsylvania and
eastern Ohio will be:

         o        primarily situated in Crawford, Mercer, Lawrence, Warren, and
                  Venango Counties, Pennsylvania, and Stark, Mahoning, Trumbull
                  and Portage Counties, Ohio;

                                       59

         o        situated on approximately 50 acres, subject to adjustment to
                  take into account lease boundaries;

         o        drilled at least 1,650 feet from each other in Pennsylvania,
                  which is greater than the 660 feet minimum distance allowed by
                  state law or local practice to protect against drainage from
                  adjacent wells, and drilled at least 1,000 feet from each
                  other in Ohio;

         o        drilled from approximately 5,100 to 6,300 feet in depth;

         o        classified as natural gas wells which may produce a small
                  amount of oil, although the wells in eastern Ohio may be
                  classified as oil wells; and

o                 primarily connected to the gathering system owned by Atlas
                  Pipeline Partners and have their natural gas production
                  primarily marketed to First Energy Solutions Corporation as
                  described below in " - Sale of Natural Gas and Oil
                  Production".

Also, see "- Secondary Areas of Operations" below, for a discussion of the
Clinton/Medina geological formation in western New York and southern Ohio.

UPPER DEVONIAN SANDSTONE RESERVOIRS, ARMSTRONG COUNTY, PENNSYLVANIA. The Upper
Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found
throughout most of the Appalachian Basin. These reservoirs have porosities
ranging from greater than 5% to 20% with attendant permeabilities. See the
geologic evaluation prepared by United Energy Development Consultants, Inc. for
a discussion of the development of the Upper Devonian Sandstone Reservoir in
Armstrong County, Pennsylvania. The prospects in Armstrong County, Pennsylvania
were acquired from U.S. Energy Exploration Corporation as described below in
"- Interests of Parties," and U.S. Energy will participate in the wells with the
partnerships.

The wells in the Upper Devonian Sandstone reservoirs will be:

         o        situated on approximately 20 acres, subject to adjustment to
                  take into account lease boundaries;

         o        drilled at least 1,000 feet from each other, although under
                  Pennsylvania law in certain circumstances a variance can be
                  obtained, and some of the wells the managing general partner
                  has drilled to date in this general area have been drilled
                  less than 1,000 feet apart, but even in those cases the wells
                  were approximately 980 feet or more from each other;

         o        drilled from approximately 1,800 to 4,400 feet in depth;

         o        classified as natural gas wells which may produce a small
                  amount of oil; and

         o        connected to a gathering system owned by U.S. Energy and have
                  their natural gas production marketed by U.S. Energy as
                  described below in "- Sale of Natural Gas and Oil Production."

UPPER DEVONIAN SANDSTONE RESERVOIRS IN MCKEAN COUNTY, PENNSYLVANIA. See "- Upper
Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania," above, for a
description of these reservoirs and also see the geologic evaluation prepared by
United Energy Development Consultants, Inc. for a discussion of the Upper
Devonian Sandstone Reservoirs in McKean County, Pennsylvania. Wells located in
McKean County and drilled to the Upper Devonian Sandstone reservoirs will be:

         o        situated on approximately 6 acres subject to adjustments to
                  take into account lease boundaries;

         o        drilled from approximately 2,000 to 2,500 feet in depth;

         o        classified as combination wells producing both natural gas and
                  oil; and

                                       60

         o        connected to the gathering systems owned by Atlas Pipeline
                  Partners and M&M Royalty, LTD. and have their natural gas
                  production primarily marketed to M&M Royalty, LTD. as
                  described below in "- Sale of Natural Gas and Oil Production."

SECONDARY AREAS OF OPERATIONS
The managing general partner also has reserved the right to use a portion of the
subscription proceeds of each partnership to drill development wells in other
areas of the Appalachian Basin. The secondary areas anticipated by the managing
general partner are discussed below.

CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN NEW YORK. Wells located in
western New York and drilled to the Clinton/Medina geological formation will be:

         o        primarily situated in Chautauqua County;

         o        situated on approximately 40 acres, subject to adjustment to
                  take into account lease boundaries;

         o        drilled from approximately 3,800 to 4,000 feet in depth;

         o        drilled on leases with a net revenue interest of approximately
                  84.375% to 87.5%;

         o        classified as natural gas wells which may produce a small
                  amount of oil; and

         o        connected to the gathering system owned by Atlas Pipeline
                  Partners and have their natural gas production primarily
                  marketed to First Energy Solutions Corporation as described
                  below, and/or commercial end users in the area, although a
                  portion of the natural gas production may be gathered and
                  marketed by Great Lakes Energy Partners, L.L.C. as described
                  below in " - Sale of Natural Gas and Oil Production."

CLINTON/MEDINA GEOLOGICAL FORMATION IN SOUTHERN OHIO. Wells located in southern
Ohio and drilled to the Clinton/Medina geological formation will be:

         o        primarily situated in Noble, Washington, Guernsey, and
                  Muskingum Counties;

         o        situated on approximately 40 acres, subject to adjustment to
                  take into account lease boundaries;

         o        drilled at least 1,000 feet from each other;

         o        drilled from approximately 4,900 to 6,500 feet in depth;

         o        drilled on leases with a net revenue interest of approximately
                  82.5% to 87.5%;

         o        classified as either natural gas wells or oil wells; and

         o        primarily connected to the gathering system owned by Atlas
                  Pipeline Partners if classified as natural gas wells and have
                  their natural gas production primarily marketed by First
                  Energy Solutions Corporation, although a portion of the
                  natural gas production may be gathered and marketed by Triad
                  Energy Corporation of West Virginia, Inc. as described below
                  in "- Sale of Natural Gas and Oil Production."

Additionally, the managing general partner anticipates that the leases in
southern Ohio will have been originally acquired from a coal company and are
subject to a provision that the well must be abandoned if it hinders the
development of the coal. Thus, the managing general partner will not drill a
well on any lease subject to this provision unless it covers lands that were
previously mined. Although this does not totally eliminate the risk because the
leases may cover other coal deposits that might be mined during the life of a
well, the managing general partner believes that drilling wells on these
previously mined leases would be in the best interests of the partnerships.

                                       61

ACQUISITION OF LEASES
The managing general partner will have the right, in its sole discretion, to
select the prospects which each partnership will drill. The managing general
partner intends that Atlas America Public #14-2004 L.P., which must close on or
before December 31, 2004, will drill the prospects described in "Appendix A -
Information Regarding Currently Proposed Prospects for Atlas America Public
#14-2004 L.P." The managing general partner also anticipates that it will
designate a portion of the prospects in each partnership designated Atlas
America Public #14-2005(_____) L.P. by a supplement or an amendment to the
registration statement of which this supplement is a part.

The leases covering each prospect on which one well will be drilled will be
acquired by a partnership from the managing general partner or its affiliates
and credited to the managing general partner as a part of its required capital
contribution to the partnership. Neither the managing general partner nor its
affiliates will receive any royalty or overriding royalty interest on any well.

The managing general partner anticipates that it will select the prospects for
each partnership, including any additional and/or substituted prospects, from
the following:

         o        leases in its and its affiliates' existing leasehold
                  inventory;

         o        leases that are subsequently acquired by it or its affiliates;
                  or

         o        leases owned by independent third-parties that may participate
                  with the partnership in drilling wells.

Most of the prospects acquired by a partnership will be in areas where the
managing general partner or its affiliates have previously conducted drilling
operations. The managing general partner believes that its and its affiliates'
leasehold inventory and leases acquired from third-parties will be sufficient to
provide all the prospects to be drilled by each partnership.

The managing general partner and its affiliates are continually engaged in
acquiring additional leasehold acreage in Pennsylvania, Ohio, and other areas of
the United States. As of April 30, 2004, the managing general partner's and its
affiliates' undeveloped leasehold acreage was as follows:



                                                                                     UNDEVELOPED LEASE ACREAGE
                                                                                     -------------------------
                                                                                      GROSS          NET (1)
                                                                                      -----          -------
Kentucky.....................................................................            9,710         4,855
Montana......................................................................            2,650         2,650
New York.....................................................................           37,737        37,737
Ohio.........................................................................           36,552        33,403
Pennsylvania.................................................................          131,483       131,483
West Virginia................................................................           10,806         5,403
Wyoming......................................................................               80            80
                                                                                       -------       -------
                                   Total.....................................          229,018       215,561
                                                                                       =======       =======


(1) The net acreage as to which leases expire in fiscal 2004, 2005 and 2006 are
    as follows: New York: 2006 - 287 acres; Ohio: 2004 - 184 acres, 2005 - 464
    acres, 2006 - 96 acres; Pennsylvania: 2004 - 2,867 acres, 2005 - 16,599
    acres, 2006 - 25,071 acres.

                                       62

Most, if not all, of the prospects to be selected for the partnerships are
expected by the managing general partner to be single well proved undeveloped
prospects. Thus, only one well will be drilled on those prospects and the number
of prospects the managing general partner will assign to each partnership will
be the same as the number of wells which the partnership has the funds to drill.
This also means that the partnership, in all likelihood, will not farmout any
acreage associated with those prospects. However, the need for a farmout might
arise, for example, if during drilling or subsequently the managing general
partner determines there might be a productive horizon situated above (i.e.
uphole) the target horizon, but the partnership does not have the funds to
complete the well in the horizon or the completion of the horizon would be
inconsistent with the partnership's objectives. In this event, the managing
general partner might determine to farmout the activity for the partnership.
Generally, a farmout is an agreement in which the owner of the lease or existing
well agrees to assign its interest in certain acreage under the lease or the
existing well to an assignee subject to the assignee drilling one or more wells
or completing or recompleting the existing well in one or more horizons. The
owner would retain some interest in the assigned acreage or well. See "Conflicts
of Interest - Conflicts Involving the Acquisition of Leases" for the procedure
for a farmout, and "Material Federal Income Tax Consequences - Farmouts."

DEEP DRILLING RIGHTS RETAINED BY MANAGING GENERAL PARTNER. In the areas where
the Clinton/Medina is the primary geological formation, the lease assignments to
each partnership will be limited to a depth of from the surface to the top of
the Queenston geological formation, and the managing general partner will retain
the deeper drilling rights beginning with the Queenston geological formation. In
all other areas the lease assignments to each partnership will be limited to a
depth of from the surface through the completion total depth of the well and the
managing general partner will retain the deeper drilling rights including
ownership of any coal bed methane production that might be obtained from the
deeper formations. Conversely, as between a partnership and the managing general
partner, the partnership will own any coal bed methane production that might be
obtained from the shallower formations that are not included in the deeper
drilling rights retained by the managing general partner.

The amount of the credit the managing general partner receives for the leases it
contributes to a partnership does not include any value allocable to the deeper
drilling rights retained by it. If in the future the managing general partner
undertakes any activities with respect to the deeper formations, then the
partnerships would not share in the profits from these activities, nor would
they pay any of the associated costs.

INTERESTS OF PARTIES
Generally, production and revenues from a well drilled by a partnership will be
net of the applicable landowner's royalty interest, which is typically 1/8th
(12.5%) of gross production, and any interest in favor of third-parties such as
an overriding royalty interest. Landowner's royalty interest generally means an
interest that is created in favor of the landowner when an oil and gas lease is
obtained; and overriding royalty interest generally means an interest that is
created in favor of someone other than the landowner. In either case, the owner
of the interest receives a specific percentage of the natural gas and oil
production free and clear of all costs of development, operation, or maintenance
of the well. This is compared with a working interest, which generally means an
interest in the lease under which the owner of the interest must pay some
portion of the cost of development, operation, or maintenance of the well. Also,
the leases will be subject to terms that are customary in the industry such as
free gas to the landowner-lessor for home heating requirements, etc.

The managing general partner anticipates that each partnership generally will
have a net revenue interest in its leases in its primary drilling areas as set
forth in the chart below. Net revenue interest generally means the percentage of
revenues the owner of an interest in a well is entitled to receive under the
lease. The following chart expresses the percentage of production revenues that
the managing general partner, the landowner, other third-parties, and you and
the other investors in a partnership will share in from the wells in three of
the four primary proposed areas. The fourth primary proposed area in Armstrong
County, Pennsylvania is discussed following the chart. The chart assumes that
the partnership owns 100% of the working interest in the well. If a partnership
acquires a lesser percentage working interest in a well, which will be the case
for all of the proposed wells situated in Armstrong County, for example, then
the partnership's net revenue interest in that well will decrease
proportionately.

The actual number, identity and percentage of working interests or other
interests in prospects to be acquired by the partnerships will depend on, among
other things:

         o        the amount of subscription proceeds received in a partnership;

         o        the latest geological and production data;

                                       63

         o        potential title or spacing problems;

         o        availability and price of drilling services, tubular goods and
                  services;

         o        approvals by federal and state departments or agencies;

         o        agreements with other working interest owners in the
                  prospects;

         o        farmins and farmouts; and

         o        continuing review of other prospects that may be available.

PRIMARY AREAS.
CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA AND
MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS IN FAYETTE AND GREENE
COUNTIES, PENNSYLVANIA AND UPPER DEVONIAN SANDSTONE RESERVOIRS IN MCKEAN COUNTY,
PENNSYLVANIA.


                                                  PARTNERSHIP                    THIRD PARTY                87.5% PARTNERSHIP
ENTITY                                            INTEREST                     ROYALTY INTEREST          NET REVENUE INTEREST (2)
- ------                                         --------------                ------------------          ------------------------
Managing General Partner.................32% partnership interest (1)                                           28.0%
Investors................................68% partnership interest (1)                                           59.5%
Third Party..........................................................12.5% Landowner Royalty Interest           12.5%
                                                                                                               ------
                                                                                                               100.0%
                                                                                                               ======

- -------------
(1) These percentages are for illustration purposes only and assume the managing
    general partner's minimum required capital contribution to each partnership
    of 25% and capital contributions of 75% from you and the other investors.
    The actual percentages are likely to be different because they will be based
    on the actual capital contributions of the managing general partner and you
    and the other investors. However, the managing general partner's total
    revenue share may not exceed 35% of partnership revenues regardless of the
    amount of its capital contributions.
(2) It is possible that the wells could have a net revenue interest to a
    partnership as low as 84.375% which would reduce the investors' interest to
    57.375%.

UPPER DEVONIAN SANDSTONE RESERVOIRS IN ARMSTRONG COUNTY, PENNSYLVANIA. The
managing general partner anticipates the leases in Armstrong County,
Pennsylvania will have a net revenue interest to a partnership of 84.375% which
would reduce the investors' net revenue interest in the above chart to 57.375%
assuming a 100% working interest. U.S. Energy, the originator of the leases,
however, will retain a 25% working interest in the wells and participate with
the partnership in the costs of drilling, completing, and operating the wells to
the extent of its retained working interest. Thus, the net revenue interest to
the investors will be reduced to approximately 43% which is 75% of 57.375%.

SECONDARY AREAS. Although the managing general partner anticipates that each
partnership will have a net revenue interest ranging from 81% to 87.5% in the
secondary areas described above, there is no minimum net revenue interest that a
partnership is required to own before drilling a well in other areas of the
United States. The leases in these other areas may be subject to interests in
favor of third-parties that are not currently known such as:

         o        overriding royalty interests;

         o        net profits interests;

         o        carried interests;

         o        production payments;

                                       64

         o        reversionary interests pursuant to farmouts or non-consent
                  elections under joint operating agreements; or

         o        other retained or carried interests.

TITLE TO PROPERTIES
Title to all leases acquired by a partnership will be held in the name of the
partnership. However, to facilitate the acquisition of the leases title to the
leases may initially be held in the name of:

         o        the managing general partner;

         o        the operator;

         o        their affiliates; or

         o        any nominee designated by the managing general partner.

Title to each partnership's leases will be transferred to the partnership and
filed for record from time to time after the wells are drilled and completed.

The managing general partner will take the steps it deems necessary to assure
that each partnership has acceptable title for its purposes. However, it is not
the practice in the natural gas and oil industry to warrant title or obtain
title insurance on leases and the managing general partner will provide neither
for the leases it assigns to a partnership. The managing general partner will
obtain a favorable formal title opinion for the leases before each well is
drilled, but will not obtain a division order title opinion after the well is
completed. The managing general partner may use its own judgment in waiving
title requirements and will not be liable for any failure of title of leases
transferred to a partnership. Also, there is no assurance that the partnerships
will not experience losses from title defects excluded from or not disclosed by
the formal title opinion or that would have been disclosed by a division order
title opinion. Although past performance is no guarantee of future results, as
of September 30, 2003 the previous partnerships sponsored by the managing
general partner and its affiliates have participated in drilling more than 1,991
wells in the Appalachian Basin since 1985, and none of the wells have been lost
because of title failure. (See "Prior Activities.")

DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS
The managing general partner intends that Atlas America Public #14-2004 L.P.,
which must close on or before December 31, 2004, will drill the prospects
described in "Appendix A - Information Regarding Currently Proposed Prospects
for Atlas America Public #14-2004 L.P." These prospects represent a portion of
the wells to be drilled if the nonbinding targeted subscription proceeds
described in "Terms of the Offering - Subscription to a Partnership" are
received. The managing general partner also anticipates that it will designate a
portion of the prospects in each partnership designated Atlas America Public
#14-2005(_____) L.P. by a supplement or an amendment to the registration
statement of which this prospectus is a part. On receipt of the minimum
subscription proceeds the managing general partner on behalf of a partnership
may break escrow, transfer the escrowed funds to a partnership account, enter
into the drilling and operating agreement, which is attached to the partnership
agreement as Exhibit II, with itself or an affiliate as operator, and begin
drilling to the extent the prospects have been identified in this prospectus or
in a supplement or an amendment to the registration statement.

Under the drilling and operating agreement, the responsibility for drilling and
either completing or plugging partnership wells will be on the managing general
partner or an affiliate as the operator and the general drilling contractor.
Under the drilling and operating agreement, each partnership is required to
prepay the investors' share of the drilling and completion costs of its wells to
the managing general partner as the operator. If one or more of a partnership's
wells will be drilled in the calendar year after the year in which the advance
payment is made, the required advance payment allows the partnership to secure
tax benefits of prepaid intangible drilling costs based on a substantial
business purpose for the advance payment under the drilling and operating
agreement. The managing general partner as operator and general drilling
contractor will begin drilling the wells no later than March 31, 2005 for Atlas
America Public #14-2004 L.P., and March 31, 2006 Atlas America Public
#14-2005(B) L.P. (See "Material Federal Income Tax Consequences-Drilling
Contracts.")

                                       65

During drilling operations the managing general partner's duties as operator and
general drilling contractor will include:

         o        making the necessary arrangements for drilling and completing
                  partnership wells and related facilities for which it has
                  responsibility under the drilling and operating agreement;

         o        managing and conducting all field operations in connection
                  with drilling, testing, and equipping the wells; and

         o        making the technical decisions required in drilling and
                  completing the wells.

All partnership wells will be drilled to a sufficient depth to test thoroughly
the objective geological formation.

Under the drilling and operating agreement the managing general partner, as
operator and general drilling contractor, will complete each well if there is a
reasonable probability of obtaining commercial quantities of natural gas or oil.
However, based on its past experience, the managing general partner anticipates
that most of the development wells drilled in the primary and secondary areas
will have to be completed before it can determine the well's productivity. If
the managing general partner, as operator and general drilling contractor,
determines that a well should not be completed, then the well will be plugged
and abandoned.

During producing operations the managing general partner's duties, as operator,
will include:

         o        managing and conducting all field operations in connection
                  with operating and producing the wells;

         o        making the technical decisions required in operating the
                  wells; and

         o        maintaining the wells, equipment, and facilities in good
                  working order during their useful life.

The managing general partner, as operator, will be reimbursed for its direct
expenses and will receive well supervision fees at competitive rates for
operating and maintaining the wells during producing operations. As discussed in
"Summary of Drilling and Operating Agreement," the drilling and operating
agreement contains a number of other material provisions which you are urged to
review.
Certain wells may be drilled with third-parties owning a portion of the working
interest in the wells. Any other working interest owner in a well may have a
separate agreement with the managing general partner for drilling and operating
the well with differing terms and conditions from those contained in a
partnership's drilling and operating agreement.

SALE OF NATURAL GAS AND OIL PRODUCTION
POLICY OF TREATING ALL WELLS EQUALLY IN A GEOGRAPHIC AREA. The managing general
partner is responsible for selling each partnership's natural gas and oil
production, and its policy is to treat all wells in a given geographic area
equally. This reduces certain potential conflicts of interest among the owners
of the various wells, including the partnerships, concerning to whom and at what
price the natural gas and oil will be sold. For example, the managing general
partner calculates a weighted average selling price for all of the natural gas
sold in the geographic area by dividing the money received from the sale of all
of the natural gas sold to customers in the area, which may be at different
prices, by the volume of all natural gas sold from the wells in the area. For
natural gas sold in western Pennsylvania the managing general partner received
an average selling price after deducting all expenses, including transportation
expenses, of approximately:

         o        $2.35 per mcf, which means 1,000 cubic feet of natural gas, in
                  1999;

         o        $3.30 per mcf in 2000;

         o        $4.08 per mcf in 2001;

         o        $3.34 per mcf in 2002; and

                                       66

         o        $4.78 per mcf in 2003.

These prices were after the effects of hedging.

If all the natural gas produced cannot be sold because of limited gathering line
or pipeline capacity, or limited demand for the natural gas, which increases
pipeline pressure, then the production that is sold will be from those wells
which have the greatest well pressure and are able to feed into the pipeline,
regardless of which partnerships own the wells. The proceeds from these natural
gas sales will be credited only to the partnerships whose wells produced the
natural gas sold.

GATHERING OF NATURAL GAS. Under the partnership agreement the managing general
partner will be responsible for gathering and transporting the natural gas
produced by the partnerships to interstate pipeline systems, local distribution
companies, and/or end-users in the area. For the majority of each partnership's
natural gas production, including natural gas in the primary areas, as discussed
below, the managing general partner anticipates that it will use the gathering
system owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating
Partnership) which is a master limited partnership formed by a subsidiary of
Atlas America as managing general partner using Atlas America and Viking
Resources personnel who act as its officers and employees. Atlas Pipeline
Partners acquired the natural gas gathering system and related facilities of
Atlas America, Resource Energy, and Viking Resources in February 2000. At
December 31, 2003, the gathering system consists of approximately 1,380 miles of
intrastate pipelines located in western Pennsylvania, eastern Ohio, and western
New York. If a partnership's natural gas is not transported through the Atlas
Pipeline Partners gathering system, it is because there is a third-party
operator or the gathering system has not been extended to the wells. In these
cases, which includes the McKean County area as described in "Compensation -
Gathering Fees," the natural gas will be transported through a third-party
gathering system, and the partnership will pay the managing general partner a
competitive gathering fee, all or a portion of which will be paid by it to the
third-party.

As a part of the sale of the gathering system to Atlas Pipeline Partners in
February 2000, Atlas America and its affiliates, Resource Energy and Viking
Resources, made the commitments set forth below which to varying degrees may
affect the partnerships. The commitments were intended to maximize the use and
expansion of the gathering system. These are continuing obligations of Atlas
America, Resource Energy, and Viking Resources.

Atlas America, Resource Energy and Viking Resources are required to pay a
gathering fee to Atlas Pipeline Partners equal to the greater of $0.35 per mcf
or 16% of the gross sales price for each mcf transported through the gathering
system of Atlas Pipeline Partners. If a partnership pays a lesser amount, which
is anticipated by the managing general partner to range from $.29 per mcf to
$.35 per mcf except in the McKean County area as described in "Compensation -
Gathering Fees," then Atlas America, Resource Energy or Viking Resources must
pay the difference to Atlas Pipeline Partners. Also, Atlas America, Resource
Energy and Viking Resources committed to adding 225 wells to the gathering
system over a period from January 1, 1999, until December 31, 2002, which
included any well drilled in a partnership sponsored by them, which has been
satisfied. The wells had to be drilled within 2,500 feet of the gathering system
and the partnership as the well owner had to construct up to 2,500 feet of small
diameter sales or flow lines from the wellhead to the gathering system. Finally,
Atlas America, Resource Energy and Viking Resources agreed to assist Atlas
Pipeline Partners in identifying existing gathering systems for possible
acquisition and Atlas America agreed to provide construction management and
financing services to Atlas Pipeline Partners in the construction of additions
or extensions to the gathering system. For a period of five years from January
28, 2000, to January 28, 2005, Atlas America has a standby commitment for a
maximum of $1.5 million in any contract year.

NATURAL GAS CONTRACTS. Initially, the majority of each partnership's natural gas
production will be sold to UGI Energy Services, Inc. As set forth in "- Primary
Areas of Operations" above, the managing general partner anticipates that more
prospects will be drilled in Fayette County than the other areas, and the
majority, if not all, of the natural gas produced from Fayette County will be
sold to UGI Energy Services until March 31, 2006 for which UGI Corporation has
provided a $7 million guaranty of the payment obligations of UGI Energy
Services, Inc. Also, the natural gas produced from Armstrong County will be sold
to U.S. Energy Exploration Corporation and the natural gas produced from McKean
County will be sold to M&M Royalty Ltd. The managing general partner anticipates
that the remainder of the natural gas produced by each partnership from wells
drilled in the other primary and secondary areas will be sold to First Energy
Solutions Corporation. See "Appendix A - Information Regarding Currently
Proposed Prospects for Atlas America Public #14-2004 L.P."

                                       67



With regard to natural gas sold to First Energy Solutions Corporation, the
managing general partner and its affiliates have an agreement with First Energy
Solutions Corporation, which is the marketing affiliate of First Energy
Corporation, which is based in Akron, Ohio and is a large regional electric
utility listed on the New York Stock Exchange and trading under the symbol (FE).
As of June 14, 2004 the managing general partner and its affiliates, including
its prior affiliated partnerships, were selling approximately 52.4% of their
natural gas production under the agreement with First Energy Solutions
Corporation. The parties to the agreement are the managing general partner,
Resource Energy and Atlas Energy Group, Inc., and the agreement is for a 10-year
term which began on April 1, 1999. Subject to the exceptions set forth below,
First Energy Solutions Corporation has the right to buy all of the natural gas
produced and delivered by the managing general partner and its affiliates, which
includes the partnerships, at certain delivery points with the facilities of:

    o   East Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio,
        and Peoples Natural Gas Company, which are local distribution companies;
        and

    o   National Fuel Gas Supply, Columbia Gas Transmission Corporation,
        Tennessee Gas Pipeline Company, and Texas Eastern Transmission Company,
        which are interstate pipelines.

The agreement with First Energy Solutions Corporation requires the parties to
negotiate a new pricing arrangement at each delivery point for subsequent
contract periods which is usually one year. If, at the end of any applicable
period, the parties cannot agree to a new price for any delivery point, then the
managing general partner and its affiliates may solicit offers from
third-parties to buy the natural gas for that delivery point. If First Energy
Solutions Corporation does not match this price, then the natural gas may be
sold to the third-party. This process is repeated at the end of each contract
period. The agreement with First Energy Solutions Corporation may be suspended
for force majeure, which means generally such things as an act of God, but also
includes the permanent closing of the factories of Carbide Graphite or Duferco
Farrell Corporation during the term of First Energy Solutions Corporation's
agreements to sell natural gas to them. If these factories were closed, however,
the managing general partner believes that First Energy Solutions Corporation
would be able to find alternative purchasers and would not invoke the force
majeure. The managing general partner agreed to a new pricing arrangement with
First Energy Solutions Corporation which is effective through March 2006. First
Energy Corporation has provided a guaranty of the monetary obligations of First
Energy Solutions Corporation of an amount up to $15 million for a period until
March 31, 2005, which will continue on a monthly basis thereafter unless
terminated on 30 days notice. As of January 1, 2004, this guaranty would cover
natural gas sales of all the managing general partner's partnerships for
approximately 85 days of sales.

The majority of the managing general partner's and its affiliates' natural gas
is subject to the agreement with First Energy Solutions Corporation, with the
following exceptions, some of which will apply to the partnerships as discussed
above regarding the initial purchasers of the partnerships' natural gas produced
from Fayette, Armstrong and McKean Counties anticipated by the managing general
partner:

    o   natural gas sold through interconnects established after the agreement
        with First Energy Solutions Corporation which includes the majority of
        the natural gas produced from wells in Fayette County;

    o   natural gas being sold to Warren Consolidated, an industrial end-user,
        and direct delivery customer of the managing general partner and its
        affiliates;

    o   natural gas that at the time of the agreement was already dedicated for
        the life of the well to another buyer;

    o   natural gas that is produced by a company which was not an affiliate of
        the managing general partner at the time of the agreement;

    o   natural gas that is delivered to interstate pipelines or local
        distribution companies other than those described above; or

    o   natural gas that is produced from well(s) operated by a third-party or
        subject to an agreement under which a third-party was to arrange for the
        gathering and sale of the natural gas such as natural gas produced from
        wells in Armstrong County and natural gas produced from wells in McKean
        County.

                                       68



The pricing arrangements with First Energy Solutions Corporation, UGI Energy
Services, U.S. Energy Exploration Corporation, M&M Royalty Ltd. and the other
third-parties are tied to the New York Mercantile Exchange Commission ("NYMEX")
monthly futures contracts price, which is reported daily in the Wall Street
Journal. The total price received for each partnership's natural 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 natural gas (the Appalachian Basin) in
relation to the natural gas market which is referred to as the basis. The
premium over quoted prices on the NYMEX received by the managing general partner
and its affiliates has ranged between $0.33 to $0.46 per Mcf during the past
three fiscal years. See "- Policy of Treating All Wells Equally in a Geographic
Area" for the average natural gas prices since 1999.


Pricing for natural gas and oil has been volatile and unpredictable for many
years. To limit the managing general partner's and its partnerships' exposure to
changes in natural gas prices the managing general partner uses hedges through
its natural gas purchasers as described below, and 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 the 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. To assure that the financial instruments will be used solely for hedging
price risks and not for speculative purposes, the managing general partner has
established a committee to assure that all financial trading is done in
compliance with the managing general partner's hedging policies and procedures.
The managing general partner does not intend to contract for positions that it
cannot offset with actual production.

First Energy Solutions Corporation, UGI Energy Services and other third-party
marketers also use NYMEX based financial instruments to hedge their pricing
exposure and make price hedging opportunities available to the managing general
partner. As of June 14, 2004, the majority of the managing general partner's
hedges are implemented through the natural gas purchasers. These transactions
are similar to NYMEX based futures contracts, swaps and options, but also
require firm delivery of the hedged quantity. Thus, the managing general partner
limits these arrangements to much smaller quantities than those projected to be
available at any delivery point. The price paid by First Energy Solutions
Corporation, UGI Energy Services, and any other third-party marketers for
certain volumes of natural gas sold under these hedge agreements may be
significantly different from the underlying monthly spot market value.

The portion of natural gas that is hedged and the manner in which it is hedged
(e.g. fixed pricing, floor and/or costless collar pricing, which is a floor
price with a cap, etc.) changes from time to time. As of June 14, 2004, the
managing general partner's overall price hedging position for the future months
ending December 31, 2004 was approximately as follows:

         o        51.2% was hedged with a fixed price;

         o        13.3% was hedged with a floor price and/or costless collar
                  price; and

         o        35.5% was not hedged and was subject to market based pricing.

Approximately 49.6% of these hedges were implemented through First Energy
Solutions Corporation and 15.8% were implemented through UGI Energy Services. It
is difficult to project what portion of these hedges will be allocated to each
partnership by the managing general partner because of uncertainty about the
quantity, timing, and delivery locations of natural gas that may be produced by
a partnership. Although hedging provides the partnerships some protection
against falling prices, these activities also could reduce the potential
benefits of price increases.

MARKETING OF NATURAL GAS PRODUCTION FROM WELLS IN OTHER AREAS OF THE UNITED
STATES. The managing general partner expects that natural gas produced from
wells drilled in areas of the Appalachian Basin other than described above, will
be primarily tied to the spot market price and supplied to:

                                       69

         o        gas marketers;

         o        local distribution companies;

         o        industrial or other end-users; and/or

         o        companies generating electricity.

CRUDE OIL. Crude oil produced from the wells will flow directly into storage
tanks where it will be picked up by the oil company, a common carrier, or
pipeline companies acting for the oil company which is purchasing the crude oil.
Unlike natural gas, crude oil does not present any transportation problem. The
managing general partner anticipates selling any oil produced by the wells to
regional oil refining companies at the prevailing spot market price for
Appalachian crude oil in spot sales. The managing general partner was receiving
an average selling price for oil of approximately:

         o        $16.20 per barrel in 1999;

         o        $26.21 per barrel in 2000;

         o        $22.60 per barrel in 2001;

         o        $18.92 per barrel in 2002; and

         o        $29.06 per barrel in 2003.

During the term of the partnerships it is anticipated that the price of oil will
be uncertain and volatile.

INSURANCE
Since 1972 the managing general partner and its affiliates, including its
partnerships, have been involved in the drilling of approximately 5,300 wells,
most of which were developmental wells, in Ohio, Pennsylvania, and other areas
of the Appalachian Basin. They have made only one material insurance claim when
in February 2003 one of the wells in another investment partnership incurred an
uncontrolled flow of natural gas and oil with a fire during drilling which was
subsequently controlled, but resulted in the loss of a subcontractor's drilling
rig and third-party claims. As of June 16, 2004, the managing general partner's
insurance carrier has paid approximately $1,233,000 for property damage claims
to third-parties and additional claims have been submitted which have not yet
been paid. The managing general partner's insurance company is exploring all
avenues for subrogation. See "Actions to be Taken by Managing General Partner to
Reduce Risks of Additional Payments by Investor General Partners - Insurance"
for a discussion of the insurance coverage.

USE OF CONSULTANTS AND SUBCONTRACTORS
The partnership agreement authorizes the managing general partner to use the
services of independent outside consultants and subcontractors on behalf of the
partnerships. The services will normally be paid on a per diem or other cash fee
basis and will be charged to the partnership on whose behalf the costs were
incurred as either a direct cost or as a direct expense under the drilling and
operating agreement. These charges will be in addition to the unaccountable,
fixed payment reimbursement paid to the managing general partner for
administrative costs and well supervision fees paid to the managing general
partner as operator.

                       COMPETITION, MARKETS AND REGULATION

NATURAL GAS REGULATION
Governmental agencies regulate the production and transportation of natural gas.
Generally, the regulatory agency in the state where a producing natural gas well
is located supervises production activities and the transportation of natural
gas sold into intrastate markets, and the Federal Energy Regulatory Commission
("FERC") regulates the interstate transportation of natural gas.

                                       70

Natural gas prices have not been regulated since 1993, and the price of natural
gas is subject to the supply and demand for the natural gas along with factors
such as the natural gas' BTU content and where the wells are located.

Since 1985 FERC has sought to promote greater competition in natural gas markets
in the United States. Traditionally, natural gas was sold by producers to
interstate pipeline companies which served as wholesalers that resold the
natural gas to local distribution companies for resale to end-users. FERC
changed this market structure by requiring interstate pipeline companies to
transport natural gas for third-parties. In 1992 FERC issued Order 636 and a
series of related orders which required pipeline companies to, among other
things, separate their sales services from their transportation services and
provide an open access transportation service that is comparable in quality for
all natural gas producers or suppliers. The premise behind FERC Order 636 was
that the interstate pipeline companies had an unfair advantage over other
natural gas producers or suppliers because they could bundle their sales and
transportation services together. FERC Order 636 is designed to ensure that no
natural gas seller has a competitive advantage over another natural gas seller
because it also provides transportation services.

In 2000 FERC issued Order 637 and subsequent orders to enhance competition by
removing price ceilings on short-term capacity release transactions. It also
enacted other regulatory policies that are intended to enhance competition in
the natural gas market and increase the flexibility of interstate natural gas
transportation. FERC has further required pipeline companies to develop
electronic bulletin boards to provide standardized access to information
concerning capacity and prices.

CRUDE OIL REGULATION
Oil prices are not regulated, and the price is subject to the supply and demand
for oil, along with qualitative factors such as the gravity of the crude oil and
sulfur content differentials.

COMPETITION AND MARKETS
There are many companies engaged in natural gas and oil drilling operations in
the Appalachian Basin, where all or most of the wells in each partnership will
be located. According to the Energy Information Administration, the independent
statistical and analytical agency within the Department of Energy, in 2002 there
were 23 TCF (a "TCF" means one trillion cubic feet of natural gas) of natural
gas consumed in the United States which represented approximately 23.6% of the
total energy used. The Appalachian Basin accounted for approximately 3.4% of the
total domestic natural gas production in the year 2002 in the United States.
Also, according to the Natural Gas Annual 2002, an annual report published by
the Energy Information Administration Office of Oil and Gas, as of December 31,
2002, the Appalachian Basin's economically recoverable reserves represented
approximately 5.7% of total domestic reserves. Further, World Oil magazine
predicted in its February 2004 issue that approximately 5,576 oil and gas wells
will be drilled in the Appalachian Basin during 2004, representing approximately
16.7% of the total number of wells it predicted will be drilled in the United
States during 2004. This is an increase of 12.8% over the number of Appalachian
wells to have been drilled during 2003 compared to an increase of 9.7% in the
total wells to have been drilled in the United States from 2003 to 2004.

The oil and gas industry is highly competitive in all phases, including
acquiring suitable leases to drill and marketing natural gas and oil production
from the wells. Product availability and price are the principal means of
competing in selling natural gas and oil. Many of the partnerships' competitors
will have financial resources and staffs larger than those available to the
partnerships. This may enable them to identify and acquire desirable leases and
market their natural gas and oil production more effectively than the managing
general partner and the partnerships. While it is impossible to accurately
determine the partnerships' industry position, the managing general partner does
not consider the partnerships' operations to be a significant factor in the
industry.

Current economic conditions indicate that the costs of exploration and
development are increasing gradually. However, the natural gas and oil industry
has from time to time experienced periods of rapid cost increases. Over the term
of a partnership there may be fluctuating or increasing costs in doing business
which directly affect the managing general partner's ability to operate the
partnership's wells at acceptable price levels. Also, the natural gas and oil
price increases which have occurred from time to time may increase the demand
for drilling rigs and other related equipment. This may increase the cost to
drill the wells, which are drilled for the partnerships on a cost plus 15%
basis, or reduce the availability of drilling rigs and related equipment, both
of which could adversely affect the partnerships. In this regard, the cost of a
partnership well has increased recently because the cost of tubular steel has
increased as a result of rising steel prices.

                                       71

The natural gas and oil produced by your partnership's wells must be marketed
for you to receive revenues. During the fiscal years ending 2003, 2002 and 2001,
the managing general partner did not experience any problems in selling natural
gas and oil, although the prices varied significantly during those periods. As
set forth above, natural gas and oil prices are not regulated, but instead are
subject to factors which are generally beyond the partnership's control such as
the supply and demand for the natural gas and oil. For example, reduced natural
gas demand and/or excess natural gas supplies will result in lower prices. Other
factors affecting the price and/or marketing of natural gas and oil production,
which are also beyond the control of the partnerships and cannot be accurately
predicted, are the following:

         o        the proximity, availability, and capacity of pipeline and
                  other transportation facilities;

         o        competition from other energy sources such as coal and nuclear
                  energy;

         o        competition from alternative fuels when large consumers of
                  natural gas are able to convert to alternative fuel use
                  systems;

         o        local, state, and federal regulations regarding production and
                  transportation;

         o        the general level of market demand for natural gas and oil on
                  a regional, national and worldwide basis;

         o        fluctuating seasonal supply and demand for natural gas and oil
                  because of various factors such as home heating requirements
                  in the winter months;

         o        political instability and/or war in natural gas and oil
                  producing countries;

         o        the amount of domestic production of natural gas and oil; and

         o        the amount of foreign imports of natural gas and oil,
                  including liquid natural gas from Canada which the managing
                  general partner believes becomes economic when natural gas
                  prices are at or above $3.50 per mcf, and the actions of the
                  members of the Organization of Petroleum Exporting Countries
                  ("OPEC") which include production quotas for petroleum
                  products from time to time with the intent of increasing,
                  maintaining, or decreasing price levels.

For example, the North American Free Trade Agreement ("NAFTA") eliminated trade
and investment barriers in the United States, Canada, and Mexico, and from time
to time there have been increased imports into the United States of Canadian
natural gas. Without a corresponding increase in demand in the United States,
the imported natural gas would have an adverse effect on both the price and
volume of natural gas sales from the partnerships' wells.


The managing general partner is unable to predict what effect the various
factors set forth above will have on the future price of the natural gas and oil
sold from the partnerships' wells. However, according to the Energy Information
Administration in 2001, the use of natural gas in the United States is projected
to increase approximately 51% to 69% between 1999 and 2020, and there have been
several developments which the managing general partner believes have the effect
of increasing the demand for natural gas. For example, the Clean Air Act
Amendments of 1990 contain incentives for the future development of "clean
alternative fuel," which includes natural gas and liquefied petroleum gas for
"clean-fuel vehicles." Also, the accelerating deregulation of electricity
transmission has caused a convergence between the natural gas and electricity
industries. In 2003, according to information from the Energy Information
Administration, the breakout of energy sources for the generation of electricity
in the United States was as follows:


         o        natural gas fired power plants were used to produce
                  approximately 15%;

         o        coal-fired power plants were used to produce approximately
                  53%;

                                       72

         o        nuclear power plants were used to produce approximately 21%;
                  and

         o        large scale hydroelectric projects were used to produce
                  approximately 7%.

In recent years, the electricity industry has increased its reliance on natural
gas because of increased competition in the electricity industry and the
enforcement of stringent environmental regulations, and according to the Energy
Information Administration, the demand for natural gas by producers of
electricity is expected to increase through the decade. For example, the
Environmental Protection Agency has sought to enforce environmental regulations
which increase the cost of operating coal-fired power plants. Also, the last
nuclear power plant to come online in the United States was in June 1996,
although the existing nuclear power plants have increased their capacity. Thus,
the managing general partner believes that natural gas is becoming the fuel of
choice for electricity producers since they have started moving away from
dirtier-burning fuels, such as coal and oil and no nuclear power plants have
come online since 1996. Also, some of the new natural gas fired power plants
which are coming into service are not designed to allow for switching to other
fuels.

STATE REGULATIONS
Oil and gas operations are regulated in Pennsylvania by the Department of
Environmental Resources. Pennsylvania and the other states where each
partnership's wells may be situated impose a comprehensive statutory and
regulatory scheme for natural gas and oil operations, including supervising the
production activities and the transportation of natural gas sold in intrastate
markets, which creates additional financial and operational burdens. Among other
things, these regulations involve:

         o        new well permit and well registration requirements,
                  procedures, and fees;

         o        landowner notification requirements;

         o        certain bonding or other security measures;

         o        minimum well spacing requirements;

         o        restrictions on well locations and underground gas storage;

         o        certain well site restoration, groundwater protection, and
                  safety measures;

         o        discharge permits for drilling operations;

         o        various reporting requirements; and

         o        well plugging standards and procedures.

These state regulatory agencies also have broad regulatory and enforcement
powers including those associated with pollution and environmental control laws,
which are discussed below.

ENVIRONMENTAL REGULATION
Each partnership's drilling and producing operations are subject to various
federal, state, and local laws covering the discharge of materials into the
environment, or otherwise relating to the protection of the environment. The
Environmental Protection Agency and state and local agencies will require the
partnerships to obtain permits and take other measures with respect to:

         o        the discharge of pollutants into navigable waters;

         o        disposal of wastewater; and

         o        air pollutant emissions.

                                       73

If these requirements or permits are violated there can be substantial civil and
criminal penalties which will increase if there was willful negligence or
misconduct. Also, the partnerships may be subject to fines, penalties and
unlimited liability for cleanup costs under various federal laws such as the
Federal Clean Water Act, the Clean Air Act, the Resource Conservation and
Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and
the Comprehensive Environmental Response, Compensation and Liability Act of 1980
for oil and/or hazardous substance contamination or other pollution caused by
the drilling activities or the well and its production.

Also, a partnership's liability can extend to pollution costs that occurred on
the leases before they were acquired by the partnership. Although the managing
general partner will not transfer any lease to a partnership if it has actual
knowledge that there is an existing potential environmental liability on the
lease, there will not be an independent environmental audit of the leases before
they are transferred to a partnership. Thus, there is a risk that the leases
will have potential environmental liability even before drilling begins.

A partnership's required compliance with these environmental laws and
regulations may cause delays or increase the cost of the partnership's drilling
and producing activities. Because these laws and regulations are frequently
changed, the managing general partner is unable to predict the ultimate costs of
complying with present and future environmental laws and regulations. Also, the
managing general partner is unable to obtain insurance to protect against many
environmental claims.

PROPOSED REGULATION
From time to time there are a number of proposals considered in Congress and in
the legislatures and agencies of various states that if enacted would
significantly and adversely affect the natural gas and oil industry and the
partnerships. The proposals involve, among other things:

         o        limiting the disposal of waste water from wells, which could
                  substantially increase a partnership's operating costs and
                  make the partnership's wells uneconomical to produce; and

         o        changes in the tax laws as discussed in "Material Federal
                  Income Tax Consequences-Changes in the Law."

Also, Congress could re-enact price controls in the future. However, it is
impossible to accurately predict what proposals, if any, will be enacted and
their subsequent effect on a partnership's activities.

                       PARTICIPATION IN COSTS AND REVENUES

IN GENERAL
The partnership agreement provides for the sharing of costs and revenues among
the managing general partner and you and the other investors. A tabular summary
of the following discussion appears below. Each partnership will be a separate
business entity from the other partnerships, and you will be a partner only in
the partnership in which you invest. You will have no interest in the business,
assets, or tax benefits of the other partnerships unless you also invest in the
other partnerships. Thus, your investment return will depend solely on the
operations and success or lack of success of the particular partnership in which
you invest.

COSTS
1.    ORGANIZATION AND OFFERING COSTS. Organization and offering costs will be
      charged 100% to the managing general partner. However, the managing
      general partner will not receive any credit towards its required capital
      contribution or its revenue share for any organization and offering costs
      charged to it in excess of 15% of a partnership's investors' subscription
      proceeds.

         o        Organization and offering costs generally means all costs of
                  organizing and selling the offering and includes the
                  dealer-manager fee, sales commissions, the up to .5%
                  reimbursement for bona fide accountable due diligence
                  expenses, and the .5% accountable reimbursement for
                  permissible non-cash compensation.

                                       74

      The managing general partner will pay a portion of the organization and
      offering costs to itself, its affiliates and third-parties and it will
      contribute the remainder to the partnership in the form of services
      related to organizing this offering. The managing general partner will
      receive a credit for these payments and services towards its required
      capital contribution in each partnership. The managing general partner's
      credit for its contribution of services for organization costs will be
      determined based on generally accepted accounting principles. The
      definition of organization and offering costs is set forth in the
      partnership agreement.

2.    LEASE COSTS. Each partnership's leases will be contributed by the managing
      general partner. The managing general partner will be credited with a
      capital contribution for each lease valued at:

         o        its cost; or

         o        fair market value if the managing general partner has reason
                  to believe that cost is materially more than fair market
                  value.

3.    INTANGIBLE DRILLING COSTS. Intangible drilling costs of your partnership
      will be charged 100% to you and the other investors.

         o        Intangible drilling costs generally means those costs of
                  drilling and completing a well that are currently deductible,
                  as compared with lease costs, which must be recovered through
                  the depletion allowance, and equipment costs, which must be
                  recovered through depreciation deductions.

Although subscription proceeds of a partnership may be used to pay the costs of
drilling different wells depending on when the subscriptions are received, not
less than 90% of the subscription proceeds of you and the other investors will
be used to pay intangible drilling costs regardless of when you subscribe. Also,
even if the IRS successfully challenged the managing general partner's
characterization of a portion of these costs as deductible intangible drilling
costs, and instead recharacterized the costs as some other item that may be
non-deductible, such as equipment costs and/or lease costs, this
recharacterization by the IRS would have no effect on the allocation and payment
of the costs by you and the other investors under the partnership agreement.

4.    EQUIPMENT COSTS. Equipment costs of your partnership will be charged 66%
      to the managing general partner and 34% to you and the other investors.
      However, if the total equipment costs for your partnership's wells that
      would be charged to you and the other investors exceeds an amount equal to
      10% of the subscription proceeds of you and the other investors in the
      partnership, then the excess will be charged to the managing general
      partner. See the discussion of equipment costs in 5, below.

         o        Equipment costs generally means the costs of drilling and
                  completing a well that are not currently deductible and are
                  not lease costs.

5.    OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER COSTS.
      Operating costs, direct costs, administrative costs, and all other
      partnership costs of your partnership not specifically charged will be
      charged to the parties in the same ratio as the related production
      revenues are being credited.

         o        These costs generally include all costs of partnership
                  administration and producing and maintaining the partnership's
                  wells.

      Each well in a partnership will have a different productive life and as a
      well becomes uneconomic to produce it will be plugged and abandoned. The
      costs of plugging and abandoning a well (other than those incurred in
      connection with the drilling of a nonproductive well) are shared between
      the managing general partner and you and the other investors in the same
      percentage as the related production revenues are being shared. For
      example, if the investors are receiving 68% of the partnership revenues


                                       75

      and the managing general partner is receiving 32% of the partnership
      revenues, then the cost of plugging and abandoning the wells will be
      shared in the same percentages. Typically, the managing general partner
      will apply the salvage value of the equipment, which generally is shared
      66% by the managing general partner and 34% by you and the other
      investors, towards this obligation. These sharing percentages, however,
      may vary to a small degree as discussed in 4, above, depending on the
      total equipment costs for your partnerships wells compared to 10% of the
      subscription proceeds of you and the other investors in the partnership.
      See "Compensation - Drilling Contracts," for a discussion of the
      partnerships' equipment costs estimated by the managing general partner
      for an average well in the primary drilling areas. To cover any shortfall
      for you and the other investors between your share of the equipment
      proceeds and your share of the plugging and abandoning costs of the well,
      the managing general partner has the right beginning one year after a
      partnership well begins producing to retain up to $200 per month to cover
      future plugging and abandonment costs of the well. This $200 also includes
      a proportionate share of the managing general partner's share of
      partnership revenues, which will be used exclusively for the managing
      general partner's share of the plugging and abandonment costs of the well.
      To the extent any portion of the reserve ultimately is not needed for the
      plugging and abandonment costs of the well, then it will be returned to
      the general operating revenues of the partnership.

6.    THE MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTION. The managing
      general partner's aggregate capital contributions to each partnership must
      not be less than 25% of all capital contributions to that partnership.
      This includes such items as the managing general partner's:

         o        credit for the cost of the leases contributed to the
                  partnership, or the fair market value of the leases if the
                  managing general partner has a reason to believe that cost is
                  materially more than fair market value;

         o        credit for organization and offering costs, including the
                  costs of services contributed as organization costs; and

         o        share of partnership equipment costs paid by it to itself as
                  operator under the drilling and operating agreement, which
                  includes its administrative overhead reimbursement and profit
                  on those costs.

The managing general partner's capital contributions must be paid or made at the
time the costs are required to be paid by the partnership, but not later than
the end of the year immediately following the year in which the partnership had
its final closing.

REVENUES
Each partnership's production revenues from all of its wells will be commingled.
Thus, regardless of when you subscribe to a partnership you will share in the
production revenues from all of the wells in that partnership on the same basis
as the other investors in the partnership in proportion to your number of units.

1.    PROCEEDS FROM THE SALE OF LEASES. If a partnership well is sold, a portion
      of the sales proceeds will be allocated to the partners in the same
      proportion as their share of the adjusted tax basis of the property. In
      addition, proceeds will be allocated to the managing general partner to
      the extent of the pre-contribution appreciation in value of the property,
      if any. Any excess will be credited as provided in 4, below.

2.    INTEREST PROCEEDS. Interest income earned on your subscription proceeds
      before your partnership's final closing will be credited to your account
      and paid not later than the partnership's first cash distributions from
      operations. After your partnership's final closing and until the
      subscription proceeds are invested in your partnership's operations, any
      interest income from temporary investments will be allocated pro rata to
      you and the other investors providing the subscription proceeds. All other
      interest income, including interest earned on the deposit of production
      revenues, will be credited as provided in 4, below.

3.    EQUIPMENT PROCEEDS. Proceeds from the sale or other disposition of
      equipment will be credited to the parties charged with the costs of the
      equipment in the ratio in which the costs were charged.

                                       76

4.    PRODUCTION REVENUES. Subject to the managing general partner's
      subordination obligation as described below, the managing general partner
      and the investors in a partnership will share in all of that partnership's
      other revenues, including production revenues, in the same percentage as
      their respective capital contribution bears to the total partnership
      capital contributions, except that the managing general partner will
      receive an additional 7% of that partnership's revenues. However, the
      managing general partner's total revenue share may not exceed 35% of that
      partnership's revenues regardless of the amount of its capital
      contributions. For example, if the managing general partner contributes
      the minimum of 25% of the total partnership capital contributions and the
      investors contribute 75% of the total partnership capital contributions,
      then the managing general partner will receive 32% of the partnership
      revenues and the investors will receive 68% of the partnership revenues.
      On the other hand, if the managing general partner contributes 30% of the
      total partnership capital contributions and the investors contribute 70%
      of the total partnership capital contributions, then the managing general
      partner will receive 35% of the partnership revenues, not 37%, because its
      revenue share cannot exceed 35% of partnership revenues, and the investors
      will receive 65% of partnership revenues.

SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET REVENUE SHARE
Each partnership is structured to provide you and the other investors with cash
distributions equal to a minimum of 10% per unit, based on $10,000 per unit
regardless of the actual subscription price for your units, in each of the first
five 12-month periods beginning with that partnership's first cash distributions
from operations. To help achieve this investment feature, the managing general
partner will subordinate up to 50% of its share of the managing general
partner's share of partnership net production revenues during this subordination
period.

         o        Partnership net production revenues means gross revenues after
                  deduction of the related operating costs, direct costs,
                  administrative costs, and all other costs not specifically
                  allocated.

Each partnership's 60-month subordination period will begin with that
partnership's first cash distribution from operations to you and the other
investors. However, no subordination distributions to you and the other
investors will be required until that partnership's first cash distribution
after substantially all of the partnership wells have been drilled, completed,
and begun producing into a sales line. Subordination distributions will be
determined by debiting or crediting current period partnership revenues to the
managing general partner as may be necessary to provide the distributions to you
and the other investors. At any time during the subordination period the
managing general partner is entitled to an additional share of partnership
revenues to recoup previous subordination distributions to the extent your cash
distributions from that partnership exceed the 10% return of capital described
above. The specific formula is set forth in Section 5.01(b)(4)(a) of the
partnership agreement.

The managing general partner anticipates that you will benefit from the
subordination if the price of natural gas and oil received by the partnership
and/or the results of the partnership's drilling activities are unable to
provide the required return. However, if the wells produce small natural gas and
oil volumes or natural gas and oil prices decrease, then even with subordination
your cash flow may be very small and you may not receive the 10% return of
capital for each of the first five years beginning with the partnership's first
cash distribution from operations.


As of April 15, 2004, the managing general partner was subordinating a portion
or all of its net revenues in two of its previous twelve limited partnerships
that currently have the subordination feature in effect. Since 1993 the managing
general partner has had a subordination feature in 27 of its partnerships and
from time to time it has subordinated its partnership net revenues in 16 of
these partnerships. The managing general partner is entitled to recoup these
subordination distributions during the subordination period to the extent cash
distributions to the investors in these previous partnerships would exceed the
specified return to the investors.


                                       77

EXAMPLE OF NET REVENUE SHARING DURING A SUBORDINATION PERIOD.


                                                                                                      NET REVENUES TO MANAGING
                                                                               MAXIMUM AMOUNT OF        GENERAL PARTNER AND
                                                                               MANAGING GENERAL     INVESTORS IF MAXIMUM AMOUNT
                                    PERCENTAGE OF        PERCENTAGE OF        PARTNER'S SHARE OF        OF MANAGING GENERAL
                                     PARTNERSHIP        PARTNERSHIP NET         PARTNERSHIP NET          PARTNER'S SHARE OF
                                       CAPITAL          REVENUES WITHOUT    REVENUES AVAILABLE FOR  PARTNERSHIP NET REVENUES IS
ENTITY                            CONTRIBUTIONS (1)    SUBORDINATION (1)       SUBORDINATION (2)        SUBORDINATED (1)(2)
- ------                            -----------------    -----------------       -----------------        -------------------
Managing General Partner................25%                   32%                    16%                        16%
Investors...............................75%                   68%                                               84%

- ------------------
(1) These percentages are for illustration purposes only and assume the managing
    general partner's minimum required capital contribution of 25% to each
    partnership and capital contributions of 75% from you and the other
    investors. The actual percentages are likely to be different because they
    will be based on the actual capital contributions of the managing general
    partner and you and the other investors. However, the managing general
    partner's total revenue share may not exceed 35% of partnership revenues
    regardless of the amount of its capital contribution.
(2) Each partnership is structured to provide you and the other investors with
    cash distributions equal to a minimum of 10% per unit, based on $10,000 per
    unit regardless of the actual subscription price for your units, in each of
    the first five 12-month periods beginning with the partnership's first cash
    distributions from operations. To help achieve this investment feature, the
    managing general partner will subordinate up to 50% of its share of
    partnership net production revenues during this subordination period.

EXAMPLE OF NET REVENUE SHARING AFTER THE END OF A SUBORDINATION PERIOD.


                                                                                                      NET REVENUES TO MANAGING
                                                                               MAXIMUM AMOUNT OF         GENERAL PARTNER AND
                                                                                MANAGING GENERAL     INVESTORS IF MAXIMUM AMOUNT
                                    PERCENTAGE OF        PERCENTAGE OF         PARTNER'S SHARE OF        OF MANAGING GENERAL
                                     PARTNERSHIP        PARTNERSHIP NET         PARTNERSHIP NET          PARTNER'S SHARE OF
                                       CAPITAL          REVENUES WITHOUT     REVENUES AVAILABLE FOR  PARTNERSHIP NET REVENUES IS
ENTITY                            CONTRIBUTIONS (1)    SUBORDINATION (1)         SUBORDINATION            SUBORDINATED (1)
- ------                            -----------------    -----------------         -------------            ----------------
Managing General Partner.................25%                  32%                     0%                         32%
Investors................................75%                  68%                                                68%

- ----------------
(1) These percentages are for illustration purposes only and assume the managing
    general partner's minimum required capital contribution of 25% to each
    partnership and capital contributions of 75% from you and the other
    investors. The actual percentages are likely to be different because they
    will be based on the actual capital contributions of the managing general
    partner and you and the other investors. However, the managing general
    partner's total revenue share may not exceed 35% of partnership revenues
    regardless of the amount of its capital contribution.

TABLE OF PARTICIPATION IN COSTS AND REVENUES
The following table sets forth the partnership costs and revenues charged and
credited between the managing general partner and you and the other investors in
each partnership after deducting from the partnership's gross revenues, the
landowner royalties, and any other lease burdens.

                                       78



                                                                                MANAGING
                                                                                GENERAL
                                                                                PARTNER              INVESTORS
                                                                                --------             ---------
PARTNERSHIP COSTS
Organization and offering costs.....................................................100%                   0%
Lease costs.........................................................................100%                   0%
Intangible drilling costs.............................................................0%                 100%
Equipment costs (1)..................................................................66%                  34%
Operating costs, administrative costs, direct costs, and all other costs.............(2)                  (2)

PARTNERSHIP REVENUES
Interest income......................................................................(3)                  (3)
Equipment proceeds (1)...............................................................66%                  34%
All other revenues including production revenues..................................(4)(5)               (4)(5)

PARTICIPATION IN DEDUCTIONS
Intangible drilling costs.............................................................0%                 100%
Depreciation (1).....................................................................66%                  34%
Percentage depletion allowance.................................................(4)(5)(6)            (4)(5)(6)

- --------------
(1) These percentages may vary. If the total equipment costs for all of a
    partnership's wells that would be charged to you and the other investors
    exceeds an amount equal to 10% of the subscription proceeds of you and the
    other investors in that partnership, then the excess will be charged to the
    managing general partner. Equipment proceeds, if any, will be credited in
    the same percentage in which the equipment costs were charged.
(2) These costs, which also include plugging and abandonment costs of the wells
    after the wells have been drilled and produced, will be charged to the
    parties in the same ratio as the related production revenues are being
    credited.
(3) Interest earned on your subscription proceeds before a partnership's final
    closing will be credited to your account and paid not later than the
    partnership's first cash distributions from operations. After the
    partnership's final closing and until proceeds from the offering are
    invested in the partnership's operations any interest income from temporary
    investments will be allocated pro rata to the investors providing the
    subscription proceeds. All other interest income in the partnership,
    including interest earned on the deposit of operating revenues, will be
    credited as production revenues are credited.
(4) In each partnership the managing general partner and the investors will
    share in all of the partnership's other revenues in the same percentage as
    their respective capital contributions bears to the total partnership
    capital contributions except that the managing general partner will receive
    an additional 7% of the partnership revenues. However, the managing general
    partner's total revenue share in a partnership may not exceed 35% of
    partnership revenues.
(5) If a portion of the managing general partner's partnership net production
    revenues is subordinated, then the actual allocation of partnership revenues
    between the managing general partner and the investors will vary from the
    allocation described in (4) above.
(6) The percentage depletion allowances will be in the same percentages as the
    production revenues.

ALLOCATION AND ADJUSTMENT AMONG INVESTORS
The investors' share as a group of each partnership's revenues, gains, income,
costs, expenses, losses, and other charges and liabilities generally will be
charged and credited among you and the other investors in that partnership in
accordance with the ratio that your respective number of units bears to the
number of units held by all investors as a group in that partnership, based on
$10,000 per unit regardless of the actual subscription price for an investor's
units. These allocations will take into account any investor general partner's
status as a defaulting investor general partner. Certain investors, however,
will pay a reduced amount for their units as described in "Plan of
Distribution." Thus, intangible drilling costs and the investors' share of the
equipment costs of drilling and completing the partnership's wells will be
charged among you and the other investors in a partnership in accordance with
the respective subscription price you and the other investors paid for the units
rather than the number of their respective units.

                                       79

DISTRIBUTIONS
The managing general partner will review each partnership's accounts at least
quarterly to determine whether cash distributions are appropriate and the amount
to be distributed, if any, taking into account its subordination obligation
discussed above in "-Subordination of Portion of Managing General Partner's Net
Revenue Share." Your partnership will distribute funds to you and the other
investors that the managing general partner, in its sole discretion, does not
believe are necessary for the partnership to retain. Distributions may be
reduced or deferred to the extent partnership revenues are used for any of the
following:

         o        repayment of borrowings;

         o        cost overruns;

         o        remedial work to improve a well's producing capability;

         o        direct costs and general and administrative expenses of the
                  partnership;

         o        reserves, including a reserve for the estimated costs of
                  eventually plugging and abandoning the wells; or

         o        indemnification of the managing general partner and its
                  affiliates by the partnership for losses or liabilities
                  incurred in connection with the partnership's activities.

Also, funds will not be advanced or borrowed for distributions if the
distribution amount would exceed the partnership's accrued and received revenues
for the previous four quarters, less paid and accrued operating costs with
respect to the revenues. Any cash distributions from a partnership to the
managing general partner will be made only in conjunction with distributions to
you and the other investors in that partnership and only out of funds properly
allocated to the managing general partner's account.

LIQUIDATION
Each partnership will continue for 50 years unless it is terminated earlier by a
final terminating event as described below, or an event which causes the
dissolution of a limited partnership under the Delaware Revised Uniform Limited
Partnership Act. However, if a partnership terminates on an event which causes a
dissolution under state law and it is not a final terminating event, then a
successor limited partnership will automatically be formed. Thus, only on a
final terminating event will a partnership be liquidated. A final terminating
event is any of the following:

         o        the election to terminate the partnership by the managing
                  general partner or the affirmative vote of investors whose
                  units equal a majority of the total units;

         o        the termination of the partnership under Section 708(b)(1)(A)
                  of the Internal Revenue Code because no part of its business
                  is being carried on; or

         o        the partnership ceases to be a going concern.

On the partnership's liquidation you will receive your interest in the
partnership to which you subscribed. Generally, your interest in the partnership
means an undivided interest in the partnership's assets, after payments to the
partnership's creditors, in the ratio your capital account bears to all of the
capital accounts until they have been reduced to zero. Thereafter, your interest
in the remaining partnership assets will equal your interest in the related
partnership revenues.

Any in-kind property distributions to you from a partnership must be made to a
liquidating trust or similar entity, unless you affirmatively consent to receive
an in-kind property distribution after being told of the risks associated with
the direct ownership or there are alternative arrangements in place which assure
that you will not be responsible for the operation or disposition of the
partnership's properties. If the managing general partner has not received your
written consent to the in-kind distribution within 30 days after it is mailed,
then it will be presumed that you have not consented. The managing general
partner may then sell the asset at the best price reasonably obtainable from an
independent third-party, or to itself or its affiliates at fair market value as
determined by an independent expert selected by the managing general partner.
Also, if a partnership is liquidated, the managing general partner will be
repaid for any debts owed to it by the partnership before there are any payments
to you and the other investors in that partnership.

                                       80

                              CONFLICTS OF INTEREST

IN GENERAL
Conflicts of interest are inherent in natural gas and oil partnerships involving
non-industry investors because the transactions are entered into without arms'
length negotiation. Your interests and those of the managing general partner and
its affiliates may be inconsistent in some respects or in certain instances, and
the managing general partner's actions may not be the most advantageous to you.

The following discussion describes certain possible conflicts of interest that
may arise for the managing general partner and its affiliates in the course of
each partnership. For some of the conflicts of interest, but not all, there are
certain limitations on the managing general partner that are designed to reduce,
but which will not eliminate, the conflicts. Other than these limitations the
managing general partner has no procedures to resolve a conflict of interest and
under the terms of the partnership agreement the managing general partner may
resolve the conflict of interest in its sole discretion and best interest.

The following discussion is materially complete; however, other transactions or
dealings may arise in the future that could result in conflicts of interest for
the managing general partner and its affiliates.

CONFLICTS REGARDING TRANSACTIONS WITH THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES
Although the managing general partner believes that the compensation and
reimbursement that it and its affiliates will receive in connection with each
partnership are reasonable, the compensation has been determined solely by the
managing general partner and did not result from negotiations with any
unaffiliated third-party dealing at arms' length. The managing general partner
and its affiliates will receive compensation and reimbursement from each
partnership for their services in drilling, completing, and operating that
partnership's wells under the drilling and operating agreement and will receive
the other fees described in "Compensation" regardless of the success of that
partnership's wells. The managing general partner and its affiliates providing
the services or equipment can be expected to profit from the transactions, and
it is usually in the managing general partner's best interest to enter into
contracts with itself and its affiliates rather than unaffiliated third-parties
even if the contract terms, skill, and experience, offered by the unaffiliated
third-parties is comparable.

The partnership agreement provides that when the managing general partner and
any affiliate provide services or equipment to a partnership their fees must be
competitive with the fees charged by unaffiliated third-parties in the same
geographic area engaged in similar businesses. Also, before the managing general
partner and any affiliate may receive competitive fees for providing services or
equipment to a partnership they must be engaged, independently of the
partnership and as an ordinary and ongoing business, in rendering the services
or selling or leasing the equipment and supplies to a substantial extent to
other persons in the natural gas and oil industry in addition to the
partnerships in which the managing general partner or an affiliate has an
interest. If the managing general partner and any affiliate is not engaged in
such a business, then the compensation must be the lesser of its cost or the
competitive rate that could be obtained in the area.

Any services not otherwise described in this prospectus or the partnership
agreement for which the managing general partner or an affiliate is to be
compensated by a partnership must be:

         o        set forth in a written contract that describes the services to
                  be rendered and the compensation to be paid; and

         o        cancelable without penalty on 60 days written notice by
                  investors whose units equal a majority of the total units.

The compensation, if any, will be reported to you in your partnership's annual
and semiannual reports, and a copy of the contract will be provided to you on
request.

                                       81

There is also a conflict of interest concerning the purchase price if the
managing general partner or an affiliate purchases a property from a
partnership, which they may do in certain limited circumstances as described in
"- Conflicts Involving the Acquisition of Leases - (6) Limitations on Sale of
Undeveloped and Developed Leases to the Managing General Partner," below.

CONFLICT REGARDING THE DRILLING AND OPERATING AGREEMENT
The managing general partner anticipates that all of the wells drilled by each
partnership will be drilled and operated under the drilling and operating
agreement. This creates a continuing conflict of interest because the managing
general partner must monitor and enforce, on behalf of each partnership, its own
compliance with the drilling and operating agreement.

CONFLICTS REGARDING SHARING OF COSTS AND REVENUES
The managing general partner will receive a percentage of revenues greater than
the percentage of costs that it pays. This sharing arrangement may create a
conflict of interest between the managing general partner and you and the other
investors in a partnership concerning the determination of which wells will be
drilled by the partnership based on the risk and profit potential associated
with the wells.

In addition, the allocation of all of the intangible drilling costs to you and
the other investors and the majority of the equipment costs to the managing
general partner creates a conflict of interest between the managing general
partner and you and the other investors concerning whether to complete a well.
For example, the completion of a marginally productive well might prove
beneficial to you and the other investors, but not to the managing general
partner. When a completion decision is made you and the other investors will
have already paid the majority of your costs so you will want to pay your share
of the additional costs to complete the well if there is a reasonable
opportunity to recoup your share of the completion costs plus any portion of the
costs paid by you before the completion attempt. You will want to plug the well,
however, if it appears likely that you will not recoup all of your share of the
additional costs to complete the well.

On the other hand, the managing general partner will have paid only a portion of
its costs before this time, and it will want to pay its additional equipment
costs to complete the well only if it is reasonably certain of recouping its
share of the completion costs and making a profit. However, based on its past
experience the managing general partner anticipates that most of the wells in
the primary areas will have to be completed before it can determine the well's
productivity, which would eliminate this potential conflict of interest. In any
event, the managing general partner will not cause any well to be plugged and
abandoned without a completion attempt unless it makes the decision in
accordance with generally accepted oil and gas field practices in the geographic
area of the well location.

CONFLICTS REGARDING TAX MATTERS PARTNER
The managing general partner will serve as each partnership's tax matters
partner and represent the partnership before the IRS. The managing general
partner will have broad authority to act on behalf of you and the other
investors in the partnership in any administrative or judicial proceeding
involving the IRS, and this authority may involve conflicts of interest. For
example, potential conflicts include:

         o        whether or not to expend partnership funds to contest a
                  proposed adjustment by the IRS, if any, to:

                  o        the amount of a partnership's deduction for
                           intangible drilling costs, which is allocated 100% to
                           you and the other investors in the partnership; or

                  o        the amount of the managing general partner's
                           depreciation deductions, or the credit to its capital
                           account for contributing the leases to a partnership
                           if the proposed adjustment would decrease the
                           managing general partner's liquidation interest in
                           the partnership; or

         o        the amount of the managing general partner's reimbursement
                  from a partnership for expenses incurred by it in its role as
                  the tax matters partner as a reasonable, ordinary and
                  necessary business deduction.

                                       82

CONFLICTS REGARDING OTHER ACTIVITIES OF THE MANAGING GENERAL PARTNER, THE
OPERATOR AND THEIR AFFILIATES The managing general partner will be required to
devote to each partnership the time and attention that it considers necessary
for the proper management of the partnership's activities. However, the managing
general partner has sponsored and continues to manage other natural gas and oil
drilling partnerships, which may be concurrent, and will engage in unrelated
business activities, either for its own account or on behalf of other
partnerships, joint ventures, corporations, or other entities in which it has an
interest. This creates a continuing conflict of interest in allocating
management time, services, and other activities among the partnerships in this
program and its other activities. The managing general partner will determine
the allocation of its management time, services, and other functions on an
as-needed basis consistent with its fiduciary duties among the partnerships in
this program and its other activities.

Subject to its fiduciary duties, the managing general partner will not be
restricted from participating in other businesses or activities, even if these
other businesses or activities compete with a partnership's activities and
operate in the same areas as the partnership. However, the managing general
partner and its affiliates may pursue business opportunities that are consistent
with the partnership's investment objectives for their own account only after
they have determined that the opportunity either:

         o        cannot be pursued by the partnership because of insufficient
                  funds; or

         o        it is not appropriate for the partnership under the existing
                  circumstances.

CONFLICTS INVOLVING THE ACQUISITION OF LEASES
The managing general partner will select, in its sole discretion, the wells to
be drilled by each partnership. Conflicts of interest may arise concerning which
wells will be drilled by each partnership in this program and which wells will
be drilled by the managing general partner's and its affiliates' other
affiliated partnerships or third-party programs in which they serve as
driller/operator. It may be in the managing general partner's or its affiliates'
advantage to have a partnership in this program bear the costs and risks of
drilling a particular well rather than another affiliate. These potential
conflicts of interest will be increased if the managing general partner
organizes and allocates wells to more than one partnership at a time. To lessen
this conflict of interest the managing general partner generally takes a similar
interest in other partnerships when it serves as managing general partner and/or
driller/operator.

The managing general partner anticipates that generally only one partnership
will be actively engaged in drilling at any time. However, when the managing
general partner must provide prospects to two or more partnerships at the same
time it will attempt to treat each partnership fairly on a basis consistent
with:

         o        the funds available to the partnerships; and

         o        the time limitations on the investment of funds for the
                  partnerships.

Generally, the managing general partner follows a policy of developing prospects
in the order of what it believes is the "best available prospect." However, the
managing general partner will constantly change its assessment of available
prospects based on the acquisition of new leases and information derived from
wells already drilled.

If more than one partnership in this program has funds available for drilling at
the same time, the partnerships will alternate drilling of wells based on the
"best available prospect" format. The determination of the "best available
prospect" is based on the managing general partner's assessment of the economic
potential of a prospect and its suitability to a particular partnership,
including the following factors:

         o        estimated reserves;

         o        the targeted geological formations;

         o        natural gas and oil markets;

                                       83

         o        geological and natural gas and oil market diversification
                  within the partnerships;

         o        the prospect's net revenue interest;

         o        estimated drilling costs; and

         o        limitations imposed by the prospectus and/or the partnership
                  agreement.

The partnership agreement gives the managing general partner the authority to
cause each partnership in this program to acquire undivided interests in natural
gas and oil properties, and to participate with other parties, including other
drilling programs previously or subsequently conducted by the managing general
partner or its affiliates, in the conduct of its drilling operations on those
properties. If conflicts between the interest of a partnership in this program
and other drilling partnerships do arise, then the managing general partner may
be unable to resolve those conflicts to the maximum advantage of the partnership
in this program because the managing general partner must deal fairly with the
investors in all of its drilling partnerships.

In addition, subject to the restrictions set forth below, the managing general
partner decides which prospects and what interest in the prospects to transfer
to a partnership. This will result in a subsequent partnership sponsored by the
managing general partner benefiting from knowledge gained through a prior
partnership's drilling experience in an area and acquiring a prospect adjacent
to the prior partnership's prospect.

No procedures, other than the guidelines set forth below and in " - Procedures
to Reduce Conflicts of Interest," have been established by the managing general
partner to resolve any conflicts that may arise. The partnership agreement
provides that the managing general partner and its affiliates will abide by the
guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and
(9) there is an exception in the partnership agreement for another program in
which the interest of the managing general partner is substantially similar to
or less than its interest in the partnerships.

(1)      TRANSFERS AT COST. All leases will be acquired from the managing
         general partner and credited towards its required capital contribution
         at the cost of the lease, unless the managing general partner has a
         reason to believe that cost is materially more than the fair market
         value of the property. If the managing general partner believes cost is
         materially more than fair market value, then the managing general
         partner's credit for the contribution must be at a price not in excess
         of the fair market value.

                  o        A determination of fair market value must be
                           supported by an appraisal from an independent expert
                           and maintained in the partnership's records for at
                           least six years.

(2)      EQUAL PROPORTIONATE INTEREST. When the managing general partner sells
         or transfers an oil and gas interest to a partnership, it must, at the
         same time, sell or transfer to the partnership an equal proportionate
         interest in all of its other property in the same prospect.

                  o        The term "prospect" generally means an area which is
                           believed to contain commercially productive
                           quantities of natural gas or oil.

         However, a prospect will be limited to the drilling or spacing unit on
         which one well will be drilled if the following two conditions are met:

                  o        the well is being drilled to a geological feature
                           which contains proved reserves as defined below; and

                  o        the drilling or spacing unit protects against
                           drainage.

                                       84

         The managing general partner believes that for a prospect located in
         Ohio, Pennsylvania and New York on which a well will be drilled to test
         the Clinton/Medina geologic formation or the Mississippian and/or Upper
         Devonian Sandstone reservoirs, a prospect will consist of the drilling
         and spacing unit because it will meet the test in the preceding
         sentence.

                  o        Proved reserves, generally, are the estimated
                           quantities of natural gas and oil which have been
                           demonstrated to be recoverable in future years with
                           reasonable certainty under existing economic and
                           operating conditions. Proved reserves include proved
                           undeveloped reserves which generally are reserves
                           expected to be recovered from existing wells where a
                           relatively major expenditure is required for
                           recompletion or from new wells on undrilled acreage.
                           Reserves on undrilled acreage will be limited to
                           those drilling units offsetting productive units that
                           are reasonably certain of production when drilled.
                           Proved Reserves for other undrilled units can be
                           claimed only where it can be demonstrated with
                           certainty that there is continuity of production from
                           the existing productive formation.

         The managing general partner anticipates that the majority of the wells
         drilled by each partnership will develop the Clinton/Medina geologic
         formation or the Mississippian and/or Upper Devonian Sandstone
         reservoirs. The drilling of these wells may provide the managing
         general partner with offset sites by allowing it to determine, at the
         partnership's expense, the value of adjacent acreage in which the
         partnership would not have any interest. The managing general partner
         owns acreage throughout the primary areas where each partnership's
         wells will be situated. To lessen this conflict of interest, for five
         years the managing general partner may not drill any well:

                  o        in the Clinton/Medina geologic formation within 1,650
                           feet of an existing partnership well in Pennsylvania
                           or within 1,000 feet of an existing partnership well
                           in Ohio; or

                  o        in the Mississippian/Upper Devonian Sandstone
                           reservoirs in Fayette and Green Counties,
                           Pennsylvania within at least 1,000 feet from a
                           producing well, although a partnership may drill a
                           new well or re-enter an existing well which is closer
                           than 1,000 feet to a plugged and abandoned well.

          If a partnership abandons its interest in a well, then this
         restriction will continue for one year following the abandonment. There
         are no similar prohibitions for the other primary areas.

(3)      SUBSEQUENTLY ENLARGING PROSPECT. In areas where the prospect is not
         limited to the drilling or spacing unit and the area constituting a
         partnership's prospect is subsequently enlarged based on geological
         information, which is later acquired, then there is the following
         special provision:

                  o        if the prospect is enlarged to cover any area where
                           the managing general partner owns a separate property
                           interest and the partnership activities were material
                           in establishing the existence of proved undeveloped
                           reserves which are attributable to the separate
                           property interest, then the separate property
                           interest or a portion thereof must be sold to the
                           partnership in accordance with (1), (2) and (4).

(4)      TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS
         AFFILIATES' ENTIRE INTEREST. If the managing general partner sells or
         transfers to a partnership less than all of its ownership in any
         prospect, then it must comply with the following conditions:

                  o        the retained interest must be a proportionate working
                           interest;

                  o        the managing general partner's obligations and the
                           partnership's obligations must be substantially the
                           same after the sale of the interest by the managing
                           general partner or its affiliates; and

                  o        the managing general partner's revenue interest must
                           not exceed the amount proportionate to its retained
                           working interest.

                                       85

         For example, if the managing general partner transfers 50% of its
         working interest in a prospect to a partnership and retains a 50%
         working interest, then the partnership will not pay any of the costs
         associated with the managing general partner's retained working
         interest as a part of the transfer. This limitation does not prevent
         the managing general partner and its affiliates from subsequently
         dealing with their retained working interest as they may choose with
         unaffiliated parties or affiliated partnerships. For example, the
         managing general partner may sell its retained working interest to a
         third-party for a profit.

(5)      LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
         AFFILIATES ON LEASES ACQUIRED BY A PARTNERSHIP. For a five year period
         after the final closing of a partnership, if the managing general
         partner proposes to acquire an interest from an unaffiliated person in
         a prospect in which the partnership owns an interest or in a prospect
         in which the partnership's interest has been terminated without
         compensation within one year before the proposed acquisition, then the
         following conditions apply:

                  o        if the managing general partner does not currently
                           own property in the prospect separately from the
                           partnership, then the managing general partner may
                           not buy an interest in the prospect; and

                  o        if the managing general partner currently owns a
                           proportionate interest in the prospect separately
                           from the partnership, then the interest to be
                           acquired must be divided in the same proportion
                           between the managing general partner and the
                           partnership as the other property in the prospect.
                           However, if the partnership does not have the cash or
                           financing to buy the additional interest, then the
                           managing general partner is also prohibited from
                           buying the additional interest.

(6)      LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE MANAGING
         GENERAL PARTNER. The managing general partner and its affiliates, other
         than an affiliated partnership as set forth in (7) below, may not
         purchase undeveloped leases or receive a farmout from a partnership
         other than at the higher of cost or fair market value. Farmouts to the
         managing general partner and its affiliates also must be made as set
         forth in (9) below.

         The managing general partner and its affiliates, other than an
         affiliated income program, may not purchase any producing natural gas
         or oil property from a partnership unless:

                  o        the sale is in connection with the liquidation of the
                           partnership; or

                  o        the managing general partner's well supervision fees
                           under the drilling and operating agreement for the
                           well have exceeded the net revenues of the well,
                           determined without regard to the managing general
                           partner's well supervision fees for the well, for a
                           period of at least three consecutive months.

         In both cases, the sale must be at fair market value supported by an
         appraisal of an independent expert selected by the managing general
         partner. The appraisal of the property must be maintained in the
         partnership's records for at least six years.

(7)      TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The
         transfer of an undeveloped lease from a partnership to an affiliated
         drilling limited partnership must be made at fair market value if the
         undeveloped lease has been held for more than two years. Otherwise, the
         transfer may be made at cost if the managing general partner deems it
         to be in the best interest of the partnership.

         An affiliated income program may purchase a producing natural gas and
         oil property from a partnership at any time at:

                  o        fair market value as supported by an appraisal from
                           an independent expert if the property has been held
                           by the partnership for more than six months or there
                           have been significant expenditures made in connection
                           with the property; or

                                       86

                  o        cost as adjusted for intervening operations if the
                           managing general partner deems it to be in the best
                           interest of the partnership.

         However, these prohibitions do not apply to joint ventures or farmouts
         among affiliated partnerships, provided that:

                  o        the respective obligations and revenue sharing of all
                           parties to the transaction are substantially the
                           same; and

                  o        the compensation arrangement or any other interest or
                           right of either the managing general partner or its
                           affiliates is the same in each affiliated partnership
                           or if different, the aggregate compensation of the
                           managing general partner or the affiliate is reduced
                           to reflect the lower compensation arrangement.

(8)      LEASES WILL BE ACQUIRED ONLY FOR STATED PURPOSE OF THE PARTNERSHIP.
         Each partnership must acquire only leases that are reasonably expected
         to meet the stated purposes of the partnership. Also, no leases may be
         acquired for the purpose of a subsequent sale, farmout or other
         disposition unless the acquisition is made after a well has been
         drilled to a depth sufficient to indicate that the acquisition would be
         in the partnership's best interest.

(9)      FARMOUT. The managing general partner will not assign to a partnership
         the working interest in a prospect for the purpose of a subsequent
         farmout, sale or other disposition. The managing general partner will
         not enter into a farmout to avoid paying its share of the costs related
         to drilling an undeveloped lease. However, the managing general
         partner's decision with respect to making a farmout and the terms of a
         farmout from a partnership involve conflicts of interest since the
         managing general partner may benefit from cost savings and reduction of
         risk.

         The partnership may farmout an undeveloped lease or well activity to
         the managing general partner, its affiliates or an unaffiliated
         third-party only if the managing general partner, exercising the
         standard of a prudent operator, determines that:

                  o        the partnership lacks the funds to complete the oil
                           and gas operations on the lease or well and cannot
                           obtain suitable financing;

                  o        drilling on the lease or the intended well activity
                           would concentrate excessive funds in one location,
                           creating undue risks to the partnership;

                  o        the leases or well activity have been downgraded by
                           events occurring after assignment to the partnership
                           so that development of the leases or well activity
                           would not be desirable; or

                  o        the best interests of the partnership would be
                           served.

         If the partnership farmouts a lease or well activity, the managing
         general partner must retain on behalf of the partnership the economic
         interests and concessions as a reasonably prudent oil and gas operator
         would or could retain under the circumstances prevailing at the time,
         consistent with industry practices. However, if the farmout is made to
         the managing general partner or its affiliates there is a conflict of
         interest since the managing general partner will represent both the
         partnership and itself or an affiliate. Although the conflict of
         interest may be resolved to the managing general partner's benefit, the
         managing general partner must still retain on behalf of the partnership
         the economic interests and concessions as a reasonably prudent oil and
         gas operator would or could retain under the circumstances prevailing
         at the time, consistent with industry practices.

CONFLICTS BETWEEN INVESTORS AND THE MANAGING GENERAL PARTNER AS AN INVESTOR
The managing general partner, its officers, directors, and affiliates may
subscribe for units in each partnership and the price of their units will be
reduced by 10.5% as described in "Plan of Distribution." Even though they pay a
reduced price for their units these investors generally will:

                                       87

         o        share in the partnership's costs, revenues, and distributions
                  on the same basis as the other investors as described in
                  "Participation in Costs and Revenues"; and

         o        have the same voting rights, except as discussed below.

Any subscription by the managing general partner, its officers, directors, or
affiliates will dilute the voting rights of you and the other investors and
there may be a conflict with respect to certain matters. The managing general
partner and its officers, directors and affiliates, however, are prohibited from
voting with respect to certain matters as described in "Summary of Partnership
Agreement - Voting Rights."

LACK OF INDEPENDENT UNDERWRITER AND DUE DILIGENCE INVESTIGATION
The terms of this offering, the partnership agreement, and the drilling and
operating agreement were determined by the managing general partner without
arms' length negotiations. You and the other investors have not been separately
represented by legal counsel, who might have negotiated more favorable terms for
you and the other investors in this offering and the agreements.

Also, there was not an extensive in-depth "due diligence" investigation of the
existing and proposed business activities of the partnerships and the managing
general partner that would be provided by independent underwriters. Although
Anthem Securities, which is affiliated with the managing general partner, serves
as dealer-manager and will receive reimbursement of accountable due diligence
expenses for certain due diligence investigations conducted by the selling
agents which will be reallowed to the selling agents, its due diligence
examination concerning this offering cannot be considered to be independent.

CONFLICTS CONCERNING LEGAL COUNSEL
The managing general partner anticipates that its legal counsel will also serve
as legal counsel to each partnership and that this dual representation will
continue in the future. If a future dispute arises between the managing general
partner and you and the other investors in a partnership, then the managing
general partner will cause you and the other investors to retain separate
counsel. Also, if counsel advises the managing general partner that counsel
reasonably believes its representation of a partnership will be adversely
affected by its responsibilities to the managing general partner, then the
managing general partner will cause you and the other investors in a partnership
to retain separate counsel.

CONFLICTS REGARDING PRESENTMENT FEATURE
You and the other investors in a partnership have the right to present your
units in the partnership to the managing general partner for purchase beginning
with the fifth calendar year after the end of the calendar year in which your
partnership closes. This creates the following conflicts of interest between you
and the managing general partner.

         o        The managing general partner may suspend the presentment
                  feature if it does not have the necessary cash flow or it
                  cannot borrow funds for this purpose on terms which it deems
                  reasonable. Both of these determinations are subjective and
                  will be made in the managing general partner's sole
                  discretion.

         o        The managing general partner will also determine the purchase
                  price based on a reserve report that it prepares and is
                  reviewed by an independent expert that it chooses. The formula
                  for arriving at the purchase price has many subjective
                  determinations that are within the discretion of the managing
                  general partner.

CONFLICTS REGARDING MANAGING GENERAL PARTNER WITHDRAWING AN INTEREST
A conflict of interest is created with you and the other investors by the
managing general partner's right to mortgage its interest or withdraw an
interest in each partnership's wells equal to or less than its revenue interest
to be used as collateral for a loan to the managing general partner. If there
was a default under the loan, this could reduce or eliminate the amount of the
managing general partner's partnership net production revenues available for its
subordination obligation to you and the other investors. Also under certain
circumstances, if the managing general partner made a subordination distribution
to you and the other investors after a default, then the lender may be able to
recoup from you and the other investors that subordination distribution.

CONFLICTS REGARDING ORDER OF PIPELINE CONSTRUCTION AND GATHERING FEES
The managing general partner may choose well locations along the Atlas Pipeline
Partners gathering system which would benefit its parent company by providing
more gathering fees to Atlas Pipeline Partners, even if there are other well
locations available in the area or other areas which offer the partnerships a
greater potential return. However, the managing general partner believes this
conflict of interest is substantially reduced because the managing general
partner expects to make the largest single capital contribution in each
partnership as explained in "Capitalization and Source of Funds and Use of
Proceeds." Thus, it is in the best interest of its parent company for the
managing general partner to choose prospects for a partnership to drill which
have the greatest potential reserves even if they are not connected to the Atlas
Pipeline Partners gathering system. In addition, Atlas America or an affiliate
will operate the Atlas Pipeline Partners gathering system. Thus, the expansion
of the Atlas Pipeline Partners gathering system will be within the control of
the managing general partner's affiliate, which will attempt to expand the Atlas
Pipeline Partners gathering system to those areas with the greatest number of
wells with the greatest potential reserves.

                                       88

The managing general partner's affiliates are obligated through their agreement
with Atlas Pipeline Partners to pay the difference between the amount each
partnership pays for gathering fees to the managing general partner as set forth
in "Compensation - Gathering Fees," and the greater of $.35 per mcf or 16% of
the gross sales price for the natural gas. This provides an incentive to the
managing general partner to increase the amount of the gathering fees paid by
each partnership to it, which are not fixed and may change as described in
"Compensation-Gathering Fees." However, the gathering fees paid to the managing
general partner may not exceed competitive rates.

PROCEDURES TO REDUCE CONFLICTS OF INTEREST
In addition to the procedures set forth in "- Conflicts Involving the
Acquisition of Leases," the managing general partner and its affiliates will
comply with the following procedures in the partnership agreement to reduce some
of the conflicts of interest with you and the other investors. The managing
general partner does not have any other conflict of interest resolution
procedures. Thus, conflicts of interest between the managing general partner and
you and the other investors may not necessarily be resolved in your best
interests. However, the managing general partner believes that its significant
capital contribution to each partnership will reduce the conflicts of interest.

(1)    FAIR AND REASONABLE. The managing general partner may not sell, transfer,
       or convey any property to, or purchase any property from, a partnership
       except pursuant to transactions that are fair and reasonable; nor take
       any action with respect to the assets or property of a partnership which
       does not primarily benefit the partnership.

(2)    NO COMPENSATING BALANCES. The managing general partner may not use a
       partnership's funds as a compensating balance for its own benefit. Thus,
       a partnership's funds may not be used to satisfy any deposit requirements
       imposed by a bank or other financial institution on the managing general
       partner for its own corporate purposes.

(3)    FUTURE PRODUCTION. The managing general partner may not commit the future
       production of a partnership well exclusively for its own benefit.

(4)    DISCLOSURE. Any agreement or arrangement that binds a partnership must be
       fully disclosed in this prospectus.

(5)    NO LOANS FROM A PARTNERSHIP. A partnership may not loan money to the
       managing general partner.

(6)    NO REBATES. The managing general partner may not participate in any
       business arrangements which would circumvent these guidelines including
       receiving rebates or give-ups.

(7)    SALE OF ASSETS. The sale of all or substantially all of the assets of a
       partnership may only be made with the consent of investors whose units
       equal a majority of the total units.

(8)    PARTICIPATION IN OTHER PARTNERSHIPS. If a partnership participates in
       other partnerships or joint ventures, then the terms of the arrangements
       must not circumvent any of the requirements contained in the partnership
       agreement, including the following:

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         o        there may be no duplication or increase in organization and
                  offering expenses, the managing general partner's
                  compensation, partnership expenses, or other fees and costs;

         o        there may be no substantive change in the fiduciary and
                  contractual relationship between the managing general partner
                  and you and the other investors; and

         o        there may be no diminishment in your voting rights.

(9)    INVESTMENTS. A partnership's funds may not be invested in the securities
       of another person except in the following instances:

         o        investments in working interests made in the ordinary course
                  of the partnership's business;

         o        temporary investments in income producing short-term highly
                  liquid investments, in which there is appropriate safety of
                  principal, such as U.S. Treasury Bills;

         o        multi-tier arrangements meeting the requirements of (8) above;

         o        investments involving less than 5% of the total subscription
                  proceeds of the partnership that are a necessary and
                  incidental part of a property acquisition transaction; and

         o        investments in entities established solely to limit the
                  partnership's liabilities associated with the ownership or
                  operation of property or equipment, provided that duplicative
                  fees and expenses are prohibited.

(10)   SAFEKEEPING OF FUNDS. The managing general partner may not employ, or
       permit another to employ, the funds or assets of a partnership in any
       manner except for the exclusive benefit of the partnership. The managing
       general partner has a fiduciary responsibility for the safekeeping and
       use of all funds and assets of each partnership whether or not in its
       possession or control.

(11)   ADVANCE PAYMENTS. Advance payments by each partnership to the managing
       general partner and its affiliates are prohibited except when advance
       payments are required to secure the tax benefits of prepaid intangible
       drilling costs and for a business purpose.

POLICY REGARDING ROLL-UPS
It is possible at some indeterminate time in the future that each partnership
may become involved in a roll-up. In general, a roll-up means a transaction
involving the acquisition, merger, conversion, or consolidation of a partnership
with or into another partnership, corporation or other entity, and the issuance
of securities by the roll-up entity to you and the other investors. A roll-up
will also include any change in the rights, preferences, and privileges of you
and the other investors in the partnership. These changes could include the
following:

         o        increasing the compensation of the managing general partner;

         o        amending your voting rights;

         o        listing the units on a national securities exchange or on
                  NASDAQ;

         o        changing the partnership's fundamental investment objectives;
                  or

         o        materially altering the partnership's duration.

If a roll-up should occur in the future the partnership agreement provides
various policies which include the following:

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         o        an independent expert must appraise all partnership assets,
                  and you must receive a summary of the appraisal in connection
                  with a proposed roll-up;

         o        if you vote "no" on the roll-up proposal, then you will be
                  offered a choice of:

                  o        accepting the securities of the roll-up entity; or

                  o        one of the following:

                           o        remaining a partner in the partnership and
                                    preserving your units in the partnership on
                                    the same terms and conditions as existed
                                    previously; or

                           o        receiving cash in an amount equal to your
                                    pro-rata share of the appraised value of the
                                    partnership's net assets; and

         o        the partnership will not participate in a proposed roll-up:

                  o        unless approved by investors whose units equal 66% of
                           the total units;

                  o        which would result in the diminishment of your voting
                           rights under the roll-up entity's chartering
                           agreement;

                  o        which includes provisions which would operate to
                           materially impede or frustrate the accumulation of
                           shares by you of the securities of the roll-up
                           entity;

                  o        in which your right of access to the records of the
                           roll-up entity would be less than those provided by
                           the partnership agreement; or

                  o        in which any of the transaction costs would be borne
                           by the partnership if the proposed roll-up is not
                           approved by investors whose units equal 66% of the
                           total units.

            FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER

IN GENERAL
The managing general partner will manage your partnership and its assets. In
conducting your partnership's affairs the managing general partner is
accountable to you as a fiduciary, which under Delaware law generally means that
the managing general partner must exercise due care and deal fairly with you and
the other investors. Neither the partnership agreement nor any other agreement
between the managing general partner and each partnership may contractually
limit any fiduciary duty owed to you and the other investors by the managing
general partner under applicable law except as set forth in Sections 4.01, 4.02,
4.03, 4.04, 4.05, and 4.06 of the partnership agreement. In this regard, the
partnership agreement does permit the managing general partner and its
affiliates to:

         o        have business interests or activities that may conflict with
                  the partnerships if they determine that the business
                  opportunity either:

                  o        cannot be pursued by the partnership because of
                           insufficient funds; or

                  o        it is not appropriate for the partnership under the
                           existing circumstances;

         o        devote only so much of their time as is necessary to manage
                  the affairs of each partnership;

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         o        conduct business with the partnerships in a capacity other
                  than as managing general partner or sponsor as described in
                  ss.ss.4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of the partnership
                  agreement;

         o        manage multiple programs simultaneously; and

         o        be indemnified and held harmless as described below in "-
                  Limitations on Managing General Partner Liability as
                  Fiduciary."

Other than as set forth above, the partnership agreement does not excuse the
managing general partner from liability or provide it with any defense for
breach of its fiduciary duty. The fiduciary duty owed by the managing general
partner to the partnership is analogous to the fiduciary duty owed by directors
to a corporation and its stockholders and is subject to the same rule, commonly
referred to as the "business judgment rule," that directors are not liable for
mistakes made in the good faith exercise of honest business judgment or for
losses incurred in the good faith performance of their duties when performed
with such care as an ordinarily prudent person would use. As a result of the
business judgment rule, the managing general partner may not be held liable for
mistakes made or losses incurred in the good faith exercise of reasonable
business judgment as described below in " - Limitations on Managing General
Partner Liability as Fiduciary."

If the managing general partner breaches its fiduciary responsibilities, then
you are entitled to an accounting and the recovery of any economic loss caused
by the breach. The Delaware Revised Uniform Limited Partnership Act provides
that a limited partner may institute legal action (a "derivative" action) on a
partnership's behalf to recover damages from a third-party when the managing
general partner refuses to institute the action or where an effort to cause the
managing general partner to do so is not likely to succeed. In addition, the
statutory or case law may permit a limited partner to institute legal action on
behalf of himself and all other similarly situated limited partners (a "class
action") to recover damages from the managing general partner for violations of
its fiduciary duties to the limited partners. Because this is a rapidly
expanding and changing area of the law, you are urged to consult your own
counsel if you have questions concerning the managing general partner's duties.

LIMITATIONS ON MANAGING GENERAL PARTNER LIABILITY AS FIDUCIARY
Under the terms of the partnership agreement the managing general partner, the
operator, and their affiliates have limited their liability to each partnership
and to you and the other investors for any loss suffered by your partnership or
you and the other investors in the partnership which arises out of any action or
inaction on their part if:

         o        they determined in good faith that the course of conduct was
                  in the best interest of the partnership;

         o        they were acting on behalf of, or performing services for, the
                  partnership; and

         o        their course of conduct did not constitute negligence or
                  misconduct.

In addition, the partnership agreement provides for indemnification of the
managing general partner, the operator, and their affiliates by each partnership
against any losses, judgments, liabilities, expenses, and amounts paid in
settlement of any claims sustained by them in connection with that partnership
provided that they meet the standards set forth above. However, there is a more
restrictive standard for indemnification for losses arising from or out of an
alleged violation of federal or state securities laws. Also, to the extent that
any indemnification provision in the partnership agreement purports to include
indemnification for liabilities arising under the Securities Act of 1933, as
amended, you should be aware that, in the SEC's opinion, this indemnification is
contrary to public policy and therefore unenforceable.


Payments arising from the indemnification or agreement to hold harmless are
recoverable only out of the following:

         o        the partnership's tangible net assets, which include its
                  revenues; and

         o        any insurance proceeds from the types of insurance for which
                  the managing general partner, the operator and their
                  affiliates may be indemnified under the partnership agreement.


                                       92



Still, use of partnership funds or assets for indemnification of the managing
general partner, the operator, or an affiliate would reduce amounts available
for partnership operations or for distribution to you and the other investors.

A partnership may not pay the cost of the portion of any insurance that insures
the managing general partner, the operator, or an affiliate against any
liability for which they cannot be indemnified. However, a partnership's funds
can be advanced to them for legal expenses and other costs incurred in any legal
action for which indemnification is being sought if the partnership has adequate
funds available and certain conditions in the partnership agreement are met.

The effect of the foregoing provisions and the business judgment rule may be to
limit your recourse against the managing general partner.


                    MATERIAL FEDERAL INCOME TAX CONSEQUENCES

SUMMARY OF TAX OPINION
This section of the prospectus is a summary of the tax opinion and of all the
material federal income tax consequences of the purchase, ownership and
disposition of the investor general partner units and the limited partner units.

The managing general partner has received and will rely on the tax opinion of
special counsel, Kunzman & Bollinger, Inc., Oklahoma City, Oklahoma, which is
included as Exhibit 8 to the Registration Statement, with respect to the
material federal income tax issues of an investment in a partnership.
Accordingly, no advance ruling on any tax consequence of an investment in a
partnership will be requested from the IRS. However, the tax opinion represents
only special counsel's best legal judgment, and has no binding effect or
official status. It is only special counsel's prediction as to the outcome of
the issues addressed and the results are not guaranteed. The IRS may challenge
the deductions claimed by a partnership or you, or the taxable year in which the
deductions are claimed, and no guaranty can be given that the challenge would
not be upheld if litigated. Special counsel's opinions are based in part on
certain factual representations of the managing general partner, which special
counsel has assumed to be correct for purposes of the tax opinion, and other
factual assumptions of special counsel which are set forth in the tax opinion.
In this regard, the managing general partner has represented that "typical
investors" in each partnership will be natural persons who purchase units in
this offering and are U.S. citizens. You are strongly urged to read the entire
tax opinion. See "Additional Information" for instructions in how to obtain a
copy of the tax opinion.

In special counsel's opinion the following tax treatment with respect to a
typical investor is the proper federal income tax treatment and will be upheld
if challenged by the IRS and litigated.

         o        PARTNERSHIP CLASSIFICATION. Each Partnership will be
                  classified as a partnership for federal income tax purposes,
                  and not as a corporation. The Partnerships, as such, will not
                  pay any federal income taxes, and all items of income, gain,
                  loss and deduction of the Partnerships will be reportable by
                  the Partners in the Partnership in which they invest.

         o        PASSIVE ACTIVITY CLASSIFICATION.

                  o        Generally, the passive activity limitations on losses
                           under ss.469 of the Code will apply to the Limited
                           Partners in a Partnership, but will not apply to the
                           Investor General Partners in the Partnership before
                           the conversion of the Investor General Partner Units
                           to Limited Partner Units in the Partnership.

                  o        A Partnership's income and gain from its natural gas
                           and oil properties which are allocated to its Limited
                           Partners, other than net income allocated to
                           converted Investor General Partners, generally will
                           be characterized as passive activity income which may
                           be offset by passive activity losses.

                                       93

                  o        Income or gain attributable to investments of working
                           capital of a Partnership will be characterized as
                           portfolio income, which cannot be offset by passive
                           activity losses.

         o        NOT A PUBLICLY TRADED PARTNERSHIP. None of the Partnerships
                  will be treated as a publicly traded partnership under the
                  Code.

         o        AVAILABILITY OF CERTAIN DEDUCTIONS. Business expenses,
                  including payments for personal services actually rendered in
                  the taxable year in which accrued, which are reasonable,
                  ordinary and necessary and do not include amounts for items
                  such as Lease acquisition costs, Tangible Costs, organization
                  and syndication fees and other items which are required to be
                  capitalized, are currently deductible.

         o        INTANGIBLE DRILLING COSTS. Although each Partnership will
                  elect to deduct currently all Intangible Drilling Costs, each
                  Participant may still elect to capitalize and deduct all or
                  part of his share of his Partnership's Intangible Drilling
                  Costs ratably over a 60 month period as discussed in "-
                  Alternative Minimum Tax," below. Subject to the foregoing,
                  Intangible Drilling Costs paid by a Partnership under the
                  terms of bona fide drilling contracts for the Partnership's
                  wells will be deductible in the taxable year in which the
                  payments are made and the drilling services are rendered,
                  assuming the amounts are reasonable consideration based on the
                  Managing General Partner's representations, and subject to
                  certain restrictions summarized below, including basis and "at
                  risk" limitations, and the passive activity loss limitation
                  with respect to the Limited Partners.

         o        PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Depending primarily
                  on when each Partnership's subscriptions are received, the
                  Managing General Partner anticipates that Atlas America Public
                  #14-2004 L.P. will prepay in 2004 most, if not all, of its
                  Intangible Drilling Costs for drilling activities that will
                  begin in 2005. In addition, the Managing General Partner
                  anticipates that Atlas America Public #14-2005(B) L.P., which
                  may close on December 31, 2005, may prepay in 2005 most, if
                  not all, of its Intangible Drilling Costs for drilling
                  activities that will begin in 2006. Assuming that the amounts
                  of any prepaid Intangible Drilling Costs of a Partnership are
                  reasonable consideration based on the Managing General
                  Partner's representations, and based in part on the factual
                  assumptions set forth below, the prepayments of Intangible
                  Drilling Costs will be deductible in the year in which they
                  are made even though all Working Interest owners in the well
                  will not be required to prepay Intangible Drilling Costs,
                  subject to certain restrictions summarized below, including
                  basis and "at risk" limitations, and the passive activity loss
                  limitation with respect to the Limited Partners.

                  The foregoing opinion is based in part on the assumptions that
                  under each Partnership's Drilling and Operating Agreement:

                  o        the estimated Intangible Drilling Costs are required
                           to be prepaid for specified wells to be drilled and,
                           if warranted, completed;

                  o        the drilling of all of the specified wells and
                           substitute wells, if any, is required to be, and
                           actually is, begun before the close of the 90th day
                           after the close of the Partnership's taxable year in
                           which the prepayments are made, and the wells are
                           continuously drilled until completed, if warranted,
                           or abandoned; and

                  o        the required prepayments are not refundable to the
                           Partnership and any excess prepayments for Intangible
                           Drilling Costs are applied to Intangible Drilling
                           Costs of the other specified wells or substitute
                           wells.

                                       94

         o        DEPLETION ALLOWANCE. The greater of cost depletion or
                  percentage depletion will be available to qualified
                  Participants as a current deduction against their share of
                  their Partnership's natural gas and oil production income,
                  subject to certain restrictions summarized below.

         o        MACRS. Each Partnership's reasonable costs for equipment
                  placed in its respective productive wells which cannot be
                  deducted immediately ("Tangible Costs") will be eligible for
                  cost recovery deductions under the Modified Accelerated Cost
                  Recovery System ("MACRS"), generally over a seven year "cost
                  recovery period" beginning in the taxable year each well is
                  completed and made capable of production, i.e. placed in
                  service, subject to certain restrictions summarized below,
                  including basis and "at risk" limitations, and the passive
                  activity loss limitation in the case of the Limited Partners.

         o        TAX BASIS OF UNITS. Each Participant's initial adjusted tax
                  basis in his Units will be the purchase price paid for the
                  Units.

         o        AT RISK LIMITATION ON LOSSES. Each Participant's initial "at
                  risk" amount in the Partnership in which he invests will be
                  the purchase price paid for the Units, assuming that:

                  o        any amount borrowed by a Participant and contributed
                           to the Partnership is not borrowed from a Person who
                           has an interest in the Partnership, other than as a
                           creditor, or a "related person", as that term is
                           defined in ss.465 of the Code, to a Person, other
                           than the Participant, having an interest in the
                           Partnership, other than as a creditor, and the
                           Participant is severally, primarily, and personally
                           liable for the borrowed amount; and

                  o        the Participant has not protected himself from loss
                           for amounts contributed to the Partnership through
                           nonrecourse financing, guarantees, stop loss
                           agreements or other similar arrangements.

         o        ALLOCATIONS. Assuming the effect of the allocations of income,
                  gain, loss and deduction, or items thereof, set forth in the
                  Partnership Agreement, including the allocations of basis and
                  amount realized with respect to natural gas and oil
                  properties, is substantial in light of a Participant's tax
                  attributes that are unrelated to the Partnership in which he
                  invests, the allocations will have "substantial economic
                  effect" and will govern the Participant's share of those items
                  to the extent the allocations do not cause or increase a
                  deficit balance in his Capital Account.

         o        SUBSCRIPTION. No gain or loss will be recognized by the
                  Participants on payment of their subscriptions to the
                  Partnership in which they invest.

         o        NO TAX SHELTER REGISTRATION. None of the Partnerships is
                  required to register with the IRS as a tax shelter. This
                  opinion is based in part on the Managing General Partner's
                  representations that none of the Partnerships has a tax
                  shelter ratio greater than 2 to 1 and each Partnership will be
                  operated as described in the Prospectus.

         o        PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND POTENTIALLY RELEVANT
                  JUDICIAL DOCTRINES. The Partnerships will possess the
                  requisite profit motive underss.183 of the Code, and the IRS
                  anti-abuse rule in Treas. Reg.ss.1.701-2 and certain
                  potentially relevant judicial doctrines will not have a
                  material adverse effect on the tax consequences of an
                  investment in a Partnership by a typical Participant as
                  described in our opinions. These opinions are based in part on
                  the results of the previous partnerships sponsored by the
                  Managing General Partner as set forth in "Prior Activities" in
                  the Prospectus, and the Managing General Partner's
                  representations. These representations include that each
                  Partnership will be operated as described in the Prospectus
                  (see "Management" and "Proposed Activities" in the
                  Prospectus), and the principal purpose of each Partnership is
                  to locate, produce and market natural gas and oil on a
                  profitable basis, apart from tax benefits. These
                  representations are also supported by the geological
                  evaluations and the other information for the Partnerships'
                  proposed drilling areas and the specific Prospects proposed to
                  be drilled Atlas America Public #14-2004 L.P. which are
                  included in Appendix A to the Prospectus.

                                       95

         o        OVERALL EVALUATION OF TAX BENEFITS. The tax benefits of each
                  Partnership, in the aggregate, which are a significant feature
                  of an investment in a Partnership by a typical Participant
                  will be realized as contemplated by the Prospectus. This
                  opinion is based on our conclusion that substantially more
                  than half of the material federal income tax benefits of each
                  Partnership, in terms of their financial impact on a typical
                  Participant in the Partnership, will be realized if challenged
                  by the IRS. The discussion in the Prospectus under the caption
                  "MATERIAL FEDERAL INCOME TAX CONSEQUENCES," insofar as it
                  contains statements of federal income tax law, is correct in
                  all material respects.

                SUMMARY DISCUSSION OF THE MATERIAL FEDERAL INCOME
               TAX CONSEQUENCES OF AN INVESTMENT IN A PARTNERSHIP

IN GENERAL
Special counsel's tax opinions are limited to those set forth above. The
following is a summary of all of the material federal income tax consequences of
the purchase, ownership and disposition of investor general partner units and
limited partner units discussed in the tax opinion which will apply to typical
investors in each partnership. Different tax considerations than those addressed
in this discussion may apply to foreign persons, corporations, partnerships,
trusts and other prospective investors which are not treated as typical
investors in the partnerships for federal income tax purposes. Also, the proper
treatment of the tax attributes of a partnership by a typical investor on his
individual federal income tax return may vary from that of another typical
investor. This is because the practical utility of the tax attributes of any
investment depends largely on each investor's particular income tax position in
the year in which items of income, gain, loss, deduction or credit are properly
taken into account in computing his federal income tax liability. Accordingly,
you are urged to seek qualified, professional assistance in evaluating the
potential tax consequences to you of an investment in a partnership with
specific reference to your own tax situation.

PARTNERSHIP CLASSIFICATION
For federal income tax purposes a partnership is not a taxable entity. The
partners, rather than the partnership, receive any deductions, as well as the
income, from the operations engaged in by the partnership. A business entity
with two or more members is classified for federal tax purposes as either a
corporation or a partnership. Each partnership will be formed as a limited
partnership under the Delaware Revised Uniform Limited Partnership Act which
describes each partnership as a "partnership." Thus, each partnership
automatically will be classified as a partnership unless it elects to be
classified as a corporation. In this regard, the managing general partner has
represented that none of the partnerships will elect to be taxed as a
corporation.

LIMITATIONS ON PASSIVE ACTIVITIES
Under the passive activity rules of the Internal Revenue Code, all income of a
taxpayer who is subject to the rules is categorized as:

         o        income from passive activities such as limited partners'
                  interests in a business;

         o        active income such as salary, bonuses, etc.; or

         o        portfolio income such as gain, interest, dividends and
                  royalties unless earned in the ordinary course of a trade or
                  business.

Losses generated by passive activities can offset only passive income and cannot
be applied against active income or portfolio income. Suspended losses may be
carried forward indefinitely, but not back, and used to offset future years'
passive activity income.

                                       96

Passive activities include any trade or business in which the taxpayer does not
materially participate on a regular, continuous, and substantial basis. Under
the partnership agreement, limited partners will not have material participation
in the partnership in which they invest and generally will be subject to the
passive activity limitations.

Investor general partners also do not materially participate in the partnership
in which they invest. However, because each partnership will own only "working
interests," as defined in the Internal Revenue Code, in its wells and investor
general partners will not have limited liability under Delaware law until they
are converted to limited partners, their deductions generally will not be
treated as passive deductions under the Internal Revenue Code before the
conversion. However, if an investor general partner invests in a partnership
through an entity which limits his liability, for example, a limited partnership
in which he is not a general partner, a limited liability company or an S
corporation, then generally he will be subject to the passive activity
limitations the same as a limited partner. Contractual limitations on the
liability of investor general partners under the partnership agreement, however,
such as insurance, limited indemnification by the managing general partner, etc.
will not cause investor general partners to be subject to the passive activity
loss limitation.

PUBLICLY TRADED PARTNERSHIP RULES. Net losses of a partner from each publicly
traded partnership are suspended and carried forward to be netted against income
from that publicly traded partnership only. In addition, net losses from other
passive activities may not be used to offset net passive income from a publicly
traded partnership. A publicly traded partnership is a partnership whose
interests are traded on an established securities market or that are readily
tradable on either a secondary market or the substantial equivalent of a
secondary market. However, due primarily to the substantial restrictions under
the partnership agreement on your ability to transfer your units in the
partnership in which you invest, in the opinion of special counsel none of the
partnerships will be treated as a publicly traded partnership under the Internal
Revenue Code. (See "Transferability of Units - Restrictions on Transfer Imposed
by the Securities Laws, the Tax Laws and the Partnership Agreement.")

CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER. If you invest in a
partnership as an investor general partner, then your share of the partnership's
deduction for intangible drilling costs in the year in which you invest will not
be subject to the passive activity loss limitation because your investor general
partner units will not be converted to limited partner units until after all of
the partnership's wells have been drilled and completed. The managing general
partner anticipates that the conversion will be in 2005 for Atlas America Public
#14-2004 L.P. and in 2006 for both Atlas America Public #14-2005(A) L.P. and
Atlas America Public #14-2005(B) L.P. (See "Actions to be Taken by Managing
General Partner to Reduce Risks of Additional Payments by Investor General
Partners," and "- Drilling Contracts," below.) After the investor general
partner units have been converted to limited partner units, each former investor
general partner will have limited liability as a limited partner under the
Delaware Revised Uniform Limited Partnership Act with respect to his interest in
his partnership's activities after the date of the conversion.

Concurrently, the former investor general partner will become subject to the
passive activity rules as a limited partner. However, he previously will have
received a non-passive loss as an investor general partner in the year in which
he invested in a partnership as a result of the partnership's deduction for
intangible drilling costs. Therefore, the Internal Revenue Code requires that
his net income from the partnership's wells after his conversion to a limited
partner must continue to be characterized as non-passive income which cannot be
offset with passive losses. The conversion of the investor general partner units
into limited partner units should not have any other adverse tax consequences to
an investor general partner unless his share of any partnership liabilities is
reduced as a result of the conversion. A reduction in a partner's share of
liabilities is treated as a constructive distribution of cash to the partner,
which reduces the basis of the partner's interest in the partnership and is
taxable to the extent it exceeds his basis.

TAXABLE YEAR AND METHOD OF ACCOUNTING
Each partnership intends to adopt a calendar year taxable year and will use the
accrual method of accounting for federal income tax purposes.

                                       97

2004 AND 2005 EXPENDITURES
The managing general partner anticipates that all of your partnership's
subscription proceeds will be expended in the year in which you invest in the
partnership, and that your share of the partnership's income and deductions,
including the deduction for intangible drilling costs, will be reflected on your
federal income tax return for that period.

Depending primarily on when each partnership's subscription proceeds are
received, the managing general partner anticipates that Atlas America Public
#14-2004 L.P. will prepay in 2004 most, if not all, of its intangible drilling
costs for drilling activities that will begin in 2005. In addition, the managing
general partner anticipates that Atlas America Public #14-2005(B) L.P., which
may close on December 31, 2005, may prepay in 2005 most, if not all, of its
intangible drilling costs for drilling activities that will begin in 2006. The
deductibility of these advance payments in the year in which you invest in the
partnership cannot be guaranteed. (See "- Drilling Contracts," below.) The
managing general partner does not anticipate that Atlas America Public
#14-2005(A) L.P., which has a targeted final closing date of May 31, 2005 (which
is not binding on the partnership), will prepay any intangible drilling costs in
2005 for drilling activities that will begin in 2006.

AVAILABILITY OF CERTAIN DEDUCTIONS
Ordinary and necessary business expenses, including reasonable compensation for
personal services actually rendered, are deductible in the year incurred. The
managing general partner has represented that the amounts payable by each
partnership to the managing general partner and its affiliates, including the
amounts payable to the managing general partner or its affiliates as general
drilling contractor, are reasonable amounts which would ordinarily be paid for
similar services in similar transactions. The fees paid to the managing general
partner and its affiliates by the partnerships will not be currently deductible,
however, to the extent they are:

         o        in excess of reasonable compensation;

         o        properly characterized as organization or syndication fees or
                  other capital costs such as the acquisition cost of the
                  leases; or

         o        not "ordinary and necessary" business expenses.

In the event of an audit, payments to the managing general partner and its
affiliates by a partnership will be scrutinized by the IRS to a greater extent
than payments to an unrelated party.

INTANGIBLE DRILLING COSTS
Subject to the limitations on deductions and losses summarized elsewhere in this
discussion, including the basis and "at risk" limitations, and the passive
activity loss limitation in the case of limited partners, you will be entitled
to deduct your share of your partnership's intangible drilling costs, which
include items which do not have salvage value, such as labor, fuel, repairs,
supplies and hauling necessary to the drilling of a well. If a partnership
re-enters an existing well as described in "Proposed Activities - Primary Areas
of Operations - Mississippian/Upper Devonian Sandstone Reservoirs, Fayette
County, Pennsylvania," the costs of deepening the well and completing it to
deeper reservoirs, if any, other than equipment costs, generally will be treated
as intangible drilling costs. Drilling and completion costs of a re-entry well
which are not related to deepening the well, if any, however, other than
equipment costs, generally will be treated as operating expenses which should be
expensed in the taxable year they are incurred for federal income tax purposes.
Those costs (other than equipment costs) of the re-entry well, however, will not
be characterized as operating costs, instead of intangible drilling costs, for
purposes of allocating the payment of the costs between the managing general
partner and the investors under the partnership agreement. Your deduction for
intangible drilling costs generally will be treated as ordinary income if a
property or your units are sold at a gain. Also, productive-well intangible
drilling costs may subject you to an alternative minimum tax in excess of
regular tax unless you elect to deduct all or part of these costs ratably over a
60-month period as discussed in "- Alternative Minimum Tax," below.

                                       98

Under the partnership agreement not less than 90% of the subscription proceeds
received by your partnership from you and the other investors will be used to
pay 100% of the partnership's intangible drilling costs of drilling and
completing its wells. The IRS could challenge the characterization of a portion
of these costs as currently deductible intangible drilling costs and
recharacterize the costs as some other item which may not be currently
deductible. However, this would have no effect on the allocation and payment of
the intangible drilling costs by you and the other investors under the
partnership agreement.

You are urged to consult with your own personal tax advisor concerning the tax
benefits to you of the deduction for intangible drilling costs in the
partnership in which you invest in light of your own tax situation.


DRILLING CONTRACTS
Each partnership will enter into the drilling and operating agreement with the
managing general partner or its affiliates, acting as a third-party general
drilling contractor, to drill and complete the partnership's development wells
on a cost plus 15% basis. For its services as general drilling contractor, the
managing general partner anticipates that on average over all of the wells
drilled and completed by each partnership, assuming a 100% working interest in
each well, it will have reimbursement of general and administrative overhead of
approximately $12,722 per net well and a profit of 15% (approximately $22,558)
per net well with respect to the intangible drilling costs and the portion of
equipment costs paid by you and the other investors in your partnership as
described in "Compensation - Drilling Contracts." However, the actual cost of
drilling and completing the wells may be more or less than the estimated amount,
due primarily to the uncertain nature of drilling operations, and the managing
general partner's profit per net well also could be more or less than the dollar
amount estimated by the managing general partner.


The managing general partner believes the prices under the drilling and
operating agreement are competitive in the proposed areas of operation.
Nevertheless, the amount of the profit realized by the managing general partner
under the drilling and operating agreement could be challenged by the IRS as
being unreasonable and disallowed as a deductible intangible drilling cost.

The managing general partner does not anticipate that Atlas America Public
#14-2005(A) L.P., which has a targeted final closing date of May 31, 2005 (which
is not binding on the partnership), will prepay in 2005 any of its intangible
drilling costs for drilling activities that will begin in 2006. However,
depending primarily on when each partnership's subscription proceeds are
received, the managing general partner anticipates that Atlas America Public
#14-2004 L.P. will prepay in 2004 most, if not all, of its intangible drilling
costs for drilling activities that will begin in 2005. In addition, the managing
general partner anticipates that Atlas America Public #14-2005(B) L.P., which
may close on December 31, 2005, may prepay in 2005 most, if not all, of its
intangible drilling costs for drilling activities that will begin in 2006. In
Keller v. Commissioner, 79 T.C. 7 (1982), aff'd 725 F.2d 1173 (8th Cir. 1984),
the Tax Court applied a two-part test for the current deductibility of prepaid
intangible drilling costs. The test is:

         o        the expenditure must be a payment rather than a refundable
                  deposit; and

         o        the deduction must not result in a material distortion of
                  income taking into substantial consideration the business
                  purpose aspects of the transaction.

Each partnership will attempt to comply with the guidelines set forth in Keller
with respect to any prepaid intangible drilling costs. In the year in which you
invest, the drilling and operating agreement will require your partnership to
prepay all of your partnership's share of the estimated intangible drilling
costs and the investors' share of your partnership's estimated equipment costs
for drilling and completing specified wells, the drilling of which may begin in
the following year. These prepayments should not result in a loss of a current
deduction for the intangible drilling costs if:

         o        there is a legitimate business purpose for the required
                  prepayment;

         o        the contract is not merely a sham to control the timing of the
                  deduction; and

         o        there is an enforceable contract of economic substance.

                                       99

The drilling and operating agreement will require each partnership to prepay the
managing general partner's estimate of the intangible drilling costs and the
investors' share of the equipment costs to drill and complete the wells
specified in the drilling and operating agreement in order to enable the
operator to:

         o        begin site preparation for the wells;

         o        obtain suitable subcontractors at the then current prices; and

         o        insure the availability of equipment and materials.

Under the drilling and operating agreement excess prepaid intangible drilling
costs, if any, will not be refundable to a partnership, but instead will be
applied only to intangible drilling cost overruns, if any, on the other
specified wells being drilled or completed by the partnership or to intangible
drilling costs to be incurred by the partnership in drilling and completing
substitute wells. Under Keller, a provision for substitute wells should not
result in the prepayments being characterized as refundable deposits.

The likelihood that prepayments of intangible drilling costs will be challenged
by the IRS on the grounds that there is no business purpose for the prepayments
is increased if prepayments are not required with respect to all of the working
interest in the well. The managing general partner anticipates that less than
100% of the working interest will be acquired by each partnership in one or more
of its wells, and prepayments of intangible drilling costs will not be required
of all owners of working interests in those wells. In the view of special
counsel, however, a legitimate business purpose for the required prepayments of
intangible drilling costs by the partnership may exist under the guidelines set
forth in Keller, even though prepayments are not required by the drilling
contractor with respect to a portion of the working interest in the wells.

In addition, a current deduction for prepaid intangible drilling costs is
available only if the drilling of the wells begins before the close of the 90th
day after the close of the taxable year in which the prepayment was made. Under
the drilling and operating agreement, the managing general partner as operator
and general drilling contractor must begin drilling each of the prepaid wells no
later than March 31, 2005 for Atlas America Public #14-2004 L.P. and March 31,
2006 for Atlas America Public #14-2005(B) L.P. However, the drilling of any
partnership well may be delayed due to circumstances beyond the control of the
managing general partner or the drilling subcontractors. These circumstances
include, for example:

         o        the unavailability of drilling rigs;

         o        decisions of third-party operators to delay drilling the
                  wells;

         o        poor weather conditions;

         o        inability to obtain drilling permits or access right to the
                  drilling site; or

         o        title problems;

and the managing general partner will have no liability to any partnership or
its investors if these types of events delay beginning the drilling of the
prepaid wells past the close of the 90th day after the close of the
partnership's taxable year. If the drilling of a prepaid partnership well does
not begin before the close of the 90th day after the close of your partnership's
taxable year in which the prepayment was made, deductions claimed by you for
prepaid intangible drilling costs for the well in the year in which you invest
in the partnership would be disallowed and deferred to the next taxable year
when the well is actually drilled.

No assurance can be given that on audit the IRS would not disallow the current
deductibility of a portion or all of any prepaid intangible drilling costs under
a partnership's drilling contracts, thereby decreasing the amount of the
investors' deductions in the partnership for the year in which they invest in
the partnership, or that the challenge would not ultimately be sustained. In the
event of disallowance, the deduction for prepaid intangible drilling costs would
be available in the next year when the wells are actually drilled.

                                       100

DEPLETION ALLOWANCE
Proceeds from the sale of each partnership's natural gas and oil production will
constitute ordinary income. A certain portion of that income will not be taxable
under the depletion allowance which permits the deduction from gross income for
federal income tax purposes of either the percentage depletion allowance or the
cost depletion allowance, whichever is greater. Depletion deductions generally
will be treated as ordinary income if a property or your units are sold at a
gain.

Cost depletion for any year is determined by dividing the adjusted tax basis for
the property by the total units of natural gas or oil expected to be recoverable
from the property and then multiplying the resultant quotient by the number of
units actually sold during the year. Cost depletion cannot exceed the adjusted
tax basis of the property to which it relates.

Percentage depletion generally is available to taxpayers other than "integrated
oil companies," which term does not include the partnerships. Percentage
depletion is based on your share of your partnership's gross production income
from its natural gas and oil properties. The rate of percentage depletion is
15%. However, percentage depletion for marginal production increases 1%, up to a
maximum increase of 10%, for each whole dollar that the domestic wellhead price
of crude oil for the immediately preceding year is less than $20 per barrel
without adjustment for inflation. The term "marginal production" includes
natural gas and oil produced from a domestic stripper well property, which is
defined as any property which produces a daily average of 15 or less equivalent
barrels of oil, which is equivalent to 90 mcf of natural gas, per producing well
on the property in the calendar year. Most, if not all, of each partnership's
wells will be marginal producing wells under this definition in the Internal
Revenue Code and will qualify for these potentially higher rates of percentage
depletion. The rate of percentage depletion for marginal production in 2004 is
15%. This rate may fluctuate from year to year depending on the price of oil,
but will not be less than the statutory rate of 15% nor more than 25%.

Also, percentage depletion:

         o        may not exceed 100% of the net income from each natural gas
                  and oil property before the deduction for depletion; and

         o        is limited to 65% of the taxpayer's taxable income for a year
                  computed without regard to deductions for percentage
                  depletion, net operating loss carry-backs and capital loss
                  carry-backs.

Availability of percentage depletion must be computed separately by you, and not
by your partnership or for investors in your partnership as a whole. You are
urged to consult your own tax advisors with respect to the availability of
percentage depletion to you.

DEPRECIATION - MODIFIED ACCELERATED COST RECOVERY SYSTEM ("MACRS")
Equipment costs ("Tangible Costs") and the related depreciation deductions of
each partnership generally are charged and allocated under the partnership
agreement 66% to the managing general partner and 34% to you and the other
investors in the partnership. However, if the total equipment costs for all of
the partnership's wells that would be charged to you and the other investors
exceeds an amount equal to 10% of the subscription proceeds of you and the other
investors, then the excess, together with the related depreciation deductions,
will be charged and allocated to the managing general partner. Most of each
partnership's equipment costs will be recovered through depreciation deductions
over a seven year cost recovery period, using the 200% declining balance method,
with a switch to straight-line to maximize the deduction, beginning in the
taxable year the equipment is "placed in service" by the partnership as
discussed below. In the case of a short tax year the MACRS deduction is prorated
on a 12-month basis. No distinction is made between new and used property and
salvage value is disregarded. Generally only a half-year of depreciation is
allowed for the year recovery property is placed in service or disposed of.
Except as discussed below, smaller depreciation deductions in a partnership's
early years are used for purposes of the alternative minimum tax. All of these
cost recovery deductions claimed by the partnerships and their respective
investors are subject to recapture as ordinary income rather than capital gain
on the sale or other taxable disposition of the property or an investor's units.

                                       101

Notwithstanding the foregoing, for federal income tax purposes Atlas America
Public #14-2004 L.P., but not Atlas America Public #14-2005(A) L.P. or Atlas
America Public #14-2005(B) L.P., will be entitled to an additional first-year
depreciation allowance based on 50% of the adjusted basis of its "qualified"
equipment costs, if any. For this purpose, the partnership's "qualified"
equipment costs means its equipment costs for productive wells which are
completed and made capable of production, i.e. placed in service, before January
1, 2005. Thus, this additional first-year depreciation allowance will not be
available for wells placed in service in 2005, even though the investors' share
of the partnership's equipment costs for the wells is prepaid in 2004, because
the special rule that allows current deductions for prepaid intangible drilling
costs does not apply to prepaid equipment costs. In addition, the basis of the
partnership's qualified equipment will be reduced by the additional 50%
first-year depreciation allowance for purposes of calculating the regular MACRS
depreciation allowances beginning in 2004. Also, if you invest in Atlas America
Public #14-2004 L.P. you will not incur any alternative minimum tax adjustment
with respect to your share of the partnership's additional 50% first-year
depreciation allowance, nor any of its other depreciation deductions for the
costs of the qualified equipment it places in productive wells which are
drilled, completed and placed in service in 2004, if any.

LEASE ACQUISITION COSTS AND ABANDONMENT
Lease acquisition costs, together with the related cost depletion deduction and
any abandonment loss for lease costs, are allocated under the partnership
agreement 100% to the managing general partner, which will contribute the leases
to each partnership as a part of its capital contribution.

TAX BASIS OF UNITS
Your share of your partnership's losses is allowable only to the extent of the
adjusted basis of your units at the end of the partnership's taxable year. The
adjusted basis of your units will be adjusted, but not below zero, for any gain
or loss to you from a sale or other taxable disposition by the partnership of a
natural gas or oil property, and will be increased by your:

         o        cash subscription payment;

         o        share of partnership income; and

         o        share, if any, of partnership debt.

The adjusted basis of your units will be reduced by your:

         o        share of partnership losses;

         o        depletion deductions, but not below zero; and

         o        cash distributions from the partnership.

The reduction in your share of partnership liabilities, if any, is considered a
cash distribution to you. Should cash distributions to you from your partnership
exceed the tax basis of your units, taxable gain would result to you to the
extent of the excess.

"AT RISK" LIMITATION FOR LOSSES
Subject to the limitations on "passive losses" generated by a partnership in the
case of limited partners, and your basis in your units, you generally may use
your share of your partnership's losses to offset income from other sources.
However, generally you may deduct the loss only to the extent of the amount you
have "at risk" in the partnership at the end of a taxable year. Your initial
amount "at risk" in the partnership in which you invest generally will equal the
amount of money you paid for your units, reduced by any amounts you may have
borrowed from persons who have an interest in the partnership, other than as a
creditor, to purchase your units. Also, the amount you have "at risk" in your
partnership may not include the amount of any loss that you are protected
against through:

         o        nonrecourse loans;

                                       102

         o        guarantees;

         o        stop loss agreements; or

         o        other similar arrangements.

DISTRIBUTIONS FROM A PARTNERSHIP
Generally, a cash distribution from your partnership to you in excess of the
adjusted basis of your units immediately before the distribution is treated as
gain to you from the sale or exchange of your units to the extent of the excess.
No loss can be recognized by you on these distributions. Other distributions of
property and liquidating distributions by your partnership may result in taxable
gain or loss to you.

SALE OF THE PROPERTIES
Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax
Act"), the maximum tax rates on a noncorporate taxpayer's adjusted net capital
gain on the sale of assets held more than a year of 20%, or 10% to the extent it
would have been taxed at a 10% or 15% rate if it had been ordinary income, have
been reduced to 15% and 5%, respectively, for most capital assets sold or
exchanged after May 5, 2003. In addition, for 2008 only, the 5% tax rate on
adjusted net capital gain is reduced to 0%. The 2003 Tax Act also eliminated the
former maximum tax rates of 18% and 8%, respectively, on qualified five-year
gain. I.R.C. ss.1(h). The new capital gain rates also apply for purposes of the
alternative minimum tax. I.R.C. ss.55(b)(3). (See "- Alternative Minimum Tax,"
below. However, the former tax rates are scheduled to be reinstated January 1,
2009, as if the 2003 Tax Act had never been enacted. "Adjusted net capital gain"
means net capital gain, less certain types of net capital gain that are taxed a
maximum rate of 28% (such as gain on the sale of most collectibles and gain on
the sale of certain small business stock); or 25% (gain attributable to real
estate depreciation). "Net capital gain" means the excess of net long-term gain
(excess of long-term gains over long-term losses) over net short-term loss
(excess of short-term gains over short-term losses). The annual capital loss
limitation for noncorporate taxpayers is the amount of capital gains plus the
lesser of $3,000, which is reduced to $1,500 for married persons filing separate
returns, or the excess of capital losses over capital gains.

Gains and losses from sales of natural gas and oil properties held for more than
12 months generally will be treated as a long-term capital gain, while a net
loss will be an ordinary deduction. However, on disposition of a natural gas or
oil property gain is treated as ordinary income to the extent of the lesser of:

         o        the amounts that were deducted as intangible drilling costs
                  rather than added to basis, plus depletion deductions that
                  reduced the basis of the property; or

         o        the amount realized in the case of a sale, exchange or
                  involuntary conversion or fair market value in all other
                  cases, minus the property's adjusted basis.

In addition, all equipment depreciation deductions, and certain losses for a
partnership's five most recent taxable years, if any, on previous sales of that
partnership's assets, are treated as ordinary income to the extent of any gain
on the sale or other taxable disposition of the property. Other gains and losses
on sales of natural gas and oil properties will generally result in ordinary
gains or losses.

DISPOSITION OF UNITS
The sale or exchange, including a purchase by the managing general partner, of
all or some of your units held by you for more than 12 months generally will
result in a recognition of long-term capital gain or loss. However, previous
deductions for depreciation, depletion and intangible drilling costs, and your
share of the partnership's "ss.751 assets" (i.e. inventory and unrealized
receivables), may be recaptured as ordinary income rather than capital gain
regardless of how long you have owned your units. (See "- Sale of the
Properties," above.) If the units are held for 12 months or less, the gain or
loss generally will be short-term gain or loss. Also, your pro rata share of
your partnership's liabilities, if any, as of the date of the sale or exchange
must be included in the amount realized. Therefore, the gain recognized by you
may result in a tax liability to you greater than the cash proceeds, if any,
received by you from the disposition. In addition to gain from a passive
activity, a portion of any gain recognized by a limited partner on the sale or
other taxable disposition of his units may be characterized as portfolio income
under the passive activity loss rules to the extent the gain is attributable to
portfolio income, e.g. interest income on investments of working capital. (See
"- Limitations on Passive Activities," above.)

                                       103

A gift of your units may result in federal and/or state income tax and gift tax
liability to you. Also, interests in different partnerships do not qualify for
tax-free like-kind exchanges. Other dispositions of your units may or may not
result in recognition of taxable gain. However, no gain should be recognized by
an investor general partner on the conversion of his investor general partner
units to limited partner units so long as there is no change in his share of his
partnership's liabilities or certain partnership assets as a result of the
conversion. In addition, if you sell or exchange all or some of your units you
are required by the Internal Revenue Code to notify your partnership within 30
days or by January 15 of the following year, if earlier and the partnership will
then report certain tax information regarding the transfer of the units to the
IRS, including your share of the partnership's ss.751 assets which are subject
to recapture as ordinary income as discussed above.

If you die, or sell or exchange all of your Units, the taxable year of your
partnership will close with respect to you, but not the remaining investors, on
the date of death, sale or exchange, with a proration of partnership items for
the partnership's taxable year. If you sell less than all of your units, the
partnership's taxable year will not terminate with respect to you, but your
proportionate share of the partnership's items of income, gain, loss and
deduction will be determined by taking into account your varying interests in
the partnership during the taxable year.

You are urged to consult with your own tax advisor before you make any
disposition of your units, including purchase of the units by the managing
general partner.

ALTERNATIVE MINIMUM TAX
With limited exceptions, you must pay an alternative minimum tax if it exceeds
your regular federal income tax for the year. Alternative minimum taxable income
generally is taxable income, plus or minus various adjustments, plus tax
preference items. The tax rate for noncorporate taxpayers is 26% for the first
$175,000, $87,500 for married individuals filing separately, of a taxpayer's
alternative minimum taxable income in excess of the exemption amount; and
additional alternative minimum taxable income is taxed at 28%. However, the
regular tax rates on capital gains also will apply for purposes of the
alternative minimum tax. (See "- Sale of the Properties," above.) Subject to the
phase-out provisions summarized below, the exemption amounts for 2004 are
$58,000 for married individuals filing jointly, $40,250 for single persons and
$29,000 for married individuals filing separately. For years beginning after
2004, these exemption amounts are scheduled to decrease to $45,000 for married
individuals filing jointly, $33,750 for single persons, and $22,500 for married
individuals filing separately. As of the date of this prospectus, the U.S. House
of Representatives had passed a bill that would extend the 2004 exemption
amounts to 2005 and index them for inflation in following years. Whether that
bill or other relief for taxpayers from the alternative minimum tax will become
law in 2005 is uncertain. (See "- Changes in the Law," below.) The exemption
amount for estates and trusts is $22,500 in 2004 and subsequent years.

The exemption amounts are reduced by 25% of alternative minimum taxable income
in excess of:

         o        $150,000, in the case of married individuals filing a joint
                  return and surviving spouses - the $58,000 exemption amount is
                  completely phased out when alternative minimum taxable income
                  is $382,000 or more, and the $45,000 amount phases out
                  completely at $330,000;

         o        $112,500, in the case of unmarried individuals other than
                  surviving spouses - the $40,250 exemption amount is completely
                  phased out when alternative minimum taxable income is $273,500
                  or more, and the $33,750 amount phases out completely at
                  $247,500; and

         o        $75,000, in the case of married individuals filing a separate
                  return - the $29,000 exemption amount is completely phased out
                  when alternative minimum taxable income is $191,000 or more
                  and the $22,500 amount phases out completely at $165,000. In
                  addition, in 2004 the alternative minimum taxable income of
                  married individuals filing separately is increased by the
                  lesser of $29,000 ($22,500 after 2004) or 25% of the excess of
                  the person's alternative minimum taxable income (determined
                  without regard to this provision) over $191,000 ($165,000
                  after 2004).

                                       104

Some of the principal adjustments to taxable income that are used to determine
alternative minimum taxable income include:

         o        Depreciation deductions may not exceed deductions computed
                  using the 150% declining balance method, except as discussed
                  above in "- Depreciation - Modified Accelerated Cost Recovery
                  System ("MACRS")" with respect to "qualified" equipment costs
                  of wells placed in service in 2004, if any, by Atlas America
                  Public #14-2004 L.P.

         o        Miscellaneous itemized deductions are not allowed.

         o        Medical expenses are deductible only to the extent they exceed
                  10% of adjusted gross income.

         o        State and local property and income taxes are not deductible.

         o        Interest deductions are restricted.

         o        The standard deduction and personal exemptions are not
                  allowed.

         o        Only some types of operating losses are deductible.

         o        Different rules under the Internal Revenue Code apply to
                  incentive stock options that may require earlier recognition
                  of income.

The principal tax preference items that must be added to taxable income for
alternative minimum tax purposes include:

         o        Certain excess intangible drilling costs, as discussed below.

         o        Tax-exempt interest earned on certain private activity bonds.

For taxpayers other than "integrated oil companies" as that term is defined in
"- Intangible Drilling Costs," above, which does not include the partnerships,
the 1992 National Energy Bill repealed:

         o        the preference for excess intangible drilling costs; and

         o        the excess percentage depletion preference for natural gas and
                  oil.

The repeal of the excess intangible drilling costs preference, however, under
current law may not result in more than a 40% reduction in the amount of the
taxpayer's alternative minimum taxable income computed as if the excess
intangible drilling costs preference had not been repealed. Under the prior
rules, the amount of intangible drilling costs which is not deductible for
alternative minimum tax purposes is the excess of the "excess intangible
drilling costs" over 65% of net income from natural gas and oil properties. Net
natural gas and oil income is determined for this purpose without subtracting
excess intangible drilling costs. Excess intangible drilling costs is the
regular intangible drilling costs deduction minus the amount that would have
been deducted under 120-month straight-line amortization, or, at the taxpayer's
election, under the cost depletion method. There is no preference item for costs
of nonproductive wells.

Also, you and the other investors in a partnership may separately elect under
ss.59(e) of the Code to capitalize all or part of your share of the
partnership's intangible drilling costs and deduct the costs ratably over a
60-month period beginning with the month in which the costs were paid or
incurred by the partnership. This election also applies for regular tax purposes
and can be revoked only with the IRS' consent. Making this election, therefore,
generally will result in the following consequences to you:

                                       105

         o        your regular tax deduction for intangible drilling costs in
                  the year in which you invest will be reduced because you must
                  spread the deduction for the amount of intangible drilling
                  costs which you elect to capitalize over the 60-month
                  amortization period; and

         o        the capitalized intangible drilling costs will not be treated
                  as a preference that is included in your alternative minimum
                  taxable income.

Other than intangible drilling costs as discussed above, the principal tax item
that may have an impact on your alternative minimum taxable income as a result
of investing in a partnership is depreciation of the partnership's equipment.
Except for wells placed in service in 2004 by Atlas America Public #14-2004
L.P., if any, as noted above, if you invest in that partnership, your cost
recovery deductions for regular income tax purposes generally will be computed
using the 200% declining balance method rather than the 150% declining balance
method used for alternative minimum tax purposes. This means that in the early
years of a partnership your depreciation deductions from the partnership
generally will be smaller for alternative minimum tax purposes when compared to
the partnership's depreciation deductions for regular income tax purposes on the
same equipment.

The rules relating to the alternative minimum tax for corporations are different
than those summarized above. All prospective investors contemplating purchasing
units in a partnership are urged to consult with their own personal tax advisors
as to the likelihood of them incurring or increasing any alternative minimum tax
liability because of an investment in a partnership.

LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST
Investment interest expense is deductible by a noncorporate taxpayer only to the
extent of net investment income each year, with an indefinite carryforward of
disallowed amounts. An investor general partner's share of any interest expense
incurred by the partnership in which he invests before his investor general
partner units are converted to limited partner units will be subject to the
investment interest limitation. In addition, the investor general partner's
share of the partnership's income and losses, including the deduction for
intangible drilling costs, will be considered to be investment income and
losses. Thus, for example, a loss allocated to an investor general partner from
the partnership in the year in which he invests in the partnership as a result
of the deduction for intangible drilling costs will reduce his net investment
income and may reduce or eliminate the deductibility of his investment interest
expense, if any, in that taxable year, with the disallowed portion to be carried
forward to the next taxable year. These rules, however, do not apply to
partnership income or expense subject to the passive activity loss limitations
for limited partners.

ALLOCATIONS
The partnership agreement allocates to each investor his share of his
partnership's income, gains, losses and deductions, including the deductions for
intangible drilling costs and depreciation. Your capital account in the
partnership in which you invest will be adjusted to reflect your share of these
allocations and your capital account, as adjusted, will be given effect in
distributions made to you on liquidation of the partnership or your interest in
the partnership. Generally, your capital account in the partnership in which you
invest will be:

         o        increased by the amount of money you contribute to the
                  partnership and allocations to you of income and gain; and

         o        decreased by the value of property or cash distributed to you
                  by the partnership and allocations to you of loss and
                  deductions by the partnership.

It should be noted that your share of your partnership's items of income, gain,
loss, and deduction must be taken into account by you whether or not you receive
any cash distributions from the partnership. Your share of partnership revenues
applied by your partnership to the repayment of loans or the reserve for
plugging wells, for example, will be included in your gross income in a manner
analogous to an actual distribution of the income to you. Thus, you may have tax
liability on taxable income from your partnership for a particular year in
excess of any cash distributions from the partnership to you with respect to
that year. To the extent a partnership has cash available for distribution,
however, it is the managing general partner's policy that partnership cash
distributions will not be less than the managing general partner's estimate of
the investors' income tax liability with respect to that partnership's income.

                                      106


If any allocation under the partnership agreement is not recognized for federal
income tax purposes, your share of the items subject to that allocation
generally will be determined in accordance with your interest in the partnership
in which you invest, determined by considering all of the relevant facts and
circumstances. To the extent the deductions allocated by the partnership
agreement exceed deductions which would be allowed under a reallocation by the
IRS, you may incur a greater tax burden.

PARTNERSHIP BORROWINGS
Under the partnership agreement the managing general partner and its affiliates
may make loans to the partnerships. The use of partnership revenues taxable to
you to repay borrowings by your partnership could create income tax liability
for you in excess of your cash distributions from the partnership, since
repayments of principal are not deductible for federal income tax purposes. In
addition, interest on the loans will not be deductible unless the loans are bona
fide loans that will not be treated as capital contributions in light of all the
surrounding facts and circumstances.

PARTNERSHIP ORGANIZATION AND OFFERING COSTS
Expenses connected with the sale of the units in the partnerships, including the
dealer-manager fee and sales commissions paid to the dealer-manager which are
charged under the partnership agreement 100% to the managing general partner as
organization and offering costs, are not deductible. Although certain
organization expenses of each partnership may be amortized over a period of not
less than 60 months, these expenses also will be paid by the managing general
partner as part of each partnership's organization and offering costs. Thus, any
related deductions, which the managing general partner does not anticipate will
be material in amount as compared to the amount of the total subscription
proceeds in any partnership, will be allocated to the managing general partner.

TAX ELECTIONS
Although each partnership may elect to adjust the basis of its property (other
than cash) on the transfer of a unit in the partnership by sale or exchange or
on the death of an investor, and on the distribution of property by the
partnership to a partner, the managing general partner does not intend to make
this election for any of the partnerships. The general effect of this election
is that transferees of the units are treated, for purposes of depreciation and
gain, as though they had acquired a direct interest in the partnership assets
and the partnership is treated for these purposes, on certain distributions to
partners, as though it had newly acquired an interest in the partnership assets
and therefore acquired a new cost basis for the assets. As of the date of this
prospectus several bills were pending in Congress that proposed to make the
ss.754 election mandatory for all partnerships. If the ss.754 election does
become mandatory, the primary effect on your partnership, other than the federal
income tax consequences summarized above, would be an increase in its
administrative and accounting expenses to make the required basis adjustments to
its properties and separately account for those adjustments after they are made.
In this regard, the partnerships generally will not make in-kind property
distributions to their respective investors, and the units have no readily
available market and are subject to substantial restrictions on their transfer.
(See "Transferability of Units - Restrictions on Transfers Imposed by the
Securities Laws, the Tax Laws and the Partnership Agreement.") These factors
will tend to limit the additional expense to your partnership if the ss.754
election applies to it. Also, certain "start-up expenditures" must be
capitalized and amortized over a 60-month period. If it is ultimately determined
that any of a partnership's expenses constituted start-up expenditures and not
deductible business expenses, the partnership's deductions for those expenses
would be deferred over the 60-month period.

TERMINATION OF A PARTNERSHIP
A partnership will be considered as terminated for federal income tax purposes
if within a 12 month period there is a sale or exchange of 50% or more of the
total interest in partnership capital and profits. In that event, you would
realize taxable gain to the extent that money regarded as distributed to you by
your partnership exceeds the adjusted basis of your units. The conversion of
investor general partner units to limited partner units, however, will not
terminate a partnership. Also, due to the restrictions on transfers of units in
the partnership agreement, the managing general partner does not anticipate that
any of the partnerships will ever be considered as terminated for this reason
for federal income tax purposes.

                                       107

LACK OF REGISTRATION AS A TAX SHELTER
An organizer of a "tax shelter" must obtain an identification number which must
be included on the individual federal income tax returns of investors in the tax
shelter. For this purpose, a "tax shelter" includes an investment with respect
to which any person could reasonably infer that the ratio that the aggregate
amount of the potentially allowable deductions and 350% of the potentially
allowable credits with respect to the investment during the first five years of
the investment bears to the amount of money and the adjusted basis of property
contributed to the investment exceeds 2 to 1. In this regard, the managing
general partner has determined that none of the partnerships has a tax shelter
ratio greater than 2 to 1. Accordingly, the managing general partner does not
intend to register any of the partnerships with the IRS as a tax shelter.

If it is subsequently determined by the IRS or the courts that the partnership
in which you invest was required to be registered with the IRS as a tax shelter,
the managing general partner would be subject to certain penalties, and you
would be liable for a $250 penalty for failure to include a tax shelter
registration number for your partnership on your individual federal income tax
return unless the failure was due to reasonable cause. You also would be liable
for a penalty of $100 for failing to furnish the tax shelter registration number
to any transferee of your units. However, special counsel has expressed the
opinion that none of the partnerships is required to register with the IRS as a
tax shelter. This opinion is based in part on the managing general partner's
representations that none of the partnerships has a tax shelter ratio greater
than 2 to 1 and each partnership will be operated as described in this
prospectus.

Issuance of a registration number does not indicate that an investment or the
claimed tax benefits have been reviewed, examined, or approved by the IRS.

INVESTOR LISTS. If requested by the IRS, a partnership may be required to
identify its investors and give the IRS certain information concerning each
investor's investment in the partnership and the tax benefits of the partnership
to the investors.

TAX RETURNS AND IRS AUDITS
IN GENERAL. The tax treatment of all partnership items generally is determined
at the partnership, rather than the partner, level; and the partners generally
are required to treat partnership items on their individual federal income tax
returns in a manner which is consistent with the treatment of the partnership
items on the partnership's federal information income tax return. Generally, the
IRS must conduct an administrative determination as to partnership items at the
partnership level before conducting deficiency proceedings against a partner,
and the partners must file a request for an administrative determination before
filing suit for any credit or refund. The period for assessing tax against you
and the other investors attributable to a partnership item may be extended by
agreement between the IRS and the managing general partner, which will serve as
each partnership's representative (the "Tax Matters Partner") in all
administrative and judicial tax proceedings conducted at the partnership level.
The managing general partner generally may enter into a settlement on behalf of,
and binding on, any investor owning less than a 1% profits interest in a
partnership if the partnership has more than 100 partners. In addition, a
partnership with at least 100 partners may elect to be governed under simplified
tax reporting and audit rules as an "electing large partnership." These rules
also facilitate the matching of partnership items with individual partner
federal income tax returns by the IRS. The managing general partner does not
anticipate that the partnerships will make this election. By executing the
partnership agreement, you agree that you will not form or exercise any right as
a member of a notice group and will not file a statement notifying the IRS that
the managing general partner does not have binding settlement authority. All
expenses of any proceedings involving the managing general partner as Tax
Matters Partner, which might be substantial, will be paid for by the partnership
being audited. The managing general partner, however, is not obligated to
contest adjustments made by the IRS. The managing general partner, as Tax
Matters Partner, will notify you and the other investors in a partnership of any
IRS audits or other tax proceedings, and will provide you any other information
regarding the proceedings as may be required by the partnership agreement or
law.

TAX RETURNS. Your individual income tax returns are your responsibility. The
partnership in which you invest will provide you with the tax information
applicable to your investment in the partnership necessary to prepare your tax
returns.

PENALTIES AND INTEREST
IN GENERAL. Interest is charged on underpayments of federal income tax and
various penalties are included in the Internal Revenue Code.

                                       108

PENALTY FOR NEGLIGENCE OR DISREGARD OF RULES OR REGULATIONS. If any portion of
an underpayment of federal income tax is attributable to negligence or disregard
of IRS rules or regulations, 20% of that portion is added to the tax. Negligence
is strongly indicated if you fail to treat partnership items on your individual
federal income tax return in a manner that is consistent with the treatment of
those items on your partnership's federal information income tax return or to
notify the IRS of the inconsistency.

VALUATION MISSTATEMENT PENALTY. There is an addition to federal income tax of
20% of the amount of any underpayment of tax of $5,000 or more which is
attributable to a substantial valuation misstatement. There is a substantial
valuation misstatement if:

         o        the value or adjusted basis of any property claimed on a
                  return is 200% or more of the correct amount; or

         o        the price for any property or services, or for the use of
                  property, claimed on a return is 200% or more, or 50% or less,
                  of the correct price.

If there is a gross valuation misstatement, which is 400% or more of the correct
value or adjusted basis or the undervaluation is 25% or less of the correct
amount, then the penalty is 40%.

SUBSTANTIAL UNDERSTATEMENT PENALTY. There is also an addition to federal income
tax of 20% of any underpayment if the difference between the tax required to be
shown on the return over the tax actually shown on the return exceeds the
greater of:

         o        10% of the tax required to be shown on the return; or

         o        $5,000.

The amount of any understatement generally will be reduced to the extent it is
attributable to the tax treatment of an item:

         o        supported by substantial authority; or

         o        adequately disclosed on the taxpayer's individual federal
                  income return and there was a reasonable basis for the tax
                  treatment.

However, in the case of "tax shelters," which as defined by the Internal Revenue
Code for this purpose includes each partnership, the understatement may be
reduced by a taxpayer, other than a corporation, only if the tax treatment of an
item attributable to a tax shelter was supported by substantial authority and
the taxpayer establishes that he reasonably believed that the tax treatment
claimed was more likely than not the proper treatment.

PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND JUDICIAL DOCTRINES. Your ability to
deduct your share of your partnership's losses could be lost if the partnership
lacks the appropriate profit motive. There is a presumption under the Internal
Revenue Code that an activity is engaged in for profit if, in any three of five
consecutive taxable years, the gross income derived from the activity exceeds
the deductions attributable to the activity. Thus, if your partnership fails to
show a profit in at least three of five consecutive years this presumption will
not be available and the possibility that the IRS could successfully challenge
the partnership deductions claimed by you would be substantially increased. The
fact that the possibility of ultimately obtaining profits is uncertain, standing
alone, does not appear to be sufficient grounds for the denial of losses. Also,
if a principal purpose of a partnership is to reduce substantially the partners'
federal income tax liability in a manner that is inconsistent with the intent of
the partnership rules of the Internal Revenue Code, based on all the facts and
circumstances, the IRS is authorized under Treas. Reg. ss.1.701-2 to remedy the
abuse. Finally, under potentially relevant judicial doctrines including the step
transaction, business purpose, economic substance, substance over form, and sham
transaction doctrines, tax deductions from a transaction will be disallowed if
the transaction has no economic substance apart from the tax benefits.

                                       109

With respect to these issues, special counsel has given its opinion that the
partnerships will possess the requisite profit motive, and the IRS anti-abuse
rule in Treas. Reg ss.1.701-2 and the potentially relevant judicial doctrines
listed above, will not have a material adverse effect on the tax consequences of
an investment in a partnership by a typical investor as described in special
counsel's opinions. These opinions are based in part on the results of the
previous partnerships sponsored by the managing general partner as set forth in
"Prior Activities" and the managing general partner's representations. These
representations include that each partnership will be operated as described in
this prospectus, see "Management" and "Proposed Activities," and the principal
purpose of each partnership is to locate, produce and market natural gas and oil
on a profitable basis, apart from tax benefits. These representations are
supported by the geological evaluations and the other information for the
partnerships' proposed drilling areas and the specific prospects proposed to be
drilled by Atlas America Public #14-2004 L.P. included in Appendix A to this
prospectus, which when supplemented or amended will cover a portion of the
prospects proposed to be drilled by each of the other partnerships when units in
those partnerships are offered to potential investors.

STATE AND LOCAL TAXES
Each partnership will operate in states and localities which may impose a tax on
its assets or income, or on its investors. The states also may impose income tax
withholding requirements on the partnership in which you invest on your share of
the partnership's income whether distributed to you or not. Deductions which are
available to you for federal income tax purposes, such as the additional 50%
first-year depreciation deduction discussed in "- Depreciation - Modified
Accelerated Cost Recovery System ("MACRS") above, which may be available to
investors in Atlas America Public #14-2004 L.P. for a portion of its wells, may
not be available for state or local income tax purposes. Your share of the net
income or net loss of the partnership in which you invest generally must be
included in determining your reportable income for state or local tax purposes
in the jurisdiction in which you reside. To the extent that you pay tax to
another state because of partnership operations within that state, you may be
entitled to a deduction or credit against tax owed to your state of residence
with respect to the same income. To the extent that the partnership operates in
certain jurisdictions, state or local estate or inheritance taxes may be payable
on the death of an investor in addition to taxes imposed by his own domicile.

You are urged to consult with your own tax advisors concerning the possible
effect of various state and local taxes on your personal tax situation resulting
from an investment in a partnership.

SEVERANCE AND AD VALOREM (REAL ESTATE) TAXES
Each partnership may incur various ad valorem or severance taxes imposed by
state or local taxing authorities on its natural gas and oil wells and/or
natural gas and oil production from the wells.

SOCIAL SECURITY BENEFITS AND SELF-EMPLOYMENT TAX
A limited partner's share of income or loss from a partnership is excluded from
the definition of "net earnings from self-employment." No increased benefits
under the Social Security Act will be earned by limited partners, and if any
limited partners are currently receiving Social Security benefits their shares
of partnership taxable income will not be taken into account in determining any
reduction in benefits because of "excess earnings."

An investor general partner's share of income or loss from a partnership will
constitute "net earnings from self-employment" for these purposes. The ceiling
for social security tax of 12.4% in 2004 is $87,900 and the ceiling for 2005 is
not yet known. There is no ceiling for medicare tax of 2.9%. Self-employed
individuals can deduct one-half of their self-employment tax.

FARMOUTS
Under a farmout by a partnership, if a property interest, other than an interest
in the drilling unit assigned to the partnership well in question, is earned by
the farmee (anyone other than the partnership) from the farmor (the partnership)
as a result of the farmee drilling or completing the well, then the farmee must
recognize income equal to the fair market value of the outside interest earned,
and the farmor must recognize gain or loss on a deemed sale equal to the
difference between the fair market value of the outside interest and the
farmor's tax basis in the outside interest. Neither the farmor nor the farmee
would have received any cash to pay the tax. The managing general partner will
attempt to eliminate or reduce any gain to a partnership from a farmout, if any.
However, if the IRS claims that a farmout by a partnership results in taxable
income to the partnership and its position is ultimately sustained, the
investors in that partnership would be required to include their share of the
resulting taxable income on their personal income tax returns, even though the
partnership and its investors received no cash from the farmout.

                                       110

FOREIGN PARTNERS
Each partnership generally will be required to withhold and pay income tax to
the IRS at the highest rate under the Internal Revenue Code applicable to
partnership income allocable to its foreign investors, even if no cash
distributions are made to them. In the event of overwithholding a investor
partner must file a United States tax return to obtain a refund. Under the
Internal Revenue Code, for withholding purposes a foreign investor generally
means an investor who is a nonresident alien individual or a foreign
corporation, partnership, trust or estate, if the investor has not certified to
his partnership the investor's nonforeign status.

ESTATE AND GIFT TAXATION
There is no federal tax on lifetime or testamentary transfers of property
between spouses. The gift tax annual exclusion in 2004 is $11,000 per donee,
which will be adjusted in subsequent years for inflation. Under the Economic
Growth and Tax Relief Reconciliation Act of 2001 ("the 2001 Tax Act"), the
maximum estate and gift tax rate of 48% in 2004 will be reduced in stages until
it is 45% from 2007 to 2009. Estates of $1.5 million in 2004, which increases in
stages to $3.5 million by 2009, or less generally are not subject to federal
estate tax. Under the 2001 Tax Act, the federal estate tax is scheduled to be
repealed in 2010, and the maximum gift tax rate in 2010 will be 35%. In 2011 the
federal estate and gift taxes are scheduled to be reinstated under the rules in
effect before the 2001 Tax Act was enacted.

CHANGES IN THE LAW
Your investment in a partnership may be affected by changes in the tax laws.
(See "- Tax Elections," above.) For example, in 2003, the top four federal
income tax brackets for individuals were reduced through December 31, 2010,
including reducing the top bracket to 35% from 38.6%. The lower federal income
tax rates will reduce to some degree the amount of taxes you save by virtue of
your share of your partnership's deductions for intangible drilling costs,
depletion and depreciation. However, the lower federal income tax rates also
will reduce the amount of federal income tax liability incurred by you on your
share of the net income of your partnership. There is no assurance that the
federal income tax rates discussed above will not be changed again before 2011.

                        SUMMARY OF PARTNERSHIP AGREEMENT

The rights and obligations of the managing general partner and you and the other
investors are governed by the form of partnership agreement attached as Exhibit
(A) to this prospectus. You are urged to not invest in a partnership without
first thoroughly reviewing the partnership agreement. The following is a summary
of the material provisions in the partnership agreement that are not covered
elsewhere in this prospectus. Thus, this prospectus summarizes all of the
material provisions of the partnership agreement.

LIABILITY OF LIMITED PARTNERS
Each partnership will be governed by the Delaware Revised Uniform Limited
Partnership Act. If you invest as a limited partner, then generally you will not
be liable to third-parties for the obligations of your partnership unless you:

         o        also invest as an investor general partner;

         o        take part in the control of the partnership's business in
                  addition to the exercise of your rights and powers as a
                  limited partner; or

         o        fail to make a required capital contribution to the extent of
                  the required capital contribution.

In addition, you may be required to return any distribution you receive if you
knew at the time the distribution was made that it was improper because it
rendered the partnership insolvent.

AMENDMENTS
Amendments to the partnership agreement of a partnership may be proposed in
writing by:

                                       111

         o        the managing general partner and adopted with the consent of
                  investors whose units equal a majority of the total units in
                  the partnership; or

         o        investors whose units equal 10% or more of the total units in
                  the partnership and adopted by an affirmative vote of
                  investors whose units equal a majority of the total units in
                  the partnership.

The partnership agreement of each partnership may also be amended by the
managing general partner without the consent of the investors for certain
limited purposes. However, an amendment that materially and adversely affects
the investors can only be made with the consent of the affected investors.

NOTICE
The following provisions apply regarding notices:

         o        when the managing general partner gives you and other
                  investors notice it begins to run from the date of mailing the
                  notice and is binding even if it is not received;

         o        the notice periods are frequently quite short, a minimum of 22
                  calendar days, and apply to matters that may seriously affect
                  your rights; and

         o        if you fail to respond in the specified time to the managing
                  general partner's second request for approval of or
                  concurrence in a proposed action, then you will conclusively
                  be deemed to have approved the action unless the partnership
                  agreement expressly requires your affirmative approval.

VOTING RIGHTS
Other than as set forth below, you generally will not be entitled to vote on any
partnership matters at any partnership meeting. However, at any time investors
whose units equal 10% or more of the total units in a partnership may call a
meeting to vote, or vote without a meeting, on the matters set forth below
without the concurrence of the managing general partner. On the matters being
voted on you are entitled to one vote per unit or if you own a fractional unit
that fraction of one vote equal to the fractional interest in the unit.
Investors whose units equal a majority of the total units in a partnership may
vote to:

         o        dissolve the partnership;

         o        remove the managing general partner and elect a new managing
                  general partner;

         o        elect a new managing general partner if the managing general
                  partner elects to withdraw from the partnership;

         o        remove the operator and elect a new operator;

         o        approve or disapprove the sale of all or substantially all of
                  the partnership assets;

         o        cancel any contract for services with the managing general
                  partner, the operator, or their affiliates without penalty on
                  60 days notice; and

         o        amend the partnership agreement; provided however, any
                  amendment may not:

                  o        without the approval of you or the managing general
                           partner increase the duties or liabilities of you or
                           the managing general partner or increase or decrease
                           the profits or losses or required capital
                           contribution of you or the managing general partner;
                           or

                  o        without the unanimous approval of all investors in
                           the partnership affect the classification of
                           partnership income and loss for federal income tax
                           purposes.

                                       112

The managing general partner, its officers, directors, and affiliates may also
subscribe for units in each partnership on a discounted basis, and they may vote
on all matters other than:

         o        the issues set forth above concerning removing the managing
                  general partner and operator; and

         o        any transaction between the managing general partner or its
                  affiliates and the partnership.

Any units owned by the managing general partner and its affiliates will not be
included in determining the requisite number of units necessary to approve any
partnership matter on which the managing general partner and its affiliates may
not vote or consent.

ACCESS TO RECORDS
You will have access to all records of your partnership at any reasonable time
on adequate notice. However, logs, well reports, and other drilling and
operating data may be kept confidential for reasonable periods of time. Your
ability to obtain the list of investors is subject to additional requirements
set forth in the partnership agreement.

WITHDRAWAL OF MANAGING GENERAL PARTNER
After 10 years the managing general partner may voluntarily withdraw as managing
general partner of a partnership for any reason by giving 120 days' written
notice to you and the other investors in the partnership. Although the
withdrawing managing general partner is not required to provide a substitute
managing general partner, a new managing general partner may be substituted by
the affirmative vote of investors whose units equal a majority of the total
units in the partnership. If the investors, however, choose not to continue the
partnership and select a substitute managing general partner, then the
partnership would terminate and dissolve which could result in adverse tax and
other consequences to you.

Also, subject to a required participation of not less than 1% of each
partnership's revenues, the managing general partner may withdraw a property
interest in the form of a working interest in the partnership's wells equal to
or less than its revenue interest if the withdrawal is:

         o        to satisfy the bona fide request of its creditors; or

         o        approved by investors in the partnership whose units equal a
                  majority of the total units.

RETURN OF SUBSCRIPTION PROCEEDS IF FUNDS ARE NOT INVESTED IN TWELVE MONTHS
Although the managing general partner anticipates that each partnership will
spend all of its subscription proceeds soon after the offering of the
partnership closes, each partnership will have 12 months in which to use or
commit funds to drilling activities. If within the 12-month period the
partnership has not used or committed for use all the subscription proceeds,
then the managing general partner will distribute the remaining subscription
proceeds to you and the other investors in the partnership in accordance with
your subscription proceeds as a return of capital.

                   SUMMARY OF DRILLING AND OPERATING AGREEMENT

The managing general partner will serve as the operator under the drilling and
operating agreement, Exhibit (II) to the partnership agreement. The operator may
be replaced at any time on 60 days' advance written notice by the managing
general partner acting on behalf of a partnership on the affirmative vote of
investors whose units equal a majority of the total units in the partnership.
You are urged not to invest in a partnership without first thoroughly reviewing
the drilling and operating agreement. The following is a summary of the material
provisions in the drilling and operating agreement that are not covered
elsewhere in this prospectus. Thus, this prospectus summarizes all of the
material provisions of the drilling and operating agreement.

The drilling and operating agreement includes a number of material provisions,
including, without limitation, those set forth below.

                                    113

         o        The operator's right to resign after five years.

         o        The operator's right beginning one year after a partnership
                  well begins producing to retain $200 per month to cover future
                  plugging and abandonment costs of the well, although the
                  managing general partner historically has never done this
                  after only one year.

         o        The grant of a first lien and security interest in the wells
                  and related production to secure payment of amounts due to the
                  operator by a partnership.

         o        The prescribed insurance coverage to be maintained by the
                  operator.

         o        Limitations on the operator's authority to incur extraordinary
                  costs with respect to producing wells in excess of $5,000 per
                  well.

         o        Restrictions on the partnership's ability to transfer its
                  interest in fewer than all wells unless the transfer is of an
                  equal undivided interest in all wells.

         o        The limitation of the operator's liability to a partnership
                  except for the operator's:

                  o        violations of law;

                  o        negligence or misconduct by it, its employees, agents
                           or subcontractors; or

                  o        breach of the drilling and operating agreement.

         o        The excuse for nonperformance by the operator due to force
                  majeure which generally means acts of God, catastrophes and
                  other causes which preclude the operator's performance and are
                  beyond its control. (See "Material Federal Income Tax
                  Consequences - Drilling Contracts.")

                              REPORTS TO INVESTORS

Under the partnership agreement for each partnership you and certain state
securities commissions will be provided the reports and information set forth
below for your partnership, which your partnership will pay as a direct cost.

         o        Beginning with the calendar year in which your partnership
                  closes, you will be provided an annual report within 120 days
                  after the close of the calendar year, and beginning with the
                  following calendar year, a report within 75 days after the end
                  of the first six months of its calendar year, containing at
                  least the following information.

                  o        Audited financial statements of the partnership
                           prepared on an accrual basis in accordance with
                           generally accepted accounting principles with a
                           reconciliation for information furnished for income
                           tax purposes. Independent certified public
                           accountants will audit the financial statements to be
                           included in the annual report, but semiannual reports
                           will not be audited.

                  o        A summary of the total fees and compensation paid by
                           the partnership to the managing general partner, the
                           operator, and their affiliates, including the
                           percentage that the annual unaccountable, fixed
                           payment reimbursement for administrative costs bears
                           to annual partnership revenues. In this regard, the
                           independent certified public accountant will provide
                           written attestation annually, which will be included
                           in the annual report, that the method used to make
                           allocations was consistent with the method described
                           inss.4.04(a)(2)(c) of the partnership agreement and
                           that the total amount of costs allocated did not
                           materially exceed the amounts actually incurred by
                           the managing general partner.

                                       114

                           If the managing general partner subsequently decides
                           to allocate expenses in a manner different from that
                           described in ss.4.04(a)(2)(c) of the partnership
                           agreement, then the change must be reported to you
                           and the other investors with an explanation of the
                           reason for the change and the basis used for
                           determining the reasonableness of the new allocation
                           method.

                  o        A description of each prospect owned by the
                           partnership, including the cost, location, number of
                           acres, and the interest.

                  o        A list of the wells drilled or abandoned by the
                           partnership indicating:

                           o        whether each of the wells has or has not
                                    been completed; and

                           o        a statement of the cost of each well
                                    completed or abandoned.

                  o        A description of all farmouts, farmins, and joint
                           ventures.

                  o        A schedule reflecting:

                           o        the total partnership costs;

                           o        the costs paid by the managing general
                                    partner and the costs paid by the investors;

                           o        the total partnership revenues; and

                           o        the revenues received or credited to the
                                    managing general partner and the revenues
                                    received or credited to you and the other
                                    investors.

         o        On request the managing general partner will provide you the
                  information specified by Form 10-Q (if that report is required
                  to be filed with the SEC) within 45 days after the close of
                  each quarterly fiscal period. Also, this information is
                  available at the SEC website www.sec.gov.

         o        By March 15 of each year you will receive the information that
                  is required for you to file your federal and state income tax
                  returns.

         o        Beginning with the second calendar year after your partnership
                  closes, and every year thereafter, you will receive a
                  computation of the partnership's total natural gas and oil
                  proved reserves and its dollar value. The reserve computations
                  will be based on engineering reports prepared by the managing
                  general partner and reviewed by an independent expert.

                               PRESENTMENT FEATURE

Beginning with the fifth calendar year after your partnership closes you and the
other investors in your partnership may present your units to the managing
general partner to purchase your units. However, you are not required to offer
your units to the managing general partner, and you may receive a greater return
if you retain your units. The managing general partner will not purchase less
than one unit unless the fractional unit represents your entire interest.

The managing general partner has no obligation and does not intend to establish
a reserve to satisfy the presentment obligation and may immediately suspend its
purchase obligation by notice to you if it determines, in its sole discretion,
that it:

         o        does not have the necessary cash flow; or

         o        cannot borrow funds for this purpose on terms it deems
                  reasonable.

                                       115

If fewer than all units presented at any time are to be purchased by the
managing general partner, then the units to be purchased will be selected by
lot.

The managing general partner's obligation to purchase the units presented may be
discharged for its benefit by a third-party or an affiliate. If you sell your
unit it will be transferred to the party who pays for it, and you will be
required to deliver an executed assignment of your unit along with any other
documents that the managing general partner requests. Your presentment is
subject to the following conditions:

         o        the managing general partner will not purchase more than 5% of
                  the units in a partnership in any calendar year;

         o        the presentment must be within 120 days of the partnership
                  reserve report discussed below;

         o        in accordance with Treas. Reg.ss.1.7704-1(f) the purchase may
                  not be made by the managing general partner until at least 60
                  calendar days after you notify the partnership in writing of
                  your intent to present your unit; and

         o        the purchase will not be considered effective until the
                  presentment price has been paid to you in cash.

The amount attributable to a partnership's natural gas and oil reserves will be
determined based on the last reserve report. Beginning with the second calendar
year after your partnership closes and every year thereafter, the managing
general partner will estimate the present worth of future net revenues
attributable to your partnership's interest in proved reserves. In making this
estimate, the managing general partner will use:

         o        a 10% discount rate;

         o        a constant oil price; and

         o        base natural gas prices on the existing natural gas contracts
                  at the time of the presentment.

Your presentment price will be based on your share of your partnership's net
assets and liabilities as described below, based on the ratio that the number of
your units bears to the total number of units in your partnership. The
presentment price will include the sum of the following partnership items:

         o        an amount based on 70% of the present worth of future net
                  revenues from the proved reserves determined as described
                  above;

         o        cash on hand;

         o        prepaid expenses and accounts receivable, less a reasonable
                  amount for doubtful accounts; and

         o        the estimated market value of all assets not separately
                  specified above, determined in accordance with standard
                  industry valuation procedures.

There will be deducted from the foregoing sum the following items:

         o        an amount equal to all debts, obligations, and other
                  liabilities, including accrued expenses; and

         o        any distributions made to you between the date of the request
                  and the actual payment. However, if any cash distributed was
                  derived from the sale, after the presentment request, of oil,
                  natural gas, or a producing property, for purposes of
                  determining the reduction of the presentment price the
                  distributions will be discounted at the same rate used to take
                  into account the risk factors employed to determine the
                  present worth of the partnership's proved reserves.

                                       116

The amount may be further adjusted by the managing general partner for estimated
changes from the date of the reserve report to the date of payment of the
presentment price to you because of the following:

         o        the production or sales of, or additions to, reserves and
                  lease and well equipment, sale or abandonment of leases, and
                  similar matters occurring before the presentment request; and

         o        any of the following occurring before payment of the
                  presentment price to you;

                  o        changes in well performance;

                  o        increases or decreases in the market price of oil,
                           natural gas, or other minerals;

                  o        revision of regulations relating to the importing of
                           hydrocarbons; and

                  o        changes in income, ad valorem, and other tax laws
                           such as material variations in the provisions for
                           depletion; and

                  o        similar matters.

As of January 1, 2004, approximately 80 units have been presented to the
managing general partner for purchase in its previous 46 limited partnerships.

                            TRANSFERABILITY OF UNITS

RESTRICTIONS ON TRANSFER IMPOSED BY THE SECURITIES LAWS, THE TAX LAWS AND THE
PARTNERSHIP AGREEMENT Your ability to sell or otherwise transfer your units in
your partnership is restricted by the securities laws, the tax laws, and the
partnership agreement as described below. Also, the transfer may create negative
tax consequences to you as described in "Material Federal Income Tax
Consequences - Disposition of Units."

First, under the tax laws you will not be able to sell, assign, exchange, or
transfer your unit if it would, in the opinion of counsel for the partnership,
result in the following:

         o        the termination of your partnership for tax purposes; or

         o        your partnership being treated as a "publicly-traded"
                  partnership for tax purposes.

Second, under the partnership agreement transfers are subject to the following
limitations:

         o        except as provided by operation of law, the partnership will
                  recognize the transfer of only one or more whole units unless
                  you own less than a whole unit, in which case your entire
                  fractional interest must be transferred;

         o        the costs and expenses associated with the transfer must be
                  paid by the person transferring the unit;

         o        the form of transfer must be in a form satisfactory to the
                  managing general partner; and

         o        the terms of the transfer must not contravene those of the
                  partnership agreement.

Your transfer of a unit will not relieve you of your responsibility for any
obligations related to the units under the partnership agreement. Also, the
transfer does not grant rights under the partnership agreement as among your
transferees to more than one party unanimously designated by the transferees to
the managing general partner. Finally, the transfer of a unit does not require
an accounting by the managing general partner. Any transfer when the assignee of
the unit does not become a substituted partner as described below in "-
Conditions to Becoming a Substitute Partner," will be effective as of:

                                       117

         o        midnight of the last day of the calendar month in which it is
                  made; or

         o        at the managing general partner's election 7:00 A.M. of the
                  following day.

Finally, you will not be able to sell, assign, pledge, hypothecate, or transfer
your unit unless there is an opinion of counsel acceptable to the managing
general partner that the registration and qualification under any applicable
federal or state securities laws are not required.

CONDITIONS TO BECOMING A SUBSTITUTE PARTNER
On a transfer unless an assignee becomes a substituted partner in accordance
with the provisions set forth below, he will not be entitled to any of the
rights granted to a partner under the agreement, other than the right to receive
all or part of the share of the profits, losses, income, gain, credits and cash
distributions or returns of capital to which his assignor would otherwise be
entitled.

The conditions to become a substitute partner are as follows:

         o        the assignor gives the assignee the right;

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

         o        the assignee executes and delivers the instruments necessary
                  to establish that a legal transfer has taken place and to
                  confirm his agreement to be bound by all terms and provisions
                  of the partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the
assigned units, including the right to vote. Each partnership will amend its
records at least once each calendar quarter to effect the substitution of
substituted partners.

                              PLAN OF DISTRIBUTION

COMMISSIONS
The units in each partnership will be offered on a "best efforts" basis by
Anthem Securities, which is an affiliate of the managing general partner, acting
as dealer-manager in all states other than Minnesota and New Hampshire and by
other selected registered broker/dealers which are members of the NASD acting as
selling agents. Anthem Securities was formed for the purpose of serving as
dealer-manager of partnerships sponsored by the managing general partner and
became an NASD member firm in April, 1997. Bryan Funding, Inc., a member of the
NASD, will serve as dealer-manager for this offering in the states of Minnesota
and New Hampshire, and will receive the same compensation as Anthem Securities
for sales in those states. The term "dealer-manager" as used in this prospectus
includes both Anthem Securities, Inc. and Bryan Funding, Inc.

The dealer-manager will manage and oversee the offering of the units as
described above. Best efforts generally means that the dealer-manager and
selling agents will not guarantee that a certain number of units will be sold.
Units may also be sold by the officers and directors of the managing general
partner in those states where they are licensed or exempt from licensing.
Messrs. Kotek, Atkinson and Hollander, Ms. Bleichmar and Ms. Black, who are
associated with Anthem Securities, will not make any offers or sales under the
SEC safe harbor from broker/dealer registration provided by SEC Rule 3a4-1
promulgated under the Securities Exchange Act of 1934 (the "Act"), although they
may do so as associated persons of Anthem Securities. Also, all offers and sales
of units by the managing general partner's remaining officers and directors will
be made under the SEC safe harbor from broker/dealer registration provided by
Rule 3a4-1. In this regard, none of the remaining officers and directors of the
managing general partner:

         o        is subject to a statutory disqualification, as that term is
                  defined in Section 3(a)(39) of the Act, at the time of his
                  participation;

         o        is compensated in connection with his participation by the
                  payment of commissions or other remuneration based either
                  directly or indirectly on transactions in securities; and

                                       118

         o        is at the time of his participation an associated person of a
                  broker or dealer.

Also, each of the remaining officers and directors:

         o        performs, or is intended primarily to perform at the end of
                  the offering, substantial duties for or on behalf of the
                  managing general partner otherwise than in connection with
                  transactions in securities;

         o        was not a broker or dealer, or an associated person of a
                  broker or dealer, within the preceding 12 months; and

         o        will not participate in selling an offering of securities for
                  any issuer more than once every 12 months, with the
                  understanding that for securities issued pursuant to Rule 415
                  under Securities Act of 1933, the 12 month period begins with
                  the last sale of any security included within one Rule 415
                  registration.

Subject to the exceptions described below, the dealer-manager will receive on
each unit sold:

         o        a 2.5% dealer-manager fee;

         o        a 7% sales commission;

         o        an up to .5% reimbursement of the selling agent's bona fide
                  accountable due diligence expenses; and

         o        a .5% accountable reimbursement for permissible non-cash
                  compensation. Under Rule 2810 of the NASD Conduct Rules,
                  non-cash compensation means any form of compensation received
                  in connection with the sale of the units that is not cash
                  compensation, including but not limited to merchandise, gifts
                  and prizes, travel expenses, meals and lodging. Permissible
                  non-cash compensation includes the following:

                  o        an accountable reimbursement for training and
                           education meetings for associated persons of the
                           selling agents;

                  o        gifts that do not exceed $100 per year and are not
                           preconditioned on achievement of a sales target;

                  o        an occasional meal, a ticket to a sporting event or
                           the theater, or comparable entertainment which is
                           neither so frequent nor so extensive as to raise any
                           question of propriety and is not preconditioned on
                           achievement of a sales target; and

                  o        contributions to a non-cash compensation arrangement
                           between a selling agent and its associated persons,
                           provided that neither the managing general partner
                           nor the dealer-manager directly or indirectly
                           participates in the selling agent's organization of a
                           permissible non-cash compensation arrangement.

All of the reimbursement of the selling agents' bona fide accountable due
diligence expenses and generally all of the 7% sales commission will be
reallowed to the selling agents. With respect to the up to .5% reimbursement of
a selling agent's bona fide accountable due diligence expenses, any bill
presented by a selling agent to the dealer-manager for reimbursement of costs
associated with its due diligence activities must be for actual costs, including
overhead, incurred by the selling agent and may not include a profit margin. It
is the responsibility of the managing general partner and the dealer-manager to
ensure compliance with the above guideline. Although the dealer-manager is not
required to obtain an itemized expense statement before paying out due diligence
expenses, any bill for due diligence submitted by the selling agent to the
dealer-manager must be based on the selling agent's actual expenses incurred in
conducting due diligence. If the dealer-manager receives a non-itemized bill for
due diligence that it has reason to question, then it has the obligation to
ensure compliance by requesting an itemized statement to support the bill
submitted by the selling agent. If the due diligence bill cannot be justified,
any excess over actual due diligence expenses that is paid is considered by the
NASD to be undisclosed underwriting compensation and is required to be included
within the 10% compensation guideline under NASD Conduct Rule 2810, and
reflected on the books and records of the selling agent. However, if the selling
agent provides the dealer-manager an itemized bill for actual due diligence
expenses which is in excess of .5%, then the excess over .5% will not be
included within the 10% compensation guideline, but instead will be included
within the 4.5% organization and offering cost guideline under NASD Conduct Rule
2810.

                                       119

The dealer-manager or managing general partner may make certain non-cash
compensation arrangements with the selling agents and their registered
representatives, which will be included in the accountable reimbursement for
permissible non-cash compensation. The dealer-manager is responsible for
ensuring that all permissible non-cash compensation arrangements comply with
Rule 2810 of the NASD Conduct Rules. For example, payments or reimbursements by
the dealer-manager or the managing general partner may be made in connection
with meetings held by the dealer-manager or the managing general partner for the
purpose of training or education of registered representatives of a selling
agent only if the following conditions are met:

         o        the registered representative obtains his selling agent's
                  prior approval to attend the meeting and attendance by the
                  registered representative is not conditioned by his selling
                  agent on the achievement of a sales target;

         o        the location of the training and education meeting is
                  appropriate to the purpose of the meeting as defined in NASD
                  Conduct Rule 2810;

         o        the payment or reimbursement is not applied to the expenses of
                  guests of the registered representative;

         o        the payment or reimbursement by the dealer-manager or the
                  managing general partner is not conditioned by the
                  dealer-manager or the managing general partner on the
                  achievement of a sales target; and

         o        the recordkeeping requirements are met.

The dealer-manager will retain any of the accountable reimbursement for
permissible non-cash compensation not reallowed to the selling agents.

The managing general partner is also using the services of wholesalers who are
employed by it or its affiliates and are registered through Anthem Securities.
The wholesalers include Mr. Jim O'Mara and three Regional Marketing Directors,
Mr. Bruce Bundy, Mr. Robert Gourlay and Ms. Vicki Burbridge. Most of the 2.5%
dealer-manager fee will be reallowed to the affiliated wholesalers for
subscriptions obtained through their efforts, which includes expense
reimbursements to them and a salary to Mr. O'Mara in connection with the
offering. The dealer-manager will retain the remainder of the dealer-manager fee
not reallowed to the wholesalers, which may be used for such items as legal fees
associated with underwriting and salaries of dual employees of the
dealer-manager and the managing general partner which are required to be
included in underwriting compensation under NASD Conduct Rule 2810 as determined
jointly by the managing general partner and the dealer-manager.

The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules
and all compensation, including non-cash compensation, to broker/dealers and
wholesalers, regardless of the source, will be limited to 10% of the gross
proceeds of the offering plus the .5% reimbursement for bona fide accountable
due diligence expenses on each subscription. Also, the offering will be made in
compliance with Rule 2810(b)(2)(C) of the NASD Conduct Rules and the
broker/dealers and wholesalers will not execute a transaction for the purchase
of units in a discretionary account without the prior written approval of the
transaction by the customer. Finally, although not anticipated, if the
dealer-manager assists in the transfer of units then it will comply with Rule
2810(b)(3)(D) of the NASD Conduct Rules.

Subject to the following, you and the other investors will pay $10,000 per unit
and generally will share costs, revenues, and distributions in the partnership
in which you subscribe in proportion with your respective number of units.
However, the subscription price for certain investors will be reduced as set
forth below:

                                       120

         o        the subscription price for the managing general partner, its
                  officers, directors, and affiliates, and investors who buy
                  units through the officers and directors of the managing
                  general partner, will be reduced by an amount equal to the
                  2.5% dealer-manager fee, the 7% sales commission, the .5%
                  reimbursement for bona fide accountable due diligence
                  expenses, and the .5% accountable reimbursement for
                  permissible non-cash compensation, which will not be paid with
                  respect to these sales; and

         o        the subscription price for registered investment advisors and
                  their clients, and selling agents and their registered
                  representatives and principals, will be reduced by an amount
                  equal to the 7% sales commission, which will not be paid with
                  respect to these sales.

No more than 5% of the total units in each partnership may be sold with the
discounts described above.

These investors who pay a reduced price for their units generally will share in
a partnership's costs, revenues, and distributions on the same basis as the
other investors who pay $10,000 per unit. Although the managing general partner
and its affiliates may buy up to 5% of the units, they do not currently
anticipate buying any units. If they do buy units, then those units will not be
applied towards the minimum subscription proceeds required for a partnership to
begin operations.

After the minimum subscriptions are received in a partnership and the checks
have cleared the banking system, the dealer-manager fee and the sales
commissions will be paid to the dealer-manager and selling agents approximately
every two weeks until the offering closes.

INDEMNIFICATION
The dealer-manager is an underwriter as that term is defined in the 1933 Act and
the sales commissions and dealer-manager fees will be deemed underwriting
compensation. The managing general partner and the dealer-managers have agreed
to indemnify each other, and it is anticipated that the dealer-managers and each
selling agent will agree to indemnify each other against certain liabilities,
including liabilities under the 1933 Act.

                                 SALES MATERIAL

In addition to the prospectus the managing general partner intends to use the
following sales material with the offering of the units:

         o        a flyer entitled "Atlas America Public #14-2004 Program";

         o        an article entitled "Tax Rewards with Oil and Gas
                  Partnerships";

         o        a brochure of tax scenarios entitled "How an Investment in
                  Atlas America Public #14-2004 Program Can Help Achieve an
                  Investor's Tax Objectives";

         o        a brochure entitled "Investing in Atlas America Public
                  #14-2004 Program";

         o        a booklet entitled "Outline of Tax Consequences of Oil and Gas
                  Drilling Programs";

         o        a brochure entitled "The Appalachian Basin: A Prime Drilling
                  Location Which Commands a Premium";

         o        a brochure entitled "Investment Insights - Tax Time";

         o        a brochure entitled "Frequently Asked Questions";

         o        a brochure entitled "AMT--A Little History";

         o        a brochure entitled "Reducing AMT through Natural Gas
                  Partnerships"; and

         o        possibly other supplementary materials.

The managing general partner has not authorized the use of other sales material
and the offering of units is made only by means of this prospectus. The sales
material is subject to the following considerations:

                                       121

         o        it must be preceded or accompanied by this prospectus;

         o        it is not complete;

         o        it does not contain any material information which is not also
                  set forth in this prospectus; and

         o        it should not be considered a part of or incorporated into
                  this prospectus or the registration statement of which this
                  prospectus is a part.

In addition, supplementary materials, including prepared presentations for group
meetings, must be submitted to the state administrators before they are used and
their use must either be preceded by or accompanied by a prospectus. Also, all
advertisements of, and oral or written invitations to, "seminars" or other group
meetings at which the units are to be described, offered, or sold will clearly
indicate the following:

         o        that the purpose of the meeting is to offer the units for
                  sale;

         o        the minimum purchase price of the units;

         o        the suitability standards to be employed; and

         o        the name of the person selling the units.

Also, no cash, merchandise, or other items of value may be offered as an
inducement to you or any prospective investor to attend the meeting. All written
or prepared audiovisual presentations, including scripts prepared in advance for
oral presentations to be made at the meetings, must be submitted to the state
administrators within a prescribed review period. These provisions, however,
will not apply to meetings consisting only of the registered representatives of
the selling agents.

You should rely only on the information contained in this prospectus in making
your investment decision. No one is authorized to provide you with information
that is different.

                                 LEGAL OPINIONS

Kunzman & Bollinger, Inc., has issued its opinion to the managing general
partner regarding the validity and due issuance of the units including
assessibility and its opinion on material federal income tax consequences to
individual typical investors in the partnerships. However, the factual
statements in this prospectus are those of the partnerships or the managing
general partner, and counsel has not given any opinions with respect to any of
the tax or other legal aspects of this offering except as expressly set forth
above.

                                     EXPERTS

The financial statements included in this prospectus for the managing general
partner as of and for the years ended September 30, 2003 and 2002 and the
balance sheet for Atlas America Public #14-2004 L.P. as of June 30, 2004, have
been audited by Grant Thornton LLP, as of the dates indicated in its reports
which appear elsewhere in this prospectus. These financial statements have been
included in reliance on its reports given on its authority as experts in
auditing and accounting.

                                       122


The geologic evaluations of United Energy Development Consultants, Inc., which
is not affiliated with the managing general partner or its affiliates, appearing
in Appendix A to this prospectus for the areas where potential prospects have
been identified for Atlas America Public #14-2004 L.P. have been included in
this prospectus on the authority of United Energy Development Consultants, Inc.
as an expert with respect to the matters covered by the evaluations and in the
giving of the evaluations.

The information concerning the prior public partnerships' estimated future net
cash flows from proved reserves presented under "Prior Activities - Table 3
Investor Operating Results - Including Expenses" was reviewed by Wright &
Company, Inc., Brentwood, Tennessee, independent petroleum consultants in
reliance on Wright & Company, Inc. as an expert in petroleum consulting.

                                   LITIGATION

The managing general partner knows of no litigation pending or threatened to
which the managing general partner or the partnerships are subject or may be a
party, which it believes would have a material adverse effect on the
partnerships or their business, and no such proceedings are known to be
contemplated by governmental authorities or other parties.

                  FINANCIAL INFORMATION CONCERNING THE MANAGING
             GENERAL PARTNER AND ATLAS AMERICA PUBLIC #14-2004 L.P.

Financial information concerning the managing general partner and the first
partnership in the program, Atlas America Public #14-2004 L.P., which is the
only partnership that has been formed, is reflected in the following financial
statements.

The securities offered by this prospectus are not securities of, nor are you
acquiring an interest in the managing general partner, its affiliates, or any
other entity other than the partnership in which you purchase units.

                                       123





AUDIT REPORT

ATLAS AMERICA PUBLIC #14-2004 L.P.
(A Delaware Limited Partnership)

JUNE 30, 2004




























                                       F-1












             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the Partners
Atlas America Public #14-2004 L.P.
(A DELAWARE LIMITED PARTNERSHIP)


We have audited the accompanying balance sheet of Atlas America Public #14-2004
L.P. (a Delaware Limited Partnership) as of June 30, 2004. This financial
statement is the responsibility of the Partnership's management. Our
responsibility is to express an opinion on this financial statement based on our
audit.

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
statement is free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statement. An audit also includes 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 statement referred to above presents fairly, in
all material respects, the financial position of Atlas America Public #14-2004
L.P. as of June 30, 2004, in conformity with accounting principles generally
accepted in the United States of America.



/s/ GRANT THORNTON LLP



Cleveland, Ohio
June 30, 2004










                                       F-2




                       Atlas America Public #14-2004 L.P.
                        (A Delaware Limited Partnership)

                                  BALANCE SHEET

                                  June 30, 2004






                                     ASSETS


                                                               $            100
Cash                                                           =================






                                PARTNERS' CAPITAL


                                                               $            100
Partners' capital:                                             =================














    The accompanying notes are an integral part of this financial statement.






                                       F-3

                       Atlas America Public #14-2004 L.P.
                        (A Delaware Limited Partnership)

                          NOTES TO FINANCIAL STATEMENT

                                  June 30, 2004



1.       ORGANIZATION AND DESCRIPTION OF BUSINESS

         Atlas America Public #14-2004 L.P. (the "Partnership") is a Delaware
         limited partnership in which Atlas Resources, Inc. ("Atlas Resources")
         of Pittsburgh, Pennsylvania (a second-tier wholly-owned subsidiary of
         Atlas America, Inc., a publicly traded company, which is a second-tier
         subsidiary of Resource America, Inc., a publicly traded company) will
         be Managing General Partner and Operator, and subscribers to Units will
         be either Limited Partners or Investor General Partners depending upon
         their election.

         The Partnerships will be funded to drill development wells which are
         proposed to be located primarily in the Appalachian Basin located in
         western Pennsylvania, eastern and southern Ohio and western New York.

         Subscriptions at a cost of $10,000 per unit, subject to discounts for
         certain investors, generally will be sold using wholesalers and through
         broker-dealers including Anthem Securities, Inc., an affiliated
         company, which will receive, on each unit sold to an investor, a 2.5%
         dealer-manager fee, a 7% sales commission, a .5% accountable
         reimbursement for permissible non-cash compensation, and an up to .5%
         reimbursement of bona fide accountable due diligence expenses.
         Commencement of Partnership operations is subject to the receipt of
         minimum Partnership subscriptions of $2,000,000 (up to a maximum of
         $125,000,000 ) by December 31, 2004.

2.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

         BASIS OF ACCOUNTING
         -------------------

         The Partnership will prepare its financial statements in accordance
         with accounting principles generally accepted in the United States of
         America.

         OIL AND GAS PROPERTIES
         ----------------------

         The Partnership will use 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 will
         be capitalized. Depreciation and depletion will be computed on a
         field-by-field basis by the unit-of-production method based on periodic
         estimates of oil and gas reserves.

         Undeveloped leaseholds and proved properties will be assessed
         periodically or whenever events or circumstances indicate that the
         carrying amount of these assets may not be recoverable. Proved
         properties will be assessed based on estimates of future cash flows.








                                       F-4



                       Atlas America Public #14-2004 L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT - CONTINUED

                                  June 30, 2004

2.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

         USE OF ESTIMATES
         ----------------

         The 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 amounts
         reported in the financial statements and accompanying notes. Actual
         results could differ from those estimates.

3.       FEDERAL INCOME TAXES

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

4.       PARTICIPATION IN REVENUES AND COSTS

         The Managing General Partner and the investor partners will participate
         in revenues and costs in the following manner:



                                                                                MANAGING
                                                                                 GENERAL             INVESTOR
                                                                                 PARTNER             PARTNERS
                                                                                --------             --------
         PARTNERSHIP COSTS
         Organization and offering costs............................................100%                   0%
         Lease costs................................................................100%                   0%
         Intangible drilling costs....................................................0%                 100%
         Equipment costs (1).........................................................66%                  34%
         Operating costs, administrative costs, direct costs, and all
         other costs.................................................................(2)                  (2)

         PARTNERSHIP REVENUES
         Interest income.............................................................(3)                  (3)
         Equipment proceeds (1)......................................................66%                  34%
         All other revenues including production revenues.........................(4)(5)               (4)(5)

         ---------------------
(1)      These percentages may vary. If the total equipment costs for all of the
         partnership's wells that would be charged to the investor partners
         exceeds an amount equal to 10% of the subscription proceeds of investor
         partners in the partnership, then the excess will be charged to the
         managing general partner. Equipment proceeds, if any, will be credited
         in the same percentage in which the equipment costs were charged.






                                       F-5


                       Atlas America Public #14-2004 L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT - CONTINUED

                                  June 30, 2004

4.       PARTICIPATION IN REVENUES AND COSTS -CONTINUED

(2)      These costs will be charged to the parties in the same ratio as the
         related production revenues are being credited. These costs also
         include plugging and abandonment costs of the wells after the wells
         have been drilled and produced.
(3)      Interest earned on subscription proceeds before the final closing of
         the partnership will be credited to their account and paid not later
         than the partnership's first cash distributions from operations. After
         the final closing of the partnership and until the subscription
         proceeds are invested in the partnership's natural gas and oil
         operations any interest income from temporary investments will be
         allocated pro rata to the investor partners providing the subscription
         proceeds. All other interest income, including interest earned on the
         deposit of operating revenues, will be credited as natural gas and oil
         production revenues are credited.
(4)      The managing general partner and the investor partners in the
         partnership will share in all of the partnership's other revenues in
         the same percentage as their respective capital contributions bears to
         the total partnership capital contributions except that the managing
         general partner will receive an additional 7% of the partnership
         revenues. However, the managing general partner's total revenue share
         may not exceed 35% of partnership revenues.
(5)      The actual allocation of partnership revenues between the managing
         general partner and the investor partners will vary from the allocation
         described in (4) above if a portion of the managing general partner's
         partnership net production revenues is subordinated as described in
         note 7.

5.       TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES

         The Partnership intends to enter into the following significant
         transactions with Atlas Resources and its affiliates as provided under
         the Partnership agreement:

                The partnership will enter into a drilling and operating
                agreement with Atlas Resources to drill and complete all of the
                Partnership wells at cost plus 15%. The cost of the wells
                includes reimbursement to Atlas Resources of the investor
                partners' share of its general and administrative overhead cost
                (approximately $12,722 per well, which will be proportionately
                reduced if the Partnership's working interest in a well is less
                than 100 %) and all ordinary and actual costs of drilling,
                testing and completing the wells.

                Atlas Resources will receive an unaccountable, fixed payment
                reimbursement for their administrative costs at $75 per well per
                month, which will be proportionately reduced if the
                partnership's working interest in a well is less than 100%.

                Atlas Resources will receive well supervision fees for operating
                and maintaining the wells during producing operations at a
                competitive rate (currently the competitive rate is $285 per
                well per month in the primary and secondary drilling areas). The
                well supervision fees will be proportionately reduced if the
                partnership's working interest in a well is less than 100%.






                                       F-6



                       Atlas America Public #14-2004 L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT - CONTINUED

                                  June 30, 2004

5.       TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES - CONT.

         Atlas Resources will charge the partnership a fee for gathering and
         transportation at a competitive rate (currently in the range of $.29 to
         $.70 per MCF in the primary and secondary drilling areas).

         Atlas Resources will contribute all the undeveloped leases necessary to
         cover each of the partnership's prospects and will receive a credit for
         its capital account in the partnership equal to the cost of the leases
         (approximately $5,232 per prospect which will be proportionately
         reduced if the Partnership's working interest is the prospect is less
         than 100%).

         As the Managing General Partner, Atlas Resources will perform all
         administrative and management functions for the partnership including
         billing and collecting revenues and paying expenses. Atlas Resources
         will be reimbursed for all direct costs expended on behalf of the
         partnership.

6.       PURCHASE COMMITMENT

         Subject to certain conditions, investor partners may present their
         interests beginning with the fifth calendar year after the partnership
         closes for purchase by the Managing General Partner. The Managing
         General Partner is not obligated to purchase more than 5% of the units
         in any calendar year. In the event that the Managing General Partner is
         unable to obtain the necessary funds, the Managing General Partner may
         suspend its purchase obligation.


7.       SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S
         NET REVENUE SHARE

         The Managing General Partner will subordinate up to 50% of its share of
         production revenues of the Partnership, net of related operating costs,
         direct costs, administrative costs and all other costs not specifically
         allocated to the receipt by the other partners of cash distributions
         from the Partnership equal to at least 10% per unit, based on $10,000
         per unit regardless of the actual price paid, determined on a
         cumulative basis, in each of the first five 12-month periods beginning
         with Partnership's first cash distributions from operations.

8.       INDEMNIFICATION

         In order to limit the potential liability of the investor general
         partners, Atlas Resources has agreed to indemnify each investor general
         partner from any liability incurred which exceeds such partner's share
         of Partnership net assets and insurance proceeds.







                                       F-7







REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS


Board of Directors
ATLAS RESOURCES, INC.

         We have audited the accompanying consolidated balance sheets of ATLAS
RESOURCES, INC. (a Pennsylvania corporation) and subsidiary as of September 30,
2003 and 2002, and the related consolidated statements of income, comprehensive
income, changes in stockholder's equity, and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

         In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of ATLAS
RESOURCES, INC. and subsidiary as of September 30, 2003 and 2002, and the
consolidated results of their operations and cash flows for the years then
ended, in conformity with accounting principles generally accepted in the United
States of America.

         As discussed in Note 2 to the consolidated financial statements,
effective October 1, 2002, the Company adopted Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations, and changed its
method of accounting for its plugging and abandonment liability related to its
oil and gas wells and associated pipelines and equipment.

         As discussed in Note 3 to the consolidated financial statements,
effective October 1, 2001, the Company changed its method of accounting for
goodwill for the adoption of Statement of Financial Accounting Standards No.
142, Goodwill and Other Intangible Assets.




/s/ Grant Thornton LLP



Cleveland, Ohio
December 5, 2003





                                       F-8


                                          ATLAS RESOURCES, INC. AND SUBSIDIARY
                                               CONSOLIDATED BALANCE SHEETS
                                               SEPTEMBER 30, 2003 AND 2002


                                                                                               2003            2002
                                                                                           -----------     --------
                                                                                           (in thousands, except share data)
ASSETS
Current assets:
   Cash and cash equivalents...........................................................     $    4,702       $      698
   Accounts receivable ................................................................          4,895            5,419
   Prepaid expenses....................................................................            532              320
                                                                                            ----------       ----------
     Total current assets..............................................................         10,129            6,437

Property and equipment:
    Oil and gas properties and equipment (successful efforts)..........................         85,199           59,757
    Buildings and land.................................................................          2,830            2,830
    Other..............................................................................            414              394
                                                                                            ----------       ----------
                                                                                                88,443           62,981

Less - accumulated depreciation, depletion, and amortization...........................        (16,388)         (10,995)
                                                                                            -----------      -----------
    Net property and equipment.........................................................         72,055           51,986

Goodwill...............................................................................         20,868           20,868
Intangible assets......................................................................          3,922            4,400
                                                                                           -----------     ------------
                                                                                            $  106,974      $    83,691
                                                                                            ==========      ===========

LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
   Current portion of long-term debt...................................................     $       56       $        -
   Accounts payable....................................................................          6,223            3,272
   Liabilities associated with drilling contracts......................................         22,157            4,948
   Accrued liabilities.................................................................            875              108
   Advances and note from parent.......................................................         51,150           51,054
                                                                                            ----------       ----------
        Total current liabilities......................................................         80,461           59,382

Asset retirement obligation............................................................            701                -
Long-term debt                                                                                     138                -
Commitments and contingencies..........................................................              -                -

Stockholder's equity:
   Common stock, stated at $10 per share;
     500 authorized shares; 200 shares issued and outstanding..........................              2                2
   Additional paid-in capital..........................................................         16,505           16,505
   Accumulated other comprehensive income (loss).......................................              -             (212)
   Retained earnings...................................................................          9,167            8,014
                                                                                            ----------       ----------
     Total stockholder's equity........................................................         25,674           24,309
                                                                                            ----------       ----------
                                                                                            $  106,974       $   83,691
                                                                                            ==========       ==========



           See accompanying notes to consolidated financial statements


                                       F-9



                                    ATLAS RESOURCES, INC. AND SUBSIDIARY
                                     CONSOLIDATED STATEMENTS OF INCOME
                                  YEARS ENDED SEPTEMBER 30, 2003 AND 2002



                                                                                   2003         2002
                                                                                -----------    --------
                                                                                       (in thousands)
REVENUES
Well Drilling................................................................    $   52,879     $   49,516
Gas and Oil Production.......................................................        16,091         10,056
Well Services................................................................         6,014          5,758
Other........................................................................           130            154
                                                                                 ----------     ----------
                                                                                     75,114         65,484

COSTS AND EXPENSES
Well Drilling................................................................        45,982         42,996
Gas and oil production and exploration.......................................         2,312          2,178
Well Services................................................................           923          1,108
Non-direct...................................................................        15,985         11,122
Depreciation, depletion and amortization.....................................         6,229          4,595
Interest.....................................................................         2,375          2,522
                                                                                 ----------     ----------
                                                                                     73,806         64,521
                                                                                 ----------     ----------

Income from operations before income taxes...................................         1,308            963
Provision for income taxes...................................................           275            135
                                                                                 ----------     ----------
Income before cumulative effect of accounting change.........................         1,033            828
Cumulative effect of change in accounting principle, net of income taxes of
   $65                                                                                  120             --
                                                                                 ----------     ----------


Net income...................................................................     $   1,153     $      828
                                                                                  =========     ==========

















           See accompanying notes to consolidated financial statements


                                      F-10




                                             ATLAS RESOURCES, INC. AND SUBSIDIARY
                                       CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                           YEARS ENDED SEPTEMBER 30, 2003 AND 2002


                                                                                                      2003           2002
                                                                                                   ----------     ----------
                                                                                                         (in thousands)
Net income...................................................................................      $    1,153     $      828
Other comprehensive income (loss):
Unrealized holding losses on natural gas futures arising during the period, net of taxes of              (541)          (264)
     $245 and $118...........................................................................
Less: reclassification adjustment for losses realized in net income, net of taxes of
     $355 and $17............................................................................             753             42
                                                                                                   ----------     ----------
                                                                                                          212           (222)
                                                                                                   ----------     -----------
Comprehensive income..........................................................................     $    1,365     $      606
                                                                                                   ==========     ==========












           See accompanying notes to consolidated financial statements




                                      F-11




                                                ATLAS RESOURCES, INC. AND SUBSIDIARY
                                     CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
                                               YEARS ENDED SEPTEMBER 30, 2003 AND 2002
                                                  (in thousands, except share data)


                                                                                           Accumulated
                                                     Common Stock          Additional         Other                        Totals
                                               ----------------------       Paid-In       Comprehensive    Retained    Stockholder's
                                                  Shares       Amount       Capital       Income (Loss)    Earnings        Equity
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2001..................        200       $    2    $      16,505      $      10       $   7,186   $    23,703
Net unrealized loss..........................          -            -                -           (222)              -          (222)
Net income...................................          -            -                -              -             828           828
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2002..................        200       $    2    $      16,505      $    (212)      $   8,014   $    24,309
Net unrealized gain..........................          -            -                -            212               -           212
Net income...................................          -            -                -              -           1,153         1,153
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2003..................        200       $    2    $      16,505      $       -       $   9,167   $    25,674
                                                 =======       ======    =============      =========       =========   ===========













           See accompanying notes to consolidated financial statements



                                      F-12



                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                     YEARS ENDED SEPTEMBER 30, 2003 AND 2002



                                                                                  2003           2002
                                                                              -----------     ----------
                                                                                     (in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.................................................................    $    1,153     $      828
Adjustments to reconcile net income to net cash provided by operating
   activities:
   Cumulative effect of change in accounting principle.....................          (120)             -
   Depreciation, depletion and amortization................................         6,229          4,595
   Management fees and interest on intercompany note due to parent.........        15,074         12,399
   Gain on sale of assets..................................................           (19)             -

Changes in operating assets and liabilities:
    Increase in accounts receivable and other current assets...............          (161)          (234)
    Increase (decrease) in accounts payable and other liabilities..........        17,798        (13,716)
                                                                                   ------        --------

Net cash provided by operating activities..................................        39,954          3,872

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures.......................................................       (21,106)       (14,757)
Proceeds from sale of assets...............................................            19              -
                                                                               ----------     ----------

Net cash used in investing activities......................................       (21,087)       (14,757)

CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings...........................................           (34)             -
Net (payments to) advances from Parent.....................................       (14,829)         6,225
                                                                               -----------    ----------

Net cash (used in) provided by financing activities........................       (14,863)         6,225
                                                                               -----------    ----------

Increase (decrease) in cash and cash equivalents...........................         4,004         (4,660)
Cash and cash equivalents at beginning of year.............................           698          5,358
                                                                               ----------     ----------
Cash and cash equivalents at end of year...................................    $    4,702     $      698
                                                                               ==========     ==========






           See accompanying notes to consolidated financial statements





                                      F-13


                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1 - NATURE OF OPERATIONS

         Atlas Resources, Inc. (the "Company"), a Pennsylvania corporation, and
its subsidiary, ARD Investments, are engaged in the exploration for development
and production of natural gas and oil primarily in the Appalachian Basin Area.
In addition, the Company performs contract drilling and well operation services.

         The Company is a second-tier wholly-owned subsidiary of Atlas America,
Inc. (Atlas). Atlas is a second-tier wholly-owned subsidiary of Resource
America, Inc. (RAI), a publicly traded company (trading under the symbol REXI on
the NASDAQ System) operating in the energy, real estate, and financial services
sectors. The Company's operations are dependent upon the resources and services
provided by Atlas. . The Company finances a substantial portion of its drilling
activities through drilling partnerships it sponsors and typically acts as the
managing general partner of these partnerships and has a material partnership
interest.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

RECLASSIFICATIONS

         Certain reclassifications have been made to the fiscal 2002
consolidated financial statements to conform to the fiscal 2003 presentation.

PRINCIPLES OF CONSOLIDATION

         The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiary. The Company also owns individual
interests in the assets, and is separately liable for its share of the
liabilities of energy partnerships, whose activities include only exploration
and production activities. In accordance with established practice in the oil
and gas industry, the Company includes its pro-rata share of assets,
liabilities, income and costs and expenses of the energy partnerships in which
the Company has an interest. All material intercompany transactions have been
eliminated.

USE OF ESTIMATES

         Preparation of the consolidated 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 consolidated financial statements and the
reported amounts of revenues and costs and expenses during the reporting period.
Actual results could differ from these estimates.

IMPAIRMENT OF LONG LIVED ASSETS

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






                                      F-14




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)

COMPREHENSIVE INCOME

         Comprehensive income (loss) includes net income and all other changes
in the equity of a business during a period from transactions and other events
and circumstances from non-owner sources. These changes, other than net income,
are referred to as "other comprehensive income" and for the Company only include
changes in the fair value, net of taxes, of unrealized hedging gains and losses.

PROPERTY AND EQUIPMENT

         Property and equipment consists of the following:



                                                                                           At September 30,
                                                                                    ----------------------------
                                                                                        2003           2002
                                                                                    -----------    -------------
                                                                                            (in thousands)
Mineral interest in properties:
    Proved properties........................................................       $         1    $           1
    Unproved properties......................................................                25               22
Wells and related equipment..................................................            84,435           59,484
Support equipment............................................................               738              250
Other........................................................................             3,244            3,224
                                                                                    -----------     ------------
                                                                                         88,443           62,981
Accumulated depreciation, depletion, amortization and valuation allowances:
    Oil and gas properties...................................................           (15,834)         (10,506)
    Other                                                                                  (554)            (489)
                                                                                    ------------    -------------
                                                                                        (16,388)         (10,995)
                                                                                    ------------    -------------
                                                                                    $    72,055     $     51,896
                                                                                    ===========     ============

OIL AND GAS PROPERTIES

         The Company follows the successful efforts method of accounting.
Accordingly, property acquisition costs, costs of successful exploratory wells,
all development costs, and the cost of support equipment and facilities are
capitalized. Costs of unsuccessful exploratory wells are expensed when such
wells are determined to be nonproductive or, if this determination cannot be
made, within twelve months of completion of drilling. The costs associated with
drilling and equipping wells not yet completed are capitalized as uncompleted
wells, equipment, and facilities. Geological and geophysical costs and the costs
of carrying and retaining undeveloped properties, including delay rentals, are
expensed as incurred. Production costs, overhead and all exploration costs other
than the costs of exploratory drilling are charged to expense as incurred.

         Oil and gas properties at September 30, 2003, include mineral rights
with a cost of $26,000 before accumulated depletion. In connection with a review
of RAI's financial statements by the staff of the Securities and Exchange
Commission, the Company has been made aware that an issue has arisen within the
industry regarding the application of provisions of Statement of Financial
Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets"
and SFAS No. 141, "Business Combinations," to companies in the extractive
industries, including gas and oil companies. The issue is whether SFAS No. 142
requires companies to reclassify costs associated with mineral rights, including
both proved and unproved leasehold acquisition costs, as intangible assets in
the balance sheet, apart from other capitalized gas and oil property costs.
Historically, the Company and other gas and oil companies have included the cost
of these gas and oil leasehold interests as part of gas and oil properties. Also
under consideration is whether SFAS No. 142 requires companies to provide the
additional disclosures prescribed by SFAS No. 142 for intangible assets for
costs associated with mineral rights.



                                      F-15


                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)

OIL AND GAS PROPERTIES - (CONTINUED)

         If it is ultimately determined that SFAS No. 142 requires the Company
to reclassify costs associated with mineral rights from property and equipment
to intangible assets, the amounts would be immaterial to the Company's financial
position. The reclassification of these amounts would not affect the method in
which such costs are amortized or the manner in which the Company assesses
impairment of capitalized costs. As a result, net income would not be affected
by the reclassification.

         The Company assesses unproved and proved properties periodically to
determine whether there has been a decline in value and, if a decline is
indicated, a loss is recognized. The assessment of significant unproved
properties for impairment is on a property-by-property basis. The Company
considers whether a dry hole has been drilled on a portion of, or in close
proximity to the property, the Company's intentions of further drilling, the
remaining lease term of the property, and its experience in similar fields in
close proximity. The Company assesses unproved properties whose costs are
individually insignificant in the aggregate. This assessment includes
considering the Company's experience with similar situations, the primary lease
terms, the average holding period of unproved properties and the relative
proportion of such properties on which proved reserves have been found in the
past.

         The Company compares the carrying value of its proved developed gas and
oil producing properties to the estimated future cash flow from such properties
in order to determine whether their carrying values should be reduced. No
adjustment was necessary during any of the fiscal years in the two year period
ended September 30, 2003.

         Upon the sale or retirement of a complete or partial unit of a proved
property, the cost and related accumulated depletion are eliminated from the
property accounts, and the resultant gain or loss is recognized in the statement
of operations. 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 statement 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.

         On an annual basis, the Company estimates the costs of future
dismantlement, restoration, reclamation, and abandonment of its gas and oil
producing properties. Additionally, the Company estimates the salvage value of
equipment recoverable upon abandonment. At September 30, 2002, the Company's
estimate of equipment salvage values was greater than or equal to the estimated
costs of future dismantlement, restoration, reclamation, and abandonment. On
October 1, 2002, the Company adopted SFAS No. 143 "Accounting for Asset
Retirement Obligations" ("SFAS 143") as discussed further in this footnote.

DEPRECIATION, DEPLETION AND AMORTIZATION

         The Company amortizes proved gas and oil properties, which include
intangible drilling and development costs, tangible well equipment and leasehold
costs, on the unit-of-production method using the ratio of current production to
the estimated aggregate proved developed gas and oil reserves.

         The Company computes depreciation on property and equipment, other than
gas and oil properties, using the straight-line method over the estimated
economic lives, which range from three to 39 years.




                                      F-16




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)

ASSET RETIREMENT OBLIGATIONS

         Effective October 1, 2002, the Company adopted SFAS 143 which requires
the Company to recognize an estimated liability for the plugging and abandonment
of its oil and gas wells and associated pipelines and equipment. Under SFAS 143,
the Company must currently recognize a liability for future asset retirement
obligations if a reasonable estimate of the fair value of that liability can be
made. The present values of the expected asset retirement costs are capitalized
as part of the carrying amount of the long-lived asset. SFAS 143 requires the
Company to consider estimated salvage value in the calculation of depletion,
depreciation and amortization. Consistent with industry practice, historically
the Company had determined the cost of plugging and abandonment on its oil and
gas properties would be offset by salvage values received. The adoption of SFAS
143 resulted in (i) an increase of total liabilities because retirement
obligations are required to be recognized, (ii) an increase in the recognized
cost of assets because the retirement costs are added to the carrying amount of
the long-lived assets and (iii) a decrease in depletion expense, because the
estimated salvage values are now considered in the depletion calculation.

         The estimated liability is based on historical experience in plugging
and abandoning wells, estimated remaining lives of those wells based on reserves
estimates, external estimates as to the cost to plug and abandon the wells in
the future, and federal and state regulatory requirements. The liability is
discounted using an assumed credit-adjusted risk-free interest rate. Revisions
to the liability could occur due to changes in estimates of plugging and
abandonment costs or remaining lives of the wells, or if federal or state
regulators enact new plugging and abandonment requirements.

         The adoption of SFAS 143 as of October 1, 2002 resulted in a cumulative
effect adjustment to record (i) a $558,000 increase in the carrying values of
proved properties, (ii) a $308,000 decrease in accumulated depletion and (iii) a
$681,000 increase in non-current plugging and abandonment liabilities. The pro
forma effect of the application of SFAS 143 was not material to the Company's
consolidated statements of operations.

         The Company has no assets legally restricted for purposes of settling
asset retirement obligations. Except for the item previously referenced, the
Company has determined that there are no other material retirement obligations
associated with tangible long-lived assets.

         A reconciliation of the Company's liability for well plugging and
abandonment costs for the year ended September 30, 2003 is as follows (in
thousands):

  Asset retirement obligations, September 30, 2002.............     $       -
  Adoption of SFAS 143.........................................           681
  Liabilities incurred.........................................            93
  Liabilities settled..........................................           (53)
  Revision in estimates........................................           (66)
  Accretion expense............................................            46
                                                                    ---------
  Asset retirement obligations, September 30, 2003.............     $     701
                                                                     ========

         The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of income and the asset
retirement obligation liabilities are classified as long-term liabilities in the
Company's consolidated balance sheet.



                                      F-17




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)

FAIR VALUE OF FINANCIAL INSTRUMENTS

         The Company used the following methods and assumptions in estimating
the fair value of each class of financial instruments for which it is
practicable to estimate fair value.

         For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments.

         For long-term debt, the carrying value approximates fair value because
interest rates approximate current market rates.

CONCENTRATION OF CREDIT RISK

         Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of periodic temporary
investments of cash. The Company places its temporary cash investments in
high-quality short-term money market instruments and deposits with high-quality
financial institutions and brokerage firms. At September 30, 2003, the Company
had $4.7 million in deposits at various banks, of which $4.5 million is over the
insurance limit of the Federal Deposit Insurance Corporation. No losses have
been experienced on such investments.

ENVIRONMENTAL MATTERS

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

         The Company 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 Company maintains
insurance that may cover in whole or in part certain environmental expenditures.
For the two years ended September 30, 2003, the Company had no environmental
matters requiring specific disclosure or requiring recording of a liability.

REVENUE RECOGNITION

         The Company conducts certain energy activities through, and a portion
of its revenues are attributable to, sponsored energy limited partnerships.
These energy partnerships raise capital from investors to drill gas and oil
wells. The Company serves as general partner of the energy partnerships and
assumes customary rights and obligations for them. As the general partner, the
Company is liable for partnership liabilities and can be liable to limited
partners if it breaches its responsibilities with respect to the operations of
the partnerships. The income from the Company's general partner interest is
recorded when the gas and oil are sold by a partnership.



                                      F-18




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)

REVENUE RECOGNITION - (CONTINUED)

         The Company contracts with the energy partnerships to drill partnership
wells. The contracts require that the energy partnerships must pay the Company
the full contract price upon execution. The income from a drilling contract is
recognized as the services are performed. The contracts are typically completed
in less than 60 days. The Company classifies the difference between the contract
payments it has received and the revenue earned as a current liability, included
in liabilities associated with drilling contracts.

         The Company recognizes transportation revenues at the time the natural
gas is delivered to the purchaser and includes them in well services revenues.

         The Company recognizes field services revenues at the time the services
are performed.

         The Company is entitled to receive management fees according to the
respective partnership agreements. The Company recognizes such fees as income
when earned and includes them in well services revenues.

         The Company sells interests in gas and oil wells and retains a working
interest and/or overriding royalty. The Company records the income from the
working interests and overriding royalties when the gas and oil are sold.

SUPPLEMENTAL CASH FLOW INFORMATION

         The Company considers temporary investments with maturity at the date
of acquisition of 90 days or less to be cash equivalents.

Supplemental disclosure of cash flow information:


                                                                                 Years Ended September 30,
                                                                                --------------------------
                                                                                    2003            2002
                                                                                -----------       --------
                                                                                       (in thousands)
CASH PAID DURING THE YEARS FOR:
Interest.....................................................................   $      110     $       114
Income taxes paid............................................................   $      363     $        -

NON-CASH ACTIVITIES INCLUDE THE FOLLOWING:
Fixed asset purchases financed with long-term debt                              $      228     $        -
Asset Retirement Obligation..................................................   $      754     $        -


INCOME TAXES

         The Company is included in the consolidated federal income tax return
of RAI. Income taxes are presented as if the Company had filed a return on a
separate company basis utilizing their calculated effective rate of 21% and 14%
for fiscal years 2003 and 2002 respectively. The Company's effective tax rate is
lower than the federal statutory rate due to the benefit of percentage depletion
and fuel credits. Deferred taxes, which are included in Advances from Parent,
reflect the tax effect of temporary differences between the tax basis of the
Company's assets and liabilities and the amounts reported in the financial
statements. Separate company state tax returns are filed in those states in
which the Company is registered to do business.





                                      F-19



                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)


 RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

         In July 2002, SFAS No. 146, ("SFAS 146") "Accounting for Costs
Associated with Exit or Disposal Activities" was issued. SFAS 146 is effective
for exit or disposal activities initiated after December 31, 2002. The adoption
of SFAS 146 did not have a material effect on the Company's financial position
or results of operations.

        In May 2003, the FASB issued SFAS No. 150 ("SFAS 150") "Accounting for
Certain Financial Instruments with Characteristics of Both Liabilities and
Equity." SFAS 150 requires that certain instruments that were previously
classified as equity on a Company's statement of financial position now be
classified as liabilities. SFAS 150 is effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. The
adoption of SFAS 150 did not have a material impact on the Company's results of
operations or financial position.

         In April 2003, the FASB issued SFAS No. 149 ("SFAS 149") "Amendment of
Statement 133 on Derivative Instruments and Hedging Activates." SFAS 149 is
effective for contracts entered into or modified after June 30, 2003 and amends
and clarifies financial accounting and reporting for derivative instruments. The
adoption of SFAS 149 did not have a material effect on the Company's financial
position or results of operations.

         In November 2002, the FASB issued Interpretation 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 clarifies the
requirements of FASB No. 5, "Accounting for Contingencies" ("SFAS 5") relating
to a guarantor's accounting for, and disclosure of, the issuance of certain
types of guarantees. FIN 45 provides for additional disclosure requirements
related to guarantees in financial statements for financial periods ending after
December 15, 2002. Additionally, FIN 45 outlines provisions for initial
recognition and measurement of the liability incurred upon the issuance of new
guarantees or the modification of existing guarantees subsequent to December 31,
2002. The adoption of the recognition and measurement requirements of FIN 45 on
January 1, 2003, did not have a significant impact on the results of operations
or financial position of the Company.

        In January 2003, the Financial Accounting Standards Board issued FASB
Interpretation No. 46 "Consolidation of Variable Interest Entities, an
Interpretation of ARB No. 51" ("FIN 46"). FIN 46 requires certain variable
interest entities to be consolidated by the primary beneficiary of the entity if
the equity investors in the entity do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. FIN 46 is effective for all new variable interest
entities created or acquired after January 31, 2003. The provisions of FIN 46
must be applied for the first interim or annual period beginning after June 15,
2003. The Company does not have any entities that require disclosure or new
consolidation as a result of adopting the provisions of FIN 46.


NOTE 3 - INTANGIBLE ASSETS AND GOODWILL

INTANGIBLE ASSETS

         Intangible assets consist of partnership management and operating
contracts acquired through acquisitions and recorded at fair value on their
acquisition dates. The Company amortizes contracts acquired on a declining
balance method, over their respective estimated lives, ranging from five to
thirteen years. Amortization expense for the years ended September 30, 2003 and
2002 was $478,000 and $414,000, respectively. The estimated amortization expense
for the next five fiscal years is $478,000



                                      F-20




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 3 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL - (CONTINUED)


         The following table provides information about intangible assets at the
dates indicated:


                                                                                    At September 30,
                                                                                ------------------------
                                                                                  2003           2002
                                                                                ----------    ----------
                                                                                      (in thousands)
Partnership management and operating contracts............................      $    6,353    $    6,353
Accumulated amortization..................................................          (2,431)       (1,953)
                                                                                ----------    ----------
Intangible assets, net....................................................      $    3,922    $    4,400
                                                                                ==========    ==========


GOODWILL

         On October 1, 2001, the Company early-adopted SFAS No. 142 ("SFAS 142")
"Goodwill and Other Intangible Assets," which requires that goodwill no longer
be amortized, but instead tested for impairment at least annually. At that time,
the Company had unamortized goodwill of $14.4 million. The transitional
impairment test required upon adoption of SFAS 142, which involved the use of
estimates related to the fair market value of the business operations associated
with the goodwill, did not indicate an impairment loss. The Company will
continue to evaluate its goodwill at least annually and will reflect the
impairment of goodwill, if any, in operating income in the statement of
operations in the period in which the impairment is indicated.

         Changes in the carrying amount of goodwill for the periods indicated
are as follows:


                                                                                Years Ended September 30,
                                                                                -------------------------
                                                                                   2003           2002
                                                                                -----------      -------
                                                                                        (in thousands)

Goodwill at beginning of period
    (less accumulated amortization of $2,320 and $1,609).....................   $    20,868       $   14,479
Syndication network reclassified from other assets
    in accordance with SFAS 142 (net of accumulated amortization
    of $711).................................................................             -            6,389
                                                                                -----------       ----------
Goodwill at end of period (net of accumulated amortization
    of $2,320 and $2,320)....................................................   $    20,868       $   20,868
                                                                                ===========       ==========


NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

         The Company conducts certain energy activities through, and a
substantial portion of its revenues are attributable to energy limited
partnerships ("Partnerships"). The Company serves as general partner of the
Partnerships and assumes customary rights and obligations for the Partnerships.
As the general partner, the Company is liable for Partnership liabilities and
can be liable to limited partners if it breaches its responsibilities with
respect to the operations of the Partnerships. The Company is entitled to
receive management fees, reimbursement for administrative costs incurred, and to
share in the Partnerships' revenue and costs and expenses according to the
respective Partnership agreements.






                                      F-21




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (CONTINUED)


         The advances from Parent represent amounts owed for advances and
transactions in the normal course of business and a note payable to the parent.
Other than the note, these advances have no repayment terms and are subordinated
to any third-party debt. The note, which is also subordinated to any third-party
debt, has a face amount of $15.0 million and accrues interest at an annual rate
of 9.50% on any unpaid balances. The principal and any unpaid interest are due
upon demand by the Parent. Interest expense related to the note, which is being
deferred, was $1.9 million for each of the years ended September 30, 2003 and
2002. The advances have no repayment terms and the note is due on demand.
Therefore the Company has classified the amounts due the Parent as a current
liability on its Consolidated Balance Sheets. The Parent does not intend to
demand payment on the advances or note within the next year.

         The Company is dependent on its' Parent for management and
administrative functions and financing for capital expenditures. The Company
pays a management fee to its Parent for management and administrative services,
which amounted to $13.1 million and $10.5 million for the years ended September
30, 2003 and 2002, respectively.


NOTE 5 - DEBT


                                                                                   At September 30,
                                                                             -------------------------
                                                                                 2003          2002
                                                                             ----------     ----------
                                                                                    (in thousands)
Long-term debt.......................................................        $      194     $        -
                                                                              ---------      ---------
                                                                                    194              -
Less current maturities..............................................                56              -
                                                                             ----------     ----------
                                                                             $      138     $        -
                                                                             ==========     ==========


         Annual debt principal payments over the next five fiscal years ending
September 30 are as follows: (in thousands):

                                     2004...............................     $       56
                                     2005...............................     $       56
                                     2006...............................     $       56
                                     2007...............................     $       26
                                     2008...............................     $        -


         During the current fiscal year ended September 30, 2003, the Company
entered into two loans through General Motors Acceptance Corporation to finance
the purchase of ten trucks used in its' well drilling and oil and gas production
activities. The first loan has a principal amount of $115,378 and bears an
annual interest rate of 2.9%. The second loan has a principal amount of $113,046
and bears an annual interest rate of 1.9%. Both loans have a 48 month repayment
term.











                                      F-22



                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 6 - COMMITMENTS AND CONTINGENCIES


         The Company leases office space and equipment under leases with varying
expiration dates through 2006. Rental expense was $359,000 and $376,000 for the
years ended September 30, 2003 and 2002, respectively. At September 30, 2003,
future minimum rental commitments for the next five fiscal years were as follows
(in thousands):

                            2004............................        $    213
                            2005............................             168
                            2006............................              17
                            2007............................               -
                            2008............................               -


         The Company is the managing general partner of various energy
partnerships, and has agreed to indemnify each investor partner from any
liability that exceeds such partner's share of partnership assets. Subject to
certain conditions, investor partners in certain energy partnerships have the
right to present their interests for purchase by the Company, as managing
general partner. The Company is not obligated to purchase more than 5% or 10% of
the units in any calendar year. Based on past experience, the Company believes
that any liability incurred would not be material.

         The Company may be required to subordinate a part of its net
partnership revenues to the receipt by investor partners of cash distributions
from the energy partnerships equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.

         The Company has access to a revolving credit facility from its parent.
In July 2002, the Company's parent entered into a $75.0 million credit facility
led by Wachovia Bank. The revolving credit facility has a current borrowing base
of $54.2 million which may be increased or decreased subject to growth in the
Parent's oil and gas reserves, including those of the Company. The facility
permits draws based on the remaining proved developed non-producing and proved
undeveloped natural gas and oil reserves attributable to the Parent's wells and
the projected fees and revenues from operation of the wells and the
administration of energy partnerships. Up to $10.0 million of the facility may
be in the form of standby letters of credit. The facility is secured by the
Parent's assets, including those of the Company. The revolving credit facility
has a term ending in July 2005 and bears interest at one of two rates (elected
at the borrower's option) which increase as the amount outstanding under the
facility increases: (i) Wachovia prime rate plus between 25 to 75 basis points,
or (ii) LIBOR plus between 175 and 225 basis points. The facility terminates in
July 2005, when all outstanding borrowings must be repaid. At September 30, 2003
and 2002, $32.3 million and $45.0 million, respectively, were outstanding under
this facility, including $1.3 million each year under letters of credit. The
interest rates ranged from 2.88% to 2.90% at September 30, 2003. The Company
owed no amounts due under this facility at September 30, 2003 and 2002.

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








                                      F-23


                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)



NOTE 7 - HEDGING ACTIVITIES

                  The Company from time to time enters into natural gas futures
and option contracts to hedge its 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.

         The Company formally documents all relationships between hedging
instruments and the items being hedged, including the Company'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. The Company 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.
Such gains and losses are charged or credited to accumulated other comprehensive
income (loss) and recognized as a component of sales revenue 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, the Company will discontinue hedge accounting
for the derivative and subsequent changes in fair value for the derivative will
be recognized immediately into earnings.

         At September 30, 2003, the Company had no open natural gas futures
contracts related to natural gas sales and accordingly, had no unrealized loss
or gain related to open NYMEX contracts at that date. Its net unrealized loss
was approximately $316,600 at September 30, 2002. The Company recognized a loss
of $1.1 million and $59,000 on settled contracts covering natural gas production
for the years ended September 30, 2003 and 2002, respectively. The Company
recognized no gains or losses during the two year period ended September 30,
2003 for hedge ineffectiveness or as a result of the discontinuance of cash flow
hedges.

         Although hedging provides the Company some protection against falling
prices, these activities could also reduce the potential benefits of price
increases, depending upon the instrument.


NOTE 8 - MAJOR CUSTOMERS


         The Company's natural gas is sold under contract to various purchasers.
For the years ended September 30, 2003 and 2002, gas sales to First Energy
Solutions Corporation accounted for 15% and 17%, respectively, of total
revenues.









                                      F-24



                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)



NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION

         Results of operations from oil and gas producing activities:


                                                                                 Years Ended September 30,
                                                                                --------------------------
                                                                                   2003          2002
                                                                                ----------      --------
                                                                                        (in thousands)
Revenues.....................................................................    $   16,091      $   10,056
Production costs.............................................................        (1,992)         (1,543)
Exploration expenses.........................................................          (320)           (635)
Depreciation, depletion and amortization.....................................        (5,605)         (3,949)
Income taxes.................................................................        (2,609)         (1,075)
                                                                                 ----------      ----------
Results of operations from oil and gas producing activities..................    $    5,565      $    2,854
                                                                                 ==========      ==========


         Capitalized Costs Related to Oil and Gas Producing Activities. The
components of capitalized costs related to the Company's oil and gas producing
activities are as follows:


                                                                                     At September 30,
                                                                                -----------------------
                                                                                   2003         2002
                                                                                ----------     --------
                                                                                       (in thousands)
Proved properties............................................................    $         1    $         1
Unproved properties..........................................................             25             22
Wells and related equipment and facilities...................................         84,435         59,484
Support equipment and facilities.............................................            738            250
                                                                                 -----------    -----------
                                                                                      85,199         59,757
Accumulated depreciation, depletion, amortization and
  valuation allowances.......................................................        (15,834)       (10,506)
                                                                                 -----------    -----------
     Net capitalized costs...................................................    $    69,365    $    49,251
                                                                                 ===========    ===========


         Costs Incurred in Oil and Gas Producing Activities. The costs incurred
by the Company in its oil and gas activities during fiscal years 2003 and 2002
are as follows:


                                                                                Years Ended September 30,
                                                                                -------------------------
                                                                                   2003           2002
                                                                                ----------      --------
                                                                                     (in thousands)
Property acquisition costs:
  Unproved properties........................................................    $        -      $        4
  Proved properties..........................................................    $        -      $        1
Exploration costs............................................................    $      320      $      635
Development costs............................................................    $   24,588      $   19,018


         The development costs above for the years ended September 30, 2003 and
2002 were substantially all incurred for the development of proved undeveloped
properties.






                                      F-25




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)

         Oil and Gas Reserve Information (Unaudited). The estimates of the
Company's proved and unproved gas reserves are based upon evaluations made by
management and verified by Wright & Company, Inc., an independent petroleum
engineering firm, as of September 30, 2003 and 2002. 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 provisions for price
and cost escalation except by contractual arrangements.

         Proved oil and gas reserves are 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.

         o    Reservoirs are considered proved if economic feasibility is
              supported by either actual production or conclusive formation
              tests. The area of a reservoir considered proved includes (a) that
              portion delineated by drilling and defined by gas-oil and/or
              oil-water contacts, if any; and (b) 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. In the absence of information on fluid contacts,
              the lowest known structural occurrence of hydrocarbons controls
              the lower proved limit of the reservoir.

         o    Reserves which can be produced economically through application of
              improved recovery techniques (such as fluid injection) are
              included in the "proved" classification when successful testing by
              a pilot project, or the operation of an installed program in the
              reservoir, provides support for the engineering analysis on which
              the project or program was based.

         o    Estimates of proved reserves do not include the following: (a) oil
              that may become available from known reservoirs but is classified
              separately as "indicated additional reservoirs"; (b) crude oil,
              natural gas, and natural gas liquids, the recovery of which is
              subject to reasonable doubt because of uncertainty as to geology,
              reservoir characteristics or economic factors; (c) crude oil,
              natural gas and natural gas liquids, that may occur in undrilled
              prospects; and (d) crude oil and natural gas, and natural gas
              liquids, that may be recovered from oil shales, coal, gilsonite
              and other such sources.

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

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






                                      F-26


                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)

         The Company's reconciliation of changes in proved reserve quantities is
as follows (unaudited):


                                                                                    Gas                    Oil
                                                                                   (Mcf)                  (Bbls)
                                                                                -----------             ---------
Balance September 30, 2001............................................           71,943,564               82,532
     Current additions................................................           17,855,966               43,089
     Transfers to limited partnerships................................           (7,396,491)             (65,692)
     Revisions........................................................           (5,321,048)              (1,876)
     Production.......................................................           (2,944,605)              (3,505)
                                                                                 ----------               -------
Balance September 30, 2002............................................           74,137,386               54,548
     Current additions................................................           21,663,845               29,394
     Transfers to limited partnerships................................           (8,688,298)             (31,386)
     Revisions........................................................               44,613               16,631
     Production.......................................................           (3,327,168)              (6,772)
                                                                                -----------              -------
Balance September 30, 2003............................................           83,830,378               62,415
                                                                                 ==========               ======

Proved developed reserves at:
     September 30, 2003...............................................           39,021,728               33,021
     September 30, 2002...............................................           36,250,709               23,162


         The following schedule presents the standardized measure of estimated
discounted future net cash flows relating to proved oil and gas reserves. The
estimated future production is priced at fiscal year-end prices, adjusted only
for fixed and determinable increases in natural gas and oil prices provided by
contractual agreements. The resulting estimated future cash inflows are reduced
by estimated future costs to develop and produce the proved reserves based on
fiscal year-end cost levels. The future net cash flows are reduced to present
value amounts by applying a 10% discount factor. The standardized measure of
future cash flows was prepared using the prevailing economic conditions existing
at September 30, 2003 and 2002 and such conditions continually change.
Accordingly such information should not serve as a basis in making any judgment
on the potential value of recoverable reserves or in estimating future results
of operations (unaudited).


                                                                             Years Ended September 30,
                                                                               2003              2002
                                                                           -----------        -----------
                                                                                    (in thousands)
Future cash inflows.....................................................   $   411,317        $   288,574
Future production costs.................................................       (82,517)           (63,697)
Future development costs................................................       (71,299)           (54,060)
Future income tax expense...............................................       (62,897)           (41,694)
                                                                           -----------        -----------

Future net cash flows...................................................       194,604            129,123
  Less 10% annual discount for estimated timing of cash flows...........      (116,896)           (80,521)
                                                                           -----------        -----------
  Standardized measure of discounted future net cash flows..............   $    77,708        $    48,602
                                                                           ===========        ===========


                  The future cash flows estimated to be spent to develop proved
undeveloped properties in the years ended September 30, 2004, 2005 and 2006 are
$27.4 million, $28.2 million and $15.6 million, respectively.






                                      F-27



                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)

         The following table summarizes the changes in the standardized measure
of discounted future net cash flows from estimated production of proved oil and
gas reserves after income taxes (unaudited):


                                                                              Years Ended September 30,
                                                                           -----------------------------
                                                                              2003               2002
                                                                           -----------       -----------
                                                                                   (in thousands)
Balance, beginning of year..............................................   $    48,602       $    53,240
Increase (decrease) in discounted future net cash flows:
  Sales and transfers of oil and gas, net of related costs..............       (14,099)           (8,513)
  Net changes in prices and production costs............................        20,455            (6,038)
  Revisions of previous quantity estimates..............................         3,678            (5,633)
  Development costs incurred............................................         3,689             3,555
  Changes in future development costs...................................          (158)             (149)
  Transfers to limited partnerships.....................................        (3,326)           (4,047)
  Extensions, discoveries, and improved recovery less
     related costs......................................................        24,574            11,049
  Accretion of discount.................................................        17,082             6,653
  Net changes in future income taxes....................................       (21,202)            1,107
  Other.................................................................        (1,587)           (2,622)
                                                                           -----------       -----------
Balance, end of year....................................................   $    77,708       $    48,602
                                                                           ===========       ===========












                                      F-28











                        CONSOLIDATED FINANCIAL STATEMENTS
                                   (UNAUDITED)

                      ATLAS RESOURCES, INC. AND SUBSIDIARY

                                  JUNE 30, 2004






























                                      F-29




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                           CONSOLIDATED BALANCE SHEETS
                        (in thousands, except share data)



                                                                                          JUNE 30,          SEPTEMBER 30,
                                                                                            2004                2003
                                                                                        ------------        -------------
                                                                                        (Unaudited)          (Audited)
ASSETS
Current assets:
   Cash and cash equivalents........................................................   $        822         $     4,702
   Accounts receivable..............................................................          6,113               4,895
   Other current assets.............................................................            787                 532
                                                                                       ------------         -----------
       Total current assets.........................................................          7,722              10,129

Property and equipment:
   Oil and gas properties and equipment (successful efforts)........................        101,695              85,199
   Buildings and land...............................................................          2,883               2,830
   Other............................................................................            366                 414
                                                                                       ------------         -----------
                                                                                            104,944              88,443

   Less - accumulated depreciation, depletion and amortization......................        (21,808)            (16,388)
   Net property and equipment.......................................................         83,136              72,055

Goodwill      ......................................................................         20,868              20,868
Operating and management contracts
   (less accumulated amortization of $2,789 and $2,431).............................          3,564               3,922
                                                                                       ------------         -----------
       Total assets.................................................................   $    115,290         $   106,974
                                                                                       ============         ===========

LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
   Current portion of long-term debt................................................   $         56          $       56
   Accounts payable and accrued liabilities.........................................          6,876               7,098
   Deferred revenue on drilling contracts...........................................         18,011              22,157
   Advances and note from Parent....................................................         62,906              51,150
                                                                                       ------------         -----------
       Total current liabilities....................................................         87,849              80,461


Long-term debt......................................................................             96                 138

Asset retirement obligation.........................................................            876                 701

Stockholder's equity:
   Common stock - stated value $10 per share;
     500 authorized shares; 200 shares issued and outstanding.......................              2                   2
   Additional paid-in capital.......................................................         16,505              16,505
   Retained earnings................................................................          9,962               9,167
                                                                                       ------------         -----------
         Total stockholder's equity.................................................         26,469              25,674
                                                                                       ------------         -----------
                                                                                       $    115,290         $   106,974
                                                                                       ============         ===========





           See accompanying notes to consolidated financial statements

                                      F-30



                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                        CONSOLIDATED STATEMENTS OF INCOME
                    NINE MONTHS ENDED JUNE 30, 2004 AND 2003
                                   (UNAUDITED)
                                 (in thousands)



                                                                                             2004               2003
                                                                                        ------------         -----------
REVENUES
Well drilling........................................................................   $     64,577             38,167
Gas and oil production...............................................................         16,704             11,705
Well services........................................................................          4,836              4,241
Other    ............................................................................            114                110
                                                                                        ------------        -----------
                                                                                              86,231             54,223
COSTS AND EXPENSES
Well drilling.........................................................................        56,154             33,188
Production and exploration............................................................         2,562              1,276
Well services.........................................................................         1,138                909
Non-direct............................................................................        17,538             12,749
Depreciation, depletion and amortization..............................................         5,952              3,639
Accretion of asset retirement obligation..............................................            37                 31
Interest .............................................................................         1,843              1,709
                                                                                        ------------        -----------
         Total costs and expenses.....................................................        85,224             53,501
                                                                                        ------------        -----------
Income from operations before income taxes............................................         1,007                722
Provision for income taxes............................................................           212                101
                                                                                        ------------        -----------
Net income............................................................................  $        795        $       621
                                                                                        ============        ===========









                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY
                         NINE MONTHS ENDED JUNE 30, 2004
                                   (UNAUDITED)
                        (in thousands, except share data)






                                                   Common stock          Additional                   Totals
                                            ----------------------------  Paid-In      Retained    Stockholder's
                                                Shares        Amount      Capital      Earnings       Equity
                                            ----------------------------------------------------------------------

Balance, October 1, 2003..................          200      $    2       $ 16,505    $  9,167      $  25,674
Net income................................                                                 795            795
                                                    ---      ------       --------    --------      ---------
Balance, June 30, 2004....................          200      $    2       $ 16,505    $  9,962      $  26,469
                                                    ===      ======       ========    ========      =========





           See accompanying notes to consolidated financial statements


                                      F-31




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                    NINE MONTHS ENDED JUNE 30, 2004 AND 2003
                                   (UNAUDITED)
                                 (in thousands)



                                                                                     2004           2003
                                                                                 -----------     -----------
Net income.................................................................        $   795        $    621

Unrealized holding losses arising during the period,

net of taxes of $364.......................................................              -            (761)

Reclassification adjustment for losses realized in net income,

net of taxes of $358.......................................................              -             726
                                                                                   --------       --------
Comprehensive income.......................................................        $    795       $    586
                                                                                   ========       ========




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                    NINE MONTHS ENDED JUNE 30, 2004 AND 2003
                                   (UNAUDITED)
                                 (in thousands)



                                                                                           2004                 2003
                                                                                        -----------         -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income..........................................................................    $       795         $       621
Adjustments to reconcile net income to net cash provided by operating activities:
   Depreciation, depletion and amortization.........................................          5,952               3,639
   Accretion of asset retirement obligation.........................................             37                  31
   Gain on asset sale...............................................................            (11)                (12)
   License fees and interest on intercompany note due to parent.....................         23,265               8,799

Change in operating assets and liabilities..........................................         (5,859)             10,875
                                                                                        -----------         -----------
Net cash provided by operating activities...........................................         24,179              23,953

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures................................................................        (16,442)            (14,086)
Proceeds-from asset sales...........................................................             33                  12
                                                                                        -----------         -----------
Net cash used in investing activities...............................................        (16,409)            (14,074)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings - long-term debt.........................................................              -                 228
Payments - long-term debt...........................................................            (42)                (20)
Payments to Parent and Affiliates...................................................        (11,608)             (1,729)
                                                                                        -----------         -----------
Net cash used in financing activities...............................................        (11,650)             (1,521)
                                                                                        -----------         -----------
(Decrease) increase in cash and cash equivalents....................................         (3,880)              8,358
Cash and cash equivalents at beginning of year......................................          4,702                 698
                                                                                        -----------         -----------
Cash and cash equivalents at end of year............................................    $       822         $     9,056
                                                                                        ===========         ===========








           See accompanying notes to consolidated financial statements


                                      F-32




                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  JUNE 30, 2004
                                   (Unaudited)

NOTE 1 - INTERIM FINANCIAL STATEMENTS

         The consolidated financial statements of Atlas Resources, Inc. and its
wholly-owned subsidiary (the "Company") as of June 30, 2004 and for the nine
months ended June 30, 2004 and 2003, are unaudited. These consolidated financial
statements have been prepared in accordance with accounting principles generally
accepted in the United States of America ("US GAAP") for interim financial
information and certain rules and regulations of the Securities and Exchange
Commission. Accordingly, they do not include all of the information and
footnotes required by US GAAP for complete financial statements.

         The preparation of financial statements in conformity with US GAAP
requires management to make estimates and assumptions that affect (i) the
reported amounts of assets and liabilities, (ii) disclosure of contingent assets
and liabilities as of the dates of the financial statements and (iii) the
reported amounts of revenues and expenses during the reporting periods. In the
opinion of management, all adjustments (consisting only of normal recurring
adjustments and certain cost allocations for expenses paid by either the Parent
or its' affiliates on behalf of the Company) considered necessary for a fair
presentation have been reflected in these consolidated financial statements.

         Operating results for the nine months ended June 30, 2004, are not
necessarily indicative of the results that may be expected for the year ending
September 30, 2004. Certain reclassifications have been made in the fiscal 2003
consolidated financial statements to conform to the fiscal 2004 presentation.
These financial statements should be read in conjunction with the Company's
audited September 30, 2003 consolidated financial statements.

NOTE 2 - CONSOLIDATED STATEMENTS OF CASH FLOWS

Supplemental disclosure of cash flow information:





                                                                                      Nine Months Ended
                                                                                           June 30,
                                                                                   -----------------------
                                                                                     2004           2003
                                                                                   -------         -------
                                                                                        (in thousands)
CASH PAID DURING THE YEARS FOR:
Interest.....................................................................       $     -        $   250
Income taxes (refunded) paid.................................................       $     -        $     -

NON-CASH ACTIVITIES INCLUDE THE FOLLOWING:
Asset Retirement Obligations incurred........................................       $   151        $     -





                                      F-33






                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
                                  JUNE 30, 2004
                                   (Unaudited)


NOTE 3 - ASSET RETIREMENT OBLIGATIONS

         The Company accounts for the estimated plugging and abandonment of its
oil and gas properties in accordance with Statement of Financial Accounting
Standards ("SFAS") No. 143, "Accounting for Asset Retirement obligations".

         A reconciliation of the Company's liability for well plugging and
abandonment costs for the nine months ended June 30, 2004 is as follows (in
thousands):

                                                                    2004
                                                                 ----------
  Asset retirement obligations, beginning of period...........   $     701
  Adoption of SFAS 143, effective October 1, 2002.............           -
  Liabilities incurred........................................         151
  Liabilities settled.........................................         (18)
  Revision in estimates.......................................           5
  Accretion expense...........................................          37
                                                                 ---------
  Asset retirement obligations, end of period.................   $     876
                                                                 =========



NOTE 4 - COMMITMENTS AND CONTINGENCIES

                  The Company is the managing general partner of various energy
partnerships, and has agreed to indemnify each investor partner from any
liability that exceeds such partner's share of partnership assets. Subject to
certain conditions, investor partners in certain energy partnerships have the
right to present their interests for purchase by the Company, as managing
general partner. The Company is not obligated to purchase more than 5% or 10% of
the units in any calendar year. Based on past experience, the Company believes
that any liability incurred would not be material.

         The Company may be required to subordinate a part of its net
partnership revenues to the receipt by investor partners of cash distributions
from the Partnership equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreement.

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









                                      F-34






                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
                                  JUNE 30, 2004
                                   (Unaudited)


NOTE 5 - DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

                  The Company from time to time enters into natural gas futures
and option contracts to hedge its 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.

         At June 30, 2004, the Company had no open natural gas futures contracts
related to natural gas sales and accordingly, had no unrealized loss or gain
related to open NYMEX contracts at that date. The Company's net unrealized loss
related to open NYMEX contracts was approximately $363,000 at June 30, 2003. The
Company did not settle any contracts during the nine months ended June 30, 2004.
The Company recognized losses of $1.1 million on settled contracts during the
nine months ended June 30, 2003. The Company recognized no gains or losses
during the nine months ended June 30, 2004 and 2003 for hedge ineffectiveness or
as a result of the discontinuance of cash flow hedges.

         Although hedging provides the Company some protection against falling
prices, these activities could also reduce the potential benefits of price
increases, depending upon the instrument.


NOTE 6- EFFECTIVE TAX RATE

         The Company is included in the consolidated federal income tax return
of RAI. Income taxes are presented as if the Company had filed a return on a
separate company basis utilizing their calculated effective rate of 21% and 14%
for the nine months ended June 30, 2004 and 2003 respectively. The Company's
effective tax rate is lower than the federal statutory rate due to the benefit
of percentage depletion and fuel credits. Deferred taxes, which are included in
Advances from Parent, reflect the tax effect of temporary differences between
the tax basis of the Company's assets and liabilities and the amounts reported
in the financial statements. Separate company state tax returns are filed in
those states in which the Company is registered to do business.












                                      F-35








                                   APPENDIX A

                              INFORMATION REGARDING
                          CURRENTLY PROPOSED PROSPECTS
                                       FOR
                       ATLAS AMERICA PUBLIC #14-2004 L.P.





               INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS

The partnerships do not currently hold any interests in any prospects on which
the wells will be drilled, and the managing general partner has absolute
discretion in determining which prospects will be acquired to be drilled.
However, set forth below is information relating to approximately 111 proposed
prospects and the wells which will be drilled on the prospects by Atlas America
Public #14-2004 L.P., which is the first partnership in the program and must be
closed by December 31, 2004. It is referred to in this section as the "2004
Partnership." One well will be drilled on each development prospect, and for
purposes of this section the well and prospect are referred to together as the
"well." Although the managing general partner does not anticipate that the wells
will be selected in the order in which they are set forth below, these wells are
currently proposed to be drilled by the 2004 Partnership when the subscription
proceeds are released from escrow and from time to time thereafter subject to
the managing general partner's right to:

     o        withdraw the wells and to substitute other wells;

     o        take a lesser working interest in the wells;

     o        add other wells; or

     o        any combination of the foregoing.


The specified wells represent the necessary wells if approximately $18,750,000
is raised and the 2004 Partnership takes the working interest in the wells which
is set forth below in the "Lease Information" for each well. The managing
general partner has not proposed any other wells if:


     o        a greater amount of subscription proceeds is raised;

     o        a lesser working interest in the wells is acquired; or

     o        the wells are substituted for any of the reasons set forth below.

The managing general partner has not authorized any person to make any
representations to you concerning the possible inclusion of any other wells
which will be drilled by the 2004 Partnership or any of the other partnerships,
and you should rely only on the information in this prospectus. The currently
proposed wells will be assigned unless there are circumstances which, in the
managing general partner's opinion, lessen the relative suitability of the
wells. These considerations include:

     o        the amount of the subscription proceeds received in the 2004
              Partnership;

     o        the latest geological and production data available;

     o        potential title or spacing problems;

     o        availability and price of drilling services, tubular goods and
              services;

     o        approvals by federal and state departments or agencies;

     o        agreements with other working interest owners in the wells;

     o        farmins; and

     o        continuing review of other properties which may be available.

Any substituted and/or additional wells will meet the same general criteria for
potential as the currently proposed wells and will generally be located in areas
where the managing general partner or its affiliates have previously conducted
drilling operations. You, however, will not have the opportunity to evaluate for
yourself the relevant production and geological information for the substituted
and/or additional wells.

                                       1


The purpose of the information regarding the currently proposed wells is to help
you evaluate the economic potential and risks of drilling the proposed wells.
This includes production information for wells in the general area of the
proposed well which the managing general partner believes is an important
indicator in evaluating the economic potential of any well to be drilled.
However, a well drilled by the 2004 Partnership may not experience production
comparable to the production experienced by wells in the surrounding area since
the geological conditions in these areas can change in a short distance. Also,
the managing general partner has not been able to obtain production information
for previously drilled wells in the immediate areas where a portion of the
currently proposed wells in Pennsylvania are situated because the information is
not available to the managing general partner as discussed in "Risk Factors -
Risks Related to an Investment In a Partnership - Lack of Production Information
Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a
Partnership's Drilling Program." These wells, for which no production data for
other wells in the immediate area are available to the managing general partner,
have been proposed by the managing general partner to be drilled because
geologic trends in the immediate area, such as sand thickness, porosities and
water saturations, lead the managing general partner to believe that the
proposed wells also will be productive.

When reviewing production information for each well offsetting or in the general
area of a proposed well to be drilled you should consider the factors set forth
below.

     o        The length of time that the well has been on-line, and the period
              for which production information is shown. Generally, the shorter
              the period for which production information is shown the less
              reliable the production information.

     o        Production from a well declines throughout the life of the well.
              The rate of decline, the "decline curve," varies based on which
              geological formation is producing, and may be affected by the
              operation of the well. For example, the wells in the
              Clinton/Medina geological formation will have a different decline
              curve from the wells in the Mississippian/Upper Devonian Sandstone
              Reservoir in Fayette and Green Counties. Also, each well in the
              Clinton/Medina geological formation or the Mississippian/Upper
              Devonian Sandstone Reservoirs will have a different rate of
              decline from the other wells in the same formation or reservoirs.

     o        The greatest volume of production ("flush production") from a well
              usually occurs in the early period of well operations and may
              indicate a greater reserve volume than the well actually will
              produce. This period of flush production can vary depending on how
              the well is operated and the location of the well.

     o        The production information for some wells is incomplete or very
              limited. The designation "N/A" means:

              o       the production information was not available to the
                      managing general partner for the reasons discussed in
                      "Risk Factors - Risks Related to an Investment In a
                      Partnership - Lack of Production Information Increases
                      Your Risk and Decreases Your Ability to Evaluate the
                      Feasibility of a Partnership's Drilling Program"; or

              o       if the managing general partner was the operator, then
                      when the information was prepared the well was:

                      o     not completed;

                      o     not on-line to sell production; or

                      o     producing for only a short period of time.

     o        Production information for wells located close to a proposed well
              tends to be more relevant than production information for wells
              located farther away, although performance and volume of
              production from wells located on contiguous prospects can be much
              different.

     o        Consistency in production among wells tends to confirm the
              reliability and predictability of the production.

                                       2


     o        A map of western Pennsylvania and eastern Ohio showing their
              counties....................................................   4

     o        Fayette County, Pennsylvania (Mississippian/Upper Devonian
              Sandstone Reservoirs)

              o        Lease information for Fayette and Greene Counties,
                       Pennsylvania.......................................   6

              o        Location and Production Maps for Fayette and Greene
                       Counties, Pennsylvania showing the proposed wells
                       and the wells in the area..........................  10

              o        Production data for Fayette and Greene Counties,
                       Pennsylvania.......................................  17

              o        United Energy Development Consultants, Inc.'s
                       geologic evaluation for the currently proposed wells
                       in Fayette and Greene Counties, Pennsylvania.......  37

     o        Western Pennsylvania (Clinton/Medina Geological Formation)

              o        Lease information for western Pennsylvania and
                       eastern Ohio.......................................  43

               o       Location and Production Maps for western
                       Pennsylvania and eastern Ohio showing the proposed
                       wells and the wells in the area....................  45

               o       Production data for western Pennsylvania and
                       eastern Ohio.......................................  49

              o        United Energy Development Consultants, Inc.'s
                       geologic evaluation for the currently proposed wells
                       in western Pennsylvania and eastern Ohio...........  51

     o        Armstrong County, Pennsylvania (Upper Devonian Sandstone
              Reservoirs)

              o        Lease information for Armstrong and Indiana
                       Counties, Pennsylvania.............................  57

               o       Location and Production Map for Armstrong and
                       Indiana Counties, Pennsylvania showing the proposed
                       wells and the wells in the area....................  59

               o       Production data for Armstrong and Indiana Counties,
                       Pennsylvania.......................................  61

               o       United Energy Development Consultants, Inc.'s
                       geologic evaluation for the currently proposed wells
                       in Armstrong and Indiana Counties, Pennsylvania....  65

     o        McKean County, Pennsylvania (Upper Devonian Sandstone
              Reservoirs)

              o        Lease information for McKean County, Pennsylvania..  71

               o       Location and Production Maps for McKean County,
                       Pennsylvania showing the proposed wells and the
                       wells in the area..................................  73

              o        Production data for McKean County, Pennsylvania....  77

               o       United Energy Development Consultants, Inc.'s
                       geologic evaluation for the currently proposed wells
                       in McKean County, Pennsylvania.....................  81

                                       3



                           MAP OF WESTERN PENNSYLVANIA

                                       AND

                                  EASTERN OHIO

















                                       4




                       [GRAPHIC OMITTED][GRAPHIC OMITTED]



























                                       5







                                LEASE INFORMATION

                                       FOR

                    FAYETTE AND GREENE COUNTIES, PENNSYLVANIA
















                                       6









                                                   EFFECTIVE     EXPIRATION    LANDOWNER
     PROSPECT NAME                      COUNTY       DATE*          DATE*       ROYALTY
     -------------                      ------       -----          -----       -------
  1  Allison/Hogsett #2                Fayette     7/31/1998         HBP         12.5%
  2  Allison/Hogsett #10               Fayette     7/31/1998         HBP         12.5%
  3  Baily #3                          Fayette     8/22/2002      8/22/2005      12.5%
  4  Barbabella #2                     Fayette     12/1/2003      6/1/2005       12.5%
  5  Behanna #1                        Fayette     1/14/2002      1/14/2005      12.5%
  6  Bertovich #5                      Fayette      2/4/2004      2/4/2006       12.5%
  7  Bezjak #3                         Fayette      6/7/2003      6/7/2006       12.5%
  8  Bezjak #6                         Fayette      6/7/2003      6/7/2006       12.5%
  9  Bolas #1                          Fayette     8/31/2001      8/31/2006      12.5%
 10  Boni/USX #2                       Fayette     10/5/2000         HBP         12.5%
 11  BSC/Ray #1                        Fayette     1/30/2001      1/30/2011      12.5%
 12  Canestrale #6                     Fayette     4/16/2002         HBP         12.5%
 13  Canestrale #18                    Fayette     4/16/2002      4/16/2005      12.5%
 14  Canestrale #20                    Fayette     4/16/2002      4/16/2005      12.5%
 15  Canistra/Graham #7                Fayette      2/9/1933         HBP         12.5%
 16  Carson #5                         Fayette     11/9/2001      11/9/2004      12.5%
 17  Celaschi #2                       Fayette      4/3/2002      4/3/2007       12.5%
 18  Christofel #2                     Fayette     3/19/2003      3/19/2005      12.5%
 19  Chubboy #8                        Fayette      5/7/2001      5/7/2006       12.5%
 20  Darr #7                            Greene     5/13/2002      5/12/2007      12.5%
 21  Dorazio #2                        Fayette      6/2/2003      6/2/2005       12.5%
 22  Dorazio #5                        Fayette     5/21/2003      5/21/2005      12.5%
 23  Dunay #2                          Fayette     4/22/1935         HBP         12.5%
 24  Erdely #1                         Fayette     11/21/2001    11/21/2004      12.5%
 25  Farquhar #1                       Fayette     11/30/2000    11/30/2010      12.5%
 26  Farquhar #6                       Fayette      6/8/2001         HBP         12.5%
 27  Gabeletto #2                      Fayette     7/31/2003      7/31/2008      12.5%
 28  Gabonay/National City #6          Fayette     2/19/2003         HBP         12.5%






                                                     OVERRIDING
                                                       ROYALTY
                                                      INTEREST    OVERRIDING
                                                       TO THE       ROYALTY                                  ACRES TO BE
                                                      MANAGING     INTEREST      NET                         ASSIGNED TO
                                                      GENERAL       TO 3RD     REVENUE   WORKING     NET         THE
     PROSPECT NAME                      COUNTY        PARTNER      PARTIES     INTEREST  INTEREST   ACRES    PARTNERSHIP
     -------------                      ------        -------      -------     --------  --------   -----    -----------
  1  Allison/Hogsett #2                Fayette           0%           0%        87.5%      100%      400          20
  2  Allison/Hogsett #10               Fayette           0%           0%        87.5%      100%      400          20
  3  Baily #3                          Fayette           0%           0%        87.5%      100%      168          20
  4  Barbabella #2                     Fayette           0%           0%        87.5%      100%       12          12
  5  Behanna #1                        Fayette           0%           0%        87.5%      100%       88          20
  6  Bertovich #5                      Fayette           0%           0%        87.5%      100%      109          20
  7  Bezjak #3                         Fayette           0%           0%        87.5%      100%       63          20
  8  Bezjak #6                         Fayette           0%           0%        87.5%      100%      189          20
  9  Bolas #1                          Fayette           0%           0%        87.5%      100%      112          20
 10  Boni/USX #2                       Fayette           0%           0%        87.5%      100%      2109         20
 11  BSC/Ray #1                        Fayette           0%           0%        87.5%      100%       76          20
 12  Canestrale #6                     Fayette           0%           0%        87.5%      100%      245          20
 13  Canestrale #18                    Fayette           0%           0%        87.5%      100%      554          20
 14  Canestrale #20                    Fayette           0%           0%        87.5%      100%       87          20
 15  Canistra/Graham #7                Fayette           0%           0%        87.5%      100%      162          20
 16  Carson #5                         Fayette           0%           0%        87.5%      100%       83          20
 17  Celaschi #2                       Fayette           0%           0%        87.5%      100%      108          20
 18  Christofel #2                     Fayette           0%           0%        87.5%      100%       35          20
 19  Chubboy #8                        Fayette           0%           0%        87.5%      100%      149          20
 20  Darr #7                            Greene           0%           0%        87.5%      100%       20          20
 21  Dorazio #2                        Fayette           0%           0%        87.5%      100%       73          20
 22  Dorazio #5                        Fayette           0%           0%        87.5%      100%       97          20
 23  Dunay #2                          Fayette           0%           0%        87.5%      100%       90          20
 24  Erdely #1                         Fayette           0%           0%        87.5%      100%       57          20
 25  Farquhar #1                       Fayette           0%           0%        87.5%      100%       83          20
 26  Farquhar #6                       Fayette           0%           0%        87.5%      100%       74          20
 27  Gabeletto #2                      Fayette           0%           0%        87.5%      100%       50          20
 28  Gabonay/National City #6          Fayette           0%           0%        87.5%      100%      300          20



                                       7















                                                   EFFECTIVE     EXPIRATION    LANDOWNER
     PROSPECT NAME                      COUNTY       DATE*          DATE*       ROYALTY
     -------------                      ------       -----          -----       -------
 29  Gross #10                         Fayette      6/9/2003      6/9/2006       12.5%
 30  Hatalowich #3                     Fayette     12/18/2001    12/18/2005      12.5%
 31  Hela #3                           Fayette     6/26/2003         HBP         12.5%
 32  Herring #6                        Fayette      1/9/2002      1/9/2005       12.5%
 33  Herring #7                        Fayette      1/9/2002      1/9/2005       12.5%
 34  Jackson Farms #23                 Fayette     10/14/1998        HBP         12.5%
 35  Kasievich #1                      Fayette      7/3/2003      7/3/2006       12.5%
 36  Kontaxes #1                       Fayette     11/21/2001    11/21/2004      12.5%
 37  Langley #5                        Fayette     6/21/2001         HBP         12.5%
 38  Lee #5                            Fayette     10/18/2003    10/18/2005      12.5%
 39  Lee #8                            Fayette     10/18/2003    10/18/2005      12.5%
 40  Leichliter #5                     Fayette     12/5/2000      12/5/2006      12.5%
 41  Liptak #3                         Fayette     10/16/2002    10/16/2007      12.5%
 42  Lubic #2                          Fayette     3/31/2003      3/31/2005      12.5%
 43  Lubic #4                          Fayette     3/31/2003      3/31/2006      12.5%
 44  Masontown Fish & Game Club #1     Fayette     10/16/2001    10/16/2004      12.5%
 45  National Mines #16                Fayette      5/8/1906         HBP         12.5%
 46  Novak-Melenyzer #3                Fayette      9/6/2001         HBP         12.5%
 47  Novobilsky #1                     Fayette     11/1/2002      11/1/2007      12.5%
 48  Patterson #10                     Fayette     7/17/2001      7/17/2006      12.5%
 49  Patterson/Hogsett #1              Fayette     7/31/1998         HBP         12.5%
 50  Peton/Hogsett #1                  Fayette     7/31/1998         HBP         12.5%
 51  Radishek #1                       Fayette     4/14/2003      4/14/2006      12.5%
 52  Randolph #2                       Fayette     2/27/2003      2/27/2006      12.5%
 53  Redman #3                         Fayette     6/16/2004      6/16/2006      12.5%
 54  Rowes Run/USX #1                  Fayette     10/5/2000         HBP         12.5%
 55  Rowes Run/USX #3                  Fayette     10/5/2000         HBP         12.5%







                                                     OVERRIDING
                                                       ROYALTY
                                                      INTEREST    OVERRIDING
                                                       TO THE       ROYALTY                                  ACRES TO BE
                                                      MANAGING     INTEREST      NET                         ASSIGNED TO
                                                      GENERAL       TO 3RD     REVENUE   WORKING     NET         THE
     PROSPECT NAME                      COUNTY        PARTNER      PARTIES     INTEREST  INTEREST   ACRES    PARTNERSHIP
     -------------                      ------        -------      -------     --------  --------   -----    -----------
 29  Gross #10                         Fayette           0%           0%        87.5%      100%       82          20
 30  Hatalowich #3                     Fayette           0%           0%        87.5%      100%      124          20
 31  Hela #3                           Fayette           0%           0%        87.5%      100%       48          20
 32  Herring #6                        Fayette           0%           0%        87.5%      100%      107          20
 33  Herring #7                        Fayette           0%           0%        87.5%      100%      107          20
 34  Jackson Farms #23                 Fayette           0%           0%        87.5%      100%       80          20
 35  Kasievich #1                      Fayette           0%           0%        87.5%      100%      113          20
 36  Kontaxes #1                       Fayette           0%           0%        87.5%      100%       32          20
 37  Langley #5                        Fayette           0%           0%        87.5%      100%      215          20
 38  Lee #5                            Fayette           0%           0%        87.5%      100%      118          20
 39  Lee #8                            Fayette           0%           0%        87.5%      100%      118          20
 40  Leichliter #5                     Fayette           0%           0%        87.5%      100%      111          20
 41  Liptak #3                         Fayette           0%           0%        87.5%      100%      154          20
 42  Lubic #2                          Fayette           0%           0%        87.5%      100%       87          20
 43  Lubic #4                          Fayette           0%           0%        87.5%      100%       35          20
 44  Masontown Fish & Game Club #1     Fayette           0%           0%        87.5%      100%       46          20
 45  National Mines #16                Fayette           0%           0%        87.5%      100%      453          20
 46  Novak-Melenyzer #3                Fayette           0%           0%        87.5%      100%       86          20
 47  Novobilsky #1                     Fayette           0%           0%        87.5%      100%       48          20
 48  Patterson #10                     Fayette           0%           0%        87.5%      100%       11          11
 49  Patterson/Hogsett #1              Fayette           0%           0%        87.5%      100%      270          20
 50  Peton/Hogsett #1                  Fayette           0%           0%        87.5%      100%      270          20
 51  Radishek #1                       Fayette           0%           0%        87.5%      100%       88          20
 52  Randolph #2                       Fayette           0%           0%        87.5%      100%       24          20
 53  Redman #3                         Fayette           0%           0%        87.5%      100%       90          20
 54  Rowes Run/USX #1                  Fayette           0%           0%        87.5%      100%      2109         20
 55  Rowes Run/USX #3                  Fayette           0%           0%        87.5%      100%      2109         20















                                                   EFFECTIVE     EXPIRATION    LANDOWNER
     PROSPECT NAME                      COUNTY       DATE*          DATE*       ROYALTY
     -------------                      ------       -----          -----       -------
 56  S.A.G.P. #4                       Fayette      6/4/2003      6/4/2008       12.5%
 57  Schuerle #2                       Fayette     6/14/1900         HBP         12.5%
 58  Sellman #2                        Fayette     7/31/2002      7/31/2005      12.5%
 59  Sepic/ACS #1                      Fayette     7/26/1933         HBP         12.5%
 60  Smetanka #2                       Fayette     4/21/2003      4/21/2005      12.5%
 61  Springer #4                       Fayette     11/29/2000    11/29/2010      12.5%
 62  Star Junction #13                 Fayette     10/5/2000         HBP         12.5%
 63  Teslovich #6                      Fayette     1/16/2003      1/16/2005      12.5%
 64  Teslovich #11                     Fayette     1/16/2003      1/16/2005      12.5%
 65  Throckmorton #1                    Greene     5/20/2002      5/19/2007      12.5%
 66  Throckmorton #4                    Greene     5/20/2002      5/19/2007      12.5%
 67  USX #11                           Fayette     7/24/2003      7/24/2005      12.5%
 68  Wilkinson #4                      Fayette     10/16/2002        HBP         12.5%
 69  Yocum/Newcomer #5                 Fayette     1/28/2002      1/28/2007      12.5%
 70  Yocum/Newcomer #7                 Fayette     1/28/2002      1/28/2007      12.5%

*HBP - Held by Production.








                                                     OVERRIDING
                                                       ROYALTY
                                                      INTEREST    OVERRIDING
                                                       TO THE       ROYALTY                                  ACRES TO BE
                                                      MANAGING     INTEREST      NET                         ASSIGNED TO
                                                      GENERAL       TO 3RD     REVENUE   WORKING     NET         THE
     PROSPECT NAME                      COUNTY        PARTNER      PARTIES     INTEREST  INTEREST   ACRES    PARTNERSHIP
     -------------                      ------        -------      -------     --------  --------   -----    -----------
 56  S.A.G.P. #4                       Fayette           0%           0%        87.5%      100%      112          20
 57  Schuerle #2                       Fayette           0%           0%        87.5%      100%       64          20
 58  Sellman #2                        Fayette           0%           0%        87.5%      100%      104          20
 59  Sepic/ACS #1                      Fayette           0%           0%        87.5%      100%      168          20
 60  Smetanka #2                       Fayette           0%           0%        87.5%      100%       32          20
 61  Springer #4                       Fayette           0%           0%        87.5%      100%       56          20
 62  Star Junction #13                 Fayette           0%           0%        87.5%      100%      2109         20
 63  Teslovich #6                      Fayette           0%           0%        87.5%      100%      164          20
 64  Teslovich #11                     Fayette           0%           0%        87.5%      100%      164          20
 65  Throckmorton #1                    Greene           0%           0%        87.5%      100%       80          20
 66  Throckmorton #4                    Greene           0%           0%        87.5%      100%       80          20
 67  USX #11                           Fayette           0%           0%        87.5%      100%      310          20
 68  Wilkinson #4                      Fayette           0%           0%        87.5%      100%      198          20
 69  Yocum/Newcomer #5                 Fayette           0%           0%        87.5%      100%      152          20
 70  Yocum/Newcomer #7                 Fayette           0%           0%        87.5%      100%      152          20

*HBP - Held by Production.





                                       9












                        LOCATION AND PRODUCTION MAPS FOR

                    FAYETTE AND GREENE COUNTIES, PENNSYLVANIA









                                       10



                            [GRAPHIC OF MAP OMITTED]









                                       11



                            [GRAPHIC OF MAP OMITTED]









                                       12



                            [GRAPHIC OF MAP OMITTED]






                                       13





                            [GRAPHIC OF MAP OMITTED]





                                       14



                            [GRAPHIC OF MAP OMITTED]



                                       15





                            [GRAPHIC OF MAP OMITTED]








                                       16






                                 PRODUCTION DATA

                                       FOR

                    FAYETTE AND GREENE COUNTIES, PENNSYLVANIA



                                       17




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.




                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
     7       Greensboro Gas Co.      David Gans #1                     1918         N/A        N/A             2957          N/A
   00019     Greensboro Gas Co.      J.V.Thompson                   10/17/1945      N/A        N/A             3044          N/A
    20       Manufacturers Light
               & Heat Co.            J.V. Thompson #4               1/27/1913       N/A        N/A             3086          N/A
   00021     Manufacturers
               Light & Heat Co.      Thompson #1                    1/28/1930       N/A        N/A             3108          N/A
   00022     Manufacturers
               Light & Heat Co.      Republic Colleries #2             N/A          N/A        N/A             1313          N/A
    34       Greensboro Gas Co.      J.V.Thompson #3                 2/1/1911       N/A        N/A             2900          N/A
    59       Fayette County Gas Co.  Jeffries #1                    10/1/1901       N/A        N/A             1408          N/A
    68       Greensboro Gas Co.      McMullen                          N/A          N/A        N/A             2782          N/A
   00086     Greensboro Gas Co.      Hibbs #1                       11/2/1912       N/A        N/A             3022          N/A
   00108     Robert E. Eberly        Ford #1                        4/16/1942       N/A        N/A             3257          N/A
    109      Robert E. Eberly        Combs #2                       12/19/1939      N/A        N/A             1259          N/A
   00120     Peoples Natural
               Gas Co.               Emery Dziak #                  4/13/1945       N/A        N/A             3489          N/A
   00143     Atlas                   Springer #1                     4/4/1901       N/A   181,000/1990         1333          N/A
   00155     Atlas                   Dunay #1                          N/A          N/A   324,000/1990          N/A          150
   00157     Atlas                   Lunnen, M. #1                     N/A          N/A   772,000/1990          N/A          373
   00162     Atlas                   Graham, W. #1                     N/A          N/A   148,000/1990          N/A           0
   00163     Atlas                   Bennington #1                     N/A          N/A   285,000/1990          N/A           0
   00177     Atlas                   Ruane Farms #1                    N/A          N/A    99,000/1990          N/A           21
   00179     Atlas                   Whitko, J. #1                     N/A          N/A   858,000/1990          N/A          N/A
   00180     Atlas                   Dantonio #1                       N/A          N/A   181,000/1990          N/A          N/A
   00181     Atlas                   O'Donnell, W. #2                  N/A          N/A   136,000/1990          N/A           1
   00182     Atlas                   Holzapeel #1                      N/A          N/A   540,000/1990          N/A           1
   00187     Atlas                   National Mines #1                 N/A          N/A   694,000/1990          N/A         1,125
   00190     Columbia Gas
               Transmission Corp     E.Areford #1                   11/18/1897      N/A   507,000/1990         2147          N/A
    196      Eugene J. Brumage       Talbert #47                       N/A          N/A        N/A              N/A          N/A
    211      W. Burkland             Linn Coal #1                      1942         N/A        N/A              N/A          N/A



                                       18




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
    216      W. Burkland             Johnson #2                        1939         N/A        N/A              660          N/A
    217      W. Burkland             Johnson #3                        1939         N/A        N/A              N/A          N/A
    226      W.Burkland              Pepson #1                      4/23/1905       N/A        N/A             1200          N/A
    245      Duquesne Gas Co.        Humphrey #1                    3/28/1931       N/A        N/A             5306          N/A
    249      Fortress Energy         Barber #1                      2/11/1944       N/A   132,907/1984         3802          N/A
    259      Chalfant, A.            Chalfant #1                       N/A          N/A        N/A              N/A          N/A
   20003     Petroleum Drilling
               Corp.                 W.C. Wells #1                  7/20/1958       N/A        N/A             3226          N/A
   20013     William E. Snee &
               Orville Eberly        Szabo #1                       8/20/1960       N/A        N/A             2640          N/A
   20054     M.C.Brumage             S.Gorley #1                    10/15/1943      N/A        N/A             2993          N/A
   20093     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
   20097     Manufacturers Light
               & Heat Co.            Wm. B. Graham #3                  N/A          N/A        N/A             1521          N/A
   20101     Peoples Natural
               Gas Co.               Martin #1                      1/29/1942       N/A   176,000/1970         3008          N/A
   20107     Greensboro Gas Co.      David Gans                        1899         N/A        N/A             1265          N/A
   20116     Orville Eberly, et al   Andrew Manyak #1                  N/A          N/A        N/A             1162          N/A
   20117     Orville Eberly, et al   Elizabeth Springer Heirs          N/A          N/A        N/A             1252          N/A
   20119     Orville Eberly, et al   Charles W. Baughman #1         10/22/1971      N/A        N/A              N/A          N/A
   20124     Greensboro Gas Co.      Republic Colleries                1931         N/A        N/A             1562          N/A
   20147     Peoples Natural Gas Co. Emery Anden #1                 9/16/1974       N/A        N/A             4004          N/A
   20150     Dale H. Campbell        John E. Dunay #1               9/25/1974       N/A        N/A             3815          N/A
   20151     Nollem Oil & Gas Co.    Combs #1                          N/A          N/A        N/A             1167          N/A
   20164     Greensboro Gas Co.      John Lovis #1                  4/23/1941       N/A        N/A             2599          N/A
   20165     J.E. Brumage            C.W. Leighty #1                7/22/1976       N/A        N/A             4209          N/A
   20167     Atlas                   National Mines #2              3/17/1977       N/A   916,000/1990         2805         3,377
   20177     George A. Burgly, Jr.   Robert Warfel #1               7/29/1983       N/A        N/A             3770          N/A
   20203     Total Resources         Sloan/Thompson #1              8/31/1978       N/A        N/A             4060          N/A
   20220     George A. Burgly, Jr.   Lila Gaskill #2                11/11/1982      N/A        N/A             2507          N/A
   20255     Peoples Natural Gas Co. Smith Rose #3498               5/14/1905       N/A        N/A             3102          N/A


                                       19




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   20256     Louden Properties, Inc. Alexander F. Kuznar #1          5/9/1980       N/A        N/A             4027          N/A
   20618     PC Exploration, Inc.    Helen Bukovac et al #4         9/29/1992       N/A        N/A             4396          N/A
   20767     Equitrans, Inc.         Landsdale America #1           6/18/1995       N/A        N/A             5529          N/A
   20770     Richard Burkland        Landsdale America #6           8/19/1995       N/A        N/A             2576          N/A
   20771     Equitrans, Inc.         Landsdale America #7           7/13/1995       N/A        N/A             4296          N/A
   20771     Richard Burkland        Landsdale America #7           7/13/1995       N/A        N/A             4298          N/A
   20807     W. Burkland             Graham Heirs #1                 3/7/1996       N/A        N/A             1500          N/A
   21072     W.Burkland              Yoho #1                           N/A          N/A        N/A              N/A          N/A
   21101     Douglas Oil & Gas, Inc. Lacey Unit #1                  7/29/1999       N/A        N/A             4024          N/A
   21254     Penneco Oil Co., Inc.   USX #1                         8/28/2001       N/A        N/A             4117          N/A
   21336     Great Lakes Energy
               Partners              Langley #1                     12/29/2002      N/A        N/A             3883          N/A
   21340     Great Lakes
               Energy Partners       Constantine #1                 11/12/2001      N/A        N/A             4142          N/A
   21341     Great Lakes
               Energy Partners       Constantine #2                 10/12/2001      N/A        N/A             4114          N/A
   21343     Atlas                   Szuhay #2                      10/14/2001      31        7,085            4492           87
   21361     Atlas                   Podolinski #3                   2/3/2002       26        5,776            3920          198
   21365     Atlas                   Barber #2                      11/21/2001      26       15,169            4395          384
   21366     Atlas                   Barber #1                      11/14/2001      26       21,247            4349          491
   21371     Atlas                   Podolinski #2                  5/21/2002       24        3,495            3800          104
   21373     Great Lakes
               Energy Partners       Randolph Unit #1               11/16/2001      N/A        N/A             4109          N/A
   21376     Atlas                   National Mines #3              2/13/2002       26       28,714            4201          902
   21382     Atlas                   Labash/Myers #3                 9/1/2003       15         130             4389           0
   21388     Atlas                   Snyder #9                      12/17/2001      26       51,798            3733         1,291
   21392     Great Lakes
               Energy Partners       Randolph Unit #2                1/8/2002       N/A        N/A             4149          N/A
   21400     Atlas                   Newcomer #2                    2/28/2002       25       10,966            2175           67
   21401     Atlas                   Newcomer #1                    1/26/2002       25        1,909            4446           28
   21402     Atlas                   National Mines #6              5/29/2002       24       69,459            4250         2,135
   21403     Atlas                   National Mines #5              11/21/2002      17       51,594            4120         2,061



                                       20




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   21405     Great Lakes
               Energy Partners       Constantine #3                 1/14/2002       N/A        N/A             3965          N/A
   21410     Atlas                   Gorley #1                      3/13/2002       26       170,886           1310         4,417
   21420     Atlas                   Gilleland #2                   6/18/2002       20        4,566            4150          161
   21428     Great Lakes
               Energy Partners       Dick #1                           N/A          N/A        N/A              N/A          N/A
   21429     Great Lakes
               Energy Partners       Dick #2                           N/A          N/A        N/A              N/A          N/A
   21436     Great Lakes
               Energy Partners       Misinay #1                     12/23/2002      N/A        N/A             4250          N/A
   21437     Great Lakes
               Energy Partners       Misinay #2                     10/31/2002      N/A        N/A             4218          N/A
   21445     Turm Oil Inc.           Michael W. & Donna J.
                                       Nelson #1                     5/1/2002       N/A        N/A             4342          N/A
   21449     Great Lakes
               Energy Partners       Carbonara #2                      N/A          N/A        N/A              N/A          N/A
   21462     Great Lakes
               Energy Partners       Randolph et al #1               8/3/2002       N/A        N/A             4054          N/A
   21466     Great Lakes
               Energy Partners       Baily #1                        1/6/2004       N/A        N/A             4145          N/A
   21467     Turm Oil Inc.           C.W. Leighty et ux #1           6/7/2002       N/A        N/A             4332          N/A
   21488     Atlas                   Borst #1                       10/1/2002       17        5,659            4412          215
   21492     Atlas                   Osley #1                       7/17/2002       22        7,486            4380          322
   21494     Atlas                   National Mines Corp. #12       7/26/2002       19       28,136            4460          711
   21514     Great Lakes
               Energy Partners       Baily #2                       9/18/2002       N/A        N/A             4138          N/A
   21528     Great Lakes
               Energy Partners       Miller #1                      11/25/2002      N/A        N/A             4150          N/A
   21529     Atlas                   Smith #9                       5/21/2003       11        8,516            4260          520
   21530     Atlas                   Smith #8                        1/3/2003       16        7,686            4090          271
   21532     Atlas                   Beadling #1A                   10/8/2002       17       10,526            4269          384
   21539     Atlas                   National Mines #8              9/18/2002       18       11,747            4370          395
   21540     Atlas                   Raleigh #1                     10/29/2002      19       20,938            4300          904
   21542     Atlas                   Jackson Farms Unit #1          2/13/2002       14       66,720            4610         4,319
   21543     Atlas                   Jackson Farms #8               11/21/2003       5       11,950            3920         2,359
   21553     Atlas                   Jackson Farms Unit #4          10/16/2002      19       14,899            4460          623
   21559     Atlas                   Debord #1                      10/17/2002      19       18,516            4416          548
   21560     Atlas                   National Mines #7              9/27/2002       18       19,915            3870          925


                                       21




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.





                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   21565     Great Lakes
               Energy Partners       Edson Farms Unit #2            7/18/2003       N/A        N/A             4028          N/A
   21566     Great Lakes
               Energy Partners       Edson Farms Unit #1            12/5/2002       N/A        N/A             4122          N/A
   21568     Atlas                   Rosa #4                        5/14/2003       11        4,428            4000          276
   21569     Atlas                   Rosa #1                        1/20/2003       15       27,826            4030         1,165
   21576     Atlas                   Jackson Farms #7               3/26/2003       13       33,958            4500         2,621
   21581     Atlas                   Snyder #10                     12/19/2002      14        3,807            4310         1,642
   21589     Atlas                   National Mines #11             12/11/2002      17        8,367            4370          468
   21590     Atlas                   Ramage #1                      2/21/2003       14       100,553           1850         5,782
   21591     Atlas                   National Mines #14             12/4/2002       17       32,265            4370         1,908
   21595     Atlas                   Carroll #4                     3/25/2003       12       23,667            4410         1,292
   21596     Atlas                   Rosa Unit #2                   3/15/2003       12       19,387            3915          966
   21597     Atlas                   Marian Unit #1A                 6/8/2003       11        9,195            4325          575
   21598     Atlas                   Marian #3                      2/15/2003       14       12,446            4300          678
   21599     Atlas                   Carroll #3                      2/4/2003       13        9,072            4210          494
   21600     Atlas                   National Mines #10             3/17/2003       14        4,047            4050          315
   21602     Great Lakes
               Energy Partners       Yoder #3                          N/A          N/A        N/A              N/A          N/A
   21603     Great Lakes
               Energy Partners       Yoder #4                       8/19/2003       N/A        N/A             4205          N/A
   21604     Great Lakes
               Energy Partners       Yoder #5                          N/A          N/A        N/A              N/A          N/A
   21612     W. Burkland             James E. Frey #1               1/14/2003       N/A        N/A             3766          N/A
   21613     Atlas                   Jackson Farms #2               4/10/2003       12       37,905            3010          850
   21619     Atlas                   Jackson Farms #3               2/17/2003       15       101,375           3805         3,925
   21628     Great Lakes
               Energy Partners       Mumaw #2                       2/25/2003       N/A        N/A             4063          N/A
   21630     Atlas                   Langley #1                     2/25/2003       12        6,523            4420          316
   21631     Atlas                   Langley #2                     12/4/2003        3        1,810            4320          601
   21632     Atlas                   Langley #3                     4/18/2003       12        6,546            4500          306
   21639     Great Lakes
               Energy Partners       Terrene Development Unit #1       N/A          N/A        N/A              N/A          N/A
   21648     Penneco Oil Co., Inc.   USX #2                         10/1/2003       N/A        N/A             4001          N/A


                                       22




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.





                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   21652     Atlas                   Jackson Farms #6                4/3/2003       14       28,274            4550         1,867
   21655     Atlas                   Harper #4                      4/21/2003       13        8,249            4400          514
   21658     Atlas                   National Mines #15             3/25/2003       13       12,418            3950          971
   21663     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
   21681     Atlas                   Jackson Farms #19               4/2/2003       12        7,844            4070          346
   21682     Atlas                   Jackson Farms #10              3/27/2003       13        6,581            3860          390
   21693     Atlas                   Blaney #1                      3/17/2003       12        5,342            4050          301
   21707     Great Lakes
              Energy Partners        Langley #2                     6/22/2003       N/A        N/A             3777          N/A
   21708     Great Lakes
               Energy Partners       Langley #3                        N/A          N/A        N/A              N/A          N/A
   21709     Great Lakes
               Energy Partners       Langley #4                        N/A          N/A        N/A              N/A          N/A
   21710     Great Lakes
               Energy Partners       Langley Unit #2                   N/A          N/A        N/A              N/A          N/A
   21714     Atlas                   Augustine #1                    6/3/2003       11       68,895            4250         5,253
   21718     Great Lakes
               Energy Partners       McManus #3                     7/30/2003       N/A        N/A             4026          N/A
   21719     Great Lakes
               Energy Partners       McManus #2                      7/8/2003       N/A        N/A             4100          N/A
   21720     Atlas                   Jackson Farms #16              7/19/2003       10        7,372            4680          559
   21721     Atlas                   Jackson Farms #11              7/10/2003       10        2,185            4310          180
   21723     Great Lakes
               Energy Partners       Randolph, et al #4                N/A          N/A        N/A              N/A          N/A
   21729     Atlas                   Augustine #4                   8/14/2003        8        3,074            4200          387
   21739     Atlas                   National Mines #13             6/22/2003       10       15,204            4070         1,315
   21752     Atlas                   National Mines #17              7/9/2003       10       20,797            3920         1,899
   21753     Atlas                   Jackson Farms #21              7/29/2003        7         424             4470          109
   21756     Atlas                   Jackson Farms #9                8/3/2003        9        4,853            4400          509
   21757     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
   21761     Atlas                   Smetanka #1                    10/23/2003       5        4,056            4350          649
   21762     Atlas                   Rosa #5                        12/12/2003       4        5,317            3990         1,253
   21764     Great Lakes
               Energy Partners       Dillinger #1                      N/A          N/A        N/A              N/A          N/A
   21765     Atlas                   Krukowski #1                   11/19/2003      N/A        N/A             4200          N/A


                                       23




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   21766     Atlas                   Hassibi #2                     10/17/2003       6        3,949            4400          412
   21767     Atlas                   Hassibi #1                     10/10/2003       6        2,927            4300          356
   21768     Atlas                   National Mines #18             8/12/2003        7       21,322            3980         3,163
   21770     Atlas                   Bierer #1                      9/20/2003        7        2,901            4460          274
   21771     Atlas                   Noble #12                      7/30/2003        8        2,733            4350          298
   21772     Atlas                   Croftcheck #9                   9/4/2003       N/A        N/A             4370          N/A
   21777     Atlas                   Jacobson #1                    7/23/2003        9        1,815            4350          164
   21780     Atlas                   Krukowski #4                   11/14/2003      N/A        N/A             4310          N/A
   21788     Atlas                   E&N Land #8                    8/19/2003        4        1,414            4548          238
   21793     Atlas                   Hassibi #3                     1/20/2004        2         806             4320          417
   21794     Atlas                   Hassibi #4                     3/12/2004        1         47              4450           47
   21798     Great Lakes
               Energy Partners       Carbonara-Chico #2             9/12/2003       N/A        N/A             3942          N/A
   21799     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
   21801     Atlas                   Martin #5                      9/19/2003        4        6,111            3960         1,562
   21802     Atlas                   Martin #6                       2/9/2004        2        4,281            4050         2,690
   21808     Atlas                   Blaney/USX #4                  12/19/2003       3        4,729            3920         1,683
   21810     Atlas                   Blaney #2                      12/5/2003        4         991             3920         3,268
   21811     Atlas                   Labash/Myers #2                9/12/2003        6         394             3850           40
   21817     Atlas                   Jackson Farms #18              9/11/2003        8       19,994            4155         2,250
   21818     Atlas                   Mullen/National City #1        10/5/2003        3        6,018            4550         3,079
   21819     Atlas                   Jackson Farms #12              9/24/2003        7       28,852            3911         3,355
   21820     Atlas                   Jackson Farms #20              10/13/2003       6       31,300            2940         3,622
   21829     Atlas                   Wozniak #1                     9/30/2003        2         952             4525          743
   21830     Atlas                   Wozniak #2                      5/5/2004       N/A        N/A             4510          N/A
   21833     Atlas                   Wozniak #3                     10/8/2003        2         911             4470          847
   21841     W. Burkland             Broadwater #1                     N/A          N/A        N/A              N/A          N/A
   21842     W.Burkland              Emery Dziak #3                    N/A          N/A        N/A              N/A          N/A


                                       24




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   21843     Penneco Oil
               Co., Inc.             USX #3                         10/8/2003       N/A        N/A             3716          N/A
   21844     Atlas                   Noble #11                      10/18/2003       6        5,479            4150          780
   21851     Atlas                   E&N Land #4                    11/8/2003        4        2,222            2190           95
   21852     Atlas                   Porter #9                      11/6/2003       N/A        N/A             3950          N/A
   21853     Atlas                   National Mines #20             11/13/2003       4        7,674            3750         1,854
   21858     Atlas                   Janco #2                       12/10/2003      N/A        N/A             1900          N/A
   21859     Atlas                   Janco #3                       10/25/2003      N/A        N/A             4150          N/A
   21860     Atlas                   Chalfant #1                    11/3/2003       N/A        N/A             3950          N/A
   21862     Atlas                   Teslovich #1                   10/25/2003       5       25,484            4500         5,394
   21863     Atlas                   Croftcheck #5                  12/10/2003       4       12,731            4500         6,268
   21867     Atlas                   Croftcheck #8                  5/26/2004       N/A        N/A             4540          N/A
   21868     Atlas                   Croftcheck #3                  11/24/2003       3        7,836            4450         3,273
   21873     Atlas                   Croftcheck #7                  2/24/2004        2         342             4550          337
   21874     Atlas                   Harper #5                      10/20/2003       6       41,524            4303         10,427
   21878     Atlas                   Porter #11                     2/10/2004       N/A        N/A             4550          N/A
   21882     Atlas                   DeBord #7                      11/17/2003       5        3,310            3860          650
   21883     Atlas                   National Mines Corp. #19       11/6/2003        5         378             3950           20
   21888     Atlas                   Seitz #1                       12/7/2003       N/A        N/A             4250          N/A
   21889     Atlas                   Teslovich #2                   3/28/2004        1         111             4458          111
   21891     Atlas                   Meyers #1                      2/17/2004        2        1,232            4250          977
   21896     Atlas                   Jackson Farms #17              12/31/2003       4       10,787            2300         1,329
   21898     Atlas                   Pradella #2                     1/5/2004       N/A        N/A             4400          N/A
   21899     Atlas                   Pradella #1                    4/20/2004       N/A        N/A             4440          N/A
   21905     Atlas                   Jackson Farms #5               11/20/2003       5         32              4027           0
   21908     Atlas                   Lilley #2                      1/18/2004        2       10,980            2550         9,075
   21909     Atlas                   Lilley #3                      2/15/2004        2         957             4510          763
   21910     Atlas                   E&N Land #2                    11/13/2003       4        9,261            4600         3,235


                                       25




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   21911     Atlas                   Porter #10                     12/29/2003      N/A        N/A             3950          N/A
   21917     Atlas                   Lilley #1                      1/27/2004        2         649             4210          437
   21921     Atlas                   Peton/Hogsett #2               1/23/2004        1         159             4210          159
   21923     Atlas                   Marian #2                      11/13/2003       5        8,731            3920         1,416
   21924     Atlas                   Yowonske-Hogsett #2            4/21/2004       N/A        N/A             4250          N/A
   21926     Atlas                   Patterson #7                    2/9/2004       N/A        N/A             2250          N/A
   21932     Atlas                   Jackson Farms #22               1/8/2004        3        1,912            4450          671
   21933     Atlas                   Wozniak #4                     3/14/2004        2        1,870            4470         1,816
   21937     Atlas                   Langley #8                     12/11/2003       3        1,277            3850          454
   21938     Atlas                   King Unit #8                    4/6/2004        1         206             3850          206
   21939     Great Lakes
               Energy Partners       Hatley Unit #4                    N/A          N/A        N/A              N/A          N/A
   21940     Great Lakes
               Energy Partners       Hatley Unit #3                    N/A          N/A        N/A              N/A          N/A
   21941     Atlas                   Brady #1                       12/2/2003        4        3,307            4200          691
   21944     Atlas                   Brady #2                       4/22/2004       N/A        N/A             4340          N/A
   21945     Great Lakes
               Energy Partners       Carbonara-Chico #4             1/17/2004       N/A        N/A             3996          N/A
   21946     Atlas                   Yowonske-Hogsett #3            4/27/2004       N/A        N/A             4150          N/A
   21951     Atlas                   Williams #23                   12/17/2003       1         443             3750          443
   21952     Atlas                   Yowonske-Hogsett #1            4/13/2004       N/A        N/A             4160          N/A
   21955     Great Lakes
               Energy Partners       Hatley Unit #2                 12/24/2003      N/A        N/A             4068          N/A
   21956     Great Lakes
               Energy Partners       Hatley Unit #1                    N/A          N/A        N/A              N/A          N/A
   21960     Atlas                   Croftcheck #4                  12/4/2003        4       14,670            4020         3,643
   21961     Atlas                   Moore #11                      2/16/2004       N/A        N/A             3660          N/A
   21966     Atlas                   Langley #6                     12/20/2003       2        2,167            4370         1,963
   21972     Atlas                   Jackson Farms #15               1/7/2004        3        4,098            3260          778
   21975     W. Burkland             LTV-Searights #2                  N/A          N/A        N/A              N/A          N/A
   21976     W. Burkland             LTV-Searights #3               12/19/2003      N/A        N/A             3909          N/A
   21978     Great Lakes
               Energy Partners       Commercial Tire #1             3/19/2004       N/A        N/A             3894          N/A


                                       26




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   21979     Great Lakes
               Energy Partners       Koltash #1                        N/A          N/A        N/A              N/A          N/A
   21982     Atlas                   Christopher/NCB #2             1/14/2004       N/A        N/A             2150          N/A
   21985     Atlas                   Gabonay/National City Bank #5  6/17/2004       N/A        N/A             4755          N/A
   21988     Atlas                   Congelio #2                    1/31/2004       N/A        N/A             4520          N/A
   21998     Atlas                   National Mines Corp. #21        5/4/2004       N/A        N/A             3750          N/A
   22004     Atlas                   Allison/Hogsett #05            2/25/2004       N/A        N/A             4420          N/A
   22005     Atlas                   Novsek #1                      2/16/2004       N/A        N/A             4150          N/A
   22006     Atlas                   Lint #6                        2/10/2004       N/A        N/A             4160          N/A
   22007     Atlas                   Gorley #2                      3/13/2004        1         54              3750           54
   22008     Atlas                   Gorley #3                       3/8/2004        1         10              3810           10
   22010     Atlas                   Stewart #11                    2/25/2004        2         377             4210          327
   22012     Atlas                   Constantine #1                 3/24/2004       N/A        N/A             4100          N/A
   22013     Atlas                   Constantine #2                 3/30/2004       N/A        N/A             4200          N/A
   22014     Atlas                   Constantine #3                  4/6/2004       N/A        N/A             4378          N/A
   22019     Kriebel Minerals,
               Inc.                  Dvofchak/P&M #2                   N/A          N/A        N/A              N/A          N/A
   22022     Atlas                   Patterson #4                   4/28/2004       N/A        N/A             4770          N/A
   22023     Atlas                   Patterson #5                    2/2/2004       N/A        N/A             4610          N/A
   22026     Atlas                   Allison/Hogsett #06             3/1/2004        1        1,336            4400         1,336
   22027     Great Lakes
               Energy Partners       Bortz Corporation #1              N/A          N/A        N/A              N/A          N/A
   22032     Atlas                   Barbabella #1                  3/18/2004       N/A        N/A             4179          N/A
   22034     Atlas                   Dancho-Brown #1                 4/2/2004       N/A        N/A             4360          N/A
   22035     Atlas                   Dancho-Brown #2                4/14/2004       N/A        N/A             4357          N/A
   22036     Atlas                   Dancho-Brown #3                2/25/2004        1         100             4260          100
   22039     Atlas                   Leichliter #4                   2/4/2004        1          5              4150           5
   22042     Atlas                   Dominiak #1                    1/27/2004       N/A        N/A             4450          N/A
   22050     Atlas                   Bowser #1                      5/14/2004       N/A        N/A             4670          N/A
   22055     Atlas                   King #9                         5/5/2004       N/A        N/A             4510          N/A


                                       27




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   22056     Atlas                   Bennette #1                    4/27/2004       N/A        N/A             4470          N/A
   22058     Atlas                   Congelio #1A                   3/15/2004       N/A        N/A             4550          N/A
   22063     Atlas                   Luckasevic #2                  5/20/2004       N/A        N/A             4460          N/A
   22064     Atlas                   Luckasevic #3                  3/26/2004       N/A        N/A             4718          N/A
   22065     Atlas                   Luckasevic #4                  5/27/2004       N/A        N/A             4460          N/A
   22073     Atlas                   Grena #2                       4/16/2004       N/A        N/A             4555          N/A
   22076     Atlas                   Novak-Melenyzer #2             5/13/2004       N/A        N/A             4745          N/A
   22078     Atlas                   Adams #4                       5/12/2004       N/A        N/A             4350          N/A
   22079     Atlas                   House #1                        5/7/2004       N/A        N/A             2000          N/A
   22083     Atlas                   Chuboy/USX #1                  4/28/2004       N/A        N/A             1620          N/A
   22099     Atlas                   Wilkinson #3                   3/25/2004       N/A        N/A             4200          N/A
   22102     Atlas                   Congelio #4                     6/9/2004       N/A        N/A             4460          N/A
   22112     Atlas                   Congelio #3                    5/27/2004       N/A        N/A             4100          N/A
   22115     Atlas                   E&N Land #3                    7/22/2004       N/A        N/A             4705          N/A
   22118     Great Lakes
               Energy Partners       Langley #1                        N/A          N/A        N/A              N/A          N/A
   22119     Great Lakes
               Energy Partners       Langley #2                        N/A          N/A        N/A              N/A          N/A
   22125     W. Burkland             Lent #1                           N/A          N/A        N/A              N/A          N/A
   22126     Atlas                   Canestrale #9                  6/22/2004       N/A        N/A             4410          N/A
   22127     Atlas                   Teslovich #15                   6/4/2004       N/A        N/A             4420          N/A
   22128     Atlas                   Chan #1                        5/12/2004       N/A        N/A             4690          N/A
   22129     Atlas                   Teslovich #14                  5/27/2004       N/A        N/A             4470          N/A
   22130     Atlas                   Kezmarsky #1                   5/21/2004       N/A        N/A             4700          N/A
   22137     Atlas                   Allison/Hogsett #01             7/2/2004       N/A        N/A             4540          N/A
   22141     Atlas                   Croftcheck #6                  6/16/2004       N/A        N/A             4700          N/A
   22142     Atlas                   Grindstone VFD/USX #2          6/25/2004       N/A        N/A             4320          N/A
   22146     Atlas                   Stark #2                       6/15/2004       N/A        N/A             4590          N/A
   22151     Atlas                   Crawford Unit #5               6/10/2004       N/A        N/A             4440          N/A


                                       28




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   22156     Atlas                   Zivkovich Unit #1               6/2/2004       N/A        N/A             3150          N/A
   22157     Atlas                   Hosler #1                       6/7/2004       N/A        N/A             4480          N/A
   22159     Atlas                   Hosler #3                       6/2/2004       N/A        N/A             4530          N/A
   22161     Atlas                   Janco Unit #1                   6/9/2004       N/A        N/A             4710          N/A
   22170     Atlas                   Canestrale #7                  6/30/2004       N/A        N/A             4280          N/A
   22184     Atlas                   Bird #1                         7/3/2004       N/A        N/A             4580          N/A
   22187     Atlas                   Hela #1                        7/17/2004       N/A        N/A             4530          N/A
   22190     Atlas                   Bullied #1                     7/19/2004       N/A        N/A             4570          N/A
   22191     Atlas                   Gazzam/USX #1                  6/25/2004       N/A        N/A             4160          N/A
   22194     Atlas                   Farquhar #5A                   7/14/2004       N/A        N/A             3710          N/A
   90011     Greensboro Gas Co.      S.Gorley #2                    6/21/1944       N/A        N/A             2989          N/A
   90018     Manufacturers Light
               & Heat Co.            Alva J. Wolfe #L-4190          1/15/1954       N/A        N/A              542          N/A
   90022     Greensboro Gas Co.      American Coke & Fuel Co. #4    9/14/1942       N/A        N/A             2807          N/A
   90023     Greensboro Gas Co.      American Coke & Fuel Co. #5    12/9/1943       N/A        N/A             2773          N/A
   90026     Greensboro Gas Co.      D.E. Lowe #1                    6/6/1941       N/A        N/A             2747          N/A
   90027     Greensboro Gas Co.      G.O. Morris                    4/23/1943       N/A        N/A             2509          N/A
   90034     Manufacturers Light
               & Heat Co.            W.A. Gilleland                 2/19/1954       N/A        N/A             3731          N/A
   90054     Greensboro Gas Co.      S.W. Fast                      4/14/1905       N/A        N/A             2840          N/A
   90060     Greensboro Gas Co.      Estella Gibson                    1917         N/A        N/A             2959          N/A
   90061     Greensboro Gas Co.      John Horner #1                 4/20/1917       N/A        N/A             2844          N/A
   90062     Greensboro Gas Co.      Joseph Horner #2               2/20/1927       N/A        N/A             3084          N/A
   90063     Greensboro Gas Co.      John Horner #2                 11/24/1918      N/A        N/A             3178          N/A
   90064     Greensboro Gas Co.      Jacobs #2                      11/15/1912      N/A        N/A             2910          N/A
   90070     Greensboro Gas Co.      L.W. & N. Ernest                  1927         N/A        N/A             3213          N/A
   90071     Greensboro Gas Co.      John Gibson #2                 3/18/1920       N/A        N/A             3108          N/A
   90074     Greensboro Gas Co.      George Cox #1                  8/27/1917       N/A        N/A             3152          N/A
   90081     Greensboro Gas Co.      Krepps #2                      10/21/1910      N/A        N/A             3106          N/A


                                       29




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   90082     Greensboro Gas Co.      Mary Lawrence                     1918         N/A        N/A             3127          N/A
   90083     Greensboro Gas Co.      John Miller #1                 10/28/1929      N/A        N/A             3156          N/A
   90084     Greensboro Gas Co.      McMullen                          N/A          N/A        N/A             3090          N/A
   90085     Greensboro Gas Co.      Moore Heirs Lot                1/13/1927       N/A        N/A             2801          N/A
   90087     Greensboro Gas Co.      John Porter #1                  3/4/1918       N/A        N/A             3212          N/A
   90089     Greensboro Gas Co.      E.M. Robinson                   9/4/1918       N/A        N/A             3082          N/A
   90090     Greensboro Gas Co.      E.M. Robinson                  3/25/1918       N/A        N/A             3073          N/A
   90091     Greensboro Gas Co.      S. Rose #1                     3/29/1905       N/A        N/A             4470          N/A
   90095     Greensboro Gas Co.      J.V. Thompson #1               6/17/1910       N/A        N/A             3309          N/A
   90118     Greensboro Gas Co.      David Gans #3                     1921         N/A        N/A             3654          N/A
   90119     Greensboro Gas Co.      A.A. Stevenson                    1930         N/A        N/A             2789          N/A
   90120     Greensboro Gas Co.      John Vesey                        1930         N/A        N/A             1473          N/A
   90122     Greensboro Gas Co.      Samuel Fast                       1924         N/A        N/A             1920          N/A
   90123     Greensboro Gas Co.      D.C. Fast                       1/1/1901       N/A        N/A             1755          N/A
   90124     Greensboro Gas Co.      W.W. Frank Heirs                  1901         N/A        N/A             1924          N/A
   90125     Greensboro Gas Co.      A.C. Fretts                       1927         N/A        N/A             1845          N/A
   90128     Greensboro Gas Co.      Woodside Coal & Coke Co.          N/A          N/A        N/A             1050          N/A
   90132     Greensboro Gas Co.      Springer Heirs                    1901         N/A        N/A             1851          N/A
   90134     Greensboro Gas Co.      E.D. Fulton                       N/A          N/A        N/A             1287          N/A
   90161     Carnegie Natural
               Gas Co.               James Clark                       N/A          N/A        N/A             2844          N/A
  F22960     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
   FC131     Fayette County
               Gas Co.               N.H. Lewis #1                  3/17/1944       N/A        N/A             2649          N/A
   FC30      Fayette County
               Gas Co.               Caroline G. Graham #1           4/1/1906       N/A        N/A             1946          N/A
   FC35      Fayette County
               Gas Co.               Langley                        2/26/1903       N/A        N/A             3381          N/A
   G171      Greensboro Gas Co.      Thos. Acklin Hrs. #2           1/11/1910       N/A        N/A             2315          N/A
   G173      Greensboro Gas Co.      W. H. Campbell #1              11/30/1909      N/A        N/A             2822          N/A
   G194      Greensboro Gas Co.      J.V. Thompson #2               10/13/1910      N/A        N/A             3010          N/A


                                       30




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
   G270      Greensboro Gas Co.      Jacobs Estate #1               7/10/1913       N/A        N/A             3015          N/A
   G280      N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
   G288      Greensboro Gas Co.      R. B. Hays #1                  1/13/1914       N/A        N/A             1538          N/A
   G302      Greensboro Gas Co.      J.N. Craft #1                  8/11/1914       N/A        N/A             3117          N/A
    G51      Greensboro Gas Co.      J.J. Honsaker #51              10/3/1901       N/A        N/A             1486          N/A
   G917      Greensboro Gas Co.      Mary Keys Graham #1             6/7/1940       N/A        N/A             1182          N/A
   G953      Greensboro Gas Co.      Margaret Bowie Heirs #2        2/26/1943       N/A        N/A             1401          N/A
   G975      Greensboro Gas Co.      Wm. Mosser #1                  10/13/1944      N/A        N/A             1998          N/A
 GRE-00367   Carnegie Natural
               Gas Co.               B. Williamson #1                8/4/1928       N/A        N/A             2913          N/A
 GRE-20101   H.C. Wilson             R. Howard #1                   1/30/1967       N/A        N/A             1668          N/A
 GRE-20105   Pennsynd Petroleum,
               Inc.                  J. H. Hillman & Sons #2        7/29/1967       N/A        N/A              519          N/A
 GRE-20106   Pennsynd Petroleum,
               Inc.                  J. H. Hillman & Sons #3         5/3/1967       N/A        N/A              490          N/A
 GRE-21227   Keystone Gas Co.        Samuel & Doris Lewis #1           N/A          N/A        N/A              N/A          N/A
 GRE-21527   Peoples Natural
               Gas Co.               H. Cree #1                     3/28/1980       N/A        N/A             3039          N/A
 GRE-P1164   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P15627   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P24257   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P24258   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P26448   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P26655   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P30505   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P31179   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P31202   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-P33500   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-P6997   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-P7339   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A


                                       31




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
GRE-UNK100   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK101   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK102   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK103   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK104   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK105   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK106   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK107   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK108   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK109   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK110   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK111   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK112   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK113   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK114   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK115   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK116   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK117   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK118   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK119   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK120   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK121   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK122   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK123   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK124   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK125   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK126   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK127   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A


                                       32




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
GRE-UNK128   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK129   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK130   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK131   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK132   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK133   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK134   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK135   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK136   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK137   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK138   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK139   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK140   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK141   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK142   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK143   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK144   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK145   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK146   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK147   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK148   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK149   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK150   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK151   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK152   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK153   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK154   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A


                                       33




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
GRE-UNK155   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK156   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK157   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK158   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK159   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK160   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK161   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK162   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK163   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK164   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK165   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK166   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK167   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK168   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK169   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK175   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK176   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK177   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK178   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK179   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK180   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK181   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK182   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK183   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK184   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK185   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK186   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A


                                       34




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
GRE-UNK188   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
GRE-UNK189   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK80   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK81   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK82   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK83   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK84   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK85   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK86   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK87   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK88   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK89   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK90   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK91   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK92   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK93   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK94   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK95   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK96   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK97   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK98   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 GRE-UNK99   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
  P21214     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
  P23112     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
  P23453     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
  P23644     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
  P23645     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A


                                       35




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.






                                                                                            TOTAL MCF
                                                                                             THROUGH           TOTAL
                                                                       DATE       MOS ON  6/30/04 EXCEPT      LOGGERS      LATEST 30
 ID NUMBER   OPERATOR                WELL NAME                       COMPLT'D      LINE    WHERE NOTED         DEPTH       DAY PROD.
 ---------   --------                ---------                       --------      ----    -----------         -----       ---------
     .       N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
  P23857
  P23859     N/A                     J. Hoover #1                  before 1935      N/A        N/A           est 2300        N/A
  P24459     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
  P24515     Monongahela Natural
               Gas Co.               N/A                            1/27/1909       N/A        N/A             2509          N/A
  P25531     Duquesne Natural
               Gas Co.               Elizabeth Provence             5/11/1931       N/A        N/A             2710          N/A
  P26608     N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
  P27181     Edward Johns et al      W. Fast                        10/4/1945       N/A        N/A             2725          N/A
  PNG3637    Peoples Natural
               Gas Co.               W. Mapstone #1                  2/4/1946       N/A        N/A             4085          N/A
 WASH-1380   N/A                     N/A                               N/A          N/A        N/A              N/A          N/A
 WASH-1975   George Sabocheck        Sabocheck #1                      N/A          N/A        N/A              N/A          N/A
 WASH-1976   George Sabocheck        Sabocheck #2                      N/A          N/A        N/A              N/A          N/A
 WASH-1978   E. Tague                Crumrine #1                     1/8/1927       N/A        N/A             2530          N/A
WASH-20033   McCormick Drilling
               Co.                   McCarty #1                      8/1/1958       N/A        N/A              900          N/A
 WASH-2061   George Sabocheck        Sabocheck #3                      N/A          N/A        N/A              N/A          N/A


                                       36





                   [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT]




                                     UEDC'S

                               GEOLOGIC EVALUATION

                                     FOR THE

                            CURRENTLY PROPOSED WELLS

                                       IN

                    FAYETTE AND GREENE COUNTIES, PENNSYLVANIA





                                       37



                               GEOLOGIC EVALUATION
                ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP
                              FAYETTE PROSPECT AREA
                                  PENNSYLVANIA

                             Dated: August 10, 2004



Program proposed by:               Report submitted by:

ATLAS RESOURCES, INC.              UEDC
311 Rouser Road                    United Energy Development Consultants, Inc.
P.O. Box 611                       1715 Crafton Blvd.
Moon Township, PA   15108          Pittsburgh, PA   15205







                         LOCATION MAP - AREA OF INTEREST



                            [GRAPHIC OF MAP OMITTED]



                                TABLE OF CONTENTS

LOCATION MAP  -  AREA OF INTEREST....................................1
TABLE OF CONTENTS....................................................1
INVESTIGATION SUMMARY................................................2
         OBJECTIVE...................................................2
         AREA OF INVESTIGATION.......................................2
         METHODOLOGY.................................................2
PROSPECT AREA HISTORY................................................2
         DRILLING ACTIVITY...........................................2
         GEOLOGY.....................................................2
                  STRATIGRAPHY, LITHOLOGY & DEPOSITION...............2
                  RESERVOIR CHARACTERISTICS..........................4
         PRODUCTION..................................................4
         CONCLUSION..................................................5
         DISCLAIMER..................................................5
         NON-INTEREST................................................5



                                       38



                              INVESTIGATION SUMMARY


OBJECTIVE

     The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Fayette Prospect Area as proposed by
Atlas Resources, Inc. ("Atlas").

AREA OF INVESTIGATION

     A portion of this prospect area, herein identified for drilling in ATLAS
AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP, contains acreage in Luzerne,
Redstone, Menallen, Nicholson, German, Jefferson and Perry Townships of Fayette
County, and Dunkard Township of Greene County, located in southwestern
Pennsylvania. Seventy (70) drilling prospects have currently been designated for
this program in the prospect area, which will be targeted to produce natural gas
from Mississippian and Upper Devonian reservoirs, found at depths from 1900 feet
to 5500 feet beneath the earth's surface. These will be the only prospects
evaluated for the purposes of this report.

METHODOLOGY

     Atlas provided the data incorporated into this report. Geological mapping
and the interpretations by Atlas geologists were also examined. Available
"electric" log, completion and production data on "key" wells within and
adjacent to the defined prospect area were utilized to determine productive and
depositional trends

                              PROSPECT AREA HISTORY

DRILLING ACTIVITY

The proposed drilling area lies within a region of southwestern Pennsylvania,
which has been active for the past six years in terms of exploration for, and
exploitation of natural gas reserves. Development within and adjacent to the
Fayette Prospect Area has continued steadily since 1996. Over four hundred
seventy five (475) wells have been drilled in the area during this period. Atlas
has encountered favorable drilling and production results while solidifying a
strong acreage position of over 50,000 acres, as Atlas continues to identify and
extend productive trends. Drilling is ongoing as of the date of this report with
recent wells displaying favorable initial drilling and completion results.

     The area of proposed drilling is situated in portions of Fayette and Greene
Counties that have had established production from shallower, historic pay
zones. Atlas will drill at least 1000 feet from producing wells, although Atlas
may drill a new well or re-enter an existing well closer than 1000 feet from
plugged and abandoned wells.

GEOLOGY

     STRATIGRAPHY, LITHOLOGY & DEPOSITION

     The Mississippian reservoirs currently producing in the Fayette Prospect
Area are the Burgoon Sandstone (lower Big Injun) and the 2nd Gas Sand. The
Burgoon Sandstone is part of the massive Big Injun fluvial-deltaic sand system,
which extends from eastern Kentucky through West Virginia into southwestern
Pennsylvania. This reservoir is an historic producing zone in this region, with
some wells still producing long beyond fifty years. There is not much history of
production from the 2nd Gas Sand in this area.

     The Upper Devonian reservoirs consist of three groups of sands, Upper
Venango, Lower Venango and Bradford. Each of these "Groups" has multiple
reservoirs making up their total rock section. The Upper Venango Group consists
of the Gantz Sand and the Fifty Foot Sand. The Lower Venango Group consists of
the Fifth Sand and the Bayard Sand. Depositional environments of these Upper and
Lower Venango Group sands are of near shore to offshore marine settings related
to the last major advance of the Catskill Delta. The Bradford Group consists of
the Lower Warren Sand, Upper Speechley Sand, Lower Speechley Sand, Upper
Balltown Sand and the First Bradford Sand. Depositional environments of these
sands are offshore marine, pro-delta and basin floor settings related to the
intermediate advance of the Catskill Delta.

                                       39

[graphic omitted]

Stratigraphically, in descending order, the potentially productive units of the
Mississippian and Upper Devonian Groups are: Burgoon, 2nd Gas Sand, Gantz, Fifty
Foot, Fifth, Bayard, Lower Warren, Upper Speechley, Lower Speechley, Upper
Balltown, and First Bradford Sand. Stratigraphic relationships are illustrated
in the diagram.

o The BURGOON SANDSTONE is a fine to medium grained, medium to massively
bedded, light-gray sandstone ranging in thickness from 200-250 feet. Average
porosity values for this sand range from 6% to 12% regionally. It is not
uncommon to encounter porosities as high as 20% and attendant producible natural
open flows from this sand. Tracking these producible natural open flow trends is
targeted for further development. Also, this zone does produce water in certain
locales within the Fayette Prospect Area. This reservoir is considered a
secondary target in the natural open flow trend areas.
o The 2ND GAS SAND of this region has limited areal extent and therefore is
not discussed in the literature regarding lithology, thickness etc. It can be
inferred from underlying and overlying sands that it is probably a fine to very
fine grained, light gray sand. Subsurface mapping indicates that the sand can
achieve a thickness of twenty (20) feet. Average porosity values for this sand
range from 10% to 13% when this zone is present in the area. Peak porosities of
17% have been encountered within the prospect area. This reservoir is considered
to be a secondary target when encountered.
o The GANTZ SAND is a white to light-gray, medium to coarse-grained sandstone
ranging in thickness from a few feet to over sixty (60) feet. Average porosity
values for this sand range from 5% to 10% regionally. Within the area of
investigation, porosities in excess of 13% occur within localized trends
characterized by producible natural open flows. These trends are targeted for
future development. This reservoir is considered a primary target in the natural
open flow trend areas.
o The FIFTY FOOT SAND is a white to light gray, thinly bedded, fine-grained
sandstone ranging in thickness from ten (10) to thirty (30) feet. Average
porosity values for this sand range from 5% to 8% regionally. Within the
prospect area, porosities in excess of 12% occur within localized trends
targeted for future development. This sand reservoir is considered a secondary
target.
o The FIFTH SAND is a white to light gray, very fine to fine grained sandstone
ranging in thickness from a few feet to forty (40) feet. Within the main Fifth
fairway, porosity values average from 9% to 15%. This sand is considered a
primary target and will be exploited in future development.
o The BAYARD SAND in the prospect area ranges in thickness from a few feet to
more than sixty (60) feet. Average porosity values range from 5% to 12% for this
fine to coarse-grained sandstone. Discrete reservoirs within the sand have been
identified and mapped. Gas shows in the member sandstones delineate trends
within the prospect area and will be targeted for future development. This sand
is considered a primary target.
o The LOWER WARREN SAND is a primary target in the prospect area. Average
thickness for this sand ranges from zero (0) feet to over forty (40) feet.
Porosities average between 8% and 12% in the area. Gas shows are commonly found
in this sand, which is probably a fine-grained, well-sorted sand. This reservoir
is targeted for future development.
o The UPPER SPEECHLEY SAND is considered a secondary target with average
thickness ranging from two (2) feet to ten (10) feet over much of the prospect
area. Gas shows from this sand are common throughout the area and the zone is
combined with other zones when treated.

                                       40


o The LOWER SPEECHLEY SAND is a primary target in the area with reservoir
thickness ranging from zero (0) to over forty (40) feet. Average porosity values
range from 5% to 12% where the sand is present. Significant natural and after
treatment flows from this sand have been encountered. This sand is being
targeted throughout the prospect area.
o The UPPER BALLTOWN SAND is currently being produced in a few wells in the
prospect area. The zone is a siltstone with fracture-enhanced porosity, based on
log interpretation, and has associated gas shows. This sand is considered a
secondary target and is usually combined with other zones when treated.
o The FIRST BRADFORD SAND, like the Balltown above, is currently being
produced in a few wells in the prospect area. This silty-sand does have porosity
up to 10% in the area and is considered to be a secondary target when
encountered.

     RESERVOIR CHARACTERISTICS

     Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping commercial quantities of natural gas in a more permeable medium. In the
Mississippian and Upper Devonian reservoirs, this occurs either
stratigraphically when a permeable sand containing hydrocarbons encounters
impermeable shale or when permeable sand changes gradually into non-permeable
sand by a cementation process known as "diagenesis". Thus, this type of trap
represents cemented-in hydrocarbon accumulations.

[GRAPHIC OMITTED]

     Electric well logs can be used in conjunction with production to interpret
reservoir parameters. When sandstones in the Mississippian and Upper Devonian
reservoirs develop porosity in excess of 8%, or a bulk density of 2.50 or less,
the permeability of the reservoir can become great enough to allow commercial
production of natural gas. Small, naturally occurring cracks in the formation,
referred to as micro-fractures, can also enhance permeability.

     A gamma, bulk density, neutron, induction and temperature log suite showing
sand development in both the Mississippian and Upper Devonian reservoirs is
illustrated.

     The temperature log shown in the illustration at left identifies where gas
is entering the wellbore. Evidence of a temperature "kick" or cooling is also an
indication of enhanced permeability and the willingness of the reservoir to
produce natural gas.

PRODUCTION

     The Fayette prospect area produces from a number of reservoirs of different
age and type. Each well has a unique combination of these reservoirs yielding
different production declines. While Atlas anticipates production from each
reservoir to be comparable to like reservoirs historically produced throughout
the Appalachian Basin, a model decline curve for this prospect area is not
included due to multiple sets of commingled reservoirs exclusively found in this
area.

                                       41




                                   STATEMENTS

CONCLUSION

     UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP, which will consist of
developmental drilling of Lower Mississippian and Upper Devonian reservoirs in
Fayette and Greene Counties, Pennsylvania. It is the professional opinion of
UEDC that the drilling of the seventy (70) wells by ATLAS AMERICA PUBLIC
#14-2004 LIMITED PARTNERSHIP is supported by sufficient geologic and engineering
data.

DISCLAIMER

     For the purpose of this evaluation, UEDC did not visit any leaseholds or
inspect any of the associated production equipment. Likewise, UEDC has no
knowledge as to the validity of title, liabilities, or corporate matters
affecting these properties. UEDC does not warrant individual well performance.

NON-INTEREST

     We hereby confirm that UEDC is an independent consulting firm and that
neither this firm or any of it's employees, contract consultants, or officers
has, or is committed to acquire any interest, directly or indirectly, in Atlas
Resources, Inc.; nor is this firm, or any employee, contract consultant, or
officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm
that neither the employment of, nor payment of compensation received by UEDC in
connection with this report, is on a contingent basis.

                                                     Respectfully submitted,

                                                           /s/ Robin Anthony
                                                                  UEDC, INC.




                                       42










                                LEASE INFORMATION

                                       FOR

                      WESTERN PENNSYLVANIA AND EASTERN OHIO

















                                       43






















                                                                        OVERRIDING
                                                                         ROYALTY
                                                                         INTEREST OVERRIDING                                ACRES
                                                                          TO THE    ROYALTY                                 TO BE
                                                                         MANAGING  INTEREST     NET                        ASSIGNED
                                      EFFECTIVE  EXPIRATION   LANDOWNER  GENERAL    TO 3RD    REVENUE    WORKING   NET      TO THE
   PROSPECT NAME            COUNTY      DATE*       DATE*      ROYALTY    PARTNER   PARTIES   INTEREST  INTEREST  ACRES  PARTNERSHIP
   -------------            ------      -----       -----      -------    -------   -------   --------  --------  -----  -----------
1  McIntyre #2             Crawford   08/11/03    08/11/06      12.5%        0%        0%       87.5%      100%    106        50
2  Conley #1               Crawford   11/29/02    11/29/05      12.5%        0%        0%       87.5%      100%    75         50
3  Merlin Enterprises #4   Crawford   07/08/02       HBP        12.5%        0%        0%       87.5%      100%    327        50
4  Wiestling #1            Crawford   09/19/02    09/19/05      12.5%        0%        0%       87.5%      100%    80         50
5  Oswald Farms #4         Crawford   04/02/02    04/02/05      12.5%        0%        0%       87.5%      100%    144        50
6  Helderlein Unit #1      Crawford   06/03/02    06/03/05      12.5%        0%        0%       87.5%      100%    26         26
7  Hebert #5               Crawford   01/02/04    01/02/07      12.5%        0%        0%       87.5%      100%    25         25
8  Greathouse #1            Mercer    01/18/02    01/18/05      12.5%        0%        0%       87.5%      100%    90         50


*HBP - Held by Production.



                                       44









                           LOCATION AND PRODUCTION MAP

                                       FOR

                      WESTERN PENNSYLVANIA AND EASTERN OHIO





                                       45






                            [GRAPHIC OF MAP OMITTED]







                                       46



                            [GRAPHIC OF MAP OMITTED]







                                       47




                            [GRAPHIC OF MAP OMITTED]







                                       48






                                 PRODUCTION DATA

                                       FOR

                      WESTERN PENNSYLVANIA AND EASTERN OHIO


























                                       49






The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.



                                                                                        TOTAL MCF THROUGH      TOTAL
                                                                    DATE       MOS ON     6/30/04 EXCEPT      LOGGERS    LATEST 30
ID NUMBER        OPERATOR                    WELL NAME            COMPLT'D      LINE       WHERE NOTED         DEPTH     DAY PROD.
- ---------        --------                    ---------            --------      ----       -----------         -----     ---------
  20232     Northern Appalachian         Kleinhas, M.             05/21/81       N/A           N/A             5293         N/A
  20233     Northern Appalachian         Rena Osborn              05/12/81       N/A           N/A             5325         N/A
  20235     Northern Appalachian         Rounds, G. T.            07/05/81       N/A           N/A             5335         N/A
  20266     Northern Appalachian         Small, C. W.             08/03/81       N/A           N/A             5345         N/A
  20274     Wainoco Oil & Gas            Carey, John #1           08/14/81       N/A           N/A             5342         N/A
  20291     Wainoco Oil & Gas            Woodcock, Russ #1        10/09/81       N/A           N/A             5351         N/A
  21212     Cabot Oil & Gas              Troyer, Eli #1           08/05/81       N/A           N/A             4641         N/A
  22072     Great Lakes Energy Partners  Hamilton #1              03/31/84       N/A           N/A             4591         N/A
  22076     Mitchell Energy              Hauser #1                01/28/84       N/A           N/A             4591         N/A
  22121     George Lapradd               Rawson #1                02/29/84       N/A           N/A             4464         N/A
  22806     Great Lakes Energy Partners  Doughman #1              06/21/00       N/A           N/A             5294         N/A
  22982     Atlas Resources, Inc.        Thompson #16             08/19/01       33           40171            5167        1308
  22984     Atlas Resources, Inc.        Cresswell #2             08/03/01       33           25907            5195         747
  24080     Atlas Resources, Inc.        Sperry Farms #4          02/19/03       15           1657             4854         41
  24110     Atlas Resources, Inc.        Morrow #2                03/26/03        8           3167             4769         309
  24208     Atlas Resources, Inc.        Hebert #4                05/18/04       N/A           N/A             4749         N/A
  24239     Atlas Resources, Inc.        Mielecki Unit #2         10/23/03        2            834             5000         N/A
  24245     Atlas Resources, Inc.        Fisher Unit #4           12/16/03        1            N/A             4790         N/A
  24248     Atlas Resources, Inc.        Townsend #4              12/12/03        1            N/A             4694         N/A
  24254     Atlas Resources, Inc.        Shearer #2               12/30/03        1            N/A             4746         N/A
  24258     Atlas Resources, Inc.        Merlin Enterprises #3    01/29/04       N/A           N/A             4668         N/A
  24268     Atlas Resources, Inc.        Grudoski #1              01/17/04        1            N/A             4754         N/A
  24272     Atlas Resources, Inc.        Crum Unit #1             02/13/04        2            N/A             4836         N/A
  24273     Atlas Resources, Inc.        Unger #1                 02/07/04       N/A           N/A             4742         N/A
  24275     Atlas Resources, Inc.        Weaver #5                02/17/04        1            N/A             4835         N/A
  24297     Atlas Resources, Inc.        Detweiler #5             03/22/04        1            N/A             4768         N/A
  24312     Atlas Resources, Inc.        Horne #12                05/07/04       N/A           N/A             4747         N/A
  90003     United Natural Gas           Naylor, James #1         11/01/23       N/A           N/A             4400         N/A





                                       50











                                     UEDC'S

                               GEOLOGIC EVALUATION

                                     FOR THE

                            CURRENTLY PROPOSED WELLS

                                       IN

                      WESTERN PENNSYLVANIA AND EASTERN OHIO











                                       51







                               GEOLOGIC EVALUATION
                ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP
                             CRAWFORD PROSPECT AREA
                                  PENNSYLVANIA

                             Dated: August 10, 2004





Program proposed by:

ATLAS RESOURCES, INC.
311 Rouser Road
P.O. Box 611
Moon Township, PA   15108



Report submitted by:

UEDC
United Energy Development Consultants, Inc.
1715 Crafton Blvd.
Pittsburgh, PA   15205

                         LOCATION MAP - AREA OF INTEREST

                                [OBJECT OMITTED]

                                TABLE OF CONTENTS

INVESTIGATION SUMMARY.........................................................2
         OBJECTIVE............................................................2
         AREA OF INVESTIGATION................................................2
         METHODOLOGY..........................................................2
PROSPECT AREA HISTORY.........................................................2
         DRILLING ACTIVITY....................................................2
         GEOLOGY..............................................................2
                  STRATIGRAPHY, LITHOLOGY & DEPOSITION........................2
                  RESERVOIR CHARACTERISTICS...................................3
         PRODUCTION...........................................................4
         CONCLUSION...........................................................5
         DISCLAIMER...........................................................5
         NON-INTEREST.........................................................5




                                       52



                              INVESTIGATION SUMMARY


OBJECTIVE

     The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Crawford Prospect Area as proposed by
Atlas Resources, Inc. ("Atlas").

AREA OF INVESTIGATION

     A portion of this prospect area, herein identified for drilling in ATLAS
AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP, contains acreage in East
Fallowfield and Sadsbury Townships of Crawford County, and Sandy Creek Township
of Mercer County, located in northwestern Pennsylvania. Eight (8) drilling
prospects will be designated for this program and will be targeted to produce
natural gas from Clinton-Medina Group reservoirs, found at an average depth
range of approximately 5,000 to 6,300 feet beneath the earth's surface over the
prospect area. These will be the only prospects evaluated for the purposes of
this report.

METHODOLOGY

     The data incorporated into this report was provided by Atlas and the
in-house archives of UEDC, Inc. Geological mapping and the interpretations by
Atlas geologists were also examined. Available "electric" log, completion, and
production data on "key" wells within and adjacent to the defined prospect area
were utilized to determine productive and depositional trends.

                              PROSPECT AREA HISTORY

DRILLING ACTIVITY

     The proposed drilling area lies within a region of northwestern
Pennsylvania which has been very active for the past decade in terms of
exploration for, and exploitation of natural gas reserves. Development within
and adjacent to the Crawford Prospect Area has escalated since 1986, with Atlas
and it's affiliates drilling over fourteen hundred (1400) wells during this
period. Atlas has encountered favorable drilling and production results while
solidifying a strong acreage position, and continues to identify and extend
productive trends. Drilling is ongoing as of the date of this report with recent
wells displaying favorable initial drilling and completion results. Competitive
activity has begun east of the prospect area, confirming the Clinton-Medina
Group of Lower Silurian age as a viable target for the further development of
producible quantities of natural gas.

GEOLOGY


     STRATIGRAPHY, LITHOLOGY & DEPOSITION

     Regionally, the Clinton-Medina Group was deposited in tide-dominated
shoreline, deltaic, and shelf environments and is lithologically comprised of
alternating sandstones, siltstones and shales. Productive sandstones are
composed of siliceous to dolomitic subarkoses, sublitharenites, and quartz
arenites. Reservoir quality sands occur throughout the delta-complex from
eastern Ohio through northwestern Pennsylvania and western New York. The
Clinton-Medina Group, deposited during the Lower Silurian, overlies the Upper
Ordovician age Queenston shale and is capped by the Middle Silurian Reynales
Formation. This dolomitic limestone "cap" is known locally to drillers as the
"Packer Shell".

     Stratigraphically, in descending order, the potentially productive units of
the Clinton-Medina Group consist of the: 1) Thorold, 2) Grimsby, 3) Cabot Head,
4) Whirlpool members. The diagram illustrates these stratigraphic relationships.

[OBJECT OMITTED]
                                       53


     The WHIRLPOOL is a light gray quartzose sandstone to siltstone ranging in
thickness from five (5) to twenty (20) feet. Average porosity values for this
sand member range from five (5) to ten (10) percent regionally. Within the area
of investigation, porosities in excess of twelve (12) percent occur within
localized trends targeted for further development.

     The CABOT HEAD is a dark green to black shale, most likely of marine
origin. Within the investigated area the CABOT HEAD SANDSTONE has been
encountered in numerous wells. This formation has been found to contribute
natural gas when reservoir characteristics, including evidence of enhanced
permeability, warrant completion. This sand member is considered a secondary
target.

     The GRIMSBY is the thickest sandstone member of the Clinton-Medina Group.
Sand development ranges from ten (10) to forty-five (45) feet within an interval
comprised of fine to very fine, light gray to red sandstones and siltstones
broken up by thin dark gray silty shale layers. Average porosity values for the
Grimsby are approximately six (6) to (10) percent over the pay interval
regionally. Permeability may be enhanced locally by the presence of naturally
occurring micro-fractures. Future development focuses on established production
trends.

     The THOROLD sandstone is the uppermost producing interval of the
Clinton-Medina sequence. This interbedded ferric sand, silt and shale interval
averages forty (40) to seventy (70) feet, from west to east in the prospect
area. Where pay sand development occurs, porosities are in the typical
Clinton-Medina group range of six (6) to (10) percent. Permeability may be
enhanced locally by the presence of naturally occurring micro-fractures.

RESERVOIR CHARACTERISTICS

     Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping natural gas of commercial quantities in a more permeable medium. In the
Clinton-Medina, this occurs either stratigraphically when a permeable sand
containing hydrocarbons encounters an impermeable shale or when a permeable sand
changes gradually into a non-permeable sand by a cementation process known as
"diagenesis". Thus, this type of trap represents cemented-in hydrocarbon
accumulations.

     Electric well logs can be used in conjunction with production to interpret
reservoir parameters. When sandstones in the Thorold, Grimsby, Cabot Head or
Whirlpool develop porosity in excess of 6%, or a bulk density of 2.55 or less,
the permeability of the reservoir (which ranges from less than 0.l to greater
than 0.2 mD) can become great enough to allow commercial production of natural
gas. Small, naturally occurring cracks in the formation, referred to as
micro-fractures, can also enhance permeability. A gamma, bulk density, density
porosity and neutron log suite showing sand development in the Grimsby, Cabot
Head and Whirlpool is illustrated. Two other phenomena detected by well logs can
occur which are indicators of enhanced permeability. These indicators used to
detect productive intervals are:

     o Mudcake buildup across the zone of interest - after loading the wellbore
with brine fluid and circulating, an interval with enhanced permeability will
accept fluid, filtering out the solids and leaving behind a buildup (or mudcake)
on the formation wall. This is detectable with a caliper log.

[OBJECT OMITTED]

                                       54

[OBJECT OMITTED]
     o Invasion profile - during circulation, a brine that has a high
conductivity (or low resistivity) that is accepted into the formation (as
described above) will change the electrical conductivity of the reservoir rock
near and around the wellbore. The resistivity will be low nearest to the
wellbore and will increase away from the wellbore. As shown in the example, a
dual laterolog can be used to detect this profile created by a permeable zone -
it records resistivity near the wellbore as well as deeper into the formation. A
zone with enhanced permeability will show a separation between the shallow and
deep laterologs, while a zone with little or no permeability would cause the two
resistivity measurements to read exactly the same.


PRODUCTION

     A model decline curve has been created based on the production histories
from approximately 900 wells drilled by Atlas and its programs in the adjacent
Mercer Fields. This model decline curve is consistent with the average estimated
decline curves for over 200 undeveloped well locations in the Mercer Field which
were used by Wright & Company, Inc., independent petroleum consultants, in
preparing Atlas' year 2000 reserve report. The model decline curve is
illustrated in the diagram below:

[OBJECT OMITTED]

     It is important to note that the model decline curve is intended only to
present how a well's production may decline from year to year, and does not
attempt to predict the average recoverable reserves per well.

     Also, the model decline curve is a forward-looking statement based on
certain assumptions and analyses of historical trends, current conditions and
expected future developments. The model decline curve is subject to a number of
risks and uncertainties including the risk that the wells are productive but do
not produce enough revenue to return the investment made and uncertainties
concerning the price of natural gas and oil. Actual results in this drilling
program will vary from the model decline curve, although a rapid decline in
production within the first several years can be expected.


                                       55



                                   STATEMENTS

CONCLUSION

     UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP, which will consist of
developmental drilling of the Clinton-Medina Group sands primarily in Crawford
and Mercer Counties, Pennsylvania. It is the professional opinion of UEDC that
the drilling of the eight (8) wells by ATLAS AMERICA PUBLIC #14-2004 LIMITED
PARTNERSHIP is supported by sufficient geologic and engineering data.

DISCLAIMER

     For the purpose of this evaluation, UEDC did not visit any leaseholds or
inspect any of the associated production equipment. Likewise, UEDC has no
knowledge as to the validity of title, liabilities, or corporate matters
affecting these properties. UEDC does not warrant individual well performance.

NON-INTEREST

     We hereby confirm that UEDC is an independent consulting firm and that
neither this firm or any of it's employees, contract consultants, or officers
has, or is committed to acquire any interest, directly or indirectly, in Atlas
Resources, Inc.; nor is this firm, or any employee, contract consultant, or
officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm
that neither the employment of, nor payment of compensation received by UEDC in
connection with this report, is on a contingent basis.

                                                      Respectfully submitted,

                                                            /s/ Robin Anthony
                                                                   UEDC, INC.







                                       56











                                LEASE INFORMATION

                                       FOR

                  ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA




                                       57


















                                                                          OVERRIDING
                                                                           ROYALTY
                                                                           INTEREST  OVERRIDING                             ACRES
                                                                            TO THE     ROYALTY                             TO BE
                                                                           MANAGING   INTEREST     NET                    ASSIGNED
                                          EFFECTIVE  EXPIRATION LANDOWNER  GENERAL     TO 3RD    REVENUE   WORKING  NET    TO THE
   PROSPECT NAME              COUNTY        DATE*      DATE*     ROYALTY   PARTNER     PARTIES  INTEREST  INTEREST ACRES PARTNERSHIP
   -------------              ------        -----      -----     -------   -------     -------  --------  -------- ----- -----------
1  Bieda #4                Westmoreland   07/09/03    07/09/06    12.5%       0%       3.125%    63.281%     75%    162     14.60
2  Bieda #5                Westmoreland   07/09/03    07/09/06    12.5%       0%       3.125%    63.281%     75%    162     14.60
3  United Railroad Corp #1   Indiana      11/01/03    11/01/05    12.5%       0%       3.125%    63.281%     75%     68     14.60
4  Lytle #12                Armstrong     01/22/01    01/22/04    12.5%       0%       3.125%    63.281%     75%     98     14.60
5  Deforno #3                Indiana      04/08/02    04/08/03    12.5%       0%       3.125%    63.281%     75%     77     14.60
6  Deforno #4                Indiana      04/08/02    04/08/03    12.5%       0%       3.125%    63.281%     75%     77     14.60
7  M. White #4              Armstrong     12/01/02    12/01/03    12.5%       0%       3.125%    63.281%     75%     87     14.60
8  M. Filippini #1          Armstrong     07/27/04    07/27/07    12.5%       0%       3.125%    63.281%     75%     28     14.60





                                       58









                           LOCATION AND PRODUCTION MAP

                                       FOR

                  ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA




                                       59


                            [GRAPHIC OF MAP OMITTED]




                                       60




                                 PRODUCTION DATA

                                       FOR

                  ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA







                                       61



The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.




                                                                                           TOTAL MCF THROUGH     TOTAL
                                                                                  MOS ON    6/30/04 EXCEPT      LOGGERS  LATEST 30
ID NUMBER  OPERATOR                    WELL NAME               DATE COMPLT'D       LINE      WHERE NOTED         DEPTH   DAY PROD.
- ---------  --------                    ---------               -------------       ----      -----------         -----   ---------
  02368    Dominion Peoples            Wray, Et. Al. #1           5/3/1921          NA      251,497/1992         3096       NA
  20128    Dominion Peoples            Martin #1                 1/14/1958          NA      205,767/1992         3134       NA
  20154    Dominion Peoples            Kerr #1                    6/3/1958          NA      203,046/1992         3229       NA
  20222    Dominion Peoples            Deemer #2           2/26/1896 / 12/3/1958    NA      251,637/1992      1584/ 3386    NA
  20600    Dominion Peoples            Geiger #2                 10/10/1963         NA      305,774/1992         3457       NA
  20768    Dominion Peoples            Chambers #2                7/9/1965          NA      243,610/1992         3604       NA
  20957    Dominion Peoples            Chambers #1               3/19/1968          NA      579,140/1992         3630       NA
  25760    Petroleum Development
               Corp. (JV USEE)         Becker #2                  5/8/1998          25         48,880            3510      1890
  26070    Petroleum Development
               Corp. (JV USEE)         Egley #1                   10/30/00           7         12,800            1240      1830
  26078    Petroleum Development
               Corp. (JV USEE)         Kleintop #1                12/20/98           7         10,620            3700      1440
  26090    Petroleum Development
               Corp. (JV USEE)         Ott #1                    1/19/1999          18         31,000            3580      1650
  26091    Petroleum Development
               Corp. (JV USEE)         Becker #3                 9/22/1999          10         19,660            3500      1860
  26093    Petroleum Development
               Corp. (JV USEE)         Ott #2                     9/8/1999          10         18,330            3580      1830
  26102    Petroleum Development
               Corp. (JV USEE)         Hollabaugh #1              02/18/99           5          9,760            3620      1890
  26108    Petroleum Development
               Corp. (JV USEE)         Wilson #2                 3/15/1999          14         19,400            3620      1350
  26127    Petroleum Development
               Corp. (JV USEE)         Kiski Sportsmen #2        4/15/1999          14         43,010            3680      2700
  26141    Petroleum Development
               Corp. (JV USEE)         Kiski Sportsmen #3        6/23/1999          12         26,940            3893      1920
  26157    Petroleum Development
               Corp. (JV USEE)         M. Couch #1               7/10/1999          12         28,440            3710      2160
  26172    Petroleum Development
               Corp. (JV USEE)         Ott #4                    9/13/1999          10         22,070            3500      2130
  26173    Petroleum Development
               Corp. (JV USEE)         Ott #3                    9/16/1999          10         16,420            3560      1470
  26188    Petroleum Development
               Corp. (JV USEE)         Kiski Sportsmen #4        9/25/1999          10         17,250            3750      1740
  26201    Petroleum Development
               Corp. (JV USEE)         Kiski Sportsmen #5        11/21/1999          6         13,300            3734      2040
  26208    Petroleum Development
               Corp. (JV USEE)         Walker #1                 12/1/1999           6          9,920            4090      1530
  26216    Petroleum Development
               Corp. (JV USEE)         Allshouse #1              12/30/1999          7         14,190            3560      1950
  26220    Petroleum Development
               Corp. (JV USEE)         Shearer #1                 3/4/2000           6         14,580            4068      2280
  26221    Petroleum Development
               Corp. (JV USEE)         Shearer #2                 3/5/2000           4          7,550            4040      1800
  26222    Petroleum Development
               Corp. (JV USEE)         G. Couch #1               3/10/2000           4          8,160            4070      2040
  26224    Petroleum Development
               Corp. (JV USEE)         Walker #4                  3/3/2000           4         14,100            4080      2910
  26225    Petroleum Development
               Corp. (JV USEE)         Walker #2                  3/2/2000           4          9,540            4100      1890
  26234    Petroleum Development
               Corp. (JV USEE)         Stankay #1                 3/6/2000           4          7,320            4100      1560
  26255    Petroleum Development
               Corp. (JV USEE)         Stankay #2                 3/7/2000           4          7,900            4098      1680
  26374    US Energy Exploration
               (JV Atlas)              Sturiale #1                2/6/2002          27          2,208            3866       22
  26426    US Energy Exploration
               (JV Atlas)              Bafik #2                   3/9/2002          26         15,364            3904       324





                                       62



The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.




                                                                                           TOTAL MCF THROUGH     TOTAL
                                                                                  MOS ON    6/30/04 EXCEPT      LOGGERS  LATEST 30
ID NUMBER  OPERATOR                    WELL NAME               DATE COMPLT'D       LINE      WHERE NOTED         DEPTH   DAY PROD.
- ---------  --------                    ---------               -------------       ----      -----------         -----   ---------
  26427    US Energy Exploration
               (JV Atlas)              Canterbury #4              5/8/2001          36         44,097            3696       962
  26431    US Energy Exploration
               (JV Atlas)              Canterbury #8              5/9/2001          36         23,261            3876       391
  26437    US Energy Exploration
               (JV Atlas)              Canterbury #12            4/30/2001          36         22,170            3791       237
  26438    US Energy Exploration
               (JV Atlas)              Canterbury #13            4/30/2001          36         11,170            3908       247
  26439    US Energy Exploration
               (JV Atlas)              Canterbury #15            7/10/2001          34          6,437            3776       167
  26440    US Energy Exploration
               (JV Atlas)              Canterbury #17            7/10/2001          34          8,627            3802       255
  26442    US Energy Exploration
               (JV Atlas)              Canterbury #20            5/22/2001          35         35,179            3944       705
  26455    US Energy Exploration
               (JV Atlas)              Canterbury #21            10/29/2001         30         22,944            3805       468
  26458    US Energy Exploration
               (JV Atlas)              Canterbury #3              5/7/2001          36         15,079            3701       208
  26557    US Energy Exploration
               (JV Atlas)              Barr #2                    8/9/2001          33         36,152            3868       861
  26558    US Energy Exploration
               (JV Atlas)              Barr #3                   8/25/2001          32         57,998            3898      1746
  26561    US Energy Exploration
               (JV Atlas)              Schrecengost #2           10/29/2001         30         16,720            3750       337
  26562    US Energy Exploration
               (JV Atlas)              Schrecengost #3           11/6/2001          30         15,534            3777       296
  26566    US Energy Exploration
               (JV Atlas)              P. White #1               11/16/2001         29         10,182            3950       530
  26596    US Energy Exploration
               (JV Atlas)              G. Couch #3               4/24/2002          24          5,714            4053       174
  26598    US Energy Exploration
               (JV Atlas)              G. Couch #5               4/24/2002          24          6,723            4355       175
  26600    US Energy Exploration
               (JV Atlas)              Dobrosky #2               10/10/2001         31         36,540            3752       801
  26621    US Energy Exploration
               (JV Atlas)              Canterbury #27            10/10/2001         31         49,072            3861      1057
  26622    US Energy Exploration
               (JV Atlas)              Canterbury #28            10/10/2001         31         56,039            3814      1635
  26625    US Energy Exploration
               (JV Atlas)              Barr #4                   10/18/2001         30         37,271            3804       834
  26627    US Energy Exploration
               (JV Atlas)              Wilson #4                 10/10/2001         31         45,375            3802      1225
  26663    US Energy Exploration
               (JV Atlas)              Crewe #1                  12/31/2001         28         48,901            4058      1084
  26669    US Energy Exploration
               (JV Atlas)              R. White #1               11/16/2001         29          8,153            4062       189
  26679    US Energy Exploration
               (JV Atlas)              Canterbury #30            1/12/2002          28         42,320            4151      1169
  26680    US Energy Exploration
               (JV Atlas)              Canterbury #34            2/18/2002          26         28,224            4220       691
  26681    US Energy Exploration
               (JV Atlas)              Canterbury #31            1/29/2002          27         28,758            4212       646
  26723    US Energy Exploration
               (JV Atlas)              Bernabo #1                1/15/2002          27          9,209            4250       264
  26730    US Energy Exploration
               (JV Atlas)              Canterbury #32            7/10/2002          22         22,544            4195       551
  26741    US Energy Exploration
               (JV Atlas)              Crewe #4                  8/16/2002          20         40,031            4153      1813
  26742    US Energy Exploration
               (JV Atlas)              Musser #1                 2/11/2002          27          5,073            4296       174
  26743    US Energy Exploration
               (JV Atlas)              Filippini #2               2/2/2002          27         13,996            3882       327





                                       63



The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.




                                                                                           TOTAL MCF THROUGH     TOTAL
                                                                                  MOS ON    6/30/04 EXCEPT      LOGGERS  LATEST 30
ID NUMBER  OPERATOR                    WELL NAME               DATE COMPLT'D       LINE      WHERE NOTED         DEPTH   DAY PROD.
- ---------  --------                    ---------               -------------       ----      -----------         -----   ---------
  26756    US Energy Exploration
               (JV Atlas)              P. White #4               2/25/2002          26          5,210            4281       154
  26758    US Energy Exploration
               (JV Atlas)              Crewe #5                  2/12/2002          27         52,663            4156      2120
  26788    US Energy Exploration
               (JV Atlas)              Pomfret #1                3/29/2002          25         26,949            3817       515
  26824    US Energy Exploration
               (JV Atlas)              Stankay #5                 1/9/2003          16          3,217            4037       242
  26827    US Energy Exploration
               (JV Atlas)              Boggs #6                   1/3/2003          16         19,590            4104       717
  26828    US Energy Exploration
               (JV Atlas)              Boggs #7                  9/28/2002          19         38,096            4219      1764
  26833    US Energy Exploration
               (JV Atlas)              Boggs #4                  8/16/2002          20         18,362            4220       564
  26844    US Energy Exploration
               (JV Atlas)              Filippini #3               1/9/2003          16         20,177            3879      1174
  26865    US Energy Exploration
               (JV Atlas)              Rumbaugh #1               11/14/2002         18          9,399            4600       317
  26973    US Energy Exploration
               (JV Atlas)              Andree #3                 2/28/2003          14          7,143            4121       748
  27024    US Energy Exploration
               (JV Atlas)              Wheatley #1                2/6/2003          15         10,959            4211      2673
  27040    US Energy Exploration
               (JV Atlas)              Pomfret #2                3/28/2003          13          9,301            3822       467
  27044    US Energy Exploration
               (JV Atlas)              Rumbaugh #2               3/26/2003          13         14,845            3808       686
  27126    US Energy Exploration
               (JV Atlas)              Andree #2                 3/14/2003          14         10,584            3790      1069
  27127    US Energy Exploration
               (JV Atlas)              Wheatley #3                3/6/2003          14         13,662            4273      2139
  32288    Petroleum Development
               Corp. (JV USEE)         R. Henderson #1            7/1/1999           7         17,230            5213      2400
  32418    Petroleum Development
               Corp. (JV USEE)         C. Coleman #1              3/8/2000           4          6,960            4220      1650
  32475    Petroleum Development
               Corp. (JV USEE)         C. Coleman #2              3/9/2000           4          7,100            4401      1590
  33016    US Energy Exploration
               (JV Atlas)              Henderson #3               5/8/2002          24         25,257            4502       692
  33042    US Energy Exploration
               (JV Atlas)              Rosensteel #5             4/24/2002          24         33,389            4325      1051
  33152    US Energy Exploration
               (JV Atlas)              Graham #1                 2/12/2003          15         21,417            4336       881
  33155    US Energy Exploration
               (JV Atlas)              Boggs #9                  1/31/2003          15         28,661            4393      1412
  33157    US Energy Exploration
               (JV Atlas)              Boggs #11                 1/27/2003          15         14,005            4361       858
  33159    US Energy Exploration
               (JV Atlas)              Shearer #4                2/11/2003          15         12,564            4314       786
  33202    US Energy Exploration
               (JV Atlas)              J. Henderson #1           1/15/2003          15         14,990            4456       602
  33273    US Energy Exploration
               (JV Atlas)              Kapusta #2                1/31/2003          15          5,832            4280       471
  33274    US Energy Exploration
               (JV Atlas)              Bosch #2                  1/21/2003          15         11,036            4392       484
  33288    US Energy Exploration
               (JV Atlas)              Kapusta #1                3/13/2003          14         10,115            4202       811
  33305    US Energy Exploration
               (JV Atlas)              Bosch #4                  3/21/2003          13         16,886            4460       995
  33306    US Energy Exploration
               (JV Atlas)              Bosch #5                  3/29/2003          13          9,718            4388       489
  33313    US Energy Exploration
               (JV Atlas)              Speranza #2                3/6/2003          14          7,389            4270       507



                                       64










                                     UEDC'S

                               GEOLOGIC EVALUATION

                                     FOR THE

                            CURRENTLY PROPOSED WELLS

                                       IN

                  ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA









                                       65






                               GEOLOGIC EVALUATION
                ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP
                             ARMSTRONG PROSPECT AREA
                                  PENNSYLVANIA

                             Dated: August 10, 2004






Program proposed by:

ATLAS RESOURCES, INC.
311 Rouser Road
P.O. Box 611
Moon Township, PA   15108


Report submitted by:

UEDC
United Energy Development Consultants, Inc.
1715 Crafton Blvd.
Pittsburgh, PA   15205



                         LOCATION MAP - AREA OF INTEREST


                                [OBJECT OMITTED]

                                TABLE OF CONTENTS

  LOCATION MAP  -  AREA OF INTEREST..........................................1
  TABLE OF CONTENTS..........................................................1
  INVESTIGATION SUMMARY......................................................2
           OBJECTIVE.........................................................2
           AREA OF INVESTIGATION.............................................2
           METHODOLOGY.......................................................2
  ARMSTRONG PROSPECT AREA....................................................2
           DRILLING ACTIVITY.................................................2
           GEOLOGY...........................................................2
                    STRATIGRAPHY, LITHOLOGY & DEPOSITION.....................2
                    RESERVOIR CHARACTERISTICS................................4
           PRODUCTION........................................................4
  STATEMENTS.................................................................5
           CONCLUSION........................................................5
           DISCLAIMER........................................................5
           NON-INTEREST......................................................5


                                       66




                              INVESTIGATION SUMMARY

OBJECTIVE

     The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Armstrong Prospect Area as proposed
by Atlas Resources, Inc. ("Atlas").

AREA OF INVESTIGATION

     A portion of this prospect area, herein identified for drilling in ATLAS
AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP, contains acreage in Kiskiminetas
Township of Armstrong County, Conemaugh Township of Indiana County, and Bell
Township of Westmoreland County, located in western Pennsylvania. Eight (8)
drilling prospects have currently been designated for this program in the
prospect area, which will be targeted to produce natural gas from Upper Devonian
reservoirs, found at depths from 1800 feet to 4500 feet beneath the earth's
surface. These will be the only prospects evaluated for the purposes of this
report.

METHODOLOGY

     Atlas and the in-house archives of UEDC, Inc. provided the data
incorporated into this report. Geological mapping and the interpretations by
Atlas geologists were also examined. Available "electric" log, completion and
production data on "key" wells within and adjacent to the defined prospect area
were used to determine productive and depositional trends.


                             ARMSTRONG PROSPECT AREA

DRILLING ACTIVITY

     The proposed drilling area lies within a region of southwestern
Pennsylvania, which has seen sporadic activity for more than the past 150 years
in terms of exploration for, and exploitation of natural gas reserves. Modern
development within and adjacent to the Armstrong Prospect Area has continued
steadily since 1950. Over 1500 wells have been drilled in the area during this
period. Atlas has entered into a Joint Venture relationship with US Energy
Exploration. Located in Rural Valley, Pennsylvania (which is less than 20 miles
from the prospect area), US Energy is a local oil and gas producer with more
than 15 years experience developing this play and currently operates over 325
wells within and adjacent to the prospect area. US Energy currently maintains an
acreage position of over 14,000 acres. Within the prospect, Atlas and its
partner adhere to the state regulations for spacing of wells in areas of deep
coal mining, which is one thousand (1000) feet in most cases. Atlas continues to
identify and extend productive trends. Drilling is ongoing as of the date of
this report with recent wells displaying favorable initial drilling and
completion results.

GEOLOGY

     STRATIGRAPHY, LITHOLOGY & DEPOSITION

     In southern Armstrong County the Upper Devonian Bradford Group reservoirs
are typically characterized as submarine fan deposits. They are thought to have
traveled westward (seaward) down slope from sands deposited out in front of
massive deltas throughout Indiana and surrounding counties. The Bradford Group
consists of the Lower Warren Sand; Upper and Lower Speechley Sands; Upper,
Middle, and Lower Balltown Sands and the First Bradford Sand.


                                       67



[OBJECT OMITTED]

     Stratigraphically, in descending order, the potentially productive units of
the Upper Devonian Groups are: Hundred Foot, Gordon, Fifth, Bayard, Lower
Warren, Upper Speechley, Lower Speechley, Upper Balltown, Middle Balltown, Lower
Balltown, and First Bradford sands. These stratigraphic relationships are
illustrated in the diagram.

     The HUNDRED FOOT SAND is the shallowest sand of Devonian age encountered in
this area. This sand is highly variable in its thickness and porosity
development. Often it is in excess of one hundred (100) feet thick with
porosities in excess of 18%. Frequently it is accompanied by gas shows and it is
used as a gas storage reservoir just to the north of the acreage. Due to its
shallow depth and attendant lower pressure this zone is not treated or
commingled with the deeper reservoirs found in the play area. However, this zone
has the potential for a producible natural completion and is considered a
secondary target.

     The GORDON SAND appears sporadic across the play area and ranges in
thickness from nearly ten (10) feet to twenty (20) feet. Porosities range from
6% to about 10%. This sand is considered a secondary target.

     The FIFTH SAND ranges in thickness from a few feet to thirty (30) feet.
Porosity values are typically 5% to 12%. This sand is considered a secondary
target.

     The BAYARD SAND in the prospect area ranges in thickness from a few feet to
more than thirty (30) feet. Porosity values range from 8% to 18% for this
sandstone. This sand is also considered a secondary target.

     The WARREN SANDS are a primary target when encountered in the prospect
area. Typically the lower portion of the Warren interval is better developed.
When sand is present in this interval the average thickness ranges from several
feet to over thirty (30) feet. Porosities range between 6% and 12% in the area.

     The SPEECHLEY SANDS are considered both primary and secondary targets
depending on where in the play area they are encountered. Present are an upper
and lower sand separated by fifty (50) to seventy-five (75) feet of shale. The
upper sand thickness ranges from just a few feet to more than twenty (20) feet
and porosity typically ranges from 5% to 12%. Meanwhile the lower sand is
usually twenty (20) feet to forty (40) feet thick with porosities that are often
between 5% to 12%.

     The BALLTOWN SANDS have limited extent throughout the project area.
Generally sand development in the upper portion of the Balltown interval is most
favorable and when encountered is typically fifteen (15) feet thick with
porosities as high as 20%. This sand is often accompanied by a gas show and is
thought to be a significant producer. In areas where this sand is more prevalent
it is considered a primary target, but is found sporadically across the play
area. Sand development in other portions of this interval are also limited in
extent but are treated when encountered.

     The FIRST BRADFORD SAND is the primary target in all wells in this
immediate area. This sand is present in every well drilled thus far on the
acreage. The First Bradford sand will generally range from ten (10) feet in
thickness to over thirty-five (35) feet in several distinct trends. Porosities
typically range from 8% to 14%. This sand is nearly always accompanied by a gas
show. Occasionally, a deeper sand, the Second Bradford sand, develops seventy
(70) to one hundred (100) feet below the First Bradford. When warranted, this
sand is also completed.

                                       68





     RESERVOIR CHARACTERISTICS

     Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping commercial quantities of natural gas in a more permeable medium. In the
Upper Devonian reservoirs, this occurs either stratigraphically when a permeable
sand containing hydrocarbons encounters impermeable shale or when permeable sand
changes gradually into non-permeable sand by a cementation process known as
"diagenesis". Thus, this type of trap represents cemented-in hydrocarbon
accumulations.

[OBJECT OMITTED]

     Electric well logs can be used in conjunction with production to interpret
reservoir parameters. When sandstones in the Upper Devonian reservoirs develop
porosity in excess of 8%, or a bulk density of 2.50 or less, the permeability of
the reservoir can become great enough to allow commercial production of natural
gas. Small, naturally occurring cracks in the formation, referred to as
micro-fractures, can also enhance permeability. A gamma, bulk density, neutron,
induction and temperature log suite showing sand development in an Upper
Devonian reservoir is illustrated at left.

     The temperature log shown in the illustration at left identifies where gas
is entering the wellbore. Evidence of a temperature "kick" or cooling is also an
indication of enhanced permeability and the willingness of the reservoir to
produce natural gas.






PRODUCTION

     The Armstrong prospect area produces from several reservoirs of different
age and type. Each well has a unique combination of these reservoirs yielding
different production declines. While Atlas anticipates production from each
reservoir to be comparable to like reservoirs historically produced throughout
the Appalachian Basin, a model decline curve for this prospect area is not
included due to the multiple sets of commingled reservoirs exclusively found in
this area.



                                       69






                                   STATEMENTS


CONCLUSION

UEDC has conducted a geologic feasibility study of the drilling area for ATLAS
AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP, which will consist of developmental
drilling of Upper Devonian reservoirs in Armstrong, Indiana and Westmoreland
Counties, Pennsylvania. It is the professional opinion of UEDC that the drilling
of the eight (8) wells by ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP is
supported by sufficient geologic and engineering data.

DISCLAIMER

     For the purpose of this evaluation, UEDC did not visit any leaseholds or
inspect any of the associated production equipment. Likewise, UEDC has no
knowledge as to the validity of title, liabilities, or corporate matters
affecting these properties. UEDC does not warrant individual well performance.

NON-INTEREST

     We hereby confirm that UEDC is an independent consulting firm and that
neither this firm or any of it's employees, contract consultants, or officers
has, or is committed to acquire any interest, directly or indirectly, in Atlas
Resources, Inc.; nor is this firm, or any employee, contract consultant, or
officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm
that neither the employment of, nor payment of compensation received by UEDC in
connection with this report, is on a contingent basis.

                                                  Respectfully submitted,

                                                        /s/ Robin Anthony
                                                               UEDC, INC.






                                       70






                                LEASE INFORMATION

                                       FOR

                           MCKEAN COUNTY, PENNSYLVANIA




                                       71









                                                                        OVERRIDING
                                                                         ROYALTY
                                                                         INTEREST OVERRIDING                                ACRES
                                                                          TO THE    ROYALTY                                 TO BE
                                                                         MANAGING  INTEREST     NET                        ASSIGNED
                                      EFFECTIVE  EXPIRATION   LANDOWNER  GENERAL    TO 3RD    REVENUE    WORKING   NET      TO THE
   PROSPECT NAME            COUNTY      DATE*       DATE*      ROYALTY    PARTNER   PARTIES   INTEREST  INTEREST  ACRES  PARTNERSHIP
   -------------            ------      -----       -----      -------    -------   -------   --------  --------  -----  -----------
 1  Claypit #1             McKean    6/7/2004    12/7/2005       15%        0%         0%        85%      100%      90        5
 2  Claypit #2             McKean    6/7/2004    12/7/2005       15%        0%         0%        85%      100%      90        5
 3  Claypit #3             McKean    6/7/2004    12/7/2005       15%        0%         0%        85%      100%      90        5
 4  Claypit #4             McKean    6/7/2004    12/7/2005       15%        0%         0%        85%      100%      90        5
 5  Claypit #5             McKean    6/7/2004    12/7/2005       15%        0%         0%        85%      100%      90        5
 6  Gates #1               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
 7  Gates #2               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
 8  Gates #3               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
 9  Gates #4               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
10  Gates #5               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
11  Gates #6               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
12  Gates #7               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
13  Gates #8               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
14  Gates #9               McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
15  Gates #10              McKean    7/2/2004    7/2/2006       12.5%       0%         0%       87.5%     100%     233        5
16  Thompson #1            McKean   6/24/2004    6/24/2007      12.5%       0%         0%       87.5%     100%      51        5
17  Thompson #2            McKean   6/24/2004    6/24/2007      12.5%       0%         0%       87.5%     100%      51        5
18  Thompson #3            McKean   6/24/2004    6/24/2007      12.5%       0%         0%       87.5%     100%      51        5
19  Thompson #4            McKean   6/24/2004    6/24/2007      12.5%       0%         0%       87.5%     100%      51        5
20  Thompson #5            McKean   6/24/2004    6/24/2007      12.5%       0%         0%       87.5%     100%      51        5
21  Young-Kane #1          McKean   10/31/2003  10/31/2013      12.5%       0%         0%       87.5%     100%    2,432       5
22  Young-Kane #2          McKean   10/31/2003  10/31/2013      12.5%       0%         0%       87.5%     100%    2,432       5
23  Young-Kane #3          McKean   10/31/2003  10/31/2013      12.5%       0%         0%       87.5%     100%    2,432       5
24  Young-Kane #4          McKean   10/31/2003  10/31/2013      12.5%       0%         0%       87.5%     100%    2,432       5
25  Young-Kane #5          McKean   10/31/2003  10/31/2013      12.5%       0%         0%       87.5%     100%    2,432       5


*HBP - Held by Production.




                                       72






                           LOCATION AND PRODUCTION MAP

                                       FOR

                           MCKEAN COUNTY, PENNSYLVANIA





                                       73






                            [GRAPHIC OF MAP OMITTED]



                                       74








                            [GRAPHIC OF MAP OMITTED]





                                       75






                            [GRAPHIC OF MAP OMITTED]





                                       76







                                 PRODUCTION DATA

                                       FOR

                           MCKEAN COUNTY, PENNSYLVANIA




                                       77




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.


                                                                                                               TOTAL
                                                                       DATE     PRODUCTION      TOTAL MCF     LOGGERS      LATEST 30
ID NUMBER      OPERATOR                  WELL NAME        MAP REF.  COMPLETED     PERIOD        GAS EQUIV.     DEPTH       DAY PROD.
- ---------      --------                  ---------        --------  ---------   -------------   ----------     -----       ---------
          M & M Royalty, LTD.           Crowl Meter           A           -     1/03 - 6/03      26,655**          -           NA
  48651   M & M Royalty, LTD.            Crowl #1                        NA           -             *             NA            -
  48653   M & M Royalty, LTD.            Crowl #3                        NA           -             *             NA            -
  48654   M & M Royalty, LTD.            Crowl #4                        NA           -             *             NA            -
          M & M Royalty, LTD.     Bradford Airport Meter      B           -     1/03 - 6/03      63,150**          -           NA
  48672   M & M Royalty, LTD.       Bradford Airport #1                  NA           -             *             NA            -
  48661   M & M Royalty, LTD.       Bradford Airport #2                  NA           -             *             NA            -
  48662   M & M Royalty, LTD.       Bradford Airport #3                  NA           -             *             NA            -
  48663   M & M Royalty, LTD.       Bradford Airport #4                  NA           -             *             NA            -
  48664   M & M Royalty, LTD.       Bradford Airport #5                  NA           -             *             NA            -
  48856   M & M Royalty, LTD.       Bradford Airport #6                  NA           -             *             NA            -
  48857   M & M Royalty, LTD.       Bradford Airport #7                  NA           -             *             NA            -
  48858   M & M Royalty, LTD.       Bradford Airport #8                  NA           -             *             NA            -
  48859   M & M Royalty, LTD.       Bradford Airport #9                  NA           -             *             NA            -
  48860   M & M Royalty, LTD.      Bradford Airport #10                  NA           -             *             NA            -
          M & M Royalty, LTD.       Big Shanty E. Meter       C           -     9/02 - 6/03      60,435**          -           NA
  48837   M & M Royalty, LTD.        Big Shanty E. #1                    NA           -             *             NA            -
  48838   M & M Royalty, LTD.        Big Shanty E. #2                    NA           -             *             NA            -
  48836   M & M Royalty, LTD.        Big Shanty E. #3                    NA           -             *             NA            -
          Atlas America, Inc.          Messer Meter           D           -     1/04 - 6/04     101,119**          -         13,608
  48783   Atlas America, Inc.            Messer #4                    09/15/03        -             *            2161           -
  48786   Atlas America, Inc.            Messer #7                    09/17/03        -             *            2246           -
  48787   Atlas America, Inc.            Messer #8                    10/17/03        -             *            2116           -
  48788   Atlas America, Inc.            Messer #9                    11/04/03        -             *            2253           -
  48789   Atlas America, Inc.           Messer #10                    10/30/03        -             *            2252           -
  48790   Atlas America, Inc.           Messer #11                    09/20/03        -             *            2260           -
  48791   Atlas America, Inc.           Messer #12                    10/15/03        -             *            2180           -
  48792   Atlas America, Inc.           Messer #13                    11/05/03        -             *            2253           -




                                       78




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.



                                                                                                               TOTAL
                                                                       DATE     PRODUCTION      TOTAL MCF     LOGGERS      LATEST 30
ID NUMBER      OPERATOR                  WELL NAME        MAP REF.  COMPLETED     PERIOD        GAS EQUIV.     DEPTH       DAY PROD.
- ---------      --------                  ---------        --------  ---------   -------------   ----------     -----       ---------
  48793   Atlas America, Inc.           Messer #14                    10/27/03        -             *            2240           -
  48794   Atlas America, Inc.           Messer #15                    10/13/03        -             *            2219           -
  48795   Atlas America, Inc.           Messer #17                    10/23/03        -             *            2238           -
  48796   Atlas America, Inc.           Messer #18                    09/23/03        -             *            2248           -
  48797   Atlas America, Inc.           Messer #19                    10/09/03        -             *            2230           -
  48798   Atlas America, Inc.           Messer #22                    10/21/03        -             *            2212           -
          Atlas America, Inc.       Big Shanty E. Meter       E           -     1/04 - 6/04      36,820**          -         6,675
  48832   Atlas America, Inc.        Big Shanty E. #9                 10/01/03        -             *            2157           -
  48833   Atlas America, Inc.        Big Shanty E. #10                09/29/03        -             *            2162           -
  48834   Atlas America, Inc.        Big Shanty E. #11                09/12/03        -             *            2251           -
  48835   Atlas America, Inc.        Big Shanty E. #12                09/25/03        -             *            2197           -
          Atlas America, Inc.     Bradford Airport Meter      F           -     4/04 - 6/04      13,435**          -         9,457
  49406   Atlas America, Inc.      Bradford Airport #16               02/06/04        -             *            1946           -
  49404   Atlas America, Inc.      Bradford Airport #17               02/10/04        -             *            1950           -
  49405   Atlas America, Inc.      Bradford Airport #18               01/27/04        -             *            1944           -
  49403   Atlas America, Inc.      Bradford Airport #19               02/02/04        -             *            1944           -
  49402   Atlas America, Inc.      Bradford Airport #20               02/04/04        -             *            1944           -
  49164   Atlas America, Inc.      Bradford Airport #21               12/31/03        -             *            1950           -
  49165   Atlas America, Inc.      Bradford Airport #22               01/03/04        -             *            1950           -
  49166   Atlas America, Inc.      Bradford Airport #23               01/06/04        -             *            1950           -
  49167   Atlas America, Inc.      Bradford Airport #24               01/08/04        -             *            1950           -
  49168   Atlas America, Inc.      Bradford Airport #25               01/12/04        -             *            1950           -
          Atlas America, Inc.          Miller Meter           G           -         6/04          973**            -          973
  49318   Atlas America, Inc.            Miller #1                    01/30/04        -             *            1944           -
  49319   Atlas America, Inc.            Miller #2                    02/03/04        -             *            1954           -
  49320   Atlas America, Inc.            Miller #3                    02/05/04        -             *            1950           -
  49321   Atlas America, Inc.            Miller #4                    02/09/04        -             *            1952           -




                                       79




The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.



                                                                                                  TOTAL
                                                                       DATE     PRODUCTION      TOTAL MCF     LOGGERS      LATEST 30
ID NUMBER      OPERATOR                  WELL NAME        MAP REF.  COMPLETED     PERIOD        GAS EQUIV.     DEPTH       DAY PROD.
- ---------      --------                  ---------        --------  ---------   -------------   ----------     -----       ---------
  49322   Atlas America, Inc.            Miller #5                    02/11/04        -             *            1954           -
  49488   Atlas America, Inc.            Miller #6                    03/20/04        -             *            1954           -
  49475   Atlas America, Inc.            Miller #7                    03/23/04        -             *            1953           -
  49476   Atlas America, Inc.            Miller #8                    03/25/04        -             *            1952           -
  49477   Atlas America, Inc.            Miller #9                    03/27/04        -             *            1954           -
  49478   Atlas America, Inc.           Miller #10                    03/30/04        -             *            1952           -




* Individual well production is not monitored, production is combined with other
wells and measured at one meter site. Actual production from individual wells
could be considerably different.

** Value represents the combined production from multiple wells.




                                       80






                                     UEDC'S

                               GEOLOGIC EVALUATION

                                     FOR THE

                            CURRENTLY PROPOSED WELLS

                                       IN

                           MCKEAN COUNTY, PENNSYLVANIA








                                       81



                               GEOLOGIC EVALUATION
                ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP
                              MCKEAN PROSPECT AREA
                                  PENNSYLVANIA

                             Dated: August 10, 2004




Program proposed by:

ATLAS RESOURCES, INC.
311 Rouser Road
P.O. Box 611
Moon Township, PA   15108



Report submitted by:

UEDC
United Energy Development Consultants, Inc.
1715 Crafton Blvd.
Pittsburgh, PA   15205



                         LOCATION MAP - AREA OF INTEREST

                                [GRAPHIC OMITTED]

                                TABLE OF CONTENTS

LOCATION MAP  -  AREA OF INTEREST.............................................1
TABLE OF CONTENTS.............................................................1
         OBJECTIVE............................................................2
         AREA OF INVESTIGATION................................................2
         METHODOLOGY..........................................................2
MCKEAN PROSPECT AREA..........................................................2
         DRILLING ACTIVITY....................................................2
         GEOLOGY..............................................................2
                  STRATIGRAPHY, LITHOLOGY & DEPOSITION........................2
                  RESERVOIR CHARACTERISTICS...................................3
         PRODUCTION...........................................................3
STATEMENTS....................................................................4
         CONCLUSION...........................................................4
         DISCLAIMER...........................................................4
         NON-INTEREST.........................................................4

                                       82





                              INVESTIGATION SUMMARY


OBJECTIVE

     The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the McKean Prospect Area as proposed by
Atlas Resources, Inc. ("Atlas").

AREA OF INVESTIGATION

     A portion of this prospect area, herein identified for drilling IN ATLAS
AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP, contains acreage in Lafayette and
Hamlin Townships of McKean County, Pennsylvania. Twenty-five (25) drilling
prospects have currently been designated for this program in the prospect area,
which will be targeted to produce oil and natural gas from Upper Devonian
reservoirs, found at depths from 1200 feet to 2500 feet beneath the earth's
surface. These will be the only prospects evaluated for the purposes of this
report.

METHODOLOGY

     Atlas and the in-house archives of UEDC, Inc. provided the data
incorporated into this report. Geological mapping and the interpretations by
Atlas geologists were also examined. Available "electric" log, completion and
production data on "key" wells within and adjacent to the defined prospect area
were used to determine productive and depositional trends.


                              MCKEAN PROSPECT AREA


DRILLING ACTIVITY

     The proposed drilling area lies within a region of north central
Pennsylvania which has seen activity for more than the past 150 years in terms
of oil production. Modern development within and adjacent to the McKean Prospect
Area has seen increased activity in the past several years with exploration for,
and exploitation of primarily natural gas reserves. Atlas continues to identify
and extend productive trends and has drilled 65 wells. Drilling is ongoing as of
the date of this report with recent wells displaying favorable initial drilling
and completion results.

GEOLOGY

     STRATIGRAPHY, LITHOLOGY & DEPOSITION

     Depositional environments in the Upper Devonian Bradford Group of McKean
County are of near shore to offshore marine settings.
     The Bradford Group reservoir sands in this area consist of the Bradford
First, Watsonville, Dewdrop, Cherry Grove, Tiona, Bradford Second, Harrisburg
Run, Bradford Third and Lewis Run. Diagram illustrates stratigraphic
relationships.

[GRAPHIC OMITTED]
                                       83




     The TIONA SAND is a primary target in all wells in this area.
Stratigraphically, it is the highest, or youngest Balltown sand within the
Bradford Group. Generally sand development in the Tiona interval is most
favorable when sand encountered is typically twenty (20) or more feet thick with
10-15% porosities.
     The BRADFORD SECOND SAND is another primary target in the area. It directly
underlies the Tiona in the Balltown section of the Bradford Group. The Bradford
Second interval is most favorable when ten (10) or more feet of sand is
encountered. Porosities typically range from 9% to 16%.
     Secondary targets may also show development. Production has occurred from
the Bradford First, Cherry Grove, Bradford Third and the Lewis Run sand within
the prospect area.

     RESERVOIR CHARACTERISTICS

     Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping commercial quantities of natural gas in a more permeable medium. In the
Upper Devonian reservoirs, this occurs either stratigraphically when a permeable
sand containing hydrocarbons encounters impermeable shale or when permeable sand
changes gradually into non-permeable sand by a cementation process known as
"diagenesis". Thus, this type of trap represents cemented-in hydrocarbon
accumulations.
     Electric well logs can be used in conjunction with production to interpret
reservoir parameters. When sandstones in the Upper Devonian reservoirs develop
porosity in excess of 8%, or a bulk density of 2.50 or less, the permeability of
the reservoir can become great enough to allow commercial production of natural
gas. Small, naturally occurring cracks in the formation, referred to as
micro-fractures, can also enhance permeability. A typical log suite with gamma,
bulk density, neutron, induction and temperature logs showing sand development
in the primary Upper Devonian reservoirs in this area is illustrated.


                                [GRAPHIC OMITTED]


PRODUCTION

     The McKean prospect area produces from several reservoir sands. Each well
has a unique combination of these reservoirs yielding different production
declines. While Atlas anticipates production from each reservoir to be
comparable to like reservoirs historically produced throughout the Appalachian
Basin, a model decline curve for this prospect area is not included due to the
multiple sets of commingled reservoirs found in this area.



                                       84






                                   STATEMENTS



CONCLUSION

     UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP, which will consist of
developmental drilling of Upper Devonian reservoirs in McKean County,
Pennsylvania. It is the professional opinion of UEDC that the drilling of the
twenty-five (25) wells by ATLAS AMERICA PUBLIC #14-2004 LIMITED PARTNERSHIP is
supported by sufficient geologic and engineering data.

DISCLAIMER

     For the purpose of this evaluation, UEDC did not visit any leaseholds or
inspect any of the associated production equipment. Likewise, UEDC has no
knowledge as to the validity of title, liabilities, or corporate matters
affecting these properties. UEDC does not warrant individual well performance.

NON-INTEREST

     We hereby confirm that UEDC is an independent consulting firm and that
neither this firm or any of it's employees, contract consultants, or officers
has, or is committed to acquire any interest, directly or indirectly, in Atlas
Resources, Inc.; nor is this firm, or any employee, contract consultant, or
officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm
that neither the employment of, nor payment of compensation received by UEDC in
connection with this report, is on a contingent basis.

                                                   Respectfully submitted,

                                                   /s/ Robin Anthony

                                                   UEDC, INC.



                                       85





                                   EXHIBIT (A)

                                     FORM OF

                        AMENDED AND RESTATED CERTIFICATE

                      AND AGREEMENT OF LIMITED PARTNERSHIP

                                       FOR

                       ATLAS AMERICA PUBLIC #14-2004 L.P.

 [FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP
                  FOR ATLAS AMERICA PUBLIC #14-2005(___) L.P.]






                                TABLE OF CONTENTS

SECTION NO.        DESCRIPTION                            PAGE
I. FORMATION
        1.01   Formation....................................1
        1.02   Certificate of Limited Partnership...........1
        1.03   Name, Principal Office and Residence.........1
        1.04   Purpose......................................1

II. DEFINITION OF TERMS
        2.01   Definitions..................................2

III.    SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
        3.01   Designation of Managing General Partner
                   and Participants........................10
        3.02   Participants................................10
        3.03   Subscriptions to the Partnership............11
        3.04   Capital Contributions of the Managing
                   General Partner.........................12
        3.05   Payment of Subscriptions....................13
        3.06   Partnership Funds...........................13

IV.     CONDUCT OF OPERATIONS
        4.01   Acquisition of Leases.......................14
        4.02   Conduct of Operations.......................16
        4.03   General Rights and Obligations of the
                   Participants and Restricted and
                   Prohibited Transactions.................19
        4.04   Designation, Compensation and
                   Removal of Managing General
                   Partner and Removal of Operator.........30
        4.05   Indemnification and Exoneration.............32
        4.06   Other Activities............................34

V.      PARTICIPATION IN COSTS AND REVENUES, CAPITAL
        ACCOUNTS, ELECTIONS AND DISTRIBUTIONS
        5.01   Participation in Costs and Revenues.........35
        5.02   Capital Accounts and Allocations
                   Thereto.................................38
        5.03   Allocation of Income, Deductions and
                   Credits.................................39
        5.04   Elections...................................41
        5.05   Distributions...............................41

VI.     TRANSFER OF INTERESTS
        6.01   Transferability.............................42
        6.02   Special Restrictions on Transfers...........43
        6.03   Right of Managing General Partner to
               Hypothecate and/or Withdraw Its Interests...44
        6.04   Presentment.................................45

VII.    DURATION, DISSOLUTION, AND WINDING UP

        7.01   Duration....................................46

        7.02   Dissolution and Winding Up..................47

VIII. MISCELLANEOUS PROVISIONS
        8.01   Notices.....................................48
        8.02   Time........................................48

        8.03   Applicable Law..............................48
        8.04   Agreement in Counterparts...................48

        8.05   Amendment...................................49
        8.06   Additional Partners.........................49
        8.07   Legal Effect................................49

EXHIBITS

        EXHIBIT (I-A)      -      Form of Managing General
                                   Partner Signature Page
        EXHIBIT (I-B)      -        Form of Subscription
                                         Agreement
        EXHIBIT (II)       -        Form of Drilling and
                                    Operating Agreement for
                                    Atlas America
                                    Public #14-2004
                                    L.P. [Atlas America
                                    Public #14-2005
                                    (___) L.P.]



            FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
           LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2004 L.P.
           [FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
       LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2005(_____) L.P.]


THIS AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP
("AGREEMENT"), amending and restating the original Certificate of Limited
Partnership, is made and entered into as of _____________________, 2004, by and
among Atlas Resources, Inc., referred to as "Atlas" or the "Managing General
Partner," and the remaining parties from time to time signing a Subscription
Agreement for Limited Partner Units, these parties sometimes referred to as
"Limited Partners," or for Investor General Partner Units, these parties
sometimes referred to as "Investor General Partners."

                                    ARTICLE I
                                    FORMATION

1.01. FORMATION. The parties have formed a limited partnership under the
Delaware Revised Uniform Limited Partnership Act on the terms and conditions set
forth in this Agreement.

1.02. CERTIFICATE OF LIMITED PARTNERSHIP. This document is not only an agreement
among the parties, but also is the Amended and Restated Certificate and
Agreement of Limited Partnership of the Partnership. This document shall be
filed or recorded in the public offices required under applicable law or deemed
advisable in the discretion of the Managing General Partner. Amendments to the
certificate of limited partnership shall be filed or recorded in the public
offices required under applicable law or deemed advisable in the discretion of
the Managing General Partner.

1.03. NAME, PRINCIPAL OFFICE AND RESIDENCE.

1.03(a). NAME. The name of the Partnership is Atlas America Public #14-2004 L.P.
[Atlas America Public #14-2005(_____) L.P.].

1.03(b). RESIDENCE. The residence of the Managing General Partner is its
principal place of business at 311 Rouser Road, Moon Township, Pennsylvania
15108, which shall also serve as the principal place of business of the
Partnership.

The residence of each Participant shall be as set forth on the Subscription
Agreement executed by the Participant.

All addresses shall be subject to change on notice to the parties.

1.03(c). AGENT FOR SERVICE OF PROCESS. The name and address of the agent for
service of process shall be Andrew M. Lubin at 110 S. Poplar Street, Suite 101,
Wilmington, Delaware 19801.

1.04. PURPOSE. The Partnership shall engage in all phases of the natural gas and
oil business. This includes, without limitation, exploration for, development
and production of natural gas and oil on the terms and conditions set forth
below and any other proper purpose under the Delaware Revised Uniform Limited
Partnership Act.

The Managing General Partner may not, without the affirmative vote of
Participants whose Units equal a majority of the total Units, do the following:

          (i)     change the investment and business purpose of the Partnership;
                  or

          (ii)    cause the Partnership to engage in activities outside the
                  stated business purposes of the Partnership through joint
                  ventures with other entities.

                                       1


                                   ARTICLE II
                               DEFINITION OF TERMS

2.01. DEFINITIONS. As used in this Agreement, the following terms shall have
      the meanings set forth below:

      1.  "Administrative Costs" means all customary and routine expenses
          incurred by the Sponsor for the conduct of Partnership administration,
          including: in-house legal, finance, in-house accounting, secretarial,
          travel, office rent, telephone, data processing and other items of a
          similar nature. Administrative Costs shall be limited as follows:

          (i)     no Administrative Costs charged shall be duplicated under any
                  other category of expense or cost; and

          (ii)    no portion of the salaries, benefits, compensation or
                  remuneration of controlling persons of the Managing General
                  Partner shall be reimbursed by the Partnership as
                  Administrative Costs. Controlling persons include directors,
                  executive officers and those holding 5% or more equity
                  interest in the Managing General Partner or a person having
                  power to direct or cause the direction of the Managing General
                  Partner, whether through the ownership of voting securities,
                  by contract, or otherwise.

      2.  "Administrator" means the official or agency administering the
          securities laws of a state.

      3.  "Affiliate" means with respect to a specific person:

          (i)     any person directly or indirectly owning, controlling, or
                  holding with power to vote 10% or more of the outstanding
                  voting securities of the specified person;

          (ii)    any person 10% or more of whose outstanding voting securities
                  are directly or indirectly owned, controlled, or held with
                  power to vote, by the specified person;

          (iii)   any person directly or indirectly controlling, controlled by,
                  or under common control with the specified person;

          (iv)    any officer, director, trustee or partner of the specified
                  person; and

          (v)     if the specified person is an officer, director, trustee or
                  partner, any person for which the person acts in any such
                  capacity.

      4.  "Agreement" means this Amended and Restated Certificate and Agreement
          of Limited Partnership, including all exhibits to this Agreement.

      5.  "Anthem Securities" means Anthem Securities, Inc., whose principal
          executive offices are located at 311 Rouser Road, P.O. Box 926, Moon
          Township, Pennsylvania 15108-0926.

      6.  "Assessments" means additional amounts of capital which may be
          mandatorily required of or paid voluntarily by a Participant beyond
          his subscription commitment.

      7.  "Atlas" means Atlas Resources, Inc., a Pennsylvania corporation, whose
          principal executive offices are located at 311 Rouser Road, Moon
          Township, Pennsylvania 15108.

      8.  "Atlas America Public #14-2004 Program" means a series of up to three
          limited partnerships entitled Atlas America Public #14-2004 L.P.,
          Atlas America Public #14-2005(A) L.P. and Atlas America Public
          #14-2005(B) L.P.

      9.  "Capital Account" or "account" means the account established for each
          party, maintained as provided in ss.5.02 and its subsections.

                                       2



      10. "Capital Contribution" means the amount agreed to be contributed to
          the Partnership by a Partner pursuant to ss.ss.3.04 and 3.05 and their
          subsections.

      11. "Carried Interest" means an equity interest in the Partnership issued
          to a Person without consideration, in the form of cash or tangible
          property, in an amount proportionately equivalent to that received
          from the Participants.

      12. "Code" means the Internal Revenue Code of 1986, as amended.

      13. "Cost," when used with respect to the sale or transfer of property to
          the Partnership, means:

          (i)     the sum of the prices paid by the seller or transferor to an
                  unaffiliated person for the property, including bonuses;

          (ii)    title insurance or examination costs, brokers' commissions,
                  filing fees, recording costs, transfer taxes, if any, and like
                  charges in connection with the acquisition of the property;

          (iii)   a pro rata portion of the seller's or transferor's actual
                  necessary and reasonable expenses for seismic and geophysical
                  services; and

          (iv)    rentals and ad valorem taxes paid by the seller or transferor
                  for the property to the date of its transfer to the buyer,
                  interest and points actually incurred on funds used to acquire
                  or maintain the property, and the portion of the seller's or
                  transferor's reasonable, necessary and actual expenses for
                  geological, engineering, drafting, accounting, legal and other
                  like services allocated to the property cost in conformity
                  with generally accepted accounting principles and industry
                  standards, except for expenses in connection with the past
                  drilling of wells which are not producers of sufficient
                  quantities of oil or gas to make commercially reasonable their
                  continued operations, and provided that the expenses
                  enumerated in this subsection (iv) shall have been incurred
                  not more than 36 months before the sale or transfer to the
                  Partnership.

          "Cost," when used with respect to services, means the reasonable,
          necessary and actual expense incurred by the seller on behalf of the
          Partnership in providing the services, determined in accordance with
          generally accepted accounting principles.

          As used elsewhere, "Cost" means the price paid by the seller in an
          arm's-length transaction.

      14. "Dealer-Manager" means:

          (i)     Anthem Securities, Inc., an Affiliate of the Managing General
                  Partner, the broker/dealer which will manage the offering and
                  sale of the Units in all states other than Minnesota and New
                  Hampshire; and

          (ii)    Bryan Funding, Inc., the broker/dealer which will manage the
                  offering and sale of Units in Minnesota and New Hampshire.

      15. "Development Well" means a well drilled within the proved area of a
          natural gas or oil reservoir to the depth of a stratigraphic Horizon
          known to be productive.

      16. "Direct Costs" means all actual and necessary costs directly incurred
          for the benefit of the Partnership and generally attributable to the
          goods and services provided to the Partnership by parties other than
          the Sponsor or its Affiliates. Direct Costs may not include any cost
          otherwise classified as Organization and Offering Costs,
          Administrative Costs, Intangible Drilling Costs, Tangible Costs,
          Operating Costs or costs related to the Leases, but may include the
          cost of services provided by the Sponsor or its Affiliates if the
          services are provided pursuant to written contracts and in compliance
          with ss.4.03(d)(7) or pursuant to the Managing General Partner's role
          as Tax Matters Partner.

                                       3



      17. "Distribution Interest" means an undivided interest in the
          Partnership's assets after payments to the Partnership's creditors or
          the creation of a reasonable reserve therefor, in the ratio the
          positive balance of a party's Capital Account bears to the aggregate
          positive balance of the Capital Accounts of all of the parties
          determined after taking into account all Capital Account adjustments
          for the taxable year during which liquidation occurs (other than those
          made pursuant to liquidating distributions or restoration of deficit
          Capital Account balances). Provided, however, after the Capital
          Accounts of all of the parties have been reduced to zero, the interest
          in the remaining Partnership assets shall equal a party's interest in
          the related Partnership revenues as set forth inss.5.01 and its
          subsections of this Agreement.

      18. "Drilling and Operating Agreement" means the proposed Drilling and
          Operating Agreement between the Managing General Partner or an
          Affiliate as Operator, and the Partnership as Developer, a copy of the
          proposed form of which is attached to this Agreement as Exhibit (II).

      19. "Exploratory Well" means a well drilled to:

          (i)     find commercially productive hydrocarbons in an unproved area;

          (ii)    find a new commercially productive Horizon in a field
                  previously found to be productive of hydrocarbons at another
                  Horizon; or

          (iii)   significantly extend a known prospect.

      20. "Farmout" means an agreement by the owner of the leasehold or Working
          Interest to assign his interest in certain acreage or well to the
          assignees, retaining some interest such as an Overriding Royalty
          Interest, an oil and gas payment, offset acreage or other type of
          interest, subject to the drilling of one or more specific wells or
          other performance as a condition of the assignment.

      21. "Final Terminating Event" means any one of the following:

          (i)     the expiration of the Partnership's fixed term;

          (ii)    notice to the Participants by the Managing General Partner of
                  its election to terminate the Partnership's affairs;

          (iii)   notice by the Participants to the Managing General Partner of
                  their similar election through the affirmative vote of
                  Participants whose Units equal a majority of the total Units;
                  or

          (iv)    the termination of the Partnership under ss.708(b)(1)(A) of
                  the Code or the Partnership ceases to be a going concern.

      22. "Horizon" means a zone of a particular formation; that part of a
          formation of sufficient porosity and permeability to form a petroleum
          reservoir.

      23. "Independent Expert" means a person with no material relationship to
          the Sponsor or its Affiliates who is qualified and in the business of
          rendering opinions regarding the value of natural gas and oil
          properties based on the evaluation of all pertinent economic,
          financial, geologic and engineering information available to the
          Sponsor or its Affiliates.

      24. "Initial Closing Date" means the date after the minimum amount of
          subscription proceeds has been received when subscription proceeds are
          first withdrawn from the escrow account.

      25. "Intangible Drilling Costs" or "Non-Capital Expenditures" means those
          expenditures associated with property acquisition and the drilling and
          completion of natural gas and oil wells that under present law are
          generally accepted as fully deductible currently for federal income
          tax purposes. This includes all expenditures made for any well before
          production in commercial quantities for wages, fuel, repairs, hauling,
          supplies and other costs and expenses incident to and necessary for
          drilling the well and preparing the well for production of natural gas
          or oil, that are currently deductible pursuant to Section 263(c) of
          the Code and Treasury Reg. Section 1.612-4, and are generally termed
          "intangible drilling and development costs," including the expense of
          plugging and abandoning any well before a completion attempt.

                                       4


      26. "Interim Closing Date" means those date(s) after the Initial Closing
          Date, but before the Offering Termination Date, that the Managing
          General Partner, in its sole discretion, applies additional
          subscription proceeds to additional Partnership activities, including
          drilling activities.

      27. "Investor General Partners" means:

          (i)     the persons signing the Subscription Agreement as Investor
                  General Partners; and

          (ii)    the Managing General Partner to the extent of any optional
                  subscription as an Investor General Partner under
                  ss.3.03(b)(2).

          All Investor General Partners shall be of the same class and
          have the same rights.

      28. "Landowner's Royalty Interest" means an interest in production, or its
          proceeds, to be received free and clear of all costs of development,
          operation, or maintenance, reserved by a landowner on the creation of
          a Lease.

      29. "Leases" means full or partial interests in natural gas and oil
          leases, oil and natural gas mineral rights, fee rights, licenses,
          concessions, or other rights under which the holder is entitled to
          explore for and produce oil and/or natural gas, and includes any
          contractual rights to acquire any such interest.

      30. "Limited Partners" means:

          (i)     the persons signing the Subscription Agreement as Limited
                  Partners;

          (ii)    the Managing General Partner to the extent of any optional
                  subscription as a Limited Partner under ss.3.03(b)(2);

          (iii)   the Investor General Partners on the conversion of their
                  Investor General Partner Units to Limited Partner Units
                  pursuant to ss.6.01(b); and

          (iv)    any other persons who are admitted to the Partnership as
                  additional or substituted Limited Partners.

          Except as provided in ss.3.05(b), with respect to the required
          additional Capital Contributions of Investor General Partners,
          all Limited Partners shall be of the same class and have the
          same rights.

      31. "Managing General Partner" means:

          (i)     Atlas Resources, Inc.; or

          (ii)    any Person admitted to the Partnership as a general partner
                  other than as an Investor General Partner who is designated to
                  exclusively supervise and manage the operations of the
                  Partnership.

      32. "Managing General Partner Signature Page" means an execution and
          subscription instrument in the form attached as Exhibit (I-A) to this
          Agreement, which is incorporated in this Agreement by reference.

      33. "Offering Termination Date" means the date after the minimum amount of
          subscription proceeds has been received on which the Managing General
          Partner determines, in its sole discretion, the Partnership's
          subscription period is closed and the acceptance of subscriptions
          ceases, which shall not be later than December 31, 2004. [December 31,
          2005 with respect to Partnerships designated "Atlas America Public
          #14-2005(_____) L.P."]

                                       5



          Notwithstanding the above, the Offering Termination Date may
          not extend beyond the time that subscriptions for the maximum
          number of Units set forth in ss.3.03(c)(1) have been received
          and accepted by the Managing General Partner.

      34. "Operating Costs" means expenditures made and costs incurred in
          producing and marketing natural gas or oil from completed wells. These
          costs include, but are not limited to:

          (i)     labor, fuel, repairs, hauling, materials, supplies, utility
                  charges and other costs incident to or related to producing
                  and marketing natural gas and oil;

          (ii)    ad valorem and severance taxes;

          (iii)   insurance and casualty loss expense; and

          (iv)    compensation to well operators or others for services rendered
                  in conducting these operations.

          Operating Costs also include reworking, workover, subsequent
          equipping, and similar expenses relating to any well, but do
          not include the costs to re-enter and deepen an existing well,
          complete the well to deeper reservoirs or plug the well if it
          is nonproductive from the targeted deeper reservoirs.

      35. "Operator" means the Managing General Partner, as operator of
          Partnership Wells in Pennsylvania, and the Managing General Partner or
          an Affiliate as Operator of Partnership Wells in other areas of the
          United States.

      36. "Organization and Offering Costs" means all costs of organizing and
          selling the offering including, but not limited to:

          (i)     total underwriting and brokerage discounts and commissions
                  (including fees of the underwriters' attorneys);

          (ii)    expenses for printing, engraving, mailing, salaries of
                  employees while engaged in sales activities, charges of
                  transfer agents, registrars, trustees, escrow holders,
                  depositaries, engineers and other experts;

          (iii)   expenses of qualification of the sale of the securities under
                  federal and state law, including taxes and fees, accountants'
                  and attorneys' fees; and

          (iv)    other front-end fees.

      37. "Organization Costs" means all costs of organizing the offering
          including, but not limited to:

          (i)     expenses for printing, engraving, mailing, salaries of
                  employees while engaged in sales activities, charges of
                  transfer agents, registrars, trustees, escrow holders,
                  depositaries, engineers and other experts;

          (ii)    expenses of qualification of the sale of the securities under
                  federal and state law, including taxes and fees, accountants'
                  and attorneys' fees; and

          (iii)   other front-end fees.

      38. "Overriding Royalty Interest" means an interest in the natural gas and
          oil produced under a Lease, or the proceeds from the sale thereof,
          carved out of the Working Interest, to be received free and clear of
          all costs of development, operation, or maintenance.

      39. "Participants" means:

          (i)     the Managing General Partner to the extent of its optional
                  subscription under ss.3.03(b)(2);


                                       6



          (ii)    the Limited Partners; and

          (iii)   the Investor General Partners.

      40. "Partners" means:

          (i)     the Managing General Partner;

          (ii)    the Investor General Partners; and

          (iii)   the Limited Partners.

      41. "Partnership" means Atlas America Public #14-2004 L.P. [ Atlas America
          Public #14-2005(_____) L.P.].

      42. "Partnership Net Production Revenues" means gross revenues after
          deduction of the related Operating Costs, Direct Costs, Administrative
          Costs and all other Partnership costs not specifically allocated.

      43. "Partnership Well" means a well, some portion of the revenues from
          which is received by the Partnership.

      44. "Person" means a natural person, partnership, corporation,
          association, trust or other legal entity.

      45. "Production Purchase" or "Income" Program means any program whose
          investment objective is to directly acquire, hold, operate, and/or
          dispose of producing oil and gas properties. Such a program may
          acquire any type of ownership interest in a producing property,
          including, but not limited to, working interests, royalties, or
          production payments. A program which spends at least 90% of capital
          contributions and funds borrowed (excluding offering and
          organizational expenses) in the above described activities is presumed
          to be a production purchase or income program.

      46. "Program" means one or more limited or general partnerships or other
          investment vehicles formed, or to be formed, for the primary purpose
          of:

          (i)     exploring for natural gas, oil and other hydrocarbon
                  substances; or

          (ii)    investing in or holding any property interests which permit
                  the exploration for or production of hydrocarbons or the
                  receipt of such production or its proceeds.

      47. "Prospect" means an area covering lands which are believed by the
          Managing General Partner to contain subsurface structural or
          stratigraphic conditions making it susceptible to the accumulations of
          hydrocarbons in commercially productive quantities at one or more
          Horizons. The area, which may be different for different Horizons,
          shall be:

          (i)     designated by the Managing General Partner in writing before
                  the conduct of Partnership operations; and

          (ii)    enlarged or contracted from time to time on the basis of
                  subsequently acquired information to define the anticipated
                  limits of the associated hydrocarbon reserves and to include
                  all acreage encompassed therein.

          If the well to be drilled by the Partnership is to a Horizon
          containing Proved Reserves, then a "Prospect" for a particular Horizon
          may be limited to the minimum area permitted by state law or local
          practice, whichever is applicable, to protect against drainage from
          adjacent wells. Subject to the foregoing sentence, "Prospect" shall be
          deemed the drilling or spacing unit for the Clinton/Medina geological
          formation and the Mississippian and/or Upper Devonian Sandstone
          reservoirs in Ohio, Pennsylvania, and New York.

      48. "Proved Developed Oil and Gas Reserves" means reserves that can be
          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.

                                       7


      49. "Proved Reserves" 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.

          (i)     Reservoirs are considered proved if economic producibility is
                  supported by either actual production or conclusive formation
                  test. The area of a reservoir considered proved includes:

                  (a)     that portion delineated by drilling and defined by
                          gas-oil and/or oil-water contacts, if any; and

                  (b)     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.

                  In the absence of information on fluid contacts, the lowest
                  known structural occurrence of hydrocarbons controls the
                  lower proved limit of the reservoir.

          (ii)    Reserves which can be produced economically through
                  application of improved recovery techniques (such as fluid
                  injection) are included in the "proved" classification when
                  successful testing by a pilot project, or the operation of an
                  installed program in the reservoir, provides support for the
                  engineering analysis on which the project or program was
                  based.

          (iii)   Estimates of proved reserves do not include the following:

                  (a)     oil that may become available from known reservoirs
                          but is classified separately as "indicated additional
                          reserves";

                  (b)     crude oil, natural gas, and natural gas liquids, the
                          recovery of which is subject to reasonable doubt
                          because of uncertainty as to geology, reservoir
                          characteristics, or economic factors;

                  (c)     crude oil, natural gas, and natural gas liquids, that
                          may occur in undrilled prospects; and

                  (d)     crude oil, natural gas, and natural gas liquids, that
                          may be recovered from oil shales, coal, gilsonite and
                          other such sources.

      50. "Proved Undeveloped Reserves" means reserves that are expected to be
          recovered from either:

          (i)     new wells on undrilled acreage; or

          (ii)    from existing wells where a relatively major expenditure is
                  required for recompletion.

          Reserves on undrilled acreage shall be limited to those drilling units
          offsetting productive units that are reasonably certain of production
          when drilled. Proved reserves for other undrilled units can be claimed
          only where it can be demonstrated with certainty that there is
          continuity of production from the existing productive formation. Under
          no circumstances should estimates for proved undeveloped reserves be
          attributable to any acreage for which an application of fluid
          injection or other improved recovery technique is contemplated, unless
          such techniques have been proved effective by actual tests in the area
          and in the same reservoir.

                                        8



      51. "Reimbursement for Permissible Non-Cash Compensation" means a .5%
          accountable reimbursement for permissible non-cash compensation, which
          includes:

          (i)     an accountable reimbursement for training and education
                  meetings for associated persons of the Selling Agents;

          (ii)    gifts that do not exceed $100 per year and are not
                  preconditioned on achievement of a sales target;

          (iii)   an occasional meal, a ticket to a sporting event or the
                  theater, or comparable entertainment which is neither so
                  frequent nor so extensive as to raise any question of
                  propriety and is not preconditioned on achievement of a sales
                  target; and

          (iv)    contributions to a non-cash compensation arrangement between a
                  Selling Agent and its associated persons, provided that
                  neither the Managing General Partner nor the Dealer-Manager
                  directly or indirectly participates in the Selling Agent's
                  organization of a permissible non-cash compensation
                  arrangement.

      52. "Roll-Up" means a transaction involving the acquisition, merger,
          conversion or consolidation, either directly or indirectly, of the
          Partnership and the issuance of securities of a Roll-Up Entity. The
          term does not include:

          (i)     a transaction involving securities of the Partnership that
                  have been listed for at least 12 months on a national exchange
                  or traded through the National Association of Securities
                  Dealers Automated Quotation National Market System; or

          (ii)    a transaction involving the conversion to corporate, trust or
                  association form of only the Partnership if, as a consequence
                  of the transaction, there will be no significant adverse
                  change in any of the following:

                  (a)     voting rights;

                  (b)     the Partnership's term of existence;

                  (c)     the Managing General Partner's compensation; and

                  (d)     the Partnership's investment objectives.

      53. "Roll-Up Entity" means a partnership, trust, corporation or other
          entity that would be created or survive after the successful
          completion of a proposed roll-up transaction.

      54. "Sales Commissions" means all underwriting and brokerage discounts and
          commissions incurred in the sale of Units payable to registered
          broker/dealers, but excluding the following:

          (i)     the 2.5% Dealer-Manager fee;

          (ii)    the .5% accountable Reimbursement for Permissible Non-Cash
                  Compensation; and

          (iii)   the up to .5% reimbursement for bona fide accountable due
                  diligence expenses.

      55. "Selling Agents" means those broker/dealers selected by the
          Dealer-Manager which will participate in the offer and sale of the
          Units.

      56. "Sponsor" means any person directly or indirectly instrumental in
          organizing, wholly or in part, a program or any person who will manage
          or is entitled to manage or participate in the management or control
          of a program. The definition includes:

                                       9



          (i)     the managing and controlling general partner(s) and any other
                  person who actually controls or selects the person who
                  controls 25% or more of the exploratory, development or
                  producing activities of the program, or any segment thereof,
                  even if that person has not entered into a contract at the
                  time of formation of the program; and

          (ii)    whenever the context so requires, the term "sponsor" shall be
                  deemed to include its affiliates.

          "Sponsor" does not include wholly independent third-parties such as
          attorneys, accountants, and underwriters whose only compensation is
          for professional services rendered in connection with the offering of
          units.

      57. "Subscription Agreement" means an execution and subscription
          instrument in the form attached as Exhibit (I-B) to this Agreement,
          which is incorporated in this Agreement by reference.

      58. "Tangible Costs" or "Capital Expenditures" means those costs
          associated with drilling and completing natural gas and oil wells
          which are generally accepted as capital expenditures under the Code.
          This includes all of the following:

          (i)     costs of equipment, parts and items of hardware used in
                  drilling and completing a well; and

          (ii)    those items necessary to deliver acceptable natural gas and
                  oil production to purchasers to the extent installed
                  downstream from the wellhead of any well and which are
                  required to be capitalized under the Code and its regulations.

      59. "Tax Matters Partner" means the Managing General Partner.

      60. "Units" or "Units of Participation" means up to 625 Limited Partner
          interests and up to 11,875 Investor General Partner interests, which
          will be converted to Limited Partner Units as set forth in ss.6.01(b),
          purchased by Participants in the Partnership under the provisions of
          ss.3.03 and its subsections, including any rights to profits, losses,
          income, gain, credits, deductions, cash distributions or returns of
          capital or other attributes of the Units.

      61. "Working Interest" means an interest in a Lease which is subject to
          some portion of the cost of development, operation, or maintenance of
          the Lease.


                                   ARTICLE III
                 SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS

3.01. DESIGNATION OF MANAGING GENERAL PARTNER AND PARTICIPANTS. Atlas shall
serve as Managing General Partner of the Partnership. Atlas shall further serve
as a Participant to the extent of any subscription made by it pursuant to
ss.3.03(b)(2).

Limited Partners and Investor General Partners, including Affiliates of the
Managing General Partner, shall serve as Participants.

3.02. PARTICIPANTS.

3.02(a). LIMITED PARTNER AT FORMATION. Atlas America, Inc., as Original Limited
Partner, has acquired one Unit and has made a Capital Contribution of $100.

On the admission of one or more Limited Partners, the Partnership shall return
to the Original Limited Partner its Capital Contribution and shall reacquire its
Unit. The Original Limited Partner shall then cease to be a Limited Partner in
the Partnership with respect to the Unit.

3.02(b). OFFERING OF INTERESTS. The Partnership is authorized to admit to the
Partnership at the Initial Closing Date, any Interim Closing Date(s), and the
Offering Termination Date additional Participants whose Subscription Agreements
are accepted by the Managing General Partner if, after the admission of the
additional Participants, the total Units do not exceed the maximum number of
Units set forth in ss.3.03(c)(1).

                                       10


3.02(c). ADMISSION OF PARTICIPANTS. No action or consent by the Participants
shall be required for the admission of additional Participants pursuant to this
Agreement.

All subscribers' funds shall be held by an independent interest bearing escrow
holder and shall not be released to the Partnership until the receipt of the
minimum amount of subscription proceeds set forth in ss.3.03(c)(2). Thereafter,
subscriptions may be paid directly to the Partnership account.

3.03. SUBSCRIPTIONS TO THE PARTNERSHIP.

3.03(a). SUBSCRIPTIONS BY PARTICIPANTS.

3.03(a)(1). SUBSCRIPTION PRICE AND MINIMUM SUBSCRIPTION. The subscription price
of a Unit in the Partnership shall be $10,000, except as set forth below, and
shall be designated on each Participant's Subscription Agreement and payable as
set forth in ss.3.05(b)(1). The minimum subscription per Participant shall be
one Unit ($10,000); however, the Managing General Partner, in its discretion,
may accept one-half Unit ($5,000) subscriptions. Larger subscriptions shall be
accepted in $1,000 increments, beginning with $6,000, $7,000, etc.

Notwithstanding the foregoing, the subscription price for:

          (i)     the Managing General Partner, its officers, directors, and
                  Affiliates, and Participants who buy Units through the
                  officers and directors of the Managing General Partner, shall
                  be reduced by an amount equal to a 2.5% Dealer-Manager fee, a
                  7% Sales Commission, a .5% accountable Reimbursement for
                  Permissible Non-Cash Compensation, and a .5% reimbursement of
                  the Selling Agents' bona fide accountable due diligence
                  expenses, which shall not be paid with respect to these sales;
                  and

          (ii)    the subscription price for Registered Investment Advisors and
                  their clients, and Selling Agents and their registered
                  representatives and principals, shall be reduced by an amount
                  equal to a 7% Sales Commission, which shall not be paid with
                  respect to these sales.

No more than 5% of the total Units, in the aggregate, shall be sold with the
discounts described above.

3.03(a)(2). EFFECT OF SUBSCRIPTION. Execution of a Subscription Agreement shall
serve as an agreement by the Participant to be bound by each and every term of
this Agreement.

3.03(b). SUBSCRIPTIONS BY MANAGING GENERAL PARTNER.

3.03(b)(1). MANAGING GENERAL PARTNER'S REQUIRED SUBSCRIPTION. The Managing
General Partner, as a general partner and not as a Participant, shall:

          (i)     contribute to the Partnership the Leases which will be drilled
                  by the Partnership on the terms set forth in ss.4.01(a)(4);
                  and

          (ii)    pay the costs or make the required contributions charged to it
                  under this Agreement.

These Capital Contributions shall be paid or made by the Managing General
Partner at the time the costs are required to be paid by the Partnership, but no
later than December 31, 2005 [December 31, 2006].

3.03(b)(2). MANAGING GENERAL PARTNER'S OPTIONAL ADDITIONAL SUBSCRIPTION. In
addition to the Managing General Partner's required subscription under
ss.3.03(b)(1), the Managing General Partner may subscribe to up to 5% of the
Units under the provisions of ss.3.03(a) and its subsections, and, subject to
the limitations on voting rights set forth in ss.4.03(c)(3), to that extent
shall be deemed a Participant in the Partnership for all purposes under this
Agreement.

3.03(b)(3). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing General Partner
has executed a Managing General Partner Signature Page which:

                                       11


          (i)     evidences the Managing General Partner's required subscription
                  under ss.3.03(b)(1); and

          (ii)    may be amended to reflect the amount of any optional
                  subscription under ss.3.03(b)(2).

Execution of the Managing General Partner Signature Page serves as an agreement
by the Managing General Partner to be bound by each and every term of this
Agreement.

3.03(c). MAXIMUM AND MINIMUM NUMBER OF UNITS.

3.03(c)(1). MAXIMUM NUMBER OF UNITS. The maximum number of Units may not exceed
12,500 Units, which is up to $125,000,000 of cash subscription proceeds
excluding the subscription discounts permitted under ss.3.03(a)(1).
Notwithstanding the foregoing, the maximum number of Units in all partnerships
in Atlas America Public #14-2004 Program, in the aggregate, shall not exceed
12,500 Units which is up to $125,000,000 of cash subscription proceeds excluding
the subscription discounts permitted under ss.3.03(a)(1).

3.03(c)(2). MINIMUM NUMBER OF UNITS. The minimum number of Units shall equal at
least 200 Units, but in any event not less than that number of Units which
provides the Partnership with cash subscription proceeds of $2,000,000,
excluding the subscription discounts permitted under ss.3.03(a)(1).

If at the Offering Termination Date the minimum number of Units has not been
received and accepted, then all monies deposited by subscribers shall be
promptly returned to them. They shall receive interest earned on their
subscription proceeds from the date the monies were deposited in escrow through
the date of refund.

The partnership may break escrow and begin its drilling activities in the
Managing General Partner's sole discretion on receipt of the minimum
subscription proceeds.

3.03(d). ACCEPTANCE OF SUBSCRIPTIONS.

3.03(d)(1). DISCRETION BY THE MANAGING GENERAL PARTNER. Acceptance of
subscriptions is discretionary with the Managing General Partner. The Managing
General Partner may reject any subscription for any reason it deems appropriate.

3.03(d)(2). TIME PERIOD IN WHICH TO ACCEPT SUBSCRIPTIONS. Subscriptions shall be
accepted or rejected by the Partnership within 30 days of their receipt. If a
subscription is rejected, then all funds shall be returned to the subscriber
promptly.

3.03(d)(3). ADMISSION TO THE PARTNERSHIP. The Participants shall be admitted to
the Partnership as follows:

          (i)     not later than 15 days after the release from escrow of
                  Participants' funds to the Partnership; and

          (ii)    after the close of the escrow account not later than the last
                  day of the calendar month in which their Subscription
                  Agreements were accepted by the Partnership.

3.04. CAPITAL CONTRIBUTIONS OF THE MANAGING GENERAL PARTNER.

3.04(a). MINIMUM AMOUNT OF MANAGING GENERAL PARTNER'S REQUIRED CONTRIBUTION. The
Managing General Partner is required to:

          (i)     make aggregate Capital Contributions to the Partnership,
                  including Leases contributed under ss.3.03(b)(1)(i), of not
                  less than 25% of all Capital Contributions to the Partnership;
                  and

          (ii)    maintain a minimum Capital Account balance equal to not less
                  than 1% of total positive Capital Account balances for the
                  Partnership.

3.04(b). ON LIQUIDATION THE MANAGING GENERAL PARTNER MUST CONTRIBUTE DEFICIT
BALANCE IN ITS CAPITAL ACCOUNT. The Managing General Partner shall contribute to
the Partnership any deficit balance in its Capital Account on the occurrence of
either of the following events:

                                       12



          (i)     the liquidation of the Partnership; or

          (ii)    the liquidation of the Managing General Partner's interest in
                  the Partnership.

This shall be determined after taking into account all adjustments for the
Partnership's taxable year during which the liquidation occurs, other than
adjustments made pursuant to this requirement, by the end of the taxable year in
which its interest in the Partnership is liquidated or, if later, within 90 days
after the date of the liquidation.

3.04(c). INTEREST FOR CONTRIBUTIONS. The interest of the Managing General
Partner, as Managing General Partner and not as a Participant, in the capital
and revenues of the Partnership is in consideration for, and is the only
consideration for, its required Capital Contributions to the Partnership.

3.05. PAYMENT OF SUBSCRIPTIONS.

3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing General Partner
shall pay any optional subscription under ss.3.03(b)(2) as set forth in
ss.3.05(b)(1).

3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL CONTRIBUTIONS OF THE
INVESTOR GENERAL PARTNERS.

3.05(b)(1). PAYMENT OF SUBSCRIPTION AGREEMENTS. A Participant shall pay the
amount designated as the subscription price on the Subscription Agreement
executed by the Participant 100% in cash at the time of subscribing. A
Participant shall receive interest on the amount he pays from the time his
subscription proceeds are deposited in the escrow account, or the Partnership
account after the minimum number of Units have been received as provided in
ss.3.06(b), up until the Offering Termination Date.

3.05(b)(2). ADDITIONAL REQUIRED CAPITAL CONTRIBUTIONS OF THE INVESTOR GENERAL
PARTNERS. Investor General Partners must make Capital Contributions to the
Partnership when called by the Managing General Partner, in addition to their
subscriptions, for their pro rata share of any Partnership obligations and
liabilities which are recourse to the Investor General Partners and are
represented by their ownership of Units before the conversion of Investor
General Units to Limited Partner Units under ss.6.01(b).

3.05(b)(3). DEFAULT PROVISIONS. The failure of an Investor General Partner to
timely make a required additional Capital Contribution under this section
results in his personal liability to the other Investor General Partners for the
amount in default. The remaining Investor General Partners, in proportion to
their respective number of Units, must pay the defaulting Investor General
Partner's share of Partnership liabilities and obligations. In that event, the
remaining Investor General Partners:

          (i)     shall have a first and preferred lien on the defaulting
                  Investor General Partner's interest in the Partnership to
                  secure payment of the amount in default plus interest at the
                  legal rate;

          (ii)    shall be entitled to receive 100% of the defaulting Investor
                  General Partner's cash distributions, in proportion to their
                  respective number of Units, until the amount in default is
                  recovered in full plus interest at the legal rate; and

          (iii)   may commence legal action to collect the amount due plus
                  interest at the legal rate.

3.06. PARTNERSHIP FUNDS.

3.06(a). FIDUCIARY DUTY. The Managing General Partner has a fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Managing General Partner's possession or
control. The Managing General Partner shall not employ, or permit another to
employ, the funds and assets in any manner except for the exclusive benefit of
the Partnership.

Neither this Agreement nor any other agreement between the Managing General
Partner and the Partnership shall contractually limit any fiduciary duty owed to
the Participants by the Managing General Partner under applicable law, except as
provided in ss.ss.4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of this Agreement.


                                       13


3.06(b). SPECIAL ACCOUNT AFTER THE RECEIPT OF THE MINIMUM PARTNERSHIP
SUBSCRIPTIONS. Following the receipt of the minimum number of Units and breaking
escrow, the funds of the Partnership shall be held in a separate
interest-bearing account maintained for the Partnership and shall not be
commingled with funds of any other entity.

3.06(c). INVESTMENT.

3.06(c)(1). INVESTMENTS IN OTHER ENTITIES. Partnership funds may not be invested
in the securities of another person except in the following instances:

          (i)     investments in Working Interests or undivided Lease interests
                  made in the ordinary course of the Partnership's business;

          (ii)    temporary investments made as set forth in ss.3.06(c)(2);

          (iii)   multi-tier arrangements meeting the requirements of
                  ss.4.03(d)(15);

          (iv)    investments involving less than 5% of the Partnership's
                  subscription proceeds which are a necessary and incidental
                  part of a property acquisition transaction; and

          (v)     investments in entities established solely to limit the
                  Partnership's liabilities associated with the ownership or
                  operation of property or equipment, provided that duplicative
                  fees and expenses shall be prohibited.

3.06(c)(2). PERMISSIBLE INVESTMENTS BEFORE INVESTMENT IN PARTNERSHIP ACTIVITIES.
After the Initial Closing Date and until proceeds from the offering are invested
in the Partnership's operations, the proceeds may be temporarily invested in
income producing short-term, highly liquid investments, in which there is
appropriate safety of principal, such as U.S. Treasury Bills.


                                   ARTICLE IV
                              CONDUCT OF OPERATIONS

4.01. ACQUISITION OF LEASES.

4.01(a). ASSIGNMENT TO PARTNERSHIP.

4.01(a)(1). IN GENERAL. The Managing General Partner shall select, acquire and
assign or cause to have assigned to the Partnership full or partial interests in
Leases, by any method customary in the natural gas and oil industry, subject to
the terms and conditions set forth below.

The Partnership and the other partnerships in Atlas America Public #14-2004
Program may acquire and develop interests in Leases covering one or more of the
same Prospects, in the Managing General Partner's discretion.

The Partnership shall acquire only Leases reasonably expected to meet the stated
purposes of the Partnership. No Leases shall be acquired for the purpose of a
subsequent sale, Farmout, or other disposition unless the acquisition is made
after a well has been drilled to a depth sufficient to indicate that the
acquisition would be in the Partnership's best interest.

4.01(a)(2). FEDERAL AND STATE LEASES. The Partnership is authorized to acquire
Leases on federal and state lands.

4.01(a)(3). MANAGING GENERAL PARTNER'S DISCRETION AS TO TERMS AND BURDENS OF
ACQUISITION. Subject to the provisions of ss.4.03(d) and its subsections, the
acquisitions of Leases or other property may be made under any terms and
obligations, including:

          (i)     any limitations as to the Horizons to be assigned to the
                  Partnership; and

          (ii)    subject to any burdens as the Managing General Partner deems
                  necessary in its sole discretion.

4.01(a)(4). COST OF LEASES. All Leases shall be:

          (i)     contributed to the Partnership by the Managing General Partner
                  or its Affiliates other than an affiliated Program; and



                                       14



          (ii)    credited towards the Managing General Partner's required
                  Capital Contribution set forth in ss.3.03(b)(1) at the Cost of
                  the Lease, unless the Managing General Partner has cause to
                  believe that Cost is materially more than the fair market
                  value of the property, in which case the credit for the
                  contribution must be made at a price not in excess of the fair
                  market value.

A determination of fair market value must be:

          (i)     supported by an appraisal from an Independent Expert; and

          (ii)    maintained in the Partnership's records for six years along
                  with associated supporting information.

4.01(a)(5). THE MANAGING GENERAL PARTNER'S, OPERATOR'S OR THEIR AFFILIATES'
RIGHTS IN THE REMAINDER INTERESTS. Subject to the provisions of ss.4.03(d) and
its subsections, to the extent the Partnership does not acquire a full interest
in a Lease from the Managing General Partner or its Affiliates, the remainder of
the interest in the Lease may be held by the Managing General Partner or its
Affiliates. They may either:

          (i)     retain and exploit the remaining interest for their own
                  account; or

          (ii)    sell or otherwise dispose of all or a part of the remaining
                  interest.

Profits from the exploitation and/or disposition of their retained interests in
the Leases shall be for the benefit of the Managing General Partner or its
Affiliates to the exclusion of the Partnership.

4.01(a)(6). NO BREACH OF DUTY. Subject to the provisions of ss.4.03 and its
subsections, acquisition of Leases from the Managing General Partner, the
Operator or their Affiliates shall not be considered a breach of any obligation
owed by them to the Partnership or the Participants.

4.01(b). NO OVERRIDING ROYALTY INTERESTS. Neither the Managing General Partner,
the Operator nor any Affiliate shall retain any Overriding Royalty Interest on
the Leases acquired by the Partnership.

4.01(c). TITLE AND NOMINEE ARRANGEMENTS.

4.01(c)(1). LEGAL TITLE. Legal title to all Leases acquired by the Partnership
shall be held on a permanent basis in the name of the Partnership. However,
Partnership properties may be held temporarily in the name of:

          (i)     the Managing General Partner;

          (ii)    the Operator;

          (iii)   their Affiliates; or

          (iv)    in the name of any nominee designated by the Managing General
                  Partner to facilitate the acquisition of the properties.

4.01(c)(2). MANAGING GENERAL PARTNER'S DISCRETION. The Managing General Partner
shall take the steps which are necessary in its best judgment to render title to
the Leases to be acquired by the Partnership acceptable for the purposes of the
Partnership. The Managing General Partner shall be free, however, to use its own
best judgment in waiving title requirements.

The Managing General Partner shall not be liable to the Partnership or to the
other parties for any mistakes of judgment; nor shall the Managing General
Partner be deemed to be making any warranties or representations, express or
implied, as to the validity or merchantability of the title to the Leases
assigned to the Partnership or the extent of the interest covered thereby except
as otherwise provided in the Drilling and Operating Agreement.

4.01(c)(3). COMMENCEMENT OF OPERATIONS. The Partnership shall not begin
operations on the Leases acquired by the Partnership unless the Managing General
Partner is satisfied that necessary title requirements have been satisfied.


                                       15


4.02. CONDUCT OF OPERATIONS.

4.02(a). IN GENERAL. The Managing General Partner shall establish a program of
operations for the Partnership. Subject to the limitations contained in Article
III of this Agreement concerning the maximum Capital Contribution which can be
required of a Limited Partner, the Managing General Partner, the Limited
Partners, and the Investor General Partners agree to participate in the program
so established by the Managing General Partner.

4.02(b). MANAGEMENT. Subject to any restrictions contained in this Agreement,
the Managing General Partner shall exercise full control over all operations of
the Partnership.

4.02(c). GENERAL POWERS OF THE MANAGING GENERAL PARTNER.

4.02(c)(1). IN GENERAL. Subject to the provisions of ss.4.03 and its
subsections, and to any authority which may be granted the Operator under
ss.4.02(c)(3)(b), the Managing General Partner shall have full authority to do
all things deemed necessary or desirable by it in the conduct of the business of
the Partnership. Without limiting the generality of the foregoing, the Managing
General Partner is expressly authorized to engage in:

          (i)     the making of all determinations of which Leases, wells and
                  operations will be participated in by the Partnership, which
                  includes:

                  (a)     which Leases are developed;

                  (b)     which Leases are abandoned; or

                  (c)     which leases are sold or assigned to other parties,
                          including other investor ventures organized by the
                          Managing General Partner, the Operator, or any of
                          their Affiliates;

          (ii)    the negotiation and execution on any terms deemed desirable in
                  its sole discretion of any contracts, conveyances, or other
                  instruments, considered useful to the conduct of the
                  operations or the implementation of the powers granted it
                  under this Agreement, including, without limitation:

                  (a)     the making of agreements for the conduct of
                          operations, including agreements and financial
                          instruments relating to hedging the Partnership's
                          natural gas and oil;

                  (b)     the exercise of any options, elections, or decisions
                          under any such agreements; and

                  (c)     the furnishing of equipment, facilities, supplies and
                          material, services, and personnel;

          (iii)   the exercise, on behalf of the Partnership or the parties, as
                  the Managing General Partner in its sole judgment deems best,
                  of all rights, elections and options granted or imposed by any
                  agreement, statute, rule, regulation, or order;

          (iv)    the making of all decisions concerning the desirability of
                  payment, and the payment or supervision of the payment, of all
                  delay rentals and shut-in and minimum or advance royalty
                  payments;

          (v)     the selection of full or part-time employees and outside
                  consultants and contractors and the determination of their
                  compensation and other terms of employment or hiring;

          (vi)    the maintenance of insurance for the benefit of the
                  Partnership and the parties as it deems necessary, but in no
                  event less in amount or type than the following:

                  (a)     worker's compensation insurance in full compliance
                          with the laws of the Commonwealth of Pennsylvania and
                          any other applicable state laws;

                  (b)     liability insurance, including automobile, which has a
                          $1,000,000 combined single limit for bodily injury and
                          property damage in any one accident or occurrence and
                          in the aggregate; and

                  (c)     liability and excess liability insurance as to bodily
                          injury and property damage with combined limits of
                          $50,000,000 during drilling operations and thereafter,
                          per occurrence or accident and in the aggregate, which
                          includes $1,000,000 of seepage, pollution and
                          contamination insurance which protects and defends the
                          insured against property damage or bodily injury
                          claims from third-parties, other than a co-owner of
                          the Working Interest, alleging seepage, pollution or
                          contamination damage resulting from a pollution
                          incident. The excess liability insurance shall be in
                          place and effective no later than the date drilling
                          operations begin, and the Partnership shall have the
                          benefit of the Managing General Partner's $50,000,000
                          liability insurance on the same basis as the Managing
                          General Partner and its Affiliates, including the
                          Managing General Partner's other Programs;


                                       16



          (vii)   the use of the funds and revenues of the Partnership, and the
                  borrowing on behalf of, and the loan of money to, the
                  Partnership, on any terms it sees fit, for any purpose,
                  including without limitation:

                  (a)     the conduct or financing, in whole or in part, of the
                          drilling and other activities of the Partnership;

                  (b)     the conduct of additional operations; and

                  (c)     the repayment of any borrowings or loans used
                          initially to finance these operations or activities;

          (viii)  the disposition, hypothecation, sale, exchange, release,
                  surrender, reassignment or abandonment of any or all assets of
                  the Partnership, including without limitation, the Leases,
                  wells, equipment and production therefrom, provided that the
                  sale of all or substantially all of the assets of the
                  Partnership shall only be made as provided in ss.4.03(d)(6);

          (ix)    the formation of any further limited or general partnership,
                  tax partnership, joint venture, or other relationship which it
                  deems desirable with any parties who it, in its sole and
                  absolute discretion, selects, including any of its Affiliates;

          (x)     the control of any matters affecting the rights and
                  obligations of the Partnership, including:

                  (a)     the employment of attorneys to advise and otherwise
                          represent the Partnership;

                  (b)     the conduct of litigation and other incurring of legal
                          expense; and

                  (c)     the settlement of claims and litigation;

          (xi)    the operation of producing wells drilled on the Leases or on a
                  Prospect which includes any part of the Leases;

          (xii)   the exercise of the rights granted to it under the power of
                  attorney created under this Agreement; and

          (xiii)  the incurring of all costs and the making of all expenditures
                  in any way related to any of the foregoing.

4.02(c)(2). SCOPE OF POWERS. The Managing General Partner's powers shall extend
to any operation participated in by the Partnership or affecting its Leases, or
other property or assets, irrespective of whether or not the Managing General
Partner is designated operator of the operation by any outside persons
participating therein.

4.02(c)(3). DELEGATION OF AUTHORITY.

4.02(c)(3)(a). IN GENERAL. The Managing General Partner may subcontract and
delegate all or any part of its duties under this Agreement to any entity chosen
by it, including an entity related to it. The party shall have the same powers
in the conduct of the duties as would the Managing General Partner. The
delegation, however, shall not relieve the Managing General Partner of its
responsibilities under this Agreement.

4.02(c)(3)(b). DELEGATION TO OPERATOR. The Managing General Partner is
specifically authorized to delegate any or all of its duties to the Operator by
executing the Drilling and Operating Agreement. This delegation shall not
relieve the Managing General Partner of its responsibilities under this
Agreement.


                                       17



In no event shall any consideration received for operator services be in excess
of competitive rates or duplicative of any consideration or reimbursements
received under this Agreement. The Managing General Partner may not benefit by
interpositioning itself between the Partnership and the actual provider of
operator services.

4.02(c)(4). RELATED PARTY TRANSACTIONS. Subject to the provisions of ss.4.03 and
its subsections, any transaction which the Managing General Partner is
authorized to enter into on behalf of the Partnership under the authority
granted in this section and its subsections, may be entered into by the Managing
General Partner with itself or with any other general partner, the Operator, or
any of their Affiliates.

4.02(d). ADDITIONAL POWERS. In addition to the powers granted the Managing
General Partner under ss.4.02(c) and its subsections or elsewhere in this
Agreement, the Managing General Partner, when specified, shall have the
following additional express powers.

4.02(d)(1). DRILLING CONTRACTS. All Partnership Wells shall be drilled under the
Drilling and Operating Agreement on a Cost plus 15% basis. The Managing General
Partner or its Affiliates, as drilling contractor, may not do the following:

          (i)     receive a rate that is not competitive with the rates charged
                  by unaffiliated contractors in the same geographic region;

          (ii)    enter into a turnkey drilling contract with the Partnership;

          (iii)   profit by drilling in contravention of its fiduciary
                  obligations to the Partnership; or

          (iv)    benefit by interpositioning itself between the Partnership and
                  the actual provider of drilling contractor services.

4.02(d)(2). POWER OF ATTORNEY.

4.02(d)(2)(a). IN GENERAL. Each Participant appoints the Managing General
Partner his true and lawful attorney-in-fact for him and in his name, place, and
stead and for his use and benefit, from time to time:

          (i)     to create, prepare, complete, execute, file, swear to,
                  deliver, endorse, and record any and all documents,
                  certificates, government reports, or other instruments as may
                  be required by law, or necessary to amend this Agreement as
                  authorized under the terms of this Agreement, or to qualify
                  the Partnership as a limited partnership or partnership in
                  commendam and to conduct business under the laws of any
                  jurisdiction in which the Managing General Partner elects to
                  qualify the Partnership or conduct business; and

          (ii)    to create, prepare, complete, execute, file, swear to,
                  deliver, endorse and record any and all instruments,
                  assignments, security agreements, financing statements,
                  certificates, and other documents as may be necessary from
                  time to time to implement the borrowing powers granted under
                  this Agreement.

4.02(d)(2)(b). FURTHER ACTION. Each Participant authorizes the attorney-in-fact
to take any further action which the attorney-in-fact considers necessary or
advisable in connection with any of the foregoing powers and rights granted to
the Managing General Partner under this section and its subsections. Each party
acknowledges that the power of attorney granted under subsection 4.02(d)(2)(a):

          (i)     is a special power of attorney coupled with an interest and
                  irrevocable; and

          (ii)    shall survive the assignment by the Participant of the whole
                  or a portion of his Units; except when the assignment is of
                  all of the Participant's Units and the purchaser, transferee,
                  or assignee of the Units is admitted as a successor
                  Participant, the power of attorney shall survive the delivery
                  of the assignment for the sole purpose of enabling the
                  attorney-in-fact to execute, acknowledge, and file any
                  agreement, certificate, instrument or document necessary to
                  effect the substitution.

4.02(d)(2)(c). POWER OF ATTORNEY TO OPERATOR. The Managing General Partner is
hereby authorized to grant a Power of Attorney to the Operator on behalf of the
Partnership.


                                       18



4.02(e). BORROWINGS AND USE OF PARTNERSHIP REVENUES.

4.02(e)(1). POWER TO BORROW OR USE PARTNERSHIP REVENUES.

4.02(e)(1)(a). IN GENERAL. If additional funds over the Participants' Capital
Contributions are needed for Partnership operations, then the Managing General
Partner may:

          (i)     use Partnership revenues for such purposes; or

          (ii)    the Managing General Partner and its Affiliates may advance to
                  the Partnership the funds necessary under ss.4.03(d)(8)(b),
                  although they are not obligated to advance the funds to the
                  Partnership.

4.02(e)(1)(b). LIMITATION ON BORROWING. The borrowings, other than credit
transactions on open account customary in the industry to obtain goods and
services, shall be subject to the following limitations:

          (i)     the borrowings must be without recourse to the Investor
                  General Partners and the Limited Partners except as otherwise
                  provided in this Agreement; and

          (ii)    the amount that may be borrowed at any one time may not exceed
                  an amount equal to 5% of the Partnership's subscription
                  proceeds.

4.02(f). TAX MATTERS PARTNER.

4.02(f)(1). DESIGNATION OF TAX MATTERS PARTNER. The Managing General Partner is
hereby designated the Tax Matters Partner of the Partnership under Section
6231(a)(7) of the Code. The Managing General Partner is authorized to act in
this capacity on behalf of the Partnership and the Participants and to take any
action, including settlement or litigation, which it in its sole discretion
deems to be in the best interest of the Partnership.

4.02(f)(2). COSTS INCURRED BY TAX MATTERS PARTNER. Costs incurred by the Tax
Matters Partner shall be considered a Direct Cost of the Partnership.

4.02(f)(3). NOTICE TO PARTICIPANTS OF IRS PROCEEDINGS. The Tax Matters Partner
shall notify all Participants of any partnership administrative or other legal
proceedings involving the IRS, and thereafter shall furnish all Participants
periodic reports at least quarterly on the status of the proceedings.

4.02(f)(4). PARTICIPANT RESTRICTIONS. Each Participant agrees as follows:

          (i)     he will not file the statement described in Section
                  6224(c)(3)(B) of the Code prohibiting the Managing General
                  Partner as the Tax Matters Partner for the Partnership from
                  entering into a settlement on his behalf with respect to
                  partnership items, as that term is defined in Section
                  6231(a)(3) of Code, of the Partnership;

          (ii)    he will not form or become and exercise any rights as a member
                  of a group of Partners having a 5% or greater interest in the
                  profits of the Partnership under Section 6223(b)(2) of the
                  Code; and

          (iii)   the Managing General Partner is authorized to file a copy of
                  this Agreement, or pertinent portions of this Agreement, with
                  the IRS under Section 6224(b) of the Code if necessary to
                  perfect the waiver of rights under this subsection.

4.03. GENERAL RIGHTS AND OBLIGATIONS OF THE PARTICIPANTS AND RESTRICTED AND
PROHIBITED TRANSACTIONS.

4.03(a)(1). LIMITED LIABILITY OF LIMITED PARTNERS. Limited Partners shall not be
bound by the obligations of the Partnership other than as provided under the
Delaware Revised Uniform Limited Partnership Act. Limited Partners shall not be
personally liable for any debts of the Partnership or any of the obligations or
losses of the Partnership beyond the amount of the subscription price designated
on the Subscription Agreement executed by each respective Limited Partner
unless:

                                       19



          (i)     they also subscribe to the Partnership as Investor General
                  Partners; or

          (ii)    in the case of the Managing General Partner, it purchases
                  Limited Partner Units.

4.03(a)(2). NO MANAGEMENT AUTHORITY OF PARTICIPANTS. Participants, other than
the Managing General Partner if it buys Units, shall have no power over the
conduct of the affairs of the Partnership. No Participant, other than the
Managing General Partner if it buys Units, shall take part in the management of
the business of the Partnership, or have the power to sign for or to bind the
Partnership.

4.03(b). REPORTS AND DISCLOSURES.

4.03(b)(1). ANNUAL REPORTS AND FINANCIAL STATEMENTS. Beginning with the calendar
year in which the Partnership had its Offering Termination Date, the Partnership
shall provide each Participant an annual report within 120 days after the close
of that calendar year, and beginning with the following calendar year, a report
within 75 days after the end of the first six months of its calendar year,
containing except as otherwise indicated, at least the information set forth
below:

          (i)     Audited financial statements of the Partnership, including a
                  balance sheet and statements of income, cash flow, and
                  Partners' equity, which shall be prepared on an accrual basis
                  in accordance with generally accepted accounting principles
                  with a reconciliation with respect to information furnished
                  for income tax purposes and accompanied by an auditor's report
                  containing an opinion of an independent public accountant
                  selected by the Managing General Partner stating that his
                  audit was made in accordance with generally accepted auditing
                  standards and that in his opinion the financial statements
                  present fairly the financial position, results of operations,
                  partners' equity, and cash flows in accordance with generally
                  accepted accounting principles. Semiannual reports are not
                  required to be audited.

          (ii)    A summary itemization, by type and/or classification of the
                  total fees and compensation including any unaccountable, fixed
                  payment reimbursements for Administrative Costs and Operating
                  Costs, paid by the Partnership, or indirectly on behalf of the
                  Partnership, to the Managing General Partner, the Operator,
                  and their Affiliates. In addition, Participants shall be
                  provided the percentage that the annual unaccountable, fixed
                  fee reimbursement for Administrative Costs bears to annual
                  Partnership revenues.

                  Also, the independent certified public accountant shall
                  provide written attestation annually, which will be included
                  in the annual report, that the method used to make allocations
                  was consistent with the method described in ss.4.04(a)(2)(c)
                  of this Agreement and that the total amount of costs allocated
                  did not materially exceed the amounts actually incurred by the
                  Managing General Partner. If the Managing General Partner
                  subsequently decides to allocate expenses in a manner
                  different from that described in ss.4.04(a)(2)(c) of this
                  Agreement, then the change must be reported to the
                  Participants together with an explanation of the reason for
                  the change and the basis used for determining the
                  reasonableness of the new allocation method.

          (iii)   A description of each Prospect in which the Partnership owns
                  an interest, including:

                  (a)     the cost, location, and number of acres under Lease;
                          and

                  (b)     the Working Interest owned in the Prospect by the
                          Partnership.

                  Succeeding reports, however, must only contain material
                  changes, if any, regarding the Prospects.

          (iv)    A list of the wells drilled or abandoned by the Partnership
                  during the period of the report, indicating:

                  (a)     whether each of the wells has or has not been
                          completed;

                  (b)     a statement of the cost of each well completed or
                          abandoned; and

                  (c)     justification for wells abandoned after production has
                          begun.


                                       20



          (v)     A description of all Farmouts, farmins, and joint ventures,
                  made during the period of the report, including:

                  (a)     the Managing General Partner's justification for the
                          arrangement; and

                  (b)     a description of the material terms.

          (vi)    A schedule reflecting:

                  (a)     the total Partnership costs;

                  (b)     the costs paid by the Managing General Partner and the
                          costs paid by the Participants;

                  (c)     the total Partnership revenues;

                  (d)     the revenues received or credited to the Managing
                          General Partner and the revenues received and credited
                          to the Participants; and

                  (e)     a reconciliation of the expenses and revenues in
                          accordance with the provisions of Article V.

Additionally, on request the Managing General Partner will provide the
information specified by Form 10-Q (if such report is required to be filed with
the SEC) within 45 days after the close of each quarterly fiscal period.

4.03(b)(2). TAX INFORMATION. The Partnership shall, by March 15 of each year,
prepare, or supervise the preparation of, and transmit to each Participant the
information needed for the Participant to file the following:

          (i)     his federal income tax return;

          (ii)    any required state income tax return; and

          (iii)   any other reporting or filing requirements imposed by any
                  governmental agency or authority.

4.03(b)(3). RESERVE REPORT. Beginning with the second calendar year after the
Offering Termination Date and every year thereafter, the Partnership shall
provide to each Participant the following:

          (i)     a summary of the computation of the Partnership's total oil
                  and gas Proved Reserves;

          (ii)    a summary of the computation of the present worth of the
                  reserves determined using:

                  (a)     a discount rate of 10%;

                  (b)     a constant price for the oil; and

                  (c)     basing the price of gas on the existing gas contracts;

          (iii)   a statement of each Participant's interest in the reserves;
                  and

          (iv)    an estimate of the time required for the extraction of the
                  reserves with a statement that because of the time period
                  required to extract the reserves the present value of revenues
                  to be obtained in the future is less than if immediately
                  receivable.

The reserve computations shall be based on engineering reports prepared by the
Managing General Partner and reviewed by an Independent Expert.

Also, if there is an event that leads to the reduction of the Partnership's
Proved Reserves of 10% or more, excluding:

          (i)     reduction as a result of normal production;

          (ii)    sales of reserves; or


                                       21



          (iii)   product price changes,

then a computation and estimate must be sent to each Participant within 90 days.

4.03(b)(4). COST OF REPORTS. The cost of all reports described in this
ss.4.03(b) shall be paid by the Partnership as Direct Costs.

4.03(b)(5). PARTICIPANT ACCESS TO RECORDS. The Participants and/or their
representatives shall be permitted access to all Partnership records. The
Participant may inspect and copy any of the records after giving adequate notice
to the Managing General Partner at any reasonable time.

Notwithstanding the foregoing, the Managing General Partner may keep logs, well
reports, and other drilling and operating data confidential for reasonable
periods of time. The Managing General Partner may release information concerning
the operations of the Partnership to the sources that are customary in the
industry or required by rule, regulation, or order of any regulatory body.

4.03(b)(6). REQUIRED LENGTH OF TIME TO HOLD RECORDS. The Managing General
Partner must maintain and preserve during the term of the Partnership and for
six years thereafter all accounts, books and other relevant documents which
include:

          (i)     a record that a Participant meets the suitability standards
                  established in connection with an investment in the
                  Partnership; and

          (ii)    any appraisal of the fair market value of the Leases as set
                  forth in ss.4.01(a)(4) or fair market value of any producing
                  property as set forth in ss.4.03(d)(3).

4.03(b)(7). PARTICIPANT LISTS. The following provisions apply regarding access
to the list of Participants:

          (i)     an alphabetical list of the names, addresses, and business
                  telephone numbers of the Participants along with the number of
                  Units held by each of them (the "Participant List") must be
                  maintained as a part of the Partnership's books and records
                  and be available for inspection by any Participant or his
                  designated agent at the home office of the Partnership on the
                  Participant's request;

          (ii)    the Participant List must be updated at least quarterly to
                  reflect changes in the information contained in the
                  Participant List;

          (iii)   a copy of the Participant List must be mailed to any
                  Participant requesting the Participant List within 10 days of
                  the written request, printed in alphabetical order on white
                  paper, and in a readily readable type size in no event smaller
                  than 10-point type and a reasonable charge for copy work will
                  be charged by the Partnership;

          (iv)    the purposes for which a Participant may request a copy of the
                  Participant List include, without limitation, matters relating
                  to Participant's voting rights under this Agreement and the
                  exercise of Participant's rights under the federal proxy laws;
                  and

          (v)     if the Managing General Partner neglects or refuses to
                  exhibit, produce, or mail a copy of the Participant List as
                  requested, the Managing General Partner shall be liable to any
                  Participant requesting the list for the costs, including
                  attorneys fees, incurred by that Participant for compelling
                  the production of the Participant List, and for actual damages
                  suffered by any Participant by reason of the refusal or
                  neglect. It shall be a defense that the actual purpose and
                  reason for the request for inspection or for a copy of the
                  Participant List is to secure the list of Participants or
                  other information for the purpose of selling the list or
                  information or copies of the list, or of using the same for a
                  commercial purpose other than in the interest of the applicant
                  as a Participant relative to the affairs of the Partnership.
                  The Managing General Partner will require the Participant
                  requesting the Participant List to represent in writing that
                  the list was not requested for a commercial purpose unrelated
                  to the Participant's interest in the Partnership. The remedies
                  provided under this subsection to Participants requesting
                  copies of the Participant List are in addition to, and shall
                  not in any way limit, other remedies available to Participants
                  under federal law or the laws of any state.


                                       22



4.03(b)(8). STATE FILINGS. Concurrently with their transmittal to Participants,
and as required, the Managing General Partner shall file a copy of each report
provided for in this ss.4.03(b) with:

          (i)     the California Commissioner of Corporations;

          (ii)    the Arizona Corporation Commission; and

          (iii)   the securities commissions of other states which request the
                  report.

4.03(c). MEETINGS OF PARTICIPANTS.

4.03(c)(1). PROCEDURE FOR A PARTICIPANT MEETING.

4.03(c)(1)(a). MEETINGS MAY BE CALLED BY MANAGING GENERAL PARTNER OR
PARTICIPANTS. Meetings of the Participants may be called as follows:

          (i)     by the Managing General Partner; or

          (ii)    by Participants whose Units equal 10% or more of the total
                  Units for any matters for which Participants may vote.

The call for a meeting by Participants shall be deemed to have been made on
receipt by the Managing General Partner of a written request from holders of the
requisite percentage of Units stating the purpose(s) of the meeting.

4.03(c)(1)(b). NOTICE REQUIREMENT. The Managing General Partner shall deposit in
the United States mail within 15 days after the receipt of the request, written
notice to all Participants of the meeting and the purpose of the meeting. The
meeting shall be held on a date not less than 30 days nor more than 60 days
after the date of the mailing of the notice, at a reasonable time and place.

Notwithstanding the foregoing, the date for notice of the meeting may be
extended for a period of up to 60 days if, in the opinion of the Managing
General Partner, the additional time is necessary to permit preparation of proxy
or information statements or other documents required to be delivered in
connection with the meeting by the SEC or other regulatory authorities.

4.03(c)(1)(c). MAY VOTE BY PROXY. Participants shall have the right to vote at
any Participant meeting either:

          (i)     in person; or

          (ii)    by proxy.

4.03(c)(2). SPECIAL VOTING RIGHTS. At the request of Participants whose Units
equal 10% or more of the total Units, the Managing General Partner shall call
for a vote by Participants. Each Unit is entitled to one vote on all matters,
and each fractional Unit is entitled to that fraction of one vote equal to the
fractional interest in the Unit. Participants whose Units equal a majority of
the total Units may, without the concurrence of the Managing General Partner or
its Affiliates, vote to:

          (i)     dissolve the Partnership;

          (ii)    remove the Managing General Partner and elect a new Managing
                  General Partner;

          (iii)   elect a new Managing General Partner if the Managing General
                  Partner elects to withdraw from the Partnership;

          (iv)    remove the Operator and elect a new Operator;

          (v)     approve or disapprove the sale of all or substantially all of
                  the assets of the Partnership;


                                       23



          (vi)    cancel any contract for services with the Managing General
                  Partner, the Operator, or their Affiliates without penalty on
                  60 days notice; and

          (vii)   amend this Agreement; provided however:

                  (a)     any amendment may not increase the duties or
                          liabilities of any Participant or the Managing General
                          Partner or increase or decrease the profit or loss
                          sharing or required Capital Contribution of any
                          Participant or the Managing General Partner without
                          the approval of the Participant or the Managing
                          General Partner; and

                  (b)     any amendment may not affect the classification of
                          Partnership income and loss for federal income tax
                          purposes without the unanimous approval of all
                          Participants.

4.03(c)(3). RESTRICTIONS ON MANAGING GENERAL PARTNER'S VOTING RIGHTS. With
respect to Units owned by the Managing General Partner or its Affiliates, the
Managing General Partner and its Affiliates may vote or consent on all matters
other than the following:

          (i)     the matters set forth in ss.4.03(c)(2)(ii) and (iv) above; or

          (ii)    any transaction between the Partnership and the Managing
                  General Partner or its Affiliates.

In determining the requisite percentage in interest of Units necessary to
approve any Partnership matter on which the Managing General Partner and its
Affiliates may not vote or consent, any Units owned by the Managing General
Partner and its Affiliates shall not be included.

4.03(c)(4). RESTRICTIONS ON LIMITED PARTNER VOTING RIGHTS. The exercise by the
Limited Partners of the rights granted Participants under ss.4.03(c), except for
the special voting rights granted Participants under ss.4.03(c)(2), shall be
subject to the prior legal determination that the grant or exercise of the
powers will not adversely affect the limited liability of Limited Partners.
Notwithstanding the foregoing, if in the opinion of counsel to the Partnership
the legal determination is not necessary under Delaware law to maintain the
limited liability of the Limited Partners, then it shall not be required. A
legal determination under this paragraph may be made either pursuant to:

          (i)     an opinion of counsel, the counsel being independent of the
                  Partnership and selected on the vote of Limited Partners whose
                  Units equal a majority of the total Units held by Limited
                  Partners; or

          (ii)    a declaratory judgment issued by a court of competent
                  jurisdiction.

The Investor General Partners may exercise the rights granted to the
Participants whether or not the Limited Partners can participate in the vote if
the Investor General Partners represent the requisite percentage of Units
necessary to take the action.

4.03(d). TRANSACTIONS WITH THE MANAGING GENERAL PARTNER.

4.03(d)(1). TRANSFER OF EQUAL PROPORTIONATE INTEREST. When the Managing General
Partner or an Affiliate (excluding another Program in which the interest of the
Managing General Partner or its Affiliates is substantially similar to or less
than their interest in the Partnership) sells, transfers or conveys any natural
gas, oil or other mineral interests or property to the Partnership, it must, at
the same time, sell, transfer or convey to the Partnership an equal
proportionate interest in all its other property in the same Prospect.
Notwithstanding, a Prospect shall be deemed to consist of the drilling or
spacing unit on which the well will be drilled by the Partnership, which is the
minimum area permitted by state law or local practice on which one well may be
drilled, if the following two conditions are met:

          (i)     the geological feature to which the well will be drilled
                  contains Proved Reserves; and

          (ii)    the drilling or spacing unit protects against drainage.

                                       24


With respect to a natural gas or oil Prospect located in Ohio, Pennsylvania and
New York on which a well will be drilled by the Partnership to test the
Clinton/Medina geological formation or the Mississippian and/or Upper Devonian
Sandstone reservoirs, a Prospect shall be deemed to consist of the drilling and
spacing unit if it meets the test in the preceding sentence. Additionally, for a
period of five years after the drilling of the Partnership Well neither the
Managing General Partner nor its Affiliates may drill any well:

          (i)     in the Clinton/Medina geological formation within 1,650 feet
                  of an existing Partnership Well in Pennsylvania or within
                  1,000 feet of an existing Partnership Well in Ohio; or

          (ii)    in the Mississippian/Upper Devonian Sandstone reservoirs in
                  Fayette County and Greene County, Pennsylvania within at least
                  1,000 feet from a producing well, although a partnership may
                  drill a new well or re-enter an existing well which is closer
                  than 1,000 feet to a plugged and abandoned well.

If the Partnership abandons its interest in a well, then this restriction will
continue for one year following the abandonment.

If the area constituting the Partnership's Prospect is subsequently enlarged to
encompass any area in which the Managing General Partner or an Affiliate
(excluding another Program in which the interest of the Managing General Partner
or its Affiliates is substantially similar to or less than their interest in the
Partnership) owns a separate property interest and the activities of the
Partnership were material in establishing the existence of Proved Undeveloped
Reserves that are attributable to the separate property interest, then the
separate property interest or a portion thereof must be sold, transferred, or
conveyed to the Partnership as set forth in this section and ss.ss.4.01(a)(4)
and 4.03(d)(2).

Notwithstanding the foregoing, Prospects in the Clinton/Medina geological
formation, the Mississippian and/or Upper Devonian Sandstone reservoirs, or any
other formation or reservoir shall not be enlarged or contracted if the Prospect
was limited to the drilling or spacing unit because the well was being drilled
to Proved Reserves in the geological formation and the drilling or spacing unit
protected against drainage.

4.03(d)(2). TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS
AFFILIATES' ENTIRE INTEREST. A sale, transfer or a conveyance to the Partnership
of less than all of the ownership of the Managing General Partner or an
Affiliate (excluding another Program in which the interest of the Managing
General Partner or its Affiliates is substantially similar to or less than their
interest in the Partnership) in any Prospect shall not be made unless:

          (i)     the interest retained by the Managing General Partner or the
                  Affiliate is a proportionate Working Interest;

          (ii)    the respective obligations of the Managing General Partner or
                  its Affiliates and the Partnership are substantially the same
                  after the sale of the interest by the Managing General Partner
                  or its Affiliates; and

          (iii)   the Managing General Partner's interest in revenues does not
                  exceed the amount proportionate to its retained Working
                  Interest.

This section does not prevent the Managing General Partner or its Affiliates
from subsequently dealing with their retained interest as they may choose with
unaffiliated parties or Affiliated partnerships.

4.03(d)(3). LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE
MANAGING GENERAL PARTNER. Other than another Program managed by the Managing
General Partner and its Affiliates as set forth in ss.ss.4.03(d)(5) and
4.03(d)(9), the Managing General Partner and its Affiliates shall not receive a
Farmout or purchase any undeveloped Leases from the Partnership other than at
the higher of Cost or fair market value.

The Managing General Partner and its Affiliates, other than an Affiliated Income
Program, may not purchase any producing natural gas or oil property from the
Partnership unless:

          (i)     the sale is in connection with the liquidation of the
                  Partnership; or

          (ii)    the Managing General Partner's well supervision fees under the
                  Drilling and Operating Agreement for the well have exceeded
                  the net revenues of the well, determined without regard to the
                  Managing General Partner's well supervision fees for the well,
                  for a period of at least three consecutive months.


                                       25


In both (i) and (ii), the sale must be at fair market value supported by an
appraisal of an Independent Expert selected by the Managing General Partner.

4.03(d)(4). LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. During a period of five years
after the Offering Termination Date of the Partnership, if the Managing General
Partner or any of its Affiliates (excluding another Program in which the
interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) proposes to acquire
an interest from an unaffiliated person in a Prospect in which the Partnership
possesses an interest or in a Prospect in which the Partnership's interest has
been terminated without compensation within one year preceding the proposed
acquisition, then the following conditions shall apply:

          (i)     if the Managing General Partner or the Affiliate (excluding
                  another Program in which the interest of the Managing General
                  Partner or its Affiliates is substantially similar to or less
                  than their interest in the Partnership) does not currently own
                  property in the Prospect separately from the Partnership, then
                  neither the Managing General Partner nor the Affiliate shall
                  be permitted to purchase an interest in the Prospect; and

          (ii)    if the Managing General Partner or the Affiliate (excluding
                  another Program in which the interest of the Managing General
                  Partner or its Affiliates is substantially similar to or less
                  than their interest in the Partnership) currently owns a
                  proportionate interest in the Prospect separately from the
                  Partnership, then the interest to be acquired shall be divided
                  between the Partnership and the Managing General Partner or
                  the Affiliate in the same proportion as is the other property
                  in the Prospect. Provided, however, if cash or financing is
                  not available to the Partnership to enable it to complete a
                  purchase of the additional interest to which it is entitled,
                  then neither the Managing General Partner nor the Affiliate
                  shall be permitted to purchase any additional interest in the
                  Prospect.

4.03(d)(5). TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The
transfer of an undeveloped Lease from the Partnership to an Affiliated Drilling
Program must be made at fair market value if the undeveloped Lease has been held
for more than two years. Otherwise, if the Managing General Partner deems it to
be in the best interest of the Partnership, the transfer may be made at Cost.

An Affiliated Income Program may purchase a producing natural gas and oil
property from the Partnership at any time at:

          (i)     fair market value as supported by an appraisal from an
                  Independent Expert if the property has been held by the
                  Partnership for more than six months or significant
                  expenditures have been made in connection with the property;
                  or

          (ii)    Cost as adjusted for intervening operations if the Managing
                  General Partner deems it to be in the best interest of the
                  Partnership.

However, these prohibitions shall not apply to joint ventures or Farmouts among
Affiliated partnerships, provided that:

          (i)     the respective obligations and revenue sharing of all parties
                  to the transaction are substantially the same; and

          (ii)    the compensation arrangement or any other interest or right of
                  either the Managing General Partner or its Affiliates is the
                  same in each Affiliated partnership or if different, the
                  aggregate compensation of the Managing General Partner or the
                  Affiliate is reduced to reflect the lower compensation
                  arrangement.

4.03(d)(6). SALE OF ALL ASSETS. The sale of all or substantially all of the
assets of the Partnership, including without limitation, Leases, wells,
equipment and production therefrom, shall be made only with the consent of
Participants whose Units equal a majority of the total Units.

4.03(d)(7). SERVICES.

4.03(d)(7)(a). COMPETITIVE RATES. The Managing General Partner and any Affiliate
shall not render to the Partnership any oil field, equipage, or other services
nor sell or lease to the Partnership any equipment or related supplies unless:


                                       26



          (i)     the person is engaged, independently of the Partnership and as
                  an ordinary and ongoing business, in the business of rendering
                  the services or selling or leasing the equipment and supplies
                  to a substantial extent to other persons in the natural gas
                  and oil industry in addition to the partnerships in which the
                  Managing General Partner or an Affiliate has an interest; and

          (ii)    the compensation, price, or rental therefor is competitive
                  with the compensation, price, or rental of other persons in
                  the area engaged in the business of rendering comparable
                  services or selling or leasing comparable equipment and
                  supplies which could reasonably be made available to the
                  Partnership.

If the person is not engaged in such a business, then the compensation, price or
rental shall be the Cost of the services, equipment or supplies to the person or
the competitive rate which could be obtained in the area, whichever is less.

4.03(d)(7)(b). IF NOT DISCLOSED IN THE PROSPECTUS OR THIS AGREEMENT THEN
SERVICES BY THE MANAGING GENERAL PARTNER MUST BE DESCRIBED IN A SEPARATE
CONTRACT AND CANCELABLE. Any services for which the Managing General Partner or
an Affiliate is to receive compensation other than those described in this
Agreement or the Prospectus shall be set forth in a written contract which
precisely describes the services to be rendered and all compensation to be paid.
These contracts are cancelable without penalty on 60 days written notice by
Participants whose Units equal a majority of the total Units.

4.03(d)(8). LOANS.

4.03(d)(8)(a). NO LOANS FROM THE PARTNERSHIP. No loans or advances shall be made
by the Partnership to the Managing General Partner or any Affiliate.

4.03(d)(8)(b). LOANS TO THE PARTNERSHIP. Neither the Managing General Partner
nor any Affiliate shall loan money to the Partnership if the interest to be
charged exceeds either:

          (i)     the Managing General Partner's or the Affiliate's interest
                  cost; or

          (ii)    that which would be charged to the Partnership, without
                  reference to the Managing General Partner's or the Affiliate's
                  financial abilities or guarantees, by unrelated lenders, on
                  comparable loans for the same purpose.

Neither the Managing General Partner nor any Affiliate shall receive points or
other financing charges or fees, regardless of the amount, although the actual
amount of the charges incurred from third-party lenders may be reimbursed to the
Managing General Partner or the Affiliate.

4.03(d)(9). FARMOUTS. The Managing General Partner shall not enter into a
Farmout to avoid its paying its share of costs related to drilling an
undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or
well activity to the Managing General Partner or its Affiliates except as set
forth in ss.4.03(d)(3). Notwithstanding, this restriction shall not apply to
Farmouts between the Partnership and another partnership managed by the Managing
General Partner or its Affiliates, either separately or jointly, provided that
the respective obligations and revenue sharing of all parties to the
transactions are substantially the same and the compensation arrangement or any
other interest or right of the Managing General Partner or its Affiliates is the
same in each partnership, or, if different, the aggregate compensation of the
Managing General Partner and its Affiliates is reduced to reflect the lower
compensation agreement.

The Partnership may Farmout an undeveloped lease or well activity only if the
Managing General Partner, exercising the standard of a prudent operator,
determines that:

          (i)     the Partnership lacks the funds to complete the oil and gas
                  operations on the Lease or well and cannot obtain suitable
                  financing;

          (ii)    drilling on the Lease or the intended well activity would
                  concentrate excessive funds in one location, creating undue
                  risks to the Partnership;

          (iii)   the Leases or well activity have been downgraded by events
                  occurring after assignment to the Partnership so that
                  development of the Leases or well activity would not be
                  desirable; or


                                       27


          (iv)    the best interests of the Partnership would be served.

If the Partnership Farmouts a Lease or well activity, the Managing General
Partner must retain on behalf of the Partnership the economic interests and
concessions as a reasonably prudent oil and gas operator would or could retain
under the circumstances prevailing at the time, consistent with industry
practices.

4.03(d)(10). NO COMPENSATING BALANCES. Neither the Managing General Partner nor
any Affiliate shall use the Partnership's funds as compensating balances for its
own benefit.

4.03(d)(11). FUTURE PRODUCTION. Neither the Managing General Partner nor any
Affiliate shall commit the future production of a well developed by the
Partnership exclusively for its own benefit.

4.03(d)(12). MARKETING ARRANGEMENTS. Subject to ss.4.06(c), all benefits from
marketing arrangements or other relationships affecting the property of the
Managing General Partner or its Affiliates and the Partnership shall be fairly
and equitably apportioned according to the respective interests of each in the
property. The Managing General Partner shall treat all wells in a geographic
area equally concerning to whom and at what price the Partnership's natural gas
and oil will be sold and to whom and at what price the natural gas and oil of
other natural gas and oil Programs which the Managing General Partner has
sponsored or will sponsor will be sold. For example, each seller of natural gas
and oil in a given area will be paid a weighted average selling price for all
natural gas and oil sold in that geographic area. The Managing General Partner,
in its sole discretion, shall determine what constitutes a geographic area.

4.03(d)(13). ADVANCE PAYMENTS. Advance payments by the Partnership to the
Managing General Partner and its Affiliates are prohibited except when advance
payments are required to secure the tax benefits of prepaid Intangible Drilling
Costs and for a business purpose.

4.03(d)(14). NO REBATES. No rebates or give-ups may be received by the Managing
General Partner or any Affiliate nor may the Managing General Partner or any
Affiliate participate in any reciprocal business arrangements which would
circumvent these guidelines.

4.03(d)(15). PARTICIPATION IN OTHER PARTNERSHIPS. If the Partnership
participates in other partnerships or joint ventures (multi-tier arrangements),
then the terms of any of these arrangements shall not result in the
circumvention of any of the requirements or prohibitions contained in this
Agreement, including the following:

          (i)     there shall be no duplication or increase in Organization and
                  Offering Costs, the Managing General Partner's compensation,
                  Partnership expenses or other fees and costs;

          (ii)    there shall be no substantive alteration in the fiduciary and
                  contractual relationship between the Managing General Partner
                  and the Participants; and

          (iii)   there shall be no diminishment in the voting rights of the
                  Participants.

4.03(d)(16). ROLL-UP LIMITATIONS.

4.03(d)(16)(a). REQUIREMENT FOR APPRAISAL AND ITS ASSUMPTIONS. In connection
with a proposed Roll-Up, an appraisal of all Partnership assets shall be
obtained from a competent Independent Expert. If the appraisal will be included
in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal
shall be filed with the SEC and the Administrator as an exhibit to the
registration statement for the offering. Thus, an issuer using the appraisal
shall be subject to liability for violation of Section 11 of the Securities Act
of 1933 and comparable provisions under state law for any material
misrepresentations or material omissions in the appraisal.

Partnership assets shall be appraised on a consistent basis. The appraisal shall
be based on all relevant information, including current reserve estimates
prepared by an independent petroleum consultant, and shall indicate the value of
the Partnership's assets as of a date immediately before the announcement of the
proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation
of the Partnership's assets over a 12-month period.


                                       28


The terms of the engagement of the Independent Expert shall clearly state that
the engagement is for the benefit of the Partnership and the Participants. A
summary of the independent appraisal, indicating all material assumptions
underlying the appraisal, shall be included in a report to the Participants in
connection with a proposed Roll-Up.

4.03(d)(16)(b). RIGHTS OF PARTICIPANTS WHO VOTE AGAINST PROPOSAL. In connection
with a proposed Roll-Up, Participants who vote "no" on the proposal shall be
offered the choice of:

          (i)     accepting the securities of the Roll-Up Entity offered in the
                  proposed Roll-Up; or

          (ii)    one of the following:

                  (a)     remaining as Participants in the Partnership and
                          preserving their Units in the Partnership on the same
                          terms and conditions as existed previously; or

                  (b)     receiving cash in an amount equal to the Participants'
                          pro rata share of the appraised value of the net
                          assets of the Partnership based on their respective
                          number of Units.

4.03(d)(16)(c). NO ROLL-UP IF DIMINISHMENT OF VOTING RIGHTS. The Partnership
shall not participate in any proposed Roll-Up which, if approved, would result
in the diminishment of any Participant's voting rights under the Roll-Up
Entity's chartering agreement.

In no event shall the democracy rights of Participants in the Roll-Up Entity be
less than those provided for under ss.ss.4.03(c)(1) and 4.03(c)(2) of this
Agreement. If the Roll-Up Entity is a corporation, then the democracy rights of
Participants shall correspond to the democracy rights provided for in this
Agreement to the greatest extent possible.

4.03(d)(16)(d). NO ROLL-UP IF ACCUMULATION OF SHARES WOULD BE IMPEDED. The
Partnership shall not participate in any proposed Roll-Up transaction which
includes provisions that would operate to materially impede or frustrate the
accumulation of shares by any purchaser of the securities of the Roll-Up Entity,
except to the minimum extent necessary to preserve the tax status of the Roll-Up
Entity.

The Partnership shall not participate in any proposed Roll-Up transaction which
would limit the ability of a Participant to exercise the voting rights of its
securities of the Roll-Up Entity on the basis of the number of Units held by
that Participant.

4.03(d)(16)(e). NO ROLL-UP IF ACCESS TO RECORDS WOULD BE LIMITED. The
Partnership shall not participate in a Roll-Up in which Participants' rights of
access to the records of the Roll-Up Entity will be less than those provided for
under ss.ss.4.03(b)(5), 4.03(b)(6) and 4.03(b)(7) of this Agreement.

4.03(d)(16)(f). COST OF ROLL-UP. The Partnership shall not participate in any
proposed Roll-Up transaction in which any of the costs of the transaction would
be borne by the Partnership if Participants whose Units equal 66% of the total
Units do not vote to approve the proposed Roll-Up.

4.03(d)(16)(g). ROLL-UP APPROVAL. The Partnership shall not participate in a
Roll-Up transaction unless the Roll-Up transaction is approved by Participants
whose Units equal 66% of the total Units.

4.03(d)(17). DISCLOSURE OF BINDING AGREEMENTS. Any agreement or arrangement
which binds the Partnership must be disclosed in the Prospectus.

4.03(d)(18). TRANSACTIONS MUST BE FAIR AND REASONABLE. Neither the Managing
General Partner nor any Affiliate shall sell, transfer, or convey any property
to or purchase any property from the Partnership, directly or indirectly, except
under transactions that are fair and reasonable, nor take any action with
respect to the assets or property of the Partnership which does not primarily
benefit the Partnership.

4.04. DESIGNATION, COMPENSATION AND REMOVAL OF MANAGING GENERAL PARTNER AND
REMOVAL OF OPERATOR.

4.04(a). MANAGING GENERAL PARTNER.

4.04(a)(1). TERM OF SERVICE. Atlas shall serve as the Managing General Partner
of the Partnership until either it:


                                       29



          (i)     is removed pursuant to ss.4.04(a)(3); or

          (ii)    withdraws pursuant to ss.4.04(a)(3)(f).

4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. In addition to the
compensation set forth in ss.ss.4.01(a)(4) and 4.02(d)(1), the Managing General
Partner shall receive the compensation set forth in ss.ss.4.04(a)(2)(b) through
4.04(a)(2)(g).

4.04(a)(2)(a). CHARGES MUST BE NECESSARY AND REASONABLE. Charges by the Managing
General Partner for goods and services must be fully supportable as to:

          (i)     the necessity of the goods and services; and

          (ii)    the reasonableness of the amount charged.

All actual and necessary expenses incurred by the Partnership may be paid out of
the Partnership's subscription proceeds and revenues.

4.04(a)(2)(b). DIRECT COSTS. The Managing General Partner and its Affiliates
shall be reimbursed for all Direct Costs. Direct Costs, however, shall be billed
directly to and paid by the Partnership to the extent practicable.

4.04(a)(2)(c). ADMINISTRATIVE COSTS. The Managing General Partner shall receive
an unaccountable, fixed payment reimbursement for its Administrative Costs of
$75 per well per month. The unaccountable, fixed payment reimbursement of $75
per well per month shall be subject to the following:

          (i)     it shall not be increased in amount during the term of the
                  Partnership;

          (ii)    it shall be proportionately reduced to the extent the
                  Partnership acquires less than 100% of the Working Interest in
                  the well;

          (iii)   it shall be the entire payment to reimburse the Managing
                  General Partner for the Partnership's Administrative Costs;
                  and

          (iv)    it shall not be received for plugged or abandoned wells.

4.04(a)(2)(d). GAS GATHERING. The Managing General Partner shall be responsible
for gathering and transporting the natural gas produced by the Partnership to
interstate pipeline systems, local distribution companies and/or end-users in
the area and shall receive a gathering fee at a competitive rate for gathering
and transporting the Partnership's gas. If the Partnership's gas production is
gathered and transported through the gathering system owned by Atlas Pipeline
Partners, then the Managing General Partner shall apply its gathering fee
towards the agreement between Atlas Pipeline Partners and Atlas America, Inc.,
Resource Energy, Inc., and Viking Resources Corporation. If the Partnership's
gas production is gathered and transferred through a gathering system owned by a
third-party, then the Managing General Partner shall pay a portion or all of its
gathering fee to the third-party gathering the natural gas.

4.04(a)(2)(e). DEALER-MANAGER FEE. Subject to ss.3.03(a)(1), the Dealer-Manager
shall receive on each Unit sold to investors:

          (i)     a 2.5% Dealer-Manager fee;

          (ii)    a 7% Sales Commission;

          (iii)   a .5% accountable Reimbursement for Permissible Non-Cash
                  Compensation; and

          (iv)    an up to .5% reimbursement of the Selling Agents' bona fide
                  accountable due diligence expenses.

4.04(a)(2)(f). DRILLING AND OPERATING AGREEMENT. The Managing General Partner
and its Affiliates shall receive compensation as set forth in the Drilling and
Operating Agreement.

                                       30



4.04(a)(2)(g). OTHER TRANSACTIONS. The Managing General Partner and its
Affiliates may enter into transactions pursuant to ss.4.03(d)(7) with the
Partnership and shall be entitled to compensation under that section.

4.04(a)(3). REMOVAL OF MANAGING GENERAL PARTNER.

4.04(a)(3)(a). MAJORITY VOTE REQUIRED TO REMOVE THE MANAGING GENERAL PARTNER.
The Managing General Partner may be removed at any time on 60 days' advance
written notice to the outgoing Managing General Partner by the affirmative vote
of Participants whose Units equal a majority of the total Units.

If the Participants vote to remove the Managing General Partner from the
Partnership, then Participants must elect by an affirmative vote of Participants
whose Units equal a majority of the total Units either to:

          (i)     terminate, dissolve, and wind up the Partnership; or

          (ii)    continue as a successor limited partnership under all the
                  terms of this Partnership Agreement as provided in ss.7.01(c).

If the Participants elect to continue as a successor limited partnership, then
the Managing General Partner shall not be removed until a substituted Managing
General Partner has been selected by an affirmative vote of Participants whose
Units equal a majority of the total Units and installed as such.

4.04(a)(3)(b). VALUATION OF MANAGING GENERAL PARTNER'S INTEREST IN THE
PARTNERSHIP. If the Managing General Partner is removed, then its interest in
the Partnership shall be determined by appraisal by a qualified Independent
Expert. The Independent Expert shall be selected by mutual agreement between the
removed Managing General Partner and the incoming Managing General Partner. The
appraisal shall take into account an appropriate discount, to reflect the risk
of recovery of natural gas and oil reserves, but not less than that used in the
most recent presentment offer, if any.

The cost of the appraisal shall be borne equally by the removed Managing General
Partner and the Partnership.

4.04(a)(3)(c). INCOMING MANAGING GENERAL PARTNER'S OPTION TO PURCHASE. The
incoming Managing General Partner shall have the option to purchase 20% of the
removed Managing General Partner's interest in the Partnership as Managing
General Partner and not as a Participant for the value determined by the
Independent Expert.

4.04(a)(3)(d). METHOD OF PAYMENT. The method of payment for the removed Managing
General Partner's interest must be fair and protect the solvency and liquidity
of the Partnership. The method of payment shall be as follows:

          (i)     when the termination is voluntary, the method of payment shall
                  be a non-interest bearing unsecured promissory note with
                  principal payable, if at all, from distributions which the
                  Managing General Partner otherwise would have received under
                  the Partnership Agreement had the Managing General Partner not
                  been terminated; and

          (ii)    when the termination is involuntary, the method of payment
                  shall be an interest bearing promissory note coming due in no
                  less than five years with equal installments each year. The
                  interest rate shall be that charged on comparable loans.

4.04(a)(3)(e). TERMINATION OF CONTRACTS. The removed Managing General Partner,
at the time of its removal shall cause, to the extent it is legally possible,
its successor to be transferred or assigned all its rights, obligations and
interests as Managing General Partner of the Partnership in contracts entered
into by it on behalf of the Partnership. In any event, the removed Managing
General Partner shall cause its rights, obligations and interests as Managing
General Partner of the Partnership in any such contract to terminate at the time
of its removal.

Notwithstanding any other provision in this Agreement, the Partnership or the
successor Managing General Partner shall not:

          (i)     be a party to any natural gas supply agreement that the
                  Managing General Partner or its Affiliates enters into with a
                  third-party;


                                       31


          (ii)    have any rights pursuant to such natural gas supply agreement;
                  or

          (iii)   receive any interest in the Managing General Partner's and its
                  Affiliates' pipeline or gathering system or compression
                  facilities.

4.04(a)(3)(f). THE MANAGING GENERAL PARTNER'S RIGHT TO VOLUNTARILY WITHDRAW. At
any time beginning 10 years after the Offering Termination Date and the
Partnership's primary drilling activities, the Managing General Partner may
voluntarily withdraw as Managing General Partner on giving 120 days' written
notice of withdrawal to the Participants. If the Managing General Partner
withdraws, then the following conditions shall apply:

          (i)     the Managing General Partner's interest in the Partnership
                  shall be determined as described in ss.4.04(a)(3)(b) above
                  with respect to removal; and

          (ii)    the interest shall be distributed to the Managing General
                  Partner as described in ss.4.04(a)(3)(d)(i) above.

Any successor Managing General Partner shall have the option to purchase 20% of
the withdrawing Managing General Partner's interest in the Partnership at the
value determined as described above with respect to removal.

4.04(a)(3)(g). THE MANAGING GENERAL PARTNER'S RIGHT TO WITHDRAW PROPERTY
INTEREST. The Managing General Partner has the right at any time to withdraw a
property interest held by the Partnership in the form of a Working Interest in
the Partnership Wells equal to or less than its respective interest in the
revenues of the Partnership under the conditions set forth in ss.6.03. If the
Managing General Partner withdraws an interest, then the Managing General
Partner shall:

          (i)     pay the expenses of withdrawing; and

          (ii)    fully indemnify the Partnership against any additional
                  expenses which may result from a partial withdrawal of its
                  interests including insuring that a greater amount of Direct
                  Costs or Administrative Costs is not allocated to the
                  Participants.

4.04(a)(4). REMOVAL OF OPERATOR. The Operator may be removed and a new Operator
may be substituted at any time on 60 days advance written notice to the outgoing
Operator by the Managing General Partner acting on behalf of the Partnership on
the affirmative vote of Participants whose Units equal a majority of the total
Units.

The Operator shall not be removed until a substituted Operator has been selected
by an affirmative vote of Participants whose Units equal a majority of the total
Units and installed as such.

4.05. INDEMNIFICATION AND EXONERATION.

4.05(a)(1). STANDARDS FOR THE MANAGING GENERAL PARTNER NOT INCURRING LIABILITY
TO THE PARTNERSHIP OR PARTICIPANTS. The Managing General Partner, the Operator,
and their Affiliates shall not have any liability whatsoever to the Partnership
or to any Participant for any loss suffered by the Partnership or Participants
which arises out of any action or inaction of the Managing General Partner, the
Operator, or their Affiliates if:

          (i)     the Managing General Partner, the Operator, and their
                  Affiliates determined in good faith that the course of conduct
                  was in the best interest of the Partnership;

          (ii)    the Managing General Partner, the Operator, and their
                  Affiliates were acting on behalf of, or performing services
                  for, the Partnership; and

          (iii)   the course of conduct did not constitute negligence or
                  misconduct of the Managing General Partner, the Operator, or
                  their Affiliates.

4.05(a)(2). STANDARDS FOR MANAGING GENERAL PARTNER INDEMNIFICATION. The Managing
General Partner, the Operator, and their Affiliates shall be indemnified by the
Partnership against any losses, judgments, liabilities, expenses, and amounts
paid in settlement of any claims sustained by them in connection with the
Partnership, provided that:

                                       32



          (i)     the Managing General Partner, the Operator, and their
                  Affiliates determined in good faith that the course of conduct
                  which caused the loss or liability was in the best interest of
                  the Partnership;

          (ii)    the Managing General Partner, the Operator, and their
                  Affiliates were acting on behalf of, or performing services
                  for, the Partnership; and

          (iii)   the course of conduct was not the result of negligence or
                  misconduct of the Managing General Partner, the Operator, or
                  their Affiliates.

Provided, however, payments arising from such indemnification or agreement to
hold harmless are recoverable only out of the following:

          (i)     the Partnership's tangible net assets which include its
                  revenues; and

          (ii)    any insurance proceeds from the types of insurance for which
                  the Managing General Partner, the Operator and their
                  Affiliates may be indemnified under this Agreement.

4.05(a)(3). STANDARDS FOR SECURITIES LAW INDEMNIFICATION. Notwithstanding
anything to the contrary contained in the above, the Managing General Partner,
the Operator, and their Affiliates and any person acting as a broker/dealer
shall not be indemnified for any losses, liabilities or expenses arising from or
out of an alleged violation of federal or state securities laws by such party
unless:

          (i)     there has been a successful adjudication on the merits of each
                  count involving alleged securities law violations as to the
                  particular indemnitee;

          (ii)    the claims have been dismissed with prejudice on the merits by
                  a court of competent jurisdiction as to the particular
                  indemnitee; or

          (iii)   a court of competent jurisdiction approves a settlement of the
                  claims against a particular indemnitee and finds that
                  indemnification of the settlement and the related costs should
                  be made, and the court considering the request for
                  indemnification has been advised of the position of the SEC,
                  the Massachusetts Securities Division, and any state
                  securities regulatory authority in which plaintiffs claim they
                  were offered or sold Units with respect to the issue of
                  indemnification for violation of securities laws.

4.05(a)(4). STANDARDS FOR ADVANCEMENT OF FUNDS TO THE MANAGING GENERAL PARTNER
AND INSURANCE. The advancement of Partnership funds to the Managing General
Partner, the Operator, or their Affiliates for legal expenses and other costs
incurred as a result of any legal action for which indemnification is being
sought is permissible only if the Partnership has adequate funds available and
the following conditions are satisfied:

          (i)     the legal action relates to acts or omissions with respect to
                  the performance of duties or services on behalf of the
                  Partnership;

          (ii)    the legal action is initiated by a third-party who is not a
                  Participant, or the legal action is initiated by a Participant
                  and a court of competent jurisdiction specifically approves
                  the advancement; and

          (iii)   the Managing General Partner or its Affiliates undertake to
                  repay the advanced funds to the Partnership, together with the
                  applicable legal rate of interest thereon, in cases in which
                  such party is found not to be entitled to indemnification.

The Partnership shall not bear the cost of that portion of insurance which
insures the Managing General Partner, the Operator, or their Affiliates for any
liability for which they could not be indemnified pursuant to ss.ss.4.05(a)(1)
and 4.05(a)(2).

4.05(b). LIABILITY OF PARTNERS. Under the Delaware Revised Uniform Limited
Partnership Act, the Investor General Partners are liable jointly and severally
for all liabilities and obligations of the Partnership. Notwithstanding the
foregoing, as among themselves, the Investor General Partners agree that each
shall be solely and individually responsible only for his pro rata share of the
liabilities and obligations of the Partnership based on his respective number of
Units.

                                       33



In addition, the Managing General Partner agrees to use its corporate assets to
indemnify each of the Investor General Partners against all Partnership related
liabilities which exceed the Investor General Partner's interest in the
undistributed net assets of the Partnership and insurance proceeds, if any.
Further, the Managing General Partner agrees to indemnify each Investor General
Partner against any personal liability as a result of the unauthorized acts of
another Investor General Partner.

If the Managing General Partner provides indemnification, then each Investor
General Partner who has been indemnified shall transfer and subrogate his rights
for contribution from or against any other Investor General Partner to the
Managing General Partner.

4.05(c). ORDER OF PAYMENT OF CLAIMS. Claims shall be paid as follows:

          (i)     first, out of any insurance proceeds;

          (ii)    second, out of Partnership assets and revenues; and

          (iii)   last, by the Managing General Partner as provided in
                  ss.ss.3.05(b)(2) and (3) and 4.05(b).

No Limited Partner shall be required to reimburse the Managing General Partner,
the Operator, their Affiliates, or the Investor General Partners for any
liability in excess of his agreed Capital Contribution, except:

          (i)     for a liability resulting from the Limited Partner's
                  unauthorized participation in Partnership management; or

          (ii)    from some other breach by the Limited Partner of this
                  Agreement.

4.05(d). AUTHORIZED TRANSACTIONS ARE NOT DEEMED TO BE A BREACH. No transaction
entered into or action taken by the Partnership, the Managing General Partner,
the Operator, or their Affiliates, which is authorized by this Agreement shall
be deemed a breach of any obligation owed by the Managing General Partner, the
Operator, or their Affiliates to the Partnership or the Participants.

4.06. OTHER ACTIVITIES.

4.06(a). THE MANAGING GENERAL PARTNER MAY PURSUE OTHER NATURAL GAS AND OIL
ACTIVITIES FOR ITS OWN ACCOUNT. The Managing General Partner, the Operator, and
their Affiliates are now engaged, and will engage in the future, for their own
account and for the account of others, including other investors, in all aspects
of the natural gas and oil business. This includes without limitation, the
evaluation, acquisition, and sale of producing and nonproducing Leases, and the
exploration for and production of natural gas, oil and other minerals.

The Managing General Partner is required to devote only so much of its time as
is necessary to manage the affairs of the Partnership. Except as expressly
provided to the contrary in this Agreement, and subject to fiduciary duties, the
Managing General Partner, the Operator, and their Affiliates may do the
following:

          (i)     continue their activities, or initiate further such
                  activities, individually, jointly with others, or as a part of
                  any other limited or general partnership, tax partnership,
                  joint venture, or other entity or activity to which they are
                  or may become a party, in any locale and in the same fields,
                  areas of operation or prospects in which the Partnership may
                  likewise be active;

          (ii)    reserve partial interests in Leases being assigned to the
                  Partnership or any other interests not expressly prohibited by
                  this Agreement;

          (iii)   deal with the Partnership as independent parties or through
                  any other entity in which they may be interested;

          (iv)    conduct business with the Partnership as set forth in this
                  Agreement; and

          (v)     participate in such other investor operations, as investors or
                  otherwise.

                                       34


The Managing General Partner and its Affiliates shall not be required to permit
the Partnership or the Participants to participate in any of the operations in
which the Managing General Partner and its Affiliates may be interested or share
in any profits or other benefits from the operations. However, except as
otherwise provided in this Agreement, the Managing General Partner and its
Affiliates may pursue business opportunities that are consistent with the
Partnership's investment objectives for their own account only after they have
determined that the opportunity either:

          (i)     cannot be pursued by the Partnership because of insufficient
                  funds; or

          (ii)    it is not appropriate for the Partnership under the existing
                  circumstances.

4.06(b). MANAGING GENERAL PARTNER MAY MANAGE MULTIPLE PARTNERSHIPS. The Managing
General Partner or its Affiliates may manage multiple Programs simultaneously.

4.06(c). PARTNERSHIP HAS NO INTEREST IN NATURAL GAS CONTRACTS OR PIPELINES AND
GATHERING SYSTEMS. Notwithstanding any other provision in this Agreement, the
Partnership shall not:

          (i)     be a party to any natural gas supply agreement that the
                  Managing General Partner, the Operator, or their Affiliates
                  enter into with a third-party or have any rights pursuant to
                  such natural gas supply agreement; or

          (ii)    receive any interest in the Managing General Partner's, the
                  Operator's, and their Affiliates' pipeline or gathering system
                  or compression facilities.


                                    ARTICLE V
                      PARTICIPATION IN COSTS AND REVENUES,
                  CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS

5.01. PARTICIPATION IN COSTS AND REVENUES. Except as otherwise provided in this
Agreement, costs and revenues shall be charged and credited to the Managing
General Partner and the Participants as set forth in this section and its
subsections.

5.01(a). COSTS. Costs shall be charged as set forth below.

5.01(a)(1). ORGANIZATION AND OFFERING COSTS. Organization and Offering Costs
shall be charged 100% to the Managing General Partner. For purposes of sharing
in revenues under ss.5.01(b)(4), the Managing General Partner shall be credited
with Organization and Offering Costs paid by it and for services provided by it
as Organization Costs up to and including 15% of the Partnership's subscription
proceeds. Any Organization and Offering Costs paid and/or provided in services
by the Managing General Partner in excess of this amount shall not be credited
towards the Managing General Partner's required Capital Contribution or revenue
share set forth in ss.5.01(b)(4). The Managing General Partner's credit for
services provided to the Partnership as Organization Costs shall be determined
based on generally accepted accounting principles.

5.01(a)(2). INTANGIBLE DRILLING COSTS. Intangible Drilling Costs shall be
charged 100% to the Participants.

5.01(a)(3). TANGIBLE COSTS. Tangible Costs shall be charged 66% to the Managing
General Partner and 34% to the Participants. However, if the total Tangible
Costs for all of the Partnership's wells that would be charged to the
Participants exceeds an amount equal to 10% of the Partnership's subscription
proceeds, then the excess shall be charged to the Managing General Partner.

5.01(a)(4). OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER
COSTS. Operating Costs, Direct Costs, Administrative Costs, and all other
Partnership costs not specifically allocated shall be charged to the parties in
the same ratio as the related production revenues are being credited.

5.01(a)(5). ALLOCATION OF INTANGIBLE DRILLING COSTS AND TANGIBLE COSTS AT
PARTNERSHIP CLOSINGS. Intangible Drilling Costs and the Participants' share of
Tangible Costs of a well or wells to be drilled and completed with the proceeds
of a Partnership closing shall be charged 100% to the Participants who are
admitted to the Partnership in that closing and shall not be reallocated to take
into account other Partnership closings.


                                       35



Although the proceeds of each Partnership closing will be used to pay the costs
of drilling different wells, not less than 90% of each Participant's
subscription proceeds shall be applied to Intangible Drilling Costs and not more
than 10% of each Participant's subscription proceeds shall be applied to
Tangible Costs regardless of when he subscribes.

5.01(a)(6). LEASE COSTS. The Leases shall be contributed to the Partnership by
the Managing General Partner as set forth in ss.4.01(a)(4).

5.01(b). REVENUES. Revenues shall be credited as set forth below.

5.01(b)(1). ALLOCATION OF REVENUES ON DISPOSITION OF PROPERTY. If the parties'
Capital Accounts are adjusted to reflect the simulated depletion of a natural
gas or oil property of the Partnership, then the portion of the total amount
realized by the Partnership on the taxable disposition of the property that
represents recovery of its simulated tax basis in the property shall be
allocated to the parties in the same proportion as the aggregate adjusted tax
basis of the property was allocated to the parties or their predecessors in
interest. If the parties' Capital Accounts are adjusted to reflect the actual
depletion of a natural gas or oil property of the Partnership, then the portion
of the total amount realized by the Partnership on the taxable disposition of
the property that equals the parties' aggregate remaining adjusted tax basis in
the property shall be allocated to the parties in proportion to their respective
remaining adjusted tax bases in the property. Thereafter, any excess shall be
allocated to the Managing General Partner in an amount equal to the difference
between the fair market value of the Lease at the time it was contributed to the
Partnership and its simulated or actual adjusted tax basis at that time.
Finally, any excess shall be credited as provided in ss.5.01(b)(4), below.

In the event of a sale of developed natural gas and oil properties with
equipment on the properties, the Managing General Partner may make any
reasonable allocation of proceeds between the equipment and the Leases.

5.01(b)(2). INTEREST. Interest earned on each Participant's subscription
proceeds before the Offering Termination Date under ss.3.05(b)(1) shall be
credited to the accounts of the respective subscribers who paid the subscription
proceeds to the Partnership. The interest shall be paid to the Participant not
later than the Partnership's first cash distribution from operations.

After the Offering Termination Date and until proceeds from the offering are
invested in the Partnership's natural gas and oil operations, any interest
income from temporary investments shall be allocated pro rata to the
Participants providing the subscription proceeds.

All other interest income, including interest earned on the deposit of
production revenues, shall be credited as provided in ss.5.01(b)(4), below.

5.01(b)(3). SALE OR DISPOSITION OF EQUIPMENT. Proceeds from the sale or
disposition of equipment shall be credited to the parties charged with the costs
of the equipment in the ratio in which the costs were charged.

5.01(b)(4). OTHER REVENUES. Subject to ss.5.01(b)(4)(a), the Managing General
Partner and the Participants shall share in all other Partnership revenues in
the same percentage as their respective Capital Contribution bears to the total
Partnership Capital Contributions, except that the Managing General Partner
shall receive an additional 7% of Partnership revenues. However, the Managing
General Partner's total revenue share may not exceed 35% of Partnership
revenues. For example, if the Managing General Partner contributes 25% of the
total Partnership Capital Contributions and the Participants contribute 75% of
the total Partnership Capital Contributions, then the Managing General Partner
shall receive 32% of the Partnership revenues and the Participants shall receive
68% of the Partnership revenues. On the other hand, if the Managing General
Partner contributes 30% of the total Partnership Capital Contributions and the
Participants contribute 70% of the total Partnership Capital Contributions, then
the Managing General Partner shall receive 35% of the Partnership revenues, not
37%, because its revenue share cannot exceed 35% of Partnership revenues, and
the Participants shall receive 65% of Partnership revenues.

5.01(b)(4)(a). SUBORDINATION. The Managing General Partner shall subordinate up
to 50% of its share of Partnership Net Production Revenues to the receipt by
Participants of cash distributions from the Partnership equal to $1,000 per Unit
(which is 10% per Unit) regardless of their actual subscription price of the
Units, in each of the first five 12-month periods beginning with the
Partnership's first cash distributions from operations. In this regard:

                                       36



          (i)     the 60-month subordination period shall begin with the first
                  cash distribution from operations to the Participants, but no
                  subordination distributions to the Participants shall be
                  required until the Partnership's first cash distribution to
                  the Participants after substantially all Partnership wells
                  have been drilled, completed, and placed in production in a
                  sales line;

          (ii)    subsequent subordination distributions, if any, shall be
                  determined and made at the time of each subsequent
                  distribution of revenues to the Participants; and

          (iii)   the Managing General Partner shall not subordinate more than
                  50% of its share of Partnership Net Production Revenues in any
                  subordination period.

The subordination shall be determined by:

          (i)     carrying forward to subsequent 12-month periods the amount, if
                  any, by which cumulative cash distributions to Participants,
                  including any subordination payments, are less than:

                  (a)     $1,000 per Unit (10% per Unit) in the first 12-month
                          period;

                  (b)     $2,000 per Unit (20% per Unit) in the second 12-month
                          period;

                  (c)     $3,000 per Unit (30% per Unit) in the third 12-month
                          period; or

                  (d)     $4,000 per Unit (40% per Unit) in the fourth 12-month
                          period (no carry forward is required if such
                          distributions are less than $5,000 per Unit (50% per
                          Unit) in the fifth 12-month period because the
                          Managing General Partner's subordination obligation
                          terminates on the expiration of the fifth 12-month
                          period); and

          (ii)    reimbursing the Managing General Partner for any previous
                  subordination payments to the extent cumulative cash
                  distributions to Participants, including any subordination
                  payments, would exceed:

                  (a)     $1,000 per Unit (10% per Unit) in the first 12-month
                          period;

                  (b)     $2,000 per Unit (20% per Unit) in the second 12-month
                          period;

                  (c)     $3,000 per Unit (30% per Unit) in the third 12-month
                          period;

                  (d)     $4,000 per Unit (40% per Unit) in the fourth 12-month
                          period; or

                  (e)     $5,000 per Unit (50% per Unit) in the fifth 12-month
                          period.

The Managing General Partner's subordination obligation shall be further subject
to the following conditions:

          (i)     the subordination obligation may be prorated in the Managing
                  General Partner's discretion (e.g. in the case of a quarterly
                  distribution, the Managing General Partner will not have any
                  subordination obligation if the distributions to Participants
                  equal $250 per Unit (25% of $1,000 per Unit per year) or more
                  assuming there is no subordination owed for any preceding
                  period);

          (ii)    the Managing General Partner shall not be required to return
                  Partnership distributions previously received by it, even
                  though a subordination obligation arises after the
                  distributions;

          (iii)   subject to the foregoing provisions of this section, only
                  Partnership revenues in the current distribution period shall
                  be debited or credited to the Managing General Partner as may
                  be necessary to provide, to the extent possible, subordination
                  distributions to the Participants and reimbursements to the
                  Managing General Partner;

          (iv)    no subordination payments to the Participants or
                  reimbursements to the Managing General Partner shall be made
                  after the expiration of the fifth 12-month subordination
                  period; and


                                       37


          (v)     subordination payments to the Participants shall be subject to
                  any lien or priority required by the Managing General
                  Partner's lenders pursuant to agreements previously entered
                  into or subsequently entered into or renewed by the Managing
                  General Partner.

5.01(b)(5). COMMINGLING OF REVENUES FROM ALL PARTNERSHIP WELLS. The revenues
from all Partnership wells will be commingled, so regardless of when a
Participant subscribes he will share in the revenues from all wells on the same
basis as the other Participants.

5.01(c). ALLOCATIONS.

5.01(c)(1). ALLOCATIONS AMONG PARTICIPANTS. Except as provided otherwise in this
Agreement, costs (other than Intangible Drilling Costs and Tangible Costs) and
revenues charged or credited to the Participants as a group, which includes all
revenue credited to the Participants under ss.5.01(b)(4), shall be allocated
among the Participants, including the Managing General Partner to the extent of
any optional subscription under ss.3.03(b)(2), in the ratio of their respective
Units based on $10,000 per Unit regardless of the actual subscription price for
a Participant's Units.

Intangible Drilling Costs and Tangible Costs charged to the Participants as a
group shall be allocated among the Participants, including the Managing General
Partner to the extent of any optional subscription under ss.3.03(b)(2), in the
ratio of the subscription price designated on their respective Subscription
Agreements rather than the number of their respective Units.

5.01(c)(2). COSTS AND REVENUES NOT DIRECTLY ALLOCABLE TO A PARTNERSHIP WELL.
Costs and revenues not directly allocable to a particular Partnership Well or
additional operation shall be allocated among the Partnership Wells or
additional operations in any manner the Managing General Partner in its
reasonable discretion, shall select, and shall then be charged or credited in
the same manner as costs or revenues directly applicable to the Partnership Well
or additional operation are being charged or credited.

5.01(c)(3). MANAGING GENERAL PARTNER'S DISCRETION IN MAKING ALLOCATIONS FOR
FEDERAL INCOME TAX PURPOSES. In determining the proper method of allocating
charges or credits among the parties, or in making any other allocations under
this Agreement, the Managing General Partner may adopt any method of allocation
which it, in its reasonable discretion, selects, if, in its sole discretion
based on advice from its legal counsel or accountants, a revision to the
allocations is required for the allocations to be recognized for federal income
tax purposes either because of the promulgation of Treasury Regulations or other
developments in the tax law. Any new allocation provisions shall be provided by
an amendment to this Agreement and shall be made in a manner that would result
in the most favorable aggregate consequences to the Participants as nearly as
possible consistent with the original allocations described in this Agreement.

5.02. CAPITAL ACCOUNTS AND ALLOCATIONS THERETO.

5.02(a). CAPITAL ACCOUNTS FOR EACH PARTY TO THE AGREEMENT. A single, separate
Capital Account shall be established for each party, regardless of the number of
interests owned by the party, the class of the interests and the time or manner
in which the interests were acquired.

5.02(b). CHARGES AND CREDITS.

5.02(b)(1). GENERAL STANDARD. Except as otherwise provided in this Agreement,
the Capital Account of each party shall be determined and maintained in
accordance with Treas. Reg. ss.1.704-l(b)(2)(iv) and shall be increased by:

          (i)     the amount of money contributed by him to the Partnership;

          (ii)    the fair market value of property contributed by him, without
                  regard to ss.7701(g) of the Code, to the Partnership, net of
                  liabilities secured by the contributed property that the
                  Partnership is considered to assume or take subject to under
                  ss.752 of the Code; and

          (iii)   allocations to him of Partnership income and gain, or items
                  thereof, including income and gain exempt from tax and income
                  and gain described in Treas. Reg. ss.1.704-l(b)(2)(iv)(g), but
                  excluding income and gain described in Treas. Reg.
                  ss.1.704-l(b)(4)(i);


                                       38


and shall be decreased by:

          (iv)    the amount of money distributed to him by the Partnership;

          (v)     the fair market value of property distributed to him, without
                  regard to ss.7701(g) of the Code, by the Partnership, net of
                  liabilities secured by the distributed property that he is
                  considered to assume or take subject to under ss.752 of the
                  Code;

          (vi)    allocations to him of Partnership expenditures described in
                  ss.705(a)(2)(B) of the Code; and

          (vii)   allocations to him of Partnership loss and deduction, or items
                  thereof, including loss and deduction described in Treas. Reg.
                  ss.1.704-l(b)(2)(iv)(g), but excluding items described in (vi)
                  above, and loss or deduction described in Treas. Reg.
                  ss.1.704-l(b)(4)(i) or (iii).

5.02(b)(2). EXCEPTION. If Treas. Reg. ss.1.704-l(b)(2)(iv) fails to provide
guidance, Capital Account adjustments shall be made in a manner that:

          (i)     maintains equality between the aggregate governing Capital
                  Accounts of the parties and the amount of Partnership capital
                  reflected on the Partnership's balance sheet, as computed for
                  book purposes;

          (ii)    is consistent with the underlying economic arrangement of the
                  parties; and

          (iii)   is based, wherever practicable, on federal tax accounting
                  principles.

5.02(c). PAYMENTS TO THE MANAGING GENERAL PARTNER. The Capital Account of the
Managing General Partner shall be reduced by payments to it pursuant to
ss.4.04(a)(2) only to the extent of the Managing General Partner's distributive
share of any Partnership deduction, loss, or other downward Capital Account
adjustment resulting from the payments.

5.02(d). DISCRETION OF MANAGING GENERAL PARTNER IN THE METHOD OF MAINTAINING
CAPITAL ACCOUNTS. Notwithstanding any other provisions of this Agreement, the
method of maintaining Capital Accounts may be changed from time to time, in the
discretion of the Managing General Partner, to take into consideration ss.704
and other provisions of the Code and the related rules, regulations and
interpretations as may exist from time to time.

5.02(e). REVALUATIONS OF PROPERTY. In the discretion of the Managing General
Partner the Capital Accounts of the parties may be increased or decreased to
reflect a revaluation of Partnership property, including intangible assets such
as goodwill, on a property-by-property basis except as otherwise permitted under
ss.704(c) of the Code and the regulations thereunder, on the Partnership's
books, in accordance with Treas. Reg. ss.1.704-l(b)(2)(iv)(f).

5.02(f). AMOUNT OF BOOK ITEMS. In cases where ss.704(c) of the Code or
ss.5.02(e) applies, Capital Accounts shall be adjusted in accordance with Treas.
Reg. ss.1.704-l(b)(2)(iv)(g) for allocations of depreciation, depletion,
amortization and gain and loss, as computed for book purposes, with respect to
the property.

5.03. ALLOCATION OF INCOME, DEDUCTIONS AND CREDITS.

5.03(a). IN GENERAL.

5.03(a)(1). DEDUCTIONS ARE ALLOCATED TO PARTY CHARGED WITH EXPENDITURE. To the
extent permitted by law and except as otherwise provided in this Agreement, all
deductions and credits, including, but not limited to, intangible drilling and
development costs and depreciation, shall be allocated to the party who has been
charged with the expenditure giving rise to the deductions and credits; and to
the extent permitted by law, these parties shall be entitled to the deductions
and credits in computing taxable income or tax liabilities to the exclusion of
any other party. Also, any Partnership deductions that would be nonrecourse
deductions if they were not attributable to a loan made or guaranteed by the
Managing General Partner or its Affiliates shall be allocated to the Managing
General Partner to the extent required by law.

5.03(a)(2). INCOME AND GAIN ALLOCATED IN ACCORDANCE WITH REVENUES. Except as
otherwise provided in this Agreement, all items of income and gain, including
gain on disposition of assets, shall be allocated in accordance with the related
revenue allocations set forth in ss.5.01(b) and its subsections.

                                       39



5.03(b). TAX BASIS OF EACH PROPERTY. Subject to ss.704(c) of the Code, the tax
basis of each oil and gas property for computation of cost depletion and gain or
loss on disposition shall be allocated and reallocated when necessary based on
the capital interest in the Partnership as to the property and the capital
interest in the Partnership for this purpose as to each property shall be
considered to be owned by the parties in the ratio in which the expenditure
giving rise to the tax basis of the property has been charged as of the end of
the year.

5.03(c). GAIN OR LOSS ON OIL AND GAS PROPERTIES. Each party shall separately
compute its gain or loss on the disposition of each natural gas and oil property
in accordance with the provisions of ss.613A(c)(7)D) of the Code, and the
calculation of the gain or loss shall consider the party's adjusted basis in his
property interest computed as provided in ss.5.03(b) and the party's allocable
share of the amount realized from the disposition of the property.

5.03(d). GAIN ON DEPRECIABLE PROPERTY. Gain from each sale or other disposition
of depreciable property shall be allocated to each party whose share of the
proceeds from the sale or other disposition exceeds its contribution to the
adjusted basis of the property in the ratio that the excess bears to the sum of
the excesses of all parties having an excess.

5.03(e). LOSS ON DEPRECIABLE PROPERTY. Loss from each sale, abandonment or other
disposition of depreciable property shall be allocated to each party whose
contribution to the adjusted basis of the property exceeds its share of the
proceeds from the sale, abandonment or other disposition in the proportion that
the excess bears to the sum of the excesses of all parties having an excess.

5.03(f). ALLOCATION IF RECAPTURE TREATED AS ORDINARY INCOME. Any recapture
treated as an increase in ordinary income by reason of ss.ss.1245, 1250, or 1254
of the Code shall be allocated to the parties in the amounts in which the
recaptured items were previously allocated to them; provided that to the extent
recapture allocated to any party is in excess of the party's gain from the
disposition of the property, the excess shall be allocated to the other parties
but only to the extent of the other parties' gain from the disposition of the
property.

5.03(g). TAX CREDITS. As of the date of the Prospectus, tax credits are not
available to the Partnership. If this changes in the future, however, and if a
Partnership expenditure, whether or not deductible, that gives rise to a tax
credit in a Partnership taxable year also gives rise to valid allocations of
Partnership loss or deduction, or other downward Capital Account adjustments,
for the year, then the parties' interests in the Partnership with respect to the
credit, or the cost giving rise thereto, shall be in the same proportion as the
parties' respective distributive shares of the loss or deduction, and
adjustments. Identical principles shall apply in determining the parties'
interests in the Partnership with respect to tax credits that arise from
receipts of the Partnership, whether or not taxable.

5.03(h). DEFICIT CAPITAL ACCOUNTS AND QUALIFIED INCOME OFFSET. Notwithstanding
any provisions of this Agreement to the contrary, an allocation of loss or
deduction which would result in a party having a deficit Capital Account balance
as of the end of the taxable year to which the allocation relates, if charged to
the party, to the extent the Participant is not required to restore the deficit
to the Partnership, taking into account:

          (i)     adjustments that, as of the end of the year, reasonably are
                  expected to be made to the party's Capital Account for
                  depletion allowances with respect to the Partnership's natural
                  gas and oil properties;

          (ii)    allocations of loss and deduction that, as of the end of the
                  year, reasonably are expected to be made to the party under
                  ss.ss.704(e)(2) and 706(d) of the Code and Treas. Reg.
                  ss.1.751-1(b)(2)(ii); and

          (iii)   distributions that, as of the end of the year, reasonably are
                  expected to be made to the party to the extent they exceed
                  offsetting increases to the party's Capital Account, assuming
                  for this purpose that the fair market value of Partnership
                  property equals its adjusted tax basis, that reasonably are
                  expected to occur during or prior to the Partnership taxable
                  years in which the distributions reasonably are expected to be
                  made;

shall be charged to the Managing General Partner. Further, the Managing General
Partner shall be credited with an additional amount of Partnership income or
gain equal to the amount of the loss or deduction as quickly as possible to the
extent such chargeback does not cause or increase deficit balances in the
parties' Capital Accounts which are not required to be restored to the
Partnership.

                                       40



Notwithstanding any provisions of this Agreement to the contrary, if a party
unexpectedly receives an adjustment, allocation, or distribution described in
(i), (ii), or (iii) above, or any other distribution, which causes or increases
a deficit balance in the party's Capital Account which is not required to be
restored to the Partnership, the party shall be allocated items of income and
gain, consisting of a pro rata portion of each item of Partnership income,
including gross income, and gain for the year, in an amount and manner
sufficient to eliminate the deficit balance as quickly as possible.

5.03(i). MINIMUM GAIN CHARGEBACK. To the extent there is a net decrease during a
Partnership taxable year in the minimum gain attributable to a Partner
nonrecourse debt, then any Partner with a share of the minimum gain attributable
to the debt at the beginning of the year shall be allocated items of Partnership
income and gain in accordance with Treas. Reg. ss.1.704-2(i).

5.03(j). PARTNERS' ALLOCABLE SHARES. Except as otherwise provided in this
Agreement, each party's allocable share of Partnership income, gain, loss,
deductions and credits shall be determined by the use of any method prescribed
or permitted by the Secretary of the Treasury by regulations or other guidelines
and selected by the Managing General Partner which takes into account the
varying interests of the parties in the Partnership during the taxable year. In
the absence of such regulations or guidelines, except as otherwise provided in
this Agreement, the allocable share shall be based on actual income, gain, loss,
deductions and credits economically accrued each day during the taxable year in
proportion to each party's varying interest in the Partnership on each day
during the taxable year.

5.04. ELECTIONS.

5.04(a). ELECTION TO DEDUCT INTANGIBLE COSTS. The Partnership's federal income
tax return shall be made in accordance with an election under the option granted
by the Code to deduct intangible drilling and development costs.

5.04(b). NO ELECTION OUT OF SUBCHAPTER K. No election shall be made by the
Partnership, any Partner, or the Operator for the Partnership to be excluded
from the application of the partnership provisions of Subchapter K of the Code.

5.04(c). CONTINGENT INCOME. If it is determined that any taxable income results
to any party by reason of its entitlement to a share of profits or revenues of
the Partnership before the profit or revenue has been realized by the
Partnership, the resulting deduction as well as any resulting gain, shall not
enter into Partnership net income or loss but shall be separately allocated to
the party.

5.04(d). SS.754 ELECTION. In the event of the transfer of an interest in the
Partnership, or on the death of an individual party hereto, or in the event of
the distribution of property to any party, the Managing General Partner may
choose for the Partnership to file an election in accordance with the applicable
Treasury Regulations to cause the basis of the Partnership's assets to be
adjusted for federal income tax purposes as provided by ss.ss.734 and 743 of the
Code.

5.05. DISTRIBUTIONS.

5.05(a). IN GENERAL.

5.05(a)(1). QUARTERLY REVIEW OF ACCOUNTS. The Managing General Partner shall
review the accounts of the Partnership at least quarterly to determine whether
cash distributions are appropriate and the amount to be distributed, if any.

5.05(a)(2). DISTRIBUTIONS. The Partnership shall distribute funds to the
Managing General Partner and the Participants allocated to their accounts which
the Managing General Partner deems unnecessary to retain by the Partnership.

5.05(a)(3). NO BORROWINGS. In no event, however, shall funds be advanced or
borrowed for distributions if the amount of the distributions would exceed the
Partnership's accrued and received revenues for the previous four quarters, less
paid and accrued Operating Costs with respect to the revenues. The determination
of revenues and costs shall be made in accordance with generally accepted
accounting principles, consistently applied.


                                       41


5.05(a)(4). DISTRIBUTIONS TO THE MANAGING GENERAL PARTNER. Cash distributions
from the Partnership to the Managing General Partner shall only be made as
follows:

                  (a)     in conjunction with distributions to Participants; and

                  (b)     out of funds properly allocated to the Managing
                          General Partner's account.

5.05(a)(5). RESERVE. At any time after one year from the date each Partnership
Well is placed into production, the Managing General Partner shall have the
right to deduct each month from the Partnership's proceeds of the sale of the
production from the well up to $200 for the purpose of establishing a fund to
cover the estimated costs of plugging and abandoning the well. All of these
funds shall be deposited in a separate interest bearing account for the benefit
of the Partnership, and the total amount so retained and deposited shall not
exceed the Managing General Partner's reasonable estimate of the costs.

5.05(b). DISTRIBUTION OF UNCOMMITTED SUBSCRIPTION PROCEEDS. Any net subscription
proceeds not expended or committed for expenditure, as evidenced by a written
agreement, by the Partnership within 12 months of the Offering Termination Date,
except necessary operating capital, shall be distributed to the Participants in
the ratio that the subscription price designated on each Participant's
Subscription Agreement bears to the total subscription prices designated on all
of the Participants' Subscription Agreements, as a return of capital. The
Managing General Partner shall reimburse the Participants for the selling or
other offering expenses, if any, allocable to the return of capital.

For purposes of this subsection, "committed for expenditure" shall mean
contracted for, actually earmarked for or allocated by the Managing General
Partner to the Partnership's drilling operations, and "necessary operating
capital" shall mean those funds which, in the opinion of the Managing General
Partner, should remain on hand to assure continuing operation of the
Partnership.

5.05(c). DISTRIBUTIONS ON WINDING UP. On the winding up of the Partnership
distributions shall be made as provided in ss.7.02.

5.05(d). INTEREST AND RETURN OF CAPITAL. No party shall under any circumstances
be entitled to any interest on amounts retained by the Partnership. Each
Participant shall look only to his share of distributions, if any, from the
Partnership for a return of his Capital Contribution.

                                   ARTICLE VI
                              TRANSFER OF INTERESTS

6.01. TRANSFERABILITY.

6.01(a). RIGHTS OF ASSIGNEE. On a transfer unless an assignee becomes a
substituted Participant in accordance with the provisions set forth below, he
shall not be entitled to any of the rights granted to a Participant under this
Agreement, other than the right to receive all or part of the share of the
profits, losses, income, gain, credits and cash distributions or returns of
capital to which his assignor would otherwise be entitled.

6.01(b). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER UNITS.

6.01(b)(1). AUTOMATIC CONVERSION. After all of the Partnership Wells have been
drilled and completed, as determined by the Managing General Partner, the
Managing General Partner shall file an amended certificate of limited
partnership with the Secretary of State of the State of Delaware for the purpose
of converting the Investor General Partner Units to Limited Partner Units.

6.01(b)(2). INVESTOR GENERAL PARTNERS SHALL HAVE CONTINGENT LIABILITY. On
conversion the Investor General Partners shall be Limited Partners entitled to
limited liability; however, they shall remain liable to the Partnership for any
additional Capital Contribution required for their proportionate share of any
Partnership obligation or liability arising before the conversion of their Units
as provided in ss.3.05(b)(2).

6.01(b)(3). CONVERSION SHALL NOT AFFECT ALLOCATIONS. The conversion shall not
affect the allocation to any Participant of any item of Partnership income,
gain, loss, deduction or credit or other item of special tax significance other
than Partnership liabilities, if any. Further, the conversion shall not affect
any Participant's interest in the Partnership's natural gas and oil properties
and unrealized receivables.


                                       42



6.01(b)(4). RIGHT TO CONVERT IF REDUCTION OF INSURANCE. Notwithstanding the
foregoing, the Managing General Partner shall notify all Participants at least
30 days before the effective date of any adverse material change in the
Partnership's insurance coverage. If the insurance coverage is to be materially
reduced, then the Investor General Partners shall have the right to convert
their Units into Limited Partner Units before the reduction by giving written
notice to the Managing General Partner.

6.02. SPECIAL RESTRICTIONS ON TRANSFERS.

6.02(a). IN GENERAL. Transfers are subject to the following general conditions:

          (i)     except as provided by operation of law:

                  (a)     only whole Units may be assigned unless the
                          Participant owns less than a whole Unit, in which case
                          his entire fractional interest must be assigned; and

                  (b)     Units may not be assigned to a person who is under the
                          age of 18 or incompetent (unless an attorney-in-fact,
                          guardian, custodian or conservator has been appointed
                          to handle the affairs of that person) without the
                          Managing General Partner's consent;

          (ii)    the costs and expenses associated with the assignment must be
                  paid by the assignor Participant;

          (iii)   the assignment must be in a form satisfactory to the Managing
                  General Partner; and

          (iv)    the terms of the assignment must not contravene those of this
                  Agreement.

Transfers of Units are subject to the following additional restrictions set
forth in ss.ss.6.02(a)(1) and 6.02(a)(2).

6.02(a)(1). TAX LAW RESTRICTIONS. Subject to transfers permitted by ss.6.04 and
transfers by operation of law, no sale, assignment, exchange, or transfer of a
Unit shall be made which, in the opinion of counsel to the Partnership, would
result in the Partnership being either:

          (i)     terminated for tax purposes under ss.708 of the Code; or

          (ii)    treated as a "publicly-traded" partnership for purposes of
                  ss.469(k) of the Code.

6.02(a)(2). SECURITIES LAWS RESTRICTION. Subject to transfers permitted by
ss.6.04 and transfers by operation of law, no Unit shall be sold, assigned,
pledged, hypothecated, or transferred which, in the opinion of counsel to the
Partnership, would result in the violation of any applicable federal or state
securities laws.

Transfers are also subject to any conditions contained in the Subscription
Agreement and Exhibit (B) to the Prospectus.

6.02(a)(3). SUBSTITUTE PARTICIPANT.

6.02(a)(3)(a). PROCEDURE TO BECOME SUBSTITUTE PARTICIPANT. Subject to
ss.ss.6.02(a)(1) and 6.02(a)(2), an assignee of a Participant's Unit shall
become a substituted Participant entitled to all the rights of a Participant if,
and only if:

          (i)     the assignor gives the assignee the right;

          (ii)    the assignee pays to the Partnership all costs and expenses
                  incurred in connection with the substitution; and

          (iii)   the assignee executes and delivers the instruments necessary
                  to establish that a legal transfer has taken place and to
                  confirm the agreement of the assignee to be bound by all of
                  the terms of this Agreement.

6.02(a)(3)(b). RIGHTS OF SUBSTITUTE PARTICIPANT. A substitute Participant is
entitled to all of the rights attributable to full ownership of the assigned
Units including the right to vote.


                                       43


6.02(b). EFFECT OF TRANSFER.

6.02(b)(1). AMENDMENT OF RECORDS. The Partnership shall amend its records at
least once each calendar quarter to effect the substitution of substituted
Participants.

Any transfer permitted under this Agreement when the assignee does not become a
substituted Participant shall be effective as follows:

          (i)     midnight of the last day of the calendar month in which it is
                  made; or

          (ii)    at the Managing General Partner's election, 7:00 A.M. of the
                  following day.

6.02(b)(2). TRANSFER DOES NOT RELIEVE TRANSFEROR OF CERTAIN COSTS. No transfer,
including a transfer of less than all of a Participant's Units or the transfer
of Units to more than one party, shall relieve the transferor of its
responsibility for its proportionate part of any expenses, obligations and
liabilities under this Agreement related to the Units so transferred, whether
arising before or after the transfer.

6.02(b)(3). TRANSFER DOES NOT REQUIRE AN ACCOUNTING. No transfer of a Unit shall
require an accounting by the Managing General Partner. Also, no transfer shall
grant rights under this Agreement, including the exercise of any elections, as
between the transferring parties and the remaining parties to this Agreement to
more than one party unanimously designated by the transferees and, if he should
have retained an interest under this Agreement, the transferor.

6.02(b)(4). NOTICE. Until the Managing General Partner receives a proper notice
of designation acceptable to it, the Managing General Partner shall continue to
account only to the person to whom it was furnishing notices before the time
pursuant to ss.8.01 and its subsections. This party shall continue to exercise
all rights applicable to the Units previously owned by the transferor.

6.03. RIGHT OF MANAGING GENERAL PARTNER TO HYPOTHECATE AND/OR WITHDRAW ITS
INTERESTS. The Managing General Partner shall have the authority without the
consent of the Participants and without affecting the allocation of costs and
revenues received or incurred under this Agreement, to hypothecate, pledge, or
otherwise encumber, on any terms it chooses for its own general purposes either:

          (i)     its Partnership interest; or

          (ii)    an undivided interest in the assets of the Partnership equal
                  to or less than its respective interest in the revenues of the
                  Partnership.

All repayments of these borrowings and costs, interest or other charges related
to the borrowings shall be borne and paid separately by the Managing General
Partner. In no event shall the repayments, costs, interest, or other charges
related to the borrowing be charged to the account of the Participants.

In addition, subject to a required participation of not less than 1% in the
Partnership as Managing General Partner, the Managing General Partner may
withdraw a property interest held by the Partnership in the form of a Working
Interest in the Partnership's Wells equal to or less than its respective
interest in the revenues of the Partnership if:

          (i)     the withdrawal is necessary to satisfy the bona fide request
                  of its creditors; or

          (ii)    the withdrawal is approved by Participants whose Units equal a
                  majority of the total Units.

6.04. PRESENTMENT.

6.04(a). IN GENERAL. Participants shall have the right to present their Units to
the Managing General Partner for purchase subject to the conditions and
limitations set forth in this section. A Participant, however, is not obligated
to present his Units for purchase.


                                       44



The Managing General Partner shall not be obligated to purchase more than 5% of
the Units in any calendar year and this 5% limit may not be waived. The Managing
General Partner shall not purchase less than one Unit unless the lesser amount
represents the Participant's entire interest in the Partnership, however, the
Managing General Partner may waive this limitation.

A Participant may present his Units in writing to the Managing General Partner
every year beginning with the fifth calendar year after the Offering Termination
Date subject to the following conditions:

          (i)     the presentment must be made within 120 days of the reserve
                  report set forth inss.4.03(b)(3);

          (ii)    in accordance with Treas. Reg. ss.1.7704-1(f), the purchase
                  may not be made until at least 60 calendar days after the
                  Participant notifies the Partnership in writing of the
                  Participant's intention to exercise the presentment right; and

          (iii)   the purchase shall not be considered effective until the
                  presentment price has been paid in cash to the Participant.

6.04(b). REQUIREMENT FOR INDEPENDENT PETROLEUM CONSULTANT. The amount of the
presentment price attributable to Partnership reserves shall be determined based
on the last reserve report of the Partnership prepared by the Managing General
Partner and reviewed by an Independent Expert. The Managing General Partner
shall estimate the present worth of future net revenues attributable to the
Partnership's interest in the Proved Reserves. In making this estimate, the
Managing General Partner shall use the following terms:

          (i)     a discount rate equal to 10%;

          (ii)    a constant price for the oil; and

          (iii)   base the price of natural gas on the existing natural gas
                  contracts at the time of the purchase.

The calculation of the presentment price shall be as set forth in ss.6.04(c).

6.04(c). CALCULATION OF PRESENTMENT PRICE. The presentment price shall be based
on the Participant's share of the net assets and liabilities of the Partnership
and allocated pro rata to each Participant in the ratio that his number of Units
bears to the total number of Units. The presentment price shall include the sum
of the following Partnership items:

          (i)     an amount based on 70% of the present worth of future net
                  revenues from the Proved Reserves determined as described in
                  ss.6.04(b);

          (ii)    cash on hand;

          (iii)   prepaid expenses and accounts receivable less a reasonable
                  amount for doubtful accounts; and

          (iv)    the estimated market value of all assets, not separately
                  specified above, determined in accordance with standard
                  industry valuation procedures.

There shall be deducted from the foregoing sum the following items:

          (i)     an amount equal to all debts, obligations, and other
                  liabilities, including accrued expenses; and

          (ii)    any distributions made to the Participants between the date of
                  the request and the actual payment. However, if any cash
                  distributed was derived from the sale, after the presentment
                  request, of natural gas, oil or other mineral production, or
                  of a producing property owned by the Partnership, for purposes
                  of determining the reduction of the presentment price, the
                  distributions shall be discounted at the same rate used to
                  take into account the risk factors employed to determine the
                  present worth of the Partnership's Proved Reserves.


                                       45


6.04(d). FURTHER ADJUSTMENT MAY BE ALLOWED. The presentment price may be further
adjusted by the Managing General Partner for estimated changes therein from the
date of the report to the date of payment of the presentment price to the
Participants because of the following:

          (i)     the production or sales of, or additions to, reserves and
                  lease and well equipment, sale or abandonment of Leases, and
                  similar matters occurring before the request for purchase; and

          (ii)    any of the following occurring before payment of the
                  presentment price to the selling Participants:

                  (a)     changes in well performance;

                  (b)     increases or decreases in the market price of natural
                          gas, oil or other minerals;

                  (c)     revision of regulations relating to the importing of
                          hydrocarbons;

                  (d)     changes in income, ad valorem, and other tax laws such
                          as material variations in the provisions for
                          depletion; and

                  (e)     similar matters.

6.04(e). SELECTION BY LOT. If less than all Units presented at any time are to
be purchased, then the Participants whose Units are to be purchased will be
selected by lot.

The Managing General Partner's obligation to purchase Units presented may be
discharged for its benefit by a third-party or an Affiliate. The Units of the
selling Participant will be transferred to the party who pays for it. A selling
Participant will be required to deliver an executed assignment of his Units,
together with any other documentation as the Managing General Partner may
reasonably request.

6.04(f). NO OBLIGATION OF THE MANAGING GENERAL PARTNER TO ESTABLISH A RESERVE.
The Managing General Partner shall have no obligation to establish any reserve
to satisfy the presentment obligations under this section.

6.04(g). SUSPENSION OF PRESENTMENT FEATURE. The Managing General Partner may
suspend this presentment feature by so notifying Participants at any time if it:

          (i)     does not have sufficient cash flow; or

          (ii)    is unable to borrow funds for this purpose on terms it deems
                  reasonable.

In addition, the presentment feature may be conditioned, in the Managing General
Partner's sole discretion, on the Managing General Partner's receipt of an
opinion of counsel that the transfers will not cause the Partnership to be
treated as a "publicly traded partnership" under the Code.

The Managing General Partner shall hold the purchased Units for its own account
and not for resale.

                                   ARTICLE VII
                      DURATION, DISSOLUTION, AND WINDING UP

7.01. DURATION.

7.01(a). FIFTY YEAR TERM. The Partnership shall continue in existence for a term
of 50 years from the effective date of this Agreement unless sooner terminated
as set forth below.


                                       46



7.01(b). TERMINATION. The Partnership shall terminate following the occurrence
of:

          (i)     a Final Terminating Event; or

          (ii)    any event which under the Delaware Revised Uniform Limited
                  Partnership Act causes the dissolution of a limited
                  partnership.

7.01(c). CONTINUANCE OF PARTNERSHIP EXCEPT ON FINAL TERMINATING EVENT. Other
than the occurrence of a Final Terminating Event, the Partnership or any
successor limited partnership shall not be wound up, but shall be continued by
the parties and their respective successors as a successor limited partnership
under all the terms of this Agreement. The successor limited partnership shall
succeed to all of the assets of the Partnership. As used throughout this
Agreement, the term "Partnership" shall include the successor limited
partnerships and the parties to the successor limited partnerships.

7.02. DISSOLUTION AND WINDING UP.

7.02(a). FINAL TERMINATING EVENT. On the occurrence of a Final Terminating Event
the affairs of the Partnership shall be wound up and there shall be distributed
to each of the parties its Distribution Interest in the remaining Partnership
assets.

7.02(b). TIME OF LIQUIDATING DISTRIBUTION. To the extent practicable and in
accordance with sound business practices in the judgment of the Managing General
Partner, liquidating distributions shall be made by:

          (i)     the end of the taxable year in which liquidation occurs,
                  determined without regard to ss.706(c)(2)(A) of the Code; or

          (ii)    if later, within 90 days after the date of the liquidation.

Notwithstanding, the following amounts are not required to be distributed within
the foregoing time periods so long as the withheld amounts are distributed as
soon as practical:

          (i)     amounts withheld for reserves reasonably required for
                  liabilities of the Partnership; and

          (ii)    installment obligations owed to the Partnership.

7.02(c). IN-KIND DISTRIBUTIONS. The Managing General Partner shall not be
obligated to offer in-kind property distributions to the Participants, but may
do so, in its discretion. Any in-kind property distributions to the Participants
shall be made to a liquidating trust or similar entity for the benefit of the
Participants, unless at the time of the distribution:

          (i)     the Managing General Partner offers the individual
                  Participants the election of receiving in-kind property
                  distributions and the Participants accept the offer after
                  being advised of the risks associated with direct ownership;
                  or

          (ii)    there are alternative arrangements in place which assure the
                  Participants that they will not, at any time, be responsible
                  for the operation or disposition of Partnership properties.

If the Managing General Partner has not received a Participant's consent within
30 days after the Managing General Partner mailed the request for consent, then
it shall be presumed that the Participant has refused his consent.

7.02(d). SALE IF NO CONSENT. Any Partnership asset which would otherwise be
distributed in-kind to a Participant, except for the failure or refusal of the
Participant to give his written consent to the distribution, may instead be sold
by the Managing General Partner at the best price reasonably obtainable from an
independent third-party, who is not an Affiliate of the Managing General Partner
or to itself or its Affiliates, including an Affiliated Income Program, at fair
market value as determined by an Independent Expert selected by the Managing
General Partner.

                                  ARTICLE VIII
                            MISCELLANEOUS PROVISIONS

8.01. NOTICES.

8.01(a). METHOD. Any notice required under this Agreement shall be:


                                       47



          (i)     in writing; and

          (ii)    given by mail or wire addressed to the party to receive the
                  notice at the address designated in ss.1.03.

If there is a transfer of Units under this Agreement, no notice to the
transferee shall be required, nor shall the transferee have any rights under
this Agreement, until notice has been given to the Managing General Partner.

Any transfer of rights under this Agreement shall not increase the duty to give
notice. If there is a transfer of Units under this Agreement to more than one
party, then notice to any owner of any interest in the Units shall be notice to
all owners of the Units.

8.01(b). CHANGE IN ADDRESS. The address of any party to this Agreement may be
changed by written notice as follows:

          (i)     to the Participants if there is a change of address by the
                  Managing General Partner; or

          (ii)    to the Managing General Partner if there is a change of
                  address by a Participant.

8.01(c). TIME NOTICE DEEMED GIVEN. If the notice is given by the Managing
General Partner, then the notice shall be considered given, and any applicable
time shall run, from the date the notice is placed in the mail or delivered to
the telegraph company.

If the notice is given by any Participant, then the notice shall be considered
given and any applicable time shall run from the date the notice is received.

8.01(d). EFFECTIVENESS OF NOTICE. Any notice to a party other than the Managing
General Partner, including a notice requiring concurrence or nonconcurrence,
shall be effective, and any failure to respond binding, irrespective of the
following:

          (i)     whether or not the notice is actually received; or

          (ii)    any disability or death on the part of the noticee, even if
                  the disability or death is known to the party giving the
                  notice.

8.01(e). FAILURE TO RESPOND. Except pursuant to ss.7.02(c) or when this
Agreement expressly requires affirmative approval of a Participant, any
Participant who fails to respond in writing within the time specified to a
request by the Managing General Partner as set forth below, for approval of or
concurrence in a proposed action shall be conclusively deemed to have approved
the action. The Managing General Partner shall send the first request and the
time period shall be not less than 15 business days from the date of mailing of
the request. If the Participant does not respond to the first request, then the
Managing General Partner shall send a second request. If the Participant does
not respond within seven calendar days from the date of the mailing of the
second request, then the Participant shall be conclusively deemed to have
approved the action.

8.02. TIME. Time is of the essence of each part of this Agreement.

8.03. APPLICABLE LAW. The terms and provisions of this Agreement shall be
construed under the laws of the State of Delaware, provided, however, this
section shall not be deemed to limit causes of action for violations of federal
or state securities law to the laws of the State of Delaware. Neither this
Agreement nor the Subscription Agreement shall require mandatory venue or
mandatory arbitration of any or all claims by Participants against the Sponsor.

8.04. AGREEMENT IN COUNTERPARTS. This Agreement may be executed in counterpart
and shall be binding on all parties executing this or similar agreements from
and after the date of execution by each party.

8.05. AMENDMENT.

8.05(a). PROCEDURE FOR AMENDMENT. No changes in this Agreement shall be binding
unless:


                                       48



          (i)     proposed in writing by the Managing General Partner, and
                  adopted with the consent of Participants whose Units equal a
                  majority of the total Units; or

          (ii)    proposed in writing by Participants whose Units equal 10% or
                  more of the total Units and approved by an affirmative vote of
                  Participants whose Units equal a majority of the total Units.

8.05(b). CIRCUMSTANCES UNDER WHICH THE MANAGING GENERAL PARTNER ALONE MAY AMEND.
The Managing General Partner is authorized to amend this Agreement and its
exhibits without the consent of Participants in any way deemed necessary or
desirable by it to do any or all of the following:

          (i)     add or substitute in the case of an assigning party additional
                  Participants;

          (ii)    enhance the tax benefits of the Partnership to the parties; or

          (iii)   satisfy any requirements, conditions, guidelines, options, or
                  elections contained in any opinion, directive, order, ruling,
                  or regulation of the SEC, the IRS, or any other federal or
                  state agency, or in any federal or state statute, compliance
                  with which it deems to be in the best interest of the
                  Partnership.

Notwithstanding the foregoing, no amendment materially and adversely affecting
the interests or rights of Participants shall be made without the consent of the
Participants whose interests will be so affected.

8.06. ADDITIONAL PARTNERS. Each Participant hereby consents to the admission to
the Partnership of additional Participants as the Managing General Partner, in
its discretion, chooses to admit.

8.07. LEGAL EFFECT. This Agreement shall be binding on and inure to the benefit
of the parties, their heirs, devisees, personal representatives, successors and
assigns, and shall run with the interests subject to this Agreement. The terms
"Partnership," "Limited Partner," "Investor General Partner," "Participant,"
"Partner," "Managing General Partner," "Operator," or "parties" shall equally
apply to any successor limited partnership, and any heir, devisee, personal
representative, successor or assign of a party.

IN WITNESS WHEREOF, the parties hereto set their hands as of the day and year
hereinabove shown.

ATLAS:                                       ATLAS RESOURCES, INC.
                                             Managing General Partner

                                             By:
                                                --------------------------------



                                       49


                                  EXHIBIT (I-A)

                                     FORM OF
                     MANAGING GENERAL PARTNER SIGNATURE PAGE






                                  EXHIBIT (I-A)
                     MANAGING GENERAL PARTNER SIGNATURE PAGE



Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND
AGREEMENT OF LIMITED PARTNERSHIP of ATLAS AMERICA PUBLIC #14-2004 L.P.

The undersigned agrees:

      1.       to serve as the Managing General Partner of ATLAS AMERICA PUBLIC
               #14-2004 L.P. (the "Partnership"), and hereby executes, swears
               to, and agrees to all the terms of the Partnership Agreement;

      2.       to pay the required subscription of the Managing General Partner
               under ss.3.03(b)(1) of the Partnership Agreement; and

      3.       to subscribe to the Partnership as follows:

               (a)     $___________________ [________] Unit(s)] under Section
                       3.03(b)(2) of the Partnership Agreement as a Limited
                       Partner; or

               (b)     $___________________ [________] Unit(s)] under Section
                       3.03(b)(2) of the Partnership Agreement as an Investor
                       General Partner.



MANAGING GENERAL PARTNER:

Atlas Resources, Inc.                        Address:


By:   __________________________             311 Rouser Road
                                             Moon Township, Pennsylvania 15108




ACCEPTED this ___ day of _______ , 2004.



                                             ATLAS RESOURCES, INC.
                                             MANAGING GENERAL PARTNER


                                             By: ______________________________




                                  EXHIBIT (I-B)

                                     FORM OF
                             SUBSCRIPTION AGREEMENT



                       ATLAS AMERICA PUBLIC #14-2004 L.P.

- --------------------------------------------------------------------------------
                             SUBSCRIPTION AGREEMENT
- --------------------------------------------------------------------------------

I, the undersigned, hereby offer to purchase Units of Atlas America Public
#14-2004 L.P. in the amount set forth on the Signature Page of this Subscription
Agreement and on the terms described in the current Prospectus for Atlas America
Public #14-2004 Program, as supplemented or amended from time to time. I
acknowledge and agree that my execution of this Subscription Agreement also
constitutes my execution of the Agreement of Limited Partnership (the
"Partnership Agreement") the form of which is attached as Exhibit (A) to the
Prospectus and I agree to be bound by all of the terms and conditions of the
Partnership Agreement if my subscription is accepted by Atlas Resources, Inc.,
the Managing General Partner. I understand and agree that I may not assign this
offer, nor may it be withdrawn after it has been accepted by the Managing
General Partner. I hereby irrevocably constitute and appoint the Managing
General Partner, and its duly authorized agents, my agent and attorney-in-fact,
in my name, place and stead, to make, execute, acknowledge, swear to, file,
record and deliver the Agreement of Limited Partnership and any certificates
related thereto.

In order to induce the Managing General Partner to accept this subscription, I
hereby represent, warrant, covenant and agree as follows:


INVESTOR'S        CO-INVESTOR'S
INITIALS          INITIALS
- --------          --------
____             _____             I have received the Prospectus.

_____             _____             I (other than if I am a Minnesota or Maine resident) recognize and understand that:

                                    o       before this offering there has been no public market for the Units and it is
                                            unlikely that after the offering there will be any such market;

                                    o       the transferability of the Units is restricted; and

                                    o       in case of emergency or other change in circumstances I cannot expect to be
                                            able to readily liquidate my investment in the Units.

_____             _____             I am purchasing the Units for the following:

                                    o       my own account;

                                    o       for investment purposes and not for the account of others; and

                                    o       with no present intention of reselling them.

_____             _____             If an individual, I am:

                                    o       a citizen of the United States of America; and

                                    o       at least twenty-one years of age.

_____             _____             If a partnership, corporation or trust, then the members, stockholders or
                                    beneficiaries thereof are citizens of the United States.  I am at least twenty-one
                                    years of age and empowered and duly authorized under a governing document, trust
                                    instrument, charter, certificate of incorporation, by-law provision or the like to
                                    enter into this Subscription Agreement and to perform the transactions contemplated
                                    by the Prospectus, including its exhibits.


                                        1




INVESTOR'S        CO-INVESTOR'S
INITIALS          INITIALS
- --------          --------
                                    (a)     If I purchase limited partner units and I am a resident of:

                                            o    ALABAMA,                 o    KENTUCKY,           o    OREGON,

                                            o    ALASKA,                  o    LOUISIANA,          o    PENNSYLVANIA,

                                            o    ARIZONA,                 o    MAINE,              o    RHODE ISLAND,

                                            o    ARKANSAS,                o    MARYLAND,           o    SOUTH CAROLINA,

                                            o    COLORADO,                o    MASSACHUSETTS,      o    SOUTH DAKOTA,

                                            o    CONNECTICUT,             o    MINNESOTA,          o    TENNESSEE,

                                            o    DELAWARE,                o    MISSISSIPPI,        o    TEXAS,

                                            o    DISTRICT OF COLUMBIA,    o    MISSOURI,           o    UTAH,

                                            o    FLORIDA,                 o    MONTANA,            o    VERMONT,

                                            o    GEORGIA,                 o    NEBRASKA,           o    VIRGINIA,

                                            o    HAWAII,                  o    NEVADA,             o    WASHINGTON

                                            o    IDAHO,                   o    NEW MEXICO          o    WEST VIRGINIA,

                                            o    ILLINOIS,                o    NEW YORK,           o    WISCONSIN, OR

                                            o    INDIANA,                 o    NORTH DAKOTA,       o    WYOMING,

                                            o    IOWA,                    o    OHIO,

                                            o    KANSAS,                  o    OKLAHOMA,

                                            then I must have either:

_____             _____                     o    a minimum net worth of $225,000, exclusive of home, home furnishings, and
                                                 automobiles; or

_____             _____                     o    a minimum net worth of $60,000, exclusive of home, home furnishings, and
                                                 automobiles, and had during the last tax year or estimate that you will have
                                                 during the current tax year "taxable income" as defined in Section 63 of the
                                                 Internal Revenue Code of at least $60,000, without regard to an investment in
                                                 the partnership.

_____             _____                     In addition, if I am a resident of OHIO, or PENNSYLVANIA, then I must not make an
                                            investment in a partnership which is in excess of 10% of my net worth, exclusive of
                                            home, home furnishings and automobiles. Finally, if I am a resident of KANSAS, it
                                            is recommended by the Office of the Kansas Securities Commissioner that Kansas
                                            investors should limit their investment in the Program and substantially similar
                                            programs to no more than 10% of their net worth, excluding home, furnishings and
                                            automobiles.

                                    (b)     If I purchase limited partner units and I am a resident of:

                                            o    CALIFORNIA,              o    NEW HAMPSHIRE,
                                                                          o    NEW JERSEY, or
                                            o    MICHIGAN,                o    NORTH CAROLINA,

                                            THEN I REPRESENT THAT I AM AWARE OF AND MEET THAT STATE'S QUALIFICATIONS AND
                                            SUITABILITY STANDARDS SET FORTH IN EXHIBIT (B) TO THE PROSPECTUS.

                                    (c)     If I purchase investor general partner units and I am a resident of:

                                            o    ALASKA,                  o    ILLINOIS,           o    SOUTH CAROLINA,

                                            o    COLORADO,                o    LOUISIANA,          o    UTAH,

                                            o    CONNECTICUT,             o    MARYLAND,           o    VIRGINIA,

                                            o    DELAWARE,                o    MONTANA,            o    WEST VIRGINIA,

                                            o    DISTRICT OF COLUMBIA,    o    NEBRASKA,           o    WISCONSIN, OR

                                            o    FLORIDA,                 o    NEVADA,             o    WYOMING,

                                            o    GEORGIA,                 o    NEW YORK,

                                            o    HAWAII,                  o    NORTH DAKOTA,

                                            o    IDAHO,                   o    RHODE ISLAND,



                                         2




INVESTOR'S        CO-INVESTOR'S
INITIALS          INITIALS
- --------          --------
                                            then I must have either:

_____             _____                     o    a net worth of at least $225,000, exclusive of  home, furnishings and
                                                 automobiles; or

_____             _____                     o  a net worth, exclusive of home, furnishings and automobiles, of:

                                                 o    at least $60,000; and

                                                 o    had during the last tax year, or estimate that I will have during the
                                                      current tax year, "taxable income" as defined in Section 63 of the
                                                      Code of at least $60,000, without regard to an investment in the
                                                      Partnership.

_____             _____            (d)      IF I PURCHASE INVESTOR GENERAL PARTNER UNITS AND I AM A RESIDENT OF:

                                            o    ALABAMA,                 o    MASSACHUSETTS,      o    OHIO,

                                            o    ARIZONA,                 o    MICHIGAN,           o    OKLAHOMA,

                                            o    ARKANSAS,                o    MINNESOTA,          o    OREGON,

                                            o    CALIFORNIA,              o    MISSISSIPPI,        o    PENNSYLVANIA,

                                            o    INDIANA,                 o    MISSOURI,           o    SOUTH DAKOTA,

                                            o    IOWA,                    o    NEW HAMPSHIRE,      o    TENNESSEE,

                                            o    KANSAS,                  o    NEW JERSEY,         o    TEXAS,

                                            o    KENTUCKY,                o    NEW MEXICO,         o    VERMONT OR

                                            o    MAINE,                   o    NORTH CAROLINA,     o    WASHINGTON,

                                            THEN I REPRESENT THAT I AM AWARE OF AND MEET THAT STATE'S QUALIFICATIONS AND
                                            SUITABILITY STANDARDS SET FORTH IN EXHIBIT (B) TO THE PROSPECTUS.

_____             _____             (e)     If I am a fiduciary, then I am purchasing for a person or entity having the
                                            appropriate income and/or net worth specified in (a) or (b) above.

_____             _____             I (other than if I am a Minnesota or Maine resident) understand that if I am an Investor
                                    General Partner, then I will have unlimited joint and several liability for Partnership
                                    obligations and liabilities including amounts in excess of my subscription to the extent
                                    the obligations and liabilities exceed the following:

                                    o       the Partnership's insurance proceeds;

                                    o       the Partnership's assets; and

                                    o       indemnification by the Managing General Partner.

                                    Insurance may be inadequate to cover these liabilities and there is no insurance coverage
                                    for certain claims.

_____             _____             I (other than if I am a Minnesota or Maine resident) understand that if I am a Limited
                                    Partner, then I may only use my Partnership losses to the extent of my net passive income
                                    from passive activities in the year, with any excess losses being deferred.

_____             _____             I (other than if I am a Minnesota or Maine resident) understand that no state or federal
                                    governmental authority has made any finding or determination relating to the fairness for
                                    public investment of the Units and no state or federal governmental authority has
                                    recommended or endorsed or will recommend or endorse the Units.


                                                               3



INVESTOR'S        CO-INVESTOR'S
INITIALS          INITIALS
- --------          --------
_____             _____             I (other than if I am a Minnesota or Maine resident) understand that the Selling Agent or
                                    registered representative is required to inform me and the other potential investors of all
                                    pertinent facts relating to the Units, including the following:

                                    o       the risks involved in the offering, including the speculative nature of the
                                            investment and the speculative nature of drilling for natural gas and oil;

                                    o       the financial hazards involved in the offering, including the risk of losing my
                                            entire investment;

                                    o       the lack of liquidity of my investment;

                                    o       the restrictions on transferability of my Units;

                                    o       the background of the Managing General Partner and the Operator;

                                    o       the tax consequences of my investment; and

                                    o       the unlimited joint and several liability of the Investor General Partners.


THE ABOVE REPRESENTATIONS DO NOT CONSTITUTE A WAIVER OF ANY RIGHTS THAT I MAY
HAVE UNDER THE ACTS ADMINISTERED BY THE SEC OR BY ANY STATE REGULATORY AGENCY
ADMINISTERING STATUTES BEARING ON THE SALE OF SECURITIES.

INSTRUCTIONS TO INVESTOR
You are required to execute your own Subscription Agreement and the Managing
General Partner will not accept any Subscription Agreement that has been
executed by someone other than you unless:

         o        the person has been given your legal power of attorney to sign
                  on your behalf; and

         o        you meet all of the conditions in the Prospectus and this
                  Subscription Agreement.

In the case of sales to fiduciary accounts, the minimum standards set forth in
the Prospectus and this Subscription Agreement must be met by:

         o        the beneficiary;

         o        the fiduciary account; or

         o        by the donor or grantor who directly or indirectly supplies
                  the funds to purchase the Partnership Units if the donor or
                  grantor is the fiduciary.

Your execution of the Subscription Agreement constitutes your binding offer to
buy Units in the Partnership. Once you subscribe you may withdraw your
subscription only by providing the Managing General Partner with written notice
of your withdrawal before your subscription is accepted by the Managing General
Partner. The Managing General Partner has the discretion to refuse to accept
your subscription without liability to you. Subscriptions will be accepted or
rejected by the Partnership within 30 days of their receipt. If your
subscription is rejected, then all of your funds will be returned to you
immediately.

If your subscription is accepted before the first closing, then you will be
admitted as a Participant not later than 15 days after the release from escrow
of the investors' funds to the Partnership. If your subscription is accepted
after the first closing, then you will be admitted into the Partnership not
later than the last day of the calendar month in which your subscription was
accepted by the Partnership.

The Managing General Partner will do the following:

         o        not complete a sale of Units to you until at least five
                  business days after the date you receive a final Prospectus;
                  and

                                       4

         o        send you a confirmation of purchase.

NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from
various requirements of Title 10 of the California Administrative Code. These
deviations include, but are not limited to the following: the definition of
Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule
260.140.121(1), does not require enlarging or contracting the size of the area
on the basis of geological data in all cases.

If a resident of California I acknowledge the receipt of California Rule
260.141.11 set forth in Exhibit (B) to the Prospectus.




                                       5

- --------------------------------------------------------------------------------
                    SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
- --------------------------------------------------------------------------------

I, the undersigned, agree to purchase ________ Units at $10,000 per Unit in
ATLAS AMERICA PUBLIC #14-2004 L.P. (the "Partnership") as (check one):


       |_|    INVESTOR GENERAL PARTNER                                                      SUBSCRIPTION PRICE
       |_|    LIMITED PARTNER                                                               $_______________________
                                                                                            (______________________# Units)

INSTRUCTIONS
=============================================================================================================================
Make your check payable to: "Atlas America Public #14-2004 L.P., Escrow Agent, National City Bank of PA"
Minimum Subscription: one Unit ($10,000), however, the Managing General Partner, in its discretion, may accept one-half
Unit ($5,000) subscriptions.  Additional Subscriptions in $1,000 increments.  If you are an individual investor you must
personally sign this signature page and provide the information requested below.
=============================================================================================================================


Subscriber (All individual investors must personally                   My Home Address (Do not use P.O. Box)
                    sign this Signature Page.)

- -------------------------------------------------                      ------------------------------------------------------
Print Name

- -------------------------------------------------                      ------------------------------------------------------
Signature

- -------------------------------------------------                      ------------------------------------------------------
Print Name
                                                                       My Address for Distributions if Different from Above
- -------------------------------------------------
Signature                                                              ------------------------------------------------------

                                                                       ------------------------------------------------------

Date: _______________                                                  Account No.: _________________________________________


My Tax I.D. No.  (Social Security No.):  _________________

My Telephone No.: Business ___________________  Home ________________________

My E-mail Address: ____________________________________

(CHECK ONE): I am a:                    |_|   Calendar Year Taxpayer           |_|   Fiscal Year Taxpayer

(CHECK IF APPLICABLE): I am a:          |_|   Farmer (2/3 or more of my gross income in 2004 or 2003 is from farming)

(CHECK ONE): OWNERSHIP OF THE UNITS-                |_|   Tenants-in-Common                            |_|  Partnership
                                                    |_|   Joint Tenancy with Right of Survivorship     |_|  C Corporation
                                                    |_|   Individual                                   |_|  S Corporation
                                                    |_|   Trust                                        |_|  Community Property
                                                    |_|   Limited Liability Company                    |_|  Other

NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP:  NAME ___________________________________________________________________________
(ENCLOSE SUPPORTING DOCUMENTS.)

                                       1



- -----------------------------------------------------------------------------------------------------------------------------
                       TO BE COMPLETED BY REGISTERED REPRESENTATIVE (FOR COMMISSION AND OTHER PURPOSES)
- -----------------------------------------------------------------------------------------------------------------------------

I hereby represent that I have discharged my affirmative obligations under Rule 2810(b)(2)(B) and (b)(3)(D) of the NASD's
Conduct Rules and specifically have obtained information from the above-named subscriber concerning his/her age, net worth,
annual income, federal income tax bracket, investment objectives, investment portfolio, and other financial information and
have determined that an investment in the Partnership is suitable for such subscriber, that such subscriber is or will be in
a financial position to realize the benefits of this investment, and that such subscriber has a fair market net worth
sufficient to sustain the risks for this investment. I have also informed the subscriber of all pertinent facts relating to
the liquidity and marketability of an investment in the Partnership, of the risks of unlimited liability regarding an
investment as an Investor General Partner, and of the passive loss limitations for tax purposes of an investment as a Limited
Partner.



- ------------------------------------------------------------           ------------------------------------------------------
Name of Registered Representative and CRD Number                       Name of Broker/Dealer

- ------------------------------------------------------------           ------------------------------------------------------
Signature of Registered Representative                                 Broker/Dealer CRD Number

Registered Representative Office Address:                              Broker/Dealer E-mail Address:_________________________

- ------------------------------------------------------------

- ------------------------------------------------------------

Phone Number:
              ----------------------------------------------

Facsimile Number:
                  ------------------------------------------

E-mail Address:
                --------------------------------------------


- ------------------------------------------------------------
Company Name (if other than Broker/Dealer Name)

NOTICE TO BROKER-DEALER:

Send SUBSCRIPTION DOCUMENTS completed and signed with CHECK MADE PAYABLE TO: "ATLAS PUBLIC #14-2004 L.P., ESCROW AGENT,
NATIONAL CITY BANK OF PA" to:

Mr. Justin Atkinson
Anthem Securities, Inc.
311 Rouser Road
P.O. Box 926
Moon Township, Pennsylvania 15108-0926
(412) 262-1680
(412) 262-7430 (FAX)

- -----------------------------------------------------------------------------------------------------------------------------
                                       TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
- -----------------------------------------------------------------------------------------------------------------------------

ACCEPTED THIS ______ day                                                             ATLAS RESOURCES, INC.,
of  _________________ , 2004                                                         MANAGING GENERAL PARTNER

                                                                                     By:_____________________________________


                                       2





                                  EXHIBIT (II)
                                     FORM OF
                        DRILLING AND OPERATING AGREEMENT
                                       FOR
                       ATLAS AMERICA PUBLIC #14-2004 L.P.
                   [ATLAS AMERICA PUBLIC #14-2005(_____) L.P.]



                                      INDEX



SECTION                                                                                                        PAGE
1.    Assignment of Well Locations; Representations and Indemnification Associated with the
      Assignment of the Lease; Designation of Additional Well Locations; Outside Activities
      Are Not Restricted..........................................................................................1

2.    Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations.................2

3.    Operator - Responsibilities in General; Covenants; Term.....................................................3

4.    Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination;
      Dry Hole Determination; Excess Funds and Cost Overruns - Intangible Drilling Costs; Excess
      Funds and Cost Overruns - Tangible Costs....................................................................4

5.    Title Examination of Well Locations; Developer's Acceptance and Liability; Additional Well Locations........7

6.    Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs;
      Pipelines; Price Determinations; Plugging and Abandonment...................................................7

7.    Billing and Payment  Procedure with Respect to Operation of Wells;  Disbursements;  Separate Account for Sale
      Proceeds; Records and Reports; Additional Information.......................................................9

8.    Operator's Lien; Right to Collect From Oil or Gas Purchaser................................................10

9.    Successors and Assigns; Transfers; Appointment of Agent....................................................11

10.   Operator's Insurance; Subcontractors' Insurance; Operator's Liability......................................12

11.   Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind..................13

12.   Effect of Force Majeure; Definition of Force Majeure; Limitation...........................................14

13.   Term.......................................................................................................14

14.   Governing Law; Invalidity..................................................................................14

15.   Integration; Written Amendment.............................................................................14

16.   Waiver of Default or Breach................................................................................14

17.   Notices....................................................................................................15

18.   Interpretation.............................................................................................15

19.   Counterparts...............................................................................................15

      Signature Page.............................................................................................15


Exhibit A                      Description of Leases and Initial Well Locations
Exhibits A-l through A-___     Maps of Initial Well Locations
Exhibit B                      Form of Assignment
Exhibit C                      Form of Addendum


                        DRILLING AND OPERATING AGREEMENT

THIS AGREEMENT made this ______ day of _______________, 200____, by and between
ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as
"Atlas" or "Operator"),

         and

ATLAS AMERICA PUBLIC #14-2004 L.P. [Atlas America Public #14-2005(_____) L.P.],
a Delaware limited partnership, (hereinafter referred to as the "Developer").

                                WITNESSETH THAT:

WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the "Leases")
described on Exhibit A attached to and made a part of this Agreement, has
certain rights to develop the ____________ (______) initial well locations (the
"Initial Well Locations") identified on the maps attached to and made a part of
this Agreement as Exhibits A-l through A-______;

WHEREAS, the Developer, subject to the terms and conditions of this Agreement,
desires to acquire certain of the Operator's rights to develop the Initial Well
Locations and to provide for the development on the terms and conditions set
forth in this Agreement of additional well locations ("Additional Well
Locations") which the parties may from time to time designate; and

WHEREAS, the Operator is in the oil and gas exploration and development
business, and the Developer desires that Operator, as its independent
contractor, perform certain services in connection with its efforts to develop
the aforesaid Initial and Additional Well Locations (collectively the "Well
Locations") and to operate the wells completed on the Well Locations, on the
terms and conditions set forth in this Agreement;

NOW THEREFORE, in consideration of the mutual covenants herein contained and
subject to the terms and conditions hereinafter set forth, the parties hereto,
intending to be legally bound, hereby agree as follows:

1.   ASSIGNMENT OF WELL LOCATIONS; REPRESENTATIONS AND INDEMNIFICATION
     ASSOCIATED WITH THE ASSIGNMENT OF THE LEASE; DESIGNATION OF ADDITIONAL WELL
     LOCATIONS; OUTSIDE ACTIVITIES ARE NOT RESTRICTED.

     (a)  ASSIGNMENT OF WELL LOCATIONS. The Operator shall execute an assignment
          of an undivided percentage of Working Interest in the Well Location
          acreage for each well to the Developer as shown on Exhibit A attached
          hereto, which assignment shall be limited to a depth from the surface
          to the ___ of the ______________ formation (the "Objective
          Formation"). In the event, however, that hydrocarbons are encountered
          in quantities that Operator believes to be in paying quantities and
          drilling ceases before the Objective Formation is penetrated, then
          Operator shall execute an assignment limited to a depth from the
          surface to the deepest depth penetrated at the cessation of drilling
          operations.

          The assignment shall be substantially in the form of Exhibit B
          attached to and made a part of this Agreement. The amount of acreage
          included in each Initial Well Location and the configuration of the
          Initial Well Location are indicated on the maps attached as Exhibits
          A-l through A-______. The amount of acreage included in each
          Additional Well Location and the configuration of the Additional Well
          Location shall be indicated on the maps to be attached as exhibits to
          the applicable addendum to this Agreement as provided in sub-section
          (c) below.

     (b)  REPRESENTATIONS AND INDEMNIFICATION ASSOCIATED WITH THE ASSIGNMENT OF
          THE LEASE. The Operator represents and warrants to the Developer that:

          (i)     the Operator is the lawful owner of the Lease and rights and
                  interest under the Lease and of the personal property on the
                  Lease or used in connection with the Lease;

          (ii)    the Operator has good right and authority to sell and convey
                  the rights, interest, and property;

          (iii)   the rights, interest, and property are free and clear from all
                  liens and encumbrances; and

          (iv)    all rentals and royalties due and payable under the Lease have
                  been duly paid.

                                       1

          These representations and warranties shall also be included in each
          recorded assignment of the acreage included in each Initial Well
          Location and Additional Well Location designated pursuant to
          sub-section (c) below, substantially in the manner set forth in
          Exhibit B.

          The Operator agrees to indemnify, protect and hold the Developer and
          its successors and assigns harmless from and against all costs
          (including but not limited to reasonable attorneys' fees),
          liabilities, claims, penalties, losses, suits, actions, causes of
          action, judgments or decrees resulting from the breach of any of the
          above representations and warranties. It is understood and agreed
          that, except as specifically set forth above, the Operator makes no
          warranty or representation, express or implied, as to its title or the
          title of the lessors in and to the lands or oil and gas interests
          covered by said Leases.

     (c)  DESIGNATION OF ADDITIONAL WELL LOCATIONS. If the parties hereto desire
          to designate Additional Well Locations to be developed in accordance
          with the terms and conditions of this Agreement, then the parties
          shall execute an addendum substantially in the form of Exhibit C
          attached to and made a part of this Agreement (Exhibit "C")
          specifying:

          (i)     the undivided percentage of Working Interest and the Oil and
                  Gas Leases to be included as Leases under this Agreement;

          (ii)    the amount and configuration of acreage included in each
                  Additional Well Location on maps attached as exhibits to the
                  addendum; and

          (iii)   their agreement that the Additional Well Locations shall be
                  developed in accordance with the terms and conditions of this
                  Agreement.

     (d)  OUTSIDE ACTIVITIES ARE NOT RESTRICTED. It is understood and agreed
          that the assignment of rights under the Leases and the oil and gas
          development activities contemplated by this Agreement relate only to
          the Initial Well Locations and the Additional Well Locations. Nothing
          contained in this Agreement shall be interpreted to restrict in any
          manner the right of each of the parties to conduct without the
          participation of the other party any additional activities relating to
          exploration, development, drilling, production, or delivery of oil and
          gas on lands adjacent to or in the immediate vicinity of the Well
          Locations or elsewhere.

2.   DRILLING OF WELLS; TIMING; DEPTH; INTEREST OF DEVELOPER; RIGHT TO
     SUBSTITUTE WELL LOCATIONS.

     (a)  DRILLING OF WELLS. Operator, as Developer's independent contractor,
          agrees to drill, complete (or plug) and operate ____________ (_____)
          oil and gas wells on the ____________ (______) Initial Well Locations
          in accordance with the terms and conditions of this Agreement.
          Developer, as a minimum commitment, agrees to participate in and pay
          the Operator's charges for drilling and completing the wells and any
          extra costs pursuant to Section 4 in proportion to the share of the
          Working Interest owned by the Developer in the wells with respect to
          all initial wells. It is understood and agreed that, subject to
          sub-section (e) below, Developer does not reserve the right to decline
          participation in the drilling of any of the initial wells to be
          drilled under this Agreement.

     (b)  TIMING. Operator shall begin drilling the first well within thirty
          (30) days after the date of this Agreement, and shall begin drilling
          each of the other initial wells for which payment is made pursuant to
          Section 4(b) of this Agreement before the close of the 90th day after
          the close of the calendar year in which this Agreement is entered into
          by Operator and the Developer. Subject to the foregoing time limits,
          Operator shall determine the timing of and the order of drilling the
          Initial Well Locations.

     (c)  DEPTH. All of the wells to be drilled under this Agreement (c) shall
          be:

          (i)     drilled and completed (or plugged) in accordance with the
                  generally accepted and customary oil and gas field practices
                  and techniques then prevailing in the geographical area of the
                  Well Locations; and

          (ii)    drilled to a depth sufficient to test thoroughly the objective
                  formation or the deepest assigned depth, whichever is less.

                                       2

     (d)  INTEREST OF DEVELOPER. Except as otherwise provided in this Agreement,
          all costs, expenses, and liabilities incurred in connection with the
          drilling and other operations and activities contemplated by this
          Agreement shall be borne and paid, and all wells, gathering lines of
          up to approximately 2,500 feet on the Well Location, in connection
          with a natural gas well, equipment, materials, and facilities
          acquired, constructed or installed under this Agreement shall be
          owned, by the Developer in proportion to the share of the Working
          Interest owned by the Developer in the wells. Subject to the payment
          of lessor's royalties and other royalties and overriding royalties, if
          any, production of oil and gas from the wells to be drilled under this
          Agreement shall be owned by the Developer in proportion to the share
          of the Working Interest owned by the Developer in the wells.

     (e)  RIGHT TO SUBSTITUTE WELL LOCATIONS. Notwithstanding the provisions of
          sub-section (a) above, if the Operator or Developer determines in good
          faith, with respect to any Well Location, before operations begin
          under this Agreement on the Well Location, that it would not be in the
          best interest of the parties to drill a well on the Well Location,
          then the party making the determination shall notify the other party
          of its determination and its basis for its determination and, unless
          otherwise instructed by Developer, the well shall not be drilled. This
          determination may be based on:

          (i)     the production or failure of production of any other wells
                  which may have been recently drilled in the immediate area of
                  the Well Location;

          (ii)    newly discovered title defects; or

          (iii)   any other evidence with respect to the Well Location as may be
                  obtained.

          If the well is not drilled, then Operator shall promptly propose a new
          well location (including all information for the Well Location as
          Developer may reasonably request) to be substituted for the original
          Well Location. Developer shall then have seven (7) business days to
          either reject or accept the proposed new well location. If the new
          well location is rejected, then Operator shall promptly propose
          another substitute well location pursuant to the provisions of this
          sub-section.

          Once the Developer accepts a substitute well location or does not
          reject it within said seven (7) day period, this Agreement shall
          terminate as to the original Well Location and the substitute well
          location shall become subject to the terms and conditions of this
          Agreement.

3.   OPERATOR - RESPONSIBILITIES IN GENERAL; COVENANTS; TERM.

     (a)  OPERATOR - RESPONSIBILITIES IN GENERAL. Atlas shall be the Operator of
          the wells and Well Locations subject to this Agreement and, as the
          Developer's independent contractor, shall, in addition to its other
          obligations under this Agreement do the following:

          (i)     arrange for drilling and completing the wells and, if a gas
                  well, installing the necessary gas gathering line systems and
                  connection facilities;

          (ii)    make the technical decisions required in drilling, testing,
                  completing, and operating the wells;

          (iii)   manage and conduct all field operations in connection with the
                  drilling, testing, completing, equipping, operating, and
                  producing the wells;

          (iv)    maintain all wells, equipment, gathering lines if a gas well,
                  and facilities in good working order during their useful
                  lives; and

          (v)     perform the necessary administrative and accounting functions.

          In performing the work contemplated by this Agreement, Operator is an
          independent contractor with authority to control and direct the
          performance of the details of the work.

     (b)  COVENANTS. Operator covenants and agrees that under this Agreement:

          (i)     it shall perform and carry on (or cause to be performed and
                  carried on) its duties and obligations in a good, prudent,
                  diligent, and workmanlike manner using technically sound,
                  acceptable oil and gas field practices then prevailing in the
                  geographical area of the Well Locations;

                                       3

          (ii)    all drilling and other operations conducted by, for and under
                  the control of Operator shall conform in all respects to
                  federal, state and local laws, statutes, ordinances,
                  regulations, and requirements;

          (iii)   unless otherwise agreed in writing by the Developer, all work
                  performed pursuant to a written estimate shall conform to the
                  technical specifications set forth in the written estimate and
                  all equipment and materials installed or incorporated in the
                  wells and facilities shall be new or used and of good quality;

          (iv)    in the course of conducting operations, it shall comply with
                  all terms and conditions, other than any minimum drilling
                  commitments, of the Leases (and any related assignments,
                  amendments, subleases, modifications and supplements);

          (v)     it shall keep the Well Locations and all wells, equipment and
                  facilities located on the Well Locations free and clear of all
                  labor, materials and other liens or encumbrances arising out
                  of operations;

          (vi)    it shall file all reports and obtain all permits and bonds
                  required to be filed with or obtained from any governmental
                  authority or agency in connection with the drilling or other
                  operations and activities; and

          (vii)   it will provide competent and experienced personnel to
                  supervise drilling, completing (or plugging), and operating
                  the wells and use the services of competent and experienced
                  service companies to provide any third party services
                  necessary or appropriate in order to perform its duties.

     (c)  TERM. Atlas shall serve as Operator under this Agreement until the
          earliest of:

          (i)     the termination of this Agreement pursuant to Section 13;

          (ii)    the termination of Atlas as Operator by the Developer at any
                  time in the Developer's discretion, with or without cause on
                  sixty (60) days' advance written notice to the Operator; or

          (iii)   the resignation of Atlas as Operator under this Agreement
                  which may occur on ninety (90) days' written notice to the
                  Developer at any time after five (5) years from the date of
                  this Agreement, it being expressly understood and agreed that
                  Atlas shall have no right to resign as Operator before the
                  expiration of the five-year period.

          Any successor Operator shall be selected by the Developer. Nothing
          contained in this sub-section shall relieve or release Atlas or the
          Developer from any liability or obligation under this Agreement which
          accrued or occurred before Atlas' removal or resignation as Operator
          under this Agreement. On any change in Operator under this provision,
          the then present Operator shall deliver to the successor Operator
          possession of all records, equipment, materials and appurtenances used
          or obtained for use in connection with operations under this Agreement
          and owned by the Developer.

4.   OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS; PAYMENT; COMPLETION
     DETERMINATION; DRY HOLE DETERMINATION; EXCESS FUNDS AND COST
     OVERRUNS-INTANGIBLE DRILLING COSTS; EXCESS FUNDS AND COST OVERRUNS-TANGIBLE
     COSTS.

     (a)  OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS. All oil and gas
          wells which are drilled and completed under this Agreement shall be
          drilled and completed on a Cost plus 15% basis. "Cost," when used with
          respect to services, shall mean the reasonable, necessary, and actual
          expenses incurred by Operator on behalf of Developer in providing the
          services under this Agreement, determined in accordance with generally
          accepted accounting principles. As used elsewhere, "Cost" shall mean
          the price paid by Operator in an arm's-length transaction.

          The estimated price for each of the wells shall be set forth in an
          Authority for Expenditure ("AFE") which shall be attached to this
          Agreement as an Exhibit, and shall cover all ordinary costs which may
          be incurred in drilling and completing each well. This includes
          without limitation, site preparation, permits and bonds, roadways,
          surface damages, power at the site, water, Operator's overhead and
          profit, rights-of-way, drilling rigs, equipment and materials, costs
          of title examinations, logging, cementing, fracturing, casing, meters
          (other than utility purchase meters), connection facilities, salt
          water collection tanks, separators, siphon string, rabbit, tubing, an
          average of 2,500 feet of gathering line per well, in connection with a
          gas well, and geological and engineering services.

                                       4

     (b)  PAYMENT. The Developer shall pay to Operator, in proportion to the
          share of the Working Interest owned by the Developer in the wells, one
          hundred percent (100%) of the estimated Intangible Drilling Costs and
          Tangible Costs as those terms are defined below, for drilling and
          completing all initial wells on execution of this Agreement.
          Notwithstanding, Atlas' payments for its share of the estimated
          Tangible Costs as that term is defined below of drilling and
          completing all initial wells as the Managing General Partner of the
          Developer shall be paid within five (5) business days of notice from
          Operator that the costs have been incurred. The Developer's payment
          shall be nonrefundable in all events in order to enable Operator to do
          the following:

          (i)     commence site preparation for the initial wells;

          (ii)    obtain suitable subcontractors for drilling and completing the
                  wells at currently prevailing prices; and

          (iii)   insure the availability of equipment and materials.

          For purposes of this Agreement, "Intangible Drilling Costs" shall mean
          those expenditures associated with property acquisition and the
          drilling and completion of oil and gas wells that under present law
          are generally accepted as fully deductible currently for federal
          income tax purposes. This includes all expenditures made with respect
          to any well before the establishment of production in commercial
          quantities for wages, fuel, repairs, hauling, supplies and other costs
          and expenses incident to and necessary for the drilling of the well
          and the preparation of the well for the production of oil or gas, that
          are currently deductible pursuant to Section 263(c) of the Internal
          Revenue Code of 1986, as amended, (the "Code"), and Treasury Reg.
          Section 1.612-4, which are generally termed "intangible drilling and
          development costs," including the expense of plugging and abandoning
          any well before a completion attempt. "Tangible Costs" shall mean
          those costs associated with property acquisitions and the drilling and
          completion of oil and gas wells which are generally accepted as
          capital expenditures pursuant to the provisions of the Code. This
          includes all costs of equipment, parts and items of hardware used in
          drilling and completing a well, and those items necessary to deliver
          acceptable oil and gas production to purchasers to the extent
          installed downstream from the wellhead of any well and which are
          required to be capitalized under the Code and its regulations.

          With respect to each additional well drilled on the Additional Well
          Locations, if any, Developer shall pay Operator, in proportion to the
          share of the Working Interest owned by the Developer in the wells, one
          hundred percent (100%) of the estimated Intangible Drilling Costs and
          Tangible Costs for the well on execution of the applicable addendum
          pursuant to Section l(c) above. Notwithstanding, Atlas' payments for
          its share of the estimated Tangible Costs of drilling and completing
          all additional wells as the Managing General Partner of the Developer
          shall be paid within five (5) business days of notice from Operator
          that the costs have been incurred. The Developer's payment shall be
          nonrefundable in all events in order to enable Operator to do the
          following:

          (i)     commence site preparation;

          (ii)    obtain suitable subcontractors for drilling and completing the
                  wells at currently prevailing prices; and

          (iii)   insure the availability of equipment and materials.

          Developer shall pay, in proportion to the share of the Working
          Interest owned by the Developer in the wells, any extra costs incurred
          for each well pursuant to sub-section (a) above within ten (10)
          business days of its receipt of Operator's statement for the extra
          costs.

     (c)  COMPLETION DETERMINATION. Operator shall determine whether or not to
          run the production casing for an attempted completion or to plug and
          abandon any well drilled under this Agreement. However, a well shall
          be completed only if Operator has made a good faith determination that
          there is a reasonable possibility of obtaining commercial quantities
          of oil and/or gas.

                                       5

     (d)  DRY HOLE DETERMINATION. If Operator determines at any time during the
          drilling or attempted completion of any well under this Agreement, in
          accordance with the generally accepted and customary oil and gas field
          practices and techniques then prevailing in the geographic area of the
          Well Location that the well should not be completed, then it shall
          promptly and properly plug and abandon the well.

     (e)  EXCESS FUNDS AND COST OVERRUNS-INTANGIBLE DRILLING COSTS. Any
          estimated Intangible Drilling Costs, which are the Intangible Drilling
          Costs set forth on the AFE, paid by Developer with respect to any well
          which exceed Operator's price specified in sub-section (a) above for
          the Intangible Drilling Costs of the well shall be retained by
          Operator and shall be applied to:

          (i)     the Intangible Drilling Costs for an additional well or wells
                  to be drilled on the Additional Well Locations; or

          (ii)    any cost overruns owed by the Developer to Operator for
                  Intangible Drilling Costs on one or more of the other wells on
                  the Well Locations;

          in proportion to the share of the Working Interest owned by the
          Developer in the wells.

          Conversely, if Operator's price specified in sub-section (a) above for
          the Intangible Drilling Costs of any well exceeds the estimated
          Intangible Drilling Costs, which are the Intangible Drilling Costs set
          forth on the AFE, paid by Developer for the well, then:

          (i)     Developer shall pay the additional price to Operator within
                  five (5) business days after notice from Operator that the
                  additional amount is due and owing; or

          (ii)    Developer and Operator may agree to delete or reduce
                  Developer's Working Interest in one or more wells which have
                  not yet been spudded to provide funds to pay the additional
                  amounts to Operator. If doing so results in any excess prepaid
                  Intangible Drilling Costs, then these funds shall be applied
                  to:

                  (a)   the Intangible Drilling Costs for an additional well or
                        wells to be drilled on the Additional Well Locations; or

                  (b)   any cost overruns owed by Developer to Operator for
                        Intangible Drilling Costs on one or more of the other
                        wells on the Well Locations;

                  in proportion to the share of the Working Interest owned by
                  the Developer in the wells.

          The Exhibits to this Agreement with respect to the affected wells
          shall be amended as appropriate.

     (f)  EXCESS FUNDS AND COST OVERRUNS - TANGIBLE COSTS. Any estimated
          Tangible Costs, which are the tangible costs set forth on the AFE,
          paid by Developer with respect to any well which exceed Operator's
          price specified in sub-section (a) above for the Tangible Costs of the
          well shall be retained by Operator and shall be applied to:

          (i)     the Intangible Drilling Costs or Tangible Costs for an
                  additional well or wells to be drilled on the Additional Well
                  Locations; or

          (ii)    any cost overruns owed by Developer to Operator for Intangible
                  Drilling Costs or Tangible Costs on one or more of the other
                  wells on the Well Locations;

          in proportion to the share of the Working Interest owned by the
          Developer in the wells.

          Conversely, if Operator's price specified in sub-section (a) above for
          the Tangible Costs of any well exceeds the estimated Tangible Costs,
          which are the tangible costs set forth on the AFE, paid by Developer
          for the well, then:

                                       6

          (i)     Developer shall pay the additional price to Operator within
                  ten (10) business days after notice from Operator that the
                  additional price is due and owing; or

          (ii)    Developer and Operator may agree to delete or reduce
                  Developer's Working Interest in one or more wells which have
                  not yet been spudded to provide funds to pay the additional
                  price to Operator. If doing so results in any excess prepaid
                  Tangible Costs, then these funds shall be applied to:

                  (a)   the Intangible Drilling Costs or Tangible Costs for an
                        additional well or wells to be drilled on the Additional
                        Well Locations; or

                  (b)   any cost overruns owed by Developer to Operator for
                        Intangible Drilling Costs or Tangible Costs on one or
                        more of the other wells on the Well Locations;

                  in proportion to the share of the Working Interest owed by the
                  Developer in the wells.

          The Exhibits to this Agreement with respect to the affected wells
          shall be amended as appropriate.

5.   TITLE EXAMINATION OF WELL LOCATIONS, DEVELOPER'S ACCEPTANCE AND LIABILITY;
     ADDITIONAL WELL LOCATIONS.

     (a)  TITLE EXAMINATION OF WELL LOCATIONS, DEVELOPER'S ACCEPTANCE AND
          LIABILITY. The Developer acknowledges that Operator has furnished
          Developer with the title opinions identified on Exhibit A, and other
          documents and information which Developer or its counsel has requested
          in order to determine the adequacy of the title to the Initial Well
          Locations and leased premises subject to this Agreement. The Developer
          accepts the title to the Initial Well Locations and leased premises
          and acknowledges and agrees that, except for any loss, expense, cost,
          or liability caused by the breach of any of the warranties and
          representations made by the Operator in Section l(b), any loss,
          expense, cost or liability whatsoever caused by or related to any
          defect or failure of the title shall be the sole responsibility of and
          shall be borne entirely by the Developer.

     (b)  ADDITIONAL WELL LOCATIONS. Before beginning drilling of any well on
          any Additional Well Location, Operator shall conduct, or cause to be
          conducted, a title examination of the Additional Well Location, in
          order to obtain appropriate abstracts, opinions and certificates and
          other information necessary to determine the adequacy of title to both
          the applicable Lease and the fee title of the lessor to the premises
          covered by the Lease. The results of the title examination and such
          other information as is necessary to determine the adequacy of title
          for drilling purposes shall be submitted to the Developer for its
          review and acceptance. No drilling on the Additional Well Locations
          shall begin until the title has been accepted in writing by the
          Developer. After any title has been accepted by the Developer, any
          loss, expense, cost, or liability whatsoever, caused by or related to
          any defect or failure of the title shall be the sole responsibility of
          and shall be borne entirely by the Developer, unless such loss,
          expense, cost, or liability was caused by the breach of any of the
          warranties and representations made by the Operator in Section l(b).

6.   OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS; FEE ADJUSTMENTS;
     EXTRAORDINARY COSTS; PIPELINES; PRICE DETERMINATIONS; PLUGGING AND
     ABANDONMENT.

     (a)  OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS. Beginning with the
          month in which a well drilled under this Agreement begins to produce,
          Operator shall be entitled to an operating fee of $285 per month for
          each well being operated under this Agreement, proportionately reduced
          to the extent the Developer owns less than 100% of the Working
          Interest in the wells. This fee shall be in lieu of any direct charges
          by Operator for its services or the provision by Operator of its
          equipment for normal superintendence and maintenance of the wells and
          related pipelines and facilities.

          The operating fees shall cover all normal, regularly recurring
          operating expenses for the production, delivery and sale of natural
          gas, including without limitation:

          (i)     well tending, routine maintenance and adjustment;

          (ii)    reading meters, recording production, pumping, maintaining
                  appropriate books and records;

                                       7

          (iii)   preparing reports to the Developer and government agencies;
                  and

          (iv)    collecting and disbursing revenues.

          The operating fees shall not cover costs and expenses related to the
          following:

          (i)     the production and sale of oil;

          (ii)    the collection and disposal of salt water or other liquids
                  produced by the wells;

          (iii)   the rebuilding of access roads; and

          (iv)    the purchase of equipment, materials or third party services;

          which, subject to the provisions of sub-section (c) of this Section 6,
          shall be paid by the Developer in proportion to the share of the
          Working Interest owned by the Developer in the wells.

          Any well which is temporarily abandoned or shut-in continuously for
          the entire month shall not be considered a producing well for purposes
          of determining the number of wells in the month subject to the
          operating fee.

     (b)  FEE ADJUSTMENTS. The monthly operating fee set forth in sub-section
          (a) above may in the following manner be adjusted annually as of the
          first day of January (the "Adjustment Date") each year beginning
          January l, 2006 with respect to the partnership designated Atlas
          America Public #14-2004 L.P., and January 1, 2007 with respect to
          partnerships designated as Atlas America Public #14-2005(_____) L.P.
          Such adjustment, if any, shall not exceed the percentage increase in
          the average weekly earnings of "Crude Petroleum, Natural Gas, and
          Natural Gas Liquids" workers, as published by the U.S. Department of
          Labor, Bureau of Labor Statistics, and shown in Employment and
          Earnings Publication, Monthly Establishment Data, Hours and Earning
          Statistical Table C-2, Index Average Weekly Earnings of "Crude
          Petroleum, Natural Gas, and Natural Gas Liquids" workers, SIC Code
          #131-2, or any successor index thereto, since January l, 2004, in the
          case of the first adjustment, and since the previous Adjustment Date,
          in the case of each subsequent adjustment.

     (c)  EXTRAORDINARY COSTS. Without the prior written consent of the
          Developer, pursuant to a written estimate submitted by Operator,
          Operator shall not undertake any single project or incur any
          extraordinary cost with respect to any well being produced under this
          Agreement reasonably estimated to result in an expenditure of more
          than $5,000, unless the project or extraordinary cost is necessary for
          the following:

          (i)     to safeguard persons or property; or

          (ii)    to protect the well or related facilities in the event of a
                  sudden emergency.

          In no event, however, shall the Developer be required to pay for any
          project or extraordinary cost arising from the negligence or
          misconduct of Operator, its agents, servants, employees, contractors,
          licensees, or invitees.

          All extraordinary costs incurred and the cost of projects undertaken
          with respect to a well being produced shall be billed at the invoice
          cost of third-party services performed or materials purchased together
          with a reasonable charge by Operator for services performed directly
          by it, in proportion to the share of the Working Interest owned by the
          Developer in the wells. Operator shall have the right to require the
          Developer to pay in advance of undertaking any project all or a
          portion of the estimated costs of the project in proportion to the
          share of the Working Interest owned by the Developer in the wells.

     (d)  PIPELINES. Developer shall have no interest in the pipeline gathering
          system, which gathering system shall remain the sole property of
          Operator or its Affiliates and shall be maintained at their sole cost
          and expense.

     (e)  PRICE DETERMINATIONS. Notwithstanding anything herein to the contrary,
          the Developer shall pay all costs in proportion to the share of the
          Working Interest owned by the Developer in the wells with respect to
          obtaining price determinations under and otherwise complying with the
          Natural Gas Policy Act of 1978 and the implementing state regulations.
          This responsibility shall include, without limitation, preparing,
          filing, and executing all applications, affidavits, interim collection
          notices, reports and other documents necessary or appropriate to
          obtain price certification, to effect sales of natural gas, or
          otherwise to comply with the Act and the implementing state
          regulations.

                                       8

          Operator agrees to furnish the information and render the assistance
          as the Developer may reasonably request in order to comply with the
          Act and the implementing state regulations without charge for services
          performed by its employees.

     (f)  PLUGGING AND ABANDONMENT. The Developer shall have the right to direct
          Operator to plug and abandon any well that has been completed under
          this Agreement as a producer. In addition, Operator shall not plug and
          abandon any well that has been drilled and completed as a producer
          before obtaining the written consent of the Developer. However, if the
          Operator in accordance with the generally accepted and customary oil
          and gas field practices and techniques then prevailing in the
          geographic area of the well location, determines that any well should
          be plugged and abandoned and makes a written request to the Developer
          for authority to plug and abandon the well and the Developer fails to
          respond in writing to the request within forty-five (45) days
          following the date of the request, then the Developer shall be deemed
          to have consented to the plugging and abandonment of the well.

          All costs and expenses related to plugging and abandoning the wells
          which have been drilled and completed as producing wells shall be
          borne and paid by the Developer in proportion to the share of the
          Working Interest owned by the Developer in the wells. Also, at any
          time after one (1) year from the date each well drilled and completed
          is placed into production, Operator shall have the right to deduct
          each month from the proceeds of the sale of the production from the
          well up to $200, in proportion to the share of the Working Interest
          owned by the Developer in the wells, for the purpose of establishing a
          fund to cover the estimated costs of plugging and abandoning the well.
          All these funds shall be deposited in a separate interest bearing
          escrow account for the account of the Developer, and the total amount
          so retained and deposited shall not exceed Operator's reasonable
          estimate of Developer's share of the costs of plugging and abandoning
          the well.

7.   BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS;
     DISBURSEMENTS; SEPARATE ACCOUNT FOR SALE PROCEEDS; RECORDS AND REPORTS;
     ADDITIONAL INFORMATION.

     (a)  BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS.
          Operator shall promptly and timely pay and discharge on behalf of the
          Developer, in proportion to the share of the Working Interest owned by
          the Developer in the wells the following:

          (i)     all expenses and liabilities payable and incurred by reason of
                  its operation of the wells in accordance with this Agreement,
                  such as severance taxes, royalties, overriding royalties,
                  operating fees, and pipeline gathering charges; and

          (ii)    any third-party invoices rendered to Operator with respect to
                  costs and expenses incurred in connection with the operation
                  of the wells.

          Operator, however, shall not be required to pay and discharge any of
          the above costs and expenses which are being contested in good faith
          by Operator.

          Operator shall:

          (i)     deduct the foregoing costs and expenses from the Developer's
                  share of the proceeds of the oil and/or gas sold from the
                  wells; and

          (ii)    keep an accurate record of the Developer's account, showing
                  expenses incurred and charges and credits made and received
                  with respect to each well.

          If the proceeds are insufficient to pay the costs and expenses, then
          Operator shall promptly and timely pay and discharge the costs and
          expenses, in proportion to the share of the Working Interest owned by
          the Developer in the wells, and prepare and submit an invoice to the
          Developer each month for the costs and expenses. The invoice shall be
          accompanied by the form of statement specified in sub-section (b)
          below, and shall be paid by the Developer within ten (10) business
          days of its receipt.

                                       9

     (b)  DISBURSEMENTS. Operator shall disburse to the Developer, on a monthly
          basis, the Developer's share of the proceeds received from the sale of
          oil and/or gas sold from the wells operated under this Agreement,
          less:

          (i)     the amounts charged to the Developer under sub-section (a);
                  and

          (ii)    the amount, if any, withheld by Operator for future plugging
                  costs pursuant to sub-section (f) of Section 6.

          Each disbursement made and/or invoice submitted pursuant to
          sub-section (a) above shall be accompanied by a statement itemizing
          with respect to each well:

          (i)     the total production of oil and/or gas since the date of the
                  last disbursement or invoice billing period, as the case may
                  be, and the Developer's share of the production;

          (ii)    the total proceeds received from any sale of the production,
                  and the Developer's share of the proceeds;

          (iii)   the costs and expenses deducted from the proceeds and/or being
                  billed to the Developer pursuant to sub-section (a) above;

          (iv)    the amount withheld for future plugging costs; and

          (v)     any other information as Developer may reasonably request,
                  including without limitation copies of all third-party
                  invoices listed on the statement for the period.

     (c)  SEPARATE ACCOUNT FOR SALE PROCEEDS. Operator agrees to deposit all
          proceeds from the sale of oil and/or gas sold from the wells operated
          under this Agreement in a separate checking account maintained by
          Operator. This account shall be used solely for the purpose of
          collecting and disbursing funds constituting proceeds from the sale of
          production under this Agreement.

     (d)  RECORDS AND REPORTS. In addition to the statements required under
          sub-section (b) above, Operator, within seventy-five (75) days after
          the completion of each well drilled, shall furnish the Developer with
          a detailed statement itemizing with respect to the well the total
          costs and charges under Section 4(a) and the Developer's share of the
          costs and charges, and any information as is necessary to enable the
          Developer:

          (i)     to allocate any extra costs incurred with respect to the well
                  between Tangible Costs and Intangible Drilling Costs; and

          (ii)    to determine the amount of investment tax credit, if
                  applicable.

     (e)  ADDITIONAL INFORMATION. Operator shall promptly furnish the Developer
          with any additional information as it may reasonably request,
          including without limitation geological, technical, and financial
          information, in the form as may reasonably be requested, pertaining to
          any phase of the operations and activities governed by this Agreement.
          The Developer and its authorized employees, agents and consultants,
          including independent accountants shall, at Developer's sole cost and
          expense:

          (i)     on at least ten (10) days' written notice have access during
                  normal business hours to all of Operator's records pertaining
                  to operations, including without limitation, the right to
                  audit the books of account of Operator relating to all
                  receipts, costs, charges, expenses and disbursements under
                  this Agreement, including information regarding the separate
                  account required under sub-section (c); and

          (ii)    have access, at its sole risk, to any wells drilled by
                  Operator under this Agreement at all times to inspect and
                  observe any machinery, equipment and operations.

8.   OPERATOR'S LIEN; RIGHT TO COLLECT FROM OIL OR GAS PURCHASER.

     (a)  OPERATOR'S LIEN. To secure the payment of all sums due from Developer
          to Operator under the provisions of this Agreement the Developer
          grants Operator a first and preferred lien on and security interest in
          the following:

                                       10

          (i)     the Developer's interest in the Leases covered by this
                  Agreement;

          (ii)    the Developer's interest in oil and gas produced under this
                  Agreement and its proceeds from the sale of the oil and gas;
                  and

          (iii)   the Developer's interest in materials and equipment under this
                  Agreement.

     (b)  RIGHT TO COLLECT FROM OIL OR GAS PURCHASER. If the Developer fails to
          timely pay any amount owing under this Agreement by it to the
          Operator, then Operator, without prejudice to other existing remedies,
          may collect and retain from any purchaser or purchasers of oil or gas
          the Developer's share of the proceeds from the sale of the oil and gas
          until the amount owed by the Developer, plus twelve percent (12%)
          interest on a per annum basis, and any additional costs (including
          without limitation actual attorneys' fees and costs) resulting from
          the delinquency, has been paid. Each purchaser of oil or gas shall be
          entitled to rely on Operator's written statement concerning the amount
          of any default.

9.   SUCCESSORS AND ASSIGNS; TRANSFERS; APPOINTMENT OF AGENT.

     (a)  SUCCESSORS AND ASSIGNS. This Agreement shall be binding on and inure
          to the benefit of the undersigned parties and their respective
          successors and permitted assigns. However, without the prior written
          consent of the Developer, the Operator may not assign, transfer,
          pledge, mortgage, hypothecate, sell or otherwise dispose of any of its
          interest in this Agreement, or any of the rights or obligations under
          this Agreement. Notwithstanding, this consent shall not be required in
          connection with:

          (i)     the assignment of work to be performed for Operator by
                  subcontractors, it being understood and agreed, however, that
                  any assignment to Operator's subcontractors shall not in any
                  manner relieve or release Operator from any of its obligations
                  and responsibilities under this Agreement;

          (ii)    any lien, assignment, security interest, pledge or mortgage
                  arising under Operator's present or future financing
                  arrangements; or

          (iii)   the liquidation, merger, consolidation, or other corporate
                  reorganization or sale of substantially all of the assets of
                  Operator.

          Further, in order to maintain uniformity of ownership in the wells,
          production, equipment, and leasehold interests covered by this
          Agreement, and notwithstanding any other provisions to the contrary,
          the Developer shall not, without the prior written consent of
          Operator, sell, assign, transfer, encumber, mortgage or otherwise
          dispose of any of its interest in the wells, production, equipment or
          leasehold interests covered by this Agreement unless the disposition
          encompasses either:

          (i)     the entire interest of the Developer in all wells, production,
                  equipment and leasehold interests subject to this Agreement;
                  or

          (ii)    an equal undivided interest in all such wells, production,
                  equipment, and leasehold interests.

     (b)  TRANSFERS. Subject to the provisions of sub-section (a) above, any
          sale, encumbrance, transfer or other disposition made by the Developer
          of its interests in the wells, production, equipment, and/or leasehold
          interests covered by this Agreement shall be made:

          (i)     expressly subject to this Agreement;

          (ii)    without prejudice to the rights of the Operator; and

          (iii)   in accordance with and subject to the provisions of the Lease.

     (c)  APPOINTMENT OF AGENT. If at any time the interest of the Developer is
          divided among or owned by co-owners, Operator may, at its discretion,
          require the co-owners to appoint a single trustee or agent with full
          authority to do the following:

                                       11

          (i)     receive notices, reports and distributions of the proceeds
                  from production;

          (ii)    approve expenditures;

          (iii)   receive billings for and approve and pay all costs, expenses
                  and liabilities incurred under this Agreement;

          (iv)    exercise any rights granted to the co-owners under this
                  Agreement;

          (v)     grant any approvals or authorizations required or contemplated
                  by this Agreement;

          (vi)    sign, execute, certify, acknowledge, file and/or record any
                  agreements, contracts, instruments, reports, or documents
                  whatsoever in connection with this Agreement or the activities
                  contemplated by this Agreement; and

          (vii)   deal generally with, and with power to bind, the co-owners
                  with respect to all activities and operations contemplated by
                  this Agreement.

          However, all the co-owners shall continue to have the right to enter
          into and execute all contracts or agreements for their respective
          shares of the oil and gas produced from the wells drilled under this
          Agreement in accordance with sub-section (c) of Section 11.

10.  OPERATOR'S INSURANCE; SUBCONTRACTORS' INSURANCE; OPERATOR'S LIABILITY.

     (a)  OPERATOR'S INSURANCE. Operator shall obtain and maintain at its own
          expense so long as it is Operator under this Agreement all required
          Workmen's Compensation Insurance and comprehensive general public
          liability insurance in amounts and coverage not less than $1,000,000
          per person per occurrence for personal injury or death and $1,000,000
          for property damage per occurrence, which shall include coverage for
          blow-outs and total liability coverage of not less than $10,000,000.

          Subject to the above limits, the Operator's general public liability
          insurance shall be in all respects comparable to that generally
          maintained in the industry with respect to services of the type to be
          rendered and activities of the type to be conducted under this
          Agreement. Operator's general public liability insurance shall, if
          permitted by Operator's insurance carrier:

          (i)     name the Developer as an additional insured party; and

          (ii)    provide that at least thirty (30) days' prior notice of
                  cancellation and any other adverse material change in the
                  policy shall be given to the Developer.

          However, the Developer shall reimburse Operator for the additional
          cost, if any, of including it as an additional insured party under the
          Operator's insurance.

          Current copies of all policies or certificates of the Operator's
          insurance coverage shall be delivered to the Developer on request. It
          is understood and agreed that Operator's insurance coverage may not
          adequately protect the interests of the Developer and that the
          Developer shall carry at its expense the excess or additional general
          public liability, property damage, and other insurance, if any, as the
          Developer deems appropriate.

     (b)  SUBCONTRACTORS' INSURANCE. Operator shall require all of its
          subcontractors to carry all required Workmen's Compensation Insurance
          and to maintain such other insurance, if any, as Operator in its
          discretion may require.

     (c)  OPERATOR'S LIABILITY. Operator's liability to the Developer as
          Operator under this Agreement shall be limited to, and Operator shall
          indemnify the Developer and hold it harmless from, claims, penalties,
          liabilities, obligations, charges, losses, costs, damages, or expenses
          (including but not limited to reasonable attorneys' fees) relating to,
          caused by or arising out of:

                                       12

          (i)     the noncompliance with or violation by Operator, its
                  employees, agents, or subcontractors of any local, state or
                  federal law, statute, regulation, or ordinance;

          (ii)    the negligence or misconduct of Operator, its employees,
                  agents or subcontractors; or

          (iii)   the breach of or failure to comply with any provisions of this
                  Agreement.

11.  INTERNAL REVENUE CODE ELECTION; RELATIONSHIP OF PARTIES; RIGHT TO TAKE
     PRODUCTION IN KIND.

     (a)  INTERNAL REVENUE CODE ELECTION. With respect to this Agreement, each
          of the parties elects under Section 761(a) of the Internal Revenue
          Code of 1986, as amended, to be excluded from the provisions of
          Subchapter K of Chapter 1 of Sub Title A of the Internal Revenue Code
          of 1986, as amended. If the income tax laws of the state or states in
          which the property covered by this Agreement is located contain, or
          may subsequently contain, a similar election, each of the parties
          agrees that the election shall be exercised.

          Beginning with the first taxable year of operations under this
          Agreement, each party agrees that the deemed election provided by
          Section 1.761-2(b)(2)(ii) of the Regulations under the Internal
          Revenue Code of 1986, as amended, will apply; and no party will file
          an application under Section 1.761-2 (b)(3)(i) and (ii) of the
          Regulations to revoke the election. Each party agrees to execute the
          documents and make the filings with the appropriate governmental
          authorities as may be necessary to effect the election.

     (b)  RELATIONSHIP OF PARTIES. It is not the intention of the parties to
          create, nor shall this Agreement be construed as creating, a mining or
          other partnership or association or to render the parties liable as
          partners or joint venturers for any purpose. Operator shall be deemed
          to be an independent contractor and shall perform its obligations as
          set forth in this Agreement or as otherwise directed by the Developer.

     (c)  RIGHT TO TAKE PRODUCTION IN KIND. Subject to the provisions of Section
          8 above, the Developer shall have the exclusive right to sell or
          dispose of its proportionate share of all oil and gas produced from
          the wells to be drilled under this Agreement, exclusive of production:

          (i)     that may be used in development and producing operations;

          (ii)    unavoidably lost; and

          (iii)   used to fulfill any free gas obligations under the terms of
                  the applicable Lease or Leases.

          Operator shall not have any right to sell or otherwise dispose of the
          oil and gas. The Developer shall have the exclusive right to execute
          all contracts relating to the sale or disposition of its proportionate
          share of the production from the wells drilled under this Agreement.

          Developer shall have no interest in any gas supply agreements of
          Operator, except the right to receive Developer's share of the
          proceeds received from the sale of any gas or oil from wells developed
          under this Agreement. The Developer agrees to designate Operator or
          Operator's designated bank agent as the Developer's collection agent
          in any contracts. On request, Operator shall assist Developer in
          arranging the sale or disposition of Developer's oil and gas under
          this Agreement and shall promptly provide the Developer with all
          relevant information which comes to Operator's attention regarding
          opportunities for sale of production.

          If Developer fails to take in kind or separately dispose of its
          proportionate share of the oil and gas produced under this Agreement,
          then Operator shall have the right, subject to the revocation at will
          by the Developer, but not the obligation, to purchase the oil and gas
          or sell it to others at any time and from time to time, for the
          account of the Developer at the best price obtainable in the area for
          the production. Notwithstanding, Operator shall have no liability to
          Developer should Operator fail to market the production.

          Any purchase or sale by Operator shall be subject always to the right
          of the Developer to exercise at any time its right to take in-kind, or
          separately dispose of, its share of oil and gas not previously
          delivered to a purchaser. Any purchase or sale by Operator of any
          other party's share of oil and gas shall be only for reasonable
          periods of time as are consistent with the minimum needs of the oil
          and gas industry under the particular circumstances, but in no event
          for a period in excess of one (1) year.

                                       13

12.  EFFECT OF FORCE MAJEURE; DEFINITION OF FORCE MAJEURE; LIMITATION.

     (a)  EFFECT OF FORCE MAJEURE. If Operator is rendered unable, wholly or in
          part, by force majeure (as defined below) to carry out any of its
          obligations under this Agreement, including but not limited to
          beginning the drilling of one or more wells by the applicable times
          set forth in Section 2(b), or any Addendum to this Agreement, the
          obligations of the Operator, so far as it is affected by the force
          majeure, shall be suspended during but no longer than, the continuance
          of the force majeure. The Operator shall give to the Developer prompt
          written notice of the force majeure with reasonably full particulars
          concerning it. Operator shall use all reasonable diligence to remove
          the force majeure as quickly as possible to the extent the same is
          within reasonable control.

     (b)  DEFINITION OF FORCE MAJEURE. The term "force majeure" shall mean an
          act of God, strike, lockout, or other industrial disturbance, act of
          the public enemy, war, blockade, public riot, lightning, fire, storm,
          flood, explosion, governmental restraint, unavailability of drilling
          rigs, equipment or materials, plant shut-downs, curtailments by
          purchasers and any other causes whether of the kind specifically
          enumerated above or otherwise, which directly preclude Operator's
          performance under this Agreement and is not reasonably within the
          control of the Operator including but not limited to, with respect to
          the Operator beginning the drilling of the wells subject to this
          Agreement by the applicable times set forth in Section 2(b), or any
          Addendum to this Agreement, decisions of third-party operators to
          delay drilling the wells, poor weather conditions, inability to obtain
          drilling permits, access right to the drilling site or title problems.

     (c)  LIMITATION. The requirement that any force majeure shall be remedied
          with all reasonable dispatch shall not require the settlement of
          strikes, lockouts, or other labor difficulty affecting the Operator,
          contrary to its wishes. The method of handling these difficulties
          shall be entirely within the discretion of the Operator.

13.  TERM.

     This Agreement shall become effective when executed by Operator and the
     Developer. Except as provided in sub-section (c) of Section 3, this
     Agreement shall continue and remain in full force and effect for the
     productive lives of the wells being operated under this Agreement.

14.  GOVERNING LAW; INVALIDITY.

     (a)  GOVERNING LAW. This Agreement shall be governed by, construed and
          interpreted in accordance with the laws of the Commonwealth of
          Pennsylvania.

     (b)  INVALIDITY. The invalidity or unenforceability of any particular
          provision of this Agreement shall not affect the other provisions of
          this Agreement, and this Agreement shall be construed in all respects
          as if the invalid or unenforceable provision were omitted.

15.  INTEGRATION; WRITTEN AMENDMENT.

     (a)  INTEGRATION. This Agreement, including the Exhibits to this Agreement,
          constitutes and represents the entire understanding and agreement of
          the parties with respect to the subject matter of this Agreement and
          supersedes all prior negotiations, understandings, agreements, and
          representations relating to the subject matter of this Agreement.

     (b)  WRITTEN AMENDMENT. No change, waiver, modification, or amendment of
          this Agreement shall be binding or of any effect unless in writing
          duly signed by the party against which the change, waiver,
          modification, or amendment is sought to be enforced.

16.  WAIVER OF DEFAULT OR BREACH.

     No waiver by any party to any default of or breach by any other party under
     this Agreement shall operate as a waiver of any future default or breach,
     whether of like or different character or nature.

                                       14

17.  NOTICES.

     Unless otherwise provided in this Agreement, all notices, statements,
     requests, or demands which are required or contemplated by this Agreement
     shall be in writing and shall be hand-delivered or sent by registered or
     certified mail, postage prepaid, to the following addresses until changed
     by certified or registered letter so addressed to the other party:

                (i)      If to the Operator, to:

                         Atlas Resources, Inc.
                         311 Rouser Road
                         Moon Township, Pennsylvania 15108
                         Attention: President

                (ii)    If to Developer, to:

                         Atlas America Public #14-2004 L.P.
                         [Atlas America Public #14-2005(____) L.P.]
                         c/o Atlas Resources, Inc.
                         311 Rouser Road
                         Moon Township, Pennsylvania 15108

     Notices which are served by registered or certified mail on the parties in
     the manner provided in this Section shall be deemed sufficiently served or
     given for all purposes under this Agreement at the time the notice is
     mailed in any post office or branch post office regularly maintained by the
     United States Postal Service or any successor. All payments shall be
     hand-delivered or sent by United States mail, postage prepaid to the
     addresses set forth above until changed by certified or registered letter
     so addressed to the other party.

18.  INTERPRETATION.

     The titles of the Sections in this Agreement are for convenience of
     reference only and shall not control or affect the meaning or construction
     of any of the terms and provisions of this Agreement. As used in this
     Agreement, the plural shall include the singular and the singular shall
     include the plural whenever appropriate.

19.  COUNTERPARTS.

     The parties may execute this Agreement in any number of separate
     counterparts, each of which, when executed and delivered by the parties,
     shall have the force and effect of an original; but all such counterparts
     shall be deemed to constitute one and the same instrument.

     IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as
of the day and year first above written.

                                ATLAS RESOURCES, INC.


                                By:____________________________________________


                                ATLAS AMERICA PUBLIC #14-2004 L.P.
                                [ATLAS AMERICA PUBLIC #14-2005(____) L.P.]


                                By its Managing General Partner:
                                ATLAS RESOURCES, INC.


                                By:____________________________________________


                                       15

                DESCRIPTION OF LEASES AND INITIAL WELL LOCATIONS

               [To be completed as information becomes available]



1.  WELL LOCATION

    (a) Oil and Gas Lease from ______________________________________ dated
        _____________________ and recorded in Deed Book Volume __________, Page
        __________ in the Recorder's Office of County, ____________, covering
        approximately _________ acres in ____________________________ Township,
        ___________________ County, __________________________.

    (b) The portion of the leasehold estate constituting the
        ____________________________________________ No. __________ Well
        Location is described on the map attached hereto as Exhibit A-l.

    (c) Title Opinion of ____________________, _________________________,
        __________________________, __________________________, dated
        ___________________, 200___.

    (d) The Developer's interest in the leasehold estate constituting this Well
        Location is an undivided % Working Interest to those oil and gas rights
        from the surface to the bottom of the __________________ Formation,
        subject to the landowner's royalty interest and overriding royalty
        interests.




                                   Exhibit A

                                                                 Well Name, Twp.
                                                                   County, State


ASSIGNMENT OF OIL AND GAS LEASE



STATE OF _______________________________

COUNTY OF _____________________________

KNOW ALL MEN BY THESE PRESENTS:


         THAT the undersigned_________________________________________________
(hereinafter called "Assignor"), for and in consideration of One Dollar and
other valuable consideration ($1.00 ovc), the receipt whereof is hereby
acknowledged, does hereby sell, assign, transfer and set over
unto____________________________________________________ (hereinafter called
"Assignee"), an undivided _____________________________ in, and to, the oil and
gas lease described as follows:







together with the rights incident thereto and the personal property thereto,
appurtenant thereto, or used, or obtained, in connection therewith.

         And for the same consideration, the assignor covenants with the said
assignee his or its heirs, successors, or assigns that assignor is the lawful
owner of said lease and rights and interest thereunder and of the personal
property thereon or used in connection therewith; that the undersigned has good
right and authority to sell and convey the same, and that said rights, interest
and property are free and clear from all liens and encumbrances, and that all
rentals and royalties due and payable thereunder have been duly paid.

         In Witness Whereof, the undersigned owner ______ and assignor ______
ha___ signed and sealed this instrument the ______ day of _______________,
200___.



Signed and acknowledged in the presence of    _________________________________

__________________________________________    _________________________________

__________________________________________    _________________________________



                                   Exhibit B
                                    (Page 1)



                          ACKNOWLEDGMENT BY INDIVIDUAL


STATE OF
         --------------------------
                                    BEFORE ME, a Notary Public, in and for said
COUNTY OF
          ------------------------


         County and State, on this day personally appeared who
acknowledged to me that ____ he ____ did sign the foregoing instrument and that
the same is _____________ free act and deed.

         In testimony whereof, I have hereunto set my hand and official seal,
at_____________________________, this ______ day of _______________, A.D.,
200___.


                                                  _____________________________
                                                  Notary Public




                           CORPORATION ACKNOWLEDGMENT


STATE OF
         --------------------------
                                    BEFORE ME, a Notary Public, in and for said
COUNTY OF
          ------------------------


         County and State, on this day personally appeared known to me to be the
person and officer whose name is subscribed to the foregoing instrument and
acknowledged that the same was the act of the said
______________________________________________, a corporation, and that he
executed the same as the act of such corporation for the purposes and
consideration therein expressed, and in the capacity therein stated.

         In testimony whereof, I have hereunto set my hand and official seal,
at_____________________________, this ______ day of _______________, A.D.,
200___.



                                                  _____________________________
                                                  Notary Public


This instrument prepared by:

Atlas Resources, Inc.
311 Rouser Road
P.O. Box 611
Moon Township, PA 15108


                                   Exhibit B
                                    (Page 2)

                             ADDENDUM NO. __________

                       TO DRILLING AND OPERATING AGREEMENT
                       DATED ___________________ , 200___

THIS ADDENDUM NO. __________ made and entered into this ______ day of
________________, 200___, by and between ATLAS RESOURCES, INC., a Pennsylvania
corporation (hereinafter referred to as "Operator"),

                                       and

ATLAS AMERICA PUBLIC #14-2004 L.P. [ATLAS AMERICA PUBLIC #14-2005(____) L.P.], a
Delaware limited partnership, (hereinafter referred to as the Developer).

                                WITNESSETH THAT:

WHEREAS, Operator and the Developer have entered into a Drilling and Operating
Agreement dated ___________________, 200___, (the "Agreement"), which relates to
the drilling and operating of ________________ (______)wells on the
________________ (______) Initial Well Locations identified on the maps attached
as Exhibits A-l through A-______ to the Agreement, and provides for the
development on the terms and conditions set forth in the Agreement of Additional
Well Locations as the parties may from time to time designate; and

WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer
presently desire to designate ________________ Additional Well Locations
described below to be developed in accordance with the terms and conditions of
the Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained in this
Addendum and intending to be legally bound, the parties agree as follows:

1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes
Operator to drill, complete (or plug) and operate, on the terms and conditions
set forth in the Agreement and this Addendum No.__________, ________________
additional wells on the ________________ Additional Well Locations described on
Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits
A-______ through A-______.

2. Operator, as Developer's independent contractor, agrees to drill, complete
(or plug) and operate the additional wells on the Additional Well Locations in
accordance with the terms and conditions of the Agreement and further agrees to
begin drilling the first additional well within thirty (30) days after the date
of this Addendum and to begin drilling all the additional wells on or before
March ___, 2005 [March ___, 2006].

3. Developer acknowledges that:

    (a) Operator has furnished Developer with the title opinions identified on
        Exhibit A to this Addendum; and

    (b) such other documents and information which Developer or its counsel
        has requested in order to determine the adequacy of the title to the
        above Additional Well Locations.

The Developer accepts the title to the Additional Well Locations and leased
premises in accordance with the provisions of Section 5 of the Agreement.

 4. The drilling and operation of the additional wells on the Additional Well
Locations shall be in accordance with and subject to the terms and conditions
set forth in the Agreement as supplemented by this Addendum No. __________ and
except as previously supplemented, all terms and conditions of the Agreement
shall remain in full force and effect as originally written.

 5. This Addendum No. __________ shall be legally binding on, and shall inure to
the benefit of, the parties and their respective successors and permitted
assigns.

                                    Exhibit C
                                    (Page 1)

WITNESS the due execution of this Addendum on the day and year first above
written.


                                    ATLAS RESOURCES, INC.


                                    By________________________________________



                                    ATLAS AMERICA PUBLIC #14-2004 L.P.
                                    [ATLAS AMERICA PUBLIC #14-2005(____) L.P.]

                                    By its Managing General Partner:

                                    ATLAS RESOURCES, INC.


                                    By________________________________________



                                    Exhibit C
                                    (Page 2)



                                   EXHIBIT (B)
                        SPECIAL SUITABILITY REQUIREMENTS
                          AND DISCLOSURES TO INVESTORS



          SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS

If you are a resident of one of the following states, then you must meet that
state's qualification and suitability standards as set forth below.

   SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING LIMITED PARTNER UNITS IN
            CALIFORNIA, MICHIGAN, NEW HAMPSHIRE, NEW JERSEY AND NORTH CAROLINA.

I.    If you are a resident of CALIFORNIA or NEW JERSEY and you purchase limited
      partners units, then you must meet any one of the following special
      suitability requirements:

         o        a net worth of not less than $250,000, exclusive of home, home
                  furnishings and automobiles, and expect to have gross income
                  in the current year of $65,000 or more; or

         o        a net worth of not less than $500,000, exclusive of home, home
                  furnishings and automobiles; or

         o        a net worth of not less than $1 million; or

         o        expected gross income in the current tax year of not less than
                  $200,000.

II.   If you are a resident of MICHIGAN OR NORTH CAROLINA and you purchase
      limited partner units, then you must meet any one of the following special
      suitability requirements:

         o        a net worth of not less than $225,000, exclusive of home, home
                  furnishings and automobiles; or

         o        a net worth of not less than $60,000, exclusive of home, home
                  furnishings and automobiles, and estimated CURRENT year
                  taxable income as defined in Section 63 of the Internal
                  Revenue Code of $60,000 or more without regard to an
                  investment in the partnership.

      In addition, if you are a resident of MICHIGAN, then you must not make an
      investment in the partnership in excess of 10% of your net worth,
      exclusive of home, home furnishings and automobiles.

III.  If you are a resident of NEW HAMPSHIRE and you purchase limited partner
      units, then you must meet any one of the following:

         o        a net worth of not less than $250,000, exclusive of home, home
                  furnishings, and automobiles, or

         o        a net worth of not less than $125,000, exclusive of home, home
                  furnishings, and automobiles, and $50,000 of taxable income.

   SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING INVESTOR GENERAL PARTNER
     UNITS IN ALABAMA, ARIZONA, ARKANSAS, CALIFORNIA, INDIANA, IOWA, KANSAS,
        KENTUCKY, MAINE, MASSACHUSETTS, MICHIGAN, MINNESOTA, MISSISSIPPI,
           MISSOURI, NEW HAMPSHIRE, NEW JERSEY, NEW MEXICO, NORTH CAROLINA,
               OHIO, OKLAHOMA, OREGON, PENNSYLVANIA, SOUTH DAKOTA,
                    TENNESSEE, TEXAS, VERMONT, OR WASHINGTON.

I.    If you are a resident of CALIFORNIA or NEW JERSEY and you purchase
      investor general partner units, then you must meet any one of the
      following special suitability requirements:

         o        a net worth of not less than $250,000, exclusive of home, home
                  furnishings and automobiles, and expect to have annual gross
                  income in the current year of $120,000 or more; or

         o        a net worth of not less than $500,000, exclusive of home, home
                  furnishings and automobiles; or

         o        a net worth of not less than $1 million; or

         o        expected gross income in the current year of not less than
                  $200,000.

                                       2

II.   If you are a resident of any of the following states:

         o    ALABAMA;          o    MINNESOTA;           o    PENNSYLVANIA;

         o    ARKANSAS;         o    NORTH CAROLINA;      o    TENNESSEE;

         o    MAINE;            o    OHIO;                o    TEXAS; OR

         o    MASSACHUSETTS;    o    OKLAHOMA;            o    WASHINGTON.

and you purchase investor general partner units, then you must meet any one of
the following special suitability requirements:

         o        an individual or joint net worth with your spouse of $225,000
                  or more, without regard to the investment in the partnership,
                  exclusive of home, home furnishings and automobiles, and A
                  COMBINED GROSS INCOME OF $100,000 OR MORE FOR THE CURRENT YEAR
                  AND FOR THE TWO PREVIOUS YEARS; or

         o        an individual or joint net worth with your spouse in excess of
                  $1 million, inclusive of home, home furnishings and
                  automobiles; or

         o        an individual or joint net worth with your spouse in excess of
                  $500,000, exclusive of home, home furnishings and automobiles;
                  or

         o        a combined "gross income" as defined in Section 61 of the
                  Internal Revenue Code of 1986, as amended, in excess of
                  $200,000 in the current year and the two previous years.

III.  If you are a resident of any of the following states:

         o    ARIZONA;          o    KENTUCKY;            o    NEW MEXICO;

         o    INDIANA;          o    MICHIGAN;            o    OREGON;

         o    IOWA;             o    MISSISSIPPI;         o    SOUTH DAKOTA; OR

         o    KANSAS;           o    MISSOURI;            o    VERMONT;

and you purchase investor general partner units, then you must meet any one of
the following special suitability requirements:

         o        an individual or joint net worth with your spouse of $225,000
                  or more, without regard to the investment in the partnership,
                  exclusive of home, home furnishings and automobiles, AND A
                  COMBINED "TAXABLE INCOME" OF $60,000 OR MORE FOR THE PREVIOUS
                  YEAR AND EXPECT TO HAVE A COMBINED "TAXABLE INCOME" OF $60,000
                  OR MORE FOR THE CURRENT YEAR AND FOR THE SUCCEEDING YEAR; or

         o        an individual or joint net worth with your spouse in excess of
                  $1 million, inclusive of home, home furnishings and
                  automobiles; or

         o        an individual or joint net worth with your spouse in excess of
                  $500,000, exclusive of home, home furnishings and automobiles;
                  or

         o        a combined "gross income" as defined in Section 61 of the
                  Internal Revenue Code of 1986, as amended, in excess of
                  $200,000 in the current year and the two previous years.

IV.   In addition, if you are a resident of any of the following states:

         o    IOWA;                            o    OHIO; OR

         o    MICHIGAN;                        o    PENNSYLVANIA;

                                       3

then you must not make an investment in the partnership in excess of 10% of your
net worth, exclusive of home, furnishings and automobiles.

Also, if you are a resident of KANSAS, it is recommended by the Office of the
Kansas Securities Commissioner that Kansas investors should limit their
investment in the Program and substantially similar programs to no more than 10%
of their net worth, excluding home, furnishings and automobiles.


V.   If you are a resident of NEW HAMPSHIRE and you purchase investor
      general partner units, then you must meet any one of the following
      special suitability requirements:

         o        a net worth of not less than $250,000, exclusive of home, home
                  furnishings, and automobiles, or

         o        have a net worth of not less than $125,000, exclusive of home,
                  home furnishings, and automobiles, and $50,000 of taxable
                  income.

                   SPECIAL REPRESENTATIONS FOR SUBSCRIBERS OF
             CALIFORNIA, MISSOURI, NORTH CAROLINA AND PENNSYLVANIA.

I.    If a resident of CALIFORNIA, I am aware that:

                  IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS
                  SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY
                  CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF
                  THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA,
                  EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES.

As a condition of qualification of the units for sale in the State of
California, the following rule is hereby delivered to each California purchaser.

CALIFORNIA ADMINISTRATIVE CODE, TITLE 10, CH. 3, RULE 260.141.11. RESTRICTION ON
TRANSFER.

         (a)      The issuer of any security upon which a restriction on
                  transfer has been imposed pursuant to Sections 260.102.6,
                  260.141.10 and 260.534 shall cause a copy of this section to
                  be delivered to each issuee or transferee of such security at
                  the time the certificate evidencing the security is delivered
                  to the issuee or transferee.

         (b)      It is unlawful for the holder of any such security to
                  consummate a sale or transfer of such security, or any
                  interest therein, without the prior written consent of the
                  Commissioner (until this condition is removed pursuant to
                  Section 260.141.12 of these rules), except:

                  (i)      to the issuer;

                  (ii)     pursuant to the order or process of any court;

                  (iii)    to any person described in Subdivision (i) of Section
                           25102 of the Code or Section 260.105.14 of these
                           rules;

                  (iv)     to the transferor's ancestors, descendants or spouse,
                           or any custodian or trustee for the account of the
                           transferor's ancestors, descendants or spouse, or to
                           a transferee by a trustee or custodian for the
                           account of the transferee or the transferee's
                           ancestors, descendants or spouse;

                  (v)      to holders of securities of the same class of the
                           same issuer;

                  (vi)     by way of gift or donation inter vivos or on death;

                  (vii)    by or through a broker-dealer licensed under the Code
                           (either acting as such or as a finder) to a resident
                           of a foreign state, territory or country who is
                           neither domiciled in this state to the knowledge of
                           the broker-dealer, nor actually present in this state
                           if the sale of such securities is not in violation of
                           any securities law of the foreign state, territory or
                           country concerned;

                  (viii)   to a broker-dealer licensed under the Code in a
                           principal transaction, or as an underwriter or member
                           of an underwriting syndicate or selling group;

                  (ix)     if the interest sold or transferred is a pledge or
                           other lien given by the purchaser to the seller upon
                           a sale of the security for which the Commissioner's
                           written consent is obtained or under this rule not
                           required;

                                       4

                  (x)      by way of a sale qualified under Sections 25111,
                           25112, 25113 or 25121 of the Code, of the securities
                           to be transferred, provided that no order under
                           Section 25140 or Subdivision (a) of Section 25143 is
                           in effect with respect to such qualification;

                  (xi)     by a corporation or wholly-owned subsidiary of such
                           corporation, or by a wholly-owned subsidiary of a
                           corporation to such corporation;

                  (xii)    by way of an exchange qualified under Sections 25111,
                           25112 or 25113 of the Code, provided that no order
                           under Section 25140 or Subdivision (a) of Section
                           25143 is in effect with respect to such
                           qualification;

                  (xiii)   between residents of foreign states, territories or
                           countries who are neither domiciled nor actually
                           present in this state;

                  (xiv)    to the State Controller pursuant to the Unclaimed
                           Property Law or to the administrator of the unclaimed
                           property law of another state;

                  (xv)     by the State Controller pursuant to the Unclaimed
                           Property Law or by the administrator of the unclaimed
                           property law of another state if, in either such
                           case, such person (i) discloses to potential
                           purchasers at the sale that transfer of the
                           securities is restricted under this rule, (ii)
                           delivers to each purchaser a copy of this rule, and
                           (iii) advises the Commissioner of the name of each
                           purchaser;

                  (xvi)    by a trustee to a successor trustee when such
                           transfer does not involve a change in the beneficial
                           ownership of the securities;

                  (xvii)   by way of an offer and sale of outstanding securities
                           in an issuer transaction that is subject to the
                           qualification requirement of Section 25110 of the
                           Code but exempt from that qualification requirement
                           by subdivision (f) of Section 25102;

                  provided that any such transfer is on the condition that any
                  certificate evidencing the security issued to such transferee
                  shall contain the legend required by this section.

         (c)      The certificates representing all such securities subject to
                  such a restriction on transfer, whether upon initial issuance
                  or upon any transfer thereof, shall bear on their face a
                  legend, prominently stamped or printed thereon in capital
                  letters of not less than 10-point size, reading as follows:

                  "IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS
                  SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY
                  CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF
                  THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA,
                  EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES."

II.   If a resident of MISSOURI, I am aware that:

                  THESE SECURITIES ARE NOT ELIGIBLE FOR ANY TRANSACTIONAL
                  EXEMPTION UNDER THE MISSOURI UNIFORM SECURITIES ACT (SECTION
                  409.402(B), R.S.MO.(1978). UNLESS THESE SECURITIES ARE AGAIN
                  REGISTERED UNDER THE ACT, THEY MAY NOT BE REOFFERED FOR SALE
                  OR RESOLD IN THE STATE OF MISSOURI (SECTION 409.301,
                  R.S.MO.(1978)).

III.  If a resident of NORTH CAROLINA, I am aware that:

                  IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR
                  OWN EXAMINATION OF THE PERSON OR ENTITY CREATING THE
                  SECURITIES AND THE TERMS OF THE OFFERING, INCLUDING THE MERITS
                  AND RISKS INVOLVED. THESE SECURITIES HAVE NOT BEEN RECOMMENDED
                  BY ANY FEDERAL OR STATE SECURITIES COMMISSION OR REGULATORY
                  AUTHORITY. FURTHERMORE, THE FOREGOING AUTHORITIES HAVE NOT
                  CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS
                  DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
                  OFFENSE.

IV.   PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than
      10% of the maximum closing amount allowed to a partnership in this
      offering, you are cautioned to carefully evaluate the partnership's
      ability to fully accomplish its stated objectives and inquire as to the
      current dollar volume of partnership subscriptions.

                                       5


TABLE OF CONTENTS
- --------------------------------------------------------------------
                                                                Page
Summary of the Offering...........................................1
Risk Factors......................................................8
Additional Information...........................................17

Forward Looking Statements and Associated
   Risks.........................................................17

Investment Objectives............................................18

Actions to be Taken by Managing General
   Partner to Reduce Risks of Additional
   Payments by Investor General Partners.........................19
Capitalization and Source of Funds and Use of
   Proceeds......................................................21

Compensation.....................................................25

Terms of the Offering............................................31

Prior Activities.................................................39

Management.......................................................49
Management's Discussion and Analysis of Financial Condition,
   Results of Operations, Liquidity and Capital Resources .......55
Proposed Activities..............................................57
Competition, Markets and Regulation..............................70
Participation in Costs and Revenues..............................74
Conflicts of Interest............................................80
Fiduciary Responsibility of the Managing
   General Partner...............................................91
Material Federal Income Tax Consequences.........................92
Summary of Partnership Agreement................................111
Summary of Drilling and Operating Agreement.....................113
Reports to Investors............................................114
Presentment Feature.............................................115
Transferability of Units........................................117
Plan of Distribution............................................118
Sales Material..................................................121
Legal Opinions..................................................122
Experts.........................................................122
Litigation......................................................122
Financial Information Concerning the Managing General Partner
   and Atlas America Public #14-2004 L.P........................123

EXHIBIT (A) - Form of Amended and Restated Certificate and Agreement of Limited
    Partnership for Atlas America Public #14-2004 L.P. [Form of Amended and
    Restated Certificate and Agreement of Limited Partnership for Atlas America
    Public #14-2005(_____) L.P.]
EXHIBIT (I-A) - Form of Managing General Partner
   Signature Page
EXHIBIT (I-B) - Form of Subscription Agreement
EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas America Public
   #14-2004 L.P. [Atlas America Public #14-2005(_____) L.P.]
EXHIBIT (B) - Special Suitability Requirements and
   Disclosures to Investors

No one has been authorized to give any information or make any representations
other than those contained in this prospectus in connection with this offering.
If given or made, you should not rely on such information or representations as
having been authorized by the managing general partner. The delivery of this
prospectus does not imply that its information is correct as of any time after
its date. This prospectus is not an offer to sell these securities in any state
to any person where the offer and sale is not permitted.


- --------------------------------------------------------------------







      --------------------------------------------------------------------




                                  ATLAS AMERICA

                             PUBLIC #14-2004 PROGRAM










                            -----------------------

                                   PROSPECTUS

                            -----------------------












      Until December 31, 2005, all dealers that effect transactions in
      these securities, whether or not participating in this offering, may
      be required to deliver a prospectus. This is in addition to the
      dealers' obligation to deliver a prospectus when acting as
      underwriters and with respect to their unsold allotments or
      subscriptions.


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