PROSPECTUS DATED OCTOBER 27, 2005
ATLAS AMERICA PUBLIC #15-2005 PROGRAM
Up to 19,400 Investor General Partner Units and 19,400 converted Limited Partner Units and up to 600 Limited Partner
Units, which are collectively referred to as the "Units," at $10,000 per Unit
$2 Million (200 Units) Minimum Aggregate Subscriptions
$200,000,000 (20,000 Units) Maximum Aggregate Subscriptions
Atlas America Public #15-2005 Program is a series of up The Offering: In addition to the information in the table below for
to four limited partnerships which will drill primarily not less than 95% of the units (19,000 units), up to 5% of the units
natural gas development wells. See "Terms of the (1,000 units), in the aggregate, may be sold at $8,950 per unit to the
Offering - Subscription to a Partnership," beginning on managing general partner, its officers, directors and affiliates, and
page 35, for a detailed description of the offering of investors who buy units through the officers and directors of the
these limited partnerships. They will be managed by managing general partner; or at $9,300 per unit to registered
Atlas Resources, Inc. of Pittsburgh, Pennsylvania. investment advisors and their clients, and selling agents and their
registered representatives and principals. These discounted prices
If you invest in a partnership, you will not have any reflect certain fees, sales commissions and reimbursements which will
interest in any of the other three partnerships unless not be paid for these sales. (See "Plan of Distribution.") To the
you also make a separate investment in the other extent that units are sold at discounted prices, a partnership's
partnerships. subscription proceeds will be reduced.
The units will be offered on a "best efforts" Total Total
"minimum-maximum" basis. This means the broker/dealers Per Unit Minimum Maximum
must sell at least 200 units and receive subscription -------- ------- -------
proceeds of at least $2 million in order for a
partnership to close, and they must use only their best Public Price $10,000 $2,000,000 $200,000,000
efforts to sell the remaining units in the
partnership. Dealer-manager fee, sales $ 1,050 $ 210,000 $ 21,000,000
commissions, accountable
Subscription proceeds for each partnership will be held reimbursements for permissible
in an interest bearing escrow account until $2 million non-cash compensation, and
has been received. The offering of Atlas America Public bona fide due diligence
#15-2005(A) L.P. will not extend beyond December 31, reimbursements (1)
2005 and the offering of Atlas America Public
#15-2006(B) L.P., Atlas America Public #15-2006(C) L.P. Proceeds to partnership $10,000 $2,000,000 $200,000,000
and Atlas America Public #15-2006(D) L.P. will not
extend beyond December 31, 2006. If the minimum ------
subscription proceeds are not received by a (1) These fees, sales commissions and reimbursements will be paid by the
partnership's offering termination date, then your managing general partner as a part of its capital contribution and
subscription will be promptly returned to you from the not from subscription proceeds.
escrow account with interest and without deduction for
any fees.
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, which makes it extremely difficult for you to sell your 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 month.
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
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
Five Year-50% 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............................................10
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...........................................12
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
Increases in the Costs of the Wells May Adversely
Affect Your Return.................................................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.......................................13
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....................14
The Partnerships in This Program and Other
Partnerships Sponsored by the Managing General
Partner May Compete With Each Other for
Prospects, Equipment, Contractors, and
Personnel..........................................................14
Managing General Partner's Subordination is Not a
Guarantee of the Return of Any of Your Investment..................14
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..........................15
The Intended Monthly Distributions to Investors
May be Reduced or Delayed..........................................15
There Are Conflicts of Interest Between the
Managing General Partner and the Investors.........................15
The Presentment Obligation May Not Be Funded
and the Presentment Price May Not Reflect Full
Value..............................................................16
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................................................17
Lack of Independent Underwriter May Reduce Due
Diligence Investigation of the Partnerships and
the Managing General Partner.......................................17
A Lengthy Offering Period May Result in Delays in
the Investment of Your Subscription and Any
Cash Distributions From the Partnership to You.....................17
Your Interests May Be Diluted.........................................17
Tax Risks................................................................18
Your Deduction for Intangible Drilling Costs May
Be Limited for Purposes of the Alternative
Minimum Tax........................................................18
Limited Partners Need Passive Income to Use Their
Deduction for Intangible Drilling Costs............................18
You May Owe Taxes in Excess of Your Cash
Distributions from Your Partnership................................18
Investment Interest Deductions of Investor
General Partners May Be Limited....................................19
Your Tax Benefits from an Investment in a
Partnership Are Not Contractually Protected........................19
An IRS Audit of Your Partnership May Result in
an IRS Audit of Your Personal Federal Income
Tax Returns........................................................19
Each Partnership's Deductions May be Challenged
by the IRS.........................................................19
Changes in the Law May Reduce Your Tax
Benefits From an Investment in a Partnership.......................19
It May Be Many Years Before You Receive Any
Marginal Well Production Credits, If Ever..........................20
ADDITIONAL INFORMATION.......................................................20
FORWARD LOOKING STATEMENTS AND
ASSOCIATED RISKS.............................................................20
INVESTMENT OBJECTIVES........................................................21
ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS........................................22
CAPITALIZATION AND SOURCE OF FUNDS
AND USE OF PROCEEDS..........................................................24
Source of Funds..........................................................24
Use of Proceeds..........................................................25
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TABLE OF CONTENTS
COMPENSATION.................................................................28
Natural Gas and Oil Revenues.............................................29
Lease Costs..............................................................29
Drilling Contracts.......................................................29
Per Well Charges.........................................................31
Gathering Fees...........................................................32
Dealer-Manager Fees......................................................33
Interest and Other Compensation..........................................34
Estimate of Administrative Costs and Direct Costs to be
Borne by the Partnerships.............................................34
TERMS OF THE OFFERING........................................................35
Subscription to a Partnership............................................35
Partnership Closings and Escrow..........................................36
Acceptance of Subscriptions..............................................37
Suitability Standards....................................................38
In General............................................................38
General Suitability Requirements for Purchasers of
Limited Partner Units..............................................38
Special Suitability Requirements for Purchasers of
Limited Partner Units..............................................39
General Suitability Requirements for Purchasers of
Investor General Partner Units.....................................40
Special Suitability Requirements for Purchasers of
Investor General Partner Units.....................................40
Fiduciary Accounts....................................................42
PRIOR ACTIVITIES.............................................................42
MANAGEMENT...................................................................53
Managing General Partner and Operator....................................53
Officers, Directors and Other Key Personnel..............................54
Atlas America, Inc., a Delaware Company..................................57
Organizational Diagram and Security Ownership of
Beneficial Owners.....................................................58
Remuneration.............................................................58
Code of Business Conduct and Ethics......................................58
Transactions with Management and Affiliates..............................59
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION, RESULTS OF OPERATIONS,
LIQUIDITY AND CAPITAL RESOURCES..............................................59
PROPOSED ACTIVITIES..........................................................60
Overview of Drilling Activities..........................................60
Primary Areas of Operations..............................................61
Mississippian/Upper Devonian Sandstone
Reservoirs, Fayette County, Pennsylvania...........................63
Clinton/Medina Geological Formation in Western
Pennsylvania.......................................................63
Upper Devonian Sandstone Reservoirs, Armstrong
County, Pennsylvania...............................................64
Upper Devonian Sandstone Reservoirs in McKean
County, Pennsylvania...............................................64
Mississippian Carbonate and Devonian Shale
Reservoirs in Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee................................64
Secondary Areas of Operations............................................65
Clinton/Medina Geological Formation
in Western New York................................................65
Clinton/Medina Geological Formation
in Southern Ohio...................................................65
Acquisition of Leases....................................................66
Deep Drilling Rights Retained by Managing General
Partner............................................................67
Interests of Parties.....................................................67
Primary Areas............................................................68
Clinton/Medina Geological Formation
in Western Pennsylvania and
Mississippian/Upper Devonian Sandstone
Reservoirs in Fayette, Greene and
Westmoreland Counties, Pennsylvania and
Upper Devonian Sandstone Reservoirs in
McKean County, Pennsylvania........................................68
Upper Devonian Sandstone Reservoirs in
Armstrong and Indiana Counties, Pennsylvania.......................69
Mississippian Carbonate and Devonian Shale
Reservoirs in Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee................................69
Secondary Areas..........................................................69
Title to Properties......................................................69
Drilling and Completion Activities; Operation
of Producing Wells....................................................70
Sale of Natural Gas and Oil Production...................................71
Policy of Treating All Wells Equally in a
Geographic Area....................................................71
Gathering of Natural Gas..............................................71
Natural Gas Contracts.................................................72
Marketing of Natural Gas Production from Wells in
Other Areas of the United States......................................73
Crude Oil................................................................73
Insurance................................................................74
Use of Consultants and Subcontractors....................................74
COMPETITION, MARKETS AND REGULATION..........................................74
Natural Gas Regulation...................................................74
Crude Oil Regulation.....................................................75
Competition and Markets..................................................75
State Regulations........................................................77
Environmental Regulation.................................................77
Proposed Regulation......................................................78
PARTICIPATION IN COSTS AND REVENUES..........................................78
In General...............................................................78
Costs....................................................................78
Revenues.................................................................80
Subordination of Portion of Managing General
Partner's Net Revenue Share...........................................81
Table of Participation in Costs and Revenues.............................82
Allocation and Adjustment Among Investors................................83
Distributions............................................................83
Liquidation..............................................................84
CONFLICTS OF INTEREST........................................................84
In General...............................................................84
Conflicts Regarding Transactions with the Managing
General Partner and its Affiliates....................................85
Conflict Regarding the Drilling and Operating
Agreement.............................................................85
Conflicts Regarding Sharing of Costs and Revenues........................85
Conflicts Regarding Tax Matters Partner..................................86
Conflicts Regarding Other Activities of the Managing
General Partner, the Operator and Their Affiliates....................86
Conflicts Involving the Acquisition of Leases............................87
Conflicts Between Investors and the Managing
General Partner as an Investor........................................91
Lack of Independent Underwriter and Due Diligence
Investigation.........................................................92
Conflicts Concerning Legal Counsel.......................................92
Conflicts Regarding Presentment Feature..................................92
Conflicts Regarding Managing General Partner
Withdrawing or Assigning an Interest..................................92
Conflicts Regarding Order of Pipeline Construction
and Gathering Fees....................................................92
Procedures to Reduce Conflicts of Interest...............................93
ii
TABLE OF CONTENTS
Policy Regarding Roll-Ups................................................94
FIDUCIARY RESPONSIBILITY OF THE
MANAGING GENERAL PARTNER.....................................................95
In General...............................................................95
Limitations on Managing General Partner Liability as
Fiduciary.............................................................96
FEDERAL INCOME TAX CONSEQUENCES..............................................97
Introduction.............................................................97
Disclosures and Limitations on Use of Tax Opinion Letter.................97
Special Counsel's Assumptions............................................98
Managing General Partner's Representations...............................98
Special Counsel's Opinions...............................................99
Summary Discussion of the Federal Income Tax
Consequences of an Investment in a Partnership by a
Typical Investor ("Summary Discussion")..............................103
Introduction............................................................103
Partnership Classification..............................................103
Limitations on Passive Activity Losses and Credits......................103
Publicly Traded Partnership Rules.......................................104
Conversion from Investor General Partner to Limited
Partner..............................................................104
Taxable Year and Method of Accounting...................................105
Business Expenses.......................................................105
Intangible Drilling Costs...............................................105
Drilling Contracts......................................................106
Depletion Allowance.....................................................108
Depreciation and Cost Recovery Deductions...............................109
Marginal Well Production Credits........................................109
Lease Acquisition Costs and Abandonment.................................110
Tax Basis of Units......................................................111
"At Risk" Limitation on Losses..........................................111
Distributions From a Partnership........................................111
Sale of the Properties..................................................112
Disposition of Units....................................................113
Alternative Minimum Tax.................................................113
Limitations on Deduction of Investment Interest.........................115
Allocations.............................................................116
Partnership Borrowings..................................................116
Partnership Organization and Offering Costs.............................116
Tax Elections...........................................................117
Tax Returns and IRS Audits..............................................118
Tax Returns..........................................................118
Profit Motive, IRS Anti-Abuse Rule and Judicial
Doctrines Limitations on Deductions..................................118
Federal Interest and Tax Penalties......................................119
State and Local Taxes...................................................120
Severance and Ad Valorem (Real Estate) Taxes............................121
Social Security Benefits and Self-Employment Tax........................121
Farmouts................................................................121
Foreign Partners........................................................121
Estate and Gift Taxation................................................122
Changes in the Law......................................................122
SUMMARY OF PARTNERSHIP AGREEMENT............................................122
Liability of Limited Partners...........................................122
Amendments..............................................................122
Notice..................................................................123
Voting Rights...........................................................123
Access to Records.......................................................124
Withdrawal of Managing General Partner..................................124
Return of Subscription Proceeds if Funds Are Not
Invested in Twelve Months............................................124
SUMMARY OF DRILLING AND OPERATING
AGREEMENT...................................................................124
TABLE OF CONTENTS
REPORTS TO INVESTORS........................................................125
PRESENTMENT FEATURE.........................................................126
TRANSFERABILITY OF UNITS....................................................128
Restrictions on Transfer Imposed by the Securities
Laws, the Tax Laws and the Partnership
Agreement............................................................128
Conditions to Becoming a Substitute Partner.............................129
PLAN OF DISTRIBUTION........................................................129
Commissions.............................................................129
Indemnification.........................................................132
SALES MATERIAL..............................................................132
LEGAL OPINIONS..............................................................133
EXPERTS.....................................................................134
LITIGATION..................................................................134
FINANCIAL INFORMATION CONCERNING THE
MANAGING GENERAL PARTNER AND ATLAS
AMERICA PUBLIC #15-2005(A) L.P. ............................................134
INDEX TO FINANCIAL STATEMENTS...............................................134
Exhibits
Appendix A Information Regarding Currently Proposed Prospects for Atlas
America Public #15-2005(A) L.P.
Exhibit (A) Form of Amended and Restated Certificate and Agreement of
Limited Partnership for Atlas America Public #15-2005(A) L.P.
[Form of Amended and Restated Certificate and Agreement of
Limited Partnership for Atlas America Public #15-2006(___)
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 #15-2005(A) L.P. [Atlas America Public #15-2006(___)
L.P.]
Exhibit (B) Special Suitability Requirements and Disclosures to Investors
iii
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 #15-2005 Program, which is sometimes referred to in this
prospectus as the "program," consists of up to four 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 in the four partnerships will be offered and sold in a
series beginning with the offering of units in the first partnership, Atlas
America Public #15-2005(A) L.P., in 2005. Units in the last three partnerships
will be offered during 2006. See "Terms of the Offering" for a discussion of the
terms and conditions involved in making an investment in a partnership.
Each partnership in the program 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, western New York and north central
Tennessee 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 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 35 private drilling partnerships and 14 public drilling
partnerships. Atlas Resources also will serve as each partnership's general
drilling contractor and operator and it will supervise the drilling, completing
and operating of the wells to be drilled.
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 The drilling operations of the partnership in which you invest 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 its 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.
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, necessitates a long-term
commitment and makes it extremely difficult for you to sell your units.
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 $200 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 by a partnership, its 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 #15-2005(A) L.P. will drill
the prospects described in "Appendix A - Information Regarding
Currently Proposed Prospects for Atlas America Public #15-2005(A) L.P."
These prospects represent a portion of the wells to be drilled if the
nonbinding targeted maximum 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 the partnerships
designated Atlas America Public #15-2006(___) 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 monthly cash distributions to its investors may be
deferred if revenues are used for partnership operations or reserves.
TERMS OF THE OFFERING
The offering period for the first partnership will begin on the date of this
prospectus. Each partnership will offer a minimum of 200 units, which is $2
million, and the partnerships, in the aggregate, will offer a maximum of 20,000
units which is $200 million. The maximum subscription proceeds for each
partnership will be the lesser of:
2
o $200 million; or
o $200 million less the amount of subscriptions sold in the preceding
partnership or partnerships.
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 in each partnership may be sold to certain investors at
discounted prices 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 each 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 has been formed as a limited
partnership under the Delaware Revised Uniform Limited Partnership Act. 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. After breaking escrow, additional subscription
proceeds may be paid directly to a partnership account for that partnership and
will continue to earn interest until the offering of units in that partnership
terminates. (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 partnerships will not issue certificates for their units, but your ownership
of your unit(s) will be recorded on the partnership's books and records. Also,
the type of unit you buy will not affect the allocation of your partnership's
costs, revenues, and cash distributions among you and its 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 limitations
on losses. For example, if you pay $10,000 for a unit, then generally
you may deduct not less than 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 "Federal Income Tax Consequences - Limitations on Passive Activity
Losses and Credits.")
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 that if:
o the insurance proceeds from any source;
o the managing general partner's indemnification of you and the
other investor general partners; 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 solely because
of your status as general partners of the partnership, 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 will 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 any 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 partnership 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 amount 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 the conversion.
LIMITED PARTNER UNITS.
o TAX EFFECT. If you invest in a partnership as a limited partner, then
your use of your share of the partnership's deduction for intangible
drilling costs will be limited to offsetting your 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 salaries, dividends or
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 net passive income from investments other than
the partnership. However, any portion of your share of the
partnership's deduction for intangible drilling costs which you cannot
use in the year in which you invest, because you do not have sufficient
net passive income in that year, may be carried forward by you and used
to offset your net passive income from the partnership or your other
passive activities, if any, in subsequent tax years. (See "Federal
Income Tax Consequences - Limitations on Passive Activity Losses and
Credits.")
4
o LIABILITY. If you invest in a partnership as a limited partner, then
you will have limited liability for the partnership's liabilities and
obligations. This means that you will not be liable for any partnership
liabilities or obligations beyond the amount of your initial investment
in the partnership and your share of the partnership's 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 three partnerships, in the
aggregate, may not exceed $200 million. The subscription proceeds of one
partnership may be substantially more or less than the subscription proceeds of
the other partnerships. In each partnership, regardless of whether the
partnership receives the minimum or the maximum subscriptions from you and the
other investors:
o 90% of the subscription proceeds will be used to pay 100% of the
intangible drilling costs, as defined above in "- Description of
Units," of drilling and completing the partnership's wells; and
o 10% of the subscription proceeds will be used to pay a portion of the
equipment costs of drilling and completing the partnership's wells.
The managing general partner will contribute all of the leases to each
partnership covering the acreage on which that partnership's wells will be
drilled and pay all of the equipment costs of drilling and completing the
partnership's wells that exceed 10% of the partnership's subscription proceeds.
Thus, the managing general partner will pay the majority of each partnership's
equipment costs. 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 "Federal
Income Tax Consequences - Intangible Drilling Costs.")
FIVE YEAR-50% 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 its other investors with cash distributions equal
to a minimum of 10% of capital, 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 distribution from
operations. To help achieve this investment feature of a 10% return of capital
in each of the first five 12-month periods, the managing general partner will
subordinate up to 50% of its share of partnership net production revenues, which
will be up to between 16% and 20% of total partnership net production revenues,
depending on the amount of the managing general partner's capital contribution
to that partnership, during this subordination period. (See "Participation in
Costs and Revenues - Subordination of Portion of the Managing General Partner's
Net Revenue Share.")
Each partnership's 60-month subordination period will begin with the
partnership's first cash distribution from operations to you and its other
investors. 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.
5
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 (1).........................................................0% 100%
Equipment costs......................................................................(2) (2)
Operating costs, administrative costs, direct costs, and all other costs.............(3) (3)
PARTNERSHIP REVENUES
Interest income......................................................................(4) (4)
Equipment proceeds...................................................................(2) (2)
All other revenues including production revenues..................................(5)(6) (5)(6)
- ----------------
(1) Ninety percent of the subscription proceeds of you and the other
investors in the partnership in which you subscribe will be used to pay
100% of the intangible drilling costs incurred by that partnership in
drilling and completing its wells.
(2) Ten percent of the subscription proceeds of you and the other investors
in the partnership in which you subscribe will be used to pay a portion
of the equipment costs incurred by that partnership in drilling and
completing its wells. All equipment costs in excess of 10% of the
partnership's subscription proceeds will be paid by the managing general
partner. Thus, the managing general partner will pay a majority of each
partnership's equipment costs. Equipment proceeds, if any, will be
credited in the same percentage in which the equipment costs were
charged. Thus, the managing general partner will receive a majority of
any equipment proceeds.
(3) 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 after their economic
reserves have been produced and depleted as described in "Participation
in Costs and Revenues."
(4) 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 distribution 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.
(5) 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 40% of
partnership revenues.
(6) The actual allocation of partnership revenues between the managing
general partner and the investors will vary from the allocation described
in (5) above if a portion of the managing general partner's partnership
net production revenues is subordinated as described above.
The managing general partner will review each partnership's accounts at least
monthly 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 its other investors that the managing general partner does not
believe are necessary for the partnership to retain. (See "Participation in
Costs and Revenues.")
6
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 40% 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 an unaccountable, fixed payment reimbursement of
$15,000 from the investors to the managing general partner for its
general and administrative overhead plus 15%.
o When a partnership's wells 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 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 distributions of the partnership's
net proceeds from the sale of its 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 49 partnerships since 1985,
however, 37 of the 49 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 a 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.")
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 it is likely that they will 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 partnerships. For example, the demand for natural gas
is usually greater in the winter months, because of residential heating
requirements, than in the summer months. This seasonal change in the demand for
natural gas 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 #15-2005(A) 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 its 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 and that of
the managing general partner will be sold to a limited number of
different natural gas purchasers as described in "Proposed Activities -
Sale of Natural Gas and Oil Production." As set forth in "Appendix A -
Information Regarding Currently Proposed Prospects for Atlas America
Public #15-2005(A) L.P.," the managing general partner has identified
five primary areas where it intends to drill each partnership's wells.
The managing general partner anticipates that initially each
partnership's natural gas production in each of the five primary areas
will be sold to a different purchaser. Thus, each partnership will
depend on a limited number of natural gas purchasers. If a partnership
loses a natural gas purchaser in a given area, the partnership may be
unable to locate a new natural gas purchaser in the area which will buy
its natural gas on as favorable terms as the initial purchaser.
Although one of the natural gas purchasers has a 10-year agreement,
which began on April 1, 1999, to buy all of the managing general
partner's and its affiliates' natural gas production, there are various
exceptions to its obligation to buy the natural gas. The most
significant exception for each partnership includes natural gas
produced from Fayette County, Pennsylvania, which is where the managing
general partner anticipates that the majority of each partnership's
prospects will be situated. The majority, if not all, of the natural
gas produced from Fayette County, Pennsylvania, by each partnership
initially will be sold to one purchaser under a natural gas contract
described in "Proposed Activities - Sale of Natural Gas and Oil
Production," which ends March 31, 2007. Of the remaining four primary
areas, there will be a different natural gas purchaser in each area and
natural gas produced from only one of those areas will be sold under
the 10-year agreement referred to above. Also, all of these natural gas
purchase contracts provide that the price paid by the natural gas
purchaser 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, none of the
partnerships will be guaranteed a specific natural gas price, other
than through hedging, and the price a partnership receives for the sale
of its natural gas may decrease in the future because of market
conditions. Although 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.
9
o Partnership revenues will decrease 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 and Anderson, Campbell, Morgan, Scott and Roane Counties,
Tennessee, 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 - Gathering of Natural Gas.")
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.")
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, which may, or may not, cover all of the
additional costs paid by the partnership.
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.
10
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 in a partnership 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 you
are converted to limited partner status, subject to certain exceptions 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;
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 if the managing general partner 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 91% 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.
11
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 most of its other partnerships and will
make this same commitment in future partnerships. (See "Financial Information
Concerning the Managing General Partner and Atlas America Public #15-2005(A)
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 list the units on any exchange.
Also, 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 disposition. (See "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 $200 million. There are no other requirements
regarding the size of a partnership other than the nonbinding targeted maximum
amounts described in "Terms of the Offering - Subscription to a Partnership."
Thus, 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
eight net wells if the minimum subscriptions of $2 million are received, which
is compared with approximately 917 net wells if subscription proceeds of $200
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. See "Proposed
Activities - Acquisition of Leases.") Also, in a large partnership greater
demands will be placed on the managing general partner's management
capabilities.
Also, 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 each partnership's wells will be paid by
the managing general partner. However, all of the intangible drilling costs of a
partnership's wells will be charged to you and the other investors in that
partnership. If a partnership incurs a cost overrun for the intangible drilling
costs of a well or wells, then the managing general partner anticipates that it
would use the partnership's 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.
12
INCREASES IN THE COSTS OF THE WELLS MAY ADVERSELY AFFECT YOUR RETURN. The
increase in natural gas and oil prices over the last several years has increased
the demand for drilling rigs and other related equipment, and the costs of
drilling and completing natural gas and oil wells also have increased.
Additionally, the managing general partner and its affiliates have experienced
an increase in the cost of tubular steel used in drilling the wells as a result
of rising steel prices. Because each partnership's wells will be drilled on a
cost plus basis as described in "Compensation - Drilling Contracts," these
increased costs will increase the cost to drill and complete each partnership's
wells. Also, the reduced availability of drilling rigs and other related
equipment may make it more difficult to drill a partnership's wells in a timely
manner or to comply with the prepaid intangible drilling costs rules discussed
in "Federal Income Tax Consequences - Drilling Contracts."
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 #15-2005(A) L.P. will drill the prospects described in "Appendix A -
Information Regarding Currently Proposed Prospects for Atlas America Public
#15-2005(A) 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 the partnerships designated Atlas America Public
#15-2006(___) 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:
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 by 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.
In addition, 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. If multiple wells are drilled
in one area at approximately the same time, then there is a greater risk that
two or more of the wells will be 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 then 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.
13
This risk is further increased with respect to wells for which the drilling and
completing costs are prepaid in one year, and the drilling of the wells must
begin within the first 90 days of the immediately following year under the tax
laws associated with deducting the intangible drilling costs of the prepaid
wells in the year in which the prepayment is made, rather than the year in which
the wells are drilled. For example, potential bad weather conditions during the
first 90 days of the following year could delay beginning the drilling of one or
more prepaid wells beyond the 90 day time limit under the tax laws. This would
have a greater adverse effect on a partnership's deduction for prepaid
intangible drilling costs if the managing general partner is required to begin
drilling many wells at the same time, rather than only a few wells. Also, "frost
laws" prohibit drilling rigs and other heavy equipment from using certain roads
during the winter, which may delay beginning the drilling of the wells within
the 90 day time limit under the tax laws. In addition, there could be shortages
of drilling rigs, equipment, supplies and personnel during this time period.
(See "Federal Income Tax Consequences - Drilling Contracts" regarding prepaid
wells and the 90 day time constraint.)
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 well proposed to be drilled. However, the
data set forth in "Appendix A - Information Concerning Currently Proposed Wells
for Atlas America Public #15-2005(A) L.P." for the proposed wells in
Pennsylvania may not show all of the surrounding 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, are not 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 IN 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 in this program are attempting to acquire prospects.
This may make it more difficult to complete the prospect acquisition and
drilling activities for the partnerships in 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 distribution 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.")
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 40%, 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.
14
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 they must comply with 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 MONTHLY DISTRIBUTIONS TO INVESTORS MAY BE REDUCED OR DELAYED. Cash
distributions to you and the other investors may not be paid each month.
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;
o the managing general partner must monitor and enforce, on behalf of the
partnerships, its own compliance with the drilling and operating
agreement and the partnership 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;
15
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 in this program, 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 partnerships drilling
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 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 the offering of units in 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 be less than the purchase price of your units.
However, 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.")
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 on you 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.")
16
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 #15-2005(A) 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 bona fide due diligence expenses for certain due diligence
investigations conducted by the selling agents which it will reallow to the
selling agents. However, Anthem Securities' 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 a portion of the partnership's wells have been
drilled, completed and placed on-line for the delivery and sale of natural gas
and/or oil, and payment has been received from the purchaser of the natural gas
and/or oil. Also, distributions of a partnership's net production revenues will
be made only after payment of the managing general partner's fees and expenses
and only if there is sufficient cash available in the managing general partner's
discretion. See "Terms of the Offering" for a discussion of the procedures
involved in the offering of the units and the formation of a partnership.
YOUR INTERESTS MAY BE DILUTED. The equity interests of you and the other
investors in a partnership may be diluted. You and the other investors will
share in a partnership's production revenues from all of its wells in proportion
to your respective number of units, based on $10,000 per unit, regardless of:
o when you subscribe;
o which wells are drilled with your subscription proceeds; or
o the actual subscription price you paid for your units as described
below.
Because the drilling results of the wells drilled with the subscription proceeds
in your closing may be better than the drilling results of wells drilled with
subscription proceeds from your partnership's other closings, the value of your
units could be diluted when compared to what their value would have been if the
other units had not been sold and the other wells had not been drilled.
Also, some investors, including the managing general partner and its officers
and directors as described in "Plan of Distribution," may buy up to 5% of the
units in each partnership at discounted prices because the dealer-manager fee,
the sales commission, the reimbursement for bona fide due diligence expenses
and/or the accountable reimbursement for permissible non-cash compensation, will
not be paid for these sales. These discounted prices will reduce the net amount
of the subscription proceeds available to a partnership to drill wells. (See "-
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.") In addition, all of the investors in each partnership will share in
the partnership's production revenues with the managing general partner, based
on each investor's number of units purchased, rather than the purchase price
paid by the investor for his units. Thus, investors who pay discounted prices
for their units will receive higher returns on their investments in a
partnership as compared to investors who pay the entire $10,000 per unit.
17
TAX RISKS
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 in the year in which you invest in an
amount equal to 90% of the subscription price you pay for your units. Under
current tax law, however, your alternative minimum taxable income in the year in
which you invest cannot be reduced by more than 40% by your deduction for
intangible drilling costs. (See "Federal Income Tax Consequences - Alternative
Minimum Tax.")
LIMITED PARTNERS NEED PASSIVE INCOME TO USE THEIR DEDUCTION FOR INTANGIBLE
DRILLING COSTS. If you invest in a partnership as a limited partner (except as
discussed below), your share of the partnership's deduction for intangible
drilling costs in the year in which you invest will be a passive loss which
cannot be used to offset "active" income, such as salary and bonuses, or
portfolio income, such as dividends and interest income. Thus, you may not have
enough passive income from the partnership or net passive income from your other
passive activities, if any, in the year in which you invest, to offset a portion
or all of your passive deduction for intangible drilling costs in the year in
which you invest. However, any unused passive loss from intangible drilling
costs may be carried forward by you to offset your passive income in subsequent
taxable years. Also, except as described below, the passive activity limitations
on your share of the partnership's deduction for intangible drilling costs in
the year in which you invest do not apply to you if you invest in the
partnership as a limited partner and you are a C corporation which:
o is not a personal service corporation or a closely held corporation;
o is a personal service corporation in which employee-owners hold 10% (by
value) or less of the stock, but is not a closely held corporation; or
o is a closely held corporation (i.e., five or fewer individuals own more
than 50% (by value) of the stock), but is not a personal service
corporation in which employee-owners own more than 10% (by value) of
the stock, in which case you may use your passive losses to offset your
net active income (calculated without regard to your passive activity
income and losses or portfolio income and losses).
(See "Federal Income Tax Consequences - Limitations on Passive Activity Losses
and Credits.")
YOU MAY OWE TAXES IN EXCESS OF YOUR CASH DISTRIBUTIONS FROM YOUR PARTNERSHIP.
You may become subject to income tax liability for partnership income in excess
of the cash and any marginal well production credits you receive from the
partnership in which you invest. For example:
o if the partnership borrows money, your share of partnership revenues
used to pay principal on the loan will be included in your income from
the partnership and will not be deductible;
o income from sales of natural gas and oil may be included in your income
from the partnership in one tax year, although payment is not actually
received by the partnership and, thus, cannot be distributed to you,
until the next tax year;
o if there is a deficit in your capital account, the partnership may
allocate income or gain to you even though you do not receive a
corresponding distribution of partnership revenues;
o the partnership's revenues may be expended by the managing general
partner for nondeductible costs or retained in the partnership to
establish a reserve for future estimated costs, including a reserve for
the estimated costs of eventually plugging and abandoning the wells,
which will increase your share of the partnership's income without a
corresponding cash distribution to you; and
o the taxable disposition of the partnership's property or your units may
result in income tax liability to you in excess of the cash you receive
from the transaction.
18
INVESTMENT INTEREST DEDUCTIONS OF INVESTOR GENERAL PARTNERS MAY BE LIMITED. If
you invest in a partnership as an investor general partner, your share of the
partnership's deduction for intangible drilling costs will reduce your
investment income and may reduce the amount of your deductible investment
interest expense, if any.
YOUR TAX BENEFITS FROM AN INVESTMENT IN A PARTNERSHIP ARE NOT CONTRACTUALLY
PROTECTED. An investment in a partnership does not give you any contractual
protection against the possibility that part or all of the intended tax benefits
of your investment will be disallowed by the IRS. No one provides any insurance,
tax indemnity or similar agreement for the tax treatment of your investment in a
partnership. You have no right to rescind your investment in the partnership or
to receive a refund of any of your investment in the partnership if a portion or
all of the intended tax consequences of your investment in the partnership are
ultimately disallowed by the IRS or the courts. Also, none of the fees paid by
the partnerships to the managing general partner, its affiliates or independent
third-parties (including special counsel which issued the tax opinion letter)
are refundable or contingent on whether the intended tax consequences of your
investment in a partnership are ultimately sustained if challenged by the IRS.
AN IRS AUDIT OF YOUR PARTNERSHIP MAY RESULT IN AN IRS AUDIT OF YOUR PERSONAL
FEDERAL INCOME TAX RETURNS. The IRS may audit each partnership's federal
information income tax returns, particularly since each partnership's investors
will receive a deduction equal to not less than 90% of their investment amount
in the year in which they invest, which includes their respective deductions for
intangible drilling costs. If the partnership in which you invest is audited,
the IRS also may audit your personal federal income tax returns, including prior
years' returns and items which are unrelated to the partnership. (See "Federal
Income Tax Consequences - Penalties and Interest.")
EACH PARTNERSHIP'S DEDUCTIONS MAY BE CHALLENGED BY THE IRS. If the IRS audits a
partnership, it may challenge the amount of the partnership's deductions and the
taxable year in which the deductions were claimed, including the deductions for
intangible drilling costs and depreciation. Any adjustments made by the IRS to
the federal information income tax returns of the partnership in which you
invest could lead to adjustments on your personal federal income tax returns and
could reduce the amount of your deductions from the partnership in the year in
which you invest in the partnership and subsequent tax years. The IRS also could
seek to recharacterize a portion of the partnership's intangible drilling costs
for drilling and completing its wells as some other type of expense, such as
lease costs or equipment costs, which would reduce or defer your share of the
partnership's deductions for those costs. (See "Federal Income Tax Consequences
- - Business Expenses," "- Depreciation and Cost Recovery Deductions," and "-
Drilling Contracts.")
In addition, depending primarily on when its subscription proceeds are received,
it is possible that each partnership may prepay in the year in which its units
are sold either none, some, or all of its intangible drilling costs for wells
the drilling of which will not begin until the next taxable year. In that event,
you will not receive a deduction in the year in which you invest in a
partnership for your share of the partnership's prepaid intangible drilling
costs for those wells unless the drilling of the prepaid wells begins on or
before the 90th day following the close of the partnership's taxable year in
which the prepayment was made. Under the drilling and operating agreement, the
drilling of all of each partnership's prepaid wells, if any, will be required to
begin within that 90 day time period. However, the drilling of any partnership
well may be delayed due to circumstances beyond the control of the managing
general partner, acting as general drilling contractor, without liability to the
managing general partner. If for any reason the drilling of a prepaid
partnership well does not begin within the required 90 day time period, your
deduction for prepaid intangible drilling costs for that well must be claimed
for the tax year in which the well is actually drilled, instead of the tax year
in which you invested in the partnership and the intangible drilling costs were
prepaid. Also, there is a greater risk that the IRS will attempt to defer your
share of the partnership's deduction for intangible drilling costs from the year
in which you invest in the partnership to the subsequent year in which the well
is actually drilled if third-parties are participating with the partnership in
drilling those prepaid wells, because under their agreements with the managing
general partner or its affiliates the third-party working interest owners will
not be required to prepay their share of the costs of drilling and completing
the wells. (See "Federal Income Tax Consequences - Drilling Contracts.")
19
CHANGES IN THE LAW MAY REDUCE YOUR TAX BENEFITS FROM AN INVESTMENT IN A
PARTNERSHIP. Your tax benefits from an investment in a partnership may be
affected by changes in the tax laws. For example, the top four federal income
tax brackets for individuals were reduced in 2003, 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 the partnership's deductions for intangible drilling costs, depletion,
and depreciation, and its marginal well production credits, if any. However, the
federal income tax rates described above could be changed again, even before
January 1, 2011, and other changes in the tax laws could be made which would
affect your tax benefits from an investment in a partnership.
IT MAY BE MANY YEARS BEFORE YOU RECEIVE ANY MARGINAL WELL PRODUCTION CREDITS, IF
EVER. Beginning in 2005, there is a federal tax credit for the sale of qualified
marginal natural gas and oil production. Although the managing general partner
anticipates that each partnership's natural gas and oil production will be
qualified production for purposes of this tax credit, any natural gas and oil
production sold by Atlas America Public #15-2005(A) L.P. in 2005 will be sold at
prices above the applicable reference prices for 2004 at which the marginal well
production credit is reduced to zero. In addition, depending primarily on market
prices for natural gas and oil, which are volatile, you may not receive any
marginal well production credits from any partnership in which you invest for
many years, if ever. (See "Federal Income Tax Consequences - Marginal Well
Production Credits.")
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
its 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," "will" and
"expects" are intended to identify forward-looking statements. These
forward-looking statements include such things as:
o investment objectives;
o references to future success in a partnership's drilling and marketing
activities;
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 and the managing general partner,
including, but not limited to:
20
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 the price of natural gas and oil, which may
decrease.
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 monthly cash distributions to you from the partnership in which
you invest until the wells are depleted, with a minimum annual return
of capital 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 monthly cash distributions approximately eight months after
the offering period for the partnership ends; however, it may take up
to 12 months before all of the wells in that partnership have been
drilled and completed and are on-line for the sale of their natural gas
or oil production. Also, see "Participation in Costs and Revenues -
Subordination of Portion of Managing General Partner's Net Revenue
Share" for a discussion of the subordination feature. The partnerships
currently do not hold any interests in any prospects on which the wells
will be drilled.
o Obtain 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 limitations on losses 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 for intangible drilling
costs of $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; or
o passive net income from your other passive activity investments,
if any, and passive income from the partnership in the year you
invest, if any, if you invest as a limited partner in a
partnership.
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.
21
o Offset a portion of any gross production income generated by your
partnership with tax deductions from percentage depletion, which is 15%
in 2005. 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 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 over the cost recovery period totaling
$1,000 per unit 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. Also, if wells in
the partnership are drilled and completed and placed in service in the
year you invest, you will begin receiving the depreciation deductions
discussed above which, to the extent they exceed your share of your
partnership's income, if any, in a taxable year, will reduce your net
earnings from self-employment in the year you invest and in your
subsequent tax years during the seven-year cost recovery period.
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.
22
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 a 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.
23
The insurance also 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 it may
be unsuccessful if the coverage becomes unavailable or too expensive.
If you are an investor general partner and there is going to be a
material adverse change in your partnership's insurance coverage, which
the managing general partner does not anticipate, then the managing
general partner will notify you at least 30 days before the effective
date of the change. You will then have the right to convert your units
into limited partner units before the change in insurance coverage 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 all of the
wells will be drilled and completed no more than 12 months after a
partnership closes, and the conversion will then follow.
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 amount 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 and 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' subscription
proceeds 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. (See "Federal
Income Tax Consequences - Tax Basis of Units" and "- `At Risk'
Limitation on 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
not exceed $200 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. (See "Terms of the Offering - Subscription to a Partnership.")
24
On completion of the offering of units in 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 $200 million if 20,000 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 $666,667 if 200 units are sold; and
o not less than $66,666,667 if 20,000 units are sold.
Thus, the total amount available to a partnership will be not less than
$2,666,667 if 200 units are sold ranging to not less than $266,666,667 if 20,000
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 also
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 will be used
by the partnership in which you invest as follows:
o 90% of the subscription proceeds will be used to pay 100% of the
intangible drilling costs of drilling and completing the partnership's
wells; and
o 10% of the subscription proceeds will be used to pay a portion of the
equipment costs of drilling and completing the partnership's wells.
The managing general partner will contribute all of the leases to each
partnership covering the acreage on which the partnership's wells will be
drilled, and pay all of the equipment costs of drilling and completing the
partnership's wells that exceed 10% of the partnership's subscription proceeds.
Thus, the managing general partner will pay the majority of each partnership's
equipment costs. 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."
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 in part on the managing general partner's
estimate of its capital contribution to a partnership based on the applicable
number of units sold as shown in the table. The managing general partner's
estimated capital contribution shown in the tables includes its credit for
organization and offering costs and contributing the leases, and exceeds in each
case its required capital contribution of not less than 25% of all capital
contributions for a partnership. 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% reimbursement for permissible
non-cash compensation, and the up to .5% reimbursement for bona fide due
diligence expenses. A portion of these payments and reimbursements, including
all of the up to .5% reimbursement for bona fide 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.
25
The tables are presented based on:
o the sale of 200 units ($2 million), which is the minimum number of
units for each partnership; and
o the sale of 20,000 units, which is the maximum number of units, in the
aggregate, for all four 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 20,000 UNITS
NATURE OF PAYMENT UNITS 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 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% $180,000,000 90%
Equipment costs (2).................................................... $ 200,000 10% $20,000,000 10%
Leases................................................................. - 0 - - 0 - - 0 - - 0 -
---------- ----- ------------ -----
TOTAL INVESTOR CAPITAL................................................. $2,000,000 100% $200,000,000 100%
========== ===== ============ =====
- --------------
(1) The percentage is based on total investor subscription proceeds, and
excludes the managing general partner's estimate of its capital
contribution in the "- Managing General Partner Capital" table below.
(2) Ninety percent of the subscription proceeds provided by you and the other
investors to each partnership will be used to pay 100% of the
partnership's intangible drilling costs. Ten percent of the subscription
proceeds provided by you and the other investors to each partnership will
be used to pay a portion of the partnership's equipment costs. (See
"Participation in Costs and Revenues.") The managing general partner will
pay all of the remaining equipment costs of each partnership, and its
share of each partnership's equipment costs as set forth 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 each partnership's
primary areas as discussed in "Compensation - Drilling Contracts."
26
MANAGING GENERAL PARTNER CAPITAL
200 20,000 UNITS
NATURE OF PAYMENT UNITS 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 due diligence expenses (2)................................... $210,000 22.72% $21,000,000 22.11%
Organization costs (2)................................................. $ 90,000 9.73% $ 9,000,000 9.49%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs.............................................. - 0 - - 0 - - 0 - - 0 -
Equipment costs (3).................................................... $557,100 60.27% $57,245,732 60.28%
Leases (4)............................................................. $ 67,288 7.28% $ 7,712,887 8.12%
-------- ------ ----------- ------
TOTAL MANAGING GENERAL PARTNER CAPITAL................................. $924,388 100% $94,958,619 100%
======== ====== =========== ======
- -------------
(1) The percentage is based on the managing general partner's estimate of its
capital contribution, and excludes the total investors' subscription
proceeds set forth in the "- Investor Capital" table above.
(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 equipment 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 $8,411 per prospect. 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 with the subscription proceeds available as set forth in the
table. The actual number of net wells drilled by the partnerships is
likely to vary from the managing general partner's estimate, based
primarily on where the wells are drilled and the actual costs of the
wells. Also, 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.
27
TOTAL PARTNERSHIP CAPITAL
200 20,000 UNITS
NATURE OF PAYMENT UNITS 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 due diligence expenses (2)................................... $ 210,000 7.18% $ 21,000,000 7.12%
Organization costs (2)................................................. $ 90,000 3.07% $ 9,000,000 3.05%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs (3).......................................... $1,800,000 61.55% $180,000,000 61.03%
Equipment costs (3).................................................... $ 757,100 25.90% $ 77,245,732 26.19%
Leases (4)............................................................. $ 67,288 2.30% $ 7,712,887 2.61%
---------- ------ ------------ ------
TOTAL PARTNERSHIP CAPITAL.............................................. $2,924,388 100% $294,958,619 100%
========== ====== ============ ======
- ---------------
(1) The percentage is based on total investor subscription proceeds in the "-
Investor Capital Table" above, and the managing general partner's
estimate of its capital contributions in the "- Managing General Partner
Capital" table above.
(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" and "Participation in Costs and
Revenues." The equipment costs will vary depending on the actual
equipment costs of drilling and completing the wells, but 90% of the
subscription proceeds provided by you and the other investors will be
used to pay intangible drilling costs and 10% will be used to pay
equipment 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
that partnership's wells will be drilled as set forth in footnote (4) to
the "- Managing General Partner Capital" table above.
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 eight gross
and net wells will be drilled if the minimum required subscription proceeds of
$2 million are received by a partnership, and approximately 960 gross wells,
which will be approximately 917 net wells, will be drilled, in the aggregate, if
subscription proceeds of $200 million are received by a partnership or 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.")
28
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 40% 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 35% of the total partnership capital contributions and the investors
contribute 65% of the total partnership capital contributions, then the managing
general partner will receive 40% of the partnership revenues, not 42%, because
its revenue share cannot exceed 40% of partnership revenues, and the investors
will receive 60% 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.
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 $8,411 per prospect assuming a partnership acquires 100% of the
working interest in the prospect. From time to time, however, 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 $67,288 if $2 million is received, which is eight net wells times
$8,411 per prospect; and
o $7,712,887 if $200 million is received, which is 917 net wells times
$8,411 per prospect.
Drilling a partnership's wells also may 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.
29
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 an unaccountable fixed payment reimbursement to the managing general
partner for the investors' share of its general and administrative overhead of
$15,000 per well 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 2003 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 2003.
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 and investors' share of its
general and administrative overhead of $15,000 per well 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.
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 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 natural 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 paid to the managing general partner for drilling and completing a
partnership well will be proportionately reduced to the extent the partnership
acquires less than 100% of the working interest in the prospect. In addition,
the amount of compensation that the managing general partner could earn as a
result of these arrangements depends on many other factors as well, 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 $200 million are received, the
managing general partner anticipates that the partnerships' weighted average
cost of drilling and completing approximately 917 net wells, excluding lease
costs, will be approximately $280,486 per net well, which includes the
unaccountable, fixed payment reimbursement of $15,000 per well to the managing
general partner for the investors' share of its general and administrative
overhead and the 15% premium. This estimate also was based on the managing
general partner's estimate of:
o the number of wells that will be drilled in each area by the
partnerships;
o the percentage of working interest that the partnerships will acquire
in the prospects in each area; and
o the estimated drilling and completion costs of the wells to be drilled
by the partnerships, which are different for wells in each area based
primarily on different depths and completion methods.
30
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 and for
the partnerships separately and as a whole.
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 $28,444 per net well with respect to the intangible
drilling costs and the portion of equipment costs paid by you and the other
investors. Also, the managing general partner anticipates that the partnerships
will acquire less than 100% of the working interest in some of their respective
prospects. 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
unaccountable, fixed payment reimbursement for general and administrative
overhead of $15,000 and profit of 15% (approximately $28,444) for one net well,
which totals $43,444, will be:
o $347,522 if $2 million is received, which is eight net wells times
$43,444; and
o $39,838,148 if $200 million is received, which is 917 net wells times
$43,444.
The managing general partner's estimated weighted average cost of $280,486 for
one net well as discussed above consists of:
o intangible drilling costs of approximately $196,262 (70%); and
o equipment costs of approximately $84,224 (30%).
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
$350,000 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 fee covers 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;
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o reading meters, recording production, pumping, maintaining appropriate
books and records; and
o preparing reports to the partnership and to 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 $27,360 if $2 million is received, which is eight net wells at $285 per
well per month; and
o $3,136,140 if $200 million is received, which is 917 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
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
gathering system 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 the gathering system owned by 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 through Atlas Pipeline Partners' gathering system.
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. If a gathering
system owned by the managing general partner or its affiliates other than Atlas
Pipeline Partners is used, then the managing general partner or its affiliates
will receive, or retain in the case of the managing general partner, the
gathering fee paid to the managing general partner.
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.
32
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, Greene and Westmoreland 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)
Mississippian and Devonian Shale Reservoirs in Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee.................................................... (4)
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.
(2) Each partnership will use a gathering system provided by a third-party
joint venture partner in the wells in this area, which will not charge the
partnership a gathering fee if it markets the natural gas. However, if the
managing general partner markets the natural 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 joint venture partner, which the
managing general partner anticipates will be $.20 per mcf.
(3) A partnership will deliver natural gas produced in this area 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.
(4) In this area, a partnership will deliver natural gas into a gathering
system provided by Knox Energy, which is referred to as the Coalfield
Pipeline. See "Proposed Activities - Interest of Parties." The Coalfield
Pipeline will receive gathering fees of $.55 per mcf plus fees for
compression. If the Coalfield Pipeline does not have sufficient capacity
to compress and transfer the natural gas produced from a partnership's
wells as determined by Atlas America, then Atlas America or an affiliate
other than Atlas Pipeline Partners will construct an additional gathering
system and/or enhancements to the Coalfield Pipeline. On completion of the
construction, Atlas America will transfer its ownership in the additional
gathering system and/or enhancements to the owners of the Coalfield
Pipeline, which will then pay Atlas America an amount equal to $.12 per
mcf of natural gas transported through the newly constructed and/or
enhanced gathering system. If the events described above occur, Coalfield
Pipeline will charge this $.12 per mcf to the partnership in addition to
the $.55 per mcf plus fees for compression. Also, if Atlas America or an
affiliate (which may or may not be Atlas Pipeline Partners) constructs any
other gathering or pipeline system, in addition to the gathering system
described above to connect to the Coalfield Pipeline gathering system,
then Atlas America may receive a competitive gathering fee.
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.
33
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 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 $21,000,000 if $200 million is received by the partnerships.
All of the reimbursement of the selling agents' bona fide due diligence
expenses, and generally all of the 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
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 $7,200 if $2 million is received, which is eight net wells at $75 per
well per month; and
o $825,300 if $200 million is received, which is 917 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:
34
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 $200 million (1)
------------- -------------------
DIRECT COSTS
External Legal...................................................... $6,000 $ 24,000
Accounting Fees for Audit and Tax Preparation....................... 29,300 106,700
Independent Engineering Reports..................................... 1,500 40,000
------- --------
TOTAL .............................................................. $36,800 $170,700
======= ========
- -----------
(1) This assumes four 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 #15-2005 Program was formed to offer for sale an aggregate
of $200 million of units in a series of up to four limited partnerships, each of
which has been formed under the Delaware Revised Uniform Limited Partnership
Act.
The targeted subscriptions for each partnership are set forth below. These
targeted amounts are not mandatory, and the managing general partner may
determine the final subscription amount for each partnership in its sole
discretion. The maximum subscription of any partnership, however, must be the
lesser of:
o $200 million; or
o $200 million less the total subscription proceeds received by any prior
partnership or partnerships in the program.
Also set forth below are the targeted ending dates for each partnership, which
are not binding except that the units in each partnership may not be offered
beyond that partnership's offering termination date as set forth below. The
managing general partner may close the offering of units in a partnership at any
time before that partnership's offering termination date once the partnership is
in receipt of the minimum required subscriptions, and the managing general
partner may withdraw the offering of units in any partnership at any time.
35
REQUIRED TARGETED TARGETED OFFERING
PARTNERSHIP MINIMUM SUBSCRIPTION ENDING TERMINATION
NAME SUBSCRIPTION PROCEEDS DATE (1) DATE (1)
---- ------------ -------- -------- --------
Atlas America Public #15-2005(A) $2 million $50 million 12/31/05 12/31/05
o The units in the above partnership will be offered and sold only during
2005.
Atlas America Public #15-2006(B) $2 million $50 million 03/31/06 12/31/06
Atlas America Public #15-2006(C) $2 million $50 million 06/30/06 12/31/06
Atlas America Public #15-2006(D) $2 million $50 million 09/30/06 12/31/06
o The units in the above partnerships will be offered and sold only
during 2006.
- --------------
(1) The partnerships will be offered in a series. Thus, units in Atlas
America Public #15-2006(B) L.P. will not be offered until the offering
of units in Atlas America Public #15-2005(A) L.P. has terminated.
Likewise, units in Atlas America Public #15-2006(C) L.P. will not be
offered until the offering of units in Atlas America Public #15-2006(B)
L.P. has terminated and units in Atlas America Public #15-2006(D) L.P.
will not be offered until the offering of units in Atlas America Public
#15-2006(C) L.P. has terminated.
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, distributions, 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
You and the other investors should make your checks for units payable to "Atlas
America Public #15-2005(A) L.P., Escrow Agent, National City Bank of PA," "Atlas
America Public #15-2006(B) L.P., Escrow Agent, National City Bank of PA," "Atlas
America Public #15-2006(C) L.P., Escrow Agent, National City Bank of PA" or
"Atlas America Public #15-2006(D) L.P., Escrow Agent, National City Bank of PA,"
depending on which partnership is then being offered at the time you subscribe
for units, and give your check to your broker/dealer for submission to the
dealer-manager and escrow agent. Subscription proceeds for each partnership will
be held in a separate interest bearing escrow account at National City Bank of
Pennsylvania until receipt of 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
break escrow and transfer the escrowed funds to a partnership account, enter
into the drilling and operating agreement with itself or an affiliate as
operator, and begin drilling operations.
36
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 for Atlas America Public #15-2005(A) L.P. is December
31, 2005, and the latest offering termination date for each of Atlas America
Public #15-2006(B) L.P., Atlas America Public #15-2006(C) L.P. and Atlas America
Public #15-2006(D) L.P. is December 31, 2006. Although the managing general
partner and its affiliates may buy up to 5% of the units in each partnership,
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. Also, any
purchases of units by the managing general partner and its affiliates must be
made for investment purposes only, and not with a view toward redistribution.
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 a
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 to
be 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
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.
You have five business days after you receive the final prospectus and execute
your subscription agreement to rescind your purchase of units in a partnership.
To rescind or withdraw your subscription agreement, you must give written notice
to the managing general partner before your subscription agreement is accepted
by the managing general partner.
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.
Subject to the foregoing, your subscription agreement 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.
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; or
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.
37
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.
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:
o ALABAMA, o KANSAS, o OKLAHOMA,
o ALASKA, o KENTUCKY, o OREGON,
o ARIZONA, o LOUISIANA, o PENNSYLVANIA,
o ARKANSAS, o MAINE, o RHODE ISLAND,
o COLORADO, o MARYLAND, o SOUTH CAROLINA,
o CONNECTICUT, o MASSACHUSETTS, o SOUTH DAKOTA,
o DELAWARE, o MINNESOTA, o TENNESSEE,
o DISTRICT OF COLUMBIA, o MISSISSIPPI, o TEXAS,
o FLORIDA, o MISSOURI, o UTAH,
o GEORGIA, o MONTANA, o VERMONT,
o HAWAII, o NEBRASKA, o VIRGINIA,
o IDAHO, o NEVADA, o WASHINGTON,
o ILLINOIS, o NEW MEXICO, o WEST VIRGINIA,
o INDIANA, o NEW YORK, o WISCONSIN, OR
o IOWA, o NORTH DAKOTA, o WYOMING,
then limited partner units may 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
38
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 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 different
suitability requirements apply to you.
SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS.
o If you are a resident of CALIFORNIA or NEW JERSEY and you subscribe for
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 subscribe
for 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 subscribe for 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.
o If you are a resident of OHIO and you subscribe for limited partner
units, then you must meet, without regard to your investment in a
partnership, either of the following special suitability requirements:
o a net worth of not less than $330,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $85,000, exclusive of home, home
furnishings, and automobiles, and an annual gross income during
the current tax year of at least $85,000.
39
Additionally, if you are a resident of OHIO you must not make an
investment in a partnership which would, after including your previous
investments in prior Atlas Resources programs, if any, and any other
similar natural gas and oil drilling programs, exceed 10% of your net
worth, exclusive of home, home furnishings and automobiles.
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 IDAHO, o NORTH DAKOTA,
o COLORADO, o ILLINOIS, o RHODE ISLAND,
o CONNECTICUT, o LOUISIANA, o SOUTH CAROLINA,
o DELAWARE, o MARYLAND, o UTAH,
o DISTRICT OF COLUMBIA, o MONTANA, o VIRGINIA,
o FLORIDA, o NEBRASKA, o WEST VIRGINIA,
o GEORGIA, o NEVADA, o WISCONSIN, OR
o HAWAII, o NEW YORK, o WYOMING,
then investor general partner units may 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 different
suitability requirements apply to you if you purchase investor general partner
units.
SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS.
o If you are a resident of any of the following states:
o ALABAMA, o MASSACHUSETTS, o PENNSYLVANIA,
o ARKANSAS, o MINNESOTA, o TENNESSEE,
o INDIANA, o NORTH CAROLINA, o TEXAS, OR
o MAINE, o OKLAHOMA, o WASHINGTON
and you subscribe for 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
40
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 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 MICHIGAN, o OREGON,
o IOWA, o MISSISSIPPI, o SOUTH DAKOTA, OR
o KANSAS, o MISSOURI, o VERMONT
o KENTUCKY, o NEW MEXICO,
and you subscribe for 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.
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.
o If you are a resident of CALIFORNIA or NEW JERSEY and you subscribe for
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
41
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 subscribe for 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; or
o a net worth of not less than $125,000, exclusive of home, home
furnishings, and automobiles, and $50,000 of taxable income.
o If you are a resident of OHIO and you subscribe for investor general
partner units, then you must meet, without regard to your investment in
a partnership, either of the following special suitability
requirements:
o a net worth of not less than $750,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $330,000, exclusive of home, home
furnishings, and automobiles, and an annual gross income of at
least $150,000 for the current year and the two previous years.
Additionally, if you are a resident of OHIO you must not make an
investment in a partnership which would, after including your previous
investments in prior Atlas Resources programs, if any, and any other
similar natural gas and oil drilling programs, exceed 10% of your net
worth, exclusive of home, home furnishings and automobiles.
FIDUCIARY ACCOUNTS. If there is a sale of a unit to a fiduciary account, then
all the suitability standards set forth above must be met by the beneficiary,
the fiduciary account, or 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.
PRIOR ACTIVITIES
The following tables reflect certain historical data with respect to 35 private
drilling partnerships which raised a total of $254,432,892, and 14 public
drilling partnerships which raised a total of $289,792,368, 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 this program and 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. 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.
42
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.
43
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 JUNE 15, 2005
Managing
Number General Date Date of
of Investor Partner Total Operations First
Partnership Investors Capital Capital Capital Began Distributions
----------- --------- -------- -------- ------- ----- -------------
1. Atlas L.P. #1 - 1985 19 $600,000 $114,800 $714,800 12/31/85 07/02/86
2. A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87
3. A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88
4. A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89
5. A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90
6. A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91
7. A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91
8. A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92
9. A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92
10. A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92
11. A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93
12. A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93
13. A.E. Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93
14. A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94
15. A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94
16. A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94
17. A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95
18. A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95
19. A.E. Nineties-Public #3 391 5,800,990 928,546 6,729,536 12/31/94 06/05/95
20. A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96
21. A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96
22. A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96
23. A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97
24. A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97
25. A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97
26. A.E. Nineties-17 217 8,813,488 2,113,947 10,927,435 08/29/97 12/12/97
27. A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98
28. A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98
29. A.E. Nineties-18 225 11,391,673 3,448,751 14,840,424 07/31/98 01/07/99
30. A.E. Nineties-Public #7 366 11,988,350 3,812,150 15,800,500 12/31/98 07/10/99
31. A.E. Partners 1998 26 1,740,000 756,360 2,496,360 12/31/98 07/02/99
32. A.E. Nineties-19 288 15,720,450 4,776,598 20,497,048 09/30/99 01/14/00
33. A.E. Nineties-Public #8 380 11,088,975 3,148,181 14,237,156 12/31/99 06/09/00
34. A.E. Partners 1999 8 450,000 196,500 646,500 12/31/99 10/02/00
35. 1999 Viking Resources LP 131 4,555,210 1,678,038 6,233,248 12/31/99 06/01/00
36. Atlas America-Series 20 361 18,809,150 6,297,945 25,107,095 09/30/00 01/30/01
37. Atlas America - Public #9 530 14,905,465 5,563,527 20,468,992 12/31/00 07/13/01
38. Atlas America - Series 21-A 282 12,510,713 4,535,799 17,046,512 05/15/01 11/16/01
39. Atlas America - Series 21-B 360 17,411,825 6,442,761 23,854,586 09/19/01 03/02/02
40. Atlas America - Public #10 818 21,281,170 7,227,432 28,508,602 12/31/01 06/20/02
41. Atlas America - Series 22 258 10,156,375 3,481,591 13,637,966 05/31/02 11/12/02
42. Atlas America - Series 23 246 9,644,550 3,214,850 12,859,400 09/30/02 02/18/03
43. Atlas America - Public #11-2002 1017 31,178,145 13,295,226 44,473,371 12/31/02 7/15/2003
44. Atlas America - Series #24-2003(A) 325 14,363,955 4,949,143 19,313,098 05/31/03 12/05/03
45. Atlas America - Series #24-2003(B) 422 20,542,850 7,300,020 27,842,870 08/29/03 02/05/04
46. Atlas America - Public #12-2003 1102 40,170,308 13,708,076 53,878,384 12/31/03 6/15/04
47. Atlas America Series # 25-2004(A) 635 27,601,053 10,266,771 37,867,824 05/31/04 11/5/04
48. Atlas America Series # 25-2004(B) 634 31,531,035 16,006,953 47,537,988 08/31/04 2/5/05
49. Atlas America Public # 14-2004 1494 52,506,570 25,971,721 78,478,291 11/15/04 (1)
50. Atlas America Public # 14-2005(A) 2192 69,674,900 (3) 69,674,900 06/17/05 (2)
- --------------------------------------------------------------------------------------------------------------------------------
Years
Wells Previous
In Assess-
Partnership Production ments
----------- ---------- -----
1. Atlas L.P. #1 - 1985 19.47 -0-
2. A.E. Partners 1986 18.47 -0-
3. A.E. Partners 1987 17.47 -0-
4. A.E. Partners 1988 16.47 -0-
5. A.E. Partners 1989 15.47 -0-
6. A.E. Partners 1990 14.47 -0-
7. A.E. Nineties-10 14.25 -0-
8. A.E. Nineties-11 13.42 -0-
9. A.E. Partners 1991 13.25 -0-
10. A.E. Nineties-12 13.17 -0-
11. A.E. Nineties-JV 92 12.50 -0-
12. A.E. Partners 1992 12.00 -0-
13. A.E. Nineties-Public #1 11.75 -0-
14. A.E. Nineties-1993 Ltd. 11.42 -0-
15. A.E. Partners 1993 11.17 -0-
16. A.E. Nineties-Public #2 10.92 -0-
17. A.E. Nineties-14 10.42 -0-
18. A.E. Partners 1994 10.17 -0-
19. A.E. Nineties-Public #3 10.17 -0-
20. A.E. Nineties-15 9.34 -0-
21. A.E. Partners 1995 8.92 -0-
22. A.E. Nineties-Public #4 9.17 -0-
23. A.E. Nineties-16 8.50 -0-
24. A.E. Partners 1996 8.17 -0-
25. A.E. Nineties-Public #5 8.17 -0-
26. A.E. Nineties-17 7.59 -0-
27. A.E. Nineties-Public #6 7.17 -0-
28. A.E. Partners 1997 7.00 -0-
29. A.E. Nineties-18 6.25 -0-
30. A.E. Nineties-Public #7 5.92 -0-
31. A.E. Partners 1998 5.92 -0-
32. A.E. Nineties-19 5.42 -0-
33. A.E. Nineties-Public #8 4.92 -0-
34. A.E. Partners 1999 4.92 -0-
35. 1999 Viking Resources LP 4.92 -0-
36. Atlas America-Series 20 4.67 -0-
37. Atlas America - Public #9 4.27 -0-
38. Atlas America - Series 21-A 4.02 -0-
39. Atlas America - Series 21-B 3.42 -0-
40. Atlas America - Public #10 3.17 -0-
41. Atlas America - Series 22 2.67 -0-
42. Atlas America - Series 23 2.42 -0-
43. Atlas America - Public #11-2002 2.17 -0-
44. Atlas America - Series #24-2003(A) 1.67 -0-
45. Atlas America - Series #24-2003(B) 1.42 -0-
46. Atlas America - Public #12-2003 1.17 -0-
47. Atlas America Series # 25-2004(A) .92 -0-
48. Atlas America Series # 25-2004(B) .50 -0-
49. Atlas America Public # 14-2004 (1) -0-
50. Atlas America Public # 14-2005(A) (2) -0-
- --------------------------------------------------------------------------
(1) This program closed November 15, 2004, and its first distribution is
expected July 2005.
(2) This program closed June 17, 2005, and its first distribution is expected
early 2006.
(3) The managing general partner's capital contribution is not available as of
the date of this table.
44
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 JUNE 15, 2005
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 0 103.15 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 #11-2002 0 167 0 0 160.50 0.00
44. Atlas America - Series #24-2003(A) 0 76 0 0 69.50 0.00
45. Atlas America - Series #24-2003(B) 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) 0 137 4 0 130.80 4.00
48. Atlas America Series # 25-2004(B) 0 171 4 0 153.40 4.00
49. Atlas America Public # 14-2004 0 262 5 0 238.50 5.00
50. Atlas America Public # 14-2005(A) 0 71 3 0 67.25 3.00
----- ---- -- ---- ------- -----
0 2717 51 0 2432.80 46.50
- ----------------------------------------------------------------------------------------------------------
(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.
45
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 JUNE 15, 2005
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 $229,019 $46,817 $14,368 $1,629,473 272%
2. A.E. Partners 1986 631,250 182,547 75,701 13,504 783,443 124%
3. A.E. Partners 1987 721,000 183,184 64,095 13,776 784,063 109%
4. A.E. Partners 1988 617,050 153,798 61,579 12,289 721,776 117%
5. A.E. Partners 1989 550,000 149,987 66,191 12,429 903,764 164%
6. A.E. Partners 1990 887,500 226,940 95,450 17,815 1,314,579 148%
7. A.E. Nineties - 10 2,200,000 483,892 105,371 46,030 2,012,839 91%
8. A.E. Nineties - 11 750,000 183,732 105,868 67,650 1,119,367 149%
9. A.E. Partners 1991 868,750 205,080 123,537 29,396 1,416,503 163%
10. A.E. Nineties - 12 2,212,500 482,214 103,585 133,491 2,174,018 98%
11. A.E. Nineties - JV 92 4,004,813 824,968 168,657 226,777 4,568,558(3) 114%
12. A.E. Partners 1992 600,000 115,983 61,388 15,751 938,212 156%
13. A.E. Nineties - Public #1 2,988,960 517,688 106,192 125,612 2,468,829 83%
14. A.E. Nineties - 1993 Ltd. 3,753,937 582,943 114,539 61,990 2,265,116 60%
15. A.E. Partners 1993 700,000 152,624 45,488 14,884 1,103,681 158%
16. A.E. Nineties - Public #2 3,323,920 518,232 94,572 88,979 2,397,396 72%
17. A.E. Nineties - 14 9,940,045 1,578,602 302,434 82,689 6,274,302 63%
18. A.E. Partners 1994 892,500 157,691 57,130 20,472 1,189,232 133%
19. A.E. Nineties - Public #3 5,800,990 852,335 162,313 103,031 4,129,462 71%
20. A.E. Nineties - 15 10,954,715 1,603,386 305,673 98,752 8,048,256 73%
21. A.E. Partners 1995 600,000 90,759 22,008 11,120 396,138 66%
22. A.E. Nineties - Public #4 6,991,350 966,744 177,743 103,911 3,488,242 50%
23. A.E. Nineties - 16 10,955,465 1,385,468 233,283 101,673 5,888,179 54%
24. A.E. Partners 1996 800,000 128,884 28,830 49,647 562,713 70%
25. A.E. Nineties - Public #5 7,992,240 970,644 176,614 119,372 4,078,820 51%
26. A.E. Nineties - 17 8,813,488 1,066,711 178,218 162,396 5,485,882 62%
27. A.E. Nineties - Public #6 9,901,025 1,239,111 205,405 144,089 6,101,795 62%
28. A.E. Partners 1997 506,250 75,057 16,661 33,241 411,635 81%
29. A.E. Nineties - 18 11,391,673 1,379,259 218,082 267,919 6,282,657 55%
30. A.E. Nineties - Public #7 11,988,350 1,205,295 182,757 68,302 4,747,724 40%
31. A.E. Partners 1998 1,740,000 230,651 28,831 63,891 1,196,076 69%
32. A.E. Nineties - 19 15,720,450 1,579,647 238,582 18,301 7,053,948 45%
33. A.E. Nineties - Public #8 11,088,975 1,067,034 162,444 84,879 5,242,235 47%
34. A.E. Partners 1999 450,000 46,558 4,959 15,993 367,792 82%
35. 1999 Viking Resources LP 4,555,210 1,351,635 0 184,991 6,689,078 147%
36. Atlas America - Series 20 18,809,150 2,722,386 261,787 196,873 13,639,507 73%
37. Atlas America - Public #9 14,905,465 1,707,033 180,278 76,569 7,887,277 53%
38. Atlas America - Series 21-A 12,510,713 1,108,375 131,186 12,964 5,805,256 46%
39. Atlas America - Series 21-B 17,411,825 1,369,725 154,505 12,983 6,899,718 40%
40. Atlas America - Public #10 21,281,170 1,653,481 187,736 70,383 9,475,449 45%
41. Atlas America - Series 22 10,156,375 685,104 77,418 10,588 4,728,353 47%
42. Atlas America - Series 23 9,644,550 620,341 68,901 10,279 3,737,295 39%
43. Atlas America - Public #11-2002 31,178,145 1,701,481 184,281 59,632 10,729,233 34%
44. Atlas America - Series 24-2003(A) 14,363,955 543,251 64,233 6,895 3,699,005 26%
45. Atlas America - Series 24-2003(B) 20,542,850 764,586 80,812 6,047 6,250,269 30%
46. Atlas America - Public #12-2003(5) 40,170,308 946,434 109,891 42,644 7,342,059 18%
47. Atlas America Series # 25-2004(A)(5) 27,601,053 283,304 27,154 10,866 2,548,737 9%
48. Atlas America Series # 25-2004(B)(5) 31,531,035 141,124 17,404 11,268 918,390 3%
49. Atlas America Public # 14-2004(5) 52,506,570 0 0 0 0 0%
50. Atlas America Public # 14-2005(A)(5) 69,674,900 0 0 0 0 0%
- ------------------------------------------------------------------------------------------------------------------------------------
Present Value of
Estimated Future Estimated Future Net
Latest Quarterly Net Cash Flows from Cash Flows from Proved
Cash Distribution Proved Reserves as of Reserves Discounted at 10%
Partnership As of Date of Table January 1, 2005(8)(9) as of January 1, 2005(8)(10)
----------- ------------------- --------------------- ----------------------------
1. Atlas L.P. #1 - 1985 $17,359 (7) (7)
2. A.E. Partners 1986 14,999 (7) (7)
3. A.E. Partners 1987 8,111 (7) (7)
4. A.E. Partners 1988 8,452 (7) (7)
5. A.E. Partners 1989 9,794 (7) (7)
6. A.E. Partners 1990 18,121 (7) (7)
7. A.E. Nineties - 10 31,138 2,190,991 1,073,724
8. A.E. Nineties - 11 12,336 585,386 295,603
9. A.E. Partners 1991 20,096 (7) (7)
10. A.E. Nineties - 12 29,002 1,690,557 843,479
11. A.E. Nineties - JV 92 55,890 3,469,888 1,686,351
12. A.E. Partners 1992 11,620 (7) (7)
13. A.E. Nineties - Public #1 37,007 1,742,165 928,742
14. A.E. Nineties - 1993 Ltd. 13,575 921,133 513,309
15. A.E. Partners 1993 12,905 (7) (7)
16. A.E. Nineties - Public #2 43,109 2,475,212 1,218,558
17. A.E. Nineties - 14 87,949 5,466,413 2,808,653
18. A.E. Partners 1994 27,840 (7) (7)
19. A.E. Nineties - Public #3 77,467 3,483,439 1,809,823
20. A.E. Nineties - 15 149,558 9,507,215 4,661,659
21. A.E. Partners 1995 5,480 (7) (7)
22. A.E. Nineties - Public #4 78,770 3,885,292 2,041,671
23. A.E. Nineties - 16 155,584 9,072,445 4,305,658
24. A.E. Partners 1996 13,064 (7) (7)
25. A.E. Nineties - Public #5 92,832 5,281,117 2,727,635
26. A.E. Nineties - 17 148,063 9,543,628 4,534,846
27. A.E. Nineties - Public #6 170,253 9,322,519 4,744,130
28. A.E. Partners 1997 17,264 (7) (7)
29. A.E. Nineties - 18 181,436 9,923,043 4,988,209
30. A.E. Nineties - Public #7 142,101 6,147,494 3,322,893
31. A.E. Partners 1998 38,590 (7) (7)
32. A.E. Nineties - 19 258,884 12,079,259 6,010,035
33. A.E. Nineties - Public #8 167,500 6,758,460 3,708,893
34. A.E. Partners 1999 9,968 (7) (7)
35. 1999 Viking Resources LP 217,145 (7) (7)
36. Atlas America - Series 20 480,893 20,506,888 10,379,405
37. Atlas America - Public #9 407,250 12,948,489 7,085,881
38. Atlas America - Series 21-A 364,024 14,489,528 7,269,656
39. Atlas America - Series 21-B 435,478 17,509,490 8,901,138
40. Atlas America - Public #10 632,303 18,448,176 10,296,772
41. Atlas America - Series 22 338,405 11,896,400 6,328,173
42. Atlas America - Series 23 298,761 8,490,290 4,859,947
43. Atlas America - Public #11-2002 1,138,706 26,604,847 15,675,979
44. Atlas America - Series 24-2003(A) 628,696 13,621,672 7,706,817
45. Atlas America - Series 24-2003(B) 1,096,602 25,605,612 14,929,026
46. Atlas America - Public #12-2003(5) 2,256,239 43,301,298 26,619,307
47. Atlas America Series # 25-2004(A)(5) 1,423,830 36,118,156 22,324,624
48. Atlas America Series # 25-2004(B)(5) 633,704 28,790,262 18,105,519
49. Atlas America Public # 14-2004(5) 0 17,414,152 11,173,874
50. Atlas America Public # 14-2005(A)(5) 0 (7) (7)
- ------------------------------------------------------------------------------------------------------------------------------
(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 other than for the
following partnerships which also include revenue from the sale of properties:
A.E. Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas America Series # 20
($6,213), A.E. Nineties-Public # 1 ($2,453), A.E. Nineties-Public # 2 ($3,292),
A.E. Nineties-Public # 3 ($2,491), A.E. Nineties-Public # 5 ($8,639), A.E.
Nineties-Public # 7 ($2,296) and Atlas America Public # 11 ($2,789).
(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 not available for these partnerships. Also,
reserve information for Public #14-2004 which closed at 11/15/04 is incomplete
since not all of its wells were drilled at 1/1/05.
(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 $6.98 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. 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 estimates 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.
46
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 JUNE 15, 2005
Total Costs
Managing General ------------------------------------ Cash
Partnership Partner Capital Operating(3) Admin. Direct Distributions(1)
----------- --------------- ------------ ------ ------ ----------------
1. Atlas L.P. #1 - 1985 $114,800 $43,623 $8,917 $2,737 $307,069
2. A.E. Partners 1986 120,400 34,771 14,419 2,572 146,370
3. A.E. Partners 1987 158,269 52,817 18,480 3,972 223,728
4. A.E. Partners 1988 135,450 49,531 19,831 3,958 229,754
5. A.E. Partners 1989 120,731 32,924 14,530 2,728 271,730
6. A.E. Partners 1990 244,622 75,647 0 0 385,969
7. A.E. Nineties - 10 484,380 161,297 0 0 705,893
8. A.E. Nineties - 11 268,003 78,742 45,372 23,935 474,677
9. A.E. Partners 1991 318,063 68,360 0 0 495,967
10. A.E. Nineties - 12 791,833 206,663 44,394 31,703 919,293
11. A.E. Nineties - JV 92 1,414,917 406,328 83,070 30,156 1,294,467
12. A.E. Partners 1992 176,100 38,661 0 0 926,593
13. A.E. Nineties - Public #1 528,934 163,480 33,534 27,860 713,398
14. A.E. Nineties - 1993 Ltd. 1,264,183 249,833 49,088 22,985 491,301
15. A.E. Partners 1993 219,600 50,875 0 0 376,907
16. A.E. Nineties - Public #2 587,340 163,652 29,865 28,099 578,428
17. A.E. Nineties - 14 3,584,027 777,520 148,960 33,548 1,879,681
18. A.E. Partners 1994 231,500 52,564 0 0 406,624
19. A.E. Nineties - Public #3 928,546 284,112 54,104 34,344 1,289,478
20. A.E. Nineties - 15 3,435,936 687,166 131,003 42,322 2,465,993
21. A.E. Partners 1995 244,725 30,253 0 0 139,873
22. A.E. Nineties - Public #4 1,287,752 322,248 59,248 34,637 953,901
23. A.E. Nineties - 16 1,643,320 379,459 63,893 23,041 1,173,021
24. A.E. Partners 1996 367,416 42,961 0 0 201,551
25. A.E. Nineties - Public #5 1,654,740 323,548 58,871 39,791 1,011,587
26. A.E. Nineties - 17 2,113,947 384,596 64,256 29,206 1,777,474
27. A.E. Nineties - Public #6 1,950,345 413,037 68,468 48,030 1,879,958
28. A.E. Partners 1997 231,050 25,019 0 0 139,387
29. A.E. Nineties - 18 3,448,751 634,258 100,286 10,333 2,599,785
30. A.E. Nineties - Public #7 3,812,150 541,509 82,108 30,686 1,149,666
31. A.E. Partners 1998 756,360 76,884 0 0 402,162
32. A.E. Nineties - 19 4,776,598 726,407 109,713 8,416 2,673,972
33. A.E. Nineties - Public #8 3,148,181 435,831 66,350 34,669 1,851,700
34. A.E. Partners 1999 196,500 15,519 0 0 125,539
35. 1999 Viking Resources LP 1,678,038 450,545 0 61,664 2,191,236
36. Atlas America - Series 20 6,297,945 1,006,910 96,825 72,816 4,869,790
37. Atlas America - Public #9 6,256,271 697,239 73,635 31,275 3,051,977
38. Atlas America - Series 21-A 4,535,799 566,758 67,081 6,629 2,782,325
39. Atlas America - Series 21-B 6,442,761 705,616 79,593 6,688 3,330,063
40. Atlas America - Public #10 7,227,432 778,112 88,347 33,122 4,161,499
41. Atlas America - Series 22 3,481,591 330,317 36,432 5,105 2,116,577
42. Atlas America - Series 23 3,214,850 291,931 32,424 4,837 1,618,168
43. Atlas America - Public #11-2002 13,295,226 876,520 94,933 30,720 4,938,692
44. Atlas America - Series 24-2003(A) 4,949,143 263,118 31,111 3,339 1,487,060
45. Atlas America - Series 24-2003(B) 7,300,020 380,346 40,200 3,008 2,563,706
46. Atlas America - Public #12-2003(2) 13,708,076 454,445 52,766 20,476 2,442,042
47. Atlas America Series # 25-2004(A)(2) 10,266,771 152,548 14,621 5,851 605,719
48. Atlas America Series # 25-2004(B)(2) 16,006,953 75,990 9,371 6,068 153,292
49. Atlas America Public # 14-2004(2) 25,971,721 0 0 0 0
50. Atlas America Public # 14-2005(A)(2) (4) 0 0 0 0
- ------------------------------------------------------------------------------------------------------------------------------------
Latest Quarterly Cash
Distribution As of
Partnership Cash Return Date of Table
----------- ----------- -------------
1. Atlas L.P. #1 - 1985 267% $3,306
2. A.E. Partners 1986 122% 2,857
3. A.E. Partners 1987 141% 2,339
4. A.E. Partners 1988 170% 2,722
5. A.E. Partners 1989 225% 2,150
6. A.E. Partners 1990 158% 7,020
7. A.E. Nineties - 10 146% 11,780
8. A.E. Nineties - 11 177% 5,287
9. A.E. Partners 1991 156% 8,007
10. A.E. Nineties - 12 116% 12,429
11. A.E. Nineties - JV 92 91% 27,528
12. A.E. Partners 1992 526% 4,617
13. A.E. Nineties - Public #1 135% 11,686
14. A.E. Nineties - 1993 Ltd. 39% 5,818
15. A.E. Partners 1993 172% 4,951
16. A.E. Nineties - Public #2 98% 12,607
17. A.E. Nineties - 14 52% 43,318
18. A.E. Partners 1994 176% 10,567
19. A.E. Nineties - Public #3 139% 25,017
20. A.E. Nineties - 15 72% 64,096
21. A.E. Partners 1995 57% 2,316
22. A.E. Nineties - Public #4 74% 26,257
23. A.E. Nineties - 16 71% 41,304
24. A.E. Partners 1996 55% 5,094
25. A.E. Nineties - Public #5 61% 29,471
26. A.E. Nineties - 17 84% 53,383
27. A.E. Nineties - Public #6 96% 56,751
28. A.E. Partners 1997 60% 6,229
29. A.E. Nineties - 18 75% 83,434
30. A.E. Nineties - Public #7 30% 63,842
31. A.E. Partners 1998 53% 14,199
32. A.E. Nineties - 19 56% 107,346
33. A.E. Nineties - Public #8 59% 42,311
34. A.E. Partners 1999 64% 3,996
35. 1999 Viking Resources LP 131% 38,457
36. Atlas America - Series 20 77% 180,179
37. Atlas America - Public #9 49% 170,788
38. Atlas America - Series 21-A 61% 186,141
39. Atlas America - Series 21-B 52% 224,337
40. Atlas America - Public #10 58% 297,556
41. Atlas America - Series 22 61% 163,159
42. Atlas America - Series 23 50% 140,596
43. Atlas America - Public #11-2002 37% 617,343
44. Atlas America - Series 24-2003(A) 30% 316,469
45. Atlas America - Series 24-2003(B) 35% 557,543
46. Atlas America - Public #12-2003(2) 18% 1,214,898
47. Atlas America Series # 25-2004(A)(2) 6% 766,678
48. Atlas America Series # 25-2004(B)(2) 1% 341,225
49. Atlas America Public # 14-2004(2) 0% 0
50. Atlas America Public # 14-2005(A)(2) 0% 0
- -------------------------------------------------------------------------------------
(1) All cash distributions were from the sale of gas. The following partnerships
also include revenue from the sale of properties: A.E. for the Nineties-1993 LTD
($2,352), A.E. Nineties-14 ($5,964), A.E. Nineties-15 ($4,776), A.E. Nineties-19
($2,473), Atlas America Series #20 ($11,538), A.E. Nineties-Public # 1 ($25),
A.E. Nineties-Public # 2 ($33), A.E. Nineties-Public # ($25), A.E.
Nineties-Public # 5 ($1,406), A.E. Nineties-Public # 7 ($2,206), Atlas America
Public # 9 ($4,446) and Atlas America Public # 11 ($5,696).
(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.
(4) The Managing General Partner's capital contribution is not available as of
the date of this table.
47
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 JUNE 15, 2005
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 $130,072 N/A $55,915
2. A.E. Partners 1986 631,250 99% 50.0% 312,889 73,859 N/A 13,507
3. A.E. Partners 1987 721,000 99% 38.5% 356,895 56,642 N/A N/A
4. A.E. Partners 1988 617,050 99% 33.0% 244,351 51,149 N/A N/A
5. A.E. Partners 1989 550,000 99% 33.0% 179,685 70,671 N/A N/A
6. A.E. Partners 1990 887,500 99% 33.0% 275,125 100,982 N/A 281,660
7. A.E. Nineties - 10 2,200,000 100% 33.0% 726,000 166,291 N/A 521,602
8. A.E. Nineties - 11 750,000 100% 31.0% 232,500 102,214 N/A 329,800
9. A.E. Partners 1991 868,750 100% 31.0% 269,313 114,141 N/A 315,893
10. A.E. Nineties - 12 2,212,500 100% 31.0% 685,875 207,767 N/A 617,285
11. A.E. Nineties - JV 92 4,004,813 92.5% 31.0% 1,322,905 363,663 N/A 1,002,109
12. A.E. Partners 1992 600,000 100% 31.0% 186,000 81,117 N/A 224,631
13. A.E. Nineties - Public #1 2,988,960 80.5% 36.0% 877,511 228,434 254,729 N/A
14. A.E. Nineties - 1993 Ltd. 3,753,937 92.5% 39.6% 1,378,377 212,712 N/A N/A
15. A.E. Partners 1993 700,000 100% 39.6% 273,216 88,666 N/A N/A
16. A.E. Nineties - Public #2 3,323,920 78.7% 39.6% 1,036,343 204,449 279,039 N/A
17. A.E. Nineties - 14 9,940,045 95% 39.6% 3,739,445 535,509 N/A N/A
18. A.E. Partners 1994 892,500 100% 39.6% 353,430 87,072 N/A N/A
19. A.E. Nineties - Public #3 5,800,990 76.2% 39.6% 1,752,761 352,648 521,115 N/A
20. A.E. Nineties - 15 10,954,715 90.0% 39.6% 3,904,261 643,574 N/A N/A
21. A.E. Partners 1995 600,000 100% 39.6% 237,600 27,516 N/A N/A
22. A.E. Nineties - Public #4 6,991,350 80.0% 39.6% 2,214,860 310,127 537,551 N/A
23. A.E. Nineties - 16 10,955,465 86.8% 39.6% 3,361,289 452,686 871,686 N/A
24. A.E. Partners 1996 800,000 100% 39.6% 316,800 45,025 N/A N/A
25. A.E. Nineties - Public #5 7,992,240 84.9% 39.6% 2,530,954 325,897 602,746 N/A
26. A.E. Nineties - 17 8,813,488 85.2% 39.6% 2,966,366 427,550 444,472 N/A
27. A.E. Nineties - Public #6 9,901,025 80.0% 39.6% 3,166,406 475,644 698,432 N/A
28. A.E. Partners 1997 506,250 100% 39.6% 200,475 31,018 N/A N/A
29. A.E. Nineties - 18 11,391,673 90.0% 39.6% 4,030,884 342,940 415,445 N/A
30. A.E. Nineties - Public #7 11,988,350 85.0% 39.6% 4,043,670 330,100 570,825 N/A
31. A.E. Partners 1998 1,740,000 100.0% 39.6% 689,040 90,420 N/A N/A
32. A.E. Nineties - 19 15,720,450 90.0% 39.6% 5,602,767 489,863 475,420 N/A
33. A.E. Nineties - Public #8 11,088,975 85.0% 39.6% 3,734,654 369,876 489,241 N/A
34. A.E. Partners 1999 450,000 100.0% 39.6% 178,200 23,868 N/A N/A
35. 1999 Viking Resources LP 4,555,210 92.0% 39.6% 1,678,038 463,551 N/A N/A
36. Atlas America - Series 20 18,809,150 90.0% 39.6% 6,712,802 848,014 486,823 N/A
37. Atlas America - Public #9 14,905,465 90.0% 39.6% 5,349,744 536,148 N/A N/A
38. Atlas America - Series 21-A 12,510,713 91.0% 39.1% 4,468,617 347,713 243,320 N/A
39. Atlas America - Series 21-B 17,411,825 91.0% 39.1% 6,197,907 410,178 306,749 N/A
40. Atlas America - Public #10 21,281,170 91.0% 39.1% 7,550,729 516,534 503,408 N/A
41. Atlas America - Series 22 10,156,375 91.0% 38.6% 3,564,312 236,356 232,347 N/A
42. Atlas America - Series 23 9,644,550 91.0% 38.6% 3,404,803 183,542 203,094 N/A
43. Atlas America - Public #11-2002 31,178,145 91.0% 38.6% 11,003,503 538,019 549,825 N/A
44. Atlas America - Series 24-2003(A) 14,363,955 91.0% 35.0% 4,578,250 119,231 262,405 N/A
45. Atlas America - Series 24-2003(B) 20,542,850 91.0% 35.0% 6,514,764 236,045 453,544 N/A
46. Atlas America - Public #12-2003(8) 40,170,308 91.0% 35.0% 12,879,332 237,861 729,413 N/A
47. Atlas America Series # 25-2004(A)(8) 27,601,053 91.0% 35.0% 8,694,332 29,802 735,421 N/A
48. Atlas America Series # 25-2004(B)(8) 31,531,035 91.0% 35.0% 9,932,276 6,319 892,121 N/A
49. Atlas America Public # 14-2004(8) 52,506,570 91.0% 35.0% 16,543,643 0 145,202 N/A
50. Atlas America Public # 14-2005(A)(8) 69,674,900 91.0% 35.0% 0 0 0 N/A
- ------------------------------------------------------------------------------------------------------------------------------------
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 $484,324 $1,629,473 $2,113,797 352%
2. A.E. Partners 1986 400,254 783,443 1,183,697 188%
3. A.E. Partners 1987 413,537 784,063 1,197,600 166%
4. A.E. Partners 1988 295,500 721,776 1,017,276 165%
5. A.E. Partners 1989 250,356 903,764 1,154,120 210%
6. A.E. Partners 1990 657,767 1,314,579 1,972,346 222%
7. A.E. Nineties - 10 1,413,893 2,012,839 3,426,732 156%
8. A.E. Nineties - 11 664,514 1,119,367 1,783,881 238%
9. A.E. Partners 1991 699,348 1,416,503 2,115,851 244%
10. A.E. Nineties - 12 1,510,926 2,174,018 3,684,945 167%
11. A.E. Nineties - JV 92 2,688,676 4,568,558 7,257,235 181%
12. A.E. Partners 1992 491,748 938,212 1,429,960 238%
13. A.E. Nineties - Public #1 1,360,674 2,468,829 3,829,503 128%
14. A.E. Nineties - 1993 Ltd. 1,591,089 2,265,116 3,856,205 103%
15. A.E. Partners 1993 361,882 1,103,681 1,465,563 209%
16. A.E. Nineties - Public #2 1,519,831 2,397,396 3,917,227 118%
17. A.E. Nineties - 14 4,274,954 6,274,302 10,549,256 106%
18. A.E. Partners 1994 440,502 1,189,232 1,629,734 183%
19. A.E. Nineties - Public #3 2,626,524 4,129,462 6,755,987 116%
20. A.E. Nineties - 15 4,547,835 8,048,256 12,596,091 115%
21. A.E. Partners 1995 265,116 396,138 661,254 110%
22. A.E. Nineties - Public #4 3,062,538 3,488,242 6,550,779 94%
23. A.E. Nineties - 16 4,685,661 5,888,179 10,573,840 97%
24. A.E. Partners 1996 361,825 562,713 924,538 116%
25. A.E. Nineties - Public #5 3,459,597 4,078,820 7,538,417 94%
26. A.E. Nineties - 17 3,838,388 5,485,882 9,324,271 106%
27. A.E. Nineties - Public #6 4,340,482 6,101,795 10,442,277 105%
28. A.E. Partners 1997 231,493 411,635 643,128 127%
29. A.E. Nineties - 18 4,789,269 6,282,657 11,071,926 97%
30. A.E. Nineties - Public #7 4,944,595 4,747,724 9,692,319 81%
31. A.E. Partners 1998 779,460 1,196,076 1,975,536 114%
32. A.E. Nineties - 19 6,568,051 7,053,948 13,621,999 87%
33. A.E. Nineties - Public #8 4,593,771 5,242,235 9,836,006 89%
34. A.E. Partners 1999 202,068 367,792 569,860 127%
35. 1999 Viking Resources LP 2,141,589 6,689,078 8,830,667 194%
36. Atlas America - Series 20 8,047,639 13,639,507 21,687,146 115%
37. Atlas America - Public #9 5,885,892 7,887,277 13,773,169 92%
38. Atlas America - Series 21-A 5,059,650 5,805,256 10,864,906 87%
39. Atlas America - Series 21-B 6,914,834 6,899,718 13,814,552 79%
40. Atlas America - Public #10 8,570,671 9,475,449 18,046,119 85%
41. Atlas America - Series 22 4,033,015 4,728,353 8,761,368 86%
42. Atlas America - Series 23 3,791,440 3,737,295 7,528,735 78%
43. Atlas America - Public #11-2002 12,091,347 10,729,233 22,820,580 73%
44. Atlas America - Series 24-2003(A) 4,959,886 3,699,005 8,658,891 60%
45. Atlas America - Series 24-2003(B) 7,204,353 6,250,269 13,454,623 65%
46. Atlas America - Public #12-2003(8) 13,846,606 7,342,059 21,188,664 53%
47. Atlas America Series # 25-2004(A)(8) 9,459,555 2,548,737 12,008,292 44%
48. Atlas America Series # 25-2004(B)(8) 10,830,716 918,390 11,749,106 37%
49. Atlas America Public # 14-2004(8) 16,688,845 0 16,688,845 32%
50. Atlas America Public # 14-2005(A)(8) 0 0 0 0%
- ------------------------------------------------------------------------------------------------------------------------------------
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. Under the terms of this offering, not less than 90% of an investor general
partner's subscription to the 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. The following
partnerships also include revenue from the sale of properties: A.E. Nineties-16
($4,776), A.E. Nineties-19 ($1,607), Atlas America Series # 20 ($6,213) A.E.
Nineties-Public # 1 ($2,453), A.E. Nineties-Public # 2 ($3,292), A.E.
Nineties-Public # 3 ($2,491), A.E. Nineties-Public # 5 ($8,639), A.E.
Nineties-Public # 7 ($2,296) and Atlas America Public # 11 ($2,789).
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.
48
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 JUNE 15, 2005
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 0 $600,000 $272,642 $55,734
2. A.E. Partners 1986 631,250 0 631,250 217,002 90,121
3. A.E. Partners 1987 721,000 0 721,000 236,001 82,576
4. A.E. Partners 1988 617,050 0 617,050 203,329 81,410
5. A.E. Partners 1989 550,000 0 550,000 182,911 80,720
6. A.E. Partners 1990 887,500 0 887,500 302,587 95,450
7. A.E. Nineties-10 2,200,000 0 2,200,000 645,190 105,371
8. A.E. Nineties-11 750,000 0 761,802(3) 262,474 151,240
9. A.E. Partners 1991 868,750 0 867,500 273,440 123,537
10. A.E. Nineties-12 2,212,500 0 2,272,017(3) 688,877 147,979
11. A.E. Nineties-JV 92 4,004,813 0 4,157,700 1,231,296 251,727
12. A.E. Partners 1992 600,000 0 600,000 154,644 61,388
13. A.E. Nineties-Public #1 2,988,960 0 3,026,348(3) 681,168 139,726
14. A.E. Nineties-1993 Ltd. 3,753,937 0 3,480,656(3) 832,775 163,628
15. A.E. Partners 1993 700,000 0 689,940 203,499 45,488
16. A.E. Nineties-Public #2 3,323,920 0 3,324,668(3) 681,884 124,437
17. A.E. Nineties-14 9,940,045 0 9,512,015(3) 2,356,122 451,394
18. A.E. Partners 1994 892,500 0 892,500 210,255 57,130
19. A.E. Nineties-Public #3 5,800,990 0 5,800,990 1,136,447 216,417
20. A.E. Nineties-15 10,954,715 0 9,859,244(3) 2,290,552 436,676
21. A.E. Partners 1995 600,000 0 600,000 121,013 22,008
22. A.E. Nineties-Public #4 6,991,350 0 6,991,350 1,288,993 236,991
23. A.E. Nineties-16 10,955,465 0 10,955,465 1,764,927 297,176
24. A.E. Partners 1996 800,000 0 800,000 171,846 28,830
25. A.E. Nineties-Public #5 7,992,240 0 7,992,240 1,294,192 235,485
26. A.E. Nineties-17 8,813,488 0 8,813,488 1,451,307 242,474
27. A.E. Nineties-Public #6 9,901,025 0 9,901,025 1,652,148 273,873
28. A.E. Partners 1997 506,250 0 506,250 100,076 16,661
29. A.E. Nineties-18 11,391,673 0 11,391,673 2,013,516 318,367
30. A.E. Nineties-Public #7 11,988,350 0 11,988,350 1,746,804 264,865
31. A.E. Partners 1998 1,740,000 0 1,740,000 307,535 28,831
32. A.E. Nineties-19 15,720,450 0 15,720,450 2,306,054 348,295
33. A.E. Nineties-Public #8 11,088,975 0 11,088,975 1,502,865 228,794
34. A.E. Partners 1999 450,000 0 450,000 62,078 4,959
35. 1999 Viking Resources LP 4,555,210 0 4,555,210 1,802,180 0
36. Atlas America-Series 20 18,809,150 0 18,809,150 3,729,296 358,612
37. Atlas America-Public #9 14,905,465 839,174 14,905,465 1,565,097 253,913
38. Atlas America-Series 21-A 12,510,713 560,149 12,510,713 1,114,983 198,266
39. Atlas America-Series 21-B 17,411,825 718,107 17,411,825 1,357,235 234,098
40. Atlas America-Public #10 21,281,170 988,812 21,281,170 1,442,781 276,083
41. Atlas America-Series 22 10,156,375 432,144 10,156,375 583,278 113,850
42. Atlas America-Series 23 9,644,550 402,523 9,644,550 509,750 101,325
43. Atlas America-Public #11-2002 31,178,145 984,789 31,178,145 1,593,212 279,213
44. Atlas America - Series 24-2003(A) 14,363,955 292,830 14,363,955 513,540 95,344
45. Atlas America - Series 24-2003(B) 20,542,850 457,953 20,542,850 686,979 121,013
46. Atlas America - Public 12-2003 40,170,308 612,311 40,170,308 788,569 162,656
47. Atlas America Series # 25-2004(A) 27,601,053 202,616 27,601,053 233,236 41,775
48. Atlas America Series # 25-2004(B) 31,531,035 63,892 31,531,035 153,222 26,775
49. Atlas America Public # 14-2004 52,506,570 0 52,506,570 0 0
50. Atlas America Public # 14-2005(A) 69,674,900 0 0 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.
49
MANAGEMENT
MANAGING GENERAL PARTNER AND OPERATOR
The partnerships will have no officers, directors or employees. Instead, Atlas
Resources, Inc., a Pennsylvania corporation which was incorporated in 1979, will
serve as the managing general partner of each partnership. However, see "-
Transactions with Management and Affiliates" regarding the managing general
partner's dependence on its parent company, Atlas America, for management and
administrative functions and financing for capital expenditures. As of June 30,
2005, the managing general partner and its affiliates operated more than 5,100
natural gas and oil wells located in Ohio, Pennsylvania, New York and Tennessee.
Since 1985 the managing general partner has sponsored 14 public and 35 private
partnerships to conduct natural gas drilling and development activities in
Pennsylvania, Ohio, New York and Tennessee. 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, which was a subsidiary of Resource America, Inc., a publicly-traded
company, which is sometimes referred to in this prospectus as Resource America.
In May 2004 Resource America conducted a public offering of a portion of its
common stock (the "shares") in Atlas America. Two million six hundred forty-five
thousand shares were registered and sold at a price of at $15.50 per share
resulting in gross proceeds of $41 million. Further, in May 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.
After the public offering, Resource America continued to own approximately 80.2%
of Atlas America's common stock until it distributed all of its remaining 10.7
million shares of common stock in Atlas America to its common stockholders on
June 30, 2005. The distribution was in the form of a spin-off by means of a tax
free dividend of approximately 0.6 shares of Atlas America to Resource America
common stockholders for each share of Resource America common stock owned. The
managing general partner believes the principal effect on Atlas America of the
distribution of its shares by Resource America is that Resource America is no
longer in a position to determine the outcome of corporate actions requiring the
approval of Atlas America's stockholders, such as:
o the election and removal of directors;
o mergers or other business combinations involving Atlas
America;
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 are defined by agreements between Resource America and Atlas
America.
In connection with the spin-off, the following transactions were implemented:
o Atlas Energy Group, Inc., the driller and operator in Ohio and
a wholly-owned subsidiary of AIC, Inc., was acquired by merger
by Atlas America, with AIC, Inc. receiving shares of Atlas
America's common stock in return;
53
o Atlas Energy Group's subsidiary, AED Investments, Inc., became
a direct wholly-owned subsidiary of Atlas America, and Atlas
America assumed Atlas Energy Group's business as driller and
operator in Ohio; and
o Atlas Energy Holdings, Inc., a holding company which was
wholly-owned by Resource America, was merged into Resource
America and Atlas Energy Holdings ceased to exist.
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 49 Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas 46 Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons 47 Executive Vice President - Operations and a Director
Jack L. Hollander 49 Senior Vice President - Direct Participation Programs
Nancy J. McGurk 49 Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines 56 Senior Vice President, Secretary and a Director
Michael G. Hartzell 50 Vice President - Land Administration
Donald R. Laughlin 57 Vice President - Drilling and Production
Marci F. Bleichmar 35 Vice President of Marketing
Sherwood S. Lutz 54 Senior Geologist/Manager of Geology
Michael W. Brecko 47 Director of Energy Sales
Karen A. Black 45 Vice President - Partnership Administration
Justin T. Atkinson 32 Director of Due Diligence
Winifred C. Loncar 64 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 of Atlas America since February 2004, and served as a
director from September 2001 until February 2004 and served as Chief Financial
Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice
President of Resource America and President of Resource Leasing, Inc. (a
wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he
resigned from Resource America and all of its subsidiaries which are not
subsidiaries of Atlas America. Mr. Kotek was President of Resource Properties
from September 2000 to October 2001 and its Executive Vice President from 1993
to August 1999. Mr. Kotek received a Bachelor of Arts degree from Rutgers
College in 1977 with high honors in Economics. He also received a Master in
Business Administration degree from the Harvard Graduate School of Business
Administration in 1981. Mr. Kotek will devote approximately 95% of his
professional time to the business and affairs of the 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.
54
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 Bachelor of Science degree with honors in Petroleum Engineering
from Marietta College in 1981 and his Masters degree in Business Administration
from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his
professional time to the business and affairs of the 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 and the Chairman of the
Investment Program Association, which is an industry association, as of March
2005. Mr. Hollander devotes approximately 100% of his professional time to the
business and affairs of the 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.
55
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 received his Bachelor of Science degree in Business Management from the
University of Phoenix in 2004. 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. 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 19 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.
56
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 COMPANY
As of April 2005, the officers and directors for Atlas America include the
following:
NAME AGE POSITION
---- --- ---------
Edward E. Cohen 66 Chairman, Chief Executive Officer and President
Frank P. Carolas 46 Executive Vice President
Freddie M. Kotek 49 Executive Vice President
Jeffrey C. Simmons 47 Executive Vice President
Michael L. Staines 56 Executive Vice President and Secretary
Matthew A. Jones 43 Chief Financial Officer
Nancy J. McGurk 49 Senior Vice President and Chief Accounting Officer
Jonathan Z. Cohen 35 Vice Chairman
Carlton M. Arrendell 43 Director
William R. Bagnell 42 Director
Donald W. Delson 54 Director
Nicholas DiNubile 53 Director
Dennis A. Holtz 65 Director
57
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 March 31, 2005, the managing general partner and its affiliates under
Atlas America employed more than 205 persons and at September 30, 2004, Atlas
America and its affiliates had more than $778 million of energy assets under
management.
ORGANIZATIONAL DIAGRAM AND SECURITY OWNERSHIP OF BENEFICIAL OWNERS
Atlas America 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.
ORGANIZATIONAL DIAGRAM
[GRAPHIC OMITTED]
--------------------------------------
Atlas America, Inc. (Delaware)
(driller and operator in Ohio) (1)
--------------------------------------
|
-------------------------------------------------------------------------------------------------------------
| | | | | | |
- ------------------ --------------- ----------- -------------------- ---------------- --------------- -------------
Viking Atlas Pipeline AIC, Inc. Atlas America, Inc. Resource Energy, Atlas Noble AED
Resources Partners, GP, (Pennsylvania) Inc. (2) Corporation (2) Investments,
Corporation (2) LLC (operating company) Inc. (1)
- ------------------ ---------------- ------------ -------------------- ---------------- --------------- -------------
| --------------------------------------------------------------------------
---------------- | | | |
Atlas Pipeline ---------------------------- -------------------------- ------------- -----------------
Partners, LP Atlas Resources, Inc., Atlas Energy Corporation, Pennsylvania Anthem Securities,
--------------- managing general partner managing general partner Industrial Inc., registered
| of Atlas America Public of exploratory drilling Energy, Inc. broker/dealer and
----------------- #15-2005 Program, partnerships and driller and dealer-manager
Atlas Pipeline driller and operator operator
Operating in Pennsylvania ---------------------------- ------------ ------------------
Partnership, L.P. -----------------------------
----------------- |
|
-----------------------------
ARD Investments, Inc.
-----------------------------
- ---------
(1) See "- Managing General Partner and Operator," above, for a 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. 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.
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.
58
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 $23.2 million, $13.1
million, and $10.5 million for the years ended September 30, 2004, 2003, and
2002, respectively. (See "Financial Information Concerning the Managing General
Partner and Atlas America Public #15-2005(A) L.P.," including the indebtedness
owed by the managing general partner to Atlas America.)
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
Atlas America Public #15-2005(A) L.P., Atlas America Public #15-2006(B) L.P.,
Atlas America Public #15-2006(C) L.P. and Atlas America Public #15-2006(D) L.P.
have been formed as limited partnerships under the Delaware Revised Uniform
Limited Partnership Act. The partnerships, however, 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 #15-2005(A)
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.
The managing general partner believes that each partnership's liquidity
requirements will be satisfied from the following:
o subscription proceeds of this offering;
o the managing general partner's capital contributions;
o 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.
59
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 and various energy subsidiaries of Atlas
America are guarantors of the credit agreement. As of September 30, 2004, this
facility had a borrowing base of $75 million. 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 is a
default under the loan. The credit facility's term ends in March 2007. At
September 30, 2004, the borrower had an outstanding balance of approximately
$26.7 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 #15-2005(A)
L.P."
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.
60
Although the majority of the wells to be drilled by each partnership will be
classified as natural gas wells, which may produce a small amount of oil, some
of the wells, such as wells drilled 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 the partnership and is determined primarily by:
o the amount of subscription proceeds raised by the partnership;
o the geographical areas in which wells are drilled by the
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 partnership's wells, including any cost
overruns for intangible drilling costs and equipment costs of
the wells which are charged to you and the other investors
under the partnership agreement.
For the estimated number of wells to be drilled at the minimum subscription
proceeds of $2 million and the maximum subscription proceeds of $200 million for
a partnership, 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.
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
areas of operations discussed below in "- Primary Areas of Operations," 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 all of the specific wells to be
drilled by a partnership until the offering of units in that partnership has
ended. However, the managing general partner intends that Atlas America Public
#15-2005(A) L.P. will drill the prospects described in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #15-2005(A)
L.P." These prospects represent the wells to be drilled if a portion of the
nonbinding targeted subscription proceeds for that partnership, 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 the
partnerships designated Atlas America Public #15-2006(B) L.P., Atlas America
Public #15-2006(C) L.P. or Atlas America Public #15-2006(D) L.P. by a supplement
or an amendment to the registration statement of which this prospectus is a
part.
61
Because not all of the prospects for each partnership will be specified, you
will not be able to evaluate some, or even 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 is closed.
This section includes a general description of the areas where the managing
general partner anticipates partnership wells may be drilled. Other than the
north central Tennessee area, all of the primary areas are in western
Pennsylvania, as discussed below. The five primary areas for the partnerships'
drilling activities are:
o the Mississippian/Upper Devonian Sandstone reservoirs in
Fayette, Greene and Westmoreland Counties, Pennsylvania;
o the Clinton/Medina geological formation which includes western
Pennsylvania, primarily Crawford and Mercer Counties,
Pennsylvania and also includes an area in eastern Ohio
primarily in Stark, Mahoning, Trumbull and Portage Counties;
o the Upper Devonian Sandstone reservoirs in Armstrong and
Indiana Counties, Pennsylvania;
o the Upper Devonian Sandstone reservoirs in McKean County,
Pennsylvania; and
o the Mississippian (carbonates) and Devonian Shale reservoirs
in Anderson, Campbell, Morgan, Roane and Scott Counties,
Tennessee.
All of the primary areas described above 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 or oolite (carbonate 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;
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. Among the primary
areas, the managing general partner anticipates that each partnership will drill
more prospects in Fayette County than in the other areas.
62
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, Greene and
Westmoreland 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" until March 31,
2007.
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 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 Clinton/Medina is
described in petroleum industry terms as a "tight" sandstone with porosity
ranging from 6% to 12% and with very low natural 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 #15-2005(A) L.P." for a discussion of the
development of the Clinton/Medina Geological Formation in western Pennsylvania
and eastern Ohio.
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;
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
63
o primarily connected to the gathering system owned by Atlas
Pipeline Partners and have their natural gas production
primarily marketed to Amerada Hess 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. in
"Appendix A - Information Regarding Currently Proposed Prospects for Atlas
America Public #15-2005(A) L.P." for a discussion of the development of the
Upper Devonian Sandstone Reservoir in Armstrong and Indiana Counties,
Pennsylvania. The prospects in Armstrong and Indiana Counties, Pennsylvania were
acquired from U.S. Energy Exploration Corporation as described below in "-
Interests of Parties," and U.S. Energy will participate in the drilling of the
wells with the partnerships.
The wells in the Upper Devonian Sandstone reservoirs will be:
o situated on approximately 15 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. in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #15-2005(A)
L.P." 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 5 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
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."
64
MISSISSIPPIAN CARBONATE AND DEVONIAN SHALE RESERVOIRS IN ANDERSON, CAMPBELL,
MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE. The Mississippian carbonate
reservoirs are discontinuous lens shaped accumulations found in the southern
Appalachian states of West Virginia, Virginia, Kentucky and Tennessee. These
reservoirs have porosities ranging from 6% to 20% with attendant permeabilities.
The Devonian shale is found throughout the Appalachian Basin. When the shale is
highly fractured it becomes a reservoir. See the geologic evaluation prepared by
United Energy Development Consultants, Inc. in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #15-2005(A)
L.P." for a discussion of the development of the Mississippian carbonate and
Devonian Shale reservoirs in Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee.
The wells in the Mississippian carbonate and Devonian Shale reservoirs will be:
o situated on 40 acres;
o drilled 1,320 feet from each other unless topography dictates
otherwise, however, in all cases no less than 700 feet;
o drilled from approximately 2,000 to 4,600 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 Knox
Energy LLC, which is referred to as the Coalfield Pipeline,
and have their natural gas production primarily marketed to
Duke Energy as described below in "- Sale of Natural Gas and
Oil Production."
The prospects in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
were acquired from Knox Energy LLC as described below in "- Interests of
Parties" and Knox Energy may participate in the drilling of the wells with the
partnership.
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 or elsewhere in the United States. The secondary
areas anticipated by the managing general partner, which are situated in the
Appalachian Basin, 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 Amerada Hess Corporation, commercial end users in
the area, and/or 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;
65
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 marketed to Amerada Hess
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.
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 #15-2005(A) L.P. will drill the
prospects described in "Appendix A - Information Regarding Currently Proposed
Prospects for Atlas America Public #15-2005(A) L.P." The managing general
partner also anticipates that it will designate a portion of the prospects in
the partnerships designated Atlas America Public #15-2006(___) 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.
The majority 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 development prospects to be drilled by Atlas
America Public #15-2005(A) L.P. if it receives its targeted maximum subscription
proceeds of $50 million. With respect to the partnerships designated Atlas
America Public #15-2006(___) L.P., 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. Thus, the managing
general partner believes that it will have a sufficient number of development
prospects for each of those three partnerships if they receive their targeted
maximum subscription proceeds of $50 million each, although as of the date of
this prospectus the managing general partner and its affiliates do not hold a
sufficient number of development prospects for all of those partnerships. As of
September 30, 2004, the managing general partner's and its affiliates'
undeveloped leasehold acreage was as follows:
66
UNDEVELOPED LEASE ACREAGE
-----------------------------
GROSS NET (1)
-------- --------
Kentucky............................. 9,710 4,855
Montana.............................. 2,650 2,650
New York............................. 37,365 37,365
Ohio................................. 39,547 36,308
Pennsylvania......................... 149,613 149,613
West Virginia........................ 10,806 5,403
Wyoming.............................. 80 80
Total....................... 249,771 236,274
(1) The net acreage as to which leases expire in fiscal 2005 and 2006 are
as follows: New York: 2006 - 188 acres; Ohio: 2005 - 255 acres, 2006 -
96 acres; Pennsylvania: 2005 - 31,667 acres, 2006 - 25,274 acres.
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 which are classified as developmental. 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 "Federal Income
Tax Consequences - Farmouts."
DEEP DRILLING RIGHTS RETAINED BY MANAGING GENERAL PARTNER. The lease assignments
to each partnership generally will be limited to a depth of from the surface to
the deepest depth penetrated at the cessation of drilling operations. 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 the managing general partner undertakes any
activities with respect to the deeper formations in the future, 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.
67
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 five primary drilling areas. The fourth and fifth primary drilling areas in
Armstrong and Indiana Counties, Pennsylvania and Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee are 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 and Indiana
Counties, Pennsylvania and may be the case in Anderson, Campbell, Morgan, Roane
and Scott Counties, Tennessee, 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;
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, GREENE AND
WESTMORELAND 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 that the
partnership has a 100% working interest and the managing general partner
contributes its minimum required capital contribution of 25% to each
partnership and the capital contributions from you and the other
investors are 75%. 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 40% of
partnership revenues regardless of the amount of its capital
contributions.
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(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% assuming that the managing general partner's capital
contribution is 25% of that partnership's total capital contributions,
which means that the investors as a group receive 68% of that
partnership's revenues.
UPPER DEVONIAN SANDSTONE RESERVOIRS IN ARMSTRONG AND INDIANA COUNTIES,
PENNSYLVANIA. The managing general partner anticipates the leases in Armstrong
and Indiana Counties, 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 that a partnership has 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%.
MISSISSIPPIAN CARBONATE AND DEVONIAN SHALE RESERVOIRS IN ANDERSON, CAMPBELL,
MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE. Generally, the leases in north
central Tennessee will have a net revenue interest to a partnership ranging from
84.375% to 81.375%, assuming that a partnership has a 100% working interest.
Whether the amount of the partnership's net revenue interest in some of the
prospects will be as low as 81.375% depends primarily on whether the landowner
royalty interest is 12.5% or 15.5%, which in turn depends on whether the natural
gas produced from those prospects, if any, is sold at a price above or below
$3.00 per mcf, and on whether Knox Energy LLC and its affiliates, the
originators of the leases, participate as a working interest owner in the leases
covering those prospects. Knox Energy and its affiliates may retain up to a 50%
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. If Knox Energy does not retain a working interest in a well,
then its overriding royalty interest will be 3.125%. However, if Knox Energy
retains a 50% working interest in a well, then its overriding royalty interest
of 3.125% will be reduced to 1.5625%. To the extent that Knox Energy
participates in a well as a working interest owner for less than a 50% working
interest, the overriding royalty interest to Knox Energy will be prorated
between an overriding royalty interest of 3.125% and 1.5625%. The investors' net
revenue interest in the above example would range from 57.375% to 55.335% if
presented on a 100% working interest basis and the investors were receiving 68%
of the partnership revenues.
Pursuant to the acquisition terms between the managing general partner and its
affiliates and Knox Energy and its affiliates, no well drilled by the managing
general partner and its affiliates in this area may produce coalbed methane gas,
and the managing general partner or its affiliates must drill 300 commitment
wells during the initial three year term of the agreement with Knox Energy or it
is a breach of the agreement.
SECONDARY AREAS. Although the managing general partner anticipates that each
partnership will have a net revenue interest ranging from 81% to 87.5% in its
leases in the secondary areas described above, assuming 100% of the working
interest, 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 overriding royalty interests,
net profits interests, carried interests, production payments, reversionary
interests pursuant to farmouts or non-consent elections under joint operating
agreements, or 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 the managing general partner, the
operator, their affiliates, or 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 March 31, 2005 the previous partnerships sponsored by the managing general
partner and its affiliates have participated in drilling more than 3,376 wells
in the Appalachian Basin since 1985, and none of the wells have been lost
because of title failure. (See "Prior Activities.")
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DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS
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.
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, 2006 for Atlas
America Public #15-2005(A) L.P. and no later than March 31, 2007 for the
partnerships designated Atlas America Public #15-2006(___) L.P. (See "Federal
Income Tax Consequences - Drilling Contracts.")
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 unless the managing general partner
determines in its sole discretion that the well shall be completed in a
formation uphole from 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 the managing general partner 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.
70
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
"Compensation." 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 will 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 and this is the price which will be paid to each
partnership in the geographic area for its natural gas. For natural gas sold in
western Pennsylvania for its previous four fiscal years the managing general
partner received an average selling price after deducting all expenses,
including transportation expenses, of approximately:
o $4.08 per mcf, which means 1,000 cubic feet of natural gas, in
2001;
o $3.34 per mcf in 2002;
o $4.78 per mcf in 2003; and
o $5.64 per mcf in 2004.
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 March
31, 2005, the gathering system consisted of approximately 1,440 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 and the north central Tennessee 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. Also, in the north central
Tennessee area, the managing general partner and its affiliates may construct a
gathering system in the future for which it will receive gathering fees as
described in "Compensation - Gathering Fees."
71
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 certain commitments which were intended to maximize the use and
expansion of the gathering system. The only commitment which is still in effect
and which affects the partnerships is that 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 and the north central Tennessee area as described in "Compensation -
Gathering Fees," then Atlas America, Resource Energy or Viking Resources must
pay the difference to Atlas Pipeline Partners.
NATURAL GAS CONTRACTS. As set forth in "- Primary Areas of Operations," each
partnership has five primary areas where it will drill its wells, and the
managing general partner anticipates that initially there will be a different
natural gas purchaser in each area. Initially, the majority of each
partnership's natural gas production will be sold to UGI Energy Services, Inc.,
since 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, 2007. Also, the natural gas produced from Armstrong County will
be sold to U.S. Energy Exploration Corporation, the natural gas produced from
McKean County will be sold to M&M Royalty Ltd. and the natural gas produced from
north central Tennessee will be sold to Duke Energy. The managing general
partner anticipates that the remainder of the natural gas produced by the
partnership from wells drilled in the other primary area and the secondary areas
will be sold to Amerada Hess Corporation ("Amerada Hess") as discussed below.
Amerada Hess is a large, licensed natural gas supplier in the Ohio Valley and
along the east coast of the United States.
The managing general partner and its affiliates previously entered into a
10-year agreement with First Energy Solutions Corporation, which is the
marketing affiliate of First Energy Corporation, a large regional electric
utility. This agreement was recently sold by First Energy Solutions Corporation
to Amerada Hess effective April 1, 2005. Subject to the exceptions set forth
below, Amerada Hess has the right to buy all of the natural gas produced and
delivered by the managing general partner and its affiliates, which includes
each partnership and the managing general partner's other partnerships, at
certain delivery points with the facilities of East Ohio Gas Company, National
Fuel Gas Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which
are local distribution companies; and National Fuel Gas Supply, Columbia Gas
Transmission Corporation, Tennessee Gas Pipeline Company, and Texas Eastern
Transmission Company, which are interstate pipelines. This contract, which ends
April 1, 2009, is important to the managing general partner and its affiliates
because as of April 30, 2005 the managing general partner and its affiliates,
including its prior affiliated partnerships, were selling approximately 43% of
their natural gas production under the agreement with Amerada Hess and
implementing 62% of their physical natural gas hedges through Amerada Hess as
discussed below. However, as set forth above, each partnership will sell a much
smaller percentage of its natural gas to Amerada Hess because of certain
exceptions to the agreement, including natural gas sold through interconnects
established after the agreement which includes the majority of the natural gas
produced from wells in Fayette County, and natural gas produced from well(s)
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, Pennsylvania, McKean County, Pennsylvania, and north central
Tennessee.
The pricing and delivery arrangements with all of the natural gas purchasers,
including UGI Energy Services, Amerada Hess Corporation, U.S. Energy Exploration
Corporation, M&M Royalty Ltd., Duke Energy 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 and with 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 $0.34 to $0.65 per Mcf
during the past three fiscal years. These figures are based on the overall
weighted average that the managing general partner and its affiliates used in
their annual reserve reports for the past three fiscal years. Generally, the
purchase agreements may be suspended for force majeure, which generally means an
Act of God. See "- Policy of Treating All Wells Equally in a Geographic Area"
for the weighted average natural gas prices since 2001. As of July 15, 2005, the
agreements with UGI Energy Services and Amerada Hess are effective through March
31, 2007. Also, UGI Corporation has provided a $7 million guaranty of the
payment obligations of UGI Energy Services, Inc. until March 31, 2007, subject
to termination by UGI Corporation on 45 days prior written notice.
72
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
decreases in natural gas prices the managing general partner uses hedges through
its natural gas purchasers as described below, and through contracts such as
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.
UGI Energy Services, Amerada Hess Corporation 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 9, 2005, the majority of the managing general partner's hedges were
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 of natural gas than those projected to
be available at any delivery point. The price paid by UGI Energy Services,
Amerada Hess Corporation 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.) by the managing general partner changes from time to
time. As of June 9, 2005, the managing general partner's overall price hedging
position for the future months ending March 31, 2007 was approximately as
follows:
o 52% was hedged with a fixed price;
o 1% was hedged with a floor price and/or costless collar price;
and
o 47% was not hedged and was subject to market based pricing.
Approximately 62.4% of these hedges were implemented through Amerada Hess
Corporation and approximately 37.6% 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:
o gas marketers;
o local distribution companies;
o industrial or other end-users; and/or
o companies generating electricity.
73
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 received an
average selling price for oil for its previous four fiscal years of
approximately $22.60 per barrel in 2001; $18.92 per barrel in 2002; $29.06 per
barrel in 2003; and $34.41 per barrel in 2004. 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 more than 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. In February
2004, one of the wells in another investment partnership incurred an
uncontrolled flow of natural gas and oil with a fire during drilling. These
problems with the well were subsequently controlled, but they resulted in the
loss of a subcontractor's drilling rig and third-party claims. As of April 19,
2005, the managing general partner's insurance carrier had paid approximately
$1.6 million to third-parties for property damage claims 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 for a partnership's benefit.
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 as discussed in "Compensation."
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.
Natural gas prices have not been regulated since 1993, and the price of natural
gas is subject to the supply and demand for 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.
74
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 2004 there
were 23 quadrillion BTU of natural gas consumed in the United States which
represented approximately 23% of the total energy used. The Appalachian Basin
accounted for approximately 5.1% of the total domestic natural gas production in
the United States in 2003. Also, according to the Natural Gas Annual 2003
Report, which is published by the Energy Information Administration Office of
Oil and Gas, as of December 31, 2004, the Appalachian Basin's economically
recoverable natural gas reserves represented approximately 7.7% of total
domestic natural gas reserves. Further, World Oil magazine predicted in its
February 2004 issue that approximately 5,576 oil and gas wells would be drilled
in the Appalachian Basin during 2004, representing approximately 16.7% of the
total number of wells it predicted would be drilled in the United States during
2004.
The natural gas and oil 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 that the partnerships' intended operations will be a significant
factor in the industry.
The natural gas and oil industry has from time to time experienced periods of
rapid cost increases. The increase in natural gas and oil prices over the last
several years currently has increased the demand for drilling rigs and other
related equipment, and the costs of drilling and completing natural gas and oil
wells also have increased. Additionally, the managing general partner and its
affiliates have experienced an increase in the cost of tubular steel used in
drilling the wells as a result of rising steel prices. Because each
partnership's wells will be drilled on a cost plus basis as described in
"Compensation - Drilling Contracts," these increased costs will increase the
cost to drill and complete the wells. Also, the reduced availability of drilling
rigs and other related equipment may make it more difficult to drill each
partnership's wells in a timely manner or to comply with the prepaid intangible
drilling costs rules discussed in "Federal Income Tax Consequences - Drilling
Contracts." Further, over the term of each 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.
The natural gas and oil produced by your partnership's wells must be marketed
for you to receive revenues. During the fiscal years ending 2004, 2003, and
2002, 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 partnerships' and
the managing general partner'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 managing general partner and the partnerships and cannot be
accurately predicted, are the following:
o the proximity, availability, and capacity of pipelines 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;
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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 or terrorist acts 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 and other countries
(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. From time to
time since then there have been increased imports of Canadian natural gas into
the United States. 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. According to the Annual Energy Outlook 2005
with Projections to 2025 recently published by the Energy Information
Administration (EIA), total natural gas consumption is projected to increase
from 22.0 trillion cubic feet in 2003 to 30.7 trillion cubic feet by 2025. Over
that same period, total natural gas supplies are projected to grow by 8.2
trillion cubic feet, with domestic natural gas production expected to account
for 34% percent of the total growth in gas supply, and net imports projected to
account for the remaining 66%. Notwithstanding, wellhead natural gas prices are
projected to decline in the early years of the forecast, as drilling levels
increase, new production capacity comes on line, and liquid natural gas ("LNG")
imports increase in response to current high prices. After 2011, however,
natural gas prices are projected to increase in response to the higher
exploration and development costs associated with smaller and deeper natural gas
deposits in the remaining domestic natural gas resource base. Also, the managing
general partner believes there have been several developments which may increase
the demand for natural gas, but may or may not be offset by an increase in the
supply of natural gas, which the managing general partner is unable to predict.
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 electric industries. In 2004, 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 17.6%;
o coal-fired power plants were used to produce approximately
50%;
o nuclear power plants were used to produce approximately 20%;
and
o large scale hydroelectric projects were used to produce
approximately 7%.
In recent years, the electric industry has increased its reliance on natural gas
because of increased competition in the electric industry and the enforcement of
stringent environmental regulations. For example, the Environmental Protection
Agency has sought to enforce environmental regulations which increase the cost
of operating coal-fired power plants. According to the Energy Information
Administration, the demand for natural gas by producers of electricity is
expected to increase through the decade. 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 and the recent energy act includes
tax credits for constructing new nuclear power plants. The managing general
partner believes that natural gas is the preferred fuel for producers of
electricity since they have started moving away from dirtier-burning fuels, such
as coal and oil. 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.
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STATE REGULATIONS
Natural gas and oil 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.
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. In addition, 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.
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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;
o changes in the tax laws as discussed in "Federal Income Tax
Consequences - Changes in the Law"; and
o tax credits and other incentives for the creation or expansion
of alternative energy sources.
Also, Congress could re-enact price controls for natural gas 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 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 due diligence expenses, and the
.5% accountable reimbursement for permissible non-cash
compensation.
The managing general partner will pay a portion of a partnership's
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 to it by the
managing general partner. The managing general partner will be credited
with a capital contribution for each lease valued at:
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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. Ninety percent of the subscription proceeds of
you and the other investors in a partnership will be used to pay 100% of
the intangible drilling costs incurred by that partnership in drilling and
completing its wells.
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, 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 not be currently
deductible, such as equipment costs and/or lease acquisition 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.
The allocation of each partnership's costs of drilling and completing its wells
between intangible drilling costs, as defined in the partnership agreement, and
equipment costs, as defined as "tangible costs" in the partnership agreement, is
made by the managing general partner, in its sole discretion, when the wells are
drilled.
4. EQUIPMENT COSTS. Ten percent of the subscription proceeds of you and the
other investors in a partnership will be used to pay a portion of the
equipment costs of that partnership. All equipment costs of that
partnership's wells that exceed 10% of the subscription proceeds of you
and the other investors in the partnership will be charged to the managing
general partner.
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
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 will be shared based
on the total amount of the actual equipment costs paid by the managing
general partner, which will in all events be a majority of total actual
equipment costs, as compared to the total amount of the actual equipment
costs paid by you and the other investors, towards this obligation. 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.
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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 the managing general partner's share of revenues, and
that portion 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 required 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 an unaccountable 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.
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 40% 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 35% of the
total partnership capital contributions and the investors contribute 65%
of the total partnership capital contributions, then the managing general
partner will receive 40% of the partnership revenues, not 42%, because its
revenue share cannot exceed 40% of partnership revenues, and the investors
will receive 60% of partnership revenues.
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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% of capital, 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, as managing general partner, of
partnership net production revenues, which will be up to between 16% and 20% of
the total partnership net production revenues, depending on the amount of its
capital contributions, 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. 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, such as the volume
of natural gas and oil produced from the partnership's wells, are unable to
provide the required return of capital. 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 June 15, 2005, the managing general partner was not subordinating any of
its net revenues in 15 limited partnerships that currently have the
subordination feature in effect. Since 1993 the managing general partner has had
a subordination feature in 31 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.
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 40% of
partnership revenues regardless of the amount of its capital
contribution.
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(2) Each partnership is structured to provide you and the other investors
with cash distributions equal to a minimum of 10% of capital, 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 of a 10% return of capital for each of the first
five 12-month periods, the managing general partner will subordinate up
to 50% of its share of partnership net production revenues, which will be
up to between 16% and 20% of the total partnership net production
revenues, depending on the amount of its capital contributions, during
this subordination period.
EXAMPLE OF NET REVENUE SHARING AFTER THE END OF A SUBORDINATION PERIOD.
MAXIMUM AMOUNT OF NET REVENUES TO MANAGING
MANAGING GENERAL GENERAL PARTNER AND
PERCENTAGE OF PERCENTAGE OF PARTNER'S SHARE OF INVESTORS WHEN NONE OF
PARTNERSHIP PARTNERSHIP NET PARTNERSHIP NET MANAGING GENERAL PARTNER'S
CAPITAL REVENUES WITHOUT REVENUES AVAILABLE FOR SHARE OF PARTNERSHIP NET
ENTITY CONTRIBUTIONS (1) SUBORDINATION (1) SUBORDINATION REVENUES IS 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 40% 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.
MANAGING
GENERAL
PARTNER INVESTORS
--------- ----------
PARTNERSHIP COSTS
Organization and offering costs.....................................................100% 0%
Lease costs.........................................................................100% 0%
Intangible drilling costs (1).........................................................0% 100%
Equipment costs......................................................................(2) (2)
Operating costs, administrative costs, direct costs, and all other costs.............(3) (3)
PARTNERSHIP REVENUES
Interest income......................................................................(4) (4)
Equipment proceeds...................................................................(2) (2)
All other revenues including production revenues..................................(5)(6) (5)(6)
PARTICIPATION IN DEDUCTIONS AND CREDITS
Intangible drilling costs.............................................................0% 100%
Depreciation.........................................................................(2) (2)
Percentage depletion allowance.................................................(5)(6)(7) (5)(6)(7)
Marginal well production credits.............................................. (5)(6)(7) (5)(6)(7)
- -----------
(1) Ninety percent of the subscription proceeds of you and the other
investors in a partnership will be used to pay 100% of the intangible
drilling costs incurred by that partnership in drilling and completing
its wells.
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(2) Ten percent of the subscription proceeds of you and the other investors
in a partnership will be used to pay a portion of the equipment costs
incurred by that partnership in drilling and completing its wells. All
equipment costs in excess of 10% of that partnership's subscription
proceeds will be paid by the managing general partner. Thus, the
managing general partner will pay the majority of a partnership's
equipment costs. Equipment proceeds, if any, will be credited in the
same percentage in which the equipment costs were charged. Thus, the
managing general partner will receive the majority of any equipment
proceeds.
(3) 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.
(4) 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.
(5) 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 40% of partnership revenues.
(6) 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 (5) above.
(7) The percentage depletion allowances and any marginal well production
credits 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, marginal well production credits, 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 set forth on the subscription agreement 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 discounted 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 as set forth above,
except that these allocations will be based on the respective subscription price
you and the other investors paid for the units as set forth on the subscription
agreements rather than $10,000 per unit for all units.
DISTRIBUTIONS
The managing general partner will review each partnership's accounts at least
monthly 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;
83
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 positive capital account bears to all
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.
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.
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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.
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 and the partnership
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.
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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
which 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.
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:
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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. Also, as discussed in "Proposed Activities," the managing
general partner has a drilling commitment with Knox Energy for the drilling of
200 wells, which creates a conflict of interest in deciding whether each
partnership will drill wells in the areas that will help the managing general
partner satisfy this drilling commitment.
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. 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;
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.
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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.
The managing general partner believes that for a prospect located in
the primary drilling areas as described in "Proposed Activities -
Primary Areas of Operations," 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.
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In the primary areas the managing general partner anticipates that the
drilling of these wells by each partnership 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
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.
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:
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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
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.
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(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:
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 for units by the managing general partner, its officers,
directors, or affiliates in the partnership in which you invest 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."
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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 bona fide 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 OR ASSIGNING AN
INTEREST
A conflict of interest is created with you and the other investors by the
managing general partner's right to mortgage its managing general partner
interest in each partnership or, subject to a 1% participation as managing
general partner, to 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 or to assign, subject to the managing general partner's
subordination obligation, its remaining managing general partner interest in
each partnership to its affiliates which also may mortgage the interests as
collateral for their loans, if any. If there was a default under a loan to the
managing general partner, or an affiliated assignee if a portion of the managing
general partner's interest was assigned, this could reduce or eliminate the
amount of the partnership net production revenues available to the managing
general partner or the affiliated assignee for their respective subordination
obligations to you and the other investors. Also, under certain circumstances,
if the managing general partner or an affiliated assignee, if a portion of the
managing general partner's partnership interest was assigned, made a
subordination distribution to you and the other investors in that partnership
after a default under the loan, then the lender may be able to recoup that
subordination distribution from you and the other investors.
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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.
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:
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;
93
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:
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:
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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;
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
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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, which is commonly referred to as the
"business judgment rule." This rule provides 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. This is a rapidly expanding and
changing area of the law, and if you have questions concerning the managing
general partner's duties you are urged to consult your own counsel.
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 partnership's tangible net assets, which include its
revenues and 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. 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.
96
The effect of the foregoing provisions and the business judgment rule may be to
limit your recourse against the managing general partner.
FEDERAL INCOME TAX CONSEQUENCES
INTRODUCTION
The managing general partner has obtained a tax opinion letter from Kunzman &
Bollinger, Inc., special counsel for this offering, with respect to the material
federal income tax consequences of an investment in a partnership by a "typical
investor" as that term is defined in "- Managing General Partner's
Representations," below. Accordingly, the managing general partner will rely on
special counsel's tax opinion letter, and no advance ruling on any tax
consequence of an investment in a partnership will be requested from the IRS.
This section of this prospectus is a summary of special counsel's tax opinion
letter. You are urged to read the entire tax opinion letter, which has been
filed as Exhibit 8 to the registration statement of which this prospectus is a
part. (See "Additional Information," for information on how to obtain a copy of
special counsel's tax opinion letter.)
Although special counsel's tax opinions express what it believes a court would
probably conclude if presented with the applicable federal tax issues, special
counsel's tax opinions are only predictions, and are not guarantees, of the
outcome of the particular tax issues being addressed. The IRS could challenge
special counsel's tax opinions, and the challenge could be sustained in the
courts if litigated and cause adverse tax consequences to you and your
partnership's other investors. Special counsel's tax opinions are based in part
on representations and statements made by the managing general partner in the
tax opinion letter and in this prospectus, including forward looking statements
relating to the partnership and its proposed activities. (See "Forward Looking
Statements and Associated Risks.") Following "- Special Counsel's Opinions,"
below, is a section entitled "Summary Discussion of the Federal Income Tax
Consequences of an Investment in a Partnership by a Typical Investor ("Summary
Discussion").
DISCLOSURES AND LIMITATION ON USE OF TAX OPINION LETTER The following
disclosures are made in special counsel's tax opinion letter.
o The tax opinion letter was written to support the marketing of
units in the partnerships to potential investors, and special
counsel has helped the managing general partner organize and
document the offering of units in the partnerships.
o The tax opinion letter is not confidential. There are no
limitations on the disclosure by any potential investor in a
partnership to any other person of the tax treatment or tax
structure of the partnerships or the contents of the tax
opinion letter.
o Investors in a partnership have no contractual protection
against the possibility that a portion or all of their
intended tax benefits from an investment in the partnership
ultimately are not sustained if challenged by the IRS. (See
"Risk Factors - Tax Risks - Your Tax Benefits from an
Investment in a Partnership Are Not Contractually Protected.")
o Because special counsel has entered into a compensation
arrangement with the managing general partner to provide the
legal services to the partnerships discussed above, its tax
opinion letter was not written, and cannot be used by you and
the other investors in the partnerships, for the purpose of
establishing your reasonable belief that your tax treatment of
any partnership tax item on your individual federal income tax
returns was more likely than not the proper treatment in order
to avoid any reportable transaction understatement penalty
under ss.6662A of the Internal Revenue Code (the "Code").
Thus, each potential investor in a partnership is urged to
seek advice from an independent tax advisor with respect to
whether an investment in a partnership would subject the
investor to that penalty.
97
o Each potential investor in a partnership is urged to seek
advice based on his particular circumstances from an
independent tax advisor with respect to the federal tax
consequences to him of an investment in a partnership.
Set forth below is a synopsis of the principal assumptions made by special
counsel and the principal representations made the managing general partner on
which special counsel relied in giving its tax opinion letter.
SPECIAL COUNSEL'S ASSUMPTIONS
In giving its opinions, special counsel made the principal assumptions
summarized below.
o You will not borrow money to buy units in a partnership from
any other investor in the same partnership.
o You will be personally liable to repay any money you borrow to
buy units in a partnership.
o You will not protect yourself through nonrecourse financing,
guarantees, stop loss agreements or other similar arrangements
from losing the money you invest in a partnership.
MANAGING GENERAL PARTNER'S REPRESENTATIONS
In giving its opinions, special counsel relied on representations from the
managing general partner set forth in the tax opinion letter, including the
principal representations summarized below.
o A "typical investor" in each partnership will be a natural
person who purchases units in this offering and is a U.S.
citizen.
o Each partnership will operate its business as described in
this prospectus and in accordance with the terms of the
partnership agreement, the drilling and operating agreement
and any applicable limited partnership acts.
o The investor general partner units in each partnership will be
converted to limited partner units after all of the wells in
that partnership have been drilled and completed. In this
regard, the managing general partner anticipates that all of
the productive wells in each partnership will be drilled and
completed no more than 12 months after that partnership's
final closing, and the conversion will then follow.
o Each partnership will elect to currently deduct all of the
intangible drilling costs of all of its wells.
o The managing general partner anticipates that all of each
partnership's subscription proceeds will be expended in the
year in which the units in that partnership are offered for
sale, and you will include your share of your partnership's
deduction for intangible drilling costs on your individual
federal income tax return for that year, subject to your right
to elect to capitalize and amortize over a 60-month period a
portion or all of your share of your partnership's deduction
for intangible drilling costs.
o Depending primarily on when its subscription proceeds are
received, the managing general partner anticipates that Atlas
America Public #15-2005(A) L.P. may prepay in 2005 most, if
not all, of its intangible drilling costs for wells the
drilling of which will not begin until 2006, and that any one
of the partnerships designated Atlas America Public
#15-2006(___) L.P. may prepay in 2006 most, if not all, of its
intangible drilling costs for wells the drilling of which will
not begin until 2007.
o Each partnership will have a calendar year taxable year.
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o The managing general partner anticipates that most, if not
all, of each partnership's natural gas and oil production will
be marginal production which will qualify for potentially
higher rates of percentage depletion and potentially available
marginal well production credits.
o The principal purpose of each partnership is to locate,
produce and market natural gas and oil on a profitable basis
to its investors, apart from tax benefits, as discussed in
this prospectus.
o Each partnership's total abandonment losses under ss.165 of
the Code, which could include, for example, the abandonment by
a partnership of wells drilled which are nonproductive (i.e. a
"dry hole"), or the abandonment by a partnership of productive
wells which have been operated until their commercial natural
gas and oil reserves have been depleted, will be less than $2
million, in the aggregate, in any taxable year of the
partnership and less than $4 million, in the aggregate, during
the partnership's first six taxable years.
Additional details, assumptions of special counsel, representations of the
managing general partner, and other matters affecting special counsel's opinions
are contained in special counsel's tax opinion letter. You are urged to obtain a
copy of the tax opinion letter from the managing general partner or the SEC, as
set forth in "Additional Information," and read the entire tax opinion letter to
assist your understanding of the federal tax benefits and risks of an investment
in a partnership.
SPECIAL COUNSEL'S OPINIONS
Taxpayers bear the burden of proof to support claimed deductions and tax
credits, and special counsel's opinions are not binding on the IRS or the
courts. Special counsel's tax opinions with respect to an investment in a
partnership by a typical investor, who is sometimes referred to in special
counsel's opinions as a "Participant," "Investor General Partner" or "Limited
Partner," are set forth below.
(1) PARTNERSHIP CLASSIFICATION. Each Partnership will be
classified as a partnership for federal income tax purposes,
and not as a corporation.
(See "- Partnership Classification" in the Summary
Discussion.)
(2) LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS.
o The passive activity limitations on losses and
credits under ss.469 of the Code will apply to:
o the Limited Partners in a Partnership; and
o will not apply to the Investor General
Partners in a Partnership until after the
conversion of the Investor General Partner
Units to Limited Partner Units in the
Partnership.
o A Partnership's income, gains, and credits, if any,
from its natural gas and oil properties which are
allocated to its Limited Partners, other than net
income and any related credits allocated to former
Investor General Partners who have been converted to
Limited Partners, will be characterized,
respectively, as:
o passive activity income and gains which a
Limited Partner may use to offset a portion
or all of his passive activity losses, if
any, except passive activity losses from
publicly traded partnership passive
activities; and
o passive activity credits which a Limited
Partner may use to offset a portion or all
of the Limited Partner's regular federal
income tax liability attributable to net
passive income received by the Limited
Partner from the Partnership or his other
passive activities, if any, except publicly
traded partnership passive activities.
99
o Income or gains attributable to investments of
working capital of a Partnership will be
characterized as portfolio income, which cannot be
offset by passive losses or credits, and will not
generate any marginal well production credits.
For a discussion of the passive activity limitations on losses
and credits and the types of entities whose investments in a
Partnership also will be subject to the passive activity
limitations on losses and credits, see "- Limitations on
Passive Activity Losses and Credits" in the Summary
Discussion.
(3) NOT A PUBLICLY TRADED PARTNERSHIP. None of the Partnerships
will be treated as a publicly traded partnership under the
Code.
(See "- Publicly Traded Partnership Rules" in the Summary
Discussion.)
(4) BUSINESS EXPENSES. 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 Offering Costs and
other items which are required to be capitalized, are
currently deductible.
o POTENTIAL LIMITATIONS ON DEDUCTIONS. A Participant's
ability in any taxable year to use the Participant's
share of these Partnership deductions on the
Participant's individual federal income tax returns
may be reduced, eliminated or deferred by the
following limitations:
o the Participant's personal tax situation,
such as the amount of the Participant's
regular taxable income, alternative minimum
taxable income, losses, deductions,
exemptions, etc., which are not related to
the Participant's investment in a
Partnership;
o the amount of the Participant's adjusted
basis in the Participant's Units at the end
of the Partnership's taxable year;
o the amount of the Participant's "at risk"
amount in the Partnership in which he
invests at the end of the Partnership's
taxable year; and
o the passive activity limitations on losses
and credits in the case of the Limited
Partners (including the Investor General
Partners after their Units are converted to
Limited Partner Units by their Partnership)
who are natural persons, or that are
entities which also are subject to the
passive activity limitations on losses and
credits.
See "- Limitations on Passive Activity Losses and Credits," "-
Business Expenses," "- Tax Basis of Units," "- `At Risk'
Limitation on Losses," and "- Alternative Minimum Tax" in the
Summary Discussion.
(5) INTANGIBLE DRILLING COSTS. Although each Partnership will
elect to deduct currently all of its Intangible Drilling
Costs, each Participant in a Partnership may still elect to
capitalize and deduct all or part of his share of his
Partnership's Intangible Drilling Costs (other than drilling
and completion costs of a re-entry well that are not related
to deepening the well, if any) 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 by Participants who
elect to currently deduct their share of their Partnership's
Intangible Drilling Costs in the taxable year in which the
payments are made and the drilling services are rendered.
(See "- Intangible Drilling Costs" in the Summary Discussion.)
100
A Participant's ability in any taxable year to use the
Participant's share of these Partnership deductions on the
Participant's personal federal income tax returns may be
reduced, eliminated or deferred by the "Potential Limitations
on Deductions" set forth in opinion (4) above.
(6) PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Subject to each
Participant's election to capitalize and amortize a portion or
all of the Participant's share of his Partnership's Intangible
Drilling Costs as set forth in opinion (5) above, any
prepayments by a Partnership in the year in which its
Participants invest in the Partnership of Intangible Drilling
Costs for wells the drilling of which will begin after
December 31 of the year in which the Participants invest in
the Partnership, but on or before March 31 of the immediately
following year, will be deductible by the Participants in that
Partnership in the year in which they invest in that
Partnership.
(See "- Drilling Contracts" in the Summary Discussion.)
A Participant's ability in any taxable year to use the
Participant's share of these Partnership deductions on the
Participant's personal federal income tax returns may be
reduced, eliminated or deferred by the "Potential Limitations
on Deductions" set forth in opinion (4) above.
(7) DEPLETION ALLOWANCE. The greater of the cost depletion
allowance or the percentage depletion allowance 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 the following restrictions:
o a Participant's cost depletion allowance cannot
exceed the Participant's share of the adjusted tax
basis of the natural gas or oil property to which it
relates; and
o a Participant's percentage depletion allowance:
o may not exceed 100% of the Participant's
share of his Partnership's taxable income
from each natural gas and oil property
before the deduction for depletion, however,
this limitation is suspended in 2005 with
respect to marginal properties; and
o is limited to 65% of the Participant's
taxable income for the year computed without
regard to percentage depletion, net
operating loss carry-backs and capital loss
carry-backs and, in the case of a
Participant that is a trust, any
distributions to its beneficiaries.
See "- Depletion Allowance" in the Summary Discussion.
(8) MACRS. Each Partnership's reasonable Tangible Costs for
equipment placed in its productive wells which cannot be
deducted immediately will be eligible for cost recovery
deductions under the Modified Accelerated Cost Recovery System
("MACRS") over a seven year "cost recovery period" on a
well-by-well basis, beginning in the taxable year each well is
drilled, completed and made capable of production, i.e. placed
in service. (See "- Depreciation and Cost Recovery Deductions"
in the Summary Discussion.)
A Participant's ability in any taxable year to use the
Participant's share of these Partnership deductions on the
Participant's personal federal income tax returns may be
reduced, eliminated or deferred by the "Potential Limitations
on Deductions" set forth in opinion (4), above.
(9) TAX BASIS OF UNITS. Each Participant's initial adjusted tax
basis in his Units will be the amount of money that the
Participant paid for his Units.
(See "- Tax Basis of Units" in the Summary Discussion.)
101
(10) AT RISK LIMITATION ON LOSSES. Each Participant's initial "at
risk" amount in the Partnership in which he invests will be
the amount of money that the Participant paid for his Units.
(See "- `At Risk' Limitation on Losses" in the Summary
Discussion.)
(11) ALLOCATIONS. The allocations of income, gain, loss, deduction,
and credit, or items thereof, and distributions set forth in
the Partnership Agreement for each Partnership, including the
allocations of basis and amount realized with respect to a
Partnership's natural gas and oil properties, will govern each
Participant's allocable share of those items to the extent the
allocations do not cause or increase a deficit balance in his
Capital Account in the Partnership in which he invests.
(See "- Allocations" in the Summary Discussion.)
(12) SUBSCRIPTION. No gain or loss will be recognized by the
Participants on payment of their subscriptions to the
Partnership in which they invest.
(13) PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND POTENTIALLY RELEVANT
JUDICIAL DOCTRINES. The Partnerships will possess the
requisite profit motive under ss.183 of the Code. Also, the
IRS anti-abuse rule in Treas. Reg. ss.1.701-2 and potentially
relevant judicial doctrines will not have a material adverse
effect on the tax consequences of an investment in a
Partnership by a Participant as described in our opinions.
(See "- Profit Motive, IRS Anti-Abuse Rule and Judicial
Doctrines Limitations on Deductions" in the Summary
Discussion.)
(14) REPORTABLE TRANSACTIONS. The Partnerships are not, and should
not be in the future, reportable transactions under
ss.6707A(c) of the Code. However, because special counsel has
entered into a compensation arrangement with the managing
general partner to provide certain legal services to the
partnerships, its tax opinion letter was not written, and
cannot be used by you or the other investors in the
partnerships, for the purpose of establishing your reasonable
belief that your tax treatment of any partnership tax item on
your individual federal income tax returns was more likely
than not the proper treatment in order to avoid any reportable
transaction understatement penalty under ss.6662A of the Code.
Thus, each potential investor in a partnership is urged to
seek advice from an independent tax advisor with respect to
whether an investment in a partnership would subject the
investor to that penalty.
(See "- Federal Interest and Tax Penalties" in the Summary
Discussion.)
(15) OVERALL CONCLUSION. Our overall conclusion is that the federal
tax treatment of a typical Participant's investment in a
Partnership as set forth in our opinions above is the proper
federal tax treatment and will be upheld on the merits if
challenged by the IRS and litigated. Our evaluation of the
federal income tax laws and the expected activities of the
Partnerships as represented to us by the Managing General
Partner in this tax opinion letter and as described in the
Prospectus causes us to believe that the deduction by a
typical Participant of all, or substantially all, of his
allocable share of his Partnership's Intangible Drilling Costs
in the year in which he invests in the Partnership (even if
the drilling of most or all of his Partnership's wells begins
after December 31 of the year in which he invests, but on or
before March 31 of the immediately following year), as set
forth in opinions (5) and (6) above, is the principal tax
benefit offered by the Partnerships to potential Participants
and also is the proper federal tax treatment, subject to each
Participant's election to capitalize and amortize a portion or
all of the Participant's share of the deduction for Intangible
Drilling Costs of the Partnership in which he invests as
discussed in "- Alternative Minimum Tax" in the Summary
Discussion.
A Participant's ability in any taxable year to use the
Participant's share of these Partnership deductions on the
Participant's personal federal income tax returns may be
reduced, eliminated or deferred by the "Potential Limitations
on Deductions" set forth in opinion (4), above.
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The discussion in this prospectus under the caption "FEDERAL
INCOME TAX CONSEQUENCES," insofar as it contains statements of
federal income tax law, is correct in all material respects.
SUMMARY DISCUSSION OF THE FEDERAL INCOME TAX CONSEQUENCES OF AN INVESTMENT
IN A PARTNERSHIP BY A TYPICAL INVESTOR ("SUMMARY DISCUSSION")
INTRODUCTION
Special counsel's tax opinions are limited to those set forth above. The
following is a summary discussion of all of the material federal income tax
consequences, and any significant federal tax issues, relating to the purchase,
ownership and disposition of investor general partner units and limited partner
units which will apply to typical investors in each partnership. Except as
otherwise noted below, however, different tax considerations from those
discussed below may apply to foreign persons, corporations, partnerships, trusts
and other prospective investors which are not treated as typical investors 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 aspects 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. In addition, the IRS may challenge the deductions, and
credits, if any, claimed by a partnership or you and the other investors in a
partnership, or the taxable year in which the deductions, and credits, if any,
are claimed, and it is possible that the challenge would be upheld if litigated.
Accordingly, you are urged to seek qualified, professional advice based on your
particular circumstances from an independent tax advisor in evaluating the
potential tax consequences to you of an investment in a partnership.
PARTNERSHIP CLASSIFICATION
For federal income tax purposes a partnership is not a taxable entity. Thus, the
partners, rather than the partnership, receive and report any deductions and tax
credits, if any, as well as the income, from a partnership's operations. A
business entity with two or more members is classified for federal tax purposes
as either a corporation or a partnership. Each partnership has been 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 for federal tax purposes since
the managing general partner has represented that no partnership will elect to
be taxed as a corporation. As a result, the managing general partner anticipates
that all of the subscription proceeds of each partnership will be expended in
the year in which their units were offered for sale, and the related income, if
any, and deductions, including the deduction for intangible drilling costs, will
be reflected on their investors' federal income tax returns for that period.
LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS
Under the passive activity rules of the 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. Similar rules apply with
respect to tax credits. (See "- Marginal Well Production Credits," below.)
Suspended passive losses and passive credits which an investor cannot use in his
current tax year may be carried forward indefinitely, but not back, and used to
offset future years' passive activity income, or offset passive activity regular
federal income tax liability (in the case of passive activity credits).
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. Thus, if you are an individual and you
invest in a partnership as a limited partner, your investment in the partnership
will be subject to the passive activity limitations. The passive activity rules
also apply to other types of investors which invest in a partnership as limited
partners, including, for example, trusts, partnerships some types of limited
liability companies which elect to be treated as corporations for federal tax
purposes, and some types of corporations, as described in more detail in "Risk
Factors - Tax Risks - Limited Partners Need Passive Income to Use Their
Deduction for Intangible Drilling Costs."
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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 by the 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 and any credits from their partnership will
not be treated as passive deductions or credits under the Code before the
conversion, unless they invest in a partnership through an entity which limits
their liability. For example, if an individual invests in a partnership
indirectly as an investor general partner by using an entity which limits his
personal liability under state law to purchase his units, such as a limited
partnership in which he is not a general partner, a limited liability company or
an S corporation, he will be subject to the passive activity limitations the
same as a limited partner. (See "- Conversion from Investor General Partner to
Limited Partner" and "- Marginal Well Production Credits," below.)
Contractual limitations on the liability of investor general partners under the
partnership agreement, such as insurance, limited indemnification by the
managing general partner, etc., as compared with limitations on liability under
state law as discussed above, will not cause investor general partners to be
subject to the passive activity limitations on losses and credits. Investor
general partners, however, may be subject to an additional limitation on their
deduction of investment interest expense as a result of their non-passive
deduction of intangible drilling costs. (See "- Limitations on Deduction of
Investment Interest," below.)
PUBLICLY TRADED PARTNERSHIP RULES
Net losses and most net credits of a partner from a publicly traded partnership
are suspended and carried forward to be netted against income or regular federal
income tax liability, respectively, 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 in which interests in the partnership are traded on
an established securities market, or in which interests in the partnership are
readily tradable on either a secondary market or the substantial equivalent of a
secondary market. However, in special counsel's opinion no partnership will be
treated as a publicly traded partnership under the Code. This opinion is based
primarily on the substantial restrictions in the partnership agreement on the
ability of you and the other investors to transfer your units in your
partnership. (See "Transferability of Units - Restrictions on Transfer Imposed
by the Securities Laws, the Tax Laws and the Partnership Agreement.") Also, the
managing general partner has represented that no partnership's units will be
traded on an established securities market.
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 in your partnership will not be subject to the passive activity
limitations on losses and credits. This is because the investor general partner
units in each partnership will not be converted to limited partner units until
after all of the wells in that partnership have been drilled and completed. The
managing general partner anticipates that all of the wells in each partnership
will be drilled and completed no more than 12 months after the final closing of
that partnership and the conversion will then follow. (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.
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Concurrently, the former investor general partner will become subject to the
passive activity limitations on losses and credits as a limited partner.
However, the former investor general partner previously will have received a
non-passive loss as an investor general partner in the year in which he invested
in the partnership as a result of the partnership's deduction for intangible
drilling costs. Therefore, the 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. For a discussion of the effect of this rule on an investor general
partner's tax credits, if any, from his partnership see "- Marginal Well
Production Credits," below. The conversion of the investor general partner units
into limited partner units should not have any other adverse tax consequences on
an investor general partner unless his share, if any, 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 partner to the extent it exceeds his basis. (See "- Tax
Basis of Units," below.)
TAXABLE YEAR AND METHOD OF ACCOUNTING
Each partnership will adopt a calendar year taxable year and will use the
accrual method of accounting for federal income tax purposes.
BUSINESS EXPENSES
Ordinary and necessary business expenses, including reasonable compensation for
personal services actually rendered, are deductible in the year incurred. In
this regard, the managing general partner has represented that the amounts
payable by each partnership to it and its affiliates, including the amounts
payable to it or its affiliates as general drilling contractor, are reasonable
and competitive amounts which would ordinarily be paid for similar services in
similar transactions in the proposed areas of the partnerships' operations. (See
"Compensation" and "- Drilling Contracts," below.) The fees paid to the managing
general partner and its affiliates by the partnerships will not be currently
deductible, however, to the extent it is determined by the IRS or the courts
that they are:
o in excess of reasonable compensation;
o properly characterized as organization or syndication fees or
other capital costs such as lease acquisition costs or
equipment costs; or
o not "ordinary and necessary" business expenses.
In the event of an IRS 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.
Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.
Although the partnerships will engage in the production of natural gas and oil
from wells drilled in the United States, the partnerships will not qualify for
the "U.S. production activities deduction." This is because the deduction cannot
exceed 50% of the IRS Form W-2 wages paid by a taxpayer for a tax year, and the
partnerships will not pay any Form W-2 wages since they will not have any
employees. Instead, the partnerships will rely on the managing general partner
and its affiliates to manage them and their respective businesses. (See
"Management.")
INTANGIBLE DRILLING COSTS
You may elect to deduct in the year in which you invest in a partnership 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 and preparing it for the production of
natural gas or oil. For a discussion of the deduction of intangible drilling
costs that are prepaid by your partnership in the year in which you invest in
the partnership for wells the drilling of which will not begin until the next
taxable year, if any, see "- Drilling Contracts," below.
If a partnership re-enters an existing well as described in "Proposed Activities
- - Primary Areas of Operations - Mississippian/Upper Devonian Sandstone
Reservoirs, Fayette, Greene and Westmoreland Counties, Pennsylvania," the costs
of deepening the well and completing it to deeper reservoirs, if any, other than
equipment costs and lease costs, will be treated under the Code as intangible
drilling costs. The intangible drilling costs of drilling and completing a
re-entry well which are not related to deepening the well, if any, however, will
be treated as operating expenses which should be expensed in the taxable year
they are incurred for federal income tax purposes. Any intangible drilling costs
of a re-entry well which are treated as operating expenses for federal income
tax purposes, 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, and cannot be amortized as intangible drilling costs over a 60-month
period as described in "- Alternative Minimum Tax," below. (See "Participation
in Costs and Revenues.")
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Your share of your partnership's gain (if a partnership well is sold at a gain),
or your gain (if your units are sold at a gain), will be treated as ordinary
income, rather than capital gain, to the extent of the previous deductions for
intangible drilling costs you have claimed, but not for the deductions for
operating expenses related to a re-entry well, if any. (See "- Sale of the
Properties" and "- Disposition of Units," below.) 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. (See "- Alternative Minimum Tax," below.)
Under the partnership agreement, 90% of the subscription proceeds received by
each partnership from its investors will be used to pay 100% of the
partnership's intangible drilling costs of drilling and completing its wells.
(See "Application of Proceeds" and "Participation in Costs and Revenues.") 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.
Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.
You are urged to seek advice based on your particular circumstances from an
independent tax advisor concerning the tax benefits to you of your share of the
partnership's deduction for intangible drilling costs in the partnership in
which you invest.
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 each partnership well at cost plus an
unaccountable, fixed payment reimbursement of $15,000 from the investors to the
managing general partner for their share of the managing general partner's
general and administrative overhead plus 15%. 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 its profit of 15%
will be approximately $28,444 per 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. Therefore, the managing general partner's 15% profit per well also
could be more or less than the dollar amount estimated by the managing general
partner as set forth above. 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.
Depending primarily on when their respective subscription proceeds are received,
the managing general partner anticipates that each partnership may prepay in the
year in which its units are offered for sale most, if not all, of its intangible
drilling costs for wells the drilling of which will begin in the immediately
following year. 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 and development costs. The test is:
o the expenditure must be a payment rather than a refundable
deposit; and
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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. The drilling and
operating agreement will require your partnership to prepay in the year in which
you invest in the partnership all of your partnership's share of the estimated
intangible drilling costs and all of the investors' share of your partnership's
share of the estimated equipment costs, for drilling and completing specified
wells. As discussed above, the drilling of most, if not all, of those wells may
not begin until the immediately following year. These prepayments of intangible
drilling costs should not result in the loss of a current deduction in the year
in which you invest in your partnership for the intangible drilling costs of any
prepaid wells if:
o the guidelines set forth in Keller are complied with;
o there is a legitimate business purpose for the required
prepayment;
o the drilling of the prepaid wells begins on or before March 31
of the immediately following year, as discussed below;
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.
The drilling and operating agreement will require each partnership to prepay the
managing general partner's estimate of the intangible drilling costs and the
investor's 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 100% of the working
interest in the well. In this regard, 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 the other 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 partnerships 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.
Therefore, under the drilling and operating agreement, the managing general
partner, serving as operator and general drilling contractor, must begin
drilling each of the prepaid wells, if any, of the partnerships no later than
March 31 of the year immediately following the year in which you invested in the
partnership. However, the drilling of any partnership well may be delayed due to
circumstances beyond the control of the managing general partner and the
drilling subcontractors. These circumstances include, for example:
107
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 (i.e., "force majeure") delay beginning
the drilling of any prepaid wells past the 90 day limit imposed by the Code.
If the drilling of a prepaid partnership well does not begin within the 90 day
time constraint imposed by the Code, deductions claimed by you and the other
investors for prepaid intangible drilling costs for the well in the year in
which you invested in the partnership, would not be lost, but those deductions
would be disallowed for the year in which you invested in the partnership and
deferred to the next taxable year when the well is actually drilled.
Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.
DEPLETION ALLOWANCE
Proceeds from the sale of each partnership's natural gas and oil production will
constitute ordinary income. A 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. Your share of the partnership's
gain (if a partnership well is sold at a gain), or your gain (if you sell your
units at a gain), will be treated as ordinary income rather than capital gain to
the extent of your previous deductions for depletion which reduced your adjusted
basis in the property or your units. (See "- Sale of the Properties" and "-
Disposition of Units," below.)
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 is available to taxpayers other than "integrated oil
companies," which term does not include the partnerships. Your percentage
depletion allowance 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. In this regard, the
managing general partner has represented that most, if not all, of the natural
gas and oil production from each partnership's wells will be marginal production
under this definition in the Code. Therefore, most, if not all, of each
partnership's gross income from the sale of its natural gas and oil production
will qualify for these potentially higher rates of percentage depletion. The
rate of percentage depletion for marginal production in 2005 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%.
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Also, percentage depletion:
o may not exceed 100% of the taxable income from each natural
gas and oil property before the deduction for depletion,
however, this limitation is suspended in 2005 with respect to
marginal properties, which the managing general partner has
represented will include most, if not all, of each
partnership's wells; and
o is limited to 65% of the taxpayer's taxable income for the
year computed without regard to percentage depletion, net
operating loss carry-backs and capital loss carry-backs and,
in the case of an investor that is a trust, any distributions
to its beneficiaries. Any disallowed percentage depletion
deductions under the preceding limitations may be carried
forward to the next taxable year.
The availability in any taxable year of your percentage depletion allowance must
be computed separately by you and not by your partnership or for investors in
your partnership as a whole. You are urged to seek advice based on your
particular circumstances from an independent tax advisor with respect to the
availability of percentage depletion to you.
DEPRECIATION AND COST RECOVERY DEDUCTIONS
Ten percent of each partnership's subscription proceeds will be used to pay
equipment costs (i.e. "Tangible Costs"), and the managing general partner will
pay all of the partnership's remaining equipment costs of drilling and
completing its wells. The related depreciation deductions, i.e., cost recovery
deductions under the modified accelerated cost recovery system ("MACRS"), will
be allocated under the partnership agreement between the managing general
partner and the investors in each partnership in proportion to the actual amount
of the partnership's equipment costs paid by each.
A partnership's reasonable Tangible Costs for equipment placed in its wells
which cannot be deducted immediately 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 each well is "placed in service" by the
partnership. In this regard, the managing general partner anticipates that each
partnership will have all of its wells drilled, completed and placed in service
for the production of natural gas or oil approximately eight to 12 months after
that partnership's final closing. In the case of a short partnership tax year,
the MACRS deduction will be prorated on a 12-month basis. No distinction is made
between new and used property and salvage value is disregarded. All property
assigned to the 7-year class is treated as placed in service, or disposed of, in
the middle of the year, unless more than 40% of the total cost of all equipment
in a partnership's wells placed in service during the year is placed in service
during the last three months of the year. If that happens, the depreciation for
the full year will be multiplied by a fraction based on the quarter the
equipment is placed in service: 87.5% for the first quarter, 62.5% for the
second, 37.5% for the third, and 12.5% for the fourth. All of these cost
recovery deductions claimed by a partnership and you and the other investors in
that partnership are subject to recapture as ordinary income rather than capital
gain on the sale or other taxable disposition of the property by the partnership
or your units by you. (See "- Sale of the Properties" and "- Disposition of
Units," below.) Depreciation for alternative minimum tax purposes is computed
using the 150% declining balance method switching to straight-line, for most
personal property. This means that the partnership's depreciation deductions in
the early years of the cost recovery period for alternative minimum tax purposes
will be less than the partnership's depreciation deductions in those years for
regular tax purposes, but, conversely, they will be greater in the later years
of the cost recovery period. This will result in adjustments in computing the
alternative minimum taxable income of you and the other investors in a
partnership in taxable years in which the partnership claims depreciation
deductions. (See "- Alternative Minimum Tax," below.)
Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.
MARGINAL WELL PRODUCTION CREDITS
There is a marginal well production credit of 50(cent) per mcf of qualified
natural gas production and $3 per barrel of qualified oil production for
purposes of the regular federal income tax beginning with qualifying production
in 2005. A tax credit, unlike a tax deduction, reduces tax liability on a
dollar-for-dollar basis. This credit, however, cannot be used under current law
to reduce alternative minimum taxes. (See "- Alternative Minimum Tax," below.)
Also, the credit will be reduced proportionately if the reference prices for the
previous calendar year are between $1.67 and $2.00 per mcf for natural gas and
$15 and $18 per barrel for oil. In this regard, none of Atlas America Public
#15-2005(A) L.P.'s natural gas and oil production in 2005, if any, will qualify
for this credit in 2005, because the reference prices for natural gas and oil in
2004 were substantially above the $2.00 per mcf of natural gas and $18.00 per
barrel of oil prices where the credit phases out completely.
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Only holders of a working interest in a qualified well can claim the credit. For
purposes of the credit, you and the other investors in a partnership will be
treated as working interest owners because of your flow-through ownership
interest in the partnership in which you invest. You will share in your
partnership's marginal well production credits, if any, in the same proportion
as your share of that partnership's production revenues. (See "Participation in
Costs and Revenues.")
The reference price for oil was $27.56 in 2003, and it has not been under the
$18.00 threshold necessary to qualify for any marginal well production credit
for oil since 1999. More importantly, since the managing general partner
anticipates that most of each partnership's production from its wells will be
natural gas, the average selling price the managing general partner received in
each of its past four fiscal years for its natural gas production, after
deducting all expenses, including transportation expenses, exceeded the $2.00
per mcf price needed to qualify for any marginal well production credits. (See
"Proposed Activities - Sale of Natural Gas Production - Policy of Treating All
Wells Equally in a Geographic Area."
Based on the prices for natural gas and oil in recent years compared with the
prices at which the credit phases out completely, it may appear unlikely that
any partnership's natural gas and oil production will ever qualify for this
credit. However, prices for natural gas and oil are volatile and could decrease
in the future. (See "Risk Factors - Risks Related To The Partnerships' Oil and
Gas Operations - Partnership Distributions May be Reduced if There is a Decrease
in the Price of Natural Gas and Oil.") Thus, it is possible that the
partnerships' production of natural gas or oil in one or more taxable years
after 2005 could qualify for the marginal well production credit, depending
primarily on the applicable reference prices for natural gas and oil in the
future. However, depending primarily on market prices for natural gas and oil,
which are volatile, each partnership's production of natural gas and oil may not
qualify for marginal well production credits for many years, if ever.
Because natural gas and oil production which qualifies as marginal production
under the percentage depletion rules discussed above, which the managing general
partner has represented will include most, if not all of the natural gas and oil
production from each partnership's productive wells, is also qualified marginal
production for purposes of this credit, the natural gas and oil production from
most, if not all, of each partnership's wells will be eligible for this credit,
subject to the applicable reference prices as discussed above.
To the extent that your share of your partnership's marginal well production
credits, if any, exceeds your regular federal income tax owed on your share of
the partnership's taxable income, the excess credits, if any, can be used by you
to offset any other regular federal income taxes owed by you, on a
dollar-for-dollar basis, subject to the passive activity limitations if you
invest in a partnership as a limited partner. (See "- Limitations on Passive
Activity Losses and Credits," above.) Also, if you invest in a partnership as an
investor general partner, your share of your partnership's marginal well
production credits, if any, will be an active credit which may offset your
regular federal income tax liability on any type of income. However, after you
are converted to a limited partner in the partnership in which you invest, your
share of the partnership's marginal well production credits, if any, will be
active credits only to the extent of your regular federal income tax liability
which is allocable to your share of any net income of the partnership from the
sale of its natural gas and oil production, which will still be treated as
non-passive income even after you have been converted to a limited partner. (See
"- Conversion from Investor General Partner to Limited Partner," above.) Any
credits in excess of that amount which are allocable to you as a converted
investor general partner, as well as all of the marginal well production credits
allocable to those investors who originally invest in the partnership as limited
partners, will be passive credits which under current law can reduce only your
regular income tax liability attributable to net passive income from the
partnership in which you invest or your other passive activities, if any, except
publicly traded partnership passive activities.
LEASE ACQUISITION COSTS AND ABANDONMENT
Lease acquisition costs, together with the related cost depletion deduction and
any abandonment loss for lease acquisition 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.
110
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 your 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 share of partnership expenditures that are not deductible in
computing its taxable income and are not properly chargeable
to capital account;
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 ON LOSSES
You may use your share of your partnership's losses to offset income from other
sources, but only to the extent of the amount you have "at risk" in your
partnership at the end of a taxable year. This "at risk" limitation on your
share of your partnership's losses, however, does not apply to you if you are a
corporation which is neither an S corporation nor a corporation in which at any
time during the last half of the taxable year five or fewer individuals own more
than 50% (in value) of the stock. Your initial "at risk" amount is equal to the
amount of money you paid for your units. However, any amounts borrowed by you to
buy your units will not be considered "at risk" if the amounts are borrowed from
another investor in your partnership or anyone related to another investor in
your partnership. In this regard, the managing general partner has represented
that it and its affiliates will not make or arrange financing for you or any
other potential investors to use to purchase units in the partnerships. Also,
the amount you have "at risk" in your partnership will not include the amount of
any loss that you are protected against through:
o nonrecourse loans;
o guarantees;
o stop loss agreements; or
o other similar arrangements.
DISTRIBUTIONS FROM A PARTNERSHIP
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. Different rules
apply, however, to payments by a partnership to a deceased investor's successor
in interest and to payments for an investor's share of his partnership's
unrealized receivables and inventory items as those terms are defined in ss.751
of the Code. No loss can be recognized by you on these types of distributions,
unless the distribution is made to liquidate your units in your partnership and
then only to the extent of the excess, if any, of your adjusted basis in your
units over the sum of the amount of money distributed to you plus your share of
the basis of any unrealized receivables and inventory items of your partnership.
(See "- Disposition of Units," below, for a discussion of unrealized receivables
and inventory items under ss.751 of the Code.) Other distributions of cash,
disproportionate distributions of property, if any, and liquidating
distributions of your partnership may result in taxable gain or loss to you.
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SALE OF THE PROPERTIES
The maximum tax rate on a noncorporate taxpayer's adjusted net capital gain on
the sale of assets held more than a year is 15%, or 5% to the extent the gain
would have been taxed at a 10% or 15% rate if it had been ordinary income,
respectively, for most capital assets. In addition, for 2008 only, the 5% tax
rate on adjusted net capital gain was reduced to 0%. The former maximum tax
rates of 18% and 8%, respectively, on qualified five-year gain have been
eliminated. These capital gain rates also apply for purposes of the alternative
minimum tax. (See "- Alternative Minimum Tax," below.) However, the former tax
rates on adjusted net capital gain of 20% and 10%, respectively, are scheduled
to be reinstated on January 1, 2009.
"Adjusted net capital gain" means net capital gain determined without taking
qualified dividend income into account:
o reduced (but not below zero) by:
o any amount of qualified dividend income taken into
account as investment income;
o net capital gain that is taxed a maximum rate of 28%
(such as gain on the sale of most collectibles and
gain on the sale of qualified small business stock);
and
o net capital gain that is taxed at a maximum rate of
25% (gain attributable to real estate depreciation);
and
o increased by the amount of qualified dividend income.
"Net capital gain" means the excess of net long-term gain (the excess of
long-term gains over long-term losses) over net short-term loss (the 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 from sales of natural gas and oil properties held for more than 12 months
will be treated as a long-term capital gain, while a net loss will be an
ordinary deduction. However, if a natural gas or oil property owned by your
partnership is sold, gain will be treated as ordinary income to the extent of
the lesser of:
o the amounts which were deducted as intangible drilling costs
rather than added to the basis of the property, plus
deductions for depletion which reduced the adjusted basis of
the property; or
o the excess of:
o the amount realized, in the case of a sale, exchange
or involuntary conversion; or
o the fair market value of the interest, in all other
cases;
minus the property's adjusted basis.
In addition, all equipment depreciation deductions, and any losses on previous
sales of a partnership's assets which have not yet been used for the purpose of
treating a portion or all of gains on previous sales of the partnership's
properties for the partnership's five most recent taxable years as ordinary
income will be treated as ordinary income to the extent of any gain on the sale
or other taxable disposition of the property. (See "- Depreciation and Cost
Recovery Deductions," above) Other gains and losses on sales of natural gas and
oil properties held by the partnership for less than 12 months, if any, will
result in ordinary gains or losses.
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DISPOSITION OF UNITS
The sale or exchange, including a purchase by the managing general partner, of
all or some of your units, if held by you for more than 12 months, will result
in your recognition of long-term capital gain or loss, except for previous
deductions for depreciation, depletion and intangible drilling costs, and your
share of the partnership's "ss.751 assets" (i.e. inventory items and unrealized
receivables). "Unrealized receivables" includes any right to payment for goods
delivered, or to be delivered, to the extent the proceeds would be treated as
amounts received from the sale or exchange of non-capital assets, or services
rendered or to be rendered, to the extent not previously includable in income
under your partnership's accounting methods. "Inventory items" includes property
properly includable in inventory and property held primarily for sale to
customers in the ordinary course of business and any other property that would
produce ordinary income if sold, including accounts receivable for goods and
services. These tax items are sometimes referred to in this discussion as
"ss.751 assets." All of these tax items 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 your units are held for 12 months or less, your gain or loss 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 will 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 Activity Losses and Credits," above.)
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 types of 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 ss.751 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 Code to notify your partnership within 30 days or by January
15 of the following year, if earlier. The partnership will then report to the
IRS any information required by the IRS to be reported regarding the transfer of
the units, including your share of your 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, and there will be 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, deduction and credit will be determined by taking into account your
varying interests in the partnership during the taxable year.
You are urged to seek advice based on your particular circumstances from an
independent tax advisor before any sale or other disposition of your units,
including any purchase of your 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
is taxable income, plus or minus various adjustments, plus tax preference items.
The principal adjustments and preference items which may apply to typical
investors in a partnership are summarized below.
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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 2005 are $58,000 for married
individuals filing jointly and surviving spouses, $40,250 for single persons
other than surviving spouses, and $29,000 for married individuals filing
separately. For years beginning after 2005, these exemption amounts are
scheduled to decrease to $45,000 for married individuals filing jointly and
surviving spouses, $33,750 for single persons other than surviving spouses, and
$22,500 for married individuals filing separately. The exemption amount for
estates and trusts is $22,500 in 2005 and subsequent years.
The exemption amounts set forth above 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 2005 the alternative minimum taxable income of
married individuals filing separately is increased by the
lesser of $29,000 ($22,500 after 2005) 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 2005).
Some of the principal adjustments to taxable income that are used to determine
alternative minimum taxable income include those summarized below:
o Depreciation deductions of the costs of the equipment in the
wells may not exceed deductions computed using the 150%
declining balance method. These adjustments are discussed in
greater detail below. (See "- Depreciation and Cost Recovery
Deductions," above.)
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 taxes and income taxes (or sales
taxes, instead of state and local income taxes, at your
election in the 2005 tax year), which are itemized and
deducted for regular tax purposes, 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 Passive activity losses are computed differently.
o Earlier recognition of income from incentive stock options may
be required.
The principal tax preference items that must be added to taxable income for
alternative minimum tax purposes include:
o excess intangible drilling costs, as discussed below; and
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o tax-exempt interest earned on specified private activity
bonds, less any deductions that would have been allowable if
the interest were included in gross income for regular income
tax purposes.
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 may elect under ss.59(e) of the Code to capitalize all or part of your
share of your 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, will include the following principal consequences to you:
o your regular federal income 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
expenses. As noted in "- Depreciation and Cost Recovery Deductions," above, in
the early years of the cost recovery period of your partnership's equipment, but
not the later years, your depreciation deductions from the partnership will be
smaller for alternative minimum tax purposes than your depreciation deductions
for regular income tax purposes on the same equipment. This, in turn, could
cause you to incur, or may increase, your alternative minimum tax liability in
those taxable years. Conversely, this adjustment may decrease your alternative
minimum taxable income in the later years of the cost recovery period.
Under current law, your share of your partnership's marginal well production
credits, if any, may not be used to reduce your alternative minimum tax
liability, if any. Also, the rules relating to the alternative minimum tax for
corporations are different from those for individuals which have been summarized
above.
All prospective investors contemplating purchasing units in a partnership are
urged to seek advice based on their particular circumstances from an independent
tax advisor as to the likelihood of them incurring or increasing any alternative
minimum tax liability as a result 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, an investor general partner's share
of the partnership's loss 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 expenses, 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 a partnership's income or expenses taken into account in computing
income or loss from a passive activity. (See "- Limitations on Passive Activity
Losses and Credits," above.)
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ALLOCATIONS
The partnership agreement allocates to you your share of your partnership's
income, gains, losses, deductions, and credits, if any, 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 units. 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 of partnership income and gain to
you; and
o decreased by the value of property or cash distributed to you
by the partnership and allocations of partnership losses and
deductions to you.
Also, any marginal well production credits of a partnership will be allocated
among the managing general partner and you and the other investors in the
partnership in which you invest in accordance with each partner's respective
interest in the partnership's production revenues from the sale of its natural
gas and oil production. (See "Participation in Costs and Revenues" and "-
Marginal Well Production Credits," above.)
It also should be noted that your share of items of income, gain, loss,
deduction, and credit, if any, in the partnership in which you invest must be
taken into account by you whether or not you receive any cash distributions from
the partnership. For example, your share of partnership revenues applied by your
partnership to the repayment of loans, if any, or the reserve for plugging
wells, will be included in your gross income in a manner analogous to an actual
distribution of the revenues (and 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 to you and the other investors in that partnership will not be
less than the managing general partner's estimate of the investors' income tax
liability with respect to that partnership's income.
If any allocation under the partnership agreement is not recognized for federal
income tax purposes, your share of the items subject to the allocation will be
determined in accordance with your interest in the partnership in which you
invest by considering all of the relevant facts and circumstances. To the extent
deductions or credits allocated by the partnership agreement exceed deductions
or credits which would be allowed under a reallocation of those tax items by the
IRS, you may incur a greater tax burden.
PARTNERSHIP BORROWINGS
Under the partnership agreement, only 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 by the IRS as capital
contributions to the partnership by the managing general partner or its
affiliates in light of all of the surrounding facts and circumstances.
PARTNERSHIP ORGANIZATION AND OFFERING COSTS
Expenses connected with the offer and sale of units in a partnership, such as
the dealer-manager fee, sales commissions, and other selling expenses,
professional fees, and printing costs, which are charged under the partnership
agreement 100% to the managing general partner as organization and offering
costs, are not deductible. Although expenses incident to the creation of a
partnership may be amortized over a period of not less than 180 months, these
expenses also will be paid by the managing general partner as part of each
partnership's organization costs. Thus, any related deductions, which the
managing general partner does not anticipate will be material in amount as
compared to the total subscription proceeds of each partnership, will be
allocated to the managing general partner.
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TAX ELECTIONS
Each partnership may elect to adjust the basis of its property 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 (other than money) by the partnership to an
investor (the ss.754 election). If the ss.754 election is made, 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 distributions to the investors, as though it had
newly acquired an interest in the partnership assets and therefore acquired a
new cost basis for the assets. Any election, once made, may not be revoked
without the consent of the IRS.
In this regard, due to the complexities and added expense of the tax accounting
required to implement a ss.754 election to adjust the basis of a partnership's
property when units are sold, taking into account the limitations on the sale of
the partnership's units, the managing general partner anticipates that none of
the partnerships will make the ss.754 election, although they reserve the right
to do so. Even if the partnerships do not make the ss.754 election, the basis
adjustment described above is mandatory under the Code with respect to the
transferee partner only, if at the time a unit is transferred by sale or
exchange, or on the death of an investor, the partnership's adjusted basis in
its property exceeds the fair market value of the property by more than $250,000
immediately after the transfer of the unit. Similarly, a basis adjustment is
mandatory under the Code if a partnership distributes property in-kind to a
partner, and the sum of the partner's loss on the distribution and the basis
increase to the distributed property is more than $250,000. In this regard, none
of the partnerships will distribute their assets in-kind to its investors,
except to a liquidating trust or similar entity for the benefit of its
investors, unless at the time of the distribution its investors have been
offered the election of receiving in-kind property distributions, and you or any
other investor in that partnership accepts the offer after being advised of the
risks associated with direct ownership; or there are alternative arrangements in
place which assure that you and the other investors in that partnership will
not, at any time, be responsible for the operation or disposition of the
partnership's properties.
If the basis of a partnership's assets must be adjusted as discussed above, the
primary effect on the partnership, other than the federal income tax
consequences discussed 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 will not make in-kind property distributions to their
respective investors except in the limited circumstances described above, and
the units have no readily available market and are subject to substantial
restrictions on their transfer. (See "Transferability of Units - Restrictions on
Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement.") These factors will tend to reduce the likelihood that a partnership
will be required to make mandatory basis adjustments to its properties. In
addition to the ss.754 election, each partnership may make various elections
under the Code for federal tax reporting purposes which could result in the
deductions of intangible drilling costs and depreciation, and the depletion
allowance, being treated differently for tax purposes than for accounting
purposes.
Also, under the Code "start-up expenditures" may be capitalized and amortized
over a 180-month period. The term "start-up expenditure" for this purpose
includes any amount:
o paid or incurred in connection with:
o investigating the creation of an active trade or
business; or
o creating an active trade or business, or
117
o any activity engaged in for profit and for the
production of income before the day on which the
active trade or business begins, in anticipation of
that activity becoming an active trade or business;
and
o which would be allowed as a deduction if paid or incurred in
connection with the expansion of an existing business.
If it is ultimately determined by the IRS or the courts that any of a
partnership's expenses constituted start-up expenditures, that partnership's
deductions for those expenses, including your share of those deductions if you
are an investor in that partnership, would be amortized over the 180-month
period.
TAX RETURNS AND IRS AUDITS
The tax treatment of most partnership items is determined at the partnership,
rather than the partner level. Accordingly, the investors are required to treat
partnership items of the partnership in which they invest 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
returns, unless they disclose to the IRS that their tax treatment of partnership
items on their personal federal income tax returns is different from their
partnership's tax treatment of those partnership items. In most cases, 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 IRS administrative determination
with respect to partnership items before filing suit for any credit or refund.
Also, the period for assessing tax against you and the other investors because
of a partnership item may be extended by agreement between the IRS and the
managing general partner, which will serve as each partnership's representative
("Tax Matters Partner") in all administrative tax proceedings and tax litigation
conducted at the partnership level.
The Tax Matters Partner may enter into a settlement on behalf of, and binding
on, any investor owning less than a 1% profits interest in a partnership if
there are more than 100 partners in the partnership, unless that investor timely
files a statement with the Secretary of the Treasury providing that the Tax
Matters Partner does not have authority to enter into a settlement agreement on
behalf of that investor. Based on its past experience, the managing general
partner anticipates that there will be more than 100 investors in each
partnership in which units are offered for sale. However, by executing the
Subscription Agreement you also are executing the partnership agreement if your
Subscription Agreement is accepted by the managing general partner. Under the
partnership agreement, you and the other investors in that partnership 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 Tax Matters Partner does
not have binding settlement authority. 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." However, most limitations affecting
the calculation of the taxable income and tax credits of an electing large
partnership are applied at the partnership level and not the partner level.
Thus, the managing general partner does not anticipate that the partnerships
will make this election, although they reserve the right to do so.
All expenses of any tax proceedings involving a partnership and the managing
general partner acting as Tax Matters Partner, which might be substantial, will
be paid for by the partnership and not by the managing general partner from its
own funds. The managing general partner, however, is not obligated to contest
any adjustments made by the IRS to a partnership's federal information income
tax returns, even if the adjustment also would affect the individual federal
income tax returns of its investors. The managing general partner will notify
you and the other investors in your partnership of any IRS audits or other tax
proceedings involving your partnership, and will provide you and the other
investors 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. Each
partnership will provide its investors with the tax information applicable to
their investment in the partnership necessary to prepare their tax returns.
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PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND JUDICIAL DOCTRINES LIMITATIONS ON
DEDUCTIONS
Your ability to deduct your share of your partnership's deductions could be
limited or lost if the partnership lacks the appropriate profit motive. The Code
creates a presumption 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 out 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 under the Treasury
Regulations 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 Code, based on all the facts and circumstances, the
IRS is authorized under Treasury Regulation 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 and tax credits from a transaction,
including each partnership's deduction for intangible drilling costs in the year
in which you and the other investors invest in a partnership, will be disallowed
if your partnership is found by the IRS or the courts, to have no economic
substance apart from the tax benefits.
With respect to these issues, special counsel has given its opinions 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 to its investors, apart from tax benefits, as described in
this prospectus. These representations are supported by the information
concerning the partnerships' proposed drilling areas in "Proposed Activities,"
and the geological evaluations and other information for the specific prospects
proposed to be drilled by Atlas America Public #15-2005(A) L.P. included in
Appendix A to this prospectus, which represent a portion of the prospects to be
drilled if that partnership's targeted maximum subscription proceeds of $50
million are received (which is not binding on the partnership) as described in
"Terms of the Offering - Subscription to a Partnership." Also, the managing
general partner has represented that Appendix A in this prospectus will be
supplemented or amended to cover a portion of the specific prospects proposed to
be drilled by the partnerships designated Atlas America Public #15-2006(___)
L.P. when units in those partnerships are first offered to prospective
investors.
FEDERAL INTEREST AND TAX PENALTIES
Taxpayers must pay tax and interest on underpayments of federal income taxes and
the Code contains various penalties, including penalties for negligence and
substantial valuation misstatements with respect to their individual federal
income tax returns. In addition, there is a penalty equal to 20% of the amount
of a substantial understatement of federal income tax liability. An
understatement occurs if the correct income tax, as finally determined by the
IRS or the courts, exceeds the income tax liability actually shown on the
taxpayer's federal income tax return. An understatement on a non-corporate
taxpayer's federal income tax return is substantial if it exceeds the greater of
10% of the correct tax, or $5,000. A non-corporate taxpayer may avoid this
penalty if the understatement was not attributable to a "tax shelter," and there
is or was substantial authority for the taxpayer's tax treatment of the item
that caused the understatement, or if the relevant facts were adequately
disclosed on the taxpayer's individual federal income tax return and the
taxpayer had a "reasonable basis" for the tax treatment of that item. In the
case of an understatement that is attributable to a "tax shelter," however,
which may include each of the partnerships for this purpose, the penalty may be
avoided by a non-corporate taxpayer only if there was reasonable cause for the
underpayment and the taxpayer acted in good faith, or there is or was
substantial authority for the taxpayer's treatment of the item that caused the
understatement, and the taxpayer reasonably believed that his or her treatment
of the item on his individual federal income tax return was more likely than not
the proper treatment.
For purposes of this penalty, the term "tax shelter" includes a partnership if a
significant purpose of the partnership is the avoidance or evasion of federal
income tax. Because the IRS has not explained what a "significant" purpose of
avoiding or evading federal income taxes means, special counsel cannot give an
opinion as to whether the partnerships are "tax shelters" as defined by the Code
for purposes of this penalty.
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In addition, there is a 20% penalty for reportable transaction understatements
for any tax year. However, if the disclosure rules for reportable transactions
under the Code and the Regulations are not met by the taxpayer, this penalty is
increased from 20% to 30%, and a "reasonable cause" exception to the penalty
which is included in the Code, will not be available to the taxpayer. Under
Treasury Regulation ss.1.6011-4, a taxpayer who participates in a reportable
transaction in any taxable year must attach to his individual federal income tax
return IRS Form 8886 "Reportable Transaction Disclosure Statement," and file it
with the IRS as directed in the Regulation, in order to comply with the
disclosure rules.
A tax item is subject to the reportable transaction rules if the tax item is
attributable to:
o any listed transaction, which is a transaction that the IRS
has publicly pronounced that it has specifically found to be a
tax avoidance transaction; or
o any of five other types of reportable transactions, if a
significant purpose of the transaction is federal income tax
avoidance or evasion.
In this regard, special counsel cannot give an opinion on whether the
partnerships have a "significant" purpose of avoiding or evading federal income
taxes, because the IRS has not explained what that phrase means for purposes of
this penalty. However, the type of reportable transaction that appears most
likely to special counsel to apply to the partnerships, but only if it is
assumed that the partnerships have the "significant" purpose of federal income
tax avoidance or evasion, which special counsel believes is unclear under
current legal authorities, is a "loss transaction." Under the Treasury
Regulations, there is a loss transaction if a partnership or any of its
noncorporate partners claims a loss under ss.165 of the Code of at least $2
million, in the aggregate, in any taxable year of the partnership, or at least
$4 million, in the aggregate, over the partnership's first six years.
Each partnership's deduction for intangible drilling costs will exceed $2
million in the taxable year in which its investors invest in the partnership if
subscription proceeds of approximately $2,225,000 or more are received by the
partnership, and will exceed $4 million if subscription proceeds of
approximately $4,450,000 are received by the partnership. However, special
counsel has given its opinion in the tax opinion letter that it believes that
losses which result from deductions claimed for intangible drilling costs for
productive wells should be treated as losses under ss.263(c) of the Code and
Treasury Regulation ss.1.612-4(a), and should not be treated as ss.165 losses
for purposes of the "loss transaction" rules. Thus, special counsel has given
its opinion that the partnerships are not, and should not be in the future,
reportable transactions under the Code. However, because special counsel has
entered into a compensation arrangement with the managing general partner to
provide certain legal services to the partnerships, its tax opinion letter was
not written, and cannot be used by you or the other investors in the
partnerships, for the purpose of establishing your reasonable belief that your
tax treatment of any partnership tax item on your individual federal income tax
returns was more likely than not the proper treatment in order to avoid any
reportable transaction understatement penalty under ss.6662A of the Code. Thus,
you are urged to seek advice from an independent tax advisor with respect to
whether an investment in a partnership would subject you to that penalty. In
this regard, special counsel's opinion is based in part on the managing general
partner's representation that each partnership's total abandonment losses under
ss.165 of the Code, which could include, for example, the abandonment by a
partnership of:
o wells drilled which are nonproductive (i.e. a "dry hole"); or
o productive wells which have been operated until their
commercial natural gas and oil reserves have been depleted;
will be less than $2 million, in the aggregate, in any taxable year of the
partnership and less than $4 million, in the aggregate, during the partnership's
first six taxable years.
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STATE AND LOCAL TAXES
Each partnership will operate in states and localities which may impose a tax on
it, or on you and the partnership's other investors, based on the partnership's
assets or its income. Each partnership also may be subject to state income tax
withholding requirements on its income whether or not the revenues that created
the income are distributed by it to its investors. Deductions and credits,
including federal marginal well production credits, if any, which may be
available to you for federal income tax purposes, may not be available for state
or local income tax purposes. If the state or locality in which you reside
imposes income taxes on you, you likely will be required under those income tax
laws to include your share of the net income or net loss of the partnership in
which you invest 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 a 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. Also, due to a partnership's operations in a
state or other local jurisdiction, 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.
Each partnership's units may be sold in all 50 states and the District of
Columbia and it is not practical for special counsel's tax opinion letter to
evaluate the many different state and local tax laws that may apply to one or
more of a partnership's investors. You are urged to seek advice based on your
particular circumstances from an independent tax advisor to determine the effect
state and local taxes, including gift and death taxes as well as income taxes,
may have on you in connection with 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. These taxes will reduce the
amount of the partnership's cash available for distribution to you and its other
investors.
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 2005 is $90,000. 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 has
represented that it 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, you and the other investors in that partnership would be
required to include your share of the resulting taxable income on your
individual income tax returns, even though the partnership and you and the other
investors in that partnership received no cash from the farmout.
FOREIGN PARTNERS
Each partnership will be required to withhold and pay income tax to the IRS at
the highest rate under the 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 foreign investor must seek a refund on his
individual United States federal income tax return. For withholding purposes, a
foreign investor means an investor who is not a United States person and
includes a nonresident alien individual, a foreign corporation, a foreign
partnership, and a foreign trust or estate, unless the investor has certified to
his partnership the investor's status as a U.S. person on Form W-9 or any other
form permitted by the IRS for that purpose.
Foreign investors are urged to seek advice based on their particular
circumstances from an independent tax advisor regarding the applicability of
these rules and the other tax consequences of an investment in a partnership to
them.
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ESTATE AND GIFT TAXATION
There is no federal tax on lifetime or testamentary transfers of property
between spouses. The gift tax annual exclusion amount is $11,000 per donee in
2005, and $12,000 per donee in 2006, 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 47% in 2005
will be reduced in stages to 46% in 2006 and 45% from 2007 through 2009. Estates
of $1.5 million in 2005, which increases in stages to $2 million in 2006, 2007
and 2008, and $3.5 million in 2009, or less are not subject to federal estate
tax to the extent those exemption amounts (i.e., unified credit amounts) were
not previously used by the decedent to avoid gift taxes on lifetime gifts in
excess of the applicable annual exclusion amount for gifts. Under the 2001 Tax
Act, the federal estate tax will be repealed in 2010, and the maximum gift tax
rate in 2010 will be 35%. In 2011, however, 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 tax benefits from an 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 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 can save by virtue of your share of your
partnership's deductions for intangible drilling costs, depletion and
depreciation, and marginal well production credits, if any. On the other hand,
the lower federal income tax rates also will reduce the amount of federal income
tax liability incurred by you on your share of your partnership's net income.
However, the federal income tax brackets discussed above could be changed again,
even before 2011, and other changes in the tax laws could be made which would
affect your tax benefits from an investment in a partnership.
You are urged to seek advice based on your particular circumstances from an
independent tax advisor with respect to the impact of recent federal tax
legislation on an investment in a partnership and the status of federal and
state legislative, regulatory or administrative tax developments and tax
proposals and their potential effect on the tax consequences to you of an
investment in a partnership.
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, a copy of which
attached as Exhibit (A) to this prospectus. You are urged to thoroughly review
the partnership agreement before you decide to invest in a partnership. 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.
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AMENDMENTS
Amendments to the partnership agreement of a partnership may be proposed in
writing by:
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.
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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% in each
partnership, the managing general partner may assign its interest in the
partnership to its affiliates. Additionally, subject to a required participation
of not less than 1% in each partnership, 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 to thoroughly review the drilling and operating agreement before
you decide whether to invest in a partnership. 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.
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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.
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.
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
in ss.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.
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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 or intention to establish a
reserve to satisfy the presentment obligation and it may immediately suspend the
presentment 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.
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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 prepared by the managing general
partner and reviewed by an independent expert. 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 your number
of 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,
after the presentment request, was derived from the sale 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.
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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 June 15, 2005, approximately 175 units have been presented to the managing
general partner for purchase in its previous 50 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 "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, 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, nor
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:
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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.
Also, 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
An assignee of a unit will not be entitled to any of the rights granted to a
partner under the partnership 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, unless the assignee becomes a substituted partner in accordance with
the provisions set forth below. 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 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.
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 and Atkinson and 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 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
129
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
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 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 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.
130
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 four Regional Marketing Directors, Mr. Bruce Bundy, Mr.
Robert Gourlay, Ms. Vicki Burbridge and Mr. Jim O'Mara. 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 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, the offering will be conducted in compliance with SEC
Rule 15c2-4.
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 invest in proportion to your respective number of units. However,
the subscription price for certain investors will be reduced as set forth below:
131
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 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 as discussed
in "Participation in Costs and Revenues - Allocation and Adjustments Among
Investors." 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 #15-2005 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 #15-2005 Program Can Help Achieve an
Investor's Tax Objectives";
o a brochure entitled "Investing in Atlas America Public
#15-2005 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 and Reducing AMT
through Natural Gas Partnerships";
132
o a brochure entitled "The Drilling Process"; 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:
o it must be preceded or accompanied by this prospectus;
o it is not complete;
o it does not contain any information which is not consistent
with 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 other 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 the material and any significant federal 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, 2004 and 2003 and the
balance sheet for Atlas America Public #15-2005(A) L.P. 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
this prospectus in reliance on the reports of Grant Thornton LLP on the
authority of that firm as an expert in accounting and auditing.
133
The information concerning the 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, which is not affiliated with the
managing general partner or its affiliates, 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 #15-2005(A) L.P.
Financial information concerning the managing general partner and the first
partnership in the program, Atlas America Public #15-2005(A) L.P., 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.
INDEX TO FINANCIAL STATEMENTS
ATLAS AMERICA PUBLIC #15-2005(A) L.P. FINANCIAL STATEMENTS
Report of Independent Registered Certified Public Accounting Firm dated August 5, 2005 (except for the last sentence
of the third paragraph of Note 1, as to which the date is September 23, 2005)......................................F-1
Balance Sheet as of August 5, 2005......................................................................................F-2
Notes to Financial Statement dated August 5, 2005 (except for the last sentence of the third paragraph of Note 1,
as to which the date is September 23, 2005)........................................................................F-3
ATLAS RESOURCES, INC. AND SUBSIDIARY AUDITED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm dated November 22, 2004.........................................F-8
Atlas Resources, Inc. and Subsidiary Consolidated Balance Sheets for the years ended September 30, 2004 and 2003........F-9
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Income for the years ended September 30, 2004
and 2003..........................................................................................................F-10
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Comprehensive Income for the years ended September
30, 2004 and 2003.................................................................................................F-11
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Changes in Stockholder's Equity for the years ended
September 30, 2004 and 2003.......................................................................................F-12
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Cash Flows for the years ended September 30, 2004
and 2003..........................................................................................................F-13
Atlas Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements........................................F-14
ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) AS OF JUNE 30, 2005
Atlas Resources, Inc. and Subsidiary Consolidated Balance Sheets as of June 30, 2005 and September 30, 2005............F-28
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Income for the nine months ended June 30, 2005 and
2004 (Unaudited)..................................................................................................F-29
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Changes in Stockholder's Equity for the nine months
ended June 30, 2005 (Unaudited)...................................................................................F-30
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Cash Flows for the nine months ended June 30, 2005
and 2004 (Unaudited)..............................................................................................F-31
Atlas Resources, Inc. and Subsidiary Notes to Consolidated Financial Statements........................................F-32
134
REPORT OF INDEPENDENT REGISTERED
CERTIFIED PUBLIC ACCOUNTING FIRM
To the Partners
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
(A DELAWARE LIMITED PARTNERSHIP)
We have audited the accompanying balance sheet of Atlas America Public #15-2005
(A) L.P. (A Delaware Limited Partnership) as of August 5, 2005. 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. The Partnership is not required to
have, nor were we engaged to perform an audit of its internal control over
financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Partnership's internal control over
financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our 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 #15-2005
(A) L.P. as of August 5, 2005, in conformity with accounting principles
generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
August 5, 2005 (except for the last sentence of the third paragraph of Note 1,
as to which the date is September 23, 2005)
F-1
Atlas America Public #15-2005 (A) L.P.
(A Delaware Limited Partnership)
BALANCE SHEET
August 5, 2005
ASSETS
Cash $ 100
============
PARTNER'S CAPITAL
Partners' capital $ 100
============
The accompanying notes to financial statement are an
integral part of this statement.
F-2
Atlas America Public #15-2005 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT
AUGUST 5, 2005
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
Atlas America Public #15-2005 (A) 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, will be Managing General Partner and Operator, and
subscribers to units will be either Limited Partners or Investor
General Partners depending upon their individual elections.
The Partnership 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,
western New York and north central Tennessee.
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 up to a .5% reimbursement of the selling agents' bona fide 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 $200,000,000) by December 31, 2005.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF ACCOUNTING
The Partnership prepares 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-3
Atlas America Public #15-2005 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT (CONTINUED)
AUGUST 5, 2005
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 his or her pro-rata share under the
partnership agreement of all items of Partnership income and
deductions in computing his or her 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 (1) 0% 100%
Equipment costs (2) (2)
Operating costs, administrative costs, direct costs,
and all other costs (3) (3)
PARTNERSHIP REVENUES
Interest income (4) (4)
Equipment proceeds (2) (2)
All other revenues including production revenues (5) (6) (5) (6)
F-4
Atlas America Public #15-2005 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT (CONTINUED)
AUGUST 5, 2005
4. PARTICIPATION IN REVENUES AND COSTS (CONTINUED)
(1) An amount equal to 90% of the subscription proceeds of investor
partners in the partnership will be used to pay 100% of the
intangible drilling costs incurred by the partnership in
drilling and completing its wells.
(2) An amount equal to 10% of the subscription proceeds of investor
partners in the partnership will be used to pay a portion of the
equipment costs incurred by the partnership in drilling and
completing its wells. All equipment costs in excess of that
amount 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.
(3) 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.
(4) Interest earned on subscription proceeds before the final
closing of the partnership will be credited to investor
partners' accounts and paid not later than the partnerships
first cash distribution 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.
(5) 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 bear 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 40% of partnership revenues.
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 an unaccountable, fixed payment
reimbursement of $15,000 per well for the investor partners'
share of Atlas Resources' general and administrative overhead
cost, plus 15%, which will be proportionately reduced if the
partnership's working interest in a well is less than 100%.
F-5
Atlas America Public #15-2005 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT (CONTINUED)
AUGUST 5, 2005
4. PARTICIPATION IN REVENUES AND COSTS (CONTINUED)
(6) The actual allocation of partnership revenues between the
managing general partner and the investor partners will vary
from the allocation described in (5) 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 an unaccountable, fixed payment reimbursement to Atlas
Resources of the investor partners' share of general and administrative
overhead cost of $15,000 per well, plus 15%, which will be
proportionately reduced if the Partnership's working interest in a well
is less than 100%. The cost of the wells will include all ordinary and
actual costs of drilling, testing and completing the wells.
Atlas Resources will receive an unaccountable, fixed payment
reimbursement for its administrative costs of $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%.
Atlas Resources will charge the partnership a fee for gathering and
transportation at a competitive rate (currently in the range of $.20 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 $8,411 per prospect which will be proportionately
reduced if the Partnership's working interest is the prospect is less
than 100%).
F-6
Atlas America Public #15-2005 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT (CONTINUED)
AUGUST 5, 2005
5. TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES (CONTINUED)
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 after five years from the partnership's first cash
distribution from operations 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 PRODUCER
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 investor partners of cash
distributions from the Partnership equal to at least a 10% return of
capital, 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 the Partnership's first cash distribution from
operations.
8. INDEMNIFICATION
In order to limit the potential liability of the investor general
partners for partnership liabilities and obligations, Atlas Resources
has agreed to indemnify each investor general partner from any
liability incurred which exceeds such partner's share of undistributed
Partnership net assets and insurance proceeds.
F-7
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2004 and
2003, 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 Standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. 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, 2004 and 2003, 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.
/s/ Grant Thornton LLP
Cleveland, Ohio
November 22, 2004
F-8
ATLAS RESOURCES , INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2004 AND 2003
2004 2003
--------- ---------
(in thousands, except share
data)
ASSETS
Current assets:
Cash and cash equivalents ........................................... $ 242 $ 4,702
Accounts receivable ................................................. 7,080 4,895
Prepaid expenses .................................................... 1,488 532
--------- ---------
Total current assets .............................................. 8,810 10,129
Property and equipment:
Oil and gas properties and equipment (successful efforts) .......... 120,506 85,199
Buildings and land ................................................. 2,947 2,830
Other .............................................................. 368 414
--------- ---------
123,821 88,443
Less - accumulated depreciation, depletion, and amortization ........... (23,654) (16,388)
--------- ---------
Net property and equipment ......................................... 100,167 72,055
Goodwill (net of accumulated amortization of $2,320) ................... 20,868 20,868
Intangible assets (net of accumulated amortization of $2,909 and $2,431) 3,444 3,922
--------- ---------
$ 133,289 $ 106,974
========= =========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt ................................... $ 56 $ 56
Accounts payable .................................................... 5,304 6,223
Liabilities associated with drilling contracts ...................... 29,375 18,609
Accrued liabilities ................................................. 3,174 4,423
Advances and note from parent ....................................... 66,725 51,150
--------- ---------
Total current liabilities ...................................... 104,634 80,461
Asset retirement obligation ............................................ 1,910 701
Long-term debt ......................................................... 82 138
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
Retained earnings ................................................... 10,156 9,167
--------- ---------
Total stockholder's equity ........................................ 26,663 25,674
--------- ---------
$ 133,289 $ 106,974
========= =========
See accompanying notes to consolidated financial statements
F-9
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2004 AND 2003
2004 2003
-------- --------
(in thousands)
REVENUES
Well Drilling ...................................... $ 86,880 $ 52,879
Gas and Oil Production ............................. 23,098 16,091
Well Services ...................................... 4,137 3,507
Transportation ..................................... 2,476 2,507
Other .............................................. 44 130
-------- --------
116,635 75,114
COSTS AND EXPENSES
Well Drilling ...................................... 75,548 45,982
Gas and oil production and exploration ............. 2,580 2,312
Well Services ...................................... 1,648 923
Non-direct ......................................... 24,831 15,985
Depreciation, depletion and amortization ........... 8,197 6,229
Interest ........................................... 2,625 2,375
-------- --------
115,429 73,806
Income from operations before income taxes ......... 1,206 1,308
Provision for income taxes ......................... 217 275
-------- --------
Income before cumulative effect of accounting change 989 1,033
Cumulative effect of change in accounting principle,
net of income taxes of $65 ....................... -- 120
-------- --------
Net income ......................................... $ 989 $ 1,153
======== ========
See accompanying notes to consolidated financial statements
F-10
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2004 AND 2003
2004 2003
----------- --------
(in thousands)
Net income................................................................................... $ 989 $ 1,153
Other comprehensive income (loss):
Unrealized holding losses on natural gas futures arising during the period , net of taxes of
$245.................................................................................... - (541)
Less: reclassification adjustment for losses realized in net income, net of taxes of
$355.................................................................................... - 753
---------- -----------
- 212
---------- -----------
Comprehensive income.......................................................................... $ 989 $ 1,365
========== ==========
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, 2004 AND 2003
(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, October 1, 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
------------ --------- ------------- ---------- ----------- -------------
Net income................................... - - - - 989 989
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2004 200 $ 2 $ 16,505 $ - $ 10,156 $ 26,663
============ ========= ============= ========== =========== =============
See accompanying notes to consolidated financial statements
F-12
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2004 AND 2003
2004 2003
-------- --------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .......................................................... $ 989 $ 1,153
Adjustments to reconcile net income to net cash provided by operating
activities:
Cumulative effect of change in accounting principle .............. -- (120)
Depreciation, depletion and amortization ......................... 8,197 6,229
Management fees and interest on intercompany note due to parent .. 32,809 15,074
Gain on sale of assets ........................................... (11) (19)
Change in operating assets and liabilities ...................... 4,016 17,637
-------- --------
Net cash provided by operating activities ........................... 46,000 39,954
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ................................................ (33,051) (21,106)
Proceeds from sale of assets ........................................ 33 19
-------- --------
Net cash used in investing activities ............................... (33,018) (21,087)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings .................................... (56) (34)
Net payments to Parent .............................................. (17,386) (14,829)
-------- --------
Net cash used in financing activities ............................... (17,442) (14,863)
-------- --------
Increase (decrease) in cash and cash equivalents .................... (4,460) 4,004
Cash and cash equivalents at beginning of year ...................... 4,702 698
-------- --------
Cash and cash equivalents at end of year ............................ $ 242 $ 4,702
======== ========
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), a publicly traded company trading under the symbol ATLS on the
NASDAQ System. 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 2003
consolidated financial statements to conform to the fiscal 2004 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 in its consolidated financial statements
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 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,
2004 2003
--------- ---------
(in thousands)
Mineral interest in properties:
Proved properties ..................................................... $ 1 $ 1
Unproved properties ................................................... 463 25
Wells and related equipment ............................................... 118,942 84,435
Support equipment ......................................................... 1,100 738
Other ..................................................................... 3,315 3,244
--------- ---------
123,821 88,443
Accumulated depreciation, depletion, amortization and valuation allowances:
Oil and gas properties ................................................ (22,623) (15,834)
Other ................................................................. (1,031) (554)
--------- ---------
(23,654) (16,388)
--------- ---------
$ 100,167 $ 72,055
========= =========
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.
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.
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)
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 the fiscal years ended September 30, 2004 and
2003.
Upon the sale or retirement of a complete 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 either a
proved or unproved property is sold, any funds received are accounted for as a
reduction of the cost in the interest retained.
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.
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 of $185,000 before taxes 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.
F-16
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
.. 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 years ended September 30, 2004 and 2003 is as follows
(in thousands):
2004 2003
---- ----
Asset retirement obligations, beginning of year ....... $ 701 $ -
Adoption of SFAS 143................................... - 681
Liabilities incurred................................... 1,212 93
Liabilities settled.................................... (40) (53)
Revision in estimates.................................. (60) (66)
Accretion expense...................................... 97 46
--------- ---------
Asset retirement obligations, end of year.............. $ 1,910 $ 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
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, 2004, the Company
had $242,000 in deposits at various banks, of which $132,000 is over the
insurance limit of the Federal Deposit Insurance Corporation. No losses have
been experienced on such investments.
F-17
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
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, 2004, 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 income from the Company's general partner interest is recorded when
the gas and oil are sold by a partnership.
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 90 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.
The Company recognizes well services revenues at the time the services
are performed.
The Company is entitled to receive well operating 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 retains a working interest and/or overriding royalty in the
wells it contracts to drill on behalf of its sponsored energy partnership. The
Company records the income from the working interests and overriding royalties
when the gas and oil are sold.
F-18
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
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,
2004 2003
----------- --------
(in thousands)
CASH PAID DURING THE YEARS FOR:
Interest............................................... $ 3 $ 110
Income taxes (refunded) paid........................... $ (223) $ 363
NON-CASH ACTIVITIES INCLUDE THE FOLLOWING:
Fixed asset purchases financed with long-term debt $ - $ 228
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 its calculated effective rate of 18% and 21%
for fiscal years 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.
NOTE 3 -- OTHER ASSETS, 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, 2004 and
2003 was approximately $478,000. The estimated amortization expense for each of
the next five fiscal years is $478,000
GOODWILL
The Company adopted SFAS No. 142 ("SFAS 142") "Goodwill and Other
Intangible Assets," which requires that goodwill no longer be amortized, but
instead evaluated for impairment at least annually. The Company performs an
annual evaluation 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.
F-19
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
Advances and note from Parent represents amounts owed for advances and
transactions in the normal course of business and a note payable to the parent.
Both the note and the advances, which have no repayment terms, are subordinated
to any third-party debt. The note, which together with any unpaid interest is
due on demand by the Parent, has a face amount of $15.0 million and accrues
interest at an annual rate of 9.50% on any unpaid balances. Interest expense
related to the note, which is being deferred, was $2.1 million and $1.9 million
for the years ended September 30, 2004 and 2003. The advances have no repayment
terms, therefore, the Company has classified the amounts due the Parent as a
current liability on its Consolidated Balance Sheets.
The Company is dependent on it's Parent for management and
administrative functions and financing for its capital expenditures. The Company
pays a management fee to its Parent for management and administrative services,
which amounted to $23.7 million and $13.1 million for the years ended September
30, 2004 and 2003, respectively.
NOTE 5 - DEBT
At September 30,
2004 2003
----------- -----------
(in thousands)
Long-term debt........................ $ 138 $ 194
Less current portion.................. (56) (56)
----------- -----------
$ 82 $ 138
========== ==========
Future annual debt principal payments are as follows: (in thousands):
2005.............. $ 56
2006.............. 56
2007.............. 26
During the 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. One 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 had an original term of 48
months.
F-20
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 6 - 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% to 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 Parent may draw from its revolving credit facility on behalf of the
Company. In July 2002, the Company's parent entered into a $75.0 million credit
facility led by Wachovia Bank, which has a current borrowing base of $75.0
million. 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 the 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 March 2007, when all outstanding borrowings
must be repaid, 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. At September 30, 2004 and 2003,
$26.7 million and $32.3 million, respectively, were outstanding under this
facility, including $1.7 million and $1.3 million at September 30, 2004 and 2003
under letters of credit. The interest rates ranged from 3.69% to 5.0% at
September 30, 2004. The Company had no amounts due under this facility at
September 30, 2004 and 2003 for borrowings on its behalf.
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-21
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 were to be determined that a derivative is not highly
effective as a hedge due to the loss of correlation between changes in gas
reference prices under a hedging instrument and actual gas prices, the Company
would discontinue hedge accounting for the derivative and subsequent changes in
its fair value would be recognized immediately into earnings.
At September 30, 2004 and 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 such contracts at those dates. The Company
recognized a loss of $1.1 million on settled contracts covering natural gas
production for the year ended September 30, 2003. The Company recognized no
gains or losses during the periods ended September 30, 2004 and September 30,
2003 for hedge ineffectiveness or from 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, 2004 and 2003, gas sales to First Energy
Solutions Corporation accounted for 10% and 15%, respectively, of total
revenues.
F-22
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,
2004 2003
-------- --------
(in thousands)
Revenues .................................................................... $ 23,098 $ 16,091
Production costs ............................................................ (2,107) (1,992)
Exploration expenses ........................................................ (473) (320)
Depreciation, depletion and amortization .................................... (7,445) (5,605)
Income taxes ................................................................ (4,256) (2,609)
-------- --------
Results of operations from oil and gas producing activities ................. $ 8,817 $ 5,565
======== ========
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,
2004 2003
---------- --------
(in thousands)
Proved properties............................................................ $ 1 $ 1
Unproved properties.......................................................... 463 25
Wells and related equipment and facilities................................... 118,942 84,435
Support equipment and facilities............................................. 1,100 738
----------- -----------
120,506 85,199
Accumulated depreciation, depletion, amortization and
valuation allowances....................................................... (22,623) (15,834)
------------ -----------
Net capitalized costs................................................... $ 97,883 $ 69,365
=========== ===========
Costs Incurred in Oil and Gas Producing Activities. The costs incurred
by the Company in its oil and gas activities during the periods indicated are as
follows:
Years Ended September 30,
2004 2003
---------- --------
(in thousands)
Property acquisition costs:
Unproved properties........................................................ $ 438 $ -
Proved properties.......................................................... $ - $ -
Exploration costs............................................................ $ 473 $ 320
Development costs............................................................ $ 32,766 $ 24,588
The development costs above for the years ended September 30,
2004 and 2003 were substantially all incurred for the development of proved
undeveloped properties.
F-23
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, 2004 and 2003. 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-24
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, 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
========== ======
Current additions................................................ 26,806,939 235,902
Transfers to limited partnerships................................ (7,808,942) (15,217)
Revisions........................................................ (6,493,890) (7,135)
Production....................................................... (3,872,923) (15,898)
----------- --------
Balance September 30, 2004............................................ 92,461,562 260,067
========== =======
Proved developed reserves at:
September 30, 2004............................................... 46,580,498 111,168
September 30, 2003............................................... 39,021,728 33,021
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, 2004 and 2003 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,
2004 2003
---------- --------
(in thousands)
Future cash inflows..................................................... $ 652,811 $ 413,066
Future production costs................................................. (79,989) (83,577)
Future development costs................................................ (91,195) (71,299)
Future income tax expense............................................... (122,962) (63,138)
------------ -----------
Future net cash flows................................................... 358,665 195,052
Less 10% annual discount for estimated timing of cash flows........... (222,143) (117,318)
------------ -----------
Standardized measure of discounted future net cash flows.............. $ 136,522 $ 77,734
=========== ===========
The future cash flows estimated to be spent to develop proved
undeveloped properties in the years ended September 30, 2005, 2006 and 2007 are
$36.0 million, $36.0 million and $19.2 million, respectively.
F-25
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,
2004 2003
----------- -----------
(in thousands)
Balance, beginning of year.............................................. $ 77,734 $ 48,602
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs.............. (20,991) (14,099)
Net changes in prices and production costs............................ 59,345 20,455
Revisions of previous quantity estimates.............................. (10,197) 3,678
Purchases of reserves in place........................................ 270 -
Estimated settlement of asset retirement obligations.................. (1,209) (701)
Estimated proceeds on disposal of well equipment...................... 190 100
Development costs incurred............................................ 4,838 3,689
Changes in future development costs................................... (1,033) (158)
Transfers to limited partnerships..................................... (9,835) (3,326)
Extensions, discoveries, and improved recovery less
related costs...................................................... 54,979 24,574
Accretion of discount................................................. 9,697 17,082
Net changes in future income taxes.................................... (23,737) (7,085)
Other................................................................. (3,529) (15,077)
----------- -----------
Balance, end of year.................................................... $ 136,522 $ 77,734
=========== ===========
F-26
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
ATLAS RESOURCES, INC. AND SUBSIDIARY
JUNE 30, 2005
F-27
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
(UNAUDITED)
JUNE 30, SEPTEMBER 30,
2005 2004
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents ........................................... $ 717 $ 242
Accounts receivable ................................................. 7,410 7,080
Prepaid expenses .................................................... 2,288 1,488
--------- ---------
Total current assets .............................................. 10,415 8,810
Property and equipment:
Oil and gas properties and equipment (successful efforts) .......... 164,610 120,506
Buildings and land ................................................. 2,993 2,947
Other .............................................................. 378 368
--------- ---------
123,821
167,981
Less - accumulated depreciation, depletion and amortization ............ (29,262) (23,654)
--------- ---------
Net property and equipment ......................................... 138,719 100,167
Goodwill (net of accumulated amortization of $2,320) ................... 20,868 20,868
Intangible assets (net of accumulated amortization of $3,266 and $2,909) 3,115
3,444
--------- ---------
$ 173,117 $ 133,289
========= =========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt ................................... $ 58 $ 56
Accounts payable .................................................... 9,399 5,304
Liabilities associated with drilling contracts ...................... 55,627 29,375
Accrued liabilities ................................................. 3,901 3,174
Advances and note to Affiliates ..................................... 57,878 66,725
--------- ---------
Total current liabilities ...................................... 126,863 104,634
Asset retirement obligations ........................................... 3,914 1,910
Long-term debt ......................................................... 37 82
Stockholder's equity:
Common stock, stated at $10 per share;
500 authorized shares; 200 shares issued and outstanding .......... 2 2
Additional paid-in capital .......................................... 30,505 16,505
Retained earnings ................................................... 11,796 10,156
--------- ---------
Total stockholder's equity ........................................ 42,303 26,663
--------- ---------
$ 173,117 $ 133,289
========= =========
See accompanying notes to consolidated financial statements
F-28
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
NINE MONTHS ENDED JUNE 30, 2005 AND 2004
(In thousands)
(UNAUDITED)
2005 2004
-------- --------
REVENUES
Well drilling ............................ $ 98,758 $ 64,577
Gas and oil production ................... 23,098 16,704
Well services ............................ 6,115 4,836
Other income ............................. 87 114
-------- --------
128,058 86,231
COSTS AND EXPENSES
Well drilling ............................ 85,876 56,154
Gas and oil production and exploration ... 3,329 2,562
Well services ............................ 1,428 1,138
Non-direct ............................... 26,315 17,538
Depreciation, depletion and amortization . 6,813 5,989
Interest ................................. 2,144 1,843
Other expense ............................ 153 --
-------- --------
126,058 85,224
-------- --------
Income from operations before income taxes 2,000 1,007
Provision for income taxes ............... 360 212
-------- --------
Net income ............................... $ 1,640 $ 795
======== ========
See accompanying notes to consolidated financial statements
F-29
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
NINE MONTHS ENDED JUNE 30, 2005
(In thousands, except share data)
(UNAUDITED)
ADDITIONAL TOTALS
COMMON STOCK PAID-IN RETAINED STOCKHOLDER'S
SHARES AMOUNT CAPITAL EARNINGS EQUITY
----------- --------------- --------------- ------------- ----------------
Balance, October 1, 2004........ 200 $ 2 $ 16,505 $ 10,156 $ 26,663
Contributed capital................. - - 14,000 - 14,000
Net Income.......................... - - - 1,640 1,640
--------- ----------- ------------- ----------- ---------------
Balance June 30, 2005............... 200 $ 2 $ 30,505 $ 11,796 $ 42,303
========= =========== ============= =========== ===============
See accompanying notes to consolidated financial statements
F-30
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NINE MONTHS ENDED JUNE 30, 2005 AND 2004
(In thousands)
(UNAUDITED)
2005 2004
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ...................................................................... $ 1,640 $ 795
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization ..................................... 6,813 5,989
Management fees, cost allocations and intercompany interest paid to affiliates 32,435 23,265
Gain on sale of assets ....................................................... (15) (11)
Change in operating assets and liabilities ................................... 29,914 (5,859)
-------- --------
Net cash provided by operating activities ....................................... 70,787 24,179
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ............................................................ (42,281) (16,442)
Proceeds from sale of assets .................................................... 17 33
-------- --------
Net cash used in investing activities ........................................... 42,264) (16,409)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings ................................................ (43) (42)
Net payments to Affiliates ...................................................... (28,005) (11,608)
-------- --------
Net cash used in financing activities ........................................... (28,048) (11,650)
Increase (decrease) in cash and cash equivalents ................................ 475 (3,880)
Cash and cash equivalents at beginning of period ................................ 242 4,702
-------- --------
Cash and cash equivalents at end of period ...................................... $ 717 $ 822
======== ========
See accompanying notes to consolidated financial statements
F-31
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - MANAGEMENT'S OPINION REAGARDING INTERIM FINANCIAL STATEMENTS
The consolidated financial statements of Atlas Resources, Inc. and its
wholly-owned subsidiary (the "Company") as of June 30, 2005 are unaudited. Atlas
Resources, Inc. is a wholly-owned subsidiary of Atlas America, Inc. (the
"Parent" or "Atlas"). 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 consolidated financial statements and the information and tables
contained in the notes to the consolidated financial statements as of June 30,
2005 and for the three months and nine months ended June 30, 2005 and 2004 are
unaudited. Certain information and footnote disclosures normally included in
financial statements prepared in accordance with accounting principles generally
accepted in the United States of America have been condensed or omitted in these
statements pursuant to the rules and regulations of the Securities and Exchange
Commission. However, in the opinion of management, these interim financial
statements include all the necessary adjustments to fairly present the results
of the interim periods presented. The results of operations for the three months
and nine months ended June 30, 2005 may not necessarily be indicative of the
results of operations for the full fiscal year ending September 30, 2005.
Certain reclassifications have been made to the consolidated financial
statements as of September 30, 2004 and for the three months and nine months
ended June 30, 2004 to conform to the presentation as of and for the three
months and nine months ended June 30, 2005.
SPIN-OFF OF ATLAS FROM RESOURCE AMERICA, INC.
On June 30, 2005, Resource America, Inc. ("RAI") (NASDAQ: REXI)
distributed its remaining 10.7 million shares of Atlas to its stockholders in
the form of a tax-free dividend. Each stockholder of RAI received 0.59367 shares
of Atlas for each share of RAI common stock owned as of June 24, 2005, the
record date. Although the distribution itself is tax-free to RAI stockholders,
as a result of the deconsolidation there may be some tax liability arising from
prior unrelated corporate transactions among Atlas and some of its subsidiaries.
Any liability arising from this transaction will be reimbursed by Atlas to RAI.
Atlas (and the Company) no longer consolidates with RAI as of June 30, 2005. In
connection with the spin-off, RAI and Atlas entered into a series of agreements,
including a master separation and distribution agreement and a tax matters
agreement, which will govern the future contractual obligations between the two
companies.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
RECEIVABLES
In evaluating its allowance for possible losses, the Company performs
ongoing credit evaluations of its customers and adjusts credit limits based upon
payment history and the customers' current creditworthiness, as determined by
the Company's review of its customers' credit information. The Company extends
credit on an unsecured basis to many of its energy customers. At June 30, 2005
and September 30, 2004, the Company's credit evaluation indicated that it has no
need for an allowance for possible losses.
REVENUE RECOGNITION
Because there are timing differences between the delivery of natural
gas, natural gas liquids ("NGL's") and oil and the Company's receipt of a
delivery statement, the Company has unbilled revenues. These revenues are
accrued based upon volumetric data from the Company's records and the Company's
estimates of the related transportation and compression fees, which are, in
turn, based upon applicable product prices. The Company had unbilled trade
receivables at June 30, 2005 and September 30, 2004 of $6.2 million and $4.9
million respectively, which are included in Accounts Receivable, on its
Consolidated Balance Sheets.
F-32
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
SUPPLEMENTAL DISCLOSURE OF 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:
NINE MONTHS ENDED
JUNE 30,
2005 2004
--------- --------
(in thousands)
CASH PAID DURING THE PERIODS FOR:
Interest ........................................ $ 489 $ -
Income taxes paid................................ $ 1 $ -
COMPREHENSIVE INCOME
Comprehensive income 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." The Company has no elements of
comprehensive income other than net income to report.
RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS
In May 2005, the Financial Accounting Standards Board, ("FASB")
issued Statement No. 154, Accounting Changes and Error Corrections ("SFAS 154").
SFAS 154 requires retrospective application to prior periods' financial
statements of changes in accounting principle. It also requires that the new
accounting principle be applied to the balances of assets and liabilities as of
the beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening balance
of retained earnings for that period rather than being reported in an income
statement. The statement will be effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
The impact of SFAS 154 will depend on the nature and extent of any voluntary
accounting changes and correction of errors after the effective date, but
management does not currently expect SFAS 154 to have a material impact on the
Company's financial position or results of operations.
In April 2005, the FASB issued FASB Staff Position No. FAS 19-1 ("FSP
FAS 19-1"), which addressed a discussion that was ongoing within the oil and gas
industry regarding capitalization of costs of drilling exploratory wells.
Paragraph 19 of FASB Statement No. 19, Financial Accounting and Reporting by Oil
and Gas Producing Companies ("FASB No. 19"), requires costs of drilling
exploratory wells to be capitalized pending determination of whether the well
has found proved reserves. If the well has found proved reserves, the
capitalized costs become part of the entity's wells, equipment, and facilities;
if, however, the well has not found proved reserves, the capitalized costs of
drilling the well are expensed. Questions arose in practice about the
application of this guidance due to changes in oil and gas exploration processes
and lifecycles. The issue was whether there are circumstances that would permit
the continued capitalization of exploratory well costs if reserves cannot be
classified as proved within one year following the completion of drilling other
than when additional exploration wells are necessary to justify major capital
expenditures and those wells are underway or firmly planned for in the near
future. FSP FAS 19-1 amends FASB No. 19 to allow for the continued
capitalization of suspended well costs when the well has found a sufficient
quantity of reserves to justify its completion as a producing well and the
enterprise is making sufficient progress assessing the reserves and the
F-33
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS (CONTINUED)
economic and operating viability of the plan. This guidance requires management
to exercise more judgment than was previously required and also requires
additional disclosure. This new guidance is effective for the first reporting
period beginning after April 4, 2005 and is to be applied prospectively to
existing and newly capitalized exploratory well costs. Management does not
believe this statement of position will have a significant effect on the
Company's financial statements.
In March 2005, the FASB issued FASB Interpretation No. 47, Accounting
for Conditional Asset Retirement Obligations ("FIN 47"), which will result in
(a) more consistent recognition of liabilities relating to asset retirement
obligations, (b) more information about expected future cash outflows associated
with those obligations, and (c) more information about investments in long-lived
assets because additional asset retirement cost will be recognized as part of
the carrying amounts of the assets. FIN 47 clarifies that the term conditional
asset retirement obligation as used in SFAS No. 143, Accounting for Asset
Retirement Obligations, refers to a legal obligation to perform an asset
retirement activity in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity. The obligation to perform the asset retirement activity is unconditional
even though uncertainty exists about the timing and (or) method of settlement.
Uncertainty about the timing and (or) method of settlement of a conditional
asset retirement obligation should be factored into the measurement of the
liability when sufficient information exists. Management does not believe this
statement of position will have a significant effect on the Company's financial
statements.
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 2005 and 2004 is as follows (in
thousands):
JUNE 30, JUNE 30,
----------- ----------
2005 2004
---- ----
Asset retirement obligations, beginning of period .................. $ 1,910 $ 701
Liabilities incurred................................................ 2,057 151
Liabilities settled................................................. (7) (18)
Revision of estimates............................................... (183) 5
Accretion expense................................................... 137 37
----------- ----------
Asset retirement obligations, end of period......................... $ 3,914 $ 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% to 10% of
the units in any calendar year. Based on past experience, the Company believes
that any liability incurred would not be material.
F-34
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4 - COMMITMENTS AND CONTINGENCIES (CONTINUED)
The Company may be required to subordinate a part of its net
partnership revenues to the receipt by investor partners of cash distributions
from their 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 Parent may draw from its revolving credit facility on behalf of the
Company. In March 2004, the Company's parent entered into a credit facility led
by Wachovia Bank, which has a current borrowing base of $75.0 million. The
facility permits draws based on the remaining proved developed producing and
non-producing and proved undeveloped natural gas and oil reserves attributable
to the Parent's interest in wells and the projected fees and revenues from
operation of the wells and the administration of their energy partnerships. The
facility is secured by the Parent's assets, including those of the Company. The
revolving credit facility has a term ending in March 2007. At June 30, 2005, the
Parent had $12.0 million outstanding under this facility, plus $1.4 million
under letters of credit. The Company had no amounts outstanding under this
facility for borrowings on its behalf at June 30, 2005.
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.
NOTE 5- INCOME TAXES
The Company is included in the consolidated federal income tax return
of Atlas' parent, Resource America, Inc. ("RAI") through June 30, 2005 and its
Parent is responsible for the payment to RAI of federal income taxes to that
date. Income taxes are presented as if the Company had filed a return on a
separate company basis utilizing their calculated effective rate of 18% and 21%
for the nine months ended June 30, 2005, (the spin-off date, see note 1) and
2004, respectively. The Company's effective tax rate is lower than the federal
statutory rate due to the benefit of percentage depletion. Deferred taxes, which
are included in Advances and note to Affiliates in the Company's consolidated
balance sheet, 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 #15-2005(A) 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 certain proposed prospects
and the wells which will be drilled on the prospects by Atlas America Public
#15-2005(A) L.P., which is the first partnership in the program and must be
closed by December 31, 2005. It is referred to in this section as the "2005(A)
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." The managing general partner does not anticipate that the wells will be
selected in the order in which they are set forth below. Also, the wells
currently proposed to be drilled by the 2005(A) Partnership when its
subscription proceeds are released from escrow, and from time to time
thereafter, are 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 $12.5 million
is raised and the 2005(A) 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.
Also, the managing general partner anticipates selecting wells in Armstrong
County, Pennsylvania and north central Tennessee. As of the date of the
prospectus the managing general partner has not identified any specific well,
but has provided a United Energy Development Consultants, Inc. geological
evaluation for those areas.
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 2005(A) Partnership or any of the other three
partnerships, and you should rely only on the information in this prospectus.
The currently proposed wells will be assigned to the 2005(A) Partnership 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 by the 2005(A)
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.
1
Any substituted and/or additional wells will meet the same general criteria that
the managing general partner used in selecting the currently proposed wells, and
generally will 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.
The information regarding the currently proposed wells is intended to help you
evaluate the economic potential and risks of drilling the proposed wells. This
includes production information for wells in the same general area as 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 2005(A) 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." The managing general partner has proposed these
wells to be drilled, even though there is no production data for other wells in
the immediate area available to the managing general partner, 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
this information is, when used for predicting the ultimate recovery of
a well.
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 Greene
Counties. Also, each well in a geological formation or reservoir 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 (generally, the ultimate amount of natural
gas and oil recoverable from a well) 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 completed, but not on-line to sell production; or
o producing for only a short period of time.
2
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.
To help you become familiar with the proposed wells the information set forth
below is included.
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, Greene and Westmoreland Counties, Pennsylvania......................................6
o Location and Production Maps for Fayette, Greene and Westmoreland Counties, Pennsylvania showing the proposed
wells and the wells in the area..................................................................9
o Production data for Fayette, Greene and Westmoreland Counties, Pennsylvania.......................................17
o United Energy Development Consultants, Inc.'s geologic evaluation for the currently proposed wells in Fayette,
Greene and Westmoreland Counties, Pennsylvania..................................................32
o Western Pennsylvania (Clinton/Medina Geological Formation)
o Lease information for western Pennsylvania and eastern Ohio.......................................................38
o Location and Production Map for western Pennsylvania and eastern Ohio showing the proposed wells and the wells in
the area........................................................................................40
o Production data for western Pennsylvania and eastern Ohio.........................................................45
o United Energy Development Consultants, Inc.'s geologic evaluation for the currently proposed wells in western
Pennsylvania and eastern Ohio...................................................................47
o Armstrong County, Pennsylvania (Upper Devonian Sandstone Reservoirs)
o United Energy Development Consultants, Inc.'s geologic evaluation for the primary drilling area in Armstrong and
Indiana Counties, Pennsylvania..................................................................53
o McKean County, Pennsylvania (Upper Devonian Sandstone Reservoirs)
o Lease information for McKean County, Pennsylvania.................................................................59
o Location and Production Maps for McKean County, Pennsylvania showing the proposed wells and the wells
in the area.....................................................................................61
o Production data for McKean County, Pennsylvania...................................................................65
o United Energy Development Consultants, Inc.'s geologic evaluation for the currently proposed wells in McKean
County, Pennsylvania............................................................................68
o Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee (Mississippian Carbonate and Devonian Shale
Reservoirs)
o A map of Tennessee showing its Counties...........................................................................73
o United Energy Development Consultants, Inc.'s geologic evaluation for the primary drilling area in Anderson,
Campbell, Morgan, Roane and Scott Counties, Tennessee...........................................75
3
MAP OF WESTERN PENNSYLVANIA
AND
EASTERN OHIO
4
[GRAPHIC OMITTED: MAP OF WESTERN PENNSYLVANIA AND EASTERN OHIO]
5
LEASE INFORMATION
FOR
FAYETTE, GREENE AND WESTMORELAND COUNTIES, PENNSYLVANIA
6
OVERRIDING ROYALTY
INTEREST TO THE
EFFECTIVE EXPIRATION LANDOWNER MANAGING GENERAL
PROSPECT NAME COUNTY DATE* DATE* ROYALTY PARTNER
1 Anden #3 Westmoreland 12/6/2002 12/6/2005 12.5% 0%
2 Angeline #2 Fayette 2/10/2003 HBP 12.5% 0%
3 BASD #3 Fayette 6/30/2003 6/30/2006 12.5% 0%
4 Betchy #2 Fayette 2/16/2005 HBP 12.5% 0%
5 Black #3 Fayette 6/1/2005 6/1/2006 12.5% 0%
6 Black #5 Fayette 6/1/2005 6/1/2006 12.5% 0%
7 Blower #5 Fayette 10/8/2000 10/8/2005 12.5% 0%
8 Brown #11 Fayette 1/13/2005 HBP 12.5% 0%
9 Cochrane #2 Fayette 5/5/1998 HBP 12.5% 0%
10 Cochrane/Meshanko #1 Fayette 7/27/2005 8/27/2006 12.5% 0%
11 Darr #6 Greene 5/13/2002 5/13/2007 12.5% 0%
12 Darr #7 Greene 5/13/2002 5/13/2007 12.5% 0%
13 Evans #3 Westmoreland 5/16/2005 5/16/2010 12.5% 0%
14 Gillis #2 Washington 5/29/2004 5/29/2009 12.5% 0%
15 Glumac #4 Fayette 1/31/2003 HBP 12.5% 0%
16 Hunt #4 Greene 5/2/2002 5/2/2007 12.5% 0%
17 Johnson #8 Fayette 5/3/2005 5/3/2007 12.5% 0%
18 Kovach #8 Fayette 12/23/2004 12/23/2007 12.5% 0%
19 Kubitza #4 Fayette 10/13/2003 10/13/2005 12.5% 0%
20 L&J Equipment #5 Fayette 7/12/2005 7/12/2006 12.5% 0%
21 L&J Equipment #7 Fayette 7/12/2005 7/12/2006 12.5% 0%
22 Lapkowicz #1 Washington 4/12/2005 4/12/2009 12.5% 0%
23 Lech/Brown #1 Fayette 1/19/2005 1/19/2010 12.5% 0%
24 Miller #42 Fayette 12/3/2004 12/3/2009 12.5% 0%
25 Miller #43 Fayette 12/3/2004 12/3/2009 12.5% 0%
26 Mood #4 Fayette 10/30/2003 11/1/2005 12.5% 0%
27 Mroz #1 Greene 5/9/2002 5/9/2007 12.5% 0%
28 Mutich #1 Fayette 4/28/2003 4/28/2008 12.5% 0%
29 Phillips #12 Greene 11/26/2001 11/25/2006 12.5% 0%
30 Staun #2 Greene 8/17/2001 8/17/2006 12.5% 0%
31 T.J. Enterprise #1 Fayette 8/4/2005 8/4/2007 12.5% 0%
32 T.J. Enterprise #2 Fayette 8/4/2005 8/4/2007 12.5% 0%
33 T.J. Enterprise #3 Fayette 8/4/2005 8/4/2007 12.5% 0%
34 T.J. Enterprise #4 Fayette 8/4/2005 8/4/2007 12.5% 0%
35 Throckmorton #1 Greene 5/20/2002 5/20/2007 12.5% 0%
36 Throckmorton #2 Greene 5/20/2002 5/20/2007 12.5% 0%
37 Vignali #1 Fayette 1/28/2005 1/28/2007 12.5% 0%
38 Consol/USX #10 Greene 5/9/2001 HBP 12.5% 0%
39 Williams #31 Fayette 11/12/2004 11/12/2007 12.5% 0%
40 Yasenosky #1 Fayette 1/8/2005 1/8/2006 12.5% 0%
*HBP - Held by Production.
7
OVERRIDING
ROYALTY NET ACRES TO BE
INTEREST TO 3RD REVENUE WORKING NET ASSIGNED TO THE
PROSPECT NAME PARTIES INTEREST INTEREST ACRES PARTNERSHIP
1 Anden #3 0% 87.5% 100% 297 20
2 Angeline #2 0% 87.5% 100% 86 20
3 BASD #3 0% 87.5% 100% 25 20
4 Betchy #2 0% 87.5% 100% 69 20
5 Black #3 0% 87.5% 100% 278 20
6 Black #5 0% 87.5% 100% 278 20
7 Blower #5 0% 87.5% 100% 82 20
8 Brown #11 0% 87.5% 100% 131 20
9 Cochrane #2 0% 87.5% 100% 32 20
10 Cochrane/Meshanko #1 0% 87.5% 100% 124 20
11 Darr #6 0% 87.5% 100% 20 20
12 Darr #7 0% 87.5% 100% 20 20
13 Evans #3 0% 87.5% 100% 90 20
14 Gillis #2 0% 87.5% 100% 106 20
15 Glumac #4 0% 87.5% 100% 57 20
16 Hunt #4 0% 87.5% 100% 52 20
17 Johnson #8 0% 87.5% 100% 2 2
18 Kovach #8 0% 87.5% 100% 25 20
19 Kubitza #4 0% 87.5% 100% 90 20
20 L&J Equipment #5 0% 87.5% 100% 217 20
21 L&J Equipment #7 0% 87.5% 100% 217 20
22 Lapkowicz #1 0% 87.5% 100% 136 20
23 Lech/Brown #1 0% 87.5% 100% 43 20
24 Miller #42 0% 87.5% 100% 42 20
25 Miller #43 0% 87.5% 100% 42 20
26 Mood #4 0% 87.5% 100% 106 20
27 Mroz #1 0% 87.5% 100% 10 10
28 Mutich #1 0% 87.5% 100% 65 20
29 Phillips #12 0% 87.5% 100% 35 20
30 Staun #2 0% 87.5% 100% 59 20
31 T.J. Enterprise #1 0% 87.5% 100% 47 20
32 T.J. Enterprise #2 0% 87.5% 100% 47 20
33 T.J. Enterprise #3 0% 87.5% 100% 40 20
34 T.J. Enterprise #4 0% 87.5% 100% 40 20
35 Throckmorton #1 0% 87.5% 100% 80 20
36 Throckmorton #2 0% 87.5% 100% 80 20
37 Vignali #1 0% 87.5% 100% 29 20
38 Consol/USX #10 0% 87.5% 100% 671 20
39 Williams #31 0% 87.5% 100% 184 20
40 Yasenosky #1 0% 87.5% 100% 104 20
*HBP - Held by Production.
8
LOCATION AND PRODUCTION MAPS FOR
FAYETTE, GREENE AND WESTMORELAND COUNTIES, PENNSYLVANIA
9
[GRAPHIC OMITTED]
10
[GRAPHIC OMITTED]
11
[GRAPHIC OMITTED]
12
[GRAPHIC OMITTED]
13
[GRAPHIC OMITTED]
14
[GRAPHIC OMITTED]
15
[GRAPHIC OMITTED]
16
PRODUCTION DATA
FOR
FAYETTE, GREENE AND WESTMORELAND 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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
2 Manufacturers Light & Heat Co John & Effie Hospodavis N/A
7 Greensboro Gas Co. David Gans #2-427 11/18/1918
10 Manufacturers Light & Heat Co Hogsett #9 10/21/1947
11 Duquesne Natural Gas Co. John Spak #1 3/8/1941
15 Manufacturers Light & Heat Co Jos. Riffle #3 1928
16 Greensboro Gas Co. Riffle Heirs 4/6/1905
22 Manufacturers Light & Heat Co. Republic Colleries #2 N/A
24 Duquesne Natural Gas Co. Nora E. Cover #1 6/8/1940
27 Greensboro Gas Co. L. Oravets #669 1924
29 Carnegie Natural Gas Co H.C. Frick (Buffington) #2 9/7/1944
33 Gerthoffer & Jones Luthern Church #1 6/1/1927
36 Greensboro Gas Co. C.P. Goodwin #1 1923
41 Greensboro Gas Co. Hogsett #2 1/1/1922
50 Keystone Gas Co Mercer #1 11/7/1958
56 Manufacturers Light & Heat Co Brown #1 5/21/1945
61 Greensboro Gas Co. Emma Honsaker #1 12/20/1923
63 Manufacturers Light & Heat Co Hogsett #6 2/17/1945
66 Manufacturers Light & Heat Co Hogsett #8 5/26/1947
76 Greensboro Gas Co Diamond #1 5/10/1940
80 Manufacturers Light & Heat Co Cinci N/A
84 Greensboro Gas Co. Hogsett #5 8/30/1944
105 Orville Eberly Mayher #1 3/6/1947
118 Peoples Natural Gas Co Kovach #1 12/7/1943
119 W.Burkland Natale #1 6/19/1944
122 Equitable Gas Co H.C. Frick (Buffington) #2 2/2/1945
172 Atlas Veltri #1 N/A
175 Columbia Gas Transmission Corp Jennie M. Bloom, et al 8/8/1922
176 Columbia Gas Transmission Corp Elizabeth Oravets 7/22/1923
198 Red Lion Gas Cooperative Assn. Willson #1 N/A
247 Bernandine Captain Captain #1 N/A
2011 N/A N/A N/A
20001 G.A. Burgly, Jr. Mark & Leona Williams #1 10/31/1956
20004 G.A. Burgly, Jr. Bertha Lester #1 12/15/1961
20059 M.C.Brumage DiCarlo #2 12/29/1967
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
2 N/A N/A N/A N/A
7 N/A N/A 2530 N/A
10 N/A N/A N/A N/A
11 N/A N/A 2290 N/A
15 N/A N/A 2641 N/A
16 N/A N/A 2337 N/A
22 N/A N/A N/A N/A
24 N/A N/A 2620 N/A
27 N/A N/A 2454 N/A
29 N/A 101,000/1959 3700 N/A
33 N/A N/A 1384 N/A
36 N/A N/A 2615 N/A
41 N/A N/A 1968 N/A
50 N/A N/A 2180 N/A
56 N/A N/A 2608 N/A
61 N/A N/A 2464 N/A
63 N/A N/A 2793 N/A
66 N/A N/A 2475 N/A
76 N/A N/A 2530 N/A
80 N/A N/A 2499 N/A
84 N/A N/A 2128 N/A
105 N/A N/A 3269 N/A
118 N/A 263,000/1992 3162 N/A
119 N/A 267,000/1992 3101 N/A
122 N/A 337,000/1995 3041 N/A
172 N/A 337,000/1990 N/A N/A
175 N/A N/A 2575 N/A
176 N/A N/A 2462 N/A
198 N/A N/A N/A N/A
247 N/A N/A N/A N/A
2011 N/A N/A N/A N/A
20001 N/A N/A 1532 N/A
20004 N/A N/A 2800 N/A
20059 N/A N/A 3093 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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
20107 Orville Eberly Bilek #1 6/21/1903
20113 Greensboro Gas Co David Longanecker N/A
20123 Columbia Gas Transmission Corp Frank Moze N/A
20138 Peoples Natural Gas Co Gray #1 (now Keslar) 9/10/1973
20148 Peoples Natural Gas Co. Michael J. Gillock #1 8/23/1974
20153 Amoco Production Co. Francis R. Griffin #1 3/10/1975
20178 G.A. Burgly, Jr. Geo. J. Elliott #123 8/26/1936
20261 Manufacturers Light & Heat Co Hogsett #7 8/22/1946
20272 Peoples Natural Gas Co Kovach #3 12/17/1980
20278 Ashtola Production Co Honsaker #1 N/A
20347 Peoples Natural Gas Co John Magerko #1 7/13/1944
20351 Questa Petroleum Co Elliot #1 2/2/1983
20371 W. Burkland Ludi #1 8/27/1983
20391 Ashtola Production Co Wedge #1 5/11/1984
20428 Ashtola Production Co Dorothy Galica, et vir #1 2/1/1985
20470 Douglas Oil & Gas, Inc. Higinbotham #1 3/3/1987
20477 Douglas Oil & Gas, Inc. Diamond #1 8/26/1987
20482 Douglas Oil & Gas, Inc. Derosa #1 3/17/1988
20486 Douglas Oil & Gas, Inc. Spak Unit #1 1/13/1988
20500 Castle Exploration Co., Inc. H. Murphy Unit #1 12/9/1989
20505 Castle Gas Co A.H. Cover #1 4/3/1989
20602 Douglas Oil & Gas, Inc. USX/Demaske Unit #1 12/30/1991
20606 Castle Exploration Co., Inc. Frances R. Griffin Unit #2 2/11/1993
20723 Kriebel Gas Inc Kovach #1 3/23/1994
20742 Kriebel Gas Inc Fairbank Rod & Gun #1 11/5/1996
20793 Douglas Oil & Gas, Inc. USX/CBM #1 N/A
20810 W. Burkland Buncic #1 3/11/1996
20918 LAHD Energy, Inc. Angelo #1 9/2/1997
20962 Atlas Lavery #1 1/13/1998
20966 Douglas Oil & Gas, Inc. USX/Demaske #2 8/6/1998
20971 Atlas Swetz #1 1/28/1998
20978 Atlas Colucci #1 2/7/1998
20992 Atlas FDS #1 3/30/1998
21020 Atlas Ralph/USX #1 1/18/1999
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
20107 N/A N/A 1268 N/A
20113 N/A N/A 2570 N/A
20123 N/A N/A 2404 N/A
20138 N/A N/A 4513 N/A
20148 N/A N/A 3902 N/A
20153 N/A N/A 8700 N/A
20178 N/A N/A 1460 N/A
20261 N/A N/A 2521 N/A
20272 N/A N/A 3347 N/A
20278 N/A N/A N/A N/A
20347 N/A N/A 3709 N/A
20351 N/A N/A 3640 N/A
20371 N/A N/A 5789 N/A
20391 N/A N/A 3664 N/A
20428 N/A N/A 3574 N/A
20470 N/A N/A 3525 N/A
20477 N/A N/A 3526 N/A
20482 N/A N/A 3540 N/A
20486 N/A N/A 3437 N/A
20500 N/A N/A 3544 N/A
20505 N/A N/A 3458 N/A
20602 N/A N/A 3766 N/A
20606 N/A N/A 3643 N/A
20723 N/A N/A 4450 N/A
20742 N/A N/A 3895 N/A
20793 N/A N/A N/A N/A
20810 N/A N/A N/A N/A
20918 N/A N/A 290 N/A
20962 92 44704 4476 141
20966 N/A N/A 4000 N/A
20971 92 8041 6000 Shut-in
20978 86 67903 4066 64
20992 87 95288 6015 406
21020 78 25338 3957 193
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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
21037 Atlas Lindsey Unit #1 11/4/1998
21040 Atlas Howe #1 5/4/1999
21061 Atlas Jarina Unit #1 2/25/1999
21072 W.Burkland Yoho #1 N/A
21079 Atlas Craig #1 3/26/1999
21080 Atlas Bowers/Hogsett #2 2/24/1999
21116 Atlas Johnston, E.#1 3/25/2000
21132 Atlas Dick #1 12/17/2001
21133 Atlas Antram #1 2/18/2000
21135 Atlas Skovran #2 (sold to landowner) 3/2/2000
21147 Atlas Krepps #1 4/1/2000
21161 Atlas Hall/Hogsett #1 9/29/2000
21166 Atlas Hall/Hogsett #7 9/14/2000
21207 Atlas Hall/Hogsett #4 11/11/2000
21224 Atlas Crable/Hogsett #1 3/26/2001
21240 W.Burkland Shimko Redmond Unit #1 N/A
21248 Atlas Bukovitz Tr. 1 #1 3/3/2001
21251 Atlas Deaton #1 3/7/2001
21285 Atlas Lambert/USX #2A 6/7/2001
21287 Atlas Hall Hogsett #5 6/13/2001
21302 Atlas Keslar #5 7/23/2001
21304 Atlas Swetz #2 11/3/2001
21310 Atlas Crable/Hogsett #2 8/15/2001
21320 Atlas Hmelyar #1 8/24/2001
21324 W.Burkland Hartley #2 N/A
21328 Atlas Hall/Hogsett #10 9/2/2001
21369 Atlas Hall/Hogsett #9 12/11/2004
21370 Atlas Hall Hogsett #8 12/3/2004
21374 Atlas Keslar #6 12/28/2001
21398 Atlas Hall #11 1/31/2002
21470 Atlas Hall/Hogsett #6 5/29/2002
21472 Atlas FDS #5 6/5/2002
21531 Atlas New Salem VFD #2 9/6/2002
21605 Atlas DeBord #2 2/6/2003
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
21037 80 57879 259 251
21040 76 93732 3988 85
21061 77 7376 3650 0
21072 N/A N/A N/A N/A
21079 75 32491 4015 258
21080 76 45584 3810 409
21116 68 104535 4270 512
21132 55 30842 3998 287
21133 68 16597 4203 151
21135 28 795 4062 N/A
21147 70 31805 4210 293
21161 55 56342 3970 0
21166 57 42294 4059 403
21207 57 51710 4032 337
21224 53 34840 3995 271
21240 N/A N/A N/A N/A
21248 53 14547 3900 167
21251 53 33178 4220 398
21285 53 52757 4122 480
21287 53 89444 3916 622
21302 53 38464 4005 109
21304 52 32044 4280 362
21310 53 68204 3977 463
21320 50 9861 4210 227
21324 N/A N/A N/A N/A
21328 53 71861 4160 760
21369 53 63227 3860 579
21370 44 32370 4010 354
21374 44 34741 4052 650
21398 N/A P&A 4230 N/A
21470 40 58037 4450 656
21472 40 93457 3960 875
21531 N/A P&A 4110 N/A
21605 32 5001 4070 82
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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
21625 Atlas Cochrane #1 1/19/2003
21626 Atlas Girolami #2 1/9/2003
21647 Atlas Harper #3 6/25/2003
21653 Atlas Bukovitz Tr.1 #2A 4/15/2003
21655 Atlas Harper #4 4/21/2003
21670 Atlas FDS #4 4/22/2003
21672 Atlas Porter #2 3/6/2003
21698 Atlas Hartley #2 6/11/2003
21702 Atlas Stewart #8 4/1/2003
21757 W. Burkland E. Siegel #1 6/11/2004
21772 Atlas Croftcheck #9 9/4/2003
21804 Atlas Hartley #3 3/3/2004
21841 W. Burkland Broadwater #1 N/A
21849 Atlas Colucci #2 4/26/2004
21862 Atlas Teslovich #1 10/25/2003
21863 Atlas Croftcheck #5 12/10/2003
21865 Atlas Stewart #7 10/31/2003
21873 Atlas Croftcheck #7 2/24/2004
21874 Atlas Harper #5 10/20/2003
21878 Atlas Porter #11 2/10/2004
21889 Atlas Teslovich #2 3/28/2004
21894 Atlas Krepps #2 1/21/2004
21902 Atlas Skovran #20 1/18/2004
21938 Atlas King Unit #8 6/4/2004
21947 W. Burkland Jonathan Orbash et ux #2 N/A
21988 Atlas Congelio #2 1/31/2004
21992 Atlas DiCarlo #8 3/2/2004
22004 Atlas Allison/Hogsett #05 2/25/2004
22022 Atlas Patterson #4 4/28/2004
22026 Atlas Allison/Hogsett #6 3/1/2004
22029 Atlas Herring #1 3/17/2004
22031 Atlas Gaydos #3 3/31/2004
22038 Atlas Higinbotham #3 10/26/2004
22046 Atlas Lambert/USX #3 2/26/2004
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
21625 32 35279 4179 481
21626 32 9998 4010 240
21647 27 10411 4500 252
21653 30 7942 4000 156
21655 30 13664 4400 309
21670 30 25618 3960 537
21672 30 6075 4275 80
21698 27 57490 2510 1469
21702 30 15330 4050 501
21757 N/A N/A 4012 N/A
21772 25 83712 4370 2927
21804 18 1709 4267 124
21841 N/A N/A N/A N/A
21849 18 16368 4050 484
21862 21 74877 4500 2446
21863 20 116970 4500 3823
21865 22 34342 3950 209
21873 18 6006 4550 326
21874 22 132907 4303 5352
21878 18 5090 4550 277
21889 18 59866 4458 4807
21894 18 22274 4100 783
21902 18 1413 3950 74
21938 18 68734 3850 5404
21947 N/A N/A N/A N/A
21988 18 6556 4520 262
21992 18 9050 3950 665
22004 18 66580 4420 3140
22022 18 1437 4770 359
22026 18 47688 4400 2801
22029 18 10889 3300 1221
22031 N/A P&A 4200 N/A
22038 10 30893 2250 5676
22046 18 5302 4160 204
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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
22050 Atlas Bowser #1 5/14/2005
22055 Atlas King #9 5/5/2004
22058 Atlas Congelio #1A 3/15/2004
22068 Atlas Kino #1 1/28/2005
22074 Atlas Kovach #7 4/7/2004
22075 Atlas Herring #3 3/24/2004
22076 Atlas Novak-Melenyzer #2 5/13/2004
22091 Atlas Tercho-Shimko #2 8/16/2004
22102 Atlas Congelio #4 6/9/2004
22112 Atlas Congelio #3 5/27/2004
22127 Atlas Teslovich #15 6/4/2004
22128 Atlas Chan #1 5/12/2004
22129 Atlas Teslovich #14 5/27/2004
22130 Atlas Kezmarsky #1 5/21/2004
22133 Atlas Ricco #2 9/8/2004
22134 Atlas Ricco #1 8/29/2004
22141 Atlas Croftcheck #6 6/16/2004
22149 Atlas Herring #2 6/8/2004
22169 Atlas Higinbotham #4 7/29/2004
22172 Atlas American Legion/USX #1 8/20/2004
22173 Atlas Carpenter #6 6/25/2004
22176 Atlas Genovese #4 8/1/2004
22182 Atlas Shashura #1 6/25/2004
22183 Atlas Allison/Hogsett #04 8/1/2004
22184 Atlas Bird #1 7/3/2004
22188 Atlas Amrick #1 6/16/2004
22189 Atlas Amrick #2 7/28/2004
22192 Atlas Ferenci #1 8/11/2004
22194 Atlas Farquhar #5A 7/14/2004
22195 Atlas Farquhar #6 11/17/2004
22202 Atlas Glumac #1 9/29/2004
22204 Atlas Whetsel #5 10/20/2004
22205 Atlas Glumac #2 9/21/2004
22210 Atlas Leckrone/USX #2 10/9/2004
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
22050 18 11473 4670 1119
22055 18 27413 4510 1825
22058 18 5819 4550 317
22068 3 3396 4685 1796
22074 18 15684 4170 1007
22075 18 121744 3988 5729
22076 18 473 4745 145
22091 14 11766 1950 0
22102 15 50009 4460 2884
22112 15 25669 4100 1965
22127 15 27017 4420 1569
22128 18 4164 4690 289
22129 15 37716 4470 2482
22130 15 362 4700 36
22133 14 16247 4635 1345
22134 14 8187 4575 674
22141 15 18725 4700 1258
22149 15 25425 4080 2618
22169 15 51503 4620 12123
22172 14 12724 4230 1430
22173 15 2251 4300 1512
22176 N/A N/A 4230 N/A
22182 N/A N/A 4800 N/A
22183 15 8087 4420 646
22184 N/A N/A 4580 N/A
22188 15 5719 4075 806
22189 15 6723 4055 867
22192 N/A N/A 4650 N/A
22194 15 9841 3710 2038
22195 N/A N/A 4420 N/A
22202 14 13295 3950 2790
22204 10 554 4500 94
22205 14 23450 4220 5700
22210 10 2860 4130 710
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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
22211 Atlas Leckrone/USX #3 10/5/2004
22213 Atlas Murray #3 9/9/2004
22214 Atlas Murray #4 6/7/2005
22227 Atlas Landman #1 8/24/2004
22229 Atlas Kovach #4 8/9/2004
22236 Atlas Pearson #3 12/3/2004
22237 Atlas Pearson #4 12/8/2004
22239 Atlas Williams #25 9/15/2004
22241 Atlas Carson #2 9/24/2004
22247 Atlas SJ Fish & Game Club/USX #20 1/4/2005
22250 Atlas Angeline #1 9/9/2004
22254 Atlas Gibson #6 10/8/2004
22256 Atlas Chubboy #7 11/16/2004
22283 Atlas Werner/SJ/USX #15 1/21/2005
22292 Atlas Dorazio #1 9/8/2004
22305 Atlas Whetsel #4 12/21/2004
22306 Atlas Whetsel #3 10/13/2004
22307 Atlas Whetsel #2 10/25/2004
22316 Atlas SJ Fish & Game Club/USX #16 1/10/2005
22317 Atlas SJ Fish & Game Club/USX #18 1/15/2005
22324 Atlas Gaydos #4 10/6/2004
22330 Atlas Duran #1 5/6/2005
22335 Atlas Carpenter #7A 12/30/2004
22336 Atlas Carpenter #8 11/30/2004
22337 Atlas Carpenter #5 11/19/2004
22338 Atlas Carpenter #4 12/5/2004
22340 Atlas Werner/SJ/USX #12 1/30/2005
22345 Atlas Campbell Farms #1 11/24/2005
22346 Atlas Campbell Farms #5 12/5/2004
22363 Atlas Coyote Creek Farm #1 12/13/2004
22364 Atlas Coyote Creek Farm #2 2/22/2005
22365 Atlas Kontaxes #1 11/21/2004
22386 Atlas Galla #1 12/20/2004
22391 Atlas Yocum-Newcomer #6 11/18/2004
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
22211 N/A N/A 4040 N/A
22213 14 1446 4600 1032
22214 N/A N/A 4024 N/A
22227 N/A N/A 4820 N/A
22229 14 51017 4500 5271
22236 N/A N/A 4210 N/A
22237 N/A N/A 4280 N/A
22239 14 2095 4445 416
22241 N/A N/A 4480 N/A
22247 N/A P&A 4210 N/A
22250 14 3430 4430 625
22254 10 2063 4770 575
22256 10 2095 4460 568
22283 N/A N/A 4360 N/A
22292 14 465 4509 465
22305 10 637 4530 109
22306 12 2520 4232 455
22307 10 1245 4490 247
22316 N/A N/A 4380 N/A
22317 N/A N/A 4400 N/A
22324 10 2400 4290 152
22330 N/A N/A 3800 N/A
22335 10 121 4450 51
22336 N/A N/A 4390 N/A
22337 10 2003 4450 1428
22338 N/A N/A 4530 N/A
22340 N/A N/A 4470 N/A
22345 10 392 4530 392
22346 10 348 4390 348
22363 N/A N/A 4650 N/A
22364 N/A N/A 3800 N/A
22365 N/A N/A 4520 N/A
22386 10 13038 4430 1872
22391 10 92 4320 92
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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
22398 Atlas Bezjak #3 8/13/2005
22400 Atlas Bezjak #5 8/8/2005
22403 Atlas Williams #26 11/6/2004
22404 Atlas Allison/Hogsett #10 12/23/2004
22405 Atlas Bird #2 1/14/2005
22414 Atlas Wright #1 2/4/2005
22421 Atlas BSC/Ray #2 2/23/2005
22423 Atlas BSC/Ray #1 2/15/2005
22431 Atlas Kovscek/Kovach Unit #1 2/2/2005
22432 Atlas Pearson #2 3/14/2005
22434 Atlas Campbell Farms #2 1/7/2005
22435 Atlas Campbell Farms #4 1/13/2005
22442 Atlas Angeline #4 2/7/2005
22454 Atlas Dorazio #5 1/20/2005
22456 Atlas Novak-Melenzyer #3A 1/11/2005
22457 Atlas Behanna #1A 4/5/2005
22459 Atlas Yocum-Newcomer #5 12/27/2004
22491 Atlas Coyote Creek Farm #3 1/11/2005
22493 Atlas Dorazio #3 1/14/2005
22504 Atlas Brown #10 3/28/2005
22513 Atlas Duda #3 1/19/2005
22514 Atlas Duda #2 2/7/2005
22515 Atlas Diamond #3 2/1/2005
22516 Atlas Diamond #4 2/7/2005
22523 Equitrans, Inc. Thomas & Melissa Luxner #2 10/2/1993
22524 Atlas Diamond/Genovese Unit #1 2/16/2005
22528 Atlas Wright #2 1/28/2005
22529 Atlas Wright #3 2/12/2005
22537 Atlas Bobbish #1 6/16/2005
22538 Atlas Redman #6 4/25/2005
22539 Atlas Redman #7 4/14/2005
22540 Atlas Redman #8 6/30/2005
22542 Atlas Werner/SJ/USX #10 8/15/2005
22544 Atlas Werner/SJ/USX #21 2/18/2005
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
22398 N/A N/A 3600 N/A
22400 N/A N/A 3650 N/A
22403 10 6399 4035 2043
22404 N/A N/A 4375 N/A
22405 4 471 4555 210
22414 N/A N/A 3230 N/A
22421 7 182 3860 182
22423 7 203 3720 203
22431 8 4916 2850 776
22432 N/A N/A 3850 N/A
22434 7 302 4560 302
22435 7 484 4490 484
22442 N/A N/A 4000 N/A
22454 N/A N/A 4440 N/A
22456 7 499 4710 0
22457 N/A N/A 4115 N/A
22459 10 186 4405 186
22491 N/A N/A 4540 N/A
22493 3 361 4440 361
22504 N/A N/A 4020 N/A
22513 7 1563 4290 1207
22514 7 389 3660 254
22515 N/A N/A 3450 N/A
22516 N/A N/A 3450 N/A
22523 N/A N/A 2924 N/A
22524 7 3795 3550 1482
22528 N/A N/A 4010 N/A
22529 N/A N/A 3470 N/A
22537 N/A N/A 4050 N/A
22538 N/A N/A 4050 N/A
22539 N/A N/A 3950 N/A
22540 N/A N/A 4100 N/A
22542 N/A N/A 4080 N/A
22544 N/A P&A 3750 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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
22563 Atlas Ewart #1 2/14/2005
22572 Atlas Berdar #1 6/15/2005
22579 Atlas Mar Inc./SJ/USX #23 3/23/2005
22589 Atlas Lynch #3 5/10/2005
22605 Atlas SAGP #1 3/29/2005
22607 Atlas SAGP #3 5/17/2005
22608 Atlas SAGP #4 4/5/2005
22611 Atlas Campbell Farms #3 5/2/2005
22614 Atlas Bokulich #1 4/12/2005
22630 Atlas Behanna #2 5/26/2005
22631 Atlas Behanna #3 5/19/2005
22638 Atlas Williams-Kadar Unit #1 5/20/2005
22639 Atlas Williams #30 5/16/2005
22643 Atlas Kadar #1 5/15/2005
22649 Atlas Padlo #1 7/14/2005
22650 Atlas Masney #1 3/17/2005
22651 Atlas Strickler #1 7/29/2005
22652 Atlas Strickler #2 8/3/2005
22653 Atlas Strickler #3 8/31/2005
22661 Rejiss Associates Diamond #1 N/A
22662 Rejiss Associates Diamond #2 N/A
22663 Rejiss Associates Diamond #3 N/A
22664 Rejiss Associates Diamond #4 N/A
22671 Atlas Brazzon #3 8/11/2005
22703 Atlas Veltri #3 7/12/2005
22706 Atlas Bezjak #10 6/28/2005
22709 Atlas Holt #2 9/8/2005
22710 Atlas Holt #4 8/30/2005
22715 Atlas Bezjak #7 7/13/2005
22719 Atlas Gilmore #3 9/13/2005
22723 Atlas Betchy #1 7/19/2005
22724 Atlas Betchy #3 7/28/2005
22728 Atlas Sveda #1 9/9/2005
22736 Atlas Jacobs Lutheran Church #3 8/18/2005
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
22563 7 48469 3250 10979
22572 3 78 4310 78
22579 N/A N/A 3710 N/A
22589 N/A N/A 4150 N/A
22605 N/A N/A 4020 N/A
22607 N/A N/A 4010 N/A
22608 N/A N/A 4000 N/A
22611 N/A N/A 3960 N/A
22614 4 14525 3950 9436
22630 N/A N/A 3930 N/A
22631 N/A N/A 3800 N/A
22638 N/A N/A 3960 N/A
22639 N/A N/A 4040 N/A
22643 N/A N/A 2670 N/A
22649 N/A P&A 3410 N/A
22650 N/A N/A 3800 N/A
22651 N/A N/A 3865 N/A
22652 N/A N/A 3850 N/A
22653 N/A N/A 3805 N/A
22661 N/A N/A N/A N/A
22662 N/A N/A N/A N/A
22663 N/A N/A N/A N/A
22664 N/A N/A N/A N/A
22671 N/A N/A 3820 N/A
22703 N/A N/A 1550 N/A
22706 N/A N/A 3590 N/A
22709 N/A N/A 3500 N/A
22710 N/A N/A 3600 N/A
22715 N/A P&A 3700 N/A
22719 N/A N/A 3650 N/A
22723 N/A N/A 3670 N/A
22724 N/A N/A 3600 N/A
22728 N/A N/A 3730 N/A
22736 N/A N/A 3490 N/A
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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
22737 Atlas Jacobs Lutheran Church #4 8/29/2005
22751 Atlas Coombs/Burkland #1 8/22/2005
22766 Atlas Joren/Burkland #1 8/12/2005
22779 Atlas Triplett #1 9/11/2005
22780 Atlas Triplett #8 8/31/2005
22783 Atlas Grlovich #1 8/4/2005
22796 Atlas Triplett #5 8/27/2005
22798 Atlas Triplett #7 8/23/2005
22803 Atlas Yocum-Newcomer #4 7/21/2005
22816 Atlas Novobilsky #2 9/1/2005
22841 Atlas Bezjak #6 8/26/2005
22855 Rejiss Associates Johns #2 N/A
90023 Greensboro Gas Co. American Coke & Fuel #5-964 12/9/1943
90025 Duquesne Natural Gas Co. Kosack #1 8/21/1941
90027 Greensboro Gas Co. G.O. Morris #1-958 4/23/1943
90043 Duquesne Natural Gas Co. Chas. E. Black #2 10/23/1937
90046 Greensboro Gas Co. G.W. Hillen #3-911 8/1/1939
90048 Duquesne Natural Gas Co. C.H. Huhn #1 12/16/1937
90054 Greensboro Gas Co. J.W. Fast #889 1931
90059 Greensboro Gas Co Hogsett #4 10/23/1923
90067 Greensboro Gas Co. J. Hogsett #3 1923
90082 Greensboro Gas Co. Mary Lawrence #428 1918
90108 Greensboro Gas Co. L.A. Brown #1 1923
90111 Greensboro Gas Co J.N. Johnson N/A
90112 Greensboro Gas Co. Humphreys 3/27/1905
90114 Greensboro Gas Co. Joseph Hibbs #1-580 1/5/1923
90115 Greensboro Gas Co. J.D. McCann N/A
90117 Greensboro Gas Co. Harry Campbell #668 7/23/1924
90118 Greensboro Gas Co. David Gans #3 1921
90119 Greensboro Gas Co. A.A. Stevenson #884 12/1/1930
90120 Greensboro Gas Co. John Vesey 11/24/1938
90123 Greensboro Gas Co. S.C. Fast #34 1/1/1901
90124 Greensboro Gas Co. M.W. Frank Heirs #47 6/1/1901
90125 Greensboro Gas Co. A.C. Fretts #801 1927
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
22737 N/A N/A 3500 N/A
22751 N/A N/A 3890 N/A
22766 N/A N/A 4010 N/A
22779 N/A N/A 3600 N/A
22780 N/A N/A 3600 N/A
22783 N/A N/A 4055 N/A
22796 N/A N/A 3600 N/A
22798 N/A N/A 3600 N/A
22803 N/A N/A 3856 N/A
22816 N/A N/A 3820 N/A
22841 N/A N/A 2620 N/A
22855 N/A N/A N/A N/A
90023 N/A N/A 2773 N/A
90025 N/A N/A 2703 N/A
90027 N/A N/A 2509 N/A
90043 N/A N/A 2480 N/A
90046 N/A N/A 2595 N/A
90048 N/A N/A 2460 N/A
90054 N/A N/A 2840 N/A
90059 N/A N/A 3045 N/A
90067 N/A N/A 3196 N/A
90082 N/A N/A 3127 N/A
90108 N/A N/A 3273 N/A
90111 N/A N/A 2553 N/A
90112 N/A N/A 1363 N/A
90114 N/A N/A 2602 N/A
90115 N/A N/A 1396 N/A
90117 N/A N/A 2402 N/A
90118 N/A N/A 3654 N/A
90119 N/A N/A 2665 N/A
90120 N/A N/A 1473 N/A
90123 N/A N/A 1755 N/A
90124 N/A N/A 1424 N/A
90125 N/A N/A 1840 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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
90126 Greensboro Gas Co. C.W. Fox #1 1923
90134 Greensboro Gas Co. E.D. Fulton #1 N/A
90142 Greensboro Gas Co Isaiah Riffle N/A
90143 Greensboro Gas Co Isaiah Riffle N/A
90144 Greensboro Gas Co Isaiah Riffle N/A
90145 Greensboro Gas Co Isaiah Riffle N/A
90148 Greensboro Gas Co. Rebecca Stouffer #2 1929
90149 Greensboro Gas Co. E.S. Stephens #724 1925
90153 Greensboro Gas Co. J. M. Hare 1925
90154 Greensboro Gas Co. Robert Gilbert #900 1931
90156 Greensboro Gas Co. H. E. Elliott #1 8/23/1911
90157 Greensboro Gas Co. Charles S. Brown #640 7/20/1923
90158 Greensboro Gas Co. Andrew Brown #820 1928
90161 Greensboro Gas Co. James Clark #107 N/A
90166 Greensboro Gas Co. Mary Miller #366 1916
90168 Greensboro Gas Co. Harvey Steele #1 7/11/1910
90186 N/A N/A N/A
90188 N/A N/A N/A
G113 Greensboro Gas Co. Richard Drew #1-113 11/26/1906
G139 N/A N/A N/A
G19 Greensboro Gas Co. W. Fast #19 6/21/1900
G268 Greensboro Gas Co. William Townsend #1 5/5/1927
G273 Greensboro Gas Co. W. Townsend #2-273 8/27/1913
G810 Greensboro Gas Co. Hattie & W.J. Dalbert #810 10/2/1927
GRE-00367 Carnegie Natural Gas Co. B. Williamson #1 8/4/1928
GRE-01322 Carnegie Natural Gas Co. W. McClure #12 1895
GRE-1200 Equitable Gas Co Hart 1941
GRE-1204 Equitable Gas Hathaway #1 6/3/1941
GRE-1365 Carnegie Natural Gas Co. W.G. Lynch #971 1947
GRE-195 N/A N/A N/A
GRE-20099 Pennsynd Petroleum, Inc. C.E. Stillwagon #1 11/30/1966
GRE-20101 H.C. Wilson R. Howard #1 1/30/1967
GRE-21129 Equitable Gas Crago #1 12/23/1931
GRE-21227 Keystone Gas Co. Samuel & Doris Lewis #1 N/A
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
90126 N/A N/A 3497 N/A
90134 N/A N/A 1287 N/A
90142 N/A N/A 1323 N/A
90143 N/A N/A 1282 N/A
90144 N/A N/A 1874 N/A
90145 N/A N/A 2754 N/A
90148 N/A N/A 2934 N/A
90149 N/A N/A 2935 N/A
90153 N/A N/A 2945 N/A
90154 N/A N/A 3081 N/A
90156 N/A N/A 2876 N/A
90157 N/A N/A 2754 N/A
90158 N/A N/A 3034 N/A
90161 N/A N/A 2844 N/A
90166 N/A N/A 2947 N/A
90168 N/A N/A 3124 N/A
90186 N/A N/A N/A N/A
90188 N/A N/A N/A N/A
G113 N/A N/A 2449 N/A
G139 N/A N/A N/A N/A
G19 N/A N/A 2070 N/A
G268 N/A N/A 2630 N/A
G273 N/A N/A 2039 N/A
G810 N/A N/A 2705 N/A
GRE-00367 N/A N/A 2913 N/A
GRE-01322 N/A N/A 1863 N/A
GRE-1200 N/A N/A 2790 N/A
GRE-1204 N/A N/A 1986 N/A
GRE-1365 N/A N/A 2378 N/A
GRE-195 N/A N/A N/A N/A
GRE-20099 N/A N/A 1080 N/A
GRE-20101 N/A N/A 1668 N/A
GRE-21129 N/A N/A 2976 N/A
GRE-21227 N/A N/A N/A 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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
GRE-21418 Dominion Peoples Amos O. Brewer #5237 N/A
GRE-21527 Peoples Natural Gas Co. H. Cree #1 3/28/1980
GRE-23088 Atlas Biddle #1 9/10/2001
GRE-23104 Atlas Harbarger #1 3/12/2002
GRE-23105 Atlas Harbarger #2 10/21/2001
GRE-23144 Atlas Jarek #1 3/18/2002
GRE-23148 Atlas Buday #1 4/5/2002
GRE-23154 Atlas Consol/USX #2 4/3/2002
GRE-23155 Atlas Consol/USX #1 3/26/2002
GRE-23357 Atlas Biddle #5 2/15/2004
GRE-23360 BY Energy Duane V. Yost #1 N/A
GRE-90021 Equittable Gas Co Oscar Hartley #1 9/10/1943
GRE-90022 Equitable Gas Co Hathaway #1 7/21/1941
GRE-90075 Equitable Gas Co Kerr #2929 8/24/1926
GRE-90076 Equitable Gas Co Hathaway #438 3/26/1926
GRE-EQM337 Philadelphia #M337 M.Fox 8/7/1917
GRE-P1149 N/A N/A N/A
GRE-P1155 N/A N/A N/A
GRE-P1156 N/A N/A N/A
GRE-P1157 N/A N/A N/A
GRE-P1158A N/A N/A N/A
GRE-P1160 N/A N/A N/A
GRE-P1163 N/A N/A N/A
GRE-P1164 N/A N/A N/A
GRE-P14824 N/A N/A N/A
GRE-P15627 N/A N/A N/A
GRE-P26860 N/A N/A N/A
GRE-P27240 N/A N/A N/A
GRE-P27572 N/A N/A N/A
GRE-P28038 N/A N/A N/A
GRE-P30479 N/A N/A N/A
GRE-P30505 N/A N/A N/A
GRE-P30505 N/A N/A N/A
GRE-P31179 N/A N/A N/A
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
GRE-21418 N/A N/A N/A N/A
GRE-21527 N/A N/A 3039 N/A
GRE-23088 50 18541 4030 142
GRE-23104 43 12120 4460 174
GRE-23105 43 12534 4375 159
GRE-23144 43 24355 4420 578
GRE-23148 43 52104 4564 980
GRE-23154 43 16190 4272 282
GRE-23155 43 25064 4300 765
GRE-23357 18 4751 3807 237
GRE-23360 N/A N/A N/A N/A
GRE-90021 N/A N/A 3550 N/A
GRE-90022 N/A N/A 3067 N/A
GRE-90075 N/A N/A 3053 N/A
GRE-90076 N/A N/A 3136 N/A
GRE-EQM337 N/A N/A 2925 N/A
GRE-P1149 N/A N/A N/A N/A
GRE-P1155 N/A N/A N/A N/A
GRE-P1156 N/A N/A N/A N/A
GRE-P1157 N/A N/A N/A N/A
GRE-P1158A N/A N/A N/A N/A
GRE-P1160 N/A N/A N/A N/A
GRE-P1163 N/A N/A N/A N/A
GRE-P1164 N/A N/A N/A N/A
GRE-P14824 N/A N/A N/A N/A
GRE-P15627 N/A N/A N/A N/A
GRE-P26860 N/A N/A N/A N/A
GRE-P27240 N/A N/A N/A N/A
GRE-P27572 N/A N/A N/A N/A
GRE-P28038 N/A N/A N/A N/A
GRE-P30479 N/A N/A N/A N/A
GRE-P30505 N/A N/A N/A N/A
GRE-P30505 N/A N/A N/A N/A
GRE-P31179 N/A N/A N/A 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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
GRE-P31179 N/A N/A N/A
GRE-P31202 N/A N/A N/A
GRE-P33500 N/A N/A N/A
GRE-P6997 N/A N/A N/A
GRE-P7339 N/A N/A N/A
GRE-P8510 N/A N/A N/A
GRE-P8513 N/A N/A N/A
GRE-PNG3994 N/A N/A N/A
GRE-PNG3996 N/A N/A N/A
L2372 N/A N/A N/A
P01969 N/A N/A N/A
P01970 N/A N/A N/A
P01973 N/A N/A N/A
P01974 N/A N/A N/A
P1201 Greensboro Gas Co. John Longnecker 9/10/1921
P1202 N/A N/A N/A
P1204 Greensboro Gas Co. Geo. A. Schroyer #1-463 7/17/1919
P1206 Greensboro Gas Co. A.M. Stephenson #1-459 1/2/1919
P1797 N/A N/A N/A
P21214 Bickerton & Vaugh G. McGill #1 3/31/1939
P22026 N/A N/A N/A
P22140 N/A N/A N/A
P22410 N/A N/A N/A
P22694 N/A N/A N/A
P22814 N/A N/A N/A
P22917 N/A N/A N/A
P22918 N/A N/A N/A
P23112 N/A N/A N/A
P23112 N/A N/A N/A
P23318 D. Mayne, et al Atlas Coal Co. #1 7/3/1941
P23453 N/A N/A N/A
P23644 N/A N/A N/A
P23645 Nollem Oil & Gas Co. Mahlon Coombs #4 10/10/1941
P23857 N/A N/A N/A
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
GRE-P31179 N/A N/A N/A N/A
GRE-P31202 N/A N/A N/A N/A
GRE-P33500 N/A N/A N/A N/A
GRE-P6997 N/A N/A N/A N/A
GRE-P7339 N/A N/A N/A N/A
GRE-P8510 N/A N/A N/A N/A
GRE-P8513 N/A N/A N/A N/A
GRE-PNG3994 N/A N/A N/A N/A
GRE-PNG3996 N/A N/A N/A N/A
L2372 N/A N/A N/A N/A
P01969 N/A N/A N/A N/A
P01970 N/A N/A N/A N/A
P01973 N/A N/A N/A N/A
P01974 N/A N/A N/A N/A
P1201 N/A N/A 2992 N/A
P1202 N/A N/A N/A N/A
P1204 N/A N/A 3315 N/A
P1206 N/A N/A 3088 N/A
P1797 N/A N/A N/A N/A
P21214 N/A N/A 1540 N/A
P22026 N/A N/A N/A N/A
P22140 N/A N/A N/A N/A
P22410 N/A N/A N/A N/A
P22694 N/A N/A N/A N/A
P22814 N/A N/A N/A N/A
P22917 N/A N/A N/A N/A
P22918 N/A N/A N/A N/A
P23112 N/A N/A N/A N/A
P23112 N/A N/A N/A N/A
P23318 N/A N/A 1414 N/A
P23453 N/A N/A N/A N/A
P23644 N/A N/A N/A N/A
P23645 N/A N/A 3200 N/A
P23857 N/A N/A N/A 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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
P23857 N/A N/A before 1935
P23911 N/A N/A N/A
P24125 Smock Gas Co. J. Hess #1 1905
P24173 M.C.Brumage Hartley #1 N/A
P24177 N/A N/A N/A
P24257 N/A N/A N/A
P24459 N/A N/A N/A
P24502 N/A N/A N/A
P24515 Monongahela Natural Gas Co. N/A 1/27/1909
P25173 Monongahela Natural Gas Co. G. Acklin 12/17/1910
P25520 N/A N/A N/A
P25531 Duquesne Natural Gas Co. Elizabeth Provence 5/11/1931
P26092 H.K.Porter Hartley #1 1/6/1944
P26094 H.K.Porter Thompson-Connellsville #1 12/17/1943
P26321 Greensboro Gas Co. J. Edgar Baily #636 9/8/1923
P26448 N/A N/A N/A
P26456 H.K.Porter Hartley #1 4/12/1944
P26595 H.K.Porter Hartley #2 11/3/1944
P27181 N/A N/A N/A
P27469 N/A N/A N/A
P27765 N/A N/A N/A
P29321 N/A N/A N/A
P30044 N/A N/A N/A
PNG3359 Peoples Natural Gas Co. D.H. Sangston #1 10/26/1942
PNG3473 Peoples Natural Gas Co. Byers #1 1/1/1944
PNG3491 Peoples Natural Gas Co. Kovach #1 4/23/1945
PNG3619 Peoples Natural Gas Co. Girolami #1 9/25/1945
PNG3860 Peoples Natural Gas Co. N/A 7/27/1949
WAS-00065 N/A N/A N/A
WAS-00695 Equitable Gas Co. Wm. H. Hill #1482 1902
WAS-01344 Atlas Ferguson #1 6/21/1918
WAS-01347 Atlas Greenfield #1 9/20/1920
WAS-01352 Atlas Van Vorhis #1 8/31/1905
WAS-01357 Atlas Hill #1 8/17/1907
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
P23857 N/A N/A N/A N/A
P23857 N/A N/A N/A N/A
P23911 N/A N/A N/A N/A
P24125 N/A N/A 1905 N/A
P24173 N/A N/A N/A N/A
P24177 N/A N/A N/A N/A
P24257 N/A N/A N/A N/A
P24459 N/A N/A N/A N/A
P24502 N/A N/A N/A N/A
P24515 N/A N/A 2509 N/A
P25173 N/A N/A 3096 N/A
P25520 N/A N/A N/A N/A
P25531 N/A N/A 2710 N/A
P26092 N/A N/A N/A N/A
P26094 N/A N/A 2930 N/A
P26321 N/A N/A 2952 N/A
P26448 N/A N/A N/A N/A
P26456 N/A N/A 2055 N/A
P26595 N/A N/A 2684 N/A
P27181 N/A N/A N/A N/A
P27469 N/A N/A N/A N/A
P27765 N/A N/A N/A N/A
P29321 N/A N/A N/A N/A
P30044 N/A N/A N/A N/A
PNG3359 N/A 53,000/1952 3814 N/A
PNG3473 N/A N/A N/A N/A
PNG3491 N/A N/A 3750 N/A
PNG3619 N/A N/A 3258 N/A
PNG3860 N/A N/A 3108 N/A
WAS-00065 N/A N/A N/A N/A
WAS-00695 N/A N/A 3087 N/A
WAS-01344 N/A N/A 3037 N/A
WAS-01347 N/A N/A 2988 N/A
WAS-01352 N/A N/A 3190 N/A
WAS-01357 N/A N/A 3055 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.
DATE
ID NUMBER OPERATOR WELL NAME COMPLT'D
WAS-01360 Atlas Gillis #1 8/3/1904
WAS-01361 Atlas Behm #1 10/26/1905
WAS-21034 Brockway Glass Co., Inc. Carl W. Martin #1 1/14/1977
WAS-21036 Brockway Glass Co., Inc. Joseph Yurkovich #1 1/2/1977
WAS-21069 Brockway Glass Co., Inc. John W. Swagler #1 8/2/1977
WAS-21239 Union Drilling, Inc. Clarence K. Hess #1 6/19/1979
WAS-21240 Union Drilling, Inc. William Gasher #1 6/12/1979
WAS-21318 Manufacturers Light & Heat Co A.W. Nickson #1 11/22/1905
WES-20668 Peoples Natural Gas Co. Donald G. Leeper #2 10/7/1973
WES-20684 Peoples Natural Gas Co. Charles A. Schue #1 4/18/1974
WES-20694 Peoples Natural Gas Co. Charles A. Schue #2 4/28/1974
WES-20716 Peoples Natural Gas Co. Franklin A. Bialon #1 9/6/1974
WES-21528 Peoples Natural Gas Co. Charles A. Schue #3 9/24/1979
WES-21667 Peoples Natural Gas Co. Charles H. Schue #1 9/10/1980
WES-21967 Peoples Natural Gas Co. John W. Leeper #1 1/16/1982
WES-23409 Dorso Energy W.J. Gillock Estate #2 6/27/1991
TOTAL MCF TOTAL LATEST 30
THROUGH LOGGERS DAY PROD.-
ID NUMBER MOS ON LINE 08/31/05 DEPTH 08/31/05
WAS-01360 N/A N/A 2993 N/A
WAS-01361 N/A N/A 3083 N/A
WAS-21034 N/A N/A 4450 N/A
WAS-21036 N/A N/A 4313 N/A
WAS-21069 N/A N/A 4261 N/A
WAS-21239 N/A N/A 4265 N/A
WAS-21240 N/A N/A 4235 N/A
WAS-21318 N/A N/A 2924 N/A
WES-20668 N/A N/A 3816 N/A
WES-20684 N/A N/A 3908 N/A
WES-20694 N/A N/A 3909 N/A
WES-20716 N/A N/A 3953 N/A
WES-21528 N/A N/A 3178 N/A
WES-21667 N/A N/A 3229 N/A
WES-21967 N/A N/A 3228 N/A
WES-23409 N/A N/A 3095 N/A
31
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
FAYETTE, GREENE AND WESTMORELAND COUNTIES, PENNSYLVANIA
32
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #15-2005(A) L. P.
FAYETTE PROSPECT AREA
PENNSYLVANIA
Dated: September 22, 2005
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 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
- --------------------------------------------------------------------------------
33
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 #15-2005(A) L.P., contains acreage in Luzerne, Redstone,
Springhill, Nicholson, German, Washington, Jefferson and Perry Townships of
Fayette County; Dunkard and Cumberland Townships of Greene County; Rostraver
Township of Westmoreland County; and Beallsville, Washington County, located in
southwestern Pennsylvania. Forty (40) 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 nine hundred (900)
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 nearly 75,000 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
Balitown 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.
34
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
Balitown, and First Bradford Sand. Stratigraphic relationships are illustrated
in the diagram.
[GRAPHIC OMITTED]
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.
35
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.
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.
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.
[GRAPHIC OMITTED]
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.
36
STATEMENTS
-----------
CONCLUSION
- ----------
UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #15-2005(A) L.P., which will consist of developmental
drilling of Lower Mississippian and Upper Devonian reservoirs in Fayette,
Greene, Washington and Westmoreland Counties, Pennsylvania. It is the
professional opinion of UEDC that the drilling of the forty (40) wells by ATLAS
AMERICA PUBLIC #15-2005(A) L.P. 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.
Respectively submitted,
[GRAPHIC OMITTED]
UEDC, INC.
37
LEASE INFORMATION
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
38
OVERRIDING
ROYALTY
INTEREST TO THE
EFFECTIVE EXPIRATION LANDOWNER MANAGING
PROSPECT NAME COUNTY DATE* DATE* ROYALTY GENERAL PARTNER
1 Griggs #1 Crawford 04/08/03 04/08/06 12.5% 0%
2 Carr #6 Crawford 10/11/02 10/11/08 12.5% 0%
3 Livingston #1 Crawford 10/03/02 10/03/08 12.5% 0%
4 Kightlinger #1 Crawford 06/18/03 06/18/06 12.5% 0%
5 Lepley #1 Crawford 05/16/03 05/16/06 12.5% 0%
6 Martin #14 Crawford 07/01/03 07/01/06 12.5% 0%
7 Hunter #10 Crawford 05/15/04 05/15/09 12.5% 0%
8 Carpenter #10 Crawford 06/01/04 06/01/09 12.5% 0%
9 Carpenter #11 Crawford 06/01/04 06/01/09 12.5% 0%
10 Tatalovic Unit #2 Crawford 05/01/04 05/01/14 12.5% 0%
11 Brooks-Tatalovic Unit #1 Crawford 07/01/04 07/01/09 12.5% 0%
12 Tatalovic Farms #3 Crawford 11/14/04 11/14/09 12.5% 0%
OVERRIDING ACRES TO BE
ROYALTY ASSIGNED TO
INTEREST TO NET REVENUE WORKING THE
PROSPECT NAME 3RD PARTIES INTEREST INTEREST NET ACRES PARTNERSHIP
1 Griggs #1 0% 87.5% 100% 50 50
2 Carr #6 0% 87.5% 100% 71 50
3 Livingston #1 0% 87.5% 100% 280.5 50
4 Kightlinger #1 0% 87.5% 100% 60 50
5 Lepley #1 0% 87.5% 100% 45 45
6 Martin #14 0% 87.5% 100% 23 23
7 Hunter #10 3.125% 84.375% 100% 328 50
8 Carpenter #10 3.125% 84.375% 100% 330 50
9 Carpenter #11 3.125% 84.375% 100% 330 50
10 Tatalovic Unit #2 3.125% 84.375% 100% 337 50
11 Brooks-Tatalovic Unit #1 3.125% 84.375% 100% 92 50
12 Tatalovic Farms #3 3.125% 84.375% 100% 520 50
*HBP - Held by Production.
39
LOCATION AND PRODUCTION MAPS
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
40
[GRAPHIC OMITTED]
41
[GRAPHIC OMITTED]
42
[GRAPHIC OMITTED]
43
[GRAPHIC OMITTED]
44
PRODUCTION DATA
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
45
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.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D
20960 Hartstown Oil & Gas Simons #1 02/18/81
21331 William M. Mohl William Mohl #1 08/30/81
22036 Envirogas, Inc. Ned Brown #1 10/25/83
24225 Atlas Resources, Inc. Holabaugh #1 09/26/03
24229 Atlas Resources, Inc. Moyers #1 09/11/04
24510 Atlas Resources, Inc. Ernst Farms #2 06/19/05
24514 Atlas Resources, Inc. Ernst Farms #1 06/30/05
24529 Atlas Resources, Inc. Ernst Farms #3 06/25/05
TOTAL MCF THROUGH
MOS ON 08/31/05 EXCEPT WHERE TOTAL LATEST 30
ID NUMBER LINE NOTED LOGGERS DEPTH DAY PROD.
20960 N/A Abandoned 4688 N/A
21331 N/A N/A 4991 N/A
22036 N/A N/A 4599 N/A
24225 24 1156 4569 N/A
24229 N/A N/A 4584 N/A
24510 N/A N/A 4596 N/A
24514 N/A N/A 4621 N/A
24529 N/A N/A 4567 N/A
46
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
WESTERN PENNSYLVANIA AND EASTERN OHIO
47
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #15-2005(A) L. P.
CRAWFORD PROSPECT AREA
PENNSYLVANIA
Dated: September 22, 2005
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 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 ...................................3
PRODUCTION ..........................................................4
CONCLUSION ..........................................................5
DISCLAIMER ..........................................................5
NON-INTEREST ........................................................5
- --------------------------------------------------------------------------------
48
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 #15-2005(A) L.P., contains acreage in South Shenango, Vernon,
Randolph and Richmond Townships of Crawford County, located in northwestern
Pennsylvania. Twelve (12) 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.
[GRAPHIC OMITTED]
49
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 <0.1 to >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.
[GRAPHIC OMITTED]
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.
50
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.
[GRAPHIC OMITTED]
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:
[GRAPHIC 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.
51
STATEMENTS
----------
CONCLUSION
- ----------
UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #15-2005(A) L.P., which will consist of developmental
drilling of the Clinton-Medina Group sands in Crawford County, Pennsylvania. It
is the professional opinion of UEDC that the drilling of the twelve (12) wells
by ATLAS AMERICA PUBLIC #15-2005(A) L.P. 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.
Respectively submitted,
[GRAPHIC OMITTED]
UEDC, INC.
52
UEDC'S
GEOLOGIC EVALUATION
FOR THE
PRIMARY DRILLING AREA
IN
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
53
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #15-2005(A) L. P.
ARMSTRONG PROSPECT AREA
PENNSYLVANIA
Dated: September 22, 2005
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 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
- --------------------------------------------------------------------------------
54
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 contains acreage in Kiskiminetas Township
of Armstrong County and Young and Conemaugh Townships of Indiana County,
located in western Pennsylvania. Drilling prospects within this area in ATLAS
AMERICA PUBLIC #15-2005(A) L.P. 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. Individual drilling locations have not been 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.
55
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.
[GRAPHIC OMITTED]
The HUNDRED FOOT SAND is the shallowest sand of Devonian age encountered in
this area. This said 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.
56
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 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.
[GRAPHIC OMITTED]
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.
57
STATEMENTS
----------
CONCLUSION
- ----------
UEDC has conducted a geologic feasibility study of the prospect area for ATLAS
AMERICA PUBLIC #15-2005(A) L.P., which will consist of developmental drilling of
Upper Devonian reservoirs in Armstrong and Indiana Counties, Pennsylvania.
Specific well locations in this program have not been evaluated for the purposes
of this report. It is the professional opinion of UEDC that the drilling of
wells within this area by ATLAS AMERICA PUBLIC #15-2005(A) L.P. 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.
Respectively submitted,
[GRAPHIC OMITTED]
UEDC, INC.
58
LEASE INFORMATION
FOR
MCKEAN COUNTY, PENNSYLVANIA
59
OVERRIDING
ROYALTY INTEREST
EFFECTIVE EXPIRATION LANDOWNER TO THE MANAGING
PROSPECT NAME COUNTY DATE* DATE* ROYALTY GENERAL PARTNER
1 Young-Kane #7 McKean 10/31/2003 10/31/2014 12.5% 0%
2 Young-Kane #9 McKean 10/31/2003 10/31/2014 12.5% 0%
3 Young-Kane #16 McKean 10/31/2003 10/31/2014 12.5% 0%
4 Young-Kane #17 McKean 10/31/2003 10/31/2014 12.5% 0%
5 Young-Kane #18 McKean 10/31/2003 10/31/2014 12.5% 0%
6 Young-Kinzua #1 McKean 3/11/2003 3/11/2006 12.5% 0%
7 Young-Kinzua #2 McKean 3/11/2003 3/11/2006 12.5% 0%
8 Young-Kinzua #3 McKean 3/11/2003 3/11/2006 12.5% 0%
9 Young-Kinzua #4 McKean 3/11/2003 3/11/2006 12.5% 0%
10 Young-Kinzua #5 McKean 3/11/2003 3/11/2006 12.5% 0%
OVERRIDING
ROYALTY NET ACRES TO BE
INTEREST TO 3RD REVENUE WORKING ASSIGNED TO THE
PROSPECT NAME PARTIES INTEREST INTEREST NET ACRES PARTNERSHIP
1 Young-Kane #7 0% 87.5% 100% 2,432.00 5
2 Young-Kane #9 0% 87.5% 100% 2,432.00 5
3 Young-Kane #16 0% 87.5% 100% 2,432.00 5
4 Young-Kane #17 0% 87.5% 100% 2,432.00 5
5 Young-Kane #18 0% 87.5% 100% 2,432.00 5
6 Young-Kinzua #1 0% 87.5% 100% 370.00 5
7 Young-Kinzua #2 0% 87.5% 100% 370.00 5
8 Young-Kinzua #3 0% 87.5% 100% 370.00 5
9 Young-Kinzua #4 0% 87.5% 100% 370.00 5
10 Young-Kinzua #5 0% 87.5% 100% 370.00 5
* HBP - Held by Production.
60
LOCATION AND PRODUCTION MAPS
FOR
MCKEAN COUNTY, PENNSYLVANIA
61
[GRAPHIC OMITTED]
62
[GRAPHIC OMITTED]
63
[GRAPHIC OMITTED]
64
PRODUCTION DATA
FOR
MCKEAN COUNTY, PENNSYLVANIA
65
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.
ID WELL NAME
NUMBER OPERATOR YOUNG KINZUA AREA MAP REF
12581 Minard Run Oil Co E K Kane #2
12582 Minard Run Oil Co E K Kane #3
12583 Minard Run Oil Co E K Kane #4
12584 Minard Run Oil Co E K Kane #5
12585 Minard Run Oil Co E K Kane #6
12586 Minard Run Oil Co Enterprise #7
12587 Minard Run Oil Co Enterprise #8
12588 Minard Run Oil Co Enterprise #9
12589 Minard Run Oil Co Enterprise #10
12590 Minard Run Oil Co Enterprise #11
12591 Minard Run Oil Co Enterprise #12
12592 Minard Run Oil Co Enterprise #13
12593 Minard Run Oil Co Enterprise #15
12594 Minard Run Oil Co Lot 219 #1
12595 Minard Run Oil Co Lot 219 #2
38425 Oilvest DE Inc E A Johnson #1
45288 Minard Run Oil Co E A Johnson #100
45287 Minard Run Oil Co E A Johnson #102
46384 Minard Run Oil Co E A Johnson #1
50153 Minard Run Oil Co Kushequa 212 #1
50155 Minard Run Oil Co Kushequa 212 #3
50157 Minard Run Oil Co Kushequa 212 #5
YOUNG KANE AREA
DMD-KANE METER
46978 Dallas Morris Drilling WT 3122 #1 A
47360 Dallas Morris Drilling WT 3122 #30 A
47359 Dallas Morris Drilling WT 3122 #43 A
7051 East Resources Inc WT 3131 #58 B
7057 East Resources Inc WT 3131 #71 B
7060 East Resources Inc WT 3131 #76 B
46055 MSL Oil & Gas Corp Lot 263 #12 B
46056 MSL Oil & Gas Corp Lot 263 #13 B
46068 MSL Oil & Gas Corp Brian Lease Lot 263 #7 B
46069 MSL Oil & Gas Corp Brian Lease Lot 263 #8 B
46070 MSL Oil & Gas Corp Brian Lease Lot 263 #9 B
46072 MSL Oil & Gas Corp Brian Lease Lot 263 #11 B
46935 PA Gen Energy Co Lot 222 #1024 B
YOUNG KANE #1 - #5 C
50048 Atlas America, Inc. Young Kane #1 C
50049 Atlas America, Inc. Young Kane #2 C
50050 Atlas America, Inc. Young Kane #3 C
50051 Atlas America, Inc. Young Kane #4 C
50052 Atlas America, Inc. Young Kane #5 C
66
TOTAL LATEST
ID DATE PRODUCTION TOTAL MCF LOGGERS 30 DAY
NUMBER COMPLETED PERIOD GAS EQUIV. DEPTH PRODUCTION
12581 1/1/1904 NA NA 2246 NA
12582 1/1/1904 NA NA 2312 NA
12583 7/29/1904 NA NA 2293 NA
12584 1/1/1903 NA NA 2275 NA
12585 10/14/1904 NA NA 2178 NA
12586 4/27/1904 NA NA 2129 NA
12587 1/1/1904 NA NA 1977 NA
12588 4/25/1904 NA NA 2001 NA
12589 9/16/1904 NA NA 1977 NA
12590 6/25/1904 NA NA 2123 NA
12591 12/11/1903 NA NA 1974 NA
12592 3/15/1904 NA NA 2202 NA
12593 8/17/1904 NA NA 1919 NA
12594 1/1/1923 NA NA 2637 NA
12595 1/1/1901 NA NA 2405 NA
38425 5/17/1980 NA NA 2984 NA
45288 9/20/1986 NA NA 2185 NA
45287 8/31/1986 NA NA 2170 NA
46384 2/13/1993 NA NA 2170 NA
50153 NA NA NA (1) 2450 NA
50155 NA NA NA (1) 2430 NA
50157 NA NA NA (1) 2435 NA
3/1999-3/2005 33,633 1020.6
46978 (2) 2635
47360 7/21/1999 (2) 1830
47359 7/16/1999 (2) 2580
7051 1922 1990-91, 1998 338 (3) 2028 -
7057 1927 1990-91, 1998 338 (3) 1886 -
7060 10/24/1939 1998 64 (3) 2624 -
46055 2/16/1989 1990-1998 7,488 (3) 1325 -
46056 2/9/1989 1990-1998 7,488 (3) 1800 -
46068 8/22/1989 1990-1998 1,128 (3) 1748 -
46069 8/15/1989 1990-1998 1,128 (3) 1619 -
46070 8/11/1989 1990-1998 1,128 (3) 1536 -
46072 8/10/1989 1990-1998 1,128 (3) 1870 -
46935 7/8/1997 1997-1998 18,618 (3) 2097 -
(Young Kane wells #1-#5 to be turned into pipeline September 2005)
50048 5/23/2005 NA NA 2065 NA
50049 5/19/2005 NA NA 2030 NA
50050 5/16/2005 NA NA 2015 NA
50051 5/12/2005 NA NA 1985 NA
50052 5/9/2005 NA NA 1960 NA
(1) Minard Run drilled three wells in anticipation of a new development area,
and are currently waiting on a pipeline connection before continuing with
their ongoing drilling program.
(2) Based upon the successful production of the Haskill by Dallas Morris
Drilling, Atlas America has committed to drilling five wells in this
portion of the Young Kane lease for 2005-2006.
(3) Combined meters, jointly produced, or common facility production is
allocated to individual wells reported to the Pennsylvania Department of
Environmental Protection, which in turn makes this reported production
available to the public. Thus, despite what the Pennsylvania Department of
Environmental Protection reports, the volume of production could vary
significantly from well to well. Thus, you are not able to analyze the
consistency of the production among the various wells. Also, annual
production totals do not always represent 365 days of continuous
production, offsets to the Young Kane lease have in some years, less than
30 days of reported production.
67
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
MCKEAN COUNTY, PENNSYLVANIA
68
GEOLOGIC EVALUATION
ATLAS AMERICA
PUBLIC #15-2005(A) L. P.
MCKEAN PROSPECT AREA
PENNSYLVANIA
Dated: September 22, 2005
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 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
- --------------------------------------------------------------------------------
69
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 #15-2005(A) L.P., contains acreage in Lafayette and Hamlin
Townships of McKean County, Pennsylvania. Ten (10) 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 over one hundred fifty (150) 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]
70
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.
71
STATEMENTS
----------
CONCLUSION
- ----------
UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #15-2005(A) L.P., 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 ten (10) wells by ATLAS
AMERICA PUBLIC #15-2005(A) L.P. 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.
Respectively submitted,
[GRAPHIC OMITTED]
UEDC, INC.
72
MAP OF TENNESSEE
73
[GRAPHIC OMITTED: MAP OF TENNESSEE]
74
UEDC'S
GEOLOGIC EVALUATION
FOR THE
PRIMARY DRILLING AREA
IN
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
75
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #15-2005(A) L. P.
TENNESSEE KNOX ENERGY PROSPECT AREA
PENNSYLVANIA
Dated: September 22, 2005
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 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
TENNESSEE KNOX ENERGY PROSPECT AREA ..........................................2
DRILLING ACTIVITY ...................................................2
GEOLOGY .............................................................3
STRATIGRAPHY, LITHOLOGY & DEPOSITION ........................3
RESERVOIR CHARACTERISTICS ...................................4
PRODUCTION ..........................................................4
STATEMENTS ...................................................................5
CONCLUSION ..........................................................5
DISCLAIMER ..........................................................5
NON-INTEREST ........................................................5
- --------------------------------------------------------------------------------
76
INVESTIGATION SUMMARY
---------------------
OBJECTIVE
- ---------
The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Tennessee Knox Energy Prospect Area
as proposed by Atlas Resources, Inc. ("Atlas").
AREA OF INVESTIGATION
- ---------------------
A portion of this prospect area contains acreage in Scott, Anderson and
Morgan Counties of Tennessee. Drilling prospects within this area in ATLAS
AMERICA PUBLIC #15-2005(A) L.P. will be targeted to produce natural gas from
Mississippian and Devonian reservoirs, found at depths from 1500 feet to 5000
feet beneath the earth's surface. Individual drilling locations have not been
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.
TENNESSEE KNOX ENERGY PROSPECT AREA
-----------------------------------
DRILLING ACTIVITY
- -----------------
The proposed drilling area lies in the Appalachian Plateau portion of
northern Tennessee. This historically oil producing area has seen recent
activity targeting zones that have yielded commercial gas production. Knox
Energy (KXE) has been actively drilling for natural gas for over three years and
has established production in a few locales within this vast area. Drilling is
ongoing as of the date of this report with recent wells displaying favorable
initial drilling and completion results.
77
GEOLOGY
- -------
STRATIGRAPHY, LITHOLOGY & DEPOSITION
The depositional environments for the Mississippian carbonates range from
shelf to lagoon and near shore settings. The Devonian or Chattanooga Shale
formed in an organic rich sea offshore from the Catskill Delta.
The Mississippian reservoirs consist of the Monteagle limestone, St. Louis
dolomite, Warsaw limey siltstone and the Ft. Payne cherry limestone. The
Chattanooga Shale underlies the Ft. Payne. Diagram illustrates stratigraphic
relationships.
The primary target in all wells in this area is the MONTEAGLE LIMESTONE.
This limestone contains thick deposits of Oolites, which provide porosity as
high as 20%. Some wells have encountered as much as 30 feet of this reservoir.
The DEVONIAN SHALE is another primary target in the area. This reservoir
underlies the Mississippian carbonates and is found in all wells throughout the
area. This formation is not only a reservoir when fractured, but is considered
the source of the hydrocarbons found in the overlying carbonates.
Secondary targets may also show development. The FT. PAYNE is the primary
reservoir for the oil in adjacent fields found north and west of the prospect
area. The ST. LOUIS and WARSAW reservoirs have been encountered less often, but
could be considerable contributors in yet to be developed parts of the vast
prospect area.
[GRAPHIC OMITTED]
78
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping commercial quantities of natural gas or oil in a more permeable medium.
In the Mississippian carbonate reservoirs this occurs in two ways. One way is
when ooids (carbonate sands) are formed and deposited (oolites) and are encased
in less permeable limestones. Another way is when limestone changes to dolomite
during a change ("diagenesis") at the atomic level of the rock.
Electric well logs (right) can be used in conjunction with production to
interpret reservoir parameters. When the carbonates in the Mississippian
reservoirs develop porosity in excess of 5%, the permeability of the reservoir
can become great enough to allow commercial production of natural gas. When
small, naturally occurring cracks or fractures exist in the Chattanooga Shale,
permeability of the reservoir is enhanced. Audio logs can detect the small
amounts of natural gas that flow from the shale.
[GRAPHIC OMITTED]
PRODUCTION
- ----------
The Tennessee Knox Energy 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.
79
STATEMENTS
----------
CONCLUSION
- ----------
UEDC has conducted a geologic feasibility study of the prospect area for
ATLAS AMERICA PUBLIC #15-2005(A) L.P., which will consist of developmental
drilling of Mississippian and Devonian reservoirs in Scott, Anderson and Morgan
Counties of Tennessee. Specific well locations in this program have not been
evaluated for the purposes of this report. It is the professional opinion of
UEDC that the drilling of wells within this area by ATLAS AMERICA PUBLIC
#15-2005(A) L.P. 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.
Respectively submitted,
[GRAPHIC OMITTED]
UEDC, INC.
80
EXHIBIT (A)
FORM OF
AMENDED AND RESTATED CERTIFICATE
AND AGREEMENT OF LIMITED PARTNERSHIP
FOR
ATLAS AMERICA PUBLIC #15-2005(A) L.P.
[FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED
PARTNERSHIP FOR ATLAS AMERICA PUBLIC #15-2006(___) L.P.]
TABLE OF CONTENTS
SECTION NO. DESCRIPTION PAGE SECTION NO. DESCRIPTION PAGE
I. FORMATION VII. DURATION, DISSOLUTION, AND WINDING UP
1.01 Formation..................................1 7.01 Duration..................................49
1.02 Certificate of Limited Partnership.........1 7.02 Dissolution and Winding Up................50
1.03 Name, Principal Office and Residence.......1
1.04 Purpose....................................1 VIII. MISCELLANEOUS PROVISIONS
8.01 Notices...................................50
II. DEFINITION OF TERMS 8.02 Time......................................51
2.01 Definitions................................2 8.03 Applicable Law............................51
8.04 Agreement in Counterparts.................51
III. SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS 8.05 Amendment.................................51
3.01 Designation of Managing General Partner 8.06 Additional Partners.......................52
and Participants......................11 8.07 Legal Effect..............................52
3.02 Participants..............................11
3.03 Subscriptions to the Partnership..........11 EXHIBITS
3.04 Capital Contributions of the Managing
General Partner.......................13 EXHIBIT (I-A) - Form of Managing General
3.05 Payment of Subscriptions..................14 Partner Signature Page
3.06 Partnership Funds.........................14 EXHIBIT (I-B) - Form of Subscription
Agreement
IV. CONDUCT OF OPERATIONS EXHIBIT (II) - Form of Drilling and
4.01 Acquisition of Leases.....................15 Operating Agreement for Atlas
4.02 Conduct of Operations.....................17 America Public #15-2005(A)
4.03 General Rights and Obligations of the L.P. [Atlas America Public
Participants and Restricted and #15-2006(___) L.P.]
Prohibited Transactions...............21
4.04 Designation, Compensation and
Removal of Managing General
Partner and Removal of Operator.......31
4.05 Indemnification and Exoneration...........35
4.06 Other Activities..........................37
V. PARTICIPATION IN COSTS AND REVENUES,
CAPITAL ACCOUNTS, ELECTIONS AND
DISTRIBUTIONS
5.01 Participation in Costs and Revenues.......37
5.02 Capital Accounts and Allocations
Thereto...............................41
5.03 Allocation of Income, Deductions and
Credits...............................42
5.04 Elections.................................44
5.05 Distributions.............................44
VI. TRANSFER OF UNITS
6.01 Transferability of Units..................45
6.02 Special Restrictions on Transfers of Units
by Participants.......................46
6.03 Presentment...............................48
i
FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #15-2005(A) L.P.
[FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #15-2006(___) 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 the date set forth below, 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 #15-2005(A)
L.P. [Atlas America Public #15-2006(___) 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, and any successor entity to Atlas
Resources, Inc., whether by merger or other form of corporate
reorganization, or the acquisition of all, or substantially all, of
Atlas Resources, Inc.'s assets.
8. "Atlas America Public #15-2005 Program" means the offering of Units in
a series of up to four limited partnerships entitled Atlas America
Public #15-2005(A) L.P., Atlas America Public #15-2006(B) L.P., Atlas
America Public #15-2006(C) L.P. and Atlas America Public #15-2006(D)
L.P.
2
9. "Capital Account" or "account" means the account established for each
party, maintained as provided in ss.5.02 and its subsections.
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 Anthem Securities, Inc., an Affiliate of the
Managing General Partner, the broker/dealer which will manage the
offering and sale of the Units.
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.
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
3
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 in ss.5.01 and its
subsections.
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:
(i) 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,";
4
(ii) the expense of plugging and abandoning any well before a
completion attempt; and
(iii) the costs (other than Tangible Costs and Lease costs) to
re-enter and deepen an existing well, complete the well to
deeper reservoirs, or plug and abandon the well if it is
nonproductive from the targeted deeper reservoirs.
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, that the Partnership's
subscription period is closed and the acceptance of subscriptions
ceases, which may be any date up to and including December 31, 2005
[December 31, 2006].
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
formations or reservoirs, or plug and abandon the well if it is
nonproductive from the targeted deeper formations or 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 #15-2005(A) L.P. [Atlas
America Public #15-2006(___) 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 and the Mississippian
Carbonate or the Devonian Shale reservoirs in Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee.
7
48. "Prospectus" means the Prospectus included in the Registration
Statement on Form S-1 relating to the offer and sale of the Units which
has been filed with the Securities and Exchange Commission (the
"Commission") under the Securities Act of 1933, as amended (the "Act").
As used in this Agreement, the terms "Prospectus" and "Registration
Statement" refer solely to the Prospectus and Registration Statement,
as amended, described above, except that:
(i) from and after the date on which any post-effective amendment
to the Registration Statement is declared effective by the
Commission, the term "Registration Statement" shall refer to
the Registration Statement as amended by that post-effective
amendment, and the term "Prospectus" shall refer to the
Prospectus then forming a part of the Registration Statement;
and
(ii) if the Prospectus filed pursuant to Rule 424(b) or (c)
promulgated by the Commission under the Act differs from the
Prospectus on file with the Commission at the time the
Registration Statement or any post-effective amendment
thereto shall have become effective, the term "Prospectus"
shall refer to the Prospectus filed pursuant thereto from and
after the date on which it was filed.
49. "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.
50. "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
8
(d) crude oil, natural gas, and natural gas liquids, that
may be recovered from oil shales, coal, gilsonite and
other such sources.
51. "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.
52. "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.
53. "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.
54. "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.
9
55. "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 due diligence
expenses.
56. "Selling Agents" means the broker/dealers which are selected by the
Dealer-Manager to participate in the offer and sale of the Units.
57. "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:
(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.
58. "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.
59. "Tangible Costs" or "Capital Expenditures" means those costs associated
with property acquisition and 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;
(ii) the costs (other than Intangible Drilling Costs and Lease
costs) to re-enter and deepen an existing well, complete the
well to deeper reservoirs, or plug and abandon the well if it
is nonproductive from the targeted deeper reservoirs; and
(iii) 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.
60. "Tax Matters Partner" means the Managing General Partner.
61. "Units" or "Units of Participation" means up to 600 Limited Partner
interests in the Partnership and up to 19,400 Investor General Partner
interests in the Partnership, which will be converted to up to 19,400
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.
62. "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.
10
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 to the extent, if any, they purchase Units, 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 sold do not exceed the maximum number
of Units set forth in ss.3.03(c)(1).
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 in an interest bearing account or accounts
by an independent escrow holder and shall not be released to the Partnership
until the receipt and acceptance 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. if the
Participant purchased one-half of a Unit, or $11,000, $12,000, etc if the
Participant purchased a full Unit.
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 the 2.5% Dealer-Manager fee,
the 7% Sales Commission, the .5% accountable Reimbursement
for Permissible Non-Cash Compensation, and the .5%
reimbursement of the Selling Agents' bona fide due diligence
expenses, which shall not be paid with respect to these
sales; and
(ii) Registered Investment Advisors and their clients, and Selling
Agents and their registered representatives and principals,
shall be reduced by an amount equal to the 7% Sales
Commission, which shall not be paid with respect to these
sales.
No more than 5% of the total Units in the Partnership shall be sold with the
discounts described above.
11
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). OPTIONAL SUBSCRIPTIONS FOR UNITS BY MANAGING GENERAL PARTNER.
3.03(b)(1). MANAGING GENERAL PARTNER'S OPTIONAL SUBSCRIPTIONS FOR UNITS. In
addition to the Managing General Partner's required Capital Contributions under
ss.3.04(a), the Managing General Partner may subscribe for up to 5% of the total
Units in the Partnership 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 to be a Participant in the Partnership for all
purposes under this Agreement.
3.03(b)(2). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing General Partner
has executed a Managing General Partner Signature Page which:
(i) evidences the Managing General Partner's required Capital
Contributions under ss.3.04(a); and
(ii) may be amended, from time-to-time, to reflect the amount of
any optional subscriptions for Units as a Participant under
ss.3.03(b)(1).
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
20,000 [____________] Units, which is up to $200,000,000 [$______________] 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
of the partnerships in the Atlas America Public #15-2005 Program, in the
aggregate, shall not exceed 20,000 Units which is up to $200,000,000 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 subscriptions for the minimum number of Units have not been received and
accepted at the Offering Termination Date, 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, without deduction for any fees.
The partnership may break escrow and begin its drilling activities in the
Managing General Partner's sole discretion on receipt and acceptance 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 of the subscriber's 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.
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3.04. CAPITAL CONTRIBUTIONS OF THE MANAGING GENERAL PARTNER.
3.04(a). MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTIONS. The Managing
General Partner, as a general partner and not as a Participant, is required to:
(i) pay the costs or make the other required Capital
Contributions charged to it under this Agreement, including
contributing to the Partnership the Leases which will be
drilled by the Partnership on the terms set forth in
ss.4.01(a)(4), in an amount equal to not less than 25%, in
the aggregate, of all Capital Contributions to the
Partnership, at the time the costs are required to be paid by
the Partnership, but no later than December 31, 2006
[December 31, 2007]; 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:
(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). MANAGING GENERAL PARTNER'S PARTNERSHIP INTEREST FOR CAPITAL
CONTRIBUTIONS. The interest of the Managing General Partner, as Managing General
Partner and not as a Participant, in the capital and profits of the Partnership
is fully vested and nonforfeitable as of the date of the formation of the
Partnership and is in consideration for, and is the only consideration for, its
required Capital Contributions to the Partnership.
3.04(d). MANAGING GENERAL PARTNER'S RIGHT TO ASSIGN ITS PARTNERSHIP INTEREST.
Subject to ss.5.01(b)(4)(a) regarding the Managing General Partner's
subordination obligation, and subject to a required 1% minimum interest in the
Partnership as Managing General Partner and not as a Participant, the Managing
General Partner has the right at any time, in its discretion, without the
consent of the Participants and without affecting the allocation of costs and
revenues to the Participants under this Agreement, to sell, contribute, exchange
or otherwise transfer its interest as Managing General Partner in the capital
and profits (or revenues) of the Partnership, or any interest therein, to its
Affiliates. In that event, except as otherwise may be permitted under this
Agreement, the Affiliated transferee of the Managing General Partner's interest
in the Partnership shall not become a Partner in the Partnership under the
Delaware Revised Uniform Limited Partnership Act and shall have no voting rights
in the Partnership. However, the Affiliated transferee, as a partner in the
Partnership for tax purposes only, shall have the right to receive the share of
the Partnership's profits, losses, income, gains, deductions, credits and
depletion allowances, or items thereof, and cash distributions and returns of
capital to which the Managing General Partner would otherwise be entitled under
this Agreement with respect to its transferred interest in the Partnership.
Subject to the foregoing, the transfer of the Managing General Partner's
interest in the Partnership to any of its Affiliates may be made on any terms
and conditions as the Managing General Partner determines, in its discretion,
and the Partnership and the Participants shall have no interest in any
consideration received by the Managing General Partner from its Affiliate for
the transfer of its interest in the Partnership. No transfer of its Partnership
interest by the Managing General Partner under this ss.3.04(d) shall require an
accounting by the Managing General Partner or the Partnership to the
Participants.
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).
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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), 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 called for by the
Managing General Partner. 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.
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 shall 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
14
(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 the Atlas America Public #15-2005
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; and
(ii) credited towards the Managing General Partner's required
Capital Contribution set forth in ss.3.04(a)(i) 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, OPERATOR 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
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(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.
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:
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(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, for purposes of satisfying this
requirement, 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;
(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;
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(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.
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 at Cost plus an unaccountable, fixed payment
reimbursement to the Managing General Partner of $15,000 per well for the
Participants' share of the Managing General Partner's general and administrative
overhead plus 15%. 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;
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(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 are 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 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
is 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.
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
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(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:
(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.
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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, or 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 of the Partnership's Administrative Costs was
consistent with the method described in ss.4.04(a)(2)(c) of
this Agreement and that the total amount of Administrative
Costs allocated did not materially exceed the amounts
actually incurred by the Managing General Partner in
providing administrative services to, or on behalf of, the
Partnership, including administrative services provided to
the Partnership by the Managing General Partner's Affiliates
or independent third-parties at the sole expense of the
Managing General Partner. If the Managing General Partner
subsequently decides to allocate Administrative Costs 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.
(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;
21
(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
natural gas and oil 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 natural gas on the existing
natural 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 any event reduces the Partnership's Proved Reserves by 10% or more,
excluding:
(i) a reduction of reserves as a result of normal production;
(ii) sales of reserves; or
(iii) natural gas or oil price changes;
then a computation and estimate of the amount of the reduction in reserves must
be sent to each Participant within 90 days after the Managing General Partner
determines that such a reduction in reserves has occurred.
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, provided
that access to the list of Participants shall be subject to ss.4.03(b)(7) below.
The Participant may inspect and copy any of the records after giving adequate
notice to the Managing General Partner at any reasonable time.
22
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.
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;
(iii) the Alabama Securities Commission; and
(iv) the securities commissions of other states which request the
report.
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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;
(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:
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(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.
With respect to a 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, and
with respect to a Prospect located in Anderson, Campbell, Morgan, Roane and
Scott Counties, Tennessee on which a well will be drilled to test the
Mississippian carbonate or Devonian Shale 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
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(ii) in the Mississippian and/or Upper Devonian Sandstone
reservoirs in Fayette, Greene and Westmoreland Counties,
Pennsylvania, within 1,000 feet from a producing Partnership
Well, although the 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, the
Mississippian carbonate or Devonian Shale 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, shall 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.
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.
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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 another drilling
Program sponsored or managed by the Managing General Partner or its Affiliates
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:
(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
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(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 shall be 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
(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.
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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.
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.
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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:
(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:
30
(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 natural 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 natural gas production is gathered and transported 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 and
transporting the natural gas. If the Partnership's natural gas production is
gathered and transported through a gathering system owned by the Managing
General Partner or its Affiliates other than Atlas Pipeline Partners, then the
Managing General Partner or its Affiliates shall receive, or retain in the case
of the Managing General Partner, the gathering fee paid to the Managing General
Partner. Also, in the Mississippian and Devonian Shale Reservoirs in Anderson,
Campbell, Morgan, Roane and Scott Counties, Tennessee, if the Coalfield Pipeline
does not have sufficient capacity to compress and transfer the natural gas
produced from the Partnership's wells as determined by Atlas America, then Atlas
America or an Affiliate other than Atlas Pipeline Partners may construct an
additional gathering system and/or enhancements to the Coalfield Pipeline. On
completion of the construction, Atlas America will transfer its ownership in the
additional gathering system and/or enhancements to the owners of the Coalfield
Pipeline, which will then pay Atlas America an amount equal to $.12 per mcf of
natural gas transported through the newly constructed and/or enhanced gathering
system. Coalfield Pipeline will charge this $.12 per mcf to the Partnership in
addition to the rate that it is charging at that time. As of the date of the
Prospectus, Coalfield Pipeline was charging $.55 per mcf for transportation plus
fees for compression.
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
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.
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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 to
calculate the presentment price in the most recent presentment offer under
ss.6.03, 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. At the time of its removal, the removed
Managing General Partner 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;
32
(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). RIGHT OF MANAGING GENERAL PARTNER TO HYPOTHECATE 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 as Managing General
Partner 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.
4.04(a)(3)(h). THE MANAGING GENERAL PARTNER'S RIGHT TO WITHDRAW PROPERTY
INTEREST. Subject to a required participation of not less than 1% in the
Partnership as Managing General Partner, the Managing General Partner has the
right to 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 as Managing General Partner 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.
If the Managing General Partner withdraws a property interest from the
Partnership as described above, 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.
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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:
(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.
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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.
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, or 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.
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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.
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.
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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. Ninety percent (90%) of the Partnership's
subscription proceeds received from the Participants shall be used to pay 100%
of the Intangible Drilling Costs.
5.01(a)(3). TANGIBLE COSTS. Ten percent (10%) of the Partnership's subscription
proceeds received from the Participants shall be used by the Partnership to pay
Tangible Costs. All remaining Tangible Costs in excess of an amount equal to 10%
of the Partnership's subscription proceeds shall be charged 100% 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.
Although the proceeds of each Partnership closing will be used to pay the costs
of drilling different wells, 90% of each Participant's subscription proceeds
shall be applied to Intangible Drilling Costs and 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.
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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 40% 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 35% of the total Partnership Capital Contributions and the
Participants contribute 65% of the total Partnership Capital Contributions, then
the Managing General Partner shall receive 40% of the Partnership revenues, not
42%, because its revenue share cannot exceed 40% of Partnership revenues, and
the Participants shall receive 60% 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. In this regard:
(i) the 60-month subordination period shall begin with the first
cash distribution from operations to the Participants;
(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.
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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 monthly
distribution, the Managing General Partner will not have any
subordination obligation if the distributions to Participants
equal $83.33 per Unit (8.333% 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
(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, allocating any item of income, gain, loss,
deduction or credit which is the result of new laws or new IRS or judicial
interpretations of existing law, or which is not otherwise specifically
allocated in this Agreement or is clearly inconsistent with a party's economic
interest in the Partnership, or making any other allocations under this
Agreement, the Managing General Partner may adopt any method of allocation which
it, in its reasonable discretion, selects in its sole discretion, after
consultation with the Partnership's legal counsel or accountants. Any new
allocation provisions shall be made in a manner that is consistent with the
parties' economic interests in the Partnership and which would result in the
most favorable aggregate consequences to the Participants as nearly as possible
consistent with the original allocations described in this Agreement.
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5.02. CAPITAL ACCOUNTS AND ALLOCATIONS THERETO.
5.02(a). CAPITAL ACCOUNTS FOR EACH PARTY TO THIS 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);
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. Also, in the event, and to the extent,
that the Managing General Partner is treated under the Code as having been
transferred an interest in the Partnership in connection with the performance of
services for the Partnership (whether before or after the formation of the
Partnership):
(i) any resulting compensation income shall be allocated 100% to
the Managing General Partner;
(ii) any associated increase in Capital Accounts shall be credited
100% to the Managing General Partner; and
40
(iii) any associated deduction to which the Partnership is entitled
shall be allocated 100% to the Managing General Partner.
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.
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.
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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. 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. If Partnership receipts, whether or not
taxable, that give rise to a tax credit, including a marginal well production
credit under ss.45I of the Code, in a Partnership taxable year also give rise to
valid allocations of Partnership income or gain, or other upward Capital Account
adjustments, for the year, then the parties' interests in the Partnership with
respect to the credit, or the Partnership's receipts or production of natural
gas and oil production giving rise thereto, shall be in the same proportion as
the parties' respective shares of the Partnership's production revenues from the
sales of its natural gas and oil production as provided in ss.5.01(b)(4).
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.
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.
5.03(k). CONTINGENT INCOME. Subject to ss.5.04(d), if it is determined that any
taxable income results to any party by reason of its entitlement to a share of
capital of the Partnership, or 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 that party.
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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 the Code, including
Subchapter K of Chapter 1 of Subtitle A of the Code.
5.04(c). 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.
5.04(d). SS.83 ELECTION. The Partnership, the Managing General Partner and each
Participant hereby agree to be legally bound by the provisions of this
ss.5.04(d) and further agree that, in the Managing General Partner's sole
discretion, the Partnership and all of its Partners may elect a safe harbor
under which the fair market value of a Partnership interest that is transferred
in connection with the performance of services is treated as being equal to the
liquidation value of that interest for transfers on or after the date final
regulations providing the safe harbor are published in the Federal Register. If
the Managing General Partner determines that the Partnership and all of its
Partners will elect the safe harbor, which determination may be made solely in
the best interests of the Managing General Partner, the Partnership, the
Managing General Partner and each Participant further agree that:
(i) the Partnership shall be authorized and directed to elect the
safe harbor;
(ii) the Partnership and each of its Partners (including any
Person to whom a Partnership interest is transferred in
connection with the performance of services) shall comply
with all requirements of the safe harbor with respect to all
Partnership interests transferred in connection with the
performance of services while the election remains effective;
and
(iii) the Managing General Partner, in its sole discretion, may
cause the Partnership to terminate the safe harbor election,
which determination may be made in the sole interests of the
Managing General Partner.
5.05. DISTRIBUTIONS.
5.05(a). IN GENERAL.
5.05(a)(1). MONTHLY REVIEW OF ACCOUNTS. The Managing General Partner shall
review the accounts of the Partnership at least monthly 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.
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:
(i) in conjunction with distributions to Participants; and
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(ii) 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 UNITS
6.01. TRANSFERABILITY OF UNITS. A Participant's transfer of a portion or all his
Units, or any interest in his Units, is subject to all provisions of this
Article VI. For purposes of this Article VI, the term "transfer" shall include
any sale, exchange, gift, assignment, pledge, mortgage, hypothecation,
redemption or other form of transfer of a Unit, or any interest in a Unit, by a
Participant (which may include the Managing General Partner or its Affiliates,
if they purchase Units) or by operation of law, including any transfers of Units
which a Participant presents to the Managing General Partner for purchase under
ss.6.03.
6.01(a). RIGHTS OF ASSIGNEE. Unless a transferee of a Participant's Unit becomes
a substitute Participant with respect to that Unit in accordance with the
provisions of ss.6.02(a)(3)(a), 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, gains, deductions,
credits and depletion allowances, or items thereof, and cash distributions or
returns of capital to which his transferor would otherwise be entitled under
this Agreement.
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).
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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.
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 OF UNITS BY PARTICIPANTS.
6.02(a). IN GENERAL. Transfers of Units by Participants are subject to the
following general conditions:
(i) except as provided by operation of law:
(a) only whole Units may be transferred unless the
Participant owns less than a whole Unit, in which case
his entire fractional interest must be transferred;
and
(b) Units may not be transferred 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 transfer must be
paid by the assignor Participant;
(iii) the transfer documents must be in a form satisfactory to the
Managing General Partner; and
(iv) the terms of the transfer must not contravene those of this
Agreement.
Transfers of Units by Participants 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.6.03 and
transfers by operation of law, no transfer of a Unit by a Participant 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.6.03 and transfers by operation of law, no Unit shall be transferred by a
Participant unless there is either:
(i) an effective registration of the Unit under the Securities
Act of 1933, as amended, and qualification under applicable
state securities laws; or
(ii) an opinion of counsel acceptable to the Managing General
Partner that the registration and qualification of the Unit
is not required.
Transfers of Units by Participants are also subject to any conditions contained
in the Subscription Agreement and Exhibit (B) to the Prospectus.
45
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), a transferee of a Participant's Unit shall
become a substitute Participant entitled to all the rights of a Participant if,
and only if:
(i) the transferor gives the transferee the right;
(ii) the transferee pays to the Partnership all costs and expenses
incurred in connection with the substitution; and
(iii) the transferee executes and delivers the instruments
necessary to establish that a legal transfer has taken place
and to confirm the agreement of the transferee to be bound by
all of the terms of this Agreement, in a form acceptable to
the Managing General Partner.
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.
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 substitute
Participants.
Any transfer of a Unit by a Participant which is permitted under this Article
VI, when the transferee does not become a substitute 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). A TRANSFER OF UNITS DOES NOT RELIEVE THE TRANSFEROR OF CERTAIN
COSTS. No transfer of a Unit by a Participant, including a transfer of less than
all of a Participant's Units or the transfer of a Participant's 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). A TRANSFER OF UNITS DOES NOT REQUIRE A PARTNERSHIP ACCOUNTING. No
transfer of a Unit by a Participant shall require an accounting by the Managing
General Partner. Also, no transfer of a Unit shall grant rights under this
Agreement, including the exercise of any elections, as between the transferring
Participant and the Partnership, the Managing General Partner and the remaining
Participants to more than one Person unanimously designated by the transferee(s)
of the Unit, and, if he has retained an interest in the transferred Unit, the
transferor of the Unit.
6.02(b)(4). REQUIRED NOTICE TO MANAGING GENERAL PARTNER OF TRANSFER OF UNITS.
Until the Managing General Partner receives from the transferring Participant a
written notice in a form acceptable to the Managing General Partner which
designates the transferee(s) of a Unit, the Managing General Partner shall
continue to account only to the Person to whom it was furnishing notices
pursuant to ss.8.01 and its subsections before the purported transfer of the
Unit. This party shall continue to exercise all rights applicable to the Units
previously owned by the transferor.
6.03. PRESENTMENT.
6.03(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 ss.6.03. A Participant, however, is not obligated
to present his Units for purchase.
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.
46
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 in ss.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.
6.03(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 as described in ss.4.03(b)(3)(ii).
The calculation of the presentment price shall be as set forth in ss.6.03(c).
6.03(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.6.03(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.
6.03(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;
47
(d) changes in income, ad valorem, and other tax laws such
as material variations in the provisions for
depletion; and
(e) similar matters.
6.03(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, in
a form satisfactory to the Managing General Partner, together with any other
documentation as the Managing General Partner may reasonably request.
6.03(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.
6.03(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.
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
partnership and the parties to the successor limited partnership.
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.
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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:
(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 of the transfer has been given to the Managing
General Partner.
Any transfer of Units 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:
49
(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:
(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
and amend the allocation provisions of this Agreement as
provided in ss.5.01(c)(3);
50
(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; or
(iv) cure any ambiguity, correct or supplement any provision that
may be inconsistent in this Agreement with any other
provision in this Agreement, or add any other provision to
this Agreement with respect to matters, events or issues
arising under this Agreement that is not inconsistent with
the provisions of this Agreement.
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 of
___________________, 2005.
ATLAS: ATLAS RESOURCES, INC.
Managing General Partner
By:
---------------------------
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 #15-2005(A) L.P.
The undersigned agrees:
1. to serve as the Managing General Partner of ATLAS AMERICA PUBLIC
#15-2005(A) 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.3.04(a)(i) of the Partnership Agreement; and
3. to subscribe to the Partnership as follows:
(a) $___________________ [________] Unit(s)] under Section
3.03(b)(1) of the Partnership Agreement as a Limited
Partner; or
(b) $___________________ [________] Unit(s)] under Section
3.03(b)(1) 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 _____ , 2005.
ATLAS RESOURCES, INC.
MANAGING GENERAL PARTNER
By: ________________________________
EXHIBIT (I-B)
FORM OF
SUBSCRIPTION AGREEMENT
ATLAS AMERICA PUBLIC #15-2005(A) L.P.
- --------------------------------------------------------------------------------
SUBSCRIPTION AGREEMENT
- --------------------------------------------------------------------------------
I, the undersigned, hereby offer to purchase Units of Atlas America Public
#15-2005(A) 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 #15-2005 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. I further understand that following the Signature Page there
are certain representations, warranties and covenants which I must make before
the Managing General Partner will accept my subscription.
- -----------------------------------------------------------------------------------------------------------------------------
SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
- -----------------------------------------------------------------------------------------------------------------------------
I, the undersigned, agree to purchase ________ Units at $10,000 per Unit in
ATLAS AMERICA PUBLIC #15-2005(A) L.P. (the "Partnership") as (check one):
SUBSCRIPTION AMOUNT
|_| INVESTOR GENERAL PARTNER $__________________________
|_| LIMITED PARTNER (____________________# Units)
INSTRUCTIONS
=============================================================================================================================
Make your check payable to: "Atlas America Public #15-2005(A) 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 sign this Signature Page.)
NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP: NAME ________________________________________________________________________
(ENCLOSE SUPPORTING DOCUMENTS.) IF A PARTNERSHIP, CORPORATION OR TRUST, THEN THE MEMBERS, STOCKHOLDERS OR BENEFICIARIES
THEREOF ARE CITIZENS OF _________________________.
Tax I. D. No.:________________________ Home Address (Do not use P.O. Box)
______________________________________ ______________________________________
Print Name
______________________________________
______________________________________
Signature ______________________________________
Address for Distributions if Different
Tax I. D. No.: _______________________ from Above OR Electronic Deposit
available, complete attached form
______________________________________ ______________________________________
Print Name
______________________________________
______________________________________
Signature ______________________________________
Account No.: _________________________
I received my final prospectus on ____
(CHECK ONE): OWNERSHIP OF THE UNITS- |_| Tenants-in-Common |_| Partnership
|_| Joint Tenancy with Right of Survivorship |_| C Corporation
|_| Individual |_| S Corporation
|_| Community Property with Survivorship Rights |_| Trust
|_| Limited Liability Company |_| Other
Date: _______________________
My Telephone No.: Home_______________________________ Business _______________________________
My E-mail Address:___________________________________
(CHECK ONE): |_| I am at least twenty-one years of age |_| I am not twenty-one years of age
(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 2005 or 2004 is from farming)
- -----------------------------------------------------------------------------------------------------------------------------
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 Facsimile Number: ________________
___________________________________________________
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 AMERICA PUBLIC #15-2005(A) 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)
WIRE TRANSFERS are available. Please contact Ms. Tammy Patterson at (412)
262-1680 for information.
- -----------------------------------------------------------------------------------------------------------------------------
TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
- -----------------------------------------------------------------------------------------------------------------------------
ACCEPTED THIS __________ day ATLAS RESOURCES, INC.,
of ______________________, 2005 MANAGING GENERAL PARTNER
By: __________________________________________________
2
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
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, the transferability of the Units
is restricted, and 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 my own account, for investment purposes and not for the
account of others, and with no present intention of reselling them.
_____ _____ If an individual, I am a citizen of the United States of America and at least twenty-one
years of age.
_____ _____ If a partnership, corporation or trust, then 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.
_____ _____ 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 Partnership's insurance proceeds, the
Partnership's assets, and indemnification by the Managing General Partner. Also, the
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.
_____ _____ 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: the risks involved in the
offering, including the speculative nature of the investment and the speculative nature of
drilling for natural gas and oil; the financial hazards involved in the offering, including
the risk of losing my entire investment; the lack of liquidity of my investment; the
restrictions on transferability of my Units; the background of the Managing General Partner
and the Operator; the tax consequences of my investment; and the unlimited joint and several
liability of the Investor General Partners.
3
To meet the suitability requirements for an investment in your state, please
check and initial either (a), (b), (c) or (d) depending on your state of
residence and whether you are buying limited partner units or investor general
partner units. Also, initial (e) if you are a fiduciary and you meet the
requirement.
INVESTOR'S CO-INVESTOR'S
INITIALS INITIALS
_____ _____ (a) IF I PURCHASE LIMITED PARTNER UNITS AND I AM A RESIDENT OF:
o ALABAMA, o KANSAS, o OKLAHOMA,
o ALASKA, o KENTUCKY, o OREGON,
o ARIZONA, o LOUISIANA, o PENNSYLVANIA,
o ARKANSAS, o MAINE, o RHODE ISLAND,
o COLORADO, o MARYLAND, o SOUTH CAROLINA,
o CONNECTICUT, o MASSACHUSETTS, o SOUTH DAKOTA,
o DELAWARE, o MINNESOTA, o TENNESSEE,
o DISTRICT OF COLUMBIA, o MISSISSIPPI, o TEXAS,
o FLORIDA, o MISSOURI, o UTAH,
o GEORGIA, o MONTANA, o VERMONT,
o HAWAII, o NEBRASKA, o VIRGINIA,
o IDAHO, o NEVADA, o WASHINGTON
o ILLINOIS, o NEW MEXICO o WEST VIRGINIA,
o INDIANA, o NEW YORK, o WISCONSIN, OR
o IOWA, o NORTH DAKOTA, o WYOMING,
then I must have either: a minimum net worth of $225,000, exclusive of home, home furnishings,
and automobiles, or a minimum net worth of $60,000, exclusive of home, home furnishings, and
automobiles, and 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 Internal Revenue Code of at least
$60,000, without regard to an investment in the partnership. In addition, if I am a resident
of 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
I should limit my investment in the partnership and substantially similar programs to no more
than 10% of my 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 NORTH CAROLINA, OR
o MICHIGAN, o NEW JERSEY, o OHIO,
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.
4
INVESTOR'S CO-INVESTOR'S
INITIALS INITIALS
- ---------- --------------
_____ _____ (c) IF I PURCHASE INVESTOR GENERAL PARTNER UNITS AND I AM A RESIDENT OF:
o ALASKA, o ILLINOIS, o RHODE ISLAND,
o COLORADO, o LOUISIANA, o SOUTH CAROLINA,
o CONNECTICUT, o MARYLAND, o UTAH,
o DELAWARE, o MONTANA, o VIRGINIA,
o DISTRICT OF COLUMBIA, o NEBRASKA, o WEST VIRGINIA,
o FLORIDA, o NEVADA, o WISCONSIN, OR
o GEORGIA, o NEW YORK, o WYOMING,
o HAWAII, o NORTH DAKOTA,
o IDAHO,
then I must have either: a net worth of at least $225,000, exclusive of home, furnishings and
automobiles, or a net worth, exclusive of home, furnishings and automobiles, of at least
$60,000, and 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), (b), (c) or (d) above.
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 the person has been given your legal
power of attorney to sign on your behalf, and 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 the beneficiary, the fiduciary account, or
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.
5
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 not complete a sale of Units to you and send
you a confirmation of purchase until at least five business days after the date
you receive a final Prospectus. Thus, you have five business days to rescind
your purchase after you receive the final prospectus and execute your
Subscription Agreement.
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 I am a resident of California,
I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B)
to the Prospectus.
SECTION D
TO BE COMPLETED BY ALL INVESTORS
TAXPAYER IDENTIFICATION NUMBER CERTIFICATION - CHECK THE FIRST BOX BELOW,
UNLESS YOU ARE A FOREIGN INVESTOR OR YOU ARE INVESTING AS A U.S. GRANTOR
TRUST.
NOTE: IF THERE IS A CHANGE IN CIRCUMSTANCES WHICH MAKES ANY OF THE
INFORMATION PROVIDED BY YOU IN YOUR CERTIFICATION BELOW INCORRECT, THEN
YOU ARE UNDER A CONTINUING OBLIGATION SO LONG AS YOU OWN UNITS IN THE
PARTNERSHIP TO NOTIFY THE PARTNERSHIP AND FURNISH THE PARTNERSHIP A NEW
CERTIFICATE WITHIN THIRTY (30) DAYS OF THE CHANGE.
[ ] UNDER PENALTIES OF PERJURY, I CERTIFY THAT:
(1) THE NUMBER PROVIDED IN MY SUBSCRIPTION AGREEMENT IS MY CORRECT
"TIN" (I.E., SOCIAL SECURITY NUMBER OR EMPLOYER IDENTIFICATION
NUMBER);
(2) I AM NOT SUBJECT TO BACKUP WITHHOLDING BECAUSE (A) I AM EXEMPT
FROM BACKUP WITHHOLDING UNDER SS.3406(G)(1) OF THE INTERNAL
REVENUE CODE AND THE RELATED REGULATIONS, OR (B) I HAVE NOT
BEEN NOTIFIED BY THE INTERNAL REVENUE SERVICE (IRS) THAT I AM
SUBJECT TO BACKUP WITHHOLDING AS A RESULT OF FAILURE TO REPORT
ALL INTEREST OR DIVIDENDS, OR (C) THE IRS HAS NOTIFIED ME THAT
I AM NO LONGER SUBJECT TO BACKUP WITHHOLDING; AND
(3) I AM A U.S. PERSON (WHICH INCLUDES U.S. CITIZENS, RESIDENT
ALIENS, ENTITIES OR ASSOCIATIONS FORMED IN THE U.S. OR UNDER
U.S. LAW, AND U.S. ESTATES AND TRUSTS.)
(NOTE: YOU MUST CROSS OUT ITEM 2 ABOVE IF YOU HAVE BEEN NOTIFIED BY THE
IRS THAT YOU ARE CURRENTLY SUBJECT TO BACKUP WITHHOLDING BECAUSE YOU HAVE
FAILED TO REPORT ALL INTEREST AND DIVIDENDS ON YOUR TAX RETURN.)
[ ] FOREIGN PARTNER. I HAVE PROVIDED THE PARTNERSHIP WITH THE
APPROPRIATE FORM W-8 CERTIFICATION OR, IF A JOINT ACCOUNT, EACH
JOINT ACCOUNT OWNER HAS PROVIDED THE PARTNERSHIP THE APPROPRIATE
FORM W-8 CERTIFICATION, AND IF ANY ONE OF THE JOINT ACCOUNT OWNERS
HAS NOT ESTABLISHED FOREIGN STATUS, THAT JOINT ACCOUNT OWNER HAS
PROVIDED THE PARTNERSHIP WITH A CERTIFIED TIN.
U.S. GRANTOR TRUSTS. UNDER PENALTIES OF PERJURY, I CERTIFY THAT:
(1) THE TRUST DESIGNATED AS THE INVESTOR ON THE SUBSCRIPTION
AGREEMENT IS A UNITED STATES GRANTOR TRUST WHICH I CAN AMEND
OR REVOKE DURING MY LIFETIME;
(2) UNDER SUBPART E OF SUBCHAPTER J OF THE INTERNAL REVENUE CODE
(CHECK ONLY ONE OF THE BOXES BELOW):
[ ] (A) 100% OF THE TRUST IS TREATED AS OWNED BY ME;
[ ] ] (B) THE TRUST IS TREATED AS OWNED IN EQUAL SHARES
BY ME AND MY SPOUSE; OR
[ ] (C) ____% OF THE TRUST IS TREATED AS OWNED
BY ________________________, AND THE
REMAINDER IS TREATED AS OWNED _____% BY ME
AND _____% BY MY SPOUSE); AND
(3) EACH GRANTOR OR OTHER OWNER OF ANY PORTION OF THE TRUST HAS
PROVIDED THE PARTNERSHIP WITH THE APPROPRIATE FORM W-8 OR FORM
W-9 CERTIFICATION.
NOTE: IF YOU CHECK THE BOX IN (2)(C), YOU MUST INSERT THE INFORMATION CALLED FOR
BY THE BLANKS.
THE INTERNAL REVENUE SERVICE DOES NOT REQUIRE YOUR CONSENT TO ANY PROVISION OF
THIS DOCUMENT OTHER THAN THE CERTIFICATIONS REQUIRED TO AVOID BACKUP
WITHHOLDING.
6
(OPTIONAL)
ATLAS RESOURCES, INC.
DIRECT DEPOSIT AUTHORIZATION FORM
ATLAS AMERICA PUBLIC 15 (A) L.P.
Please complete this form to request direct deposit into your
checking or savings account. If the account is a brokerage account or a money
market account, please indicate whether it is a checking or savings account.
ATTACH a VOIDED CHECK OR HAVE THE FINANCIAL INSTITUTION SIGN to confirm your
account/routing numbers and send to:
Atlas Resources, Inc.
Attn: Markia Banks
311 Rouser Road, Moon Township, PA 15108
1-800-251-0171. Ext. 186 Fax: 412-262-7430 - Mbanks@atlasamerica.com
TO BE COMPLETED BY THE INVESTOR
- ------------------------------------------------------------------------------------------------------------------------
PERSONAL INFORMATION: (Individual, Trust, LLC, Corp., etc.)
INVESTOR NAME:
- ------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------
Print Name Above
Social Security Number_______________________ Atlas Investor Number: ______________
- ------------------------------------------------------------------------------------------------------------------------
Address
- ------------------------------------------------------------------------------------------------------------------------
City State Zip Code
- ------------------------------------------------------------------------------------------------------------------------
Home Phone # Other Phone # E-Mail Address
- ------------------------------------------------------------------------------------------------------------------------
TO BE COMPLETED BY THE FINANCIAL INSTITUTION (ACH TRANSACTIONS ONLY, NOT FOR WIRE USE)
- ------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------
Name of Financial Institution
- ------------------------------------------------------------------------------------------------------------------------
Routing Number (ABA#) Must be nine digits (ACH ONLY)
- ------------------------------------------------------------------------------------------------------------------------
Account Number
- ------------------------------------------------------------------------------------------------------------------------
Further Reference Information (Optional)
- ------------------------------------------------------------------------------------------------------------------------
Name on Account
__________ Checking / Broker
PLEASE CHECK ACCOUNT TYPE
__________ Savings
Financial Institution Signature _______________________________________________
Phone Number
- ------------------------------------------------------------------------------------------------------------------------
Investors Signature_______________________________________________________________________
Print Signature___________________________________________Date________________________
OFFICE USE ONLY
Date Received: ___________ Date Entered: __________ Initials: ______________
7
EXHIBIT (II)
FORM OF
DRILLING AND OPERATING AGREEMENT
FOR
ATLAS AMERICA PUBLIC #15-2005(A) L.P.
[ATLAS AMERICA PUBLIC #15-2006(___) 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....................................................................5
5. Title Examination of Well Locations; Developer's Acceptance and Liability; Additional Well Locations........8
6. Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price
Determinations; Plugging and Abandonment....................................................................8
7. Billing and Payment Procedure with Respect to Operation of Wells; Disbursements;
Separate Account for Sale Proceeds; Records and Reports; Additional Information............................10
8. Operator's Lien; Right to Collect From Oil or Gas Purchaser................................................12
9. Successors and Assigns; Transfers; Appointment of Agent....................................................12
10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability......................................13
11. Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind..................14
12. Effect of Force Majeure; Definition of Force Majeure; Limitation...........................................15
13. Term.......................................................................................................15
14. Governing Law; Invalidity..................................................................................15
15. Integration; Written Amendment.............................................................................16
16. Waiver of Default or Breach................................................................................16
17. Notices....................................................................................................16
18. Interpretation.............................................................................................16
19. Counterparts...............................................................................................17
Signature Page.............................................................................................17
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 #15-2005(A) L.P. [Atlas America Public #15-2006(___) 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 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.
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.
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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 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.
(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.
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(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;
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(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;
(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. Each oil
and gas well which is drilled and completed under this
Agreement shall be drilled and completed on a Cost plus an
unaccountable, fixed payment reimbursement of $15,000 per well
for Developer's Participants' share of Operator's general and
administrative overhead 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.
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(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:
(i) 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";
(ii) the expense of plugging and abandoning any well before a
completion attempt; and
(iii) the costs (other than Tangible Costs and Lease costs) to
re-enter and deepen an existing well, complete the well
to deeper formations or reservoirs, or plug and abandon
the well if it is nonproductive from the targeted deeper
formations or reservoirs.
"Tangible Costs" shall mean those costs associated with
property acquisition 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:
(i) all costs of equipment, parts and items of hardware used
in drilling and completing a well;
(ii) the costs (other than Intangible Drilling Costs and
Lease costs) to re-enter and deepen an existing well,
complete the well to deeper formations or reservoirs, or
plug and abandon the well if it is nonproductive from
the targeted deeper formations or reservoirs; and
(iii) 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, 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 for
drilling and completing 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.
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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.
(d) DRY HOLE DETERMINATION. If Operator determines at any time
during the drilling or attempted completion of any well
drilled 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) prepaid 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, in
proportion to the share of the Working Interest owned by the
Developer in the wells, 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.
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) prepaid 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 to be
drilled under this Agreement which have not yet been
spudded to provide funds to pay the additional amounts
owed by Developer to Operator. If doing so results in
any excess prepaid Intangible Drilling Costs, then these
funds shall be applied, in proportion to the share of
the Working Interest owned by the Developer in the
wells, 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 the Developer to
Operator for Intangible Drilling Costs on one or
more of the other wells on the Well Locations.
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) prepaid 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, in proportion to the share of the
Working Interest owned by the Developer in the wells, to:
(i) the Developer's Participants' share of the Tangible
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
the Developer's Participants' share of the Tangible
Costs on one or more of the other wells on the Well
Locations.
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Conversely, if Operator's price specified in sub-section (a)
above for the Developer's Participants' share of Tangible
Costs of any well exceeds the estimated Tangible Costs (which
are the Tangible Costs set forth on the AFE) prepaid by
Developer for the Developer's Participants' share of the
Tangible Costs for the well, then:
(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 to be
drilled under this Agreement which have not yet been
spudded to provide funds to pay the additional amounts
owed by Developer to Operator. If doing so results in
any excess prepaid Tangible Costs, then these funds
shall be applied, in proportion to the share of the
Working Interest owed by the Developer in the wells, to:
(a) the Developer's Participants' share of the
Tangible Costs for an additional well or wells to
be drilled on the Additional Well Locations; or
(b) any cost overruns owed by the Developer to
Operator for the Developer's Participants' share
of the Tangible Costs on one or more of the other
wells on the Well Locations.
(iii) The Developer's Participants' share of the Tangible
Costs of all of the wells drilled under this Agreement
and any additional wells to be drilled on the Additional
Well Locations under any Addendum to this Agreement is
ten percent (10%) of the total price prepaid by
Developer to Operator pursuant to Section 4(b) of this
Agreement or any Addendum hereto. The Developer's
Participants' share of the Tangible Costs of any one
well drilled under this Agreement shall be determined
subject to the preceding sentence, taking into account
the Developer's share of all of the Tangible Costs of
all of the wells to be drilled under this Agreement and
any Addendum hereto.
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).
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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;
(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 be adjusted by Operator annually, as of the first day
of January (the "Adjustment Date") of each year, beginning January
l, 2006 [January 1, 2007]. 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 1, 2003 [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.
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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.
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 well, 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 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.
9
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.
(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 or
marginal well production 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:
10
(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:
(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
11
(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:
(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.
12
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:
(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 Subtitle 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)
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.
13
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.
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, the
inability of Operator to begin the drilling of the wells
subject to this Agreement by the applicable times set forth in
Section 2(b) or in any Addendum to this Agreement due to
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.
14
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.
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 #15-2005(A) L.P.
[Atlas America Public #15-2006(__) 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.
15
IN WITNESS WHEREOF, the parties hereto have duly executed this
Agreement as of the day and year first above written.
ATLAS RESOURCES, INC.
By:
----------------------------------------------
Frank P. Carolas, Executive Vice President
ATLAS AMERICA PUBLIC #15-2005(A) L.P.
[ATLAS AMERICA PUBLIC #15-2006(___) L.P.]
By its Managing General Partner:
ATLAS RESOURCES, INC.
By:
----------------------------------------------
Frank P. Carolas, Executive Vice President
16
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 deepest depth penetrated at the
cessation of drilling activities (which is ___________ feet), 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 #15-2005(A) L.P. [ATLAS AMERICA PUBLIC #15-2006(___) 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 of the additional wells before the
close of the 90th day after the close of the calendar year in which the
Agreement was entered into by Operator and the Developer, or, if this Addendum
is dated thereafter, to begin drilling the first additional well within thirty
(30) days after the date of this Addendum and to drill and complete (or plug)
all of the remaining additional wells by the end of the calendar year in which
this Addendum is dated.
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 #15-2005(A) L.P.
[ATLAS AMERICA PUBLIC #15-2006(___) 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.
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.
IV. If you are a resident of OHIO and you subscribe for limited partner units,
then you must meet, without regard to your investment in a partnership,
either of the following special suitability requirements:
o a net worth of not less than $330,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $85,000, exclusive of home, home
furnishings, and automobiles, and an annual gross income during the
current tax year of at least $85,000.
Additionally, if you are a resident of OHIO you must not make an
investment in a partnership which would, after including your previous
investments in prior Atlas Resources programs, if any, and any other
similar natural gas and oil drilling programs, exceed 10% of your net
worth, exclusive of home, home furnishings and automobiles.
1
SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING
INVESTOR GENERAL PARTNER UNITS.
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.
II. If you are a resident of any of the following states:
o ALABAMA; o MASSACHUSETTS; o PENNSYLVANIA;
o ARKANSAS; o MINNESOTA; o TENNESSEE;
o INDIANA; o NORTH CAROLINA; o TEXAS; OR
o MAINE; 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 MICHIGAN; o OREGON;
o IOWA; o MISSISSIPPI; o SOUTH DAKOTA; OR
o KANSAS; o MISSOURI; o VERMONT;
o KENTUCKY; o NEW MEXICO;
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.
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IV. In addition, if you are a resident of any of the following states:
o IOWA; o PENNSYLVANIA;
o MICHIGAN; OR
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 you should limit your investment in the
program and substantially similar programs to no more than 10% of your 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 a net worth of not less than $125,000, exclusive of home, home
furnishings, and automobiles, and $50,000 of taxable income.
VI. If you are a resident of OHIO and you subscribe for investor general
partner units, then you must meet, without regard to your investment in a
partnership, either of the following special suitability requirements:
o a net worth of not less than $750,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $330,000, exclusive of home, home
furnishings, and automobiles, and an annual gross income of at least
$150,000 for the current year and the two previous years.
Additionally, if you are a resident of OHIO you must not make an
investment in a partnership which would, after including your previous
investments in prior Atlas Resources programs, if any, and any other
similar natural gas and oil drilling programs, exceed 10% of your net
worth, exclusive of home, home furnishings and automobiles.
SPECIAL REPRESENTATIONS OF SUBSCRIBERS IN
CALIFORNIA, IOWA, 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;
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(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;
(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."
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II. If a resident of IOWA or 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.
III. 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.
TABLE OF CONTENTS
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Page
Summary of the Offering.......................................................1
Risk Factors..................................................................8
Additional Information.......................................................20
Forward Looking Statements and Associated
Risks.....................................................................20
Investment Objectives........................................................21
Actions to be Taken by Managing General
Partner to Reduce Risks of Additional
Payments by Investor General Partners.....................................22
Capitalization and Source of Funds and Use of
Proceeds..................................................................24
Compensation.................................................................28
Terms of the Offering........................................................35
Prior Activities.............................................................42
Management...................................................................53
Management's Discussion and Analysis of Financial Condition,
Results of Operations, Liquidity and Capital Resources....................59
Proposed Activities..........................................................60
Competition, Markets and Regulation..........................................74
Participation in Costs and Revenues..........................................78
Conflicts of Interest........................................................84
Fiduciary Responsibility of the Managing
General Partner...........................................................95
Federal Income Tax Consequences..............................................97
Summary of Partnership Agreement............................................122
Summary of Drilling and Operating Agreement.................................124
Reports to Investors........................................................125
Presentment Feature.........................................................126
Transferability of Units....................................................128
Plan of Distribution........................................................129
Sales Material..............................................................132
Legal Opinions..............................................................133
Experts.....................................................................134
Litigation..................................................................134
Financial Information Concerning the Managing General Partner
and Atlas America Public #15-2005(A) L.P...............................134
Index to Financial Statements...............................................134
EXHIBIT (A) - Form of Amended and Restated Certificate and Agreement of Limited
Partnership for Atlas America Public #15-2005(A) L.P. [Form of Amended and
Restated Certificate and Agreement of Limited Partnership for Atlas America
Public #15-2006(___) 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
#15-2005(A) L.P. [Atlas America Public #15-2006(___) 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.
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ATLAS AMERICA
PUBLIC #15-2005 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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