As filed with the Securities and Exchange Commission on August 9, 2005
Registration Number ____________
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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ATLAS AMERICA PUBLIC #15-2005 PROGRAM
(Exact name of Registrant as Specified in its Charter)
DELAWARE
(State or other jurisdiction of incorporation or organization)
----------
1311
(Primary Standard Industrial Classification Code Number)
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NOT APPLICABLE
(IRS Employer Identification Number)
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311 ROUSER ROAD
MOON TOWNSHIP, PENNSYLVANIA 15108
(412) 262-2830
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
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JACK L. HOLLANDER, SENIOR VICE PRESIDENT - DIRECT PARTICIPATION PROGRAMS
ATLAS RESOURCES, INC.
311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108
(412) 262-2830
(Name, address, including zip code, and telephone
number, including area code, of agent for service)
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With a Copy to:
WALLACE W. KUNZMAN, JR., ESQ.
KUNZMAN & BOLLINGER, INC.
5100 N. BROOKLINE
SUITE 600
OKLAHOMA CITY, OKLAHOMA 73112
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AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES EFFECTIVE.
(Approximate Date of Commencement of Proposed Sale to the Public)
If any of the securities being registered on this form are to be
offered on a delayed or continuous basis pursuant to Rule 415 under the
Securities Act of 1933, check the following box: [X]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to rule
462(c) under the Securities Act, check the following box and list the Securities
Act registration statement number of the earlier effective registration
statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to rule
462(d) under the Securities Act, check the following box and list the Securities
Act registration statement number of the earlier effective registration
statement for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule
434, please check the following box: [ ]
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CALCULATION OF REGISTRATION FEE
Title of Each Unit Dollar Proposed Maximum Proposed Maximum Amount of
Class of Securities Amounts Amounts to be Offering Aggregate Registration
to be Registered to be Registered Registered Price per Unit Offering Price Fee
- ----------------------------------- ---------------- ---------------- ---------------- ---------------- ----------------
Investor General Partner Units (1) 14,550 $ 145,500,000 $ 10,000 $ 145,500,000 $ 17,125.35
Converted Limited Partner Units (2) 14,550 -0- -0- -0- -0-
Limited Partner Units (2) 450 $ 4,500,000 $ 10,000 $ 4,500,000 $ 529.65
---------------- ---------------- ---------------- ---------------- ----------------
TOTAL 15,000 $ 150,000,000 $ 150,000,000 $ 17,655.00
================ ================ ================ ================
(1) "Investor General Partner Units" means the investor general partner
interests offered to participants in the program.
(2) "Limited Partner Units" means up to 450 initial limited partner
interests offered to participants in the program and up to 14,550
limited partner units into which the investor general partner units
automatically will be converted by the managing general partner with no
additional price paid by the investor.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATES AS MAY BE
NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER
AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL
THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES
ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH
DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.
ATLAS AMERICA PUBLIC #15-2005 PROGRAM
CROSS REFERENCE SHEET
Item of Form S-1 Caption in Prospectus
- --------------------------------------------------------------------- -----------------------------------------------------------
Item 1. Forepart of the Registration Statement and Outside Front Front Page of Registration Statement and Outside Front
Cover Page of Prospectus.................................... Cover Page of Prospectus
Item 2. Inside Front and Outside Back Cover Pages of Prospectus..... Inside Front and Outside Back Cover Pages of Prospectus
Item 3. Summary Information, Risk Factors and Ratio Of
Earnings to Fixed Charges.................................. Summary of the Offering; Risk Factors
Item 4. Use of Proceeds............................................. Capitalization and Source of Funds and Use of Proceeds
Item 5. Determination of Offering Price............................. Terms of the Offering
The program has not conducted any activities and the
managing general partner's officers, directors,
promoters and affiliated persons have not acquired any
units during the past five years. Also, no units will
be issued in this offering to the managing general
partner except units subscribed for by the managing
general partner, which it does not anticipate.
Discounted units, if any, are described
Item 6. Dilution.................................................... in "Plan of Distribution."
Item 7. Selling Security Holders.................................... The program does not have any selling security holders.
Item 8. Plan of Distribution........................................ Plan of Distribution
Summary of the Offering; Terms of the Offering; Summary
Item 9. Description of Securities to be Registered.................. of Partnership Agreement
Item 10. Interests of Named Experts and Counsel...................... Legal Opinions; Experts
Item 11. Information with respect to the Registrant
(a) Description of Business............................... Proposed Activities; Management
(b) Description of Property............................... Proposed Activities
(c) Legal Proceedings..................................... Litigation
The partnerships composing the program have no markets
(d) Market Price of and Dividends on the Registrant's in which their units are being traded and they have not yet
Common Equity and Related Stockholder Matters......... conducted activities or paid any dividends.
Financial Information Concerning the Managing General
(e) Financial Statements.................................. Partner and Atlas America Public #15-2005(A) L.P.
None of the partnerships have conducted any activities.
(f) Selected Financial Data............................... Thus, the program does not have this information.
None of the partnerships have conducted any activities.
(g) Supplementary Financial Information................... Thus, the program does not have this information.
Management's Discussion and Analysis of Financial
(h) Management's Discussion and Analysis of Condition, Results of Operations, Liquidity and Capital
Financial Condition and Results of Operations......... Resources
(i) Changes in and Disagreements with Accountants There have been no changes in and disagreements with
on Accounting and Financial Disclosure................ accountants on accounting and financial disclosure.
Item of Form S-1 Caption in Prospectus
- --------------------------------------------------------------------- -----------------------------------------------------------
(j) Quantitative and Qualitative Disclosures about The partnerships have no market for their units and none
Market Risk........................................... will be created.
(k) Directors and Executive Officers...................... Management
(l) Executive Compensation................................ Management
(m) Security Ownership of Certain Beneficial Owners
and Management........................................ Management
(n) Certain Relationships and Related Transactions........ Compensation; Management; Conflicts of Interest
Item 12. Disclosure of Commission Position on Indemnification
for Securities Act Liabilities............................. Fiduciary Responsibilities of the Managing General Partner
The information in this prospectus is not complete and may be changed. We may
not sell these securities until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell these securities and it is not soliciting an offer to buy these
securities in any state where the offer or sale is not permitted.
PROSPECTUS SUBJECT TO COMPLETION DATED _________________, 2005
ATLAS AMERICA PUBLIC #15-2005 PROGRAM
Up to 14,550 Investor General Partner Units and 14,550 converted Limited
Partner Units and up to 450 Limited Partner Units,
which are collectively referred to as the "Units," at $10,000 per Unit
$2 Million (200 Units) Minimum Aggregate Subscriptions
$150,000,000 (15,000 Units) Maximum Aggregate Subscriptions
Atlas America Public #15-2005 Program is a series of up to three limited
partnerships which will drill primarily natural gas development wells. See
"Terms of the Offering - Subscription to a Partnership," beginning on page ___
for a detailed description of the offering of these limited partnerships. They
will be managed by Atlas Resources, Inc. of Pittsburgh, Pennsylvania.
If you invest in a partnership, you will not have any interest in either of the
other two partnerships unless you also make a separate investment in the other
partnerships.
The units will be offered on a "best efforts" "minimum-maximum" basis. This
means the broker/dealers 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 efforts to sell the remaining units in the partnership.
Subscription proceeds for each partnership will be held in an interest bearing
escrow account until $2 million has been received. The offering of Atlas America
Public #15-2005(A) L.P. will not extend beyond December 31, 2005 and the
offering of Atlas America Public #15-2006(B) L.P. and Atlas America Public
#15-2006(C) L.P. will not extend beyond December 31, 2006. If the minimum
subscription proceeds are not received by a partnership's offering termination
date, then your subscription will be promptly returned to you from the escrow
account with interest and without deduction for any fees.
The Offering: In addition to the information in the table below for not
less than 95% of the units (14,250 units), up to 5% of the units (750
units), in the aggregate, may be sold at $8,950 per unit to the managing
general partner, its officers, directors and affiliates, and investors who
buy units through the officers and directors of the managing general
partner; or at $9,300 per unit to registered investment advisors and their
clients, and selling agents and their registered representatives and
principals. These discounted prices reflect certain fees, sales commissions
and reimbursements which will not be paid for these sales. (See "Plan of
Distribution.") To the extent that units are sold at discounted prices, a
partnership's subscription proceeds will be reduced.
Total Total
Per Unit MINIMUM Maximum
------------- ------------- -------------
PUBLIC PRICE $ 10,000 $ 2,000,000 $ 150,000,000
Dealer-manager fee, sales
commissions, accountable $ 1,050 $ 210,000 $ 15,750,000
reimbursements for permissible
non-cash compensation, and
bona fide due diligence
reimbursements (1)
Proceeds to partnership $ 10,000 $ 2,000,000 $ 150,000,000
- ----------
(1) These fees, sales commissions and reimbursements will be paid by the
managing general partner as a part of its capital contribution and not
from subscription proceeds.
o A partnership's drilling operations involve the possibility of a
substantial or partial loss of your investment because of wells which
are productive, but do not produce enough revenue to return the
investment made and dry holes.
o A partnership's revenues are directly related to the ability to market
the natural gas and natural gas and oil prices, which are volatile and
uncertain. If natural gas and oil prices decrease, then your investment
return will decrease.
o Unlimited joint and several liability for partnership obligations if
you choose to invest as an investor general partner until you are
converted to a limited partner.
o Lack of liquidity or a market for the units, 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.......................................14
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...................16
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..................................................................17
Your Deduction for Intangible Drilling Costs May Be Limited for
Purposes of the Alternative Minimum Tax.................................17
Limited Partners Need Passive Income to Use Their Deduction
for Intangible Drilling Costs........................................17
You May Owe Taxes in Excess of Your Cash Distributions from
Your Partnership.....................................................18
Investment Interest Deductions of Investor General Partners
May Be Limited.......................................................18
Your Tax Benefits from a Partnership Are Not Contractually
Protected............................................................18
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..........................................19
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
i
TABLE OF CONTENTS
COMPENSATION..................................................................27
Natural Gas and Oil Revenues...............................................28
Lease Costs................................................................28
Drilling Contracts.........................................................29
Per Well Charges...........................................................30
Gathering Fees.............................................................31
Dealer-Manager Fees........................................................33
Interest and Other Compensation............................................33
Estimate of Administrative Costs and Direct Costs to be Borne by
the Partnerships........................................................33
TERMS OF THE OFFERING.........................................................34
Subscription to a Partnership..............................................34
Partnership Closings and Escrow............................................35
Acceptance of Subscriptions................................................36
Suitability Standards......................................................37
In General..............................................................37
General Suitability Requirements for Purchasers of
Limited Partner Units................................................37
Special Suitability Requirements for Purchasers of
Limited Partner Units................................................38
General Suitability Requirements for Purchasers of
Investor General Partner Units.......................................38
Special Suitability Requirements for Purchasers of
Investor General Partner Units.......................................39
Fiduciary Accounts......................................................41
PRIOR ACTIVITIES..............................................................41
MANAGEMENT....................................................................51
Managing General Partner and Operator......................................51
Officers, Directors and Other Key Personnel................................52
Atlas America, Inc., a Delaware Company....................................55
Organizational Diagram and Security Ownership of Beneficial Owners.........56
Remuneration...............................................................56
Code of Business Conduct and Ethics........................................56
Transactions with Management and Affiliates................................57
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS
OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES................................57
PROPOSED ACTIVITIES...........................................................58
Overview of Drilling Activities............................................58
Primary Areas of Operations................................................59
Mississippian/Upper Devonian Sandstone
Reservoirs, Fayette County, Pennsylvania.............................61
Clinton/Medina Geological Formation in Western Pennsylvania.............61
Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania.....62
Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania......62
Mississippian Carbonate and Devonian Shale Reservoirs in
Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee..................................................63
Secondary Areas of Operations..............................................63
Clinton/Medina Geological Formation
in Western New York..................................................63
Clinton/Medina Geological Formation
in Southern Ohio.....................................................64
Acquisition of Leases......................................................64
Deep Drilling Rights Retained by Managing General Partner...............65
Interests of Parties.......................................................66
Primary Areas..............................................................67
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 .........................................67
Upper Devonian Sandstone Reservoirs in Armstrong and Indiana
Counties, Pennsylvania...............................................67
Mississippian Carbonate and Devonian Shale Reservoirs in
Anderson, Campbell, Morgan, Roane and Scott Counties,
Tennessee............................................................67
Secondary Areas............................................................68
Title to Properties........................................................68
Drilling and Completion Activities; Operation
of Producing Wells......................................................68
Sale of Natural Gas and Oil Production.....................................69
Policy of Treating All Wells Equally in a
Geographic Area......................................................69
Gathering of Natural Gas................................................70
Natural Gas Contracts...................................................70
Marketing of Natural Gas Production from Wells in Other Areas of
the United States.......................................................72
Crude Oil..................................................................72
Insurance..................................................................72
Use of Consultants and Subcontractors......................................72
COMPETITION, MARKETS AND REGULATION...........................................72
Natural Gas Regulation.....................................................72
Crude Oil Regulation.......................................................73
Competition and Markets....................................................73
State Regulations..........................................................75
Environmental Regulation...................................................76
Proposed Regulation........................................................76
PARTICIPATION IN COSTS AND REVENUES...........................................77
In General.................................................................77
Costs......................................................................77
Revenues...................................................................79
Subordination of Portion of Managing General
Partner's Net Revenue Share.............................................79
Table of Participation in Costs and Revenues...............................81
Allocation and Adjustment Among Investors..................................82
Distributions..............................................................82
Liquidation................................................................82
CONFLICTS OF INTEREST.........................................................83
In General.................................................................83
Conflicts Regarding Transactions with the Managing General
Partner and its Affiliates..............................................83
Conflict Regarding the Drilling and Operating
Agreement...............................................................84
Conflicts Regarding Sharing of Costs and Revenues..........................84
Conflicts Regarding Tax Matters Partner....................................85
Conflicts Regarding Other Activities of the Managing General
Partner, the Operator and Their Affiliates..............................85
Conflicts Involving the Acquisition of Leases..............................85
Conflicts Between Investors and the Managing General Partner as
an Investor.............................................................90
Lack of Independent Underwriter and Due Diligence Investigation ...........90
Conflicts Concerning Legal Counsel.........................................90
Conflicts Regarding Presentment Feature....................................91
Conflicts Regarding Managing General Partner Withdrawing an Interest.......91
Conflicts Regarding Order of Pipeline Construction and Gathering Fees......91
Procedures to Reduce Conflicts of Interest.................................91
Policy Regarding Roll-Ups..................................................93
ii
TABLE OF CONTENTS
FIDUCIARY RESPONSIBILITY OF THE
MANAGING GENERAL PARTNER......................................................94
In General.................................................................94
Limitations on Managing General Partner Liability as Fiduciary.............94
FEDERAL INCOME TAX CONSEQUENCES...............................................95
Introduction...............................................................95
Disclosures................................................................95
Special Counsel's Assumptions..............................................96
Managing General Partner's Representations.................................96
Special Counsel's Opinions.................................................97
Summary Discussion of the Federal Income Tax Consequences of an
Investment in a Partnership by a Typical
Investor ("Summary Discussion")........................................101
Introduction..............................................................101
Partnership Classification................................................101
Limitations on Passive Activity Losses and Credits........................102
Publicly Traded Partnership Rules.........................................102
Conversion from Investor General Partner to Limited Partner...............103
Taxable Year and Method of Accounting.....................................103
Business Expenses.........................................................103
Intangible Drilling Costs.................................................104
Drilling Contracts........................................................105
Depletion Allowance.......................................................106
Depreciation and Cost Recovery Deductions.................................107
Marginal Well Production Credits..........................................108
Lease Acquisition Costs and Abandonment...................................109
Tax Basis of Units........................................................109
"At Risk" Limitation on Losses............................................109
Distributions From a Partnership..........................................110
Sale of the Properties....................................................110
Disposition of Units......................................................111
Alternative Minimum Tax...................................................112
Limitations on Deduction of Investment Interest...........................114
Allocations...............................................................114
Partnership Borrowings....................................................115
Partnership Organization and Offering Costs...............................115
Tax Elections.............................................................115
Tax Returns and IRS Audits................................................116
Tax Returns............................................................117
Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines
Limitations on Deductions...............................................117
Federal Interest and Tax Penalties........................................117
State and Local Taxes.....................................................119
Severance and Ad Valorem (Real Estate) Taxes..............................119
Social Security Benefits and Self-Employment Tax..........................119
Farmouts..................................................................119
Foreign Partners..........................................................119
Estate and Gift Taxation..................................................120
Changes in the Law........................................................120
SUMMARY OF PARTNERSHIP AGREEMENT.............................................120
Liability of Limited Partners.............................................120
Amendments................................................................121
Notice....................................................................121
Voting Rights.............................................................121
Access to Records.........................................................122
Withdrawal of Managing General Partner....................................122
Return of Subscription Proceeds if Funds Are Not Invested in
Twelve Months.............................................................122
SUMMARY OF DRILLING AND OPERATING AGREEMENT..................................122
REPORTS TO INVESTORS.........................................................123
PRESENTMENT FEATURE..........................................................124
TRANSFERABILITY OF UNITS.....................................................126
Restrictions on Transfer Imposed by the Securities Laws, the Tax
Laws and the Partnership Agreement.....................................126
Conditions to Becoming a Substitute Partner...............................127
PLAN OF DISTRIBUTION.........................................................127
Commissions...............................................................127
Indemnification...........................................................130
SALES MATERIAL...............................................................130
LEGAL OPINIONS...............................................................131
EXPERTS......................................................................131
LITIGATION...................................................................132
FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND
ATLAS AMERICA PUBLIC #15-2005(A) L.P......................................132
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 three Delaware limited
partnerships. These limited partnerships are sometimes referred to in this
prospectus in the singular as a "partnership" or in the plural as the
"partnerships." Units in the three 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 two 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 36 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
allb1ciip, Atlas American Publci Well Production Credits in
2005 or 2006, and it May Be Many Years Before You Receive
Those cre partnerships, in the aggregate, may not exceed
$150 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 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
15,000 units which is $150 million. The maximum subscription proceeds for each
partnership will be the lesser of:
2
o $150 million; or
o $150 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
You may buy either:
o investor general partner units; or
o limited partner units;
in the partnership being offered at the time you subscribe.
The partnerships will not issue certificates for their units, but your ownership
of your unit(s) will be recorded on the partnership's books. 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 $150 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% per unit, based on $10,000 per unit regardless of the actual
subscription price for your units, in each of the first five 12-month periods
beginning with the partnership's first cash 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 its 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.
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.
5
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 50 partnerships since 1985,
however, 37 of the 50 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 -
8
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.")
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 may be less the farther the natural gas
is transported because of increased transportation costs.
o Production from wells drilled in certain areas, such as the
wells in Crawford County, Pennsylvania and to a lesser extent,
Fayette County, Pennsylvania 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.
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
10
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
11
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.
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 $150 million. There are no other requirements
regarding the size of a partnership other than the nonbinding targeted amounts
described in "Terms of the Offering - Subscription to a Partnership." 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 688 net wells if subscription proceeds of $150
million are received by a partnership. A gross well is a well in which a
partnership owns a working interest. This is compared with a net well which is
the sum of the fractional working interests owned in the gross wells. For
example, a 50% working interest owned in three wells is three gross wells, but
1.5 net wells.
On the other hand, to the extent more than the minimum subscriptions are
received by a partnership and the number of wells drilled increases, the
partnership's overall investment return may decrease if the managing general
partner is unable to find enough suitable wells to be drilled. Also, in a large
partnership greater demands will be placed on the managing general partner's
management capabilities.
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.
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
12
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.
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
13
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.
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
14
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;
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;
15
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.")
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
16
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, its due diligence examination concerning the
partnerships cannot be considered to be independent or as comprehensive as an
investigation that would be conducted by an independent broker/dealer. (See
"Conflicts of Interest.")
A LENGTHY OFFERING PERIOD MAY RESULT IN DELAYS IN THE INVESTMENT OF YOUR
SUBSCRIPTION AND ANY CASH DISTRIBUTIONS FROM THE PARTNERSHIP TO YOU. Because the
offering period for a particular partnership can extend for many months, it is
likely that there will be a delay in the investment of your subscription
proceeds. This may create a delay in the partnership's cash distributions to you
which will be paid only after 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. 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
when you subscribe, which wells are drilled with your subscription proceeds, or
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.
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
17
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 taxable 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 taxable 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.
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 investment interest expense,
if any.
YOUR TAX BENEFITS FROM 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.
18
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 constraint. 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 the intangible drilling costs were prepaid and you invested in
the partnership. 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.")
CHANGES IN THE LAW MAY REDUCE YOUR TAX BENEFITS FROM AN INVESTMENT IN A
PARTNERSHIP. Your investment in the 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, the managing general
partner further anticipates that 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 in 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.")
19
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:
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.
20
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.
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
21
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.
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
22
$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.
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
23
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 $150 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.")
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 $150 million if 15,000 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 $50,000,000 if 15,000 units are sold.
24
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 $200,000,000 if 15,000
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 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.
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 15,000 units, which is the maximum number of
units, in the aggregate, for all partnerships in the program.
Substantially all of the proceeds available to each partnership will be expended
for the following purposes and in the following manner:
25
INVESTOR CAPITAL
200
UNITS 15,000 UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1)
- ----------------------------------------------------------------------- ---------- ------- ------------- ------
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions, .5% accountable reimbursement
for permissible non-cash compensation, and up to .5% reimbursement for
bona fide 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% $ 135,000,000 90%
Equipment costs (2).................................................... $ 200,000 10% $ 15,000,000 10%
Leases................................................................. - 0 - - 0 - - 0 - - 0 -
---------- ------- ------------- ------
TOTAL INVESTOR CAPITAL................................................. $2,000,000 100% $ 150,000,000 100%
========== ======= ============= ======
- ----------
(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."
MANAGING GENERAL PARTNER CAPITAL
200 15,000
UNITS UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1)
- ----------------------------------------------------------------------- ---------- ------- ------------- ------
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions, .5% accountable reimbursement
for permissible non-cash compensation, and up to .5% reimbursement for
bona fide due diligence expenses (2).................................. $ 210,000 22.72% $ 15,750,000 22.11%
Organization costs (2)................................................. $ 90,000 9.73% $ 6,750,000 9.49%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs.............................................. - 0 - - 0 - - 0 - - 0 -
Equipment costs (3).................................................... $ 557,100 60.27% $ 42,934,299 60.28%
Leases (4)............................................................. $ 67,288 7.28% $ 5,786,768 8.12%
---------- ------- ------------- ------
TOTAL MANAGING GENERAL PARTNER CAPITAL................................. $ 924,388 100% $ 71,221,067 100%
========== ======= ============= ======
- ----------
(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.
26
(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.
TOTAL PARTNERSHIP CAPITAL
200 15,000
UNITS UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1)
- ----------------------------------------------------------------------- ----------- ------- ------------- ------
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions, .5% accountable reimbursement
for permissible non-cash compensation, and up to .5% reimbursement for
bona fide due diligence expenses (2)................................... $ 210,000 7.18% $ 15,750,000 7.12%
Organization costs (2)................................................. $ 90,000 3.07% $ 6,750,000 3.05%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs (3).......................................... $ 1,800,000 61.55% $ 135,000,000 61.02%
Equipment costs (3).................................................... $ 757,100 25.90% $ 57,934,299 26.19%
Leases (4)............................................................. $ 67,288 2.30% $ 5,786,768 2.62%
----------- ------- ------------- ------
TOTAL PARTNERSHIP CAPITAL.............................................. $ 2,924,388 100% $ 221,221,067 100%
=========== ======= ============= ======
- ----------
(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
27
received by a partnership, and approximately 720 gross wells, which will be
approximately 688 net wells, will be drilled, in the aggregate, if subscription
proceeds of $150 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.")
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:
28
o $67,288 if $2 million is received, which is eight net wells
times $8,411 per prospect; and
o $5,786,768 if $150 million is received, which is 688 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.
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 $150 million are received, the
managing general partner anticipates that the partnerships' weighted average
cost of drilling and completing approximately 688 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
29
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.
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 $29,889,472 if $150 million is received, which is 688 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
30
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;
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 $2,352,960 if $150 million is received, which is 688 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.
31
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.
CURRENT AMOUNT OF GATHERING FEES
EACH PARTNERSHIP'S PRIMARY AND TO 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, however, 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.
32
The actual amount of gathering fees to be paid by a partnership to the managing
general partner cannot be quantified, because the volume of natural gas that
will be produced and transported from the partnership's wells cannot be
predicted.
DEALER-MANAGER FEES
Subject to certain exceptions described in "Plan of Distribution," Anthem
Securities, the dealer-manager and an affiliate of the managing general partner,
will receive on each unit sold to an investor:
o a 2.5% dealer-manager fee;
o a 7% sales commission;
o a .5% reimbursement for accountable permissible non-cash
compensation; and
o an up to .5% reimbursement of the selling agents' bona fide
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 $15,750,000 if $150 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:
33
o $7,200 if $2 million is received, which is eight net wells at
$75 per well per month; and
o $619,200 if $150 million is received, which is 688 net wells
at $75 per well per month.
Direct costs will be determined by the managing general partner, in its sole
discretion, including the provider of the services or goods and the amount of
the provider's compensation. Direct costs will be billed directly to and paid by
each partnership to the extent practicable. The anticipated direct costs set
forth below for a partnership's first 12 months of operation after all of its
wells have been placed into production may vary from the estimates shown for
numerous reasons which cannot accurately be predicted. These reasons include:
o the number of investors;
o the number of wells drilled;
o the partnership's degree of success in its activities;
o the extent of any production problems;
o inflation; and
o various other factors involving the administration of the
partnership.
Minimum Maximum
Subscriptions Subscriptions
of $2 million of $150 million (1)
------------- -------------------
DIRECT COSTS
External Legal...................................................... $ 6,000 $ 24,000
Accounting Fees for Audit and Tax Preparation....................... 22,000 80,000
Independent Engineering Reports..................................... 1,500 40,000
---------- -------------
TOTAL .............................................................. $ 29,500 $ 144,000
========== =============
- ----------
(1) This assumes three partnerships are formed as described below in "Terms
of the Offering - Subscription to a Partnership" and the targeted
nonbinding subscriptions of each partnership are received.
TERMS OF THE OFFERING
SUBSCRIPTION TO A PARTNERSHIP
Atlas America Public #15-2005 Program was formed to offer for sale an aggregate
of $150 million of units in a series of up to three 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 $150 million; or
o $150 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
34
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.
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 05/31/06 12/31/06
Atlas America Public #15-2006(C) $ 2 million $ 50 million 08/31/06 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.
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" or
"Atlas America Public #15-2006(C) L.P., Escrow Agent, National City Bank of PA,"
as appropriate, and give your check to your broker/dealer for submission to the
dealer-manager and escrow agent. 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.
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)
35
L.P. is December 31, 2005 and the latest offering termination date for both
Atlas America Public #15-2006(B) L.P. and Atlas America Public #15-2006(C) 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.
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.
36
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 OHIO,
o ALASKA, o KENTUCKY, o OKLAHOMA,
o ARIZONA, o LOUISIANA, o OREGON,
o ARKANSAS, o MAINE, o PENNSYLVANIA,
o COLORADO, o MARYLAND, o RHODE ISLAND,
o CONNECTICUT, o MASSACHUSETTS, o SOUTH CAROLINA,
o DELAWARE, o MINNESOTA, o SOUTH DAKOTA,
o DISTRICT OF COLUMBIA, o MISSISSIPPI, o TENNESSEE,
o FLORIDA, o MISSOURI, o TEXAS,
o GEORGIA, o MONTANA, o UTAH,
o HAWAII, o NEBRASKA, o VERMONT,
o IDAHO, o NEVADA, o VIRGINIA,
o ILLINOIS, o NEW MEXICO, o WASHINGTON,
o INDIANA, o NEW YORK, o WEST VIRGINIA,
o IOWA, o NORTH DAKOTA, o WISCONSIN, OR
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
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
37
Section 63 of the Internal Revenue Code of at least $60,000,
without regard to an investment in the partnership.
In addition, if you are a resident of OHIO or PENNSYLVANIA, then you must not
make an investment in a partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings and automobiles. Finally, if you are a
resident of KANSAS, it is recommended by the Office of the Kansas Securities
Commissioner that Kansas investors should limit their investment in the program
and substantially similar programs to no more than 10% of their net worth,
excluding home, furnishings and automobiles.
However, if you are a resident of the states set forth below, then 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.
GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS. If you are a resident of any of the following states or jurisdictions:
38
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 MINNESOTA, o PENNSYLVANIA,
o ARKANSAS, o NORTH CAROLINA, o TENNESSEE,
o MAINE, o OHIO, o TEXAS, OR
o MASSACHUSETTS, o OKLAHOMA, o WASHINGTON
and you 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
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.
39
o In addition, if you are a resident of OHIO or PENNSYLVANIA,
then you must not make an investment in a partnership which is
in excess of 10% of your net worth, exclusive of home, home
furnishings, and automobiles.
o If you are a resident of any of the following states:
o ARIZONA, o KENTUCKY, o NEW MEXICO,
o INDIANA, o MICHIGAN, o OREGON,
o IOWA, o MISSISSIPPI, o SOUTH DAKOTA, OR
o KANSAS, o MISSOURI, o VERMONT
and you 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
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
40
o a net worth of not less than $125,000, exclusive of
home, home furnishings, and automobiles, and $50,000
of taxable income.
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 $289,802,868, 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.
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.
41
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 Years
Number General Date Date of Wells Previous
of Investor Partner Total Operations First In Assess-
Partnership Investors Capital Capital Capital Began Distributions Production ments
- --------------------------------------- --------- ----------- ----------- ------------ ---------- ------------- ---------- --------
1. Atlas L.P. #1 - 1985 19 $ 600,000 $ 114,800 $ 714,800 12/31/85 07/02/86 19.47 -0-
2. A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 18.47 -0-
3. A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 17.47 -0-
4. A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 16.47 -0-
5. A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 15.47 -0-
6. A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 14.47 -0-
7. A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 14.25 -0-
8. A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 13.42 -0-
9. A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 13.25 -0-
10. A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 13.17 -0-
11. A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 12.50 -0-
12. A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 12.00 -0-
13. A.E. Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 11.75 -0-
14. A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 11.42 -0-
15. A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 11.17 -0-
16. A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 10.92 -0-
17. A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 10.42 -0-
18. A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 10.17 -0-
19. A.E. Nineties-Public #3 391 5,800,990 928,546 6,729,536 12/31/94 06/05/95 10.17 -0-
20. A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96 9.34 -0-
21. A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96 8.92 -0-
22. A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96 9.17 -0-
23. A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 8.50 -0-
24. A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97 8.17 -0-
25. A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 8.17 -0-
26. A.E. Nineties-17 217 8,813,488 2,113,947 10,927,435 08/29/97 12/12/97 7.59 -0-
27. A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98 7.17 -0-
28. A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98 7.00 -0-
29. A.E. Nineties-18 225 11,391,673 3,448,751 14,840,424 07/31/98 01/07/99 6.25 -0-
30. A.E. Nineties-Public #7 366 11,988,350 3,812,150 15,800,500 12/31/98 07/10/99 5.92 -0-
31. A.E. Partners 1998 26 1,740,000 756,360 2,496,360 12/31/98 07/02/99 5.92 -0-
32. A.E. Nineties-19 288 15,720,450 4,776,598 20,497,048 09/30/99 01/14/00 5.42 -0-
33. A.E. Nineties-Public #8 380 11,088,975 3,148,181 14,237,156 12/31/99 06/09/00 4.92 -0-
34. A.E. Partners 1999 8 450,000 196,500 646,500 12/31/99 10/02/00 4.92 -0-
35. 1999 Viking Resources LP 131 4,555,210 1,678,038 6,233,248 12/31/99 06/01/00 4.92 -0-
36. Atlas America-Series 20 361 18,809,150 6,297,945 25,107,095 09/30/00 01/30/01 4.67 -0-
37. Atlas America - Public #9 530 14,905,465 5,563,527 20,468,992 12/31/00 07/13/01 4.27 -0-
38. Atlas America - Series 21-A 282 12,510,713 4,535,799 17,046,512 05/15/01 11/16/01 4.02 -0-
39. Atlas America - Series 21-B 360 17,411,825 6,442,761 23,854,586 09/19/01 03/02/02 3.42 -0-
40. Atlas America - Public #10 818 21,281,170 7,227,432 28,508,602 12/31/01 06/20/02 3.17 -0-
41. Atlas America - Series 22 258 10,156,375 3,481,591 13,637,966 05/31/02 11/12/02 2.67 -0-
42. Atlas America - Series 23 246 9,644,550 3,214,850 12,859,400 09/30/02 02/18/03 2.42 -0-
43. Atlas America - Public #11-2002 1017 31,178,145 13,295,226 44,473,371 12/31/02 7/15/2003 2.17 -0-
44. Atlas America - Series #24-2003 (A) 325 14,363,955 4,949,143 19,313,098 05/31/03 12/05/03 1.67 -0-
45. Atlas America - Series #24-2003 (B) 422 20,542,850 7,300,020 27,842,870 08/29/03 02/05/04 1.42 -0-
46. Atlas America - Public #12-2003 1102 40,170,308 13,708,076 53,878,384 12/31/03 6/15/04 1.17 -0-
47. Atlas America Series # 25-2004 (A) 635 27,601,053 10,266,771 37,867,824 05/31/04 11/5/04 .92 -0-
48. Atlas America Series # 25-2004 (B) 634 31,531,035 16,006,953 47,537,988 08/31/04 2/5/05 .50 -0-
49. Atlas America Public # 14-2004 1494 52,506,570 25,971,721 78,478,291 11/15/04 (1) (1) -0-
50. Atlas America Public # 14-2005 (A) 2192 69,674,900 (3) 69,674,900 06/17/05 (2) (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.
42
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.
43
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
Partnership Capital(1) Operating(6) Admin. Direct Distributions(2)(4)
- ------------------------------------------- ------------- -------------- ---------- --------- -------------------
1. Atlas L.P. #1 - 1985 $ 600,000 $ 229,019 $ 46,817 $ 14,368 $ 1,629,473
2. A.E. Partners 1986 631,250 182,547 75,701 13,504 783,443
3. A.E. Partners 1987 721,000 183,184 64,095 13,776 784,063
4. A.E. Partners 1988 617,050 153,798 61,579 12,289 721,776
5. A.E. Partners 1989 550,000 149,987 66,191 12,429 903,764
6. A.E. Partners 1990 887,500 226,940 95,450 17,815 1,314,579
7. A.E. Nineties - 10 2,200,000 483,892 105,371 46,030 2,012,839
8. A.E. Nineties - 11 750,000 183,732 105,868 67,650 1,119,367
9. A.E. Partners 1991 868,750 205,080 123,537 29,396 1,416,503
10. A.E. Nineties - 12 2,212,500 482,214 103,585 133,491 2,174,018
11. A.E. Nineties - JV 92 4,004,813 824,968 168,657 226,777 4,568,558(3)
12. A.E. Partners 1992 600,000 115,983 61,388 15,751 938,212
13. A.E. Nineties - Public #1 2,988,960 517,688 106,192 125,612 2,468,829
14. A.E. Nineties - 1993 Ltd. 3,753,937 582,943 114,539 61,990 2,265,116
15. A.E. Partners 1993 700,000 152,624 45,488 14,884 1,103,681
16. A.E. Nineties - Public #2 3,323,920 518,232 94,572 88,979 2,397,396
17. A.E. Nineties - 14 9,940,045 1,578,602 302,434 82,689 6,274,302
18. A.E. Partners 1994 892,500 157,691 57,130 20,472 1,189,232
19. A.E. Nineties - Public #3 5,800,990 852,335 162,313 103,031 4,129,462
20. A.E. Nineties - 15 10,954,715 1,603,386 305,673 98,752 8,048,256
21. A.E. Partners 1995 600,000 90,759 22,008 11,120 396,138
22. A.E. Nineties - Public #4 6,991,350 966,744 177,743 103,911 3,488,242
23. A.E. Nineties - 16 10,955,465 1,385,468 233,283 101,673 5,888,179
24. A.E. Partners 1996 800,000 128,884 28,830 49,647 562,713
25. A.E. Nineties - Public #5 7,992,240 970,644 176,614 119,372 4,078,820
26. A.E. Nineties - 17 8,813,488 1,066,711 178,218 162,396 5,485,882
27. A.E. Nineties - Public #6 9,901,025 1,239,111 205,405 144,089 6,101,795
28. A.E. Partners 1997 506,250 75,057 16,661 33,241 411,635
29. A.E. Nineties - 18 11,391,673 1,379,259 218,082 267,919 6,282,657
30. A.E. Nineties - Public #7 11,988,350 1,205,295 182,757 68,302 4,747,724
31. A.E. Partners 1998 1,740,000 230,651 28,831 63,891 1,196,076
32. A.E. Nineties - 19 15,720,450 1,579,647 238,582 18,301 7,053,948
33. A.E. Nineties - Public #8 11,088,975 1,067,034 162,444 84,879 5,242,235
34. A.E. Partners 1999 450,000 46,558 4,959 15,993 367,792
35. 1999 Viking Resources LP 4,555,210 1,351,635 0 184,991 6,689,078
36. Atlas America - Series 20 18,809,150 2,722,386 261,787 196,873 13,639,507
37. Atlas America - Public #9 14,905,465 1,707,033 180,278 76,569 7,887,277
38. Atlas America - Series 21-A 12,510,713 1,108,375 131,186 12,964 5,805,256
39. Atlas America - Series 21-B 17,411,825 1,369,725 154,505 12,983 6,899,718
40. Atlas America - Public #10 21,281,170 1,653,481 187,736 70,383 9,475,449
41. Atlas America - Series 22 10,156,375 685,104 77,418 10,588 4,728,353
42. Atlas America - Series 23 9,644,550 620,341 68,901 10,279 3,737,295
43. Atlas America - Public #11-2002 31,178,145 1,701,481 184,281 59,632 10,729,233
44. Atlas America - Series 24-2003 (A) 14,363,955 543,251 64,233 6,895 3,699,005
45. Atlas America - Series 24-2003 (B) 20,542,850 764,586 80,812 6,047 6,250,269
46. Atlas America - Public #12-2003 (5) 40,170,308 946,434 109,891 42,644 7,342,059
47. Atlas America Series # 25-2004 (A) (5) 27,601,053 283,304 27,154 10,866 2,548,737
48. Atlas America Series # 25-2004 (B) (5) 31,531,035 141,124 17,404 11,268 918,390
49. Atlas America Public # 14-2004 (5) 52,506,570 0 0 0 0
50. Atlas America Public # 14-2005 (A) (5) 6,974,900 0 0 0 0
Present Value of
Estimated Future Estimated Future Net
Latest Quarterly Net Cash Flows from Cash Flows from Proved
Cash Cash Distribution Proved Reserves as of Reserves Discounted at 10%
Partnership Return(4) As of Date of Table January 1, 2005(8)(9) as of January 1, 2005(8)(10)
- ------------------------------------------- ----------- ------------------- --------------------- ----------------------------
1. Atlas L.P. #1 - 1985 272% $ 17,359 (7) (7)
2. A.E. Partners 1986 124% 14,999 (7) (7)
3. A.E. Partners 1987 109% 8,111 (7) (7)
4. A.E. Partners 1988 117% 8,452 (7) (7)
5. A.E. Partners 1989 164% 9,794 (7) (7)
6. A.E. Partners 1990 148% 18,121 (7) (7)
7. A.E. Nineties - 10 91% 31,138 2,190,991 1,073,724
8. A.E. Nineties - 11 149% 12,336 585,386 295,603
9. A.E. Partners 1991 163% 20,096 (7) (7)
10. A.E. Nineties - 12 98% 29,002 1,690,557 843,479
11. A.E. Nineties - JV 92 114% 55,890 3,469,888 1,686,351
12. A.E. Partners 1992 156% 11,620 (7) (7)
13. A.E. Nineties - Public #1 83% 37,007 1,742,165 928,742
14. A.E. Nineties - 1993 Ltd. 60% 13,575 921,133 513,309
15. A.E. Partners 1993 158% 12,905 (7) (7)
16. A.E. Nineties - Public #2 72% 43,109 2,475,212 1,218,558
17. A.E. Nineties - 14 63% 87,949 5,466,413 2,808,653
18. A.E. Partners 1994 133% 27,840 (7) (7)
19. A.E. Nineties - Public #3 71% 77,467 3,483,439 1,809,823
20. A.E. Nineties - 15 73% 149,558 9,507,215 4,661,659
21. A.E. Partners 1995 66% 5,480 (7) (7)
22. A.E. Nineties - Public #4 50% 78,770 3,885,292 2,041,671
23. A.E. Nineties - 16 54% 155,584 9,072,445 4,305,658
24. A.E. Partners 1996 70% 13,064 (7) (7)
25. A.E. Nineties - Public #5 51% 92,832 5,281,117 2,727,635
26. A.E. Nineties - 17 62% 148,063 9,543,628 4,534,846
27. A.E. Nineties - Public #6 62% 170,253 9,322,519 4,744,130
28. A.E. Partners 1997 81% 17,264 (7) (7)
29. A.E. Nineties - 18 55% 181,436 9,923,043 4,988,209
30. A.E. Nineties - Public #7 40% 142,101 6,147,494 3,322,893
31. A.E. Partners 1998 69% 38,590 (7) (7)
32. A.E. Nineties - 19 45% 258,884 12,079,259 6,010,035
33. A.E. Nineties - Public #8 47% 167,500 6,758,460 3,708,893
34. A.E. Partners 1999 82% 9,968 (7) (7)
35. 1999 Viking Resources LP 147% 217,145 (7) (7)
36. Atlas America - Series 20 73% 480,893 20,506,888 10,379,405
37. Atlas America - Public #9 53% 407,250 12,948,489 7,085,881
38. Atlas America - Series 21-A 46% 364,024 14,489,528 7,269,656
39. Atlas America - Series 21-B 40% 435,478 17,509,490 8,901,138
40. Atlas America - Public #10 45% 632,303 18,448,176 10,296,772
41. Atlas America - Series 22 47% 338,405 11,896,400 6,328,173
42. Atlas America - Series 23 39% 298,761 8,490,290 4,859,947
43. Atlas America - Public #11-2002 34% 1,138,706 26,604,847 15,675,979
44. Atlas America - Series 24-2003 (A) 26% 628,696 13,621,672 7,706,817
45. Atlas America - Series 24-2003 (B) 30% 1,096,602 25,605,612 14,929,026
46. Atlas America - Public #12-2003 (5) 18% 2,256,239 43,301,298 26,619,307
47. Atlas America Series # 25-2004 (A) (5) 9% 1,423,830 36,118,156 22,324,624
48. Atlas America Series # 25-2004 (B) (5) 3% 633,704 28,790,262 18,105,519
49. Atlas America Public # 14-2004 (5) 0% 0 17,414,152 11,173,874
50. Atlas America Public # 14-2005 (A) (5) 0% 0 (7) (7)
44
- ----------
(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.
45
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
Latest
Managing Quarterly Cash
General Total Costs Cash Distribution
Partner --------------------------------- Distributions Cash As of
Partnership Capital Operating(3) Admin. Direct (1) Return Date of Table
- ------------------------------------------- ------------ ------------ --------- -------- ------------- ------ --------------
1. Atlas L.P. #1 - 1985 $ 114,800 $ 43,623 $ 8,917 $ 2,737 $ 307,069 267% $ 3,306
2. A.E. Partners 1986 120,400 34,771 14,419 2,572 146,370 122% 2,857
3. A.E. Partners 1987 158,269 52,817 18,480 3,972 223,728 141% 2,339
4. A.E. Partners 1988 135,450 49,531 19,831 3,958 229,754 170% 2,722
5. A.E. Partners 1989 120,731 32,924 14,530 2,728 271,730 225% 2,150
6. A.E. Partners 1990 244,622 75,647 0 0 385,969 158% 7,020
7. A.E. Nineties - 10 484,380 161,297 0 0 705,893 146% 11,780
8. A.E. Nineties - 11 268,003 78,742 45,372 23,935 474,677 177% 5,287
9. A.E. Partners 1991 318,063 68,360 0 0 495,967 156% 8,007
10. A.E. Nineties - 12 791,833 206,663 44,394 31,703 919,293 116% 12,429
11. A.E. Nineties - JV 92 1,414,917 406,328 83,070 30,156 1,294,467 91% 27,528
12. A.E. Partners 1992 176,100 38,661 0 0 926,593 526% 4,617
13. A.E. Nineties - Public #1 528,934 163,480 33,534 27,860 713,398 135% 11,686
14. A.E. Nineties - 1993 Ltd. 1,264,183 249,833 49,088 22,985 491,301 39% 5,818
15. A.E. Partners 1993 219,600 50,875 0 0 376,907 172% 4,951
16. A.E. Nineties - Public #2 587,340 163,652 29,865 28,099 578,428 98% 12,607
17. A.E. Nineties - 14 3,584,027 777,520 148,960 33,548 1,879,681 52% 43,318
18. A.E. Partners 1994 231,500 52,564 0 0 406,624 176% 10,567
19. A.E. Nineties - Public #3 928,546 284,112 54,104 34,344 1,289,478 139% 25,017
20. A.E. Nineties - 15 3,435,936 687,166 131,003 42,322 2,465,993 72% 64,096
21. A.E. Partners 1995 244,725 30,253 0 0 139,873 57% 2,316
22. A.E. Nineties - Public #4 1,287,752 322,248 59,248 34,637 953,901 74% 26,257
23. A.E. Nineties - 16 1,643,320 379,459 63,893 23,041 1,173,021 71% 41,304
24. A.E. Partners 1996 367,416 42,961 0 0 201,551 55% 5,094
25. A.E. Nineties - Public #5 1,654,740 323,548 58,871 39,791 1,011,587 61% 29,471
26. A.E. Nineties - 17 2,113,947 384,596 64,256 29,206 1,777,474 84% 53,383
27. A.E. Nineties - Public #6 1,950,345 413,037 68,468 48,030 1,879,958 96% 56,751
28. A.E. Partners 1997 231,050 25,019 0 0 139,387 60% 6,229
29. A.E. Nineties - 18 3,448,751 634,258 100,286 10,333 2,599,785 75% 83,434
30. A.E. Nineties - Public #7 3,812,150 541,509 82,108 30,686 1,149,666 30% 63,842
31. A.E. Partners 1998 756,360 76,884 0 0 402,162 53% 14,199
32. A.E. Nineties - 19 4,776,598 726,407 109,713 8,416 2,673,972 56% 107,346
33. A.E. Nineties - Public #8 3,148,181 435,831 66,350 34,669 1,851,700 59% 42,311
34. A.E. Partners 1999 196,500 15,519 0 0 125,539 64% 3,996
35. 1999 Viking Resources LP 1,678,038 450,545 0 61,664 2,191,236 131% 38,457
36. Atlas America - Series 20 6,297,945 1,006,910 96,825 72,816 4,869,790 77% 180,179
37. Atlas America - Public #9 6,256,271 697,239 73,635 31,275 3,051,977 49% 170,788
38. Atlas America - Series 21-A 4,535,799 566,758 67,081 6,629 2,782,325 61% 186,141
39. Atlas America - Series 21-B 6,442,761 705,616 79,593 6,688 3,330,063 52% 224,337
40. Atlas America - Public #10 7,227,432 778,112 88,347 33,122 4,161,499 58% 297,556
41. Atlas America - Series 22 3,481,591 330,317 36,432 5,105 2,116,577 61% 163,159
42. Atlas America - Series 23 3,214,850 291,931 32,424 4,837 1,618,168 50% 140,596
43. Atlas America - Public #11-2002 13,295,226 876,520 94,933 30,720 4,938,692 37% 617,343
44. Atlas America - Series 24-2003 (A) 4,949,143 263,118 31,111 3,339 1,487,060 30% 316,469
45. Atlas America - Series 24-2003 (B) 7,300,020 380,346 40,200 3,008 2,563,706 35% 557,543
46. Atlas America - Public #12-2003 (2) 13,708,076 454,445 52,766 20,476 2,442,042 18% 1,214,898
47. Atlas America Series # 25-2004 (A) (2) 10,266,771 152,548 14,621 5,851 605,719 6% 766,678
48. Atlas America Series # 25-2004 (B) (2) 16,006,953 75,990 9,371 6,068 153,292 1% 341,225
49. Atlas America Public # 14-2004 (2) 25,971,721 0 0 0 0 0% 0
50. Atlas America Public # 14-2005 (A) (2) (4) 0 0 0 0 0% 0
46
- ----------
(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 # 3 ($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 1st Year
Investor Tax Tax 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 Cash Dist. Percent of Cash
Distribution And Tax Dist. And Tax
As of Date of Savings Savings to Date
Partnership Total Table (5) (6) (5) (6) (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%
48
- ----------
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.
49
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.
50
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 March 31,
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. 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., the parent of Atlas Energy
Group, Inc., receiving shares of Atlas America's common stock
in return;
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.
51
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.
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 45 Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons 46 Executive Vice President - Operations and a Director
Jack L. Hollander 48 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 49 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 44 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
52
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.
FRANK P. CAROLAS. Executive Vice President - Land and Geology and a Director
since January 2001. Mr. Carolas has been an Executive Vice President of Atlas
America since January 2001 and served as a Director of Atlas America from
January 2002 until February 2004. Mr. Carolas was a Vice President of Resource
America from April 2001 until May 2004 when he resigned from Resource America.
Mr. Carolas served as Vice President of Land and Geology for the managing
general partner from July 1999 until December 2000 and for Atlas America from
1998 until December 2000. Before that Mr. Carolas served as Vice President of
Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent
company of the managing general partner. Mr. Carolas is a certified petroleum
geologist and has been with the managing general partner and its affiliates
since 1981. He received a Bachelor of Science degree in Geology from
Pennsylvania State University in 1981 and is an active member of the American
Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of
his professional time to the business and affairs of the managing general
partner and Atlas America.
JEFFREY C. SIMMONS. Executive Vice President - Operations and a Director since
January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America
since January 2001 and was a Director of Atlas America from January 2002 until
February 2004. Mr. Simmons was a Vice President of Resource America from April
2001 until May 2004 when he resigned from Resource America. Mr. Simmons served
as Vice President of Operations for the managing general partner from July 1999
until December 2000 and for Atlas America from 1998 until December 2000. Mr.
Simmons joined Resource America in 1986 as a senior petroleum engineer and has
served in various executive positions with its energy subsidiaries since then.
Before Mr. Simmons' career with Resource America, he had worked with Core
Laboratories, Inc., of Dallas, Texas, and PNC Bank of Pittsburgh. Mr. Simmons
received his Petroleum Engineering degree from Marietta College in 1981 and his
Masters degree in Business Administration from Ashland University in 1992. Mr.
Simmons devotes approximately 80% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates, primarily Viking Resources and Resource Energy.
JACK L. HOLLANDER. Senior Vice President - Direct Participation Programs since
January 2002 and before that he served as Vice President - Direct Participation
Programs from January 2001 until December 2001. Mr. Hollander also serves as
Senior Vice President - Direct Participation Programs of Atlas America since
January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak,
concentrating in tax matters and real estate transactions, from 1990 to January
2001, and served as in-house counsel for Integrated Resources, Inc. (a
diversified financial services company) from 1982 to 1990. Mr. Hollander earned
a Bachelor of Science degree from the University of Rhode Island in 1978, his
law degree from Brooklyn Law School in 1981, and a Master of Law degree in
Taxation from New York University School of Law Graduate Division in 1982. Mr.
Hollander is a member of the New York State bar 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.
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
53
until May 2004 when he resigned from Resource America. Mr. Staines was a
director of Resource America from 1989 to February 2000 and Secretary from 1989
to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP
since January 2001 and its Chief Operating Officer and a member of its Managing
Board since its formation in November 1999. Mr. Staines is a member of the Ohio
Oil and Gas Association and the Independent Oil and Gas Association of New York.
Mr. Staines received a Bachelor of Science degree from Cornell University in
1971 and a Master of Business degree from Drexel University in 1977. Mr. Staines
will devote approximately 5% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates, including Atlas Pipeline Partners GP.
MICHAEL G. HARTZELL. Vice President - Land Administration since September 2001.
Mr. Hartzell has been Vice President - Land Administration of Atlas America
since January 2002, and before that served as Senior Land Coordinator from
January 1999 to January 2002. Mr. Hartzell has been with the managing general
partner and its affiliates since 1980 when he began his career as a land
department representative. Mr. Hartzell manages all Land Department functions.
Mr. Hartzell serves on the Environmental Committee of the Independent Oil and
Gas Association of Pennsylvania and is a past Chairman of the Committee. Mr.
Hartzell devotes approximately 100% of his professional time to the business and
affairs of the managing general partner and Atlas America.
DONALD R. LAUGHLIN. Vice President - Drilling and Production since September
2001. Mr. Laughlin also serves as Vice President - Drilling and Production for
Atlas America since January 2002, and before that served as Senior Drilling
Engineer since May 2001 when he joined Atlas America. Mr. Laughlin has over
thirty years of experience as a petroleum engineer in the Appalachian Basin,
having been employed by Columbia Gas Transmission Corporation from October 1995
to May 2001 as a senior gas storage engineer and team leader, Cabot Oil & Gas
Corporation from 1989 to 1995 as Manager of Drilling Operations and Technical
Services, Doran & Associates, Inc. (an industrial engineering firm) from 1977
until 1989 as Vice President--Operations, and Columbia Gas from 1970 to 1977 as
Drilling Engineer and Gas Storage Engineer. Mr. Laughlin received his Petroleum
Engineering degree from the University of Pittsburgh in 1970. He is a member of
the Society of Petroleum Engineers. Mr. Laughlin devotes approximately 100% of
his professional time to the business and affairs of the managing general
partner and Atlas America.
MARCI F. BLEICHMAR. Vice President of Marketing since February 2001. Ms.
Bleichmar also serves as Vice President of Marketing for Atlas America since
February 2001 and was with Resource America from February 2001 until May 2004
when she resigned from Resource America. From March 2000 until February 2001,
Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a
mutual fund manager), and from March 1998 until March 2000, she was an account
executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms.
Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms.
Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in
1992. Ms. Bleichmar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.
SHERWOOD S. LUTZ. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined
Viking Resources, which was purchased by Resource America in 1999 as senior
geologist. Since 1999 Mr. Lutz has been a senior geologist for the managing
general partner and Atlas America. Mr. Lutz received his Bachelor of Science
degree in Geological Sciences from the Pennsylvania State University in 1973.
Mr. Lutz is a certified petroleum geologist with the American Association of
Petroleum Geologists as well as a licensed professional geologist in
Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to
the business and affairs of the managing general partner and Atlas America.
MICHAEL W. BRECKO. Director of Energy Sales since November 2002. Mr. Brecko has
over 16 years of natural gas marketing experience in the oil and natural gas
industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University
with a Bachelor of Science degree in Civil Engineering. His career in natural
gas marketing began when he joined Equitable Gas Company, a local distribution
company, as a marketing representative in the commercial/ industrial marketing
division from May 1986 to August 1992. He subsequently joined O&R Energy, a
subsidiary of Orange and Rockland Utilities, as regional marketing manager from
August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr.
Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and
natural gas producer, as an account executive and he was promoted in August 1998
to natural gas trader. In November 2001, he joined Sprague Energy
54
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.
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 45 Executive Vice President
Freddie M. Kotek 49 Executive Vice President
Jeffrey C. Simmons 46 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 34 Vice Chairman
Carlton M. Arrendell 43 Director
William R. Bagnell 42 Director
Donald W. Delson 54 Director
Nicholas DiNubile 52 Director
Dennis A. Holtz 65 Director
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.
55
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
---------------------------------
Atlas America, Inc. (Delaware)
(driller and operator in Ohio)(1)
---------------------------------
|
______________________________________________________________________________________________________
| | | | | |
| | | | | |
- ------------------- ------------ ------------------- ---------------- --------------- ------------
Viking AIC, Inc. Atlas America, Inc. Resource Atlas Noble AED
Resources ------------ (Pennsylvania) Energy, Inc. (2) Corporation (2) Investments,
Corporation (2) | (operating company) ---------------- --------------- Inc. (1)
- ------------------- | ------------------- ------------
| |____________________________________________________________________________________
| | | | |
| | | | |
- ------------------- --------------------------------- --------------------------- --------------- -------------------
Atlas Pipeline Atlas Resources, Inc., managing Atlas Energy Corporation, Pennsylvania Anthem Securities,
Partners, GP, general partner of Atlas America managing general partner of Industrial Inc., registered
LLC Public #15-2005 Program, driller exploratory drilling Eneergy, Inc. broker/dealer and
- ------------------- and operator in Pennsylvania partnerships and driller --------------- dealer-manager
| --------------------------------- and operator -------------------
| | ---------------------------
- ------------------- |
Atlas Pipeline ---------------------
Partners, LP ARD Investments, Inc.
- ------------------- ---------------------
|
|
- -------------------
Atlas Pipeline
Operating
Partnership, L.P.
- -------------------
- ----------
(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.
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.
56
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. and
Atlas America Public #15-2006(C) 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.
57
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.
58
Although the majority of the wells will be classified as natural gas wells,
which may produce a small amount of oil, some of the wells, such as those in
McKean County, Pennsylvania, may be classified as oil or combination oil and
natural gas wells.
Each partnership will be a separate business entity from the other partnerships,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest.
Each partnership generally will drill different wells, but they may own working
interests and participate in drilling and completing one or more of the same
wells. The number of wells to be drilled by a partnership cannot be determined
precisely before the funding of 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 of the wells which are
paid 100% by you and the other investors in the partnership,
and any cost overruns for equipment costs which are paid by
you and the other investors in the partnership which will not
exceed an amount equal to 10% of the partnership's
subscription proceeds.
For the estimated number of wells to be drilled at the minimum subscription
proceeds of $2 million and the maximum subscription proceeds of $150,000,000 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 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
59
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. or Atlas America Public #15-2006(C) L.P. by a supplement or an amendment to
the registration statement of which this prospectus is a part.
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. 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.
Fayette County, Greene County and Westmoreland County, as well as Armstrong
County and McKean County, are in western Pennsylvania. The Clinton/Medina
geological formation in Pennsylvania and Ohio is the same geological formation,
although in Pennsylvania it is often referred to as the Medina/Whirlpool
geological formation. For purposes of this prospectus, the term Clinton/Medina
geological formation is used for both Ohio and Pennsylvania. The wells drilled
to the Clinton/Medina geological formation, regardless of whether they are
situated in western Pennsylvania, eastern Ohio, western New York, or southern
Ohio, the Mississippian and/or Upper Devonian Sandstone reservoirs and the
Mississippian (carbonates) and Devonian Shale reservoirs in north central
Tennessee 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
60
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.
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 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, which also includes
an area in eastern Ohio primarily in Stark, Mahoning, Trumbull, and Portage
Counties.
The wells in the Clinton/Medina geological formation in western Pennsylvania and
eastern Ohio will be:
o primarily situated in Crawford, Mercer, Lawrence, Warren, and
Venango Counties, Pennsylvania, and Stark, Mahoning, Trumbull
and Portage Counties, Ohio;
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;
61
o drilled from approximately 5,100 to 6,300 feet in depth;
o classified as natural gas wells which may produce a small
amount of oil, although the wells in eastern Ohio may be
classified as oil wells; and
o primarily connected to the gathering system owned by Atlas
Pipeline Partners and have their natural gas production
primarily marketed to 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
62
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."
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. The secondary areas anticipated by the managing
general partner are discussed below.
CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN NEW YORK. Wells located in
western New York and drilled to the Clinton/Medina geological formation will be:
o primarily situated in Chautauqua County;
o situated on approximately 40 acres, subject to adjustment to
take into account lease boundaries;
o drilled from approximately 3,800 to 4,000 feet in depth;
o drilled on leases with a net revenue interest of approximately
84.375% to 87.5%;
o classified as natural gas wells which may produce a small
amount of oil; and
o connected to the gathering system owned by Atlas Pipeline
Partners and have their natural gas production primarily
marketed to Amerada Hess Corporation as described below,
and/or commercial end users in the
63
area, although a portion of the natural gas production may be
gathered and marketed by Great Lakes Energy Partners, L.L.C.
as described below in "- Sale of Natural Gas and Oil
Production."
CLINTON/MEDINA GEOLOGICAL FORMATION IN SOUTHERN OHIO. Wells located in southern
Ohio and drilled to the Clinton/Medina geological formation will be:
o primarily situated in Noble, Washington, Guernsey, and
Muskingum Counties;
o situated on approximately 40 acres, subject to adjustment to
take into account lease boundaries;
o drilled at least 1,000 feet from each other;
o drilled from approximately 4,900 to 6,500 feet in depth;
o drilled on leases with a net revenue interest of approximately
82.5% to 87.5%;
o classified as either natural gas wells or oil wells; and
o primarily connected to the gathering system owned by Atlas
Pipeline Partners if classified as natural gas wells and have
their natural gas production primarily marketed by 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.
64
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 prospects to be drilled by each partnership.
The managing general partner and its affiliates are continually engaged in
acquiring additional leasehold acreage in Pennsylvania, Ohio, and other areas of
the United States. As of September 30, 2004, the managing general partner's and
its affiliates' undeveloped leasehold acreage was as follows:
UNDEVELOPED LEASE ACREAGE
-----------------------------
GROSS NET (1)
------- --------
Kentucky...................................... 9,710 4,855
Montana....................................... 2,650 2,650
New York...................................... 37,365 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. 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.
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INTERESTS OF PARTIES
Generally, production and revenues from a well drilled by a partnership will be
net of the applicable landowner's royalty interest, which is typically 1/8th
(12.5%) of gross production, and any interest in favor of third-parties such as
an overriding royalty interest. Landowner's royalty interest generally means an
interest that is created in favor of the landowner when an oil and gas lease is
obtained; and overriding royalty interest generally means an interest that is
created in favor of someone other than the landowner. In either case, the owner
of the interest receives a specific percentage of the natural gas and oil
production free and clear of all costs of development, operation, or maintenance
of the well. This is compared with a working interest, which generally means an
interest in the lease under which the owner of the interest must pay some
portion of the cost of development, operation, or maintenance of the well. Also,
the leases will be subject to terms that are customary in the industry such as
free gas to the landowner-lessor for home heating requirements, etc.
The managing general partner anticipates that each partnership generally will
have a net revenue interest in its leases in its primary drilling areas as set
forth in the chart below. Net revenue interest generally means the percentage of
revenues the owner of an interest in a well is entitled to receive under the
lease. The following chart expresses the percentage of production revenues that
the managing general partner, the landowner, other third-parties, and you and
the other investors in a partnership will share in from the wells in three of
the five primary proposed areas. The fourth and fifth primary proposed 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.
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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 the
managing general partner's minimum required capital contribution to
each partnership of 25% and capital contributions of 75% from you and
the other investors. The actual percentages are likely to be different
because they will be based on the actual capital contributions of the
managing general partner and you and the other investors. However, the
managing general partner's total revenue share may not exceed 40% of
partnership revenues regardless of the amount of its capital
contributions.
(2) It is possible that the wells could have a net revenue interest to a
partnership as low as 84.375% which would reduce the investors'
interest to 57.375% 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 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 Anderson,
Campbell, Morgan, Roane and Scott Counties, Tennessee will have a net revenue
interest to a partnership ranging from 83.4375% to 81.875%. The amount of the
partnership's net revenue interest is described in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #15-2005(A) L.P.
- - Lease Information for Anderson, Campbell, Morgan Roane and Scott Counties,
Tennessee." However, the amount of the partnership's net revenue interest in
some of the proposed prospects could be as low as 81.375%, which depends on
whether the landowner royalty interest is 12.5% or 15.5%, which in turn depends
on whether the natural gas produced from those proposed 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
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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 the
secondary areas described above, there is no minimum net revenue interest that a
partnership is required to own before drilling a well in other areas of the
United States. The leases in these other areas may be subject to interests in
favor of third-parties that are not currently known such as 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.")
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
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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.
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
69
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."
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," the
managing general partner has five primary areas where it will drill and in each
area it is initially anticipated that the managing general partner will sell its
natural gas to a different purchaser. 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 any 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. 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
70
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 use 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.
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.
71
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.
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
72
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.
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
73
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;
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
74
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 energy bill supported by the
President and currently under consideration in Congress includes incentives,
such as tax breaks and loan guarantees, 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.
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.
75
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.
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.
76
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:
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 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.
77
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. 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 administrative overhead
reimbursement and profit on those costs.
78
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.
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
79
revenues to recoup previous subordination distributions to the extent your cash
distributions from that partnership exceed the 10% return of capital described
above. The specific formula is set forth in Section 5.01(b)(4)(a) of the
partnership agreement.
The managing general partner anticipates that you will benefit from the
subordination if the price of natural gas and oil received by the partnership
and/or the results of the partnership's drilling activities are unable to
provide the required return 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.
(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.
80
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.
(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.
81
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;
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:
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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.
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.
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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.
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
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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:
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
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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.
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
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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.
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.
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(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:
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
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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.
(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;
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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."
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.
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CONFLICTS REGARDING PRESENTMENT FEATURE
You and the other investors in a partnership have the right to present your
units in the partnership to the managing general partner for purchase beginning
with the fifth calendar year after the end of the calendar year in which your
partnership closes. This creates the following conflicts of interest between you
and the managing general partner.
o The managing general partner may suspend the presentment
feature if it does not have the necessary cash flow or it
cannot borrow funds for this purpose on terms which it deems
reasonable. Both of these determinations are subjective and
will be made in the managing general partner's sole
discretion.
o The managing general partner will also determine the purchase
price based on a reserve report that it prepares and is
reviewed by an independent expert that it chooses. The formula
for arriving at the purchase price has many subjective
determinations that are within the discretion of the managing
general partner.
CONFLICTS REGARDING MANAGING GENERAL PARTNER WITHDRAWING AN INTEREST
A conflict of interest is created with you and the other investors by the
managing general partner's right to mortgage its interest or withdraw an
interest in each partnership's wells equal to or less than its revenue interest,
subject to a 1% participation as managing general partner, to be used as
collateral for a loan to the managing general partner. If there was a default
under the loan, this could reduce or eliminate the amount of the managing
general partner's partnership net production revenues available for its
subordination obligation to you and the other investors. Also under certain
circumstances, if the managing general partner made a subordination distribution
to you and the other investors after a default under the loan, then the lender
may be able to recoup that subordination distribution from you and the other
investors.
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.
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(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;
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.
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(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:
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.
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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
Sections 4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of the
partnership agreement;
o manage multiple programs simultaneously; and
o be indemnified and held harmless as described below in "-
Limitations on Managing General Partner Liability as
Fiduciary."
Other than as set forth above, the partnership agreement does not excuse the
managing general partner from liability or provide it with any defense for
breach of its fiduciary duty. The fiduciary duty owed by the managing general
partner to the partnership is analogous to the fiduciary duty owed by directors
to a corporation and its stockholders, 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;
94
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.
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. 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.")
DISCLOSURES
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.
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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, for the purpose of establishing your
reasonable belief that your tax treatment of any partnership
tax item on your federal income tax returns was more likely
than not the proper treatment in order to avoid any reportable
transaction understatement penalty under Section 6662A of the
Internal Revenue Code (the "Code") that may be imposed on you.
o The tax opinion letter is not confidential. There are no
limitations on the disclosure by a partnership or 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 a
Partnership Are Not Contractually Protected," in this
prospectus.)
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 from losing the money you invest
in a partnership through nonrecourse financing, guarantees,
stop loss agreements or other similar arrangements.
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 approximately 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 the
subscription proceeds of each partnership will be expended in
the year in which the units in that partnership are offered
for sale, and you and the other investors in your partnership
will include your share of that partnership's deduction for
intangible drilling costs on your personal federal income tax
returns for that year, subject to your right to elect to
capitalize
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and amortize over a 60-month period a portion or all of your
share of your partnership's deduction for intangible drilling
costs.
o None of Atlas America Public #15-2005(A) L.P.'s production of
natural gas and oil from its wells in 2005, if any, will
qualify for the marginal well production credit in 2005,
because natural gas and oil prices in 2004 were substantially
higher than the prices where the credit phases out completely.
o Depending primarily on when their respective 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 drilling activities that will begin in 2006, and
that Atlas America Public #15-2006(B) L.P. and/or Atlas
America Public #15-2006(C) L.P., may prepay in 2006 most, if
not all, of their respective intangible drilling costs for
drilling activities that will begin in 2007.
o Each partnership will have a calendar year taxable year.
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 also will qualify
for marginal well production credits depending on the
applicable reference prices for natural gas and oil in any
year. However, it may be many years, if ever, before the
natural gas and oil produced by any of the partnerships
qualifies for the marginal well production credit, depending
primarily on the applicable reference prices of natural gas
and oil.
o The principal purpose of each partnership is to locate,
produce and market natural gas and oil on a profitable basis
to you and the other investors, apart from tax benefits, as
discussed in this prospectus.
o Based primarily on its past experience, the managing general
partner believes that each partnership's total abandonment
losses under Section 165 of the Internal Revenue Code (the
"Code"), which could include, for example, the abandonment by
a partnership of wells drilled which are nonproductive (i.e. a
"dry hole"), or 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 each partnership and less than $4 million, in the
aggregate, during each 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 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
section of this tax opinion letter.)
(2) PASSIVE ACTIVITY CLASSIFICATION.
o The passive activity limitations on losses and
credits under Section 469 of the Code will apply to:
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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 as:
o passive activity income and gains which a Limited
Partner may use to offset a portion or all of any
passive activity losses, except passive activity
losses from a publicly traded partnership passive
activity; 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 from
passive income received by the Limited Partner from
the Partnership or net passive income received by the
Limited Partner from his other passive activities, if
any, except publicly traded partnership passive
activities.
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.
(See "- Limitations on Passive Activity Losses and Credits" and " -
Conversion from Investor General Partner to Limited Partner" in the
Summary Discussion section of this tax opinion letter.)
For a discussion of the types of entities whose investments in a
Partnership also will be subject to the passive activity limitations on
losses and credits, see the Summary Discussion "- Limitations on
Passive Activity Losses and Credits," below.
(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
section of this tax opinion letter.)
(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
syndication fees 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 personal 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 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;
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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 which are
entities which also are subject to the passive
activity limitations on losses and credits.
See "- Business Expenses," "- Tax Basis of Units," "- `At Risk'
Limitation For Losses," "- Alternative Minimum Tax" and "- Limitations
on Passive Activity Losses and Credits" in the Summary Discussion
section of the tax opinion letter.
(5) INTANGIBLE DRILLING COSTS. Although each partnership will elect to
deduct currently all Intangible Drilling Costs, each participant may
still elect to capitalize and deduct all or part of his share of his
partnership's Intangible Drilling Costs (other than drilling and
completion costs of a re-entry well which 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 section of
the tax opinion letter.)
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 deductions for 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 of 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 section of the
tax opinion letter.)
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:
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o may not exceed 100% of the participant's share of his
partnership's net 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.
See "- Depletion Allowance" in the Summary Discussion section of the
tax opinion letter.
(8) MACRS. Each partnership's reasonable costs for equipment placed in its
respective productive wells which cannot be deducted immediately
("Tangible Costs") will be eligible for cost recovery deductions under
the Modified Accelerated Cost Recovery System ("MACRS") over a seven
year "cost recovery period" 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 section of this tax opinion letter.)
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 section of the
tax opinion letter.)
(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
section of the tax opinion letter.)
(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 section of the tax
opinion letter.)
(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 Section 183 of the Code. Also, the IRS anti-abuse rule in Treas.
Reg.Section 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 section of the tax
opinion letter.)
(14) REPORTABLE TRANSACTIONS. The partnerships are not reportable
transactions under Section 6707A of the Code and Treasury Regulation
Section 1.6011-4(b), the participants in a partnership will not be
required to report to the IRS
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that the Partnership in which they invest is a reportable transaction
and they will not be subject to the penalty under Section 6707A of the
Code for not doing so, and the participants in a partnership will not
be subject to the reportable transaction understatement penalty under
Section 6662A of the Code with respect to their investment in a
partnership.
(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.
The primary reason we have reached this overall conclusion is that 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 this 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 the Summary Discussion "- Alternative Minimum Tax" section
of the tax opinion letter.
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.
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 since the managing
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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 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
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."
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 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,
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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 approximately 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.
Concurrently, the former investor general partner will become subject to the
passive activity rules 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 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
o not "ordinary and necessary" business expenses.
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In the event of an audit, payments to the managing general partner and its
affiliates by a partnership will be scrutinized by the IRS to a greater extent
than payments to an unrelated party.
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 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, in the taxable year your
partnership's wells are drilled and completed. For a discussion of the deduction
of prepaid intangible drilling costs in the year in which you invest in the
partnership, 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.")
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.
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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 all of the partnerships may prepay
in the year in which their units are offered for sale most, if not all, of their
respective intangible drilling costs for drilling activities that 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
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
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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:
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
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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. 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%.
Also, percentage depletion:
o may not exceed 100% of the net 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.
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 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 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 the case of a short
partnership tax year, the MACRS deduction is prorated on a 12-month basis. No
distinction is made between new and used property and salvage value is
disregarded. 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
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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. This credit, however, cannot be used under current law to reduce
alternative minimum taxes. (See "- Alternative Minimum Tax," below.) The credit
will be reduced proportionately for reference prices between $1.67 and $2.00 per
mcf for natural gas and $15 and $18 per barrel for oil. The applicable reference
price for a tax year is determined by the IRS based on the average price of
natural gas and oil in the previous calendar year.
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. Similarly, 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."
In this regard, the managing general partner has represented that 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 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. 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
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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 is still 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 passive income from the partnership in which you
invest or your net passive income from 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.
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 pay 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
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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
Section 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.
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 is 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 (excess of long-term
gains over long-term losses) over net short-term loss (excess of short-term
gains over short-term losses). The annual capital loss limitation for
noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000,
which is reduced to $1,500 for married persons filing separate returns, or the
excess of capital losses over capital gains.
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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.
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 "Section 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
"Section 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 Section 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 Section 751
assets which are subject to recapture as ordinary income as discussed above.
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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.
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.
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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 Different rules under the Code apply to incentive stock
options that may require earlier recognition of income.
The principal tax preference items that must be added to taxable income for
alternative minimum tax purposes include:
o excess intangible drilling costs, as discussed below; and
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 Section 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 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
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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
the partnership's early 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 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, the investor general partner's
share of the partnership's income and losses, including the deduction for
intangible drilling costs, will be considered to be investment income and
losses. Thus, for example, a loss allocated to an investor general partner from
the partnership in the year in which he invests in the partnership as a result
of the deduction for intangible drilling costs will reduce his net investment
income and may reduce or eliminate the deductibility of his investment interest
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.)
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 to you of income and gain; and
o decreased by the value of property or cash distributed to you
by the partnership and allocations to you of losses and
deductions.
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
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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 by the IRS, you may incur
a greater tax burden.
PARTNERSHIP BORROWINGS
Under the partnership agreement the managing general partner and its affiliates
may make loans to the partnerships. The use of partnership revenues taxable to
you to repay borrowings by your partnership could create income tax liability
for you in excess of your cash distributions from the partnership, since
repayments of principal are not deductible for federal income tax purposes. In
addition, interest on the loans will not be deductible unless the loans are bona
fide loans that will not be treated 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 and offering 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.
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 Section 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 Section 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 Section 754 election, although they
reserve the right to do so. Even if the partnerships do not make the Section 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
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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
limit the additional expense to a partnership if the mandatory basis adjustments
to a partnership's assets described above apply to it. In addition to the
Section 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
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. Also, the partners are required to treat
partnership items on their individual federal income tax returns in a manner
which is consistent with the treatment of the partnership items on the
partnership's federal information income tax return, unless they disclose to the
IRS that their tax treatment of partnership tax items on their personal federal
income tax return is different from their partnership's tax treatment of those
tax items. The IRS must conduct an administrative determination as to
partnership items at the partnership level before conducting deficiency
proceedings against a partner, and the partners must file a request for an
administrative determination before filing suit for any credit or refund. The
period for assessing tax against you and the other investors attributable to a
partnership item may be extended by agreement between the IRS and the managing
general partner, which will serve as each partnership's representative ("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. In this regard, the managing general partner
anticipates, based on its past experience, that there will be more than 100
investors in each of the partnerships. Also, by your execution of 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." These rules would help the IRS match
partnership tax items with its investors' personal federal income tax returns.
In addition, most limitations affecting the
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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 either partnership
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. Under the partnership agreement, however, the managing general
partner is not obligated to contest any adjustments made by the IRS to the
federal information income tax returns of any partnership, which also may be
binding on the partnership's investors for purposes of their personal federal
income tax returns. The managing general partner will notify you of any IRS
audits or other tax proceedings involving your partnership, and will provide you
any other information regarding the proceedings as may be required by the
partnership agreement or law.
TAX RETURNS. Your individual income tax returns are your responsibility. Each
partnership will provide its investors with the tax information applicable to
their investment in the partnership necessary to prepare their tax returns.
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 Section 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. Section 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 for the partnerships' proposed drilling areas in
"Proposed Activities," and 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).
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 Atlas America Public #15-2006(B) L.P. and
Atlas America Public #15-2006(C) L.P. when units in those partnership 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 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
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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
taxpayer may avoid this penalty if the understatement was not attributable to a
"tax shelter," and there 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 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
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, and the taxpayer reasonably believed that his or her
treatment of the item on the 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. Due to a lack of clear legal authorities, special
counsel is unable to give an opinion as to whether any of the partnerships has a
"significant" purpose of federal income tax avoidance as defined under the Code
for this purpose.
In addition, there is a 20% penalty for reportable transaction understatements
for any tax year. If the disclosure rules for reportable transactions are not
met, then 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. A
reportable transaction understatement is:
o the amount of the increase (if any) in taxable income
resulting from the proper tax treatment of a tax item subject
to this rule, as discussed below, instead of the taxpayer's
treatment of the tax item on the taxpayer's tax return,
multiplied by the highest noncorporate income tax rate (or
corporate income tax rate, in the case of a corporation); and
o the amount of the decrease (if any) in the aggregate amount of
credits resulting from a difference between the taxpayer's
treatment of a tax item subject to this rule, as discussed
below, and the proper tax treatment.
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 special counsel's opinion, the type of reportable transaction that appears
most likely to apply to the partnerships is a "loss transaction," which is a
reportable transaction if a partnership or any of its noncorporate partners
claims a loss under Section 165 of the Code of at least $2 million, in the
aggregate, in any taxable year or $4 million, in the aggregate, over the
partnership's first six years. Each partnership's deduction for intangible
drilling costs will exceed $2 million if subscription proceeds of approximately
$2,225,000 or more are received by that partnership. However, special counsel
has stated in its 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 Section 263(c) of the Code and Treasury
Regulation 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 reportable transactions under the Code. This
opinion is based in part on the managing general partner's representation, based
primarily on its past experience, that each partnership's total abandonment
losses under Section 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 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 a
partnership and less than $4 million, in the aggregate, during a 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 to you and the other investors in that partnership.
Deductions and credits, including the federal marginal well production credit,
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 will likely 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 will 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 would 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 personal
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 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,
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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.
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.
ESTATE AND GIFT TAXATION
There is no federal tax on lifetime or testamentary transfers of property
between spouses. The gift tax annual exclusion in 2005 is $11,000 per donee,
which will be adjusted in subsequent years for inflation. Under the Economic
Growth and Tax Relief Reconciliation Act of 2001 (the "2001 Tax Act"), the
maximum estate and gift tax rate of 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 were not previously used by the decedent to avoid gift taxes
on lifetime gifts in excess of the annual exclusion amount. 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 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 the net income of your partnership. 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 legislation on an
investment in a partnership and the status of legislative, regulatory or
administrative developments and proposals and their potential effect on you if
you invest 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
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o without the unanimous approval of all investors in
the partnership affect the classification of
partnership income and loss for federal income tax
purposes.
The managing general partner, its officers, directors, and affiliates may also
subscribe for units in each partnership on a discounted basis, and they may vote
on all matters other than:
o the issues set forth above concerning removing the managing
general partner and operator; and
o any transaction between the managing general partner or its
affiliates and the partnership.
Any units owned by the managing general partner and its affiliates will not be
included in determining the requisite number of units necessary to approve any
partnership matter on which the managing general partner and its affiliates may
not vote or consent.
ACCESS TO RECORDS
You will have access to all records of your partnership at any reasonable time
on adequate notice. However, logs, well reports, and other drilling and
operating data may be kept confidential for reasonable periods of time. Your
ability to obtain the list of investors is subject to additional requirements
set forth in the partnership agreement.
WITHDRAWAL OF MANAGING GENERAL PARTNER
After 10 years the managing general partner may voluntarily withdraw as managing
general partner of a partnership for any reason by giving 120 days' written
notice to you and the other investors in the partnership. Although the
withdrawing managing general partner is not required to provide a substitute
managing general partner, a new managing general partner may be substituted by
the affirmative vote of investors whose units equal a majority of the total
units in the partnership. If the investors, however, choose not to continue the
partnership and select a substitute managing general partner, then the
partnership would terminate and dissolve which could result in adverse tax and
other consequences to you.
Also, subject to a required participation of not less than 1% of each
partnership's revenues, the managing general partner may withdraw a property
interest in the form of a working interest in the partnership's wells equal to
or less than its revenue interest if the withdrawal is:
o to satisfy the bona fide request of its creditors; or
o approved by investors in the partnership whose units equal a
majority of the total units.
RETURN OF SUBSCRIPTION PROCEEDS IF FUNDS ARE NOT INVESTED IN TWELVE MONTHS
Although the managing general partner anticipates that each partnership will
spend all of its subscription proceeds soon after the offering of the
partnership closes, each partnership will have 12 months in which to use or
commit funds to drilling activities. If within the 12-month period the
partnership has not used or committed for use all the subscription proceeds,
then the managing general partner will distribute the remaining subscription
proceeds to you and the other investors in the partnership in accordance with
your subscription proceeds as a return of capital.
SUMMARY OF DRILLING AND OPERATING AGREEMENT
The managing general partner will serve as the operator under the drilling and
operating agreement, Exhibit (II) to the partnership agreement. The operator may
be replaced at any time on 60 days' advance written notice by the managing
general partner acting on behalf of a partnership on the affirmative vote of
investors whose units equal a majority of the total units in the partnership.
You are urged 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.
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The drilling and operating agreement includes a number of material provisions,
including, without limitation, those set forth below.
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 Section 4.04(a)(2)(c) of the partnership agreement
and that the
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total amount of costs allocated did not materially
exceed the amounts actually incurred by the managing
general partner.
If the managing general partner subsequently decides
to allocate expenses in a manner different from that
described in Section 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
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o cannot borrow funds for this purpose on terms it deems
reasonable.
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.Section 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 the number of
your units bears to the total number of units in your partnership. The
presentment price will include the sum of the following partnership items:
o an amount based on 70% of the present worth of future net
revenues from the proved reserves determined as described
above;
o cash on hand;
o prepaid expenses and accounts receivable, less a reasonable
amount for doubtful accounts; and
o the estimated market value of all assets not separately
specified above, determined in accordance with standard
industry valuation procedures.
There will be deducted from the foregoing sum the following items:
o an amount equal to all debts, obligations, and other
liabilities, including accrued expenses; and
o any distributions made to you between the date of the request
and the actual payment. However, if any cash distributed,
after the presentment request, was derived from the sale of
oil, natural gas, or a producing
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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.
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.
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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:
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
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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
128
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.
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, although not anticipated, if the dealer-manager assists
in the transfer of units then it will comply with Rule 2810(b)(3)(D) of the NASD
Conduct Rules.
Subject to the following, you and the other investors will pay $10,000 per unit
and generally will share costs, revenues, and distributions in the partnership
in which you invest in proportion to your respective number of units. However,
the subscription price for certain investors will be reduced as set forth below:
129
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";
o a brochure entitled "The Drilling Process"; and
130
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.
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,
131
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.
132
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 audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. The Partnership is not
required to have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included consideration of internal
control over financial reporting as a basis for designing audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Partnership's internal control over
financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial 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
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 $150,000,000) 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 provider 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 at $75 per well per month, which will be
proportionately reduced if the partnership's working interest in a well is
less than 100%.
Atlas Resources will receive well supervision fees for operating and
maintaining the wells during producing operations at a competitive rate
(currently the competitive rate is $285 per well per month in the primary
and secondary drilling areas). The well supervision fees will be
proportionately reduced if the partnership's working interest in a well is
less than 100%.
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 10% per unit, based on $10,000 per
unit regardless of the actual price paid, determined on a cumulative basis,
in each of the first five 12-month periods beginning with 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 and facilities...................................... 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
MARCH 31, 2005
F-27
ATLAS RESOURCES , INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
MARCH 31, SEPTEMBER 30,
2005 2004
------------- -------------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents ................................................... $ 2,842 $ 242
Accounts receivable ......................................................... 7,231 7,080
Prepaid expenses ............................................................ 1,993 1,488
------------- -------------
Total current assets ...................................................... 12,066 8,810
Property and equipment:
Oil and gas properties and equipment (successful efforts) .................. 150,924 120,506
Buildings and land ......................................................... 2,994 2,947
Other ...................................................................... 378 368
------------- -------------
154,296 123,821
Less - accumulated depreciation, depletion and amortization .................... (28,088) (23,654)
------------- -------------
Net property and equipment ................................................. 126,208 100,167
Goodwill (net of accumulated amortization of $2,320) ........................... 20,868 20,868
Intangible assets (net of accumulated amortization of $3,147 and $2,909) ....... 3,206 3,444
------------- -------------
$ 162,348 $ 133,289
============= =============
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt ........................................... $ 58 $ 56
Accounts payable ............................................................ 5,423 5,304
Liabilities associated with drilling contracts .............................. 23,060 29,375
Accrued liabilities ......................................................... 4,601 3,174
Advances and note from Parent ............................................... 98,013 66,725
------------- -------------
Total current liabilities ................................................. 131,155 104,634
Asset retirement obligations ................................................... 3,653 1,910
Long-term debt ................................................................. 52 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 .................................................. 16,505 16,505
Retained earnings ........................................................... 10,981 10,156
------------- -------------
Total stockholder's equity ................................................ 27,488 26,663
------------- -------------
$ 162,348 $ 133,289
============= =============
See accompanying notes to consolidated financial statements
F-28
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
SIX MONTHS ENDED MARCH 31, 2005 AND 2004
(UNAUDITED)
2005 2004
------------- -------------
(in thousands)
REVENUES
Well drilling .................................................................. $ 72,009 $ 48,207
Gas and oil production ......................................................... 14,613 10,456
Well services .................................................................. 2,513 1,939
Transportation ................................................................. 1,162 1,259
Other income ................................................................... 62 42
------------- -------------
90,359 61,903
COSTS AND EXPENSES
Well drilling .................................................................. 62,617 41,919
Gas and oil production and exploration ......................................... 1,558 1,963
Well services .................................................................. 951 573
Non-direct ..................................................................... 17,796 11,375
Depreciation, depletion and amortization ....................................... 4,766 3,925
Interest ....................................................................... 1,512 1,259
Other expense .................................................................. 152 (62)
------------- -------------
89,352 60,952
------------- -------------
Income from operations before income taxes ..................................... 1,007 951
Provision for income taxes ..................................................... 182 200
------------- -------------
Net income ..................................................................... $ 825 $ 751
============= =============
See accompanying notes to consolidated financial statements
F-29
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
SIX MONTHS ENDED MARCH 31, 2005
(UNAUDITED)
(in thousands, except share data)
Common Stock Additional Totals
------------------------------ Paid-In Retained Stockholder's
Shares Amount Capital Earnings Equity
------------- ------------- ------------- ------------- -------------
Balance, October 1, 2004 ..... 200 $ 2 $ 16,505 $ 10,156 $ 26,663
Net income ................... - - - 825 825
------------- ------------- ------------- ------------- -------------
Balance, March 31, 2005 ...... 200 $ 2 $ 16,505 $ 10,981 $ 27,488
============= ============= ============= ============= =============
See accompanying notes to consolidated financial statements
F-30
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
SIX MONTHS ENDED MARCH 31, 2005 AND 2004
(UNAUDITED)
2005 2004
------------- -------------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ..................................................................... $ 825 $ 751
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization .................................... 4,766 3,925
Management fees, cost allocation and, intercompany interest ................. 22,421 15,187
Gain on sale of assets ...................................................... (8) (19)
Change in operating assets and liabilities ................................. (5,433) (8,289)
------------- -------------
Net cash provided by operating activities ...................................... 22,571 11,555
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ........................................................... (28,818) (12,704)
Proceeds from sale of assets ................................................... 8 33
------------- -------------
Net cash used in investing activities .......................................... (28,810) (12,671)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings ............................................... (28) (28)
Net payments from (to) Parent .................................................. 8,867 (3,125)
------------- -------------
Net cash used in financing activities .......................................... 8,839 (3,153)
------------- -------------
Increase (decrease) in cash and cash equivalents ............................... 2,600 (4,269)
Cash and cash equivalents at beginning of year ................................. 242 4,702
------------- -------------
Cash and cash equivalents at end of year ....................................... $ 2,842 $ 433
============= =============
See accompanying notes to consolidated financial statements
F-31
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - INTERIM FINANCIAL STATEMENTS
The consolidated financial statements of Atlas Resources, Inc. and its
wholly-owned subsidiary (the "Company") as of March 31, 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 preparation of financial statements in conformity with US GAAP requires
management to make estimates and assumptions that affect (i) the reported
amounts of assets and liabilities, (ii) disclosure of contingent assets and
liabilities as of the dates of the financial statements and (iii) the reported
amounts of revenues and expenses during the reporting periods. In the opinion of
management, all adjustments (consisting only of normal recurring adjustments and
certain cost allocations for expenses paid by either the Parent or its'
affiliates on behalf of the Company) considered necessary for a fair
presentation have been reflected in these consolidated financial statements.
Operating results for the six months ended March 31, 2005, are not
necessarily indicative of the results that may be expected for the year ending
September 30, 2005. Certain reclassifications have been made to the fiscal 2004
consolidated financial statements to conform to the fiscal 2005 presentation.
These financial statements should be read in conjunction with the Company's
audited September 30, 2004 consolidated financial statements.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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:
Six Months Ended
March 31,
------------------------------
2005 2004
------------- -------------
(in thousands)
CASH PAID DURING THE PERIODS FOR:
Interest ....................................................................... $ 412 $ -
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.
F-32
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 six months ended March 2005 and 2004 is as follows (in
thousands):
March 31, March 31,
2005 2004
------------- -------------
Asset retirement obligations, beginning of period .............................. $ 1,910 $ 701
Liabilities incurred ........................................................... 1,658 101
Liabilities settled ............................................................ (7) (41)
Revision of estimates .......................................................... - 23
Accretion expense .............................................................. 92 25
------------- -------------
Asset retirement obligations, end of period .................................... $ 3,653 $ 809
============= =============
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.
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 July 2002, 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 March 31, 2005,
the Parent had $50 million outstanding under this facility, including $1.4
million under letters of credit. The Company had no amounts outstanding under
this facility for borrowings on its behalf at March 31, 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.
F-33
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 5- INCOME TAXES
The Company is included in the consolidated federal income tax return
of Atlas' parent, Resource America, Inc. 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 six months ended March 31, 2005
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 from Parent 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-34
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 $____ 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.
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 either of the other two
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.
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
1
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.
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.
2
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..................................5
o Fayette County, Pennsylvania (Mississippian/Upper
Devonian Sandstone Reservoirs)
o Lease information for Fayette, Greene and
Westmoreland Counties, Pennsylvania.................7
o Location and Production Maps for Fayette, Greene
and Westmoreland Counties, Pennsylvania showing
the proposed wells and the wells in the area.......10
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.............................28
o Western Pennsylvania (Clinton/Medina Geological
Formation)
o Lease information for western Pennsylvania and
eastern Ohio.......................................34
o Location and Production Map for western
Pennsylvania and eastern Ohio showing the
proposed wells and the wells in the area...........36
o Production data for western Pennsylvania and
eastern Ohio.......................................38
o United Energy Development Consultants, Inc.'s
geologic evaluation for the currently proposed
wells in western Pennsylvania and eastern Ohio.....40
o Armstrong County, Pennsylvania (Upper Devonian Sandstone
Reservoirs)
o Lease information for Armstrong and Indiana
Counties, Pennsylvania.............................46
o Location and Production Map for Armstrong and
Indiana Counties, Pennsylvania showing the
proposed wells and the wells in the area...........48
o Production data for Armstrong and Indiana
Counties, Pennsylvania.............................50
o United Energy Development Consultants, Inc.'s
geologic evaluation for the currently proposed
wells in Armstrong and Indiana Counties,
Pennsylvania.......................................54
o McKean County, Pennsylvania (Upper Devonian Sandstone
Reservoirs)
o Lease information for McKean County,
Pennsylvania.......................................60
o Location and Production Maps for McKean County,
Pennsylvania showing the proposed wells and the
wells in the area..................................62
o Production data for McKean County, Pennsylvania....68
o United Energy Development Consultants, Inc.'s
geologic evaluation for the currently proposed
wells in McKean County, Pennsylvania...............73
3
o Anderson, Campbell, Morgan, Roane and Scott Counties,
Tennessee (Mississippian Carbonate and Devonian Shale
Reservoirs)
o A map of Tennessee showing its Counties............78
o Lease information for Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennssesee.......80
o Location and Production Maps for Anderson,
Campbell, Morgan, Roane and Scott Counties,
Tennessee showing the proposed wells and the
wells in the area..................................82
o Production data for Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee................87
o United Energy Development Consultants, Inc.'s
geologic evaluation for the currently proposed
wells in Anderson, Campbell, Morgan, Roane and
Scott Counties, Tennessee..........................90
4
MAP OF WESTERN PENNSYLVANIA
AND
EASTERN OHIO
5
[GRAPHIC APPEARS HERE]
6
LEASE INFORMATION
FOR
FAYETTE, GREENE AND WESTMORELAND COUNTIES, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
7
LOCATION AND PRODUCTION MAPS FOR
FAYETTE, GREENE AND WESTMORELAND COUNTIES, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
8
PRODUCTION DATA
FOR
FAYETTE, GREENE AND WESTMORELAND COUNTIES, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
9
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
FAYETTE, GREENE AND WESTMORELAND COUNTIES, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
10
LEASE INFORMATION
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
11
LOCATION AND PRODUCTION MAP
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
12
PRODUCTION DATA
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
13
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
WESTERN PENNSYLVANIA AND EASTERN OHIO
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
14
LEASE INFORMATION
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
15
LOCATION AND PRODUCTION MAP
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
16
PRODUCTION DATA
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
17
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
18
LEASE INFORMATION
FOR
MCKEAN COUNTY, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
19
LOCATION AND PRODUCTION MAPS
FOR
MCKEAN COUNTY, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
20
PRODUCTION DATA
FOR
MCKEAN COUNTY, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
21
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
MCKEAN COUNTY, PENNSYLVANIA
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
22
MAP OF TENNESSEE
23
[GRAPHIC APPEARS HERE]
24
LEASE INFORMATION
FOR
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
25
LOCATION AND PRODUCTION MAPS
FOR
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
26
PRODUCTION DATA
FOR
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
27
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
[THIS INFORMATION WILL BE INCLUDED IN A SUBSEQUENT PRE-EFFECTIVE
AMENDMENT TO THE REGISTRATION STATEMENT.]
28
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
- ----------- ----------- ----
I. FORMATION
1.01 Formation........................................................1
1.02 Certificate of Limited Partnership...............................1
1.03 Name, Principal Office and Residence.............................1
1.04 Purpose..........................................................1
II. DEFINITION OF TERMS
2.01 Definitions......................................................2
III. SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
3.01 Designation of Managing General Partner and Participants........11
3.02 Participants....................................................11
3.03 Subscriptions to the Partnership................................11
3.04 Capital Contributions of the Managing General Partner...........13
3.05 Payment of Subscriptions........................................13
3.06 Partnership Funds...............................................14
IV. CONDUCT OF OPERATIONS
4.01 Acquisition of Leases...........................................15
4.02 Conduct of Operations...........................................16
4.03 General Rights and Obligations of the Participants and
Restricted and Prohibited Transactions.........................20
4.04 Designation, Compensation and Removal of Managing General
Partner and Removal of Operator................................30
4.05 Indemnification and Exoneration.................................33
4.06 Other Activities................................................35
V. PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND
DISTRIBUTIONS
5.01 Participation in Costs and Revenues.............................36
5.02 Capital Accounts and Allocations Thereto........................39
5.03 Allocation of Income, Deductions and Credits....................40
5.04 Elections.......................................................42
5.05 Distributions...................................................43
VI. TRANSFER OF INTERESTS
6.01 Transferability.................................................44
6.02 Special Restrictions on Transfers...............................44
6.03 Right of Managing General Partner to Hypothecate and/or
Withdraw Its Interests.........................................46
6.04 Presentment.....................................................46
SECTION NO. DESCRIPTION PAGE
- ----------- ----------- ----
VII. DURATION, DISSOLUTION, AND WINDING UP
7.01 Duration........................................................48
7.02 Dissolution and Winding Up......................................48
VIII. MISCELLANEOUS PROVISIONS
8.01 Notices.........................................................49
8.02 Time............................................................50
8.03 Applicable Law..................................................50
8.04 Agreement in Counterparts.......................................50
8.05 Amendment.......................................................50
8.06 Additional Partners.............................................51
8.07 Legal Effect....................................................51
EXHIBITS
EXHIBIT (I-A) - Form of Managing General Partner Signature Page
EXHIBIT (I-B) - Form of Subscription Agreement
EXHIBIT (II) - Form of Drilling and Operating Agreement for
Atlas America Public #15-2005(A) L.P.
[Atlas America Public #15-2006(___) L.P.]
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.
8. "Atlas America Public #15-2005 Program" means the offering of
Units in a series of up to three limited partnerships entitled
Atlas America Public #15-2005(A) L.P., Atlas America Public
#15-2006(B) L.P. and Atlas America Public #15-2006(C) L.P.
9. "Capital Account" or "account" means the account established
for each party, maintained as provided in Section 5.02 and its
subsections.
2
10. "Capital Contribution" means the amount agreed to be
contributed to the Partnership by a Partner pursuant to
Sections 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.
14. "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.
15. "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.
16. "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.
17. "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 Section 4.03(d)(7) or pursuant to the Managing
General Partner's role as Tax Matters Partner.
18. "Distribution Interest" means an undivided interest in the
Partnership's assets after payments to the Partnership's
creditors or the creation of a reasonable reserve therefor, in
the ratio the positive balance of a party's Capital Account
bears to the aggregate positive balance of the Capital
Accounts of all of the parties determined after taking into
account all Capital Account adjustments for the taxable year
during which liquidation occurs (other than those made
pursuant to liquidating distributions or restoration of
deficit Capital Account balances). Provided, however, after
the Capital Accounts of all of the parties have been
3
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 Section 5.01 and its
subsections.
19. "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).
20. "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.
21. "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.
22. "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 Section
708(b)(1)(A) of the Code or the Partnership ceases to
be a going concern.
23. "Horizon" means a zone of a particular formation; that part of
a formation of sufficient porosity and permeability to form a
petroleum reservoir.
24. "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.
25. "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.
26. "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,";
(ii) the expense of plugging and abandoning any well
before a completion attempt; and
4
(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.
27. "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.
28. "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 Section 3.03(b)(2).
All Investor General Partners shall be of the same class and
have the same rights.
29. "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.
30. "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.
31. "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
Section 3.03(b)(2);
(iii) the Investor General Partners on the conversion of
their Investor General Partner Units to Limited
Partner Units pursuant to Section 6.01(b); and
(iv) any other persons who are admitted to the Partnership
as additional or substituted Limited Partners.
Except as provided in Section 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.
32. "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.
33. "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.
34. "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 Section 3.03(c)(1) have been
received and accepted by the Managing General Partner.
35. "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.
36. "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.
37. "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.
38. "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.
39. "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.
40. "Participants" means:
(i) the Managing General Partner to the extent of its
optional subscription under Section 3.03(b)(2);
6
(ii) the Limited Partners; and
(iii) the Investor General Partners.
41. "Partners" means:
(i) the Managing General Partner;
(ii) the Investor General Partners; and
(iii) the Limited Partners.
42. "Partnership" means Atlas America Public #15-2005(A) L.P.
[Atlas America Public #15-2006(___) L.P.].
43. "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.
44. "Partnership Well" means a well, some portion of the revenues
from which is received by the Partnership.
45. "Person" means a natural person, partnership, corporation,
association, trust or other legal entity.
46. "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.
47. "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.
48. "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.
49. "Prospectus" means the Prospectus included in the Registration
Statement on Form S-1 relating to the offer
7
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"). The
Registration Statement has been declared effective by the
Commission and the Partnerships and the Units are described in
the Prospectus that forms a part of the Registration
Statement. 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.
50. "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.
51. "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.
52. "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.
53. "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.
54. "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.
55. "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
56. "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.
57. "Selling Agents" means the broker/dealers which are selected
by the Dealer-Manager to participate in the offer and sale of
the Units.
58. "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.
59. "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.
60. "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.
61. "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.
62. "Tax Matters Partner" means the Managing General Partner.
63. "Units" or "Units of Participation" means up to 450 Limited
Partner interests in the Partnership and up to 14,550 Investor
General Partner interests in the Partnership, which will be
converted to up to 14,550 Limited Partner Units as set forth
in Section 6.01(b), purchased by Participants in the
Partnership under the provisions of Section 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.
64. "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
Section 3.03(b)(2).
Limited Partners and Investor General Partners, including Affiliates of the
Managing General Partner, shall serve as Participants.
3.02. PARTICIPANTS.
3.02(a). LIMITED PARTNER AT FORMATION. Atlas America, Inc., as Original Limited
Partner, has acquired one Unit and has made a Capital Contribution of $100.
On the admission of one or more Limited Partners, the Partnership shall return
to the Original Limited Partner its Capital Contribution and shall reacquire its
Unit. The Original Limited Partner shall then cease to be a Limited Partner in
the Partnership with respect to the Unit.
3.02(b). OFFERING OF INTERESTS. The Partnership is authorized to admit to the
Partnership at the Initial Closing Date, any Interim Closing Date(s), and the
Offering Termination Date additional Participants whose Subscription Agreements
are accepted by the Managing General Partner if, after the admission of the
additional Participants, the total Units sold do not exceed the maximum number
of Units set forth in Section 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 Section 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 Section 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). SUBSCRIPTIONS BY MANAGING GENERAL PARTNER.
3.03(b)(1). MANAGING GENERAL PARTNER'S REQUIRED SUBSCRIPTION. The Managing
General Partner, as a general partner and not as a Participant, shall:
(i) contribute to the Partnership the Leases which will be drilled
by the Partnership on the terms set forth in Section
4.01(a)(4); and
(ii) pay the costs or make the required contributions charged to it
under this Agreement.
These Capital Contributions shall be paid or made by the Managing General
Partner or any Affiliate in the Managing General Partner's discretion at the
time the costs are required to be paid by the Partnership, but no later than
December 31, 2005 [December 31, 2006].
3.03(b)(2). MANAGING GENERAL PARTNER'S OPTIONAL ADDITIONAL SUBSCRIPTION. In
addition to the Managing General Partner's required subscription under Section
3.03(b)(1), the Managing General Partner may subscribe for up to 5% of the total
Units in the Partnership under the provisions of Section 3.03(a) and its
subsections, and, subject to the limitations on voting rights set forth in
Section 4.03(c)(3), to that extent shall be deemed a Participant in the
Partnership for all purposes under this Agreement.
3.03(b)(3). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing General Partner
has executed a Managing General Partner Signature Page which:
(i) evidences the Managing General Partner's required subscription
under Section 3.03(b)(1); and
(ii) may be amended to reflect the amount of any optional
subscription under Section 3.03(b)(2).
Execution of the Managing General Partner Signature Page serves as an agreement
by the Managing General Partner to be bound by each and every term of this
Agreement.
3.03(c). MAXIMUM AND MINIMUM NUMBER OF UNITS.
3.03(c)(1). MAXIMUM NUMBER OF UNITS. The maximum number of Units may not exceed
15,000 [____________] Units, which is up to $150,000,000 [$______________] of
cash subscription proceeds, excluding the subscription discounts permitted under
Section 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 15,000 Units which is up to $150,000,000 of cash
subscription proceeds excluding the subscription discounts permitted under
Section 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 Section 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.
12
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.
3.04. CAPITAL CONTRIBUTIONS OF THE MANAGING GENERAL PARTNER.
3.04(a). MINIMUM AMOUNT OF MANAGING GENERAL PARTNER'S REQUIRED CONTRIBUTION. The
Managing General Partner is required to:
(i) make aggregate Capital Contributions to the Partnership,
including Leases contributed under Section 3.03(b)(1)(i), of
not less than 25% of all Capital Contributions to the
Partnership; and
(ii) maintain a minimum Capital Account balance equal to not less
than 1% of total positive Capital Account balances for the
Partnership.
3.04(b). ON LIQUIDATION THE MANAGING GENERAL PARTNER MUST CONTRIBUTE DEFICIT
BALANCE IN ITS CAPITAL ACCOUNT. The Managing General Partner shall contribute to
the Partnership any deficit balance in its Capital Account on the occurrence of
either of the following events:
(i) the liquidation of the Partnership; or
(ii) the liquidation of the Managing General Partner's interest in
the Partnership.
This shall be determined after taking into account all adjustments for the
Partnership's taxable year during which the liquidation occurs, other than
adjustments made pursuant to this requirement, by the end of the taxable year in
which its interest in the Partnership is liquidated or, if later, within 90 days
after the date of the liquidation.
3.04(c). INTEREST FOR CONTRIBUTIONS. The interest of the Managing General
Partner, as Managing General Partner and not as a Participant, in the capital
and revenues of the Partnership is 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.
3.05. PAYMENT OF SUBSCRIPTIONS.
3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing General Partner
shall pay any optional subscription under Section 3.03(b)(2) as set forth in
Section 3.05(b)(1).
3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL CONTRIBUTIONS OF THE
INVESTOR GENERAL PARTNERS.
3.05(b)(1). PAYMENT OF SUBSCRIPTION AGREEMENTS. A Participant shall pay the
amount designated as the subscription price on the Subscription Agreement
executed by the Participant 100% in cash at the time of subscribing. A
Participant shall receive interest on the amount he pays from the time his
subscription proceeds are deposited in the escrow account, or the Partnership
account after the minimum number of Units have been received as provided in
Section 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 Section 6.01(b).
13
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 Sections 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 Section 3.06(c)(2);
(iii) multi-tier arrangements meeting the requirements of Section
4.03(d)(15);
(iv) investments involving less than 5% of the Partnership's
subscription proceeds which are a necessary and incidental
part of a property acquisition transaction; and
(v) investments in entities established solely to limit the
Partnership's liabilities associated with the ownership or
operation of property or equipment, provided that duplicative
fees and expenses shall be prohibited.
3.06(c)(2). PERMISSIBLE INVESTMENTS BEFORE INVESTMENT IN PARTNERSHIP ACTIVITIES.
After the Initial Closing Date and until proceeds from the offering are invested
in the Partnership's operations, the proceeds may be temporarily invested in
income producing short-term, highly liquid investments, in which there is
appropriate safety of principal, such as U.S. Treasury Bills.
14
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 Section 4.03(d) and its subsections,
the acquisitions of Leases or other property may be made under any terms and
obligations, including:
(i) any limitations as to the Horizons to be assigned to the
Partnership; and
(ii) subject to any burdens as the Managing General Partner deems
necessary in its sole discretion.
4.01(a)(4). COST OF LEASES. All Leases shall be:
(i) contributed to the Partnership by the Managing General Partner
or its Affiliates other than an affiliated Program; and
(ii) credited towards the Managing General Partner's required
Capital Contribution set forth in Section 3.03(b)(1) at the
Cost of the Lease, unless the Managing General Partner has
cause to believe that Cost is materially more than the fair
market value of the property, in which case the credit for the
contribution must be made at a price not in excess of the fair
market value.
A determination of fair market value must be:
(i) supported by an appraisal from an Independent Expert; and
(ii) maintained in the Partnership's records for six years along
with associated supporting information.
4.01(a)(5). THE MANAGING GENERAL PARTNER, OPERATOR OR THEIR AFFILIATES' RIGHTS
IN THE REMAINDER INTERESTS. Subject to the provisions of Section 4.03(d) and its
subsections, to the extent the Partnership does not acquire a full interest in a
Lease from the Managing General Partner or its Affiliates, the remainder of the
interest in the Lease may be held by the Managing General Partner or its
Affiliates. They may either:
(i) retain and exploit the remaining interest for their own
account; or
(ii) sell or otherwise dispose of all or a part of the remaining
interest.
Profits from the exploitation and/or disposition of their retained interests in
the Leases shall be for the benefit of the Managing General Partner or its
Affiliates to the exclusion of the Partnership.
15
4.01(a)(6). NO BREACH OF DUTY. Subject to the provisions of Section 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 Section 4.03 and its
subsections, and to any authority which may be granted the Operator under
Section 4.02(c)(3)(b), the Managing General Partner shall have full authority to
do all things deemed necessary or desirable by it in the conduct of the business
of the Partnership. Without limiting the generality of the foregoing, the
Managing General Partner is expressly authorized to engage in:
(i) the making of all determinations of which Leases, wells and
operations will be participated in by the Partnership, which
includes:
(a) which Leases are developed;
(b) which Leases are abandoned; or
16
(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;
(d) 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;
(e) 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;
(f) 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;
(g) 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:
(iii) worker's compensation insurance in full compliance with the
laws of the Commonwealth of Pennsylvania and any other
applicable state laws;
(iv) 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
(v) liability and excess liability insurance as to bodily injury
and property damage with combined limits of $50,000,000 during
drilling operations and thereafter, per occurrence or accident
and in the aggregate, which includes $1,000,000 of seepage,
pollution and contamination insurance which protects and
defends the insured against property damage or bodily injury
claims from third-parties, other than a co-owner of the
Working Interest, alleging seepage, pollution or contamination
damage resulting from a pollution incident. The excess
liability insurance shall be in place and effective no later
than the date drilling operations begin, and the Partnership
shall have the benefit of the Managing General Partner's
$50,000,000 liability insurance on the same basis as the
Managing General Partner and its Affiliates, including the
Managing General Partner's other Programs;
(vi) 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;
(vii) 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 Section
4.03(d)(6);
17
(viii) 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;
(ix) 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;
(x) the operation of producing wells drilled on the Leases or on a
Prospect which includes any part of the Leases;
(xi) the exercise of the rights granted to it under the power of
attorney created under this Agreement; and
(xii) 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 Section
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 Section 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;
(ii) enter into a turnkey drilling contract with the Partnership;
18
(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 Section
4.03(d)(8)(b), although they are not obligated to advance the
funds to the Partnership.
4.02(e)(1)(b). LIMITATION ON BORROWING. The borrowings, other than credit
transactions on open account customary in the industry to obtain goods and
services, shall be subject to the following limitations:
(i) the borrowings must be without recourse to the Investor
General Partners and the Limited Partners except as otherwise
provided in this Agreement; and
(ii) the amount that may be borrowed at any one time may not exceed
an amount equal to 5% of the Partnership's subscription
proceeds.
19
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.
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
20
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 Section 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 Section 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;
(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.
21
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 Section
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 Section 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.
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.
22
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 Section 4.01(a)(4) or fair market value of any
producing property as set forth in Section 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 Section 4.03(b) with:
(i) the California Commissioner of Corporations;
(ii) the Arizona Corporation Commission; and
(iii) the securities commissions of other states which request the
report.
4.03(c). MEETINGS OF PARTICIPANTS.
4.03(c)(1). PROCEDURE FOR A PARTICIPANT MEETING.
4.03(c)(1)(a). MEETINGS MAY BE CALLED BY MANAGING GENERAL PARTNER OR
PARTICIPANTS. Meetings of the Participants may be called as follows:
23
(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:
(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.
24
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 Section 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 Section 4.03(c),
except for the special voting rights granted Participants under Section
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
(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.
25
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 Sections 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 Sections 4.03(d)(5) and
4.03(d)(9), the Managing General Partner and its Affiliates shall not receive a
Farmout or purchase any undeveloped Leases from the Partnership other than at
the higher of Cost or fair market value.
The Managing General Partner and its Affiliates, other than an Affiliated Income
Program, may not purchase any producing natural gas or oil property from the
Partnership unless:
(i) the sale is in connection with the liquidation of the
Partnership; or
(ii) the Managing General Partner's well supervision fees under the
Drilling and Operating Agreement for the well have exceeded
the net revenues of the well, determined without regard to the
Managing General Partner's well supervision fees for the well,
for a period of at least three consecutive months.
In both (i) and (ii), the sale must be at fair market value supported by an
appraisal of an Independent Expert selected by the Managing General Partner.
4.03(d)(4). LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. During a period of five years
after the Offering Termination Date of the Partnership, if the Managing General
Partner or any of its Affiliates (excluding another Program in which the
interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) proposes to acquire
an interest from an unaffiliated person in a Prospect in which the Partnership
possesses an interest or in a Prospect in which the Partnership's interest has
been terminated without compensation within one year preceding the proposed
acquisition, then the following conditions shall apply:
26
(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
(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.
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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 Section 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.
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.
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4.03(d)(12). MARKETING ARRANGEMENTS. Subject to Section 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.
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
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(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
Sections 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 Sections 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 Section 4.04(a)(3); or
(ii) withdraws pursuant to Section 4.04(a)(3)(f).
4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. In addition to the
compensation set forth in Sections 4.01(a)(4) and 4.02(d)(1), the Managing
General Partner shall receive the compensation set forth in Sections
4.04(a)(2)(b) through 4.04(a)(2)(g).
4.04(a)(2)(a). CHARGES MUST BE NECESSARY AND REASONABLE. Charges by the Managing
General Partner for goods and services must be fully supportable as to:
(i) the necessity of the goods and services; and
(ii) the reasonableness of the amount charged.
All actual and necessary expenses incurred by the Partnership may be paid out of
the Partnership's subscription proceeds and revenues.
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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 Section 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.
4.04(a)(2)(g). OTHER TRANSACTIONS. The Managing General Partner and its
Affiliates may enter into transactions pursuant to Section 4.03(d)(7) with the
Partnership and shall be entitled to compensation under that section.
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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 Section
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
Section 6.04, 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;
(ii) have any rights pursuant to such natural gas supply agreement;
or
32
(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 Section 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 Section 4.04(a)(3)(d)(i) above.
Any successor Managing General Partner shall have the option to purchase 20% of
the withdrawing Managing General Partner's interest in the Partnership at the
value determined as described above with respect to removal.
4.04(a)(3)(g). THE MANAGING GENERAL PARTNER'S RIGHT TO WITHDRAW PROPERTY
INTEREST. The Managing General Partner has the right at any time to withdraw a
property interest held by the Partnership in the form of a Working Interest in
the Partnership Wells equal to or less than its respective interest in the
revenues of the Partnership under the conditions set forth in Section 6.03. If
the Managing General Partner withdraws an interest, then the Managing General
Partner shall:
(i) pay the expenses of withdrawing; and
(ii) fully indemnify the Partnership against any additional
expenses which may result from a partial withdrawal of its
interests, including insuring that a greater amount of Direct
Costs or Administrative Costs is not allocated to the
Participants.
4.04(a)(4). REMOVAL OF OPERATOR. The Operator may be removed and a new Operator
may be substituted at any time on 60 days advance written notice to the outgoing
Operator by the Managing General Partner acting on behalf of the Partnership on
the affirmative vote of Participants whose Units equal a majority of the total
Units.
The Operator shall not be removed until a substituted Operator has been selected
by an affirmative vote of Participants whose Units equal a majority of the total
Units and installed as such.
4.05. INDEMNIFICATION AND EXONERATION.
4.05(a)(1). STANDARDS FOR THE MANAGING GENERAL PARTNER NOT INCURRING LIABILITY
TO THE PARTNERSHIP OR PARTICIPANTS. The Managing General Partner, the Operator,
and their Affiliates shall not have any liability whatsoever to the Partnership,
or to any Participant for any loss suffered by the Partnership or Participants
which arises out of any action or inaction of the Managing General Partner, the
Operator, or their Affiliates if:
(i) the Managing General Partner, the Operator, and their
Affiliates determined in good faith that the course of conduct
was in the best interest of the Partnership;
(ii) the Managing General Partner, the Operator, and their
Affiliates were acting on behalf of, or performing services
for, the Partnership; and
(iii) the course of conduct did not constitute negligence or
misconduct of the Managing General Partner, the Operator, or
their Affiliates.
4.05(a)(2). STANDARDS FOR MANAGING GENERAL PARTNER INDEMNIFICATION. The Managing
General Partner, the Operator, and their Affiliates shall be indemnified by the
Partnership against any losses, judgments, liabilities, expenses, and amounts
paid in settlement of any claims sustained by them in connection with the
Partnership, provided that:
(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;
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(ii) the Managing General Partner, the Operator, and their
Affiliates were acting on behalf of, or performing services
for, the Partnership; and
(iii) the course of conduct was not the result of negligence or
misconduct of the Managing General Partner, the Operator, or
their Affiliates.
Provided, however, payments arising from such indemnification or agreement to
hold harmless are recoverable only out of the following:
(i) the Partnership's tangible net assets, which include its
revenues; and
(ii) any insurance proceeds from the types of insurance for which
the Managing General Partner, the Operator and their
Affiliates may be indemnified under this Agreement.
4.05(a)(3). STANDARDS FOR SECURITIES LAW INDEMNIFICATION. Notwithstanding
anything to the contrary contained in the above, the Managing General Partner,
the Operator, and their Affiliates and any person acting as a broker/dealer
shall not be indemnified for any losses, liabilities or expenses arising from or
out of an alleged violation of federal or state securities laws by such party
unless:
(i) there has been a successful adjudication on the merits of each
count involving alleged securities law violations as to the
particular indemnitee;
(ii) the claims have been dismissed with prejudice on the merits by
a court of competent jurisdiction as to the particular
indemnitee; or
(iii) a court of competent jurisdiction approves a settlement of the
claims against a particular indemnitee and finds that
indemnification of the settlement and the related costs should
be made, and the court considering the request for
indemnification has been advised of the position of the SEC,
the Massachusetts Securities Division, and any state
securities regulatory authority in which plaintiffs claim they
were offered or sold Units with respect to the issue of
indemnification for violation of securities laws.
4.05(a)(4). STANDARDS FOR ADVANCEMENT OF FUNDS TO THE MANAGING GENERAL PARTNER
AND INSURANCE. The advancement of Partnership funds to the Managing General
Partner, the Operator, or their Affiliates for legal expenses and other costs
incurred as a result of any legal action for which indemnification is being
sought is permissible only if the Partnership has adequate funds available and
the following conditions are satisfied:
(i) the legal action relates to acts or omissions with respect to
the performance of duties or services on behalf of the
Partnership;
(ii) the legal action is initiated by a third-party who is not a
Participant, or the legal action is initiated by a Participant
and a court of competent jurisdiction specifically approves
the advancement; and
(iii) the Managing General Partner or its Affiliates undertake to
repay the advanced funds to the Partnership, together with the
applicable legal rate of interest thereon, in cases in which
such party is found not to be entitled to indemnification.
The Partnership shall not bear the cost of that portion of insurance which
insures the Managing General Partner, the Operator, or their Affiliates for any
liability for which they could not be indemnified pursuant to Sections
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
34
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 Sections
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.
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
35
Managing General Partner and its Affiliates may pursue business opportunities
that are consistent with the Partnership's investment objectives for their own
account only after they have determined that the opportunity either:
(i) cannot be pursued by the Partnership because of insufficient
funds; or
(ii) it is not appropriate for the Partnership under the existing
circumstances.
4.06(b). MANAGING GENERAL PARTNER MAY MANAGE MULTIPLE PARTNERSHIPS. The Managing
General Partner or its Affiliates may manage multiple Programs simultaneously.
4.06(c). PARTNERSHIP HAS NO INTEREST IN NATURAL GAS CONTRACTS OR PIPELINES AND
GATHERING SYSTEMS. Notwithstanding any other provision in this Agreement, the
Partnership shall not:
(i) be a party to any natural gas supply agreement that the
Managing General Partner, the Operator, or their Affiliates
enter into with a third-party or have any rights pursuant to
such natural gas supply agreement; or
(ii) receive any interest in the Managing General Partner's, the
Operator's, and their Affiliates' pipeline or gathering system
or compression facilities.
ARTICLE V
PARTICIPATION IN COSTS AND REVENUES,
CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS
5.01. PARTICIPATION IN COSTS AND REVENUES. Except as otherwise provided in this
Agreement, costs and revenues shall be charged and credited to the Managing
General Partner and the Participants as set forth in this section and its
subsections.
5.01(a). COSTS. Costs shall be charged as set forth below.
5.01(a)(1). ORGANIZATION AND OFFERING COSTS. Organization and Offering Costs
shall be charged 100% to the Managing General Partner. For purposes of sharing
in revenues under Section 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 Section 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.
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5.01(a)(6). LEASE COSTS. The Leases shall be contributed to the Partnership by
the Managing General Partner as set forth in Section 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 Section 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 Section 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 Section 5.01(b)(4), below.
5.01(b)(3). SALE OR DISPOSITION OF EQUIPMENT. Proceeds from the sale or
disposition of equipment shall be credited to the parties charged with the costs
of the equipment in the ratio in which the costs were charged.
5.01(b)(4). OTHER REVENUES. Subject to Section 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
37
(iii) the Managing General Partner shall not subordinate more than
50% of its share of Partnership Net Production Revenues in any
subordination period.
The subordination shall be determined by:
(i) carrying forward to subsequent 12-month periods the amount, if
any, by which cumulative cash distributions to Participants,
including any subordination payments, are less than:
(a) $1,000 per Unit (10% per Unit) in the first 12-month
period;
(b) $2,000 per Unit (20% per Unit) in the second 12-month
period;
(c) $3,000 per Unit (30% per Unit) in the third 12-month
period; or
(d) $4,000 per Unit (40% per Unit) in the fourth 12-month
period (no carry forward is required if such
distributions are less than $5,000 per Unit (50% per
Unit) in the fifth 12-month period because the
Managing General Partner's subordination obligation
terminates on the expiration of the fifth 12-month
period); and
(ii) reimbursing the Managing General Partner for any previous
subordination payments to the extent cumulative cash
distributions to Participants, including any subordination
payments, would exceed:
(a) $1,000 per Unit (10% per Unit) in the first 12-month
period;
(b) $2,000 per Unit (20% per Unit) in the second 12-month
period;
(c) $3,000 per Unit (30% per Unit) in the third 12-month
period;
(d) $4,000 per Unit (40% per Unit) in the fourth 12-month
period; or
(e) $5,000 per Unit (50% per Unit) in the fifth 12-month
period.
The Managing General Partner's subordination obligation shall be further subject
to the following conditions:
(i) the subordination obligation may be prorated in the Managing
General Partner's discretion (e.g. in the case of a 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.
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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 Section 5.01(b)(4), shall be
allocated among the Participants, including the Managing General Partner to the
extent of any optional subscription under Section 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 Section 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.
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. Section 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 Section 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
Section 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. Section
1.704-l(b)(2)(iv)(g), but excluding income and gain described
in Treas. Reg. Section 1.704-l(b)(4)(i);
and shall be decreased by:
39
(iv) the amount of money distributed to him by the Partnership;
(v) the fair market value of property distributed to him, without
regard to Section 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 Section 752 of
the Code;
(vi) allocations to him of Partnership expenditures described in
Section 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.
Section 1.704-l(b)(2)(iv)(g), but excluding items described in
(vi) above, and loss or deduction described in Treas. Reg.
Section 1.704-l(b)(4)(i) or (iii).
5.02(b)(2). EXCEPTION. If Treas. Reg. Section 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 Section
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
(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 Section
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
Section 704(c) of the Code and the regulations thereunder, on the Partnership's
books, in accordance with Treas. Reg. Section 1.704-l(b)(2)(iv)(f).
5.02(f). AMOUNT OF BOOK ITEMS. In cases where Section 704(c) of the Code or
Section 5.02(e) applies, Capital Accounts shall be adjusted in accordance with
Treas. Reg. Section 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
40
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 Section 5.01(b) and its subsections.
5.03(b). TAX BASIS OF EACH PROPERTY. Subject to Section 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 Section 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 Section 5.03(b) and the party's
allocable share of the amount realized from the disposition of the property.
5.03(d). GAIN ON DEPRECIABLE PROPERTY. Gain from each sale or other disposition
of depreciable property shall be allocated to each party whose share of the
proceeds from the sale or other disposition exceeds its contribution to the
adjusted basis of the property in the ratio that the excess bears to the sum of
the excesses of all parties having an excess.
5.03(e). LOSS ON DEPRECIABLE PROPERTY. Loss from each sale, abandonment or other
disposition of depreciable property shall be allocated to each party whose
contribution to the adjusted basis of the property exceeds its share of the
proceeds from the sale, abandonment or other disposition in the proportion that
the excess bears to the sum of the excesses of all parties having an excess.
5.03(f). ALLOCATION IF RECAPTURE TREATED AS ORDINARY INCOME. Any recapture
treated as an increase in ordinary income by reason of Sections 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 Section 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 Section 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;
41
(ii) allocations of loss and deduction that, as of the end of the
year, reasonably are expected to be made to the party under
Sections 704(e)(2) and 706(d) of the Code and Treas. Reg.
Section 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. Section 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 Section 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.
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). SECTION 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 Sections 734 and 743 of
the Code.
5.04(d). SECTION 83 ELECTION. The Partnership, the Managing General Partner and
each Participant hereby agree to be legally bound by the provisions of this
Section 5.04(e) 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
42
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
(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.
43
5.05(c). DISTRIBUTIONS ON WINDING UP. On the winding up of the Partnership
distributions shall be made as provided in Section 7.02.
5.05(d). INTEREST AND RETURN OF CAPITAL. No party shall under any circumstances
be entitled to any interest on amounts retained by the Partnership. Each
Participant shall look only to his share of distributions, if any, from the
Partnership for a return of his Capital Contribution.
ARTICLE VI
TRANSFER OF INTERESTS
6.01. TRANSFERABILITY.
6.01(a). RIGHTS OF ASSIGNEE. On a transfer unless an assignee becomes a
substituted Participant in accordance with the provisions set forth below, he
shall not be entitled to any of the rights granted to a Participant under this
Agreement, other than the right to receive all or part of the share of the
profits, losses, income, gain, credits and cash distributions or returns of
capital to which his assignor would otherwise be entitled.
6.01(b). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER UNITS.
6.01(b)(1). AUTOMATIC CONVERSION. After all of the Partnership Wells have been
drilled and completed, as determined by the Managing General Partner, the
Managing General Partner shall file an amended certificate of limited
partnership with the Secretary of State of the State of Delaware for the purpose
of converting the Investor General Partner Units to Limited Partner Units.
6.01(b)(2). INVESTOR GENERAL PARTNERS SHALL HAVE CONTINGENT LIABILITY. On
conversion the Investor General Partners shall be Limited Partners entitled to
limited liability; however, they shall remain liable to the Partnership for any
additional Capital Contribution required for their proportionate share of any
Partnership obligation or liability arising before the conversion of their Units
as provided in Section 3.05(b)(2).
6.01(b)(3). CONVERSION SHALL NOT AFFECT ALLOCATIONS. The conversion shall not
affect the allocation to any Participant of any item of Partnership income,
gain, loss, deduction or credit or other item of special tax significance other
than Partnership liabilities, if any. Further, the conversion shall not affect
any Participant's interest in the Partnership's natural gas and oil properties
and unrealized receivables.
6.01(b)(4). RIGHT TO CONVERT IF REDUCTION OF INSURANCE. Notwithstanding the
foregoing, the Managing General Partner shall notify all Participants at least
30 days before the effective date of any adverse material change in the
Partnership's insurance coverage. If the insurance coverage is to be materially
reduced, then the Investor General Partners shall have the right to convert
their Units into Limited Partner Units before the reduction by giving written
notice to the Managing General Partner.
6.02. SPECIAL RESTRICTIONS ON TRANSFERS.
6.02(a). IN GENERAL. Transfers are subject to the following general conditions:
(i) except as provided by operation of law:
(a) only whole Units may be assigned unless the
Participant owns less than a whole Unit, in which
case his entire fractional interest must be assigned;
and
(b) Units may not be assigned to a person who is under
the age of 18 or incompetent (unless an
attorney-in-fact, guardian, custodian or conservator
has been appointed to handle the affairs of that
person) without the Managing General Partner's
consent;
(ii) the costs and expenses associated with the assignment must be
paid by the assignor Participant;
(iii) the assignment must be in a form satisfactory to the Managing
General Partner; and
44
(iv) the terms of the assignment must not contravene those of this
Agreement.
Transfers of Units are subject to the following additional restrictions set
forth in Sections 6.02(a)(1) and 6.02(a)(2).
6.02(a)(1). TAX LAW RESTRICTIONS. Subject to transfers permitted by Section 6.04
and transfers by operation of law, no sale, assignment, exchange, or transfer of
a Unit shall be made which, in the opinion of counsel to the Partnership, would
result in the Partnership being either:
(i) terminated for tax purposes under Section 708 of the Code; or
(ii) treated as a "publicly-traded" partnership for purposes of
Section 469(k) of the Code.
6.02(a)(2). SECURITIES LAWS RESTRICTION. Subject to transfers permitted by
Section 6.04 and transfers by operation of law, no Unit shall be sold, assigned,
pledged, hypothecated, or transferred 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 are also subject to any conditions contained in the Subscription
Agreement and Exhibit (B) to the Prospectus.
6.02(a)(3). SUBSTITUTE PARTICIPANT.
6.02(a)(3)(a). PROCEDURE TO BECOME SUBSTITUTE PARTICIPANT. Subject to Sections
6.02(a)(1) and 6.02(a)(2), an assignee of a Participant's Unit shall become a
substituted Participant entitled to all the rights of a Participant if, and only
if:
(i) the assignor gives the assignee the right;
(ii) the assignee pays to the Partnership all costs and expenses
incurred in connection with the substitution; and
(iii) the assignee executes and delivers the instruments necessary
to establish that a legal transfer has taken place and to
confirm the agreement of the assignee to be bound by all of
the terms of this Agreement.
6.02(a)(3)(b). RIGHTS OF SUBSTITUTE PARTICIPANT. A substitute Participant is
entitled to all of the rights attributable to full ownership of the assigned
Units including the right to vote.
6.02(b). EFFECT OF TRANSFER.
6.02(b)(1). AMENDMENT OF RECORDS. The Partnership shall amend its records at
least once each calendar quarter to effect the substitution of substituted
Participants.
Any transfer permitted under this Agreement when the assignee does not become a
substituted Participant shall be effective as follows:
(i) midnight of the last day of the calendar month in which it is
made; or
(ii) at the Managing General Partner's election, 7:00 A.M. of the
following day.
6.02(b)(2). TRANSFER DOES NOT RELIEVE TRANSFEROR OF CERTAIN COSTS. No transfer,
including a transfer of less than all of a Participant's Units or the transfer
of Units to more than one party, shall relieve the transferor of its
responsibility for its proportionate part of any expenses, obligations and
liabilities under this Agreement related to the Units so transferred, whether
arising before or after the transfer.
45
6.02(b)(3). TRANSFER DOES NOT REQUIRE AN ACCOUNTING. No transfer of a Unit shall
require an accounting by the Managing General Partner. Also, no transfer shall
grant rights under this Agreement, including the exercise of any elections, as
between the transferring parties and the remaining parties to this Agreement to
more than one party unanimously designated by the transferees and, if he should
have retained an interest under this Agreement, the transferor.
6.02(b)(4). NOTICE. Until the Managing General Partner receives a proper notice
of designation acceptable to it, the Managing General Partner shall continue to
account only to the person to whom it was furnishing notices before the time
pursuant to Section 8.01 and its subsections. This party shall continue to
exercise all rights applicable to the Units previously owned by the transferor.
6.03. RIGHT OF MANAGING GENERAL PARTNER TO HYPOTHECATE AND/OR WITHDRAW ITS
INTERESTS. The Managing General Partner shall have the authority without the
consent of the Participants and without affecting the allocation of costs and
revenues received or incurred under this Agreement, to hypothecate, pledge, or
otherwise encumber, on any terms it chooses for its own general purposes either:
(i) its Partnership interest; or
(ii) an undivided interest in the assets of the Partnership equal
to or less than its respective interest in the revenues of the
Partnership.
All repayments of these borrowings and costs, interest or other charges related
to the borrowings shall be borne and paid separately by the Managing General
Partner. In no event shall the repayments, costs, interest, or other charges
related to the borrowing be charged to the account of the Participants.
In addition, subject to a required participation of not less than 1% in the
Partnership as Managing General Partner, the Managing General Partner may
withdraw a property interest held by the Partnership in the form of a Working
Interest in the Partnership's Wells equal to or less than its respective
interest in the revenues of the Partnership if:
(i) the withdrawal is necessary to satisfy the bona fide request
of its creditors; or
(ii) the withdrawal is approved by Participants whose Units equal a
majority of the total Units.
6.04. PRESENTMENT.
6.04(a). IN GENERAL. Participants shall have the right to present their Units to
the Managing General Partner for purchase subject to the conditions and
limitations set forth in this section. A Participant, however, is not obligated
to present his Units for purchase.
The Managing General Partner shall not be obligated to purchase more than 5% of
the Units in any calendar year and this 5% limit may not be waived. The Managing
General Partner shall not purchase less than one Unit unless the lesser amount
represents the Participant's entire interest in the Partnership, however, the
Managing General Partner may waive this limitation.
A Participant may present his Units in writing to the Managing General Partner
every year beginning with the fifth calendar year after the Offering Termination
Date subject to the following conditions:
(i) the presentment must be made within 120 days of the reserve
report set forth in Section 4.03(b)(3);
(ii) in accordance with Treas. Reg. Section 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.
46
6.04(b). REQUIREMENT FOR INDEPENDENT PETROLEUM CONSULTANT. The amount of the
presentment price attributable to Partnership reserves shall be determined based
on the last reserve report of the Partnership prepared by the Managing General
Partner and reviewed by an Independent Expert. The Managing General Partner
shall estimate the present worth of future net revenues attributable to the
Partnership's interest in the Proved Reserves. In making this estimate, the
Managing General Partner shall use the following terms:
(i) a discount rate equal to 10%;
(ii) a constant price for the oil; and
(iii) base the price of natural gas on the existing natural gas
contracts at the time of the purchase.
The calculation of the presentment price shall be as set forth in Section
6.04(c).
6.04(c). CALCULATION OF PRESENTMENT PRICE. The presentment price shall be based
on the Participant's share of the net assets and liabilities of the Partnership
and allocated pro rata to each Participant in the ratio that his number of Units
bears to the total number of Units. The presentment price shall include the sum
of the following Partnership items:
(i) an amount based on 70% of the present worth of future net
revenues from the Proved Reserves determined as described in
Section 6.04(b);
(ii) cash on hand;
(iii) prepaid expenses and accounts receivable less a reasonable
amount for doubtful accounts; and
(iv) the estimated market value of all assets, not separately
specified above, determined in accordance with standard
industry valuation procedures.
There shall be deducted from the foregoing sum the following items:
(i) an amount equal to all debts, obligations, and other
liabilities, including accrued expenses; and
(ii) any distributions made to the Participants between the date of
the request and the actual payment. However, if any cash
distributed was derived from the sale after the presentment
request of natural gas, oil or other mineral production, or of
a producing property owned by the Partnership, for purposes of
determining the reduction of the presentment price, the
distributions shall be discounted at the same rate used to
take into account the risk factors employed to determine the
present worth of the Partnership's Proved Reserves.
6.04(d). FURTHER ADJUSTMENT MAY BE ALLOWED. The presentment price may be further
adjusted by the Managing General Partner for estimated changes therein from the
date of the report to the date of payment of the presentment price to the
Participants because of the following:
(i) the production or sales of, or additions to, reserves and
lease and well equipment, sale or abandonment of Leases, and
similar matters occurring before the request for purchase; and
(ii) any of the following occurring before payment of the
presentment price to the selling Participants:
(a) changes in well performance;
(b) increases or decreases in the market price of natural
gas, oil or other minerals;
(c) revision of regulations relating to the importing of
hydrocarbons;
(d) changes in income, ad valorem, and other tax laws
such as material variations in the provisions for
depletion; and
(e) similar matters.
47
6.04(e). SELECTION BY LOT. If less than all Units presented at any time are to
be purchased, then the Participants whose Units are to be purchased will be
selected by lot.
The Managing General Partner's obligation to purchase Units presented may be
discharged for its benefit by a third-party or an Affiliate. The Units of the
selling Participant will be transferred to the party who pays for it. A selling
Participant will be required to deliver an executed assignment of his Units,
together with any other documentation as the Managing General Partner may
reasonably request.
6.04(f). NO OBLIGATION OF THE MANAGING GENERAL PARTNER TO ESTABLISH A RESERVE.
The Managing General Partner shall have no obligation to establish any reserve
to satisfy the presentment obligations under this section.
6.04(g). SUSPENSION OF PRESENTMENT FEATURE. The Managing General Partner may
suspend this presentment feature by so notifying Participants at any time if it:
(i) does not have sufficient cash flow; or
(ii) is unable to borrow funds for this purpose on terms it deems
reasonable.
In addition, the presentment feature may be conditioned, in the Managing General
Partner's sole discretion, on the Managing General Partner's receipt of an
opinion of counsel that the transfers will not cause the Partnership to be
treated as a "publicly traded partnership" under the Code.
The Managing General Partner shall hold the purchased Units for its own account
and not for resale.
ARTICLE VII
DURATION, DISSOLUTION, AND WINDING UP
7.01. DURATION.
7.01(a). FIFTY YEAR TERM. The Partnership shall continue in existence for a term
of 50 years from the effective date of this Agreement unless sooner terminated
as set forth below.
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.
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 Section 706(c)(2)(A) of the Code;
or
48
(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 Section 1.03.
If there is a transfer of Units under this Agreement, no notice to the
transferee shall be required, nor shall the transferee have any rights under
this Agreement, until notice has been given to the Managing General Partner.
Any transfer of rights under this Agreement shall not increase the duty to give
notice. If there is a transfer of Units under this Agreement to more than one
party, then notice to any owner of any interest in the Units shall be notice to
all owners of the Units.
8.01(b). CHANGE IN ADDRESS. The address of any party to this Agreement may be
changed by written notice as follows:
(i) to the Participants if there is a change of address by the
Managing General Partner; or
(ii) to the Managing General Partner if there is a change of
address by a Participant.
49
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 Section 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 Section 5.01(c)(3);
(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
50
(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:
--------------------------------
51
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 Section 3.03(b)(1) of the Partnership Agreement;
and
3. to subscribe to the Partnership as follows:
(a) $___________________ [________] Unit(s)] under
Section 3.03(b)(2) of the Partnership Agreement as a
Limited Partner; or
(b) $___________________ [________] Unit(s)] under
Section 3.03(b)(2) of the Partnership Agreement as an
Investor General Partner.
MANAGING GENERAL PARTNER:
Atlas Resources, Inc. Address:
By:
---------------------------------- 311 Rouser Road
Moon Township, Pennsylvania 15108
ACCEPTED this ________ day of __________________ , 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.
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
1
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.
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 KENTUCKY, o OREGON,
o ALASKA, o LOUISIANA, o PENNSYLVANIA,
o ARIZONA, o MAINE, o RHODE ISLAND,
o ARKANSAS, o MARYLAND, o SOUTH CAROLINA,
o COLORADO, o MASSACHUSETTS, o SOUTH DAKOTA,
o CONNECTICUT, o MINNESOTA, o TENNESSEE,
o DELAWARE, o MISSISSIPPI, o TEXAS,
o DISTRICT OF COLUMBIA, o MISSOURI, o UTAH,
o FLORIDA, o MONTANA, o VERMONT,
o GEORGIA, o NEBRASKA, o VIRGINIA,
o HAWAII, o NEVADA, o WASHINGTON
o IDAHO, o NEW MEXICO o WEST VIRGINIA,
o ILLINOIS, o NEW YORK, o WISCONSIN, OR
o INDIANA, o NORTH DAKOTA, o WYOMING,
o IOWA, o OHIO,
o KANSAS, o OKLAHOMA,
then I must have either: 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 OHIO,
or PENNSYLVANIA, then I must not make
an investment in a partnership which is
in excess of 10% of my net worth,
exclusive of home, home furnishings and
automobiles. Finally, if I am a
resident of KANSAS, it is recommended
by the Office of the Kansas Securities
Commissioner that 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,
o MICHIGAN, o NEW JERSEY, OR
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.
2
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 SOUTH CAROLINA,
o COLORADO, o LOUISIANA, o UTAH,
o CONNECTICUT, o MARYLAND, o VIRGINIA,
o DELAWARE, o MONTANA, o WEST VIRGINIA,
o DISTRICT OF COLUMBIA, o NEBRASKA, o WISCONSIN, OR
o FLORIDA, o NEVADA, o WYOMING,
o GEORGIA, o NEW YORK,
o HAWAII, o NORTH DAKOTA,
o IDAHO, o RHODE ISLAND,
then 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.
3
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 until at
least five business days after the date you receive a final Prospectus, and send
you a confirmation of purchase. 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 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 Section 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.
4
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 PRICE
[ ] 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.
<c>
Subscriber (All individual investors must personally My Home Address (Do not use P.O. Box)
sign this Signature Page.)
My Tax I.D. No. (Social Security No.):
---------------- -----------------------------------------------------
- ------------------------------------------------------- -----------------------------------------------------
Print Name
- ------------------------------------------------------- -----------------------------------------------------
Signature
My Tax I.D. No. (Social Security No.): My Address for Distributions if Different from Above
---------------
- ------------------------------------------------------- -----------------------------------------------------
Print Name
- ------------------------------------------------------- -----------------------------------------------------
Signature
Account No.:
----------------------------------------
I received my final prospectus on
-------------------
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 ________________.
(CHECK ONE): OWNERSHIP OF THE UNITS- [ ] Tenants-in-Common [ ] Partnership
[ ] Joint Tenancy with Right of Survivorship [ ] C Corporation
[ ] Individual [ ] S Corporation
[ ] Trust [ ] Community Property with
Survivorship Rights
[ ] Limited Liability Company [ ] Other
<s> <c>
Date: _______________
My Telephone No.: Business ____________________________ Home ____________________________
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)
5
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.
<s> <c>
- ------------------------------------------------------- -----------------------------------------------------------
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 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)
TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
<s> <c>
ACCEPTED THIS ______ day ATLAS RESOURCES, INC.,
of _________________ , 2005 MANAGING GENERAL PARTNER
By:
------------------------------------------
6
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
- -------------------------------------------------------------------------------------------------------------- ----
<s> <c>
1. Assignment of Well Locations; Representations and Indemnification Associated with the
Assignment of the Lease; Designation of Additional Well Locations;
Outside Activities Are Not Restricted................................................................... 1
2. Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations............. 2
3. Operator - Responsibilities in General; Covenants; Term................................................. 3
4. Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination;
Dry Hole Determination; Excess Funds and Cost Overruns - Intangible Drilling Costs; Excess
Funds and Cost Overruns - Tangible Costs................................................................ 4
5. Title Examination of Well Locations; Developer's Acceptance and Liability; Additional Well Locations.... 7
6. Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs;
Pipelines; Price Determinations; Plugging and Abandonment............................................... 8
7. Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for
Sale Proceeds; Records and Reports; Additional Information.............................................. 9
8. Operator's Lien; Right to Collect From Oil or Gas Purchaser............................................. 11
9. Successors and Assigns; Transfers; Appointment of Agent................................................. 11
10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability................................... 12
11. Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind................ 13
12. Effect of Force Majeure; Definition of Force Majeure; Limitation......................................... 14
13. Term..................................................................................................... 14
14. Governing Law; Invalidity................................................................................ 14
15. Integration; Written Amendment........................................................................... 15
16. Waiver of Default or Breach.............................................................................. 15
17. Notices.................................................................................................. 15
18. Interpretation........................................................................................... 15
19. Counterparts............................................................................................. 15
Signature Page........................................................................................... 15
Exhibit A Description of Leases and Initial Well Locations
Exhibits A-l through A-___ Maps of Initial Well Locations
Exhibit B Form of Assignment
Exhibit C Form of Addendum
DRILLING AND OPERATING AGREEMENT
THIS AGREEMENT made this ______ day of _______________, 200____, by and between
ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as
"Atlas" or "Operator"),
and
ATLAS AMERICA PUBLIC #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.
1
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
2
be owned by the Developer in proportion to the share of the
Working Interest owned by the Developer in the wells.
(e) RIGHT TO SUBSTITUTE WELL LOCATIONS. Notwithstanding the
provisions of sub-section (a) above, if the Operator or
Developer determines in good faith, with respect to any Well
Location, before operations begin under this Agreement on the
Well Location, that it would not be in the best interest of
the parties to drill a well on the Well Location, then the
party making the determination shall notify the other party of
its determination and its basis for its determination and,
unless otherwise instructed by Developer, the well shall not
be drilled. This determination may be based on:
(i) the production or failure of production of any other
wells which may have been recently drilled in the
immediate area of the Well Location;
(ii) newly discovered title defects; or
(iii) any other evidence with respect to the Well Location
as may be obtained.
If the well is not drilled, then Operator shall promptly
propose a new well location (including all information for the
Well Location as Developer may reasonably request) to be
substituted for the original Well Location. Developer shall
then have seven (7) business days to either reject or accept
the proposed new well location. If the new well location is
rejected, then Operator shall promptly propose another
substitute well location pursuant to the provisions of this
sub-section.
Once the Developer accepts a substitute well location or does
not reject it within said seven (7) day period, this Agreement
shall terminate as to the original Well Location and the
substitute well location shall become subject to the terms and
conditions of this Agreement.
3. OPERATOR - RESPONSIBILITIES IN GENERAL; COVENANTS; TERM.
(a) OPERATOR - RESPONSIBILITIES IN GENERAL. Atlas shall be the
Operator of the wells and Well Locations subject to this
Agreement and, as the Developer's independent contractor,
shall, in addition to its other obligations under this
Agreement do the following:
(i) arrange for drilling and completing the wells and, if
a gas well, installing the necessary gas gathering
line systems and connection facilities;
(ii) make the technical decisions required in drilling,
testing, completing, and operating the wells;
(iii) manage and conduct all field operations in connection
with the drilling, testing, completing, equipping,
operating, and producing the wells;
(iv) maintain all wells, equipment, gathering lines if a
gas well, and facilities in good working order during
their useful lives; and
(v) perform the necessary administrative and accounting
functions.
In performing the work contemplated by this Agreement,
Operator is an independent contractor with authority to
control and direct the performance of the details of the work.
(b) COVENANTS. Operator covenants and agrees that under this
Agreement:
(i) it shall perform and carry on (or cause to be
performed and carried on) its duties and obligations
in a good, prudent, diligent, and workmanlike manner
using technically sound, acceptable oil and gas field
practices then prevailing in the geographical area of
the Well Locations;
(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
3
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.
(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
4
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.
5
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.
6
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).
7
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.
8
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
10
Agreement. The Developer and its authorized employees, agents
and consultants, including independent accountants shall, at
Developer's sole cost and expense:
(i) on at least ten (10) days' written notice have access
during normal business hours to all of Operator's
records pertaining to operations, including without
limitation, the right to audit the books of account
of Operator relating to all receipts, costs, charges,
expenses and disbursements under this Agreement,
including information regarding the separate account
required under sub-section (c); and
(ii) have access, at its sole risk, to any wells drilled
by Operator under this Agreement at all times to
inspect and observe any machinery, equipment and
operations.
8. OPERATOR'S LIEN; RIGHT TO COLLECT FROM OIL OR GAS PURCHASER.
(a) OPERATOR'S LIEN. To secure the payment of all sums due from
Developer to Operator under the provisions of this Agreement
the Developer grants Operator a first and preferred lien on
and security interest in the following:
(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
13
Developer's collection agent in any contracts. On request,
Operator shall assist Developer in arranging the sale or
disposition of Developer's oil and gas under this Agreement
and shall promptly provide the Developer with all relevant
information which comes to Operator's attention regarding
opportunities for sale of production.
If Developer fails to take in kind or separately dispose of
its proportionate share of the oil and gas produced under this
Agreement, then Operator shall have the right, subject to the
revocation at will by the Developer, but not the obligation,
to purchase the oil and gas or sell it to others at any time
and from time to time, for the account of the Developer at the
best price obtainable in the area for the production.
Notwithstanding, Operator shall have no liability to Developer
should Operator fail to market the production.
Any purchase or sale by Operator shall be subject always to
the right of the Developer to exercise at any time its right
to take in-kind, or separately dispose of, its share of oil
and gas not previously delivered to a purchaser. Any purchase
or sale by Operator of any other party's share of oil and gas
shall be only for reasonable periods of time as are consistent
with the minimum needs of the oil and gas industry under the
particular circumstances, but in no event for a period in
excess of one (1) year.
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
Exhibit C
(Page 1)
respective successors and permitted assigns.
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.
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 MAINE; o MINNESOTA;
o ARKANSAS; o MASSACHUSETTS; o NORTH CAROLINA;
1
o OHIO; o PENNSYLVANIA; o TEXAS; OR
o OKLAHOMA; o TENNESSEE; o WASHINGTON.
and you purchase investor general partner units, then you must meet any one of
the following special suitability requirements:
o an individual or joint net worth with your spouse of
$225,000 or more, without regard to the investment in the
partnership, exclusive of home, home furnishings and
automobiles, and A COMBINED GROSS INCOME OF $100,000 OR MORE
FOR THE CURRENT YEAR AND FOR THE TWO PREVIOUS YEARS; or
o an individual or joint net worth with your spouse in excess
of $1 million, inclusive of home, home furnishings and
automobiles; or
o an individual or joint net worth with your spouse in excess
of $500,000, exclusive of home, home furnishings and
automobiles; or
o a combined "gross income" as defined in Section 61 of the
Internal Revenue Code of 1986, as amended, in excess of
$200,000 in the current year and the two previous years.
III. If you are a resident of any of the following states:
o ARIZONA; o KENTUCKY; o NEW MEXICO;
o INDIANA; o MICHIGAN; o OREGON;
o IOWA; o MISSISSIPPI; o SOUTH DAKOTA; OR
o KANSAS; o MISSOURI; o VERMONT;
and you purchase investor general partner units, then you must meet any one of
the following special suitability requirements:
o an individual or joint net worth with your spouse of
$225,000 or more, without regard to the investment in the
partnership, exclusive of home, home furnishings and
automobiles, AND A COMBINED "TAXABLE INCOME" OF $60,000 OR
MORE FOR THE PREVIOUS YEAR AND EXPECT TO HAVE A COMBINED
"TAXABLE INCOME" OF $60,000 OR MORE FOR THE CURRENT YEAR AND
FOR THE SUCCEEDING YEAR; or
o an individual or joint net worth with your spouse in excess
of $1 million, inclusive of home, home furnishings and
automobiles; or
o an individual or joint net worth with your spouse in excess
of $500,000, exclusive of home, home furnishings and
automobiles; or
o a combined "gross income" as defined in Section 61 of the
Internal Revenue Code of 1986, as amended, in excess of
$200,000 in the current year and the two previous years.
IV. In addition, if you are a resident of any of the following states:
o IOWA; o OHIO; OR
o MICHIGAN; o PENNSYLVANIA;
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.
2
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.
SPECIAL REPRESENTATIONS OF SUBSCRIBERS IN
CALIFORNIA, NORTH CAROLINA AND PENNSYLVANIA.
I. If a resident of CALIFORNIA, I am aware that:
IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS
SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY
CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF
THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA,
EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES.
As a condition of qualification of the units for sale in the State of
California, the following rule is hereby delivered to each California purchaser.
CALIFORNIA ADMINISTRATIVE CODE, TITLE 10, CH. 3, RULE 260.141.11. RESTRICTION ON
TRANSFER.
(a) The issuer of any security upon which a restriction on
transfer has been imposed pursuant to Sections 260.102.6,
260.141.10 and 260.534 shall cause a copy of this section to
be delivered to each issuee or transferee of such security
at the time the certificate evidencing the security is
delivered to the issuee or transferee.
(b) It is unlawful for the holder of any such security to
consummate a sale or transfer of such security, or any
interest therein, without the prior written consent of the
Commissioner (until this condition is removed pursuant to
Section 260.141.12 of these rules), except:
(i) to the issuer;
(ii) pursuant to the order or process of any court;
(iii) to any person described in Subdivision (i) of
Section 25102 of the Code or Section 260.105.14 of
these rules;
(iv) to the transferor's ancestors, descendants or
spouse, or any custodian or trustee for the account
of the transferor's ancestors, descendants or
spouse, or to a transferee by a trustee or custodian
for the account of the transferee or the
transferee's ancestors, descendants or spouse;
(v) to holders of securities of the same class of the
same issuer;
(vi) by way of gift or donation inter vivos or on death;
(vii) by or through a broker-dealer licensed under the
Code (either acting as such or as a finder) to a
resident of a foreign state, territory or country
who is neither domiciled in this state to the
knowledge of the broker-dealer, nor actually present
in this state if the sale of such securities is not
in violation of any securities law of the foreign
state, territory or country concerned;
(viii) to a broker-dealer licensed under the Code in a
principal transaction, or as an underwriter or
member of an underwriting syndicate or selling
group;
(ix) if the interest sold or transferred is a pledge or
other lien given by the purchaser to the seller upon
a sale of the security for which the Commissioner's
written consent is obtained or under this rule not
required;
(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;
3
(xi) by a corporation or wholly-owned subsidiary of such
corporation, or by a wholly-owned subsidiary of a
corporation to such corporation;
(xii) by way of an exchange qualified under Sections
25111, 25112 or 25113 of the Code, provided that no
order under Section 25140 or Subdivision (a) of
Section 25143 is in effect with respect to such
qualification;
(xiii) between residents of foreign states, territories or
countries who are neither domiciled nor actually
present in this state;
(xiv) to the State Controller pursuant to the Unclaimed
Property Law or to the administrator of the
unclaimed property law of another state;
(xv) by the State Controller pursuant to the Unclaimed
Property Law or by the administrator of the
unclaimed property law of another state if, in
either such case, such person (i) discloses to
potential purchasers at the sale that transfer of
the securities is restricted under this rule, (ii)
delivers to each purchaser a copy of this rule, and
(iii) advises the Commissioner of the name of each
purchaser;
(xvi) by a trustee to a successor trustee when such
transfer does not involve a change in the beneficial
ownership of the securities;
(xvii) by way of an offer and sale of outstanding
securities in an issuer transaction that is subject
to the qualification requirement of Section 25110 of
the Code but exempt from that qualification
requirement by subdivision (f) of Section 25102;
provided that any such transfer is on the condition that any
certificate evidencing the security issued to such
transferee shall contain the legend required by this
section.
(c) The certificates representing all such securities subject to
such a restriction on transfer, whether upon initial
issuance or upon any transfer thereof, shall bear on their
face a legend, prominently stamped or printed thereon in
capital letters of not less than 10-point size, reading as
follows:
"IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS
SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY
CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF
THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA,
EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES."
II. If a resident of 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.
4
ATLAS AMERICA
PUBLIC #15-2005 PROGRAM
----------
PROSPECTUS
----------
TABLE OF CONTENTS
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.....................................................27
Terms of the Offering............................................34
Prior Activities.................................................41
Management.......................................................51
Management's Discussion and Analysis of Financial Condition,
Results of Operations, Liquidity and Capital Resources...... 57
Proposed Activities..............................................58
Competition, Markets and Regulation..............................72
Participation in Costs and Revenues..............................77
Conflicts of Interest............................................83
Fiduciary Responsibility of the Managing
General Partner.................................................94
Federal Income Tax Consequences..................................95
Summary of Partnership Agreement................................120
Summary of Drilling and Operating Agreement.....................122
Reports to Investors............................................123
Presentment Feature.............................................124
Transferability of Units........................................126
Plan of Distribution............................................127
Sales Material..................................................130
Legal Opinions..................................................131
Experts.........................................................131
Litigation......................................................132
Financial Information Concerning the Managing General
Partner and Atlas America Public #15-2005(A) L.P. .............132
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.
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.
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The expenses to be incurred in connection with the issuance and distribution of
the securities to be registered, other than underwriting discounts, commissions
and expense allowances, are estimated to be as follows:
Accounting Fees and Expenses...................................................................$ 60,000*
Legal Fees (including Blue Sky) and Expenses.......................................................200,000*
Printing...........................................................................................345,000*
SEC Registration Fee.............................................................................. .17,655
Blue Sky Filing Fees (excluding legal fees)........................................................181,690*
NASD Filing Fee.....................................................................................15,500
Miscellaneous......................................................................................370,000*
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Total......................................................$ 1,189,845*
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*Estimated
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Title 8, Section 141 of the Delaware Code provides for indemnification of
officers, directors, employees and agents by a corporation subject to certain
limitations.
Under Section 4.05 of the Amended and Restated Certificate and Agreement of
Limited Partnership, the Participants, within the limits of their Capital
Contributions, and the Partnership, generally agree to indemnify and exonerate
the Managing General Partner, the Operator and their Affiliates from claims of
liability to any third party arising out of operations of the Partnership
provided that:
o they determined in good faith that the course of conduct which
caused the loss or liability was in the best interest of the
Partnership;
o they were acting on behalf of or performing services for the
Partnership; and
o the course of conduct was not the result of their negligence or
misconduct.
Paragraph 11 of the Dealer-Manager Agreement provides for the indemnification of
the Managing General Partner, the Partnership and control persons under
specified conditions by the Dealer-Manager and/or Selling Agent.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.
None by the Registrant.
Atlas Resources, Inc. ("Atlas"), an Affiliate of the Registrant, has made sales
of unregistered and registered securities within the last three years. See the
section of the Prospectus captioned "Prior Activities" regarding the sale of
limited and general partner interests. In the opinion of Atlas, the foregoing
unregistered securities in each case have been and/or are being offered and sold
in compliance with exemptions from registration provided by the Securities Act
of 1933, as amended, including the exemptions provided by Section 4(2) of that
Act and certain rules and regulations promulgated thereunder. The securities in
each case have been and/or are being offered and sold to a limited number of
persons who had the sophistication to understand the merits and risks of the
investment and who had the financial ability to bear such risks. The units of
limited and general partner interests were sold to persons who were Accredited
Investors, as that term is defined in Regulation D (17 CFR 230.501(a)), or who
had, at the time of purchase, 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 $125,000 and gross income of at least
$75,000, or otherwise satisfied Atlas that the investment was suitable.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) Exhibits
1
1(a) Proposed form of Dealer-Manager Agreement with Anthem
Securities, Inc.
3(a) Articles of Incorporation of Atlas Resources, Inc.
3(b) Bylaws of Atlas Resources, Inc.
4(a) Certificate of Limited Partnership for Atlas America Public
#15-2005(A) L.P.
4(b) Certificate of Limited Partnership for Atlas America Public
#15-2006(B) L.P.
4(c) Certificate of Limited Partnership for Atlas America Public
#15-2006(C) L.P.
4(d) 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.]
(See Exhibit (A) to Prospectus)
5 Opinion of Kunzman & Bollinger, Inc. as to the legality of the
Units
8 Opinion of Kunzman & Bollinger, Inc. as to tax matters
10(a) Escrow Agreement for Atlas America Public #15-2005(A) L.P.
10(b) Form of Drilling and Operating Agreement for Atlas America
Public #15-2005(A) L.P. [Atlas America Public #15-2006(___)
L.P.] (See Exhibit (II) to the Form of Limited Partnership
Agreement, Exhibit (A) to Prospectus)
10(c) Gas Purchase Agreement dated March 31, 1999 between Northeast
Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas
Resources, Inc., and Resource Energy, Inc.
10(d) Guaranty dated August 12, 2003 between First Energy Corp. and
Atlas Resources, Inc. to Gas Purchase Agreement dated March 31,
1999 between Northeast Ohio Gas Marketing, Inc., and Atlas
Energy Group, Inc., Atlas Resources, Inc., and Resource Energy,
Inc.
10(e) Master Natural Gas Gathering Agreement dated February 2, 2000
among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating
Partnership, L.P., Atlas America, Inc., Resource Energy, Inc.,
and Viking Resources Corporation
10(f) Omnibus Agreement dated February 2, 2000 among Atlas America,
Inc., Resource Energy, Inc., and Viking Resources Corporation,
and Atlas Pipeline Operating Partnership, L.P., and Atlas
Pipeline Partners, L.P.
10(g) Natural Gas Gathering Agreement dated January 1, 2002 among
Atlas Pipeline Partners, L.P., and Atlas Pipeline Operating
Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy
Group, Inc. and Atlas Noble Corporation, and Resource Energy
Inc., and Viking Resources Corporation
10(h) Base Contract for Sale and Purchase of Natural Gas dated
November 13, 2002 Between UGI Energy Services, Inc. and Viking
Resources Corp.
10(i) Guaranty dated June 1, 2004 between UGI Corporation and Viking
Resources Corp.
10(j) Guaranty as of December 7, 2004 between FirstEnergy Corp. and
Atlas Resources, Inc.
10(k) Confirmation of Gas Purchase and Sales Agreement dated November
17, 2004 between Atlas Resources, Inc. et. al. and First Energy
Solutions Corp. for the period from April 1, 2006 through March
31, 2007 production/calendar periods
10(l) Transaction Confirmation dated December 14, 2004 between Atlas
America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK
2
10(m) Drilling and Operating Agreement Dated September 15, 2004 by and
between Atlas America, Inc. and Knox Energy, LLC
10(n) Guaranty dated January 1, 2005 between UGI Corporation and
Viking Resources Corp.
23(a) Consent of Independent Certified Public Accountants
23(b) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)
23(c) Consent of Wright & Company, Inc.
24 Power of Attorney
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(b) Financial Statement Schedules
All financial statement schedules are omitted because the information is
not required, is not material or is otherwise included in the financial
statements or related notes thereto.
ITEM 17. UNDERTAKINGS.
(a) The undersigned Registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this Registration Statement:
(i) To include any Prospectus required by Section 10(a)(3) of
the Securities Act of 1933.
(ii) To reflect in the Prospectus any facts or events arising
after the effective date of the Registration Statement (or
the most recent Post-Effective Amendment thereof) which,
individually or in the aggregate, represent a fundamental
change in the information set forth in the Registration
Statement. Notwithstanding the foregoing, any increase or
decrease in volume of securities offered (if the total
dollar value of the securities offered would not exceed
that which was registered) and any deviation from the low
or high end of the estimated maximum offering range may be
reflected in the form of prospectus filed with the
Commission pursuant to Rule 424(b) if, in the aggregate,
the changes in volume and price represent no more than a
20% change in the maximum aggregate offering price set
forth in the "Calculation of Registration Fee" table in
the effective registration statement.
(iii) To include any material information with respect to the
plan of distribution not previously disclosed in the
Registration Statement or any material change to such
information in the Registration Statement.
Provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) do
not apply if the registration statement is on Form S-3 or Form
S-8 and the information required to be included in a
post-effective amendment by those paragraphs is contained in
periodic reports filed by the registrant pursuant to section 13
or section 15(d) of the Securities Exchange Act of 1934 that are
incorporated by reference in the registration statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall
be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide
offering thereof.
(3) To remove from registration by means of a post-effective
amendment any of the securities being registered which remain
unsold at the termination of the offering.
The undersigned Registrant hereby undertakes to provide at the closing
specified in the underwriting agreement certificates in such denominations and
registered in such names as required by the underwriters to permit prompt
delivery to each purchaser.
Because acceleration is requested of the effective date of the
Registration Statement pursuant to Rule 461 under the Securities Act, and: (1)
provisions or arrangements exist whereby the Registrant may indemnify a
director, officer or controlling
3
person of the Registrant against liabilities arising under the Securities Act,
or the underwriting agreement contains a provision whereby the Registrant
indemnifies the underwriter or controlling persons of the underwriter against
such liabilities and a director, officer or controlling person of the Registrant
is such an underwriter or controlling person thereof or a member of any firm
which is such an underwriter, and (2) the benefits of such indemnification are
not waived by such persons, the Registrant makes the following undertaking:
Insofar as indemnification for liabilities arising under the Securities
Act of 1933 (the "Act") may be permitted to directors, officers and controlling
persons of the Registrant pursuant to the foregoing provisions, or otherwise,
the Registrant has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as expressed
in the Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
Registrant in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in connection with the
securities being registered, the Registrant will, unless in the opinion of its
counsel the matter has been settled by controlling precedent, submit to a court
of appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Securities Act and will be governed by
the final adjudication of such issue.
The undersigned Registrant hereby undertakes that:
o For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed
as part of this Registration Statement in reliance upon Rule
430A and contained in a form of prospectus filed by the
Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the
Securities Act shall be deemed to be part of this Registration
Statement as of the time it was declared effective.
o For purposes of determining any liability under the Securities
Act, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of
such securities at that time shall be deemed to be the initial
bona fide offering thereof.
4
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in Moon Township,
Pennsylvania on August 9, 2005.
ATLAS AMERICA PUBLIC #15-2005 PROGRAM
(Registrant)
By: Atlas Resources, Inc.,
Managing General Partner
Jack L. Hollander, pursuant By: /s/ Jack L. Hollander
to the Registration Statement, has ---------------------------------
been granted Power of Attorney and is Jack L. Hollander, Senior Vice
signing on behalf of the names shown President - Direct Participation
below, in the capacities indicated. Programs
In accordance with the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
Signature Title Date
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Freddie M. Kotek President, Chief Executive Officer and Chairman of the Board of Directors August 9, 2005
Frank P. Carolas Executive Vice President - Land and Geology and a Director August 9, 2005
Jeffrey C. Simmons Executive Vice President - Operations and a Director August 9, 2005
Nancy J. McGurk Senior Vice President, Chief Financial Officer and Chief Accounting Officer August 9, 2005
As filed with the Securities and Exchange Commission on August 9, 2005
Registration Number 333-_____________
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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EXHIBITS
TO
FORM S-1
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933
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ATLAS AMERICA PUBLIC #15-2005 PROGRAM
(Exact name of Registrant as Specified in its Charter)
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JACK L. HOLLANDER, SENIOR VICE PRESIDENT - DIRECT PARTICIPATION PROGRAMS
ATLAS RESOURCES, INC.
311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108
(412) 262-2830
(Name, Address and Telephone Number of Agent for Service)
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Copies to:
WALLACE W. KUNZMAN, JR., ESQ. JACK L. HOLLANDER
KUNZMAN & BOLLINGER, INC. ATLAS RESOURCES, INC.
5100 N. BROOKLINE, SUITE 600 311 ROUSER ROAD
OKLAHOMA CITY, OKLAHOMA 73112 MOON TOWNSHIP, PENNSYLVANIA 15108
EXHIBIT INDEX
Exhibit No. Description
- ----------- -----------------------------------------------------------------
1(a) Proposed form of Dealer-Manager Agreement with Anthem Securities,
Inc.
3(a) Articles of Incorporation of Atlas Resources, Inc.
3(b) Bylaws of Atlas Resources, Inc.
4(a) Certificate of Limited Partnership for Atlas America Public
#15-2005(A) L.P.
4(b) Certificate of Limited Partnership for Atlas America Public
#15-2006(B) L.P.
4(c) Certificate of Limited Partnership for Atlas America Public
#15-2006(C) L.P.
4(d) 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.] (See
Exhibit (A) to Prospectus)
5 Opinion of Kunzman & Bollinger, Inc. as to the legality of the
Units
8 Opinion of Kunzman & Bollinger, Inc. as to tax matters
10(a) Escrow Agreement for Atlas America Public #15-2005(A) L.P.
10(b) Form of Drilling and Operating Agreement for Atlas America Public
#15-2005(A) L.P. [Atlas America Public #15-2006(___) L.P.] (See
Exhibit (II) to the Form of Limited Partnership Agreement,
Exhibit (A) to Prospectus)
10(c) Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio
Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas
Resources, Inc., and Resource Energy, Inc.
10(d) Guaranty dated August 12, 2003 between First Energy Corp. and
Atlas Resources, Inc. to Gas Purchase Agreement dated March 31,
1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy
Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc.
10(e) Master Natural Gas Gathering Agreement dated February 2, 2000
among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating
Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., and
Viking Resources Corporation
10(f) Omnibus Agreement dated February 2, 2000 among Atlas America,
Inc., Resource Energy, Inc., and Viking Resources Corporation, and
Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline
Partners, L.P.
10(g) Natural Gas Gathering Agreement dated January 1, 2002 among Atlas
Pipeline Partners, L.P., and Atlas Pipeline Operating Partnership,
L.P. and Atlas Resources, Inc., and Atlas Energy Group, Inc. and
Atlas Noble Corporation, and Resource Energy Inc., and Viking
Resources Corporation
10(h) Base Contract for Sale and Purchase of Natural Gas dated November
13, 2002 Between UGI Energy Services, Inc. and Viking Resources
Corp.
10(i) Guaranty dated June 1, 2004 between UGI Corporation and Viking
Resources Corp.
10(j) Guaranty as of December 7, 2004 between FirstEnergy Corp. and
Atlas Resources, Inc.
10(k) Confirmation of Gas Purchase and Sales Agreement dated November
17, 2004 between Atlas Resources, Inc. et. al. and First Energy
Solutions Corp. for the period from April 1, 2006 through March
31, 2007 production/calendar periods
10(l) Transaction Confirmation dated December 14, 2004 between Atlas
America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK
10(m) Drilling and Operating Agreement Dated September 15, 2004 by and
between Atlas America, Inc. and Knox Energy, LLC
10(n) Guaranty dated January 1, 2005 between UGI Corporation and Viking
Resources Corp.
i
Exhibit No. Description
- ---------- -----------------------------------------------------------------
23(a) Consent of Independent Certified Public Accountants
23(b) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)
23(c) Consent of Wright & Company, Inc.
24 Power of Attorney
ii