- ------------------------------------------------------------------------------
As filed with the Securities and Exchange Commission on
September 12, 1997
Registration No. 333-31681
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
PRE-EFFECTIVE AMENDMENT NO. 1
TO
FORM SB-2
REGISTRATION STATEMENT
Under The Securities Act of 1933
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
(Exact name of Registrant as Specified in its Charter)
311 ROUSER ROAD
MOON TOWNSHIP, PENNSYLVANIA 15108
(412) 262-2830
(Address and Telephone Number of
Principal Executive Offices and
Principal Place of Business)
JAMES R. O'MARA, PRESIDENT
ATLAS RESOURCES, INC.
311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108
(412) 262-2830
(Name, Address and Telephone Number of Agent for Service)
Copies to:
WALLACE W. KUNZMAN, JR., ESQ. JAMES R. O'MARA
KUNZMAN & BOLLINGER, INC. ATLAS RESOURCES, INC.
5100 N. BROOKLINE 311 ROUSER ROAD
SUITE 600 MOON TOWNSHIP,
OKLAHOMA CITY, OKLAHOMA 73112 PENNSYLVANIA
15108
Approximate Date of Commencement of Proposed Sale to the Public;
AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES
EFFECTIVE.
If any of the securities being registered on this form are to be
offered on a delayed or continous basis pursuant to Rule 415 under the
Securities Act of 1933, check the following box: [X]
CALCILATION OF REGISTRATION FEE
==============================================================================
Proposed Proposed
Title of Each Dollar Maximum Maximum Amount of
Class of Securities Amount Offering Aggregate
Registration
to be Registered to be Registered Price per Unit Offering Price Fee
Units(1) $10,000,000 $10,000 $10,000,000 $3,030
(1) "Units" means the Limited Partner interests and the Investor
General Partner interests offered to Participants in the Partnership.
THE REGISTRANT HEREBY AMENDS THE 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.
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ATLAS-ENERGY FOR THE NINETIES-PUBLIC NO.6 LTD.
CROSS REFERENCE SHEET
PURSUANT TO RULE 404
ITEM OF FORM SB-2
- ----------------------------------
CAPTION IN PROSPECTUS
1. Front of Registration
Statement and Outside Front
Cover of Prospectus
- ----------------------------------
Front Page of Registration
Statement and Outside Front Cover
Page of Prospectus
=================================
2. Inside Front and
Outside Back Cover Pages of
Prospectus
- ---------------------------------
Inside Front and Outside Back
Cover Pages of Prospectus
=================================
3. Summary Information and
Risk Factors
- --------------------------------
Summary of the Offering; Risk
Factors
================================
4. Use of Proceeds
- --------------------------------
Summary of the Offering;
Capitalization and Source of Funds
and Use of Proceeds
================================
5. Determination of
Offering Price
- --------------------------------
Not Applicable
================================
6. Dilution
- --------------------------------
Not Applicable
================================
7. Selling Security
Holders
- --------------------------------
Not Applicable
================================
8. Plan of Distribution
- --------------------------------
Summary of the Offering; Plan of
Distribution
================================
9. Legal Proceedings
- --------------------------------
Litigation
================================
10. Directors, Executive
Officers, Promoters and
Control Persons
- -------------------------------
Management
===============================
11. Security Ownership of
Certain Beneficial Owners and
Management
- ------------------------------
Management
===============================
12. Description of
Securities
- -------------------------------
Summary of the Offering; Terms of
the Offering; Summary of
Partnership Agreement
===============================
13. Interest of Named
Experts and Counsel
- -------------------------------
Legal Opinions; Experts
===============================
14. Disclosure of
Commission Position on
Indemnification for Securities
Act Liabilities
- -------------------------------
Fiduciary Responsibilities of the
Managing General Partner
===============================
15. Organization Within
Last Five Years
- -------------------------------
Management
===============================
16. Description of
Business
- -------------------------------
Proposed Activities; Management
===============================
17. Management's
Discussion and Analysis or
Plan of Operation
- -------------------------------
Proposed Activities
===============================
18. Description of
Property
A. Issuers Engaged or to
Be Engaged in Significant
Mining Operations
B. Supplementing Financial
Information about Oil and
Gas Producing Activities
- ------------------------------
Proposed Activities
Not Applicable
Not Applicable
=============================
19. Certain Relationships
and Related Transactions
- -----------------------------
Compensation; Management;
Conflicts of Interest
============================
20. Market for Common
Equity and Related Stockholder
Matters
- ----------------------------
Not Applicable
============================
21. Executive Compensation
- ----------------------------
Management
============================
22. Financial Statements
- ----------------------------
Financial Information Concerning
the Managing General Partner,
Atlas Group and the Partnership
============================
23. Changes In and
Disagreements With Accountants
on Accounting and Financial
Disclosure
- ----------------------------
Not Applicable
============================
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- --
Preliminary Prospectus (Subject to Completion) Dated September 12, 1997
Prospectus
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
$1,000,000 Minimum Aggregate Capital Contributions
General and Limited Partner Interests at $10,000 per Unit
Minimum Purchase: 1 Unit ($10,000)
This Prospectus describes an offering of 800 general and limited
partner interests of $10,000 each in Atlas-Energy for the
Nineties-Public #6 Ltd., a limited partnership. Investors in the
Partnership will be admitted either as Investor General Partners or
Limited Partners depending upon their election and whether the
requisite suitability standards are met. See "Summary of the Offering -
Terms of the Offering - Type of Units" for a discussion of the
difference between Investor General Partner Units and Limited Partner
Units. Upon commencement of operations, the Partnership will acquire
Leases for drilling Development Wells thereon, and produce and market
natural gas, if any, derived therefrom. The Partnership is expected to
generate significant tax deductions. (See "Proposed Activities" and
"Tax Aspects".) The Partnership, upon commencement of the offering of
Units, will not have any properties or assets. The Managing General
Partner of the Partnership is Atlas Resources, Inc. ("Atlas"), a
Pennsylvania corporation. Atlas is responsible for the acquisition and
supervision of the Partnership's properties and all other activities of
the Partnership. For the meaning of certain capitalized terms used
herein, see "Definitions".
THESE SECURITIES ARE SPECULATIVE AND ARE SUBJECT TO CERTAIN RISKS
INCLUDING:
? PURCHASE OF THE UNITS INVOLVES A HIGH LEVEL OF RISK; CONSEQUENTLY,
PROSPECTIVE INVESTORS MUST MEET STRICT SUITABILITY STANDARDS
ESTABLISHED BY THE MANAGING GENERAL PARTNER;
? THE DRILLING AND COMPLETION OPERATIONS TO BE UNDERTAKEN BY THE
PARTNERSHIP FOR THE DEVELOPMENT OF GAS RESERVES INVOLVE THE
POSSIBILITY OF A SUBSTANTIAL OR PARTIAL LOSS OF AN INVESTMENT IN THE
PARTNERSHIP BECAUSE OF WELLS WHICH ARE PRODUCTIVE BUT DO NOT PRODUCE
ENOUGH REVENUE TO RETURN THE INVESTMENT MADE;
? THE REVENUES OF THE PARTNERSHIP ARE DIRECTLY RELATED TO THE ABILITY
TO MARKET THE NATURAL GAS AND THE PRICE OF NATURAL GAS WHICH IS
CURRENTLY UNSTABLE AND CANNOT BE PREDICTED AND IF THE PRICE OF GAS
DECREASES THEN THE PARTICIPANT RETURNS WILL DECREASE;
? UNLIMITED JOINT AND SEVERAL LIABILITY FOR PARTNERSHIP OBLIGATIONS
FOR THOSE INVESTORS WHO CHOOSE TO INVEST AS INVESTOR GENERAL
PARTNERS UNTIL THEY CONVERT TO LIMITED PARTNER INTERESTS;
? LACK OF LIQUIDITY OR A MARKET FOR THE UNITS;
? LACK OF CONFLICT OF INTEREST RESOLUTION PROCEDURES, CONSEQUENTLY,
CONFLICTS OF INTEREST BETWEEN THE MANAGING GENERAL PARTNER AND THE
INVESTORS MAY NOT NECESSARILY BE RESOLVED IN THE BEST INTERESTS OF
THE INVESTORS;
? TOTAL RELIANCE ON MANAGING GENERAL PARTNER AND ITS AFFILIATES;
? AUTHORIZATION OF SUBSTANTIAL FEES TO MANAGING GENERAL PARTNER AND
ITS AFFILIATES;
? INVESTORS AND THE MANAGING GENERAL PARTNER WILL SHARE IN COSTS
DISPROPORTIONATELY TO THEIR SHARING OF REVENUES;
? POSSIBLE ALLOCATION OF TAXABLE INCOME TO INVESTORS IN EXCESS OF
THEIR CASH DISTRIBUTIONS FROM THE PARTNERSHIP; AND
? NO GUARANTY OF CASH DISTRIBUTIONS EVERY QUARTER.
(SEE "RISK FACTORS", PAGE 8.)
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
NOR HAS THE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON
THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE
CONTRARY IS A CRIMINAL OFFENSE.
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.
Dealer-Manager Fee,
Price Commissions and Due- Proceeds to Net Proceeds
for
To Public Diligence Reimbusment(3) Partnership(4) Drillig
Costs(5)
Per Unit (1) $10,000 $1,050 $10,000$ $10,000
Minimum (2) $1,000,000 $105,000 $1,000,000 $1,000,000
Maximum (2) $8,000,000 $840,000 $8,000,000 $8,000,000
Potential
Maximum (2) $10,000,000 $1,050,000 $10,000,000 $10,000,000
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<PAGE> ii
(1) The minimum required purchase is one (1) Unit or $10,000;
however, the Managing General Partner, in its discretion, may
accept one-half Unit ($5,000) subscriptions. (See "Terms of the
Offering - Suitability Standards".)
(2) The subscription period will terminate on or before December
31, 1997 ("Offering Termination Date"). The maximum amount of
subscriptions to be accepted from Participants will be $8,000,000
(800 Units), and the minimum amount of subscriptions will be
$1,000,000 (100 Units). However, if subscriptions for all 800 Units
being offered are obtained, the Managing General Partner, in its
sole discretion, may offer not more than 200 additional Units and
increase the maximum aggregate subscriptions with which the
Partnership may be funded to not more than 1,000 Units
($10,000,000). Although the Managing General Partner and its
Affiliates may buy up to 10% of the Units, which will not be
applied towards the minimum Partnership Subscription required for
the Partnership to begin operations, the Managing General Partner
currently does not anticipate that it and its Affiliates will
purchase any Units.
The subscription proceeds will be deposited in an interest bearing
escrow account at National City Bank of Pennsylvania prior to the
receipt of the minimum Partnership Subscription. Subject to the
receipt of the minimum Partnership Subscription, there will be two
closings which are tentatively set for December 1, 1997 ("Initial
Closing Date"), and December 31, 1997. The Partnership will begin
all activities, including drilling, after the Initial Closing Date.
A Participant will receive interest on his Agreed Subscription up
until the Offering Termination Date at the market rate paid by
National City Bank of Pennsylvania.
If subscriptions for $1,000,000 are not received by December 31,
1997, the sums deposited in the escrow account will be returned to
the subscriber with interest thereon. Checks for the full
subscription amount should be made payable to "National City Bank,
Escrow Agent, Atlas Public #6 Ltd." and sent, together with a copy
of the executed subscription, to National City Bank of
Pennsylvania., Corporate Trust Department, 300 Fourth Avenue,
Pittsburgh, Pennsylvania 15278-2331. (See "Terms of the Offering -
Partnership Closings and Escrow".)
(3) The Units will be offered on a "best efforts" basis by Anthem
Securities, Inc., a registered broker-dealer which is a member of
the NASD and a wholly-owned subsidiary of Atlas Group, acting as
Dealer-Manager in all states other than Minnesota and New
Hampshire, and by other selected registered broker-dealers, which
are members of the NASD, acting as Selling Agents. Bryan Funding,
Inc., a member of the NASD, will serve as Dealer-Manager in the
states of Minnesota and New Hampshire, and will receive the same
compensation as Anthem Securities, Inc. with respect to sales in
those states. Best efforts means that the Dealer-Manager and
broker-dealers will not guarantee the sale of a certain amount of
Units.
The Dealer-Manager will manage and oversee the offering of the
Units as described above and will receive from the Partnership on
each Unit sold to investors a 2.5% Dealer-Manager fee, a 7.5% Sales
Commission and a .5% reimbursement of the Selling Agents' bona fide
accountable due diligence expenses. The 7.5% Sales Commission and
the .5% reimbursement of accountable due diligence expenses will be
reallowed to the Selling Agents. Atlas is also utilizing the
services of three wholesalers. One of the wholesalers is associated
with Anthem Securities, Inc., and the other two are associated with
Bryan Funding, Inc. (See "Plan of Distribution".) The 2.5%
Dealer-Manager fee will be reallowed to the wholesalers for Agreed
Subscriptions obtained through such wholesalers' effort.
Subject to the receipt of the minimum Partnership Subscription and
the checks having cleared the banking system, Dealer-Manager fees,
Sales Commissions and accountable due diligence reimbursements will
be paid to the broker-dealers approximately every two weeks until
the Offering Termination Date.
The Dealer-Manager Fee, Sales Commissions and due diligence
reimbursements will be paid by the Managing General Partner and
will not be paid with subscription proceeds. (See "Participation in
Costs and Revenues".)
(4) The Managing General Partner will pay all Organization Costs
associated with the issuance of the Units, which will not exceed
4.5% of Agreed Subscriptions ($450 per Unit). (See "Participation
in Costs and Revenues".)
(5) After the payment of Organization and Offering Costs by the
Managing General Partner, the Partnership will utilize 100% of the
Partnership Subscription to drill and complete Development Wells as
described herein. (See "Proposed Activities".)
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<PAGE>iii
TABLE OF CONTENTS
Summary of the Offering 1
The Partnership 1
Investment Objectives 1
Investment Features 1
Terms of the Offering 2
Reports 2
No Additional Assessments 2
Suitability Standards - Long Term
Investment 3
Partnership Agreement 3
Application of Proceeds 3
Required Capital Contributions of
the Managing General Partner 3
Participation in Costs and Revenues 4
Prior Activities 4
Risk Factors 4
Actions to be Taken by Managing
General Partner to Reduce Risks of
Additional Payments by Investor
General Partners 6
Compensation to the Managing General
Partner, the Operator and their
Affiliates 6
Conflicts of Interest 7
Distribution 8
Risk Factors 8
Special Risks of the Partnership 8
Speculative Nature of Investment 8
Unlimited Liability of Investor
General Partners 8
Illiquid Investment and Restrictions on
Transferability of Participants'
Interests 9
Total Reliance upon the Managing
General Partner 9
Management Obligations of Managing
General Partner Not Exclusive 9
Managing General Partner Liquid
Net Worth IsNot Guaranteed 10
Diversification Depends Upon
Subscription Proceeds 10
Disproportionate Costs Borne by
Participants 10
Compensation and Fees to the
Managing General Partner
Regardless of Success of the
Activities 10
Dry Hole Risk in Development
Drilling 10
Risk of Unproductive Wells in
Development Drilling 10
Risks Regarding Marketing of Gas 10
Possible Delays in Production and
Shut-In Wells 11
Unspecified Location of a Portion
of the Prospects 11
No Guarantee of Data Regarding
Currently Proposed Prospects 12
Atlas' Subordination is not a
Guarantee 12
Borrowings by the Managing General
Partner
Could Reduce Funds Available for
Its Subordination Obligation 12
Possibility of Reduction or
Unavailability of Insurance 12
Possible Nonperformance by
Subcontractors 12
Risk of Prepayment to Atlas 12
Possible Leasehold Defects 12
Partnership Borrowings May Reduce
or Delay Distributions 12
Atlas Will Receive Benefit from
Transferof Leases 13
Other Circumstances Under Which
Distributions May Be Reduced or
Delayed 13
Conflicts of Interest 13
Risk Regarding Participation with
Third Parties 13
Dissolution of the Partnership or
Withdrawal or Removal of the
Managing General Partner May
Have Adverse Effects 13
Indemnification and Exoneration of
The Managing General Partner Would
Reduce Distributions 14
Limited Partner Liability for
Repayment of Certain Distributions 14
Possibility of Unauthorized Acts
of Investor General Partners 14
Risks That Repurchase Obligation
May Not Be Funded and Repurchase
Price May Not Reflect Full Value 14
Possible Participation in Roll-Up 15
General Risks of the Oil and Gas
Business 15
Speculative Nature of Gas Business 15
Risks of Decrease in the Price of Gas 15
Drilling Hazards May Be Encountered 15
Competition in Marketing Natural Gas
Production 15
Risk of New Governmental Regulations 15
Potential Liability for Pollution;
Environmental Matters 16
Uncertainty of Costs 16
Tax Risks 16
Tax Consequences May Vary
Depending on Individual Circumstances 16
Risk of Changes in the Law 16
No Advance Ruling from the IRS on
Tax Consequences 16
Possible Taxes in Excess of Cash
Distributions 16
Partnership Allocations Are
Subject to Challenge
by the IRS in the Event of an Audit 16
1997 Tax Deductions Are Subject to
Challenge
by the IRS in the Event of an Audit 17
Possible Alternative Minimum Tax
Liability 17
Investment Interest Deductions May
Be
Limited 17
Lack of Tax Shelter Registration
17
State and Local Taxes May Apply 17
Capitalization and Source of Funds and
Use of Proceeds 17
In General 17
Source of Funds 18
Use of Proceeds 18
Subsequent Source of Funds and
Borrowings 19
Compensation 19
Oil and Gas Revenues 20
Lease Costs 20
Administrative Costs 20
Drilling Contracts 20
Per Well Charges 20
Transportation and Marketing Fees 21
Dealer-Manager Fees 21
Other Compensation 21
Estimate of Administrative Costs and
Direct Costs to be
Borne by the Partnership 21
Terms Of The Offering 22
Subscription to the Partnership 22
Payment of Subscriptions 22
Partnership Closings and Escrow 22
Offering Period 22
Acceptance of Subscriptions 22
Drilling Period 23
Interest of Participants in the
Partnership 23
Qualification of the Partnership 23
Suitability Standards 23
Subscription by Managing General Partner24
Conflicts of Interest 24
In General 24
Fiduciary Responsibility of the
Managing General Partner 24
Transactions with Atlas and its
Affiliates 25
Conflict Regarding the Drilling and
Operating Agreement 25
Conflicts Regarding Sharing of Costs
and Revenues 25
Tax Matters Partner 26
Other Activities of the Managing
General Partner,
the Operator and their Affiliates 26
Conflicts Involving the Acquisition
of Leases 26
Conflicts Between Participants 28
<PAGE>iv
TABLE OF CONTENTS
Lack of Independent Underwriter and
Due Diligence Investigation 28
Conflicts Concerning Legal Counsel 28
Conflicts Regarding Repurchase
Obligation 29
Other Conflicts 29
Procedures to Reduce Conflicts of
Interest 29
Policy Regarding Roll-Ups 30
Certain Transactions 31
Fiduciary Responsibility of the
Managing General
Partner 31
General 31
Limitations on Managing General
Partner Liability as Fiduciary 32
Limitations on Managing General
Partner Indemnification 32
Prior Activities 33
Management 40
Managing General Partner and
Operator 40
Officers, Directors and Key
Personnel 41
Remuneration 42
Security Ownership of Certain
Beneficial Owners
and Managers 43
Transactions with Management and
Affiliates 44
Investment Objectives 45
Proposed Activities 45
In General 45
Intended Areas of Operations 46
Acquisition of Leases 46
Title to Properties 47
Formation of the Partnership and
Powers of the Managing General Partner 47
Drilling and Completion Activities;
Operation of Producing Wells 48
Sale of Oil and Gas Production 49
Interests of Parties 50
Insurance 50
Use of Consultants and Subcontractors 51
Information Regarding Currently Proposed
Prospects 51
Competition, Markets and Regulation 79
Competition 79
Marketing 79
State Regulations 79
Environmental Regulation 80
Crude Oil Regulation 80
Federal Gas Regulation 80
Proposed Regulation 80
Participation in Costs and Revenues 80
In General 80
Costs 80
Revenues 81
Subordination of Portion of Managing
General Partner's Net Revenue Share 82
Allocation and Adjustment Among
Participants 83
Distributions 83
Tax Aspects 84
Summary of Tax Opinion 84
In General 86
Partnership Classification 86
Limitations on Passive Activities 86
Taxable Year 87
1997 Expenditures 87
Availability of Certain Deductions 87
Intangible Drilling and Development
Costs 88
Drilling Contracts 88
Depletion Allowance 89
Depreciation - Accelerated Cost
Recovery System 89
Leasehold Costs and Abandonment 90
Tax Basis of Participants' Interests 90
Distributions from a Partnership 90
Sale of the Properties 90
Disposition of Partnership Interests 90
Minimum Tax - Tax Preferences 91
Limitations on Deduction of
Investment Interest 91
Allocations 91
"At Risk" Limitation for Losses 92
Partnership Organization and
Syndication Fees 92
Tax Elections 92
Disallowance of Deductions under
Section 183 of the Code 93
Termination of a Partnership 93
Lack of Registration as a Tax Shelter 93
Tax Returns and Audits 93
Penalties and Interest 94
State and Local Taxes 94
Severance, Franchise, and Ad Valorem
(Real Estate) Taxes 94
Social Security Benefits and Self-
Employment Tax 95
Foreign Partners 95
Estate and Gift Taxation 95
Changes in Law 95
Definitions 95
Summary of Partnership Agreement 100
Responsibility of Managing
General Partner 101
Liabilities of General Partners,
Including Investor General Partners 101
Liability of Limited Partners 101
Amendments 101
Notice 101
Voting Rights 102
Access to Records 102
Withdrawal of Managing General Partner 102
Removal of Operator 103
Term and Dissolution 103
Summary of Drilling and Operating
Agreement 103
Reports to Investors 104
Repurchase Obligation 104
Transferability of Units 105
Plan of Distribution 106
Sales Material 107
Legal Opinions 107
Experts 107
Litigation 107
Additional Information 108
Financial Information Concerning the
Managing General Partner, Atlas
Group and the Partnership 108
==========================================
Exhibits
Exhibit (A)
Amended and Restated Certificate and Agreement of Limited Partnership
Exhibit (I-A)
Managing General Partner Signature Page
Exhibit (I-B)
Subscription Agreement
Exhibit (II)
Drilling and Operating Agreement
Exhibit (B)
Special Suitability Requirements and Disclosures to Investors
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<PAGE>1
SUMMARY OF THE OFFERING
This summary is qualified in its entirety by the more detailed
information appearing elsewhere in this Prospectus. Prospective
investors are directed to "Definitions," which defines the capitalized
terms used throughout this Prospectus.
THE PARTNERSHIP
Atlas-Energy for the Nineties-Public #6 Ltd. (the "Partnership"), is a
Pennsylvania limited partnership which includes Atlas Resources, Inc.
("Atlas"), of Pittsburgh, Pennsylvania, as Managing General Partner and
Operator, and subscribers to Units as either Limited Partners or
Investor General Partners. The Partnership will be funded to drill
wells which are located primarily in the Mercer County area of
Pennsylvania, although the Managing General Partner has reserved the
right to use up to 15% of the Partnership Subscription to drill wells
in other areas of the United States. Atlas anticipates that all of the
Partnership's wells will be classified as gas wells which may produce a
small amount of oil. The majority of the wells drilled by the
Partnership will be Development Wells which will test the
Clinton/Medina geological formation ("Clinton/Medina"). For a
description of the Prospects which are currently proposed see "Proposed
Activities - Information Regarding Currently Proposed Prospects".
Atlas and its Affiliates will act as general drilling contractor and
operator for all the wells. (See "Proposed Activities".)
INVESTMENT OBJECTIVES
Except for the historical information contained herein, the matters
discussed below are forward looking statements that involve risks and
uncertainties, including the risk that the Wells are productive but do
not produce enough revenue to return the investment made, Dry Holes,
uncertainties concerning the price of gas, and the other risks detailed
below. The actual results that the Partnership achieves may differ
materially from the objectives set forth below due to such risks and
uncertainties. The Partnership's principal investment objectives are to
invest the Partnership Subscription in natural gas Development Wells
which will:
(1) Provide quarterly cash distributions until the wells are
depleted, (historically 20+ years) with a preferred annual cash
flow of 10% during the first five years based on the original
subscription amount. (See "Risk Factors - Special Risks of the
Partnership - Risk of Unproductive Wells in Development Drilling,"
"Prior Activities" and "Participation in Costs and Revenues -
Subordination of Portion of Managing General Partner's Net Revenue
Share".)
(2) Obtain tax deductions in 1997 from intangible drilling and
development costs to offset a portion of the Participants' taxable
income (subject to the passive activity rules in the case of
Limited Partners). One Unit will produce a 1997 tax deduction of
$8,000 against ordinary income for Investor General Partners and
against passive income for Limited Partners. For an investor in
either the 39.6% or 36% tax bracket, one Unit will save $3,168 or
$2,880 respectively in federal taxes this year. Most states also
allow this type of a deduction against the state income tax.
(3) Offset a portion of any taxable income generated by the
Partnership with tax deductions from percentage depletion,
presently 16% (estimated to be 18% on net revenue). Atlas estimates
that this feature should reduce an investor's effective tax rate
from 39.6% to 33.3% (i.e., 84% of 39.6%) on Partnership net
revenues.
(4) Obtain tax deductions of the remaining 20% of the initial
investment from 1998 through 2005. The investor will receive an
additional $2,000 tax deduction per Unit generated through the
remaining depreciation over a seven-year cost recovery period of
the Partnership's equipment costs for the wells.
ATTAINMENT OF THE PARTNERSHIP'S INVESTMENT OBJECTIVES WILL DEPEND ON
MANY FACTORS, INCLUDING THE ABILITY OF THE MANAGING GENERAL PARTNER TO
SELECT SUITABLE PROSPECTS WHICH WILL BE PRODUCTIVE AND PRODUCE ENOUGH
REVENUE TO RETURN THE INVESTMENT MADE. THE SUCCESS OF THE PARTNERSHIP
DEPENDS LARGELY ON FUTURE ECONOMIC CONDITIONS, ESPECIALLY THE FUTURE
PRICE OF NATURAL GAS WHICH IS VOLATILE.
THERE CAN BE NO GUARANTEE THAT THE FOREGOING OBJECTIVES WILL BE
ATTAINED.
INVESTMENT FEATURES
PREFERRED 10% CASH RETURN (CUMULATIVE 5 YEARS). The Partnership is
structured to provide preferred cash distributions to the Participants
equal to a minimum of 10% of their Agreed Subscription in each of the
first five twelve-month periods of Partnership operations. To help
insure the Participants achieve this investment feature, Atlas will
subordinate a part of its Partnership revenues in an amount up to 10%
of the Partnership Net Production Revenues. (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.) This feature allows the investors to
receive a greater percentage of cash distributions if the Partnership
does not provide the 10% return to Participants as described above. As
of July 15, 1997, all of Atlas' previous five public limited
partnerships are achieving or exceeding the 10% preferred twelve-month
cash distributions. Atlas has subordinated from time to time its
Partnership revenues in all of the five partnerships. (See "Risk
Factors - Special Risks of the Partnership - Borrowings by the Managing
General Partner Could Reduce Funds Available for Its Subordination
Obligation" and "Participation in Costs and Revenues - Subordination
of Portion of Managing General Partner's Net Revenue Share".)
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<PAGE>2
REPURCHASE OBLIGATION. Beginning in 2001, the Participants may present
their interests for repurchase by the Managing General Partner.
Repurchase of Units is subject to certain conditions, including the
financial ability of the Managing General Partner to purchase the
Units. As of July 15, 1997, no Units have been presented to Atlas for
repurchase in its previous five public limited partnerships. (See
"Risk Factors - Special Risks of the Partnership - Risk That Repurchase
Obligation May Not Be Funded and Repurchase Price May Not Reflect Full
Value" and "Repurchase Obligation".)
INVESTOR INTEREST FEATURE. A Participant will receive interest on his
Agreed Subscription up until the Offering Termination Date. The
interest will be paid to Participants approximately eight weeks after
the Offering Termination Date.
TERMS OF THE OFFERING
IN GENERAL. Units of Participation ("Units") are offered at $10,000 per
Unit. The minimum subscription is one Unit; however, the Managing
General Partner, in its discretion, may accept one-half Unit ($5,000)
subscriptions. Larger subscriptions will be accepted in $1,000
increments. Agreed Subscriptions are payable 100% in cash at the time
of subscribing.
The maximum amount of subscriptions to be accepted from Participants
will be $8,000,000 (800 Units), and the minimum amount of subscriptions
will be $1,000,000 (100 Units). However, if subscriptions for all 800
Units being offered are obtained, the Managing General Partner, in its
sole discretion, may offer not more than 200 additional Units and
increase the maximum aggregate subscriptions with which the Partnership
may be funded to not more than 1,000 Units ($10,000,000).
Pending receipt of the minimum Partnership Subscription, subscription
deposits in the escrow account will earn interest at National City Bank
of Pennsylvania's variable market rate for short-term deposits. If the
minimum Partnership Subscription is not received on or before December
31, 1997, subscriptions will be refunded in full with interest earned
thereon. Although the Managing General Partner and its Affiliates may
buy up to 10% of the Units, which will not be applied towards the
minimum Partnership Subscription required for the Partnership to begin
operations, the Managing General Partner currently does not anticipate
that it and its Affiliates will purchase any Units. For a full
discussion of the various terms of the offering, see "Terms of the
Offering".
ESCROW ACCOUNT. The subscription proceeds will be deposited in an
interest bearing escrow account at National City Bank of Pennsylvania,
Pittsburgh, Pennsylvania until the receipt of the minimum Partnership
Subscription after which the funds will be paid directly to the
Partnership account. Subject to receipt of the minimum Partnership
Subscription, there will be two closings which are tentatively set for
December 1, 1997 ("Initial Closing Date"), and December 31, 1997. The
Partnership will begin its activities, including drilling, after the
Initial Closing Date. (See "Terms of the Offering - Partnership
Closings and Escrow".)
TYPE OF UNITS. Participants may purchase Limited Partner Units or
Investor General Partner Units. Although costs, revenues and cash
distributions allocable to the Participants are shared pro rata based
upon the amount of their Agreed Subscriptions, there are material
differences in the federal income tax effects and liability associated
with these different types of Units in the Partnership. Investor
General Partners will have unlimited joint and several liability
regarding Partnership activities, but their use of Partnership losses
will not be subject to the passive activity limitations. Limited
Partners will have limited liability, but their use of Partnership
losses generally will be limited to net passive income from "passive"
trade or business activities, which generally includes the Partnership
and other limited partnership investments. (See "- Actions to be Taken
by Managing General Partner to Reduce Risks of Additional Payments by
Investor General Partners," below, "Risk Factors - Special Risks of
the Partnership- Unlimited Liability of Investor General Partners,"
"Tax Aspects - Limitations on Passive Activities," and "Summary of
Partnership Agreement".)
REPORTS
A status report detailing the progress of drilling activities will be
furnished to each Participant. In addition, each Participant will be
provided within 120 days after the end of each calendar year audited
financial statements showing the income, expenses, assets and
liabilities of the Partnership at the end of its fiscal year prepared
in accordance with generally accepted accounting principles. Tax
information with respect to the Partnership's operations for each
calendar year will be furnished to each Participant by March 15 of the
following year. (See "Reports to Investors".)
NO ADDITIONAL ASSESSMENTS
The Units are not subject to assessment. The Partnership will not call
upon the Participants for additional amounts of capital beyond their
Agreed Subscriptions. However, in the case of Investor General
Partners, if the insurance proceeds, Partnership assets, and the
indemnification of the Investor General Partners by Atlas and Atlas
Group (which was formerly AEG Holdings, Inc.) were not sufficient to
satisfy Partnership liabilities for which the Investor General Partners
were also liable, the Managing General Partner could call upon Investor
General Partners to make additional Capital Contributions to the
Partnership from their personal assets to satisfy such liabilities.
Investor General Partners do not have an option to refuse to contribute
an additional Capital Contribution called by the Managing General
- - -------------------------------------------------------------------------
<PAGE>3
Partner to pay Partnership liabilities. (See "Summary of Partnership
Agreement - Liabilities of General Partners Including Investor General
Partners.") Also, if the Partnership requires additional funds, which
the Managing General Partner does not anticipate, such funds will have
to be provided by borrowings or the retention of Partnership revenues.
(See "Capitalization and Source of Funds and Use of Proceeds".)
SUITABILITY STANDARDS - LONG TERM INVESTMENT
The Managing General Partner has instituted strict suitability
standards for investment in the Partnership. The high degree of
investment risk together with the restrictions on the sale of Units,
lack of a market for the Units, and the tax consequences of the
investment make the purchase of Units in the Partnership suitable only
for persons who are able to hold their Units on a long-term investment
basis. (See "Terms of the Offering - Suitability Standards".)
This is not an appropriate investment for IRAs, Keogh plans and
qualified retirement plans.
PARTNERSHIP AGREEMENT
The Partnership is a Pennsylvania limited partnership and will be
governed by the Partnership Agreement, the form of which is included as
Exhibit (A) to this Prospectus, as well as the provisions of the
Pennsylvania Revised Uniform Limited Partnership Act. Among other
matters, the Partnership Agreement provides for the distribution of
revenues and the allocation of costs, revenues, expenses, income, gain,
deductions and credits to and among the Partners. The Partnership
Agreement also provides for Partnership reporting and the conduct of
Partnership business and operations. The Participants have certain
rights, exercisable with limited exception by majority vote, relating
to their ownership of a Unit in the Partnership including the right to:
(i) call a meeting of the Partners; (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) amend the Partnership Agreement; (vi) dissolve and wind
up the Partnership; (vii) approve or disapprove any sale of all or
substantially all of the assets of the Partnership; and (viii) cancel
any contract for services with the Managing General Partner, the
Operator or their Affiliates without penalty upon sixty days' notice.
Atlas and its Affiliates may vote any Units purchased by them with
respect to certain of these matters. These and other rights are more
particularly described in Section 4.03(c) and its subsections of the
Partnership Agreement and are subject to certain limitations as set
forth therein.
APPLICATION OF PROCEEDS
The Partnership Subscription will be expended by the Partnership for
the purposes and in the percentages shown below assuming the minimum
number of Units is sold.
EXPENDITURE OF THE PARTNERSHIP SUBSCRIPTION
MINIMUM PARTNERSHIP
SUBSCRIPTION ($1,000,000) PERCENTAGE
Organization and Offering Costs $ -0- -0-
Lease Acquisition Costs -0- -0-
Intangible Drilling Costs 800,000 80%
Tangible Costs 200,000 20%
TOTAL $1,000,000 100%
For a more complete discussion of how the Partnership will apply the
proceeds of this offering, see "Capitalization and Source of Funds and
Use of Proceeds".
REQUIRED CAPITAL CONTRIBUTIONS OF THE MANAGING GENERAL PARTNER
The Managing General Partner is required to contribute to the
Partnership the Leases which will be drilled by the Partnership at its
cost or fair market value if Cost is materially more than fair market
value. The Managing General Partner also is required to pay 14% of the
Tangible Costs of drilling the Partnership wells and to pay 100% of the
Organization and Offering Costs. The Managing General Partner's
payment of Organization and Offering costs in an amount up to 15% of
the Partnership Subscription will be credited towards its required
Capital Contribution. Although Organization and Offering Costs in
excess of 15% of the Partnership Subscription also will be paid by the
Managing General Partner, such payments will be without recourse to the
Partnership and the Managing General Partner will not be credited with
such amounts towards its required Capital Contribution. In any event,
the Managing General Partner's aggregate Capital Contributions to the
Partnership (including the Leases contributed) must equal at least
16.5% of all Capital Contributions to the Partnership. (See
3.04(b)(1) of the Partnership Agreement.) The Managing General
Partner will also pay 25% of the Partnership's Operating Costs,
Administrative Costs, Direct Costs and all other costs not specifically
allocated.
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<PAGE>4
PARTICIPATION IN COSTS AND REVENUES
The following table sets forth the participation in costs and revenues
of the Partnership between the Managing General Partner and the
Participants. Gross revenues from the sale of the Partnership's gas
will be reduced by Landowner Royalties and any other burdens on the
Leases. (See "Proposed Activities - Interests of Parties",
"Participation in Costs and Revenues" and "Definitions".)
MANAGING
GENERAL
PARTNER PARTICIPANTS
PARTNERSHIP COSTS
Organization and Offering Costs (1) 100% 0%
Lease Costs 100% 0%
Intangible Drilling Costs (2) 0% 100%
Tangible Costs 14% 86%
Operating Costs, Administrative Costs,
Direct Costs and All Other Costs (3) 25% 75%
PARTNERSHIP REVENUES
Equipment Proceeds (4) (4)
All other Revenues including
Production Revenues (5) 25% 75%
(1) The Managing General Partner's payment of Organization and Offering
costs in an amount up to 15% of the Partnership Subscription will
be credited towards its required Capital Contribution. Although
Organization and Offering Costs in excess of 15% of the Partnership
Subscription also will be paid by the Managing General Partner,
such payments will be without recourse to the Partnership and the
Managing General Partner will not be credited with such amounts
towards its required Capital Contribution.
(2) More specifically, 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 will be
charged 100% to the Participants who are admitted to the
Partnership in such closing and will 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, each Participant will pay the same amount of such
costs regardless of when he subscribes.
(3) In the event Atlas has to subordinate its Partnership revenues in
an amount up to 10% of Net Production Revenues of the Partnership,
then Operating Costs, Direct Costs, Administrative Costs and all
other Partnership costs not specifically allocated will be charged
to the parties in the same ratio as the related production revenues
are being credited. (See "- Investment Features - Preferred 10%
Cash Return (cumulative 5 years)," above and "Risk Factors -
Special Risks of the Partnership - Borrowings by the Managing
General Partner Could Reduce Funds Available for Its Subordination
Obligation".)
(4) Proceeds from the sale or other disposition of equipment will be
credited to the parties charged with the costs of such equipment in
the ratio in which such costs were charged.
(5) 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.
PRIOR ACTIVITIES
Atlas has previously sponsored five public and twenty-one private
Development Drilling Programs formed since 1985 to conduct natural gas
drilling and development activities in Pennsylvania and Ohio. With
respect to Atlas' prior partnerships since 1985, twenty-four of the
twenty-six partnerships have not yet returned to the investor 100% of
his capital contributions without taking tax savings into account.
However, all of the partnerships are continuing to make cash
distributions and twenty-one of the partnerships were formed in 1990 or
subsequent years. (See "- General Risks of the Oil and Gas Business -
Speculative Nature of Gas Business," "Prior Activities" and "Proposed
Activities".) Also, as of July 15, 1997, the annual return on
investment (ROI) for the prior 23 Programs which have a full twelve
months of gas sales from all of their Wells has averaged 13.4%, and has
ranged from 7% to 25% without taking tax savings into account. Atlas
has drilled approximately 1,600 Development Wells over the 25 year
period from 1972 to 1997 and during this time approximately 97% of the
wells have been completed and produced commercial quantities of gas. In
the current area of primary interest in Mercer County, Pennsylvania,
approximately 98% of more than approximately 738 wells drilled have
been completed and produced commercial quantities of gas. (See "Prior
Activities" and "Proposed Activities - Information Regarding Currently
Proposed Prospects".)
RISK FACTORS
This offering involves numerous risks, including the risks of oil and
gas drilling, the risks associated with investments in oil and gas
drilling programs, and tax risks. (See "Risk Factors".) Each
prospective investor should carefully consider a number of significant
risk factors inherent in and affecting the business of the Partnership
and this offering, including the following.
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<PAGE>5
RISKS PERTAINING TO OIL AND GAS INVESTMENTS:
The drilling and completion operations to be undertaken by the
Partnership for the development of gas reserves involve the
possibility of a substantial or partial loss of an investment in
the Partnership because of wells which are productive but do not
produce enough revenue to return the investment made and/or from
time to time Dry Holes.
The revenues of the Partnership are directly related to the
ability to market the natural gas and the price of natural gas
which is currently unstable and cannot be predicted. If gas prices
decrease then investor returns will decrease.
Oil and gas operations in the United States are subject to
extensive government regulation. Future pollution and
environmental laws could have an adverse effect on the
Partnership.
SPECIAL RISKS OF THE PARTNERSHIP:
The Managing General Partner will have the exclusive management
and control of all aspects of the business of the Partnership.
Investor General Partner Units in the Partnership will be
converted to Limited Partner interests by the Managing General
Partner after substantially all of the Partnership Wells have been
drilled and completed, which is anticipated to be in late summer
of 1998. Investor General Partner Units may also be converted to
Limited Partner interests at the option of the Investor General
Partner if the Partnership's insurance will be materially reduced,
which is not anticipated. (See "Proposed Activities - Insurance"
and "Transferability of Units - Conversion of Units by Investor
General Partners.") Prior to the conversion of Investor General
Partners to Limited Partners, Investor General Partners will have
unlimited joint and several liability for all obligations and
liabilities to creditors and claimants arising from the conduct of
Partnership operations and if such liabilities exceed the
Partnership's assets, insurance and the assets of the Managing
General Partner and Atlas Group (which have agreed to indemnify
the Investor General Partners), the Investor General Partners
could incur liability in excess of their Agreed Subscriptions.
Lack of liquidity or a market for the Units, necessitating a
long-term investment commitment.
Lack of asset diversification and concentration of investment risk
should less than the maximum Partnership Subscription be raised
and thus fewer wells drilled. The Managing General Partner
anticipates that 35 to 36 wells will be drilled if the maximum
Partnership Subscription of $8,000,000 is received, and 4 to 5
wells will be drilled if only the minimum Partnership Subscription
of $1,000,000 is received.
Certain conflicts of interest between the Managing General Partner
and the Partnership and lack of procedures to resolve such
conflicts.
Atlas and its Affiliates can be expected to profit from the
Partnership even though it is possible that Partnership activities
could result in little or no profit, or a loss, to Participants.
Investors and the Managing General Partner will share in costs
disproportionately to their sharing of revenues.
Atlas intends that the Partnership will drill the currently
proposed Prospects described in "Proposed Activities - Information
Regarding Currently Proposed Prospects"; however, if there are
adverse events with respect to any of the currently proposed
Prospects, Atlas has the right acting as a prudent operator to
substitute the Partnership's Prospects. Also, up to 15% of the
Partnership Subscription may be used to drill Prospects which are
located in other areas of the United States and are not described
in "Proposed Activities - Information Regarding Currently Proposed
Prospects".
Although Atlas has pledged to subordinate a portion of its
Partnership Net Production Revenues, the subordination is not a
guarantee by Atlas. If the wells produce gas in small amounts
and/or the price of gas decreases, then even with subordination
the cash flow to the Participants may be very small and they may
not receive a return of their entire investment.
Quarterly cash distributions to investors may be deferred to the
extent revenues are used for Partnership operations or reserves or
if production is reduced because of decreases in the price of gas.
Subject to certain conditions, beginning in 2001 the Participants
may present their interests for purchase by the Managing General
Partner. There is a risk that the Managing General Partner, or its
Affiliates, will not have the necessary cash flow or be able to
arrange financing for such purposes on terms which are reasonable
as determined by the Managing General Partner, and in such event
the Managing General Partner is able to suspend its repurchase
obligation.
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<PAGE>6
TAX RISKS:
There is no guarantee that if the Partnership is audited the IRS
will not challenge the deductions claimed by the Partnership.
Alternative minimum taxable income of "independent producers,"
which includes most investors, cannot be reduced by more than 40%
in the 1997 tax year by reason of the repeal of the preference
item for intangible drilling and development costs.
The proper application of many provisions of the IRS regulations
governing partnership allocations is currently unclear. Should the
IRS successfully challenge the allocation provisions contained in
the Partnership Agreement, Participants could incur a greater tax
liability. (See "Tax Aspects - Allocations".)
ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF
ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS
The Managing General Partner will attempt to conduct the operations of
the Partnership in a manner designed to reduce the risk that an
Investor General Partner could be required to make additional payments
to the Partnership. The actions to be taken by the Managing General
Partner include:
1. INSURANCE. Fifty million dollars of liability coverage during
drilling operations and eleven million dollars thereafter as set
forth in "Proposed Activities - Insurance."
2. CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED
PARTNER INTERESTS. Pursuant to the Partnership Agreement, Investor
General Partner Units in the Partnership will be converted to
Limited Partner interests by the Managing General Partner after
substantially all of the Partnership Wells have been drilled and
completed, which is anticipated to be in late summer of 1998. Once
conversion has taken place, Investor General Partners will
continue to have the responsibilities of general partners with
respect to Partnership tort, contract and environmental
liabilities and obligations incurred prior to the effective date
of the conversion. However, such Investor General Partners will
have the lesser liability of limited partners under Pennsylvania
law with respect to obligations and liabilities arising after the
conversion. Nevertheless, an Investor General Partner might become
liable for obligations in excess of his Agreed Subscription to the
Partnership during the time when the Partnership is engaged in
drilling activities and for environmental claims that arose during
drilling activities but were not discovered until after
conversion.
3. NONRECOURSE DEBT. Under the Partnership Agreement the Partnership
will be permitted to borrow funds only from Atlas or its
Affiliates which will not have recourse against the non-
Partnership assets of the individual Investor General Partners.
Accordingly, no Investor General Partner could be required to
contribute funds to the Partnership in the case of a default under
such loan arrangement and any such borrowings will be repaid from
Partnership revenues. The amount that may be borrowed at any one
time may not exceed an amount equal to 5% of the Partnership
Subscription. Because the Participants do not bear the risk of
repaying these borrowings with non-Partnership assets, the
borrowings will not increase the extent to which Participants are
allowed to deduct their individual shares of Partnership losses.
(See "Tax Aspects - Tax Basis of Participants' Interests" and "-
`At Risk' Limitation For Losses".)
To further protect the Investor General Partners, during producing
operations all third party goods and services will be acquired by
Atlas and its Affiliates and the Partnership will then acquire
such goods and services from Atlas and its Affiliates at their
Cost.
4. INDEMNIFICATION. Atlas and Atlas Group will indemnify each
Investor General Partner from any liability incurred in connection
with the Partnership which is in excess of such Investor General
Partner's interest in the undistributed net assets of the
Partnership and insurance proceeds, if any. Upon such
indemnification by Atlas and/or Atlas Group, each Investor General
Partner who has been indemnified is deemed to have transferred and
subrogated his rights for contribution from or against any other
Investor General Partner to Atlas and/or Atlas Group. Atlas' and
Atlas Group's indemnification obligation, however, will not
eliminate an Investor General Partner's potential liability in the
event that insurance is not sufficient or available to cover a
liability and Atlas' and Atlas Group's assets are insufficient to
satisfy their indemnification obligation. There can be no
assurance that Atlas' and Atlas Group's assets, including their
liquid assets, will be sufficient to satisfy their indemnification
obligation. (See "Risk Factors - Special Risks of the Partnership
- - Managing General Partner Liquid Net Worth Is Not Guaranteed" and
"Financial Information Concerning the Managing General Partner,
Atlas Group and the Partnership".)
COMPENSATION TO THE MANAGING GENERAL PARTNER, THE OPERATOR AND THEIR
AFFILIATES
The following is a tabular presentation of the items of compensation
and reimbursement to be received by Atlas and its Affiliates from the
Partnership which are discussed more fully in "Compensation."
- ------------------------------------------------------------------------------
<PAGE>7
FORM OF COMPENSATION AND/OR REIMBURSEMENT ......AMOUNT
Partnership Interest 25% of the oil and gas revenues of the
Partnership in return for paying
Organization and Offering Costs equal
to 15% of the Partnership
Subscription, 14% of Tangible Costs
and contributing all Prospects to the
Partnership at Cost, or fair market
Value if Cost is materially more than
fair market value.(1)
Contract drilling rates Competitive industry rates. Atlas
anticipates that it will have a
profit of approximately 15% per well
if the well is drilled to a depth of
6,150 feet in the Mercer County area
of the Appalachian Basin. (1)
Operator's Per-Well
Charges Competitive industry rates, currently
$275 per well per month in the
Appalachian Basin. (See "Proposed
Activities - Drilling and Completion
Activities; Operation of Producing
Wells".) (1)
Direct Costs Reimbursement at Cost.(1)
Administrative Costs Unaccountable, fixed payment reimbursement of
Managing General Partner's
administrative overhead which the
Managing General Partner has set at
$75 per well per month. (1)
Transportation and
Marketing Fee Competitive industry rate of 29>
per MCF. (1)
Dealer-Manager Fees The Dealer-Manager will receive from Atlas
certain fees on each Unit sold. (See
"Compensation".)
(1) Cannot be quantified at the present time because the number of
wells that will be drilled and the amount of gas that will be
produced from the wells cannot be predicted.
The following organizational chart shows the relationship between Atlas
Resources, Inc., the Managing General Partner, and its Affiliates. (See
"Management".)
Organizational Diagram
<TABLE>
<CAPTION>
Organizational Diagram
THE ATLAS GROUP, INC.
:
AIC, INC
:
..............................................................................................
: : : : : : : :
ATLAS MERCER GAS PENNSYLVANIA ATLAS ENERGY TRANSATCO ATLAS GAS ANTHEM ATLAS
ENERGY
RESOURCES GATHERING INDUSTRIAL CORPORATION INC.,WHICH MARKETING SECURITIES GROUP,
INC.
(MANAGING INC., (GAS ENERGY,INC. (DRILLER AND OWNS 50% OF INC. INC. (DRILLER
AND
GENERAL GATHERING ("PIE") OPERATOR IN TOPICO (MARKETS OPERATOR
IN
PARTNER, COMPANY) (SELLS GAS TO WV AND (OPERATES NATURAL
OHIO
DRILLER PENNSYLVANIA MANAGING PIPELINE GAS) :
AND OPERATOR) INDUSTRY) GENERAL IN OHIO :
: :
: :
ARD AED
INVESTMENTS, INC.
INVESTMENTS,
INC.
<C> <C> <C> <C> <C> <C> <C>
1 2 3 4 5 6 6
</TABLE>
CONFLICTS OF INTEREST
The Managing General Partner has a fiduciary duty to exercise good
faith and to deal fairly with the Participants in handling the affairs
of the Partnership. Nevertheless, there are various conflicts of
interest between the Managing General Partner and the Participants
with respect to the Partnership. Conflicts of interest are inherent in
oil and gas drilling programs involving non-industry participants
because the transactions are entered into without arms' length
negotiation. Such conflicts of interest include: (i) services provided
to the Partnership by the Managing General Partner and its Affiliates
and the amount
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<PAGE>8
of compensation paid by the Partnership for such
services; (ii) which Leases will be acquired by the Partnership or
other Programs sponsored by the Managing General Partner or its
Affiliates and the terms upon which such acquisitions are made; (iii)
the allocation of the Managing General Partner's management time,
services and other functions among the Partnership and other Programs
sponsored by the Managing General Partner and its Affiliates; (iv) the
Managing General Partner's obligation to repurchase Participants' Units
presented to it beginning in 2001 and the amount of the repurchase
price; and (v) other conflicts of interest.
Other than certain guidelines set forth in "Conflicts of Interest",
the Managing General Partner has no established procedures to resolve
a conflict of interest. Consequently, conflicts of interest between
the Managing General Partner and the Participants may not necessarily
be resolved in the best interests of the Participants. Under Section
4.05(a) of the Partnership Agreement, the Managing General Partner, the
Operator and their Affiliates have no liability to the Participants
for any action or inaction on their part which they determined was in
the best interest of the Partnership, provided that such course of
conduct did not constitute negligence or misconduct of the Managing
General Partner, the Operator or their Affiliates. (See "Conflicts of
Interest".)
DISTRIBUTION
The Units will be offered on a "best efforts" basis by Anthem
Securities, Inc., a registered broker-dealer which is a member of the
NASD and a wholly-owned subsidiary of Atlas Group, acting as Dealer-
Manager in all states other than Minnesota and New Hampshire, and by
other selected registered broker-dealers, which are members of the
NASD, acting as Selling Agents. Bryan Funding, Inc., a member of the
NASD, will serve as Dealer-Manager in the states of Minnesota and New
Hampshire, and will receive the same compensation as Anthem Securities,
Inc. with respect to sales in those states. Best efforts means that
the Dealer-Manager and broker-dealers will not guarantee the sale of a
certain amount of Units.
The Dealer-Manager will manage and oversee the offering of the Units as
described above and will receive from the Partnership on each Unit sold
to investors a 2.5% Dealer-Manager fee, a 7.5% Sales Commission and a
.5% reimbursement of the Selling Agents' bona fide accountable due
diligence expenses. The 7.5% Sales Commission and the .5%
reimbursement of accountable due diligence expenses will be reallowed
to the Selling Agents. Atlas is also utilizing the services of three
wholesalers. One of the wholesalers is associated with Anthem
Securities, Inc., and the other two are associated with Bryan Funding,
Inc. The 2.5% Dealer-Manager fee will be reallowed to the wholesalers
for Agreed Subscriptions obtained through such wholesalers' effort.
Subject to the receipt of the minimum Partnership Subscription and the
checks having cleared the banking system, Dealer-Manager fees, Sales
Commissions and accountable due diligence reimbursements will be paid
to the broker-dealers approximately every two weeks until the Offering
Termination Date. (See "Terms of the Offering - Partnership Closings
and Escrow," "Participation in Costs and Revenues" and "Plan of
Distribution".)
THE FOREGOING SUMMARY OF CERTAIN PROVISIONS OF THE PROSPECTUS DOES NOT
PURPORT TO BE A COMPLETE DESCRIPTION OF THE TERMS AND CONSEQUENCES OF
AN INVESTMENT IN THE PARTNERSHIP. PROSPECTIVE INVESTORS AND THEIR
ADVISERS SHOULD CAREFULLY READ THE ENTIRE PROSPECTUS AND ALL ATTACHED
EXHIBITS BEFORE MAKING AN INVESTMENT IN THE PARTNERSHIP.
RISK FACTORS
An investment in the Partnership involves a high degree of risk and is
suitable only for investors of substantial financial means who have no
need of liquidity in their investment.
SPECIAL RISKS OF THE PARTNERSHIP
SPECULATIVE NATURE OF INVESTMENT. Exploration for gas is an inherently
speculative activity. There is always the risk that drilling activity
may result in wells which do not produce gas in sufficient quantities
to return the investment made and from time to time Dry Holes. There
is a substantial risk that the price of gas will be volatile and may
decrease. A Participant will be able to recover his investment only
through distributions of sales proceeds from production of the
Partnership gas reserves which deplete over time. All or a portion of
these distributions may be considered to include a return to
Participants of their investment in the Partnership. There can be no
guarantee that the Participants will recover all of their investment
or if they do recover their investment that they will receive a rate
of return on their investment that is competitive with other types of
investment. (See "Proposed Activities - Intended Areas of
Operations".)
UNLIMITED LIABILITY OF INVESTOR GENERAL PARTNERS. Under Pennsylvania
law, each Investor General Partner will have unlimited joint and
several liability with respect to the activities of the Partnership
which could result in an Investor General Partner being required to
make payments, in addition to his original investment, in amounts
which are impossible to determine because of their uncertain nature
with respect to the development and operation of the wells. Also, the
Partnership may own less than 100% of the
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<PAGE>9
Working Interest in the
Prospects and in that event each Investor General Partner may have
joint and several liability with the other third party owners of the
Working Interest. Although under the terms of the Partnership
Agreement the Investor General Partners agree to be responsible for
and pay their respective proportionate shares of such obligations and
liabilities, such agreement does not legally negate each Investor
General Partner's joint and several liability for such obligations and
liabilities if an Investor General Partner does not pay his respective
proportionate share of such obligations and liabilities and/or in the
event that a court holds the Investor General Partners and the other
third party owners of the Working Interest to be jointly and severally
liable. Participants will not have liability for any non-
environmental events on the Prospect which occurred before its
transfer to the Partnership. (See "Summary of the Offering - Actions
to be Taken by Managing General Partner to Reduce Risks of Additional
Payments by Investor General Partners", "- General Risks of the Oil
and Gas Business - Drilling Hazards May Be Encountered," "- General
Risks of the Oil and Gas Business - Potential Liability for Pollution;
Environmental Matters," and "Summary of Partnership Agreement -
Liabilities of General Partners, Including Investor General
Partners".)
In addition to the other actions summarized in this Prospectus which
will be taken by Atlas to reduce the risk of additional payments by
the Investor General Partners, Atlas and Atlas Group have agreed to
indemnify each Investor General Partner from any liability incurred in
connection with the Partnership which is in excess of such Investor
General Partner's share of Partnership assets. There can be no
assurance that Atlas' and Atlas Group's assets, including their liquid
assets, will be sufficient to satisfy their indemnification
obligation. This risk is increased because Atlas and Atlas Group have
made and will make similar financial commitments in other drilling
programs. The Partnership will also have the benefit of general and
excess liability insurance of $50,000,000 during drilling operations
and, thereafter, $11,000,000, per occurrence and in the aggregate.
Nevertheless, the Investor General Partners may become subject to
contract or tort liability in excess of the amounts insured under such
policies and also may be subject to liability for pollution, abuses of
the environment and other damages 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. Although Atlas will not transfer any Prospect to the
Partnership if it has actual knowledge that there is an existing
potential environmental liability on the Prospect, there will not be
an independent environmental audit of the Prospects before they are
transferred to the Partnership. Therefore, there can be no guarantee
that the Prospects will not have any existing potential environmental
liability. (See " - Possibility of Reduction or Unavailability of
Insurance" and "Proposed Activities - Insurance".)
If the insurance proceeds, Partnership assets, and Atlas' and Atlas
Group's indemnification of the Investor General Partners were not
sufficient to satisfy such liability an Investor General Partner's
personal assets could be required to be used to satisfy such
liability. Investor General Partners do not have an option to refuse
to contribute an additional Capital Contribution called by the
Managing General Partner to pay Partnership liabilities. (See
"Summary of Partnership Agreement - Liabilities of General Partners
Including Investor General Partners.")
ILLIQUID INVESTMENT AND RESTRICTIONS ON TRANSFERABILITY OF
PARTICIPANTS' INTERESTS. Participants in the Partnership must assume
the risks of an illiquid investment. Participants' interests are not
marketable; and the transferability of Participants' interests is
limited, both by express provision of the Partnership Agreement and the
provisions of state and federal securities laws. Such interests cannot
be readily liquidated by a Participant in the event of an emergency,
and any such sale would create adverse tax and economic consequences
for the selling Participant. (See "Repurchase Obligation" and
"Transferability of Units".)
Under the Partnership Agreement, Units are nontransferable except with
the consent of the Managing General Partner, and an assignee of a
Participant's Unit is entitled to become a substituted Partner only if
the assignor gives the assignee such right, the Managing General
Partner consents to such substitution in its discretion, the assignee
pays all costs of such substitution, and the assignee executes and
delivers the instruments, in form and substance satisfactory to the
Managing General Partner, necessary to effect substitution and confirm
the agreement of the assignee to be bound by the terms and conditions
of the Partnership Agreement. Under the federal securities laws, Units
cannot be transferred in the absence of an effective registration of
the Units under the Securities Act of 1933, as amended, or an exemption
therefrom. The Managing General Partner has no obligation to register
the Units for such purpose. The Managing General Partner will not
consent to a transfer and substitution of a Participant if doing so
would result in a violation of the securities laws or cause the
Partnership to be terminated or treated as a publicly traded
partnership for tax purposes. (See "Tax Aspects - Limitations on
Passive Activities" and " - Termination of a Partnership".)
TOTAL RELIANCE UPON THE MANAGING GENERAL PARTNER. The Managing General
Partner will have the exclusive right to control the affairs and
business of the Partnership. No prospective investor should purchase
any Units in the Partnership unless he is willing to entrust all
aspects of management of the Partnership to Atlas. Nevertheless, a
Participant has the right at any time to obtain full information
regarding the business and financial condition of the Partnership and,
if necessary, to sue for an accounting. (See "Conflicts of Interest"
and "Summary of Partnership Agreement".)
MANAGEMENT OBLIGATIONS OF MANAGING GENERAL PARTNER NOT EXCLUSIVE. Atlas
must devote that amount of time to the Partnership's affairs as it
determines reasonably necessary. Atlas and its Affiliates will be
engaged in other oil and gas activities and other unrelated business
ventures for their own account or for the account of others during the
term of the Partnership. (See "Conflicts of Interest - Other Activities
of the Managing General Partner, the Operator and their Affiliates".)
<PAGE>10
MANAGING GENERAL PARTNER LIQUID NET WORTH IS NOT GUARANTEED. Atlas, as
Managing General Partner, is primarily responsible for the conduct of
the Partnership's affairs. A significant financial reversal for Atlas
could adversely affect the Partnership and the value of the Units
therein if it diverted Atlas' time and attention away from the
Partnership or caused staff reductions that impaired Atlas' ability to
perform its duties as Managing General Partner and Operator with
respect to the operation of the wells and the marketing of the
Partnership's gas production.
The net worth of Atlas and Atlas Group is largely based on the
estimated value of producing gas properties that they hold, and is not
readily available in cash absent borrowings or a sale of the
properties. Also, gas prices are volatile and if gas prices decrease,
this will have a direct adverse effect on the estimated value of such
properties and, therefore, on the net worth of Atlas and Atlas Group.
There is no assurance that Atlas and Atlas Group will have the
necessary net worth, currently or in the future, to meet their
indemnification obligation to the Investor General Partners or with
respect to Atlas its other financial commitments under the Partnership
Agreement. These risks are increased because Atlas and Atlas Group have
made and will make similar financial commitments in other Programs.
(See "Financial Information Concerning the Managing General Partner,
Atlas Group and the Partnership".)
DIVERSIFICATION DEPENDS UPON SUBSCRIPTION PROCEEDS. The fewer the
number of Units purchased the fewer the number of wells which the
Partnership will participate in developing which will limit the ability
to spread the risks of drilling. Conversely, as the Partnership size
increases the number of wells will increase, thereby increasing the
diversification of the Partnership. The Managing General Partner
anticipates that 35 to 36 wells will be drilled if the maximum
Partnership Subscription of $8,000,000 is received, and 4 to 5 wells
will be drilled if only the minimum Partnership Subscription of
$1,000,000 is received. If the Managing General Partner, however, is
unable to secure sufficient attractive Prospects for a larger
Partnership, it is possible that the average quality of the wells
drilled could decline. In addition, greater demands will be placed on
the management capabilities of the Managing General Partner in a large
Partnership. (See "Proposed Activities - In General".)
DISPROPORTIONATE COSTS BORNE BY PARTICIPANTS. Under the cost and
revenue sharing provisions of the Partnership Agreement, the
Participants and the Managing General Partner will share in costs
disproportionately to their sharing of revenues. Atlas will pay 100% of
Organization and Offering Costs and 14% of the Tangible Costs and
contribute the Leases to the Partnership. Atlas' Capital Contributions
must equal at least 16.5% of all Capital Contributions to the
Partnership. In return, Atlas will receive 25% of the Partnership's
production revenues and pay 25% of the Partnership's Operating Costs,
Administrative Costs, Direct Costs and all other costs not specifically
allocated. The Participants will pay 100% of Intangible Drilling Costs
and 86% of Tangible Costs. The Participant's Capital Contributions
will equal 83.5% of all Capital Contributions to the Partnership. In
return, the Participants will receive 75% of the Partnership's
production revenues and pay 75% of the Partnership's Operating Costs,
Administrative Costs, Direct Costs and all other costs not specifically
allocated. (See "Participation in Costs and Revenues".)
COMPENSATION AND FEES TO THE MANAGING GENERAL PARTNER REGARDLESS OF
SUCCESS OF THE ACTIVITIES. Atlas and its Affiliates can be expected to
profit from the Partnership even though Partnership activities result
in little or no profit, or a loss to Participants. (See
"Compensation".)
DRY HOLE RISK IN DEVELOPMENT DRILLING. Although the Dry Hole risk
associated with drilling Development Wells is greatly reduced, there
can be no assurance that there will not be some Dry Holes. (See "Prior
Activities".)
RISK OF UNPRODUCTIVE WELLS IN DEVELOPMENT DRILLING. Completion of a
Development Well in the Clinton/Medina geological formation in
Pennsylvania or Ohio, or any other Development Well drilled by the
Partnership in the United States, should not be equated with
commercial success. For example, the Clinton/Medina geologic formation
is characterized by low permeability (ability of hydrocarbon-bearing
rock to allow the flow of oil and gas), low porosity (capacity of rock
to hold oil and gas) and other geological characteristics which may
reduce the profit potential of a well completed to such geologic
formation. A Development Well drilled to the Clinton/Medina or other
geologic formations in the United States may be completed and
productive but not produce enough revenue to return the investment
made, even if tax consequences are considered. With respect to Atlas'
prior partnerships since 1985, twenty-four of the twenty-six
partnerships have not yet returned to the investor 100% of his capital
contributions without taking tax savings into account. However, all of
the partnerships are continuing to make cash distributions and twenty-
one of the partnerships were formed in 1990 or subsequent years. (See
"- General Risks of the Oil and Gas Business - Speculative Nature of
Gas Business," "Prior Activities" and "Proposed Activities".)
RISKS REGARDING MARKETING OF GAS. Atlas estimates that a portion of the
Partnership's gas production in the Mercer County area, which is the
primary area of interest, will be transported through Atlas' and its
Affiliates' own pipeline system and sold directly to industrial
end-users in the area where the wells will be drilled. The remainder of
the Partnership's gas from the Mercer County area will be transported
through Atlas' and its Affiliates' pipelines to the interconnection
points maintained with Tennessee Gas Transmission Co., National Fuel
Supply Corporation, National Fuel Gas Distribution Company, East Ohio
Natural Gas Company
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<PAGE>11
and Peoples Natural Gas Company. Atlas markets
portions of the gas through long term contracts, short term contracts
and monthly spot market sales. There is no assurance of the price at
which the Partnership's gas will be sold, and generally, the revenues
received by the Partnership will be less the farther the gas is
transported because of the increased transportation costs. During 1996
the average price paid after deducting all expenses, including
transportation costs, was $2.29 per MCF. (See "- General Risks of the
Oil and Gas Business - Risk of Decrease in the Price of Gas," "Proposed
Activities - Sale of Oil and Gas Production" and "Competition, Markets
and Regulation - Marketing".)
It is anticipated that approximately 10% to 30% of the gas produced by
Atlas and its Affiliates, including Atlas' previous Programs, in the
Mercer County area will be sold to industrial end-users and all of the
gas currently being produced is being sold. Also, Atlas has not
voluntarily restricted its gas production within the last two years
because of a lack of a profitable market price.
The sale to industrial end-users also can raise risks relating to the
credit worthiness of the industrial end-user. In the event that the
industrial end-user does not pay, or delays payment, the Partnership
may not be paid or may experience delays in receiving payment for
natural gas that has already been delivered. For example, after Sharon
Steel Corporation ("Sharon") filed Chapter 11 bankruptcy in 1987, it
continued to purchase most of Atlas' and its Affiliates' natural gas
production in the Mercer County field until it filed a second Chapter
11 bankruptcy in 1992. At that time, Atlas and various programs where
Atlas is either the Managing General Partner and/or operator lost
approximately $2,400,000, for approximately 77 days of gas sales, of
which approximately $600,000 was owed to Atlas and the balance was owed
to the various programs. (See "- General Risk of the Oil and Gas
Business - Competition in Marketing Natural Gas Production," "Proposed
Activities - Sale of Oil and Gas Production," "Competition, Markets and
Regulation - Marketing" and "Financial Information Concerning the
Managing General Partner, Atlas Group and the Partnership".)
Also, there can be no assurance that the terms of a gas supply
agreement with an end-user will continue to be favorable over the life
of the wells. Most gas supply agreements provide that prices may be
adjusted upward or downward from time to time in accordance with market
conditions. Also, when the gas supply agreements expire the industrial
end-users may negotiate lower pricing terms. (See "Proposed Activities
- - Sale of Oil and Gas Production" and "Competition, Markets and
Registration - Marketing".)
Finally, potential conflicts of interest are presented by the Managing
General Partner's obligation to market the oil and gas production of
other Programs sponsored by the Managing General Partner and its
Affiliates as well as any oil and gas production of the Partnership.
In this regard, the Managing General Partner and its Affiliates have
adopted the following procedures and conditions to reduce some of these
potential conflicts of interest. All benefits from marketing
arrangements or other relationships affecting property of the Managing
General Partner or its Affiliates and the Partnership will be fairly
and equitably apportioned according to the respective interest of each
in such property. Marketing all of the relatively small amounts of oil
produced by the wells generally is not a problem. Atlas anticipates
selling all of such oil to Quaker State Oil Refinery Company or other
oil companies in the area where the well is situated in spot sales.
With respect to natural gas production from the wells, the Managing
General Partner will treat all wells in a geographic area equally
concerning to whom and at what price the Partnership's gas will be sold
and to whom and at what price the gas of other oil and gas Programs
which the Managing General Partner has sponsored or will sponsor will
be sold. The Managing General Partner calculates a weighted average
selling price for all of the gas sold in a geographic area by taking
all money received from the sale of all of the gas sold to its
customers in a geographic area and dividing by the volume of all gas
sold from the wells in that geographic area. This ensures that the
various Programs receive the same selling price for their gas
production in the same geographic area. Also, in the event that Atlas
determines curtailment of production would be in the best interests of
its Programs, production will be curtailed to the same degree in all of
the wells in the same geographic area. On the other hand, if Atlas has
not decided to curtail production, but all of the gas produced cannot
be sold because of limited demand which increases pipeline pressure,
then the production that is sold will be from those wells which are
best able to feed into the pipeline, regardless of which Programs own
the wells. (See "Conflicts of Interest - Procedures to Reduce
Conflicts of Interest.")
POSSIBLE DELAYS IN PRODUCTION AND SHUT-IN WELLS. Production from wells
may be reduced or Shut-In due to marketing demands which tend to be
seasonal. There is no assurance that Atlas will not have to curtail
production in 1998 or subsequent years awaiting a better price for the
gas. Production from wells drilled in certain areas may also be delayed
for up to several months until construction of the necessary pipelines
and production facilities is completed. However, such delays are not
anticipated by Atlas with respect to any of the wells currently
proposed for the Partnership. (See "Proposed Activities - Sale of Oil
and Gas Production" and "Competition, Markets and Regulation -
Marketing".)
UNSPECIFIED LOCATION OF A PORTION OF THE PROSPECTS. Atlas intends that
the Partnership will be assigned 100% of the Working Interest and will
drill the currently proposed Prospects described in "Proposed
Activities - Information Regarding Currently Proposed Prospects" which
represent approximately 80% of the potential $10,000,000 maximum
Partnership Subscription assuming 100% of the Working Interest is
acquired by the Partnership and the Managing General Partner elects to
increase the size of the offering to $10,000,000. The currently
proposed Prospects are all situated in the Mercer County area of
Pennsylvania. However, the Managing General Partner has reserved the
right to use up to 15% of the Partnership Subscription to drill
Development Wells on
<APGE>12
Prospects in other areas of the United States
which are not described herein. The Partnership also may acquire
Working Interests in additional Prospects which are not described if
more than $8,000,000 is raised and/or the Partnership acquires less
than 100% of the Working Interest in one or more Prospects. In
addition, Atlas has the right to delete any Prospect which it deems to
be inappropriate for the Partnership because of adverse events or for
which insufficient funds are available, and it may substitute or adjust
the Partnership's interest in the Prospects as it deems necessary to
meet the objectives of the Partnership.
A prospective Participant has no information regarding any additional
and/or substitutional Leases. The Partnership does not have the right
of first refusal in the selection of Leases from the inventory of the
Managing General Partner and its Affiliates, and they may sell their
Leases to other Programs, companies, joint ventures or other persons at
any time. (See "- Total Reliance upon the Managing General Partner,"
above, and "Proposed Activities - Acquisition of Leases" and "Proposed
Activities - Information Regarding Currently Proposed Prospects".)
NO GUARANTEE OF DATA REGARDING CURRENTLY PROPOSED PROSPECTS. The data
included in "Proposed Activities - Information Regarding Currently
Proposed Prospects" has been prepared by Atlas from sources deemed
reliable by it; however, Atlas cannot guarantee that the data reflects
all of the wells drilled in the area or that the amount of gas
production in the area is accurate in all cases. As to certain of the
Prospects the production information is incomplete because the wells
are being operated by third parties and the information is unavailable
to Atlas. Also, some of the wells have only been producing for a short
period of time or are not yet completed or online. (See "Proposed
Activities - Information Regarding Currently Proposed Prospects".)
ATLAS' SUBORDINATION IS NOT A GUARANTEE. Atlas has agreed to
subordinate a portion of its share of Partnership Net Production
Revenues generated from the sale of gas in the Partnership. If the
wells, however, produce gas in small amounts, and/or the price of gas
decreases, then even with subordination the cash flow to the
Participants may be very small and they may not receive a return of
their entire investment. (See "- Borrowings by the Managing General
Partner Could Reduce Funds Available for Its Subordination Obligation"
and "Participation in Costs and Revenues - Subordination of Portion of
Managing General Partner's Net Revenue Share".)
BORROWINGS BY THE MANAGING GENERAL PARTNER COULD REDUCE FUNDS AVAILABLE
FOR ITS SUBORDINATION OBLIGATION. It is anticipated that the Managing
General Partner will pledge, for its own corporate purposes, either its
Partnership interest and/or an undivided interest in the assets of the
Partnership equal to its interest in the revenues of the Partnership.
Such a pledge, in the event of a default to the lender, would reduce
the Partnership Net Production Revenues of Atlas available for Atlas'
subordination obligation. Also, the Managing General Partner is not
obligated to attempt or arrange for or secure any similar financing for
any Participants for their own account. (See "Conflicts of Interest -
Other Conflicts" and "Summary of Partnership Agreement".)
POSSIBILITY OF REDUCTION OR UNAVAILABILITY OF INSURANCE. It is possible
that some or all of the insurance coverage which the Partnership has
available may become unavailable or prohibitively expensive. In such
case, Investor General Partners who elected to remain Investor General
Partners after notice that the insurance is being reduced could be
exposed to additional financial risk, and all Participants could be
subject to greater risk of loss of their investment. (See "- General
Risks of the Oil and Gas Business - Drilling Hazards May Be
Encountered," "Proposed Activities - Insurance" and "Tax Aspects -
Limitations on Passive Activities".)
POSSIBLE NONPERFORMANCE BY SUBCONTRACTORS. Atlas, as Operator and
general drilling contractor, will subcontract some of the services to
subcontractors. There is a risk that if such subcontractors fail to
timely pay for materials or services on the wells the Partnership could
incur excess costs. To reduce this risk Atlas will use only
subcontractors that have previously performed similar activities for
Atlas in a satisfactory manner, will endeavor to ascertain the
financial condition of the subcontractors and attempt to secure lien
releases from the various subcontractors. (See - "Unlimited Liability
of Investor General Partners," above and "Proposed Activities -
Drilling and Completion Activities; Operation of Producing Wells".)
RISK OF PREPAYMENT TO ATLAS. Advance payments by the Partnership to the
Managing General Partner and its Affiliates are prohibited, except where
advance payments are required to secure tax benefits of prepaid drilling
costs and for a business purpose. Because it is anticipated the
Partnership will be required to pay the entire contract price for the
Partnership Wells immediately because of tax reasons, such funds could
be subject to claims of creditors of such Operator. Currently, Atlas is
not aware of any existing creditors of Atlas or its Affiliates which
would have a claim to prepaid Partnership funds. (See "Financial
Information Concerning the Managing General Partner, Atlas Group and the
Partnership".)
POSSIBLE LEASEHOLD DEFECTS. The Working Interests in the Leases to be
assigned to the Partnership by Atlas will be assigned without title
insurance and there is a risk of title failure. (See "Proposed
Activities - Title to Properties".)
PARTNERSHIP BORROWINGS MAY REDUCE OR DELAY DISTRIBUTIONS. Although it is
not anticipated that the Partnership will borrow any funds, the Managing
General Partner is authorized to increase the working capital of the
Partnership by making advances
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<PAGE>13
to the Partnership. Borrowings by the
Partnership can result in delayed or reduced cash distributions while
the loan is being repaid. (See "Capitalization and Source of Funds and
Use of Proceeds" and "- Tax Risks - Possible Taxes in Excess of Cash
Distributions," below.)
ATLAS WILL RECEIVE BENEFIT FROM TRANSFER OF LEASES. The Managing
General Partner will contribute sufficient undeveloped Leases to the
Partnership to drill the Partnership's wells at the Cost of such Leases,
or fair market value if Cost is materially more than fair market value.
The Cost of the Leases will include a portion of the Managing General
Partner's reasonable, necessary and actual expenses for geological,
geophysical, engineering, interest expense, legal, and other like
services allocated to the Partnership's Leases determined using industry
guidelines. The Managing General Partner will receive a benefit from
these transactions. In addition, such contributions could create
conflicts of interest for the Managing General Partner. In the
Partnership's primary area of interest wells will be drilled to test the
Clinton /Medina geologic formation, a blanket geological formation
prevalent in Ohio and Pennsylvania. A Prospect will be deemed to
consist of the drilling or spacing unit on which such well will be
drilled if the Clinton/Medina geological formation to which such well
will be drilled contains Proved Reserves and the drilling or spacing
unit protects against drainage. The development of wells on such
acreage may provide Atlas with offset sites by allowing it to ascertain
at the Partnership's expense the value of adjacent acreage in which the
Partnership would not have any right to participate in developing. (See
"Conflicts of Interest - Conflicts Involving Acquisition of Leases,"
"Conflicts of Interest - Other Activities of the Managing General
Partner, the Operator and their Affiliates" and "Proposed Activities".)
OTHER CIRCUMSTANCES UNDER WHICH DISTRIBUTIONS MAY BE REDUCED OR DELAYED.
Although the Managing General Partner intends to distribute the cash
quarterly, distributions may be deferred to the extent revenues are used
for cost overruns, costs related to completing and Fracturing some of
the wells in a third zone, remedial work to improve a well's producing
capability or if a productive gas well is Shut-In for an indeterminate
time awaiting an acceptable market for such production. In addition, the
Operator pursuant to the Drilling and Operating Agreement has reserved
the right at any time after three years from the date a Partnership Well
has been placed into production to withhold revenues of the well of up
to $200 per month to establish a reserve for the estimated costs of
eventually plugging and abandoning the well, although historically Atlas
has never done so after only three years. There can be no assurance that
cash distributions will be regularly paid or that they will exceed the
amount of the taxes payable by a Participant with respect to his
investment in the Units. (See "- Tax Risks - Possible Taxes in Excess
of Cash Distributions".)
CONFLICTS OF INTEREST. There are conflicts of interest between the
Managing General Partner and its Affiliates and the Partnership
including, but not limited to, the compensation paid by the Partnership
to Atlas and the terms of the offering have been determined solely by
Atlas; Atlas may have conflicts of interest in allocating management
time, services and other functions (which are allocated on an as-needed
basis consistent with its fiduciary duties) among the Partnership and
its other Programs; and conflicts of interest may arise concerning which
Leases Atlas will assign to the Partnership for drilling, and which
Leases Atlas will assign to its other Programs. Other than certain
guidelines set forth in "Conflicts of Interest", the Managing General
Partner has no established procedures to resolve a conflict of interest.
(See " - Risks Regarding Marketing of Gas" above, and "Conflicts of
Interest".)
RISK REGARDING PARTICIPATION WITH THIRD PARTIES. It is anticipated that
the Partnership will own 100% of the Working Interest in the wells,
however, the Partnership has reserved the right to take as little as 25%
of the Working Interest. Therefore, it is possible that other Working
Interest owners will participate with the Partnership to drill some of
the wells. Additional financial risks are inherent in any operation
where the cost of drilling, equipping, completing and operating wells is
shared by more than one person. In the event the Partnership pays its
share of such costs, but another Working Interest owner does not, the
Partnership may have to pay the costs of such defaulting party. (See "-
Unlimited Liability of Investor General Partners," above, and "Proposed
Activities".)
DISSOLUTION OF THE PARTNERSHIP OR WITHDRAWAL OR REMOVAL OF THE MANAGING
GENERAL PARTNER MAY HAVE ADVERSE EFFECTS. At any time commencing ten
years after the Offering Termination Date and the Partnership's primary
drilling activities, the Managing General Partner may voluntarily
withdraw as Managing General Partner without the consent of the
Participants upon giving 120 days' written notice of withdrawal to the
Participants. In addition, the Managing General Partner may be removed
at any time upon sixty days' advance written notice to the outgoing
Managing General Partner, by the affirmative vote of Participants whose
Agreed Subscriptions equal a majority of the Partnership Subscription
(excluding any Units purchased by the Managing General Partner or its
Affiliates). If Atlas would withdraw or be removed as Managing General
Partner of the Partnership and the Participants failed to elect to
continue the Partnership and to designate a substituted Managing General
Partner of the Partnership, the Partnership would terminate and dissolve
and adverse tax and other consequences could result.
If the Partnership was dissolved the Participants may receive a
distribution of direct property interests. As joint interest owners,
Limited Partners would have joint and several liability for the
obligations or liabilities arising out of joint owner operations and
might
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<PAGE>14
find it desirable to obtain insurance protection or dispose of the
property interests, which may be difficult. To reduce this risk the
Managing General Partner will attempt upon liquidation and dissolution
to use its best efforts to sell the Partnership's properties or to cause
some type of entity which would preserve the limited liability of the
former Limited Partners, such as a liquidating trust, to be established
to hold the Partnership's properties. However, even if the properties
were transferred to a liquidating trust upon dissolution of the
Partnership, it might be difficult for the liquidating trust to deal
with such assets and realize their full value. For example, to replace
the management provided by the Managing General Partner, the trustee of
the liquidating trust would need the services of professional operators.
Further, after dissolution and the completion of payments to third party
creditors, the Managing General Partner has priority in liquidation for
any claims of indebtedness before the Participants. Such distributions
may also have adverse income tax consequences to the Participants. (See
"- Unlimited Liability of Investor General Partners," above, and "Tax
Aspects - Disposition of Partnership Interests".)
INDEMNIFICATION AND EXONERATION OF THE MANAGING GENERAL PARTNER WOULD
REDUCE DISTRIBUTIONS. Under the Partnership Agreement the Managing
General Partner and its Affiliates may be indemnified by the Partnership
for losses or liabilities incurred in connection with the activities of
the Partnership if they determined in good faith that the course of
conduct which caused the loss or liability was in the best interest of
the Partnership, they were acting on behalf of or performing services
for the Partnership and such course of conduct was not the result of
their negligence or misconduct. Use of Partnership capital or assets for
such indemnification would reduce amounts available for Partnership
operations or for distribution to Participants. (See "Fiduciary
Responsibility of the Managing General Partner".)
LIMITED PARTNER LIABILITY FOR REPAYMENT OF CERTAIN DISTRIBUTIONS. Under
the Pennsylvania Revised Uniform Limited Partnership Act (the
"Partnership Act"), the liability of the Limited Partners for the
losses, debts and obligations of the Partnership will generally be
limited to their Agreed Subscription and their allocable share of any
undistributed net profits. However, under the Partnership Act a Limited
Partner may, for a period of two years, be required to repay to the
Partnership any Capital Contributions "wrongfully" returned to a Limited
Partner in violation of the Partnership Agreement or Pennsylvania law,
with interest thereon, including but not limited to any distribution to
the Limited Partners to the extent that, after giving effect to such
distribution, all liabilities of the Partnership, other than liabilities
to the Participants on account of their contributions and to the
Managing General Partner, exceed Partnership assets. Also, a Limited
Partner will be liable for the obligations of the Partnership if he
takes part in the control of the business of the Partnership. (See
"Summary of Partnership Agreement - Liability of Limited Partners".)
POSSIBILITY OF UNAUTHORIZED ACTS OF INVESTOR GENERAL PARTNERS. Under the
Partnership Act a general partner may bind the partnership by his
action, unless the partner in fact has no authority to act for the
partnership and the person with whom he is dealing has knowledge of the
fact he has no such authority. Under the Partnership Act, knowledge may
be actual knowledge of the lack of authority or knowledge of other facts
which in the circumstances would show bad faith. Although there is a
risk that an Investor General Partner might bind the Partnership by his
acts, Atlas believes it will have such exclusive control over the
conduct of the business of the Partnership that it is unlikely a third
party, in the absence of bad faith, would deal with an Investor General
Partner as to the Partnership's business.
RISKS THAT REPURCHASE OBLIGATION MAY NOT BE FUNDED AND REPURCHASE PRICE
MAY NOT REFLECT FULL VALUE. Subject to certain conditions, beginning in
2001 the Participants may present their interests for purchase by the
Managing General Partner. The Managing General Partner anticipates
purchasing such interests primarily through cash flow and secondarily
through corporate borrowings secured by the interests purchased. There
is a risk that the Managing General Partner, or its Affiliates, will not
have the necessary cash flow or be able to arrange financing for such
purposes on terms which are reasonable as determined by the Managing
General Partner in its sole discretion, and in such event the Managing
General Partner is able to suspend its repurchase obligation. In
addition, the Managing General Partner has and will incur similar
presentment obligations in connection with other Programs which it or
its Affiliates may sponsor.
The purchase price to be paid to the Participant will be based upon the
Participant's share of the net assets and liabilities of the Partnership
based upon his Agreed Subscription. The purchase price will include:
(i) 70% of the present worth of future net revenues from the
Partnership's Proved Reserves, (ii) Partnership cash on hand, (iii)
prepaid expenses and accounts receivable of the Partnership, less a
reasonable amount for doubtful accounts, and (iv) the estimated market
value of all assets of the Partnership not separately specified above,
determined in accordance with standard industry valuation procedures.
The amount attributable to Partnership reserves will be determined based
on an engineering report prepared by the Managing General Partner and
reviewed by an Independent Expert. The Participants will be provided a
computation of the total oil and gas reserves of the Partnership and the
present worth thereof, employing a discount rate equal to 10%, a
constant price for the oil and basing the price of gas upon the existing
gas contract(s) at the time of the repurchase. The reserve report must
be within 120 days of the commencement of the repurchase offer. There
will be deducted from the foregoing sum: (i) all Partnership 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; provided, however, that if any cash
distributed was derived from the sale, subsequent to the request, of
oil, gas or other mineral
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<PAGE>15
production or of a producing property owned by
the Partnership, for purposes of determining the reduction of the
purchase price, such 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 reserves. The purchase price may be
further adjusted by the Managing General Partner for estimated changes
therein from the date of such reserve report to the date of payment of
the purchase price to the Participants: (i) by reason of production or
sales of, or additions to, reserves and lease and well equipment, sale
or abandonment of leases, and similar matters occurring prior to payment
of the purchase price to the selling Participant, and (ii) by reason of
any of the following occurring prior to payment of the purchase price to
the selling Participant: changes in well performance, increases or
decreases in the market price of oil, gas or other minerals, revision of
regulations relating to the importing of hydrocarbons, changes in
income, ad valorem and other tax laws (e.g., material variations in the
provisions for depletion) and similar matters.
Because of the difficulty in accurately estimating oil and gas reserves,
the purchase price may not reflect the full value of the Partnership
property to which it relates. Such estimates are merely appraisals of
value and may not correspond to realizable value. There can be no
assurance that the purchase price paid for the interest and any revenues
received by the Participant prior to the repurchase will be equal to
the original price paid for such interests. Conversely, a Participant
might realize a greater return if he retains the Units, which the
Participant may elect, rather than sells the Units as provided herein.
(See "Conflicts of Interest - Conflicts Regarding Repurchase Obligation"
and "Repurchase Obligation".)
POSSIBLE PARTICIPATION IN ROLL-UP. There is no assurance that at some
indeterminate time in the future the Partnership will not become
involved in a "Roll-Up" transaction. In that event, there could be
changes in the rights, preferences, and privileges of the Participants
in the Partnership; such as increasing the compensation of the Managing
General Partner, amending the voting rights of the Participants, listing
the Units on a national securities exchange or on NASDAQ, changing the
fundamental investment objectives of the Partnership, or materially
altering the duration of the Partnership. However, any Participant who
votes "no" on a Roll-Up proposal will be offered a choice of (i)
accepting the securities of the Roll-Up Entity offered in the proposed
Roll-Up; (ii) remaining a Participant in the Partnership and preserving
his interests in the Partnership on the same terms and conditions as
existed previously; or (iii) receiving cash in an amount equal to his
pro-rata share of the appraised value of the Partnership's net assets.
(See "Conflicts of Interest - Policy Regarding Roll-Ups" .)
GENERAL RISKS OF THE OIL AND GAS BUSINESS
SPECULATIVE NATURE OF GAS BUSINESS. Gas exploration is an inherently
speculative activity. The Managing General Partner cannot predict the
amount of gas recoverable from any Prospect, the time it will take to
recover the gas or the price at which the gas will be marketed. Because
of the risk involved, there can be no guarantee that the Participants
will recover all of their investment or that their investment will be
profitable. (See "Proposed Activities - Intended Areas of Operations".)
RISKS OF DECREASE IN THE PRICE OF GAS. The price at which the gas can be
sold will depend on factors largely beyond the control of the
Partnership. For example, during most of the 1980's and 1990's oil and
gas prices have been unstable. If there is a significant reduction in
the price of gas, it will have a material adverse impact on the net
revenues which the Partnership will derive from the production of its
wells, possibly even precluding or limiting distributions to the
Participants. There is a substantial risk that the price of gas will
continue to be volatile and may decrease. (See "Proposed Activities -
Sale of Oil and Gas Production" and "Competition, Markets and Regulation
- - Marketing".)
DRILLING HAZARDS MAY BE ENCOUNTERED. There are numerous natural hazards
involved in the drilling of wells including unexpected or unusual
formations, pressures and blowouts that may result in possible damage to
property and third parties including surface damage, bodily injury,
damage to and loss of equipment, reservoir damage and loss of reserves.
The Partnership may also be subject to liability for pollution such as
accidental leakages, abuses of the environment and other similar damages
incurred during drilling. Although the Partnership will maintain
insurance coverage in the amounts the Managing General Partner deems
appropriate, it is possible that insurance coverage may be insufficient.
Uninsured liabilities would reduce the funds available to the
Partnership, may result in the loss of Partnership properties and may
create liability for Investor General Partners. (See "Proposed
Activities - Insurance".)
COMPETITION IN MARKETING NATURAL GAS PRODUCTION. There is competition
for the most desirable Leases, and the Partnership will encounter
intense competition in the sale of its gas production. The quantities of
gas to be delivered by the Partnership may also be affected by factors
beyond its control, such as the inability of the wells to deliver gas at
pipeline quality and pressure, premature exhaustion of reserves, changes
in governmental regulations affecting allowable production and priority
allocations and price limitations imposed by federal and state
regulatory agencies. (See " - Special Risks of the Partnership - Risks
Regarding Marketing of Gas", "Proposed Activities - Sale of Oil and Gas
Production" and "Competition, Markets and Regulation".)
RISK OF NEW GOVERNMENTAL REGULATIONS. Oil and gas operations in the
United States, including lease acquisitions and other energy-related
activities, are subject to extensive government
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<PAGE>16
regulation and to
interruption or termination by governmental authorities on account of
ecological and other considerations. Proposals concerning regulation and
taxation of the oil and gas industry are constantly before Congress. It
is impossible to predict which proposals, if any, will be enacted into
law and, if enacted, the exact effect they might have on the
Partnership. (See "Competition, Markets and Regulation".)
POTENTIAL LIABILITY FOR POLLUTION; ENVIRONMENTAL MATTERS. The
Partnership may be subject to liability for pollution and other damages
due to hazards which cannot be insured against or will not be insured
against due to prohibitive premium costs or for other reasons. In this
regard the Investor General Partners might become liable for obligations
in excess of their Agreed Subscriptions for environmental claims that
arose during drilling activities, but were not discovered until after
the Investor General Partners converted to Limited Partner status.
Environmental regulatory matters also could increase substantially the
cost of doing business, and may cause delays in producing natural gas
from the Partnership's wells or require the modification of operations
in certain areas. (See "Competition, Markets and Regulation".)
UNCERTAINTY OF COSTS. There is no assurance that over the life of the
Partnership there will not be fluctuating or even increasing costs in
doing business. This would directly affect the Managing General
Partner's ability to operate the Partnership's wells and property at
acceptable price levels. (See "Competition, Markets and Regulation -
Competition".)
TAX RISKS
TAX CONSEQUENCES MAY VARY DEPENDING ON INDIVIDUAL CIRCUMSTANCES. There
are various risks associated with the federal income tax aspects of an
investment in the Partnership. Each potential investor is urged to
consult his own tax advisor concerning the effects of federal income tax
law and regulations and interpretations thereof, on his own tax
situation. (See "Tax Aspects".)
RISK OF CHANGES IN THE LAW. The Partnership and the Participants could
be adversely affected by changes in the tax laws that may result through
future Congressional action, Tax Court or other judicial decisions, or
interpretations by the IRS. (See "Tax Aspects".)
NO ADVANCE RULING FROM THE IRS ON TAX CONSEQUENCES. The Managing General
Partner has received an opinion of counsel that, more likely than not,
the Partnership will be classified as a partnership for federal income
tax purposes and not as a corporation or a publicly traded partnership.
The opinion of counsel is not binding on the IRS and is based upon
certain factual assumptions which may or may not prove to be true. No
advance ruling on this or any other tax consequence of an investment in
the Partnership will be requested. (See "Tax Aspects - Partnership
Classification".) Nevertheless, Special Counsel's tax opinion includes
its opinion that the significant tax benefits of the Partnership, in the
aggregate, more likely than not will be realized as contemplated by this
Prospectus. (See "Tax Aspects - Summary of Tax Opinion".)
POSSIBLE TAXES IN EXCESS OF CASH DISTRIBUTIONS. A Participant's share of
Partnership revenues applied to principal on any Partnership loans from
Atlas will be included in his taxable income. Although Partnership
income may be offset in part by depletion or other deductions, interest
on Partnership borrowings will be subject to certain restrictions on the
deduction of "investment interest" and the limitation on passive
activity losses in the case of Limited Partners and no deductions will
be allowed for repayments of principal. Thus, a Participant may become
subject to income tax liability in excess of cash actually received from
the Partnership. To the extent the Partnership has cash available for
distribution, however, it is Atlas' policy that Partnership
distributions will not be less than the Participants' estimated income
tax liability with respect to Partnership income. (See "Tax Aspects -
Limitations on Passive Activities," "- Limitations on Deduction of
Investment Interest," and "- Allocations".)
Under the Partnership Agreement, taxable income or gain may be allocated
to the Participants in the event there are deficits in the Participants'
Capital Accounts even though such Participants are not allocated a
corresponding amount of Partnership revenues. Also, there may be tax
liability in excess of cash distributions to the Participants because
Partnership production revenues are retained by the Operator beginning
three years after the wells are placed in production to establish a
reserve for the estimated costs of eventually plugging and abandoning
Partnership Wells, although historically Atlas has never done this after
only three years. In addition, the taxable disposition of Partnership
property or a Participant's interest in the Partnership may result in
income tax liability in excess of cash distributions. (See "Tax Aspects
- - Sale of the Properties" and "- Disposition of Partnership Interests".)
PARTNERSHIP ALLOCATIONS ARE SUBJECT TO CHALLENGE BY THE IRS IN THE EVENT
OF AN AUDIT. The allocations of Partnership costs, revenues and related
tax items between the Managing General Partner and the Participants are
subject to Treasury Regulations and the proper application of many
provisions of the regulations is currently unclear. Should the IRS
successfully challenge the allocation provisions contained in the
Partnership Agreement, Participants could incur a greater tax liability.
However, assuming the effect of the allocations set forth in the
Partnership Agreement is substantial in light of a Participant's tax
attributes that are unrelated to the Partnership, in Special Counsel's
opinion it is more likely than not that such allocations will govern
each Participant's distributive share to the extent they do not cause or
increase deficit balances in the Participants' Capital Accounts. (See
"Tax Aspects - Allocations".)
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<PAGE>17
1997 TAX DEDUCTIONS ARE SUBJECT TO CHALLENGE BY THE IRS IN THE EVENT OF
AN AUDIT. The Managing General Partner anticipates that all of the
Partnership Subscription will be expended in 1997, and that the
Participants' allocable share of income and deductions generated thereby
will be reflected on the Participants' tax returns for that period. Any
net loss of the Partnership allocable to a Limited Partner (but not an
Investor General Partner) generally will be subject to the "passive
activity" loss limitation rules under the Tax Reform Act of 1986. In
addition, there is no guarantee that if the Partnership is audited the
IRS will not challenge the deductions claimed by the Partnership. The
time for assessment of tax resulting from adjustments to the
Partnership's information tax returns may extend beyond the time for
other assessments. (See "Tax Aspects - Limitations on Passive
Activities," "-1997 Expenditures," "- Availability of Certain
Deductions" and "- Intangible Drilling and Development Costs".)
Depending primarily on when the Partnership Subscription is received, it
is anticipated that the Partnership will prepay in 1997 most, if not
all, of its Intangible Drilling Costs for wells the drilling of which
will be commenced in 1998. The deductibility in 1997 of such advance
payments cannot be guaranteed. (See "Tax Aspects - Drilling Contracts".)
POSSIBLE ALTERNATIVE MINIMUM TAX LIABILITY. Alternative minimum taxable
income of "independent producers," which includes most investors, cannot
be reduced by more than 40% in the 1997 tax year by reason of the repeal
of the preference item for intangible drilling and development costs.
(See "Tax Aspects - Minimum Tax - Tax Preferences".)
INVESTMENT INTEREST DEDUCTIONS MAY BE LIMITED. Interest paid to acquire
or carry investment assets is deductible only to the extent of net
investment income. Because investment income includes income from
activities, such as the Partnership in the case of Investor General
Partners, which are not passive activities and in which the taxpayer
does not materially participate, losses from the Partnership will reduce
an Investor General Partner's investment income and may adversely affect
the deductibility of the Investor General Partner's investment interest
expense, if any. (See "Tax Aspects - Limitations on Deduction of
Investment Interest".)
LACK OF TAX SHELTER REGISTRATION. Atlas believes that the Partnership
will not be a tax shelter required to register with the IRS and does not
intend to cause the Partnership to register as such with the IRS. If it
is subsequently determined that the Partnership was required to be
registered with the IRS as a tax shelter, each Participant would be
liable for a $250 penalty for failure to include the tax registration
number of the Partnership on his tax return, unless such failure was due
to reasonable cause. However, based on the representations of the
Managing General Partner, Special Counsel has expressed the opinion that
the Partnership, more likely than not, is not required to be registered
with the IRS as a tax shelter. (See "Tax Aspects - Lack of Registration
as a Tax Shelter".)
STATE AND LOCAL TAXES MAY APPLY. A Participant may incur tax liability
with respect to Partnership income in the state and locality in which he
resides as well as the states and localities where the Partnership's
Development Wells are situated. Participants should consult with their
own tax advisors concerning the state and local tax consequences of an
investment in the Partnership. (See "Tax Aspects - State and Local
Taxes.)
CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS
IN GENERAL
The Units will not be subject to Assessments. The Partnership will not
call upon the Participants for additional amounts of capital beyond
their Agreed Subscriptions. However, in the case of Investor General
Partners, if the insurance proceeds, Partnership assets, and Atlas' and
Atlas Group's indemnification of the Investor General Partners were not
sufficient to satisfy a Partnership liability for which the Investor
General Partners were also liable, the Managing General Partner could
call upon Investor General Partners to make additional Capital
Contributions to the Partnership from their personal assets to satisfy
such liability. Investor General Partners do not have an option to
refuse to contribute an additional Capital Contribution called by the
Managing General Partner to pay Partnership liabilities. (See "Summary
of Partnership Agreement - Liabilities of General Partners Including
Investor General Partners.")
The drilling of the wells is expected to be funded entirely through the
Partnership Subscription and the Capital Contributions of the Managing
General Partner. In the event the Partnership requires additional funds
as a result of cost overruns in the drilling or completion of wells,
which the Managing General Partner does not anticipate, other than
completing and Fracturing some of the wells in a third zone, or
additional development or remedial work is subsequently required for a
well, then such funds may be provided by borrowings as discussed below
in "- Subsequent Source of Funds and Borrowings" or by the retention of
Partnership revenues. The Managing General Partner does not anticipate,
however, that any borrowings will be required prior to any availability
of revenues from production.
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<PAGE>18
SOURCE OF FUNDS
Upon completion of the offering, the Capital Contributions to the
Partnership of the Participants will range from $1,000,000 to $8,000,000
unless Atlas in its sole discretion offers not more than 200 additional
Units and increases the Participants' Capital Contributions to the
Partnership to not more than $10,000,000. Assuming all of the Leases
are situated in the Mercer County area the Capital Contributions of the
Managing General Partner will range from $198,723 if the Capital
Contributions of the Participants are $1,000,000, to $1,589,705 if the
Capital Contributions of the Participants are $8,000,000, to $1,987,235
if the Capital Contributions of the Participants are $10,000,000. See
the "- Managing General Partner Capital" table below for a breakout of
the costs paid by the Managing General Partner. Therefore, the total
amount of Capital Contributions available to the Partnership from the
Participants and the Managing General Partner would range from
$1,198,723 if 100 Units are sold, to $9,589,705 if 800 Units are sold,
to $11,987,235 if 1,000 Units are sold.
USE OF PROCEEDS
The following tables present information respecting the financing of the
Partnership in three different circumstances: (1) if 1,000 Units
($10,000,000) are sold, (2) if 800 Units ($8,000,000) are sold, and (3)
if the minimum 100 Units ($1,000,000) are sold. Substantially all of the
Partnership Subscription available to the Partnership will be disbursed
for the following purposes and in the following manner:
PARTICIPANT CAPITAL
ENTITY
RECEIVING
PAYMENT 1,000 UNITS 800 UNITS 100 UNITS
TOTAL PARTICIPANT CAPITAL $10,000,000 100% $8,000,000 100% $1,000,000 100%
LESS: PUBLIC OFFERING EXPENSES
Broker-Dealers 0 0 0 0 0 0
Dealer-Manager fee,
Sales Commissions,
and reimbursement
for bona fide
accountable due
diligence expenses (2)
Various
Organization Costs (2) 0 0 0 0 0 0
AMOUNT AVAILABLE FOR INVESTMENT:
The Managing
General
Partner Capital available
for drilling and
completing wells $10,000,000 100% $8,000,000 100% $1,000,000 100%
The Managing
General
Partner
Leases (3) 0 0 0 0 0 0
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1) The percentage is based upon total Participants' Agreed
Subscriptions and excludes the Managing General Partner's Capital
Contribution.
(2) Organization and Offering Costs will be paid by the Managing
General Partner. However, the Managing General Partner will not be
credited with the payment of Organization and Offering Costs in
excess of 15% of the Partnership Subscription towards its required
Capital Contribution of 16.5%.
(3) Instead of making a contribution in cash for Leases, the Leases
will be contributed to the Partnership in kind by the Managing
General Partner and valued at its Cost or fair market value if Cost
is materially more than fair market value. In the Mercer County
area, which is the Partnership's primary area of interest, the
Managing General Partner's cost is $3,600 per Prospect. The Managing
General Partner will contribute approximately 4.49 Prospects if 100
Units are sold, 35.9 Prospects if 800 Units are sold, and 44.9
Prospects if 1,000 Units are sold and all of the Prospects are
situated in the Mercer County area.
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<PAGE>19
MANAGING GENERAL PARTNER CAPITAL
ENTITY
RECEIVING
PAYMENT 1,000 UNITS 800 UNITS 100 UNITS
TOTAL MANAGING GENERAL PARTNER CAPITAL
$1,987,235 100% $1,589,705 100% $198,723 100%
LESS: PUBLIC OFFERING EXPENSES
Broker-Dealers
Dealer-Manager fee,
Sales Commissions,
and reimbursement
for bona fide
accountable due
diligence expenses(2) $1,050,000 53% $840,000 53% $105,000 53%
Various
Organization Costs (2 $450,000 23 $360,000 23% $45,000 23%
AMOUNT AVAILABLE FOR INVESTMENT:
The Managing
General
Partner
Capital available
for drilling and
completing wells $325,581 16 $260,465 16% $32,558 16%
The Managing
General
Partner
Leases (3) $161,654 8% $129,240 8% $16,165 8%
(1) The percentage is based upon the Managing General Partner's
Capital Contribution and excludes the Participants' Agreed
Subscriptions.
(2) Organization and Offering Costs will be paid by the Managing
General Partner. However, the Managing General Partner will not be
credited with the payment of Organization and Offering Costs in
excess of 15% of the Partnership Subscription towards its required
Capital Contribution of 16.5% .
(3) Instead of making a contribution in cash for Leases, the Leases
will be contributed to the Partnership in kind by the Managing
General Partner at its Cost or fair market value if Cost is
materially more than fair market value. In the Mercer County area,
which is the Partnership's primary area of interest, the Managing
General Partner's cost is $3,600 per Prospect. The Managing General
Partner will contribute approximately 4.49 Prospects if 100 Units are
sold, 35.9 Prospects if 800 Units are sold, and 44.9 Prospects if
1,000 Units are sold and all of the Prospects are situated in the
Mercer County area.
SUBSEQUENT SOURCE OF FUNDS AND BORROWINGS
As indicated above, it is anticipated that substantially all of the
Partnership's initial capital will be committed or expended following
the offering. Any additional funds which may subsequently be required
will be withheld from production from Partnership Wells or borrowings by
the Partnership from Atlas or its Affiliates, although Atlas is not
contractually committed to make such a loan. There will be no borrowings
from third parties.
The amount that may be borrowed by the Partnership from Atlas and its
Affiliates may not at any time exceed 5% of the Partnership Subscription
and must be without recourse to the Participants. The Partnership's
repayment of any such borrowings would be from Partnership production
revenues and would reduce or delay cash distributions to the
Participants. See "Conflicts of Interest - Procedures to Reduce
Conflicts of Interest," paragraph (9), for the terms of any loan with
Atlas.
COMPENSATION
A narrative presentation of the items of compensation paid to the
Managing General Partner and its Affiliates from the Partnership is set
forth below. Following the narrative presentation is a tabular
presentation of the estimated Administrative Costs and Direct Costs to
be borne by the Partnership.
OIL AND GAS REVENUES. The Managing General Partner will be allocated 25%
of the oil and gas revenues of the Partnership in return for paying
Organization and Offering Costs equal to 15% of the Partnership
Subscription, 14% of Tangible Costs and contributing all Leases to the
Partnership at Cost, or fair market value if Cost is materially more
than fair market value. (See "Participation in Costs and Revenues.)
<PAGE>20
LEASE COSTS. The Managing General Partner will contribute sufficient
undeveloped Leases to the Partnership to drill the Partnership's wells
at the Cost of such Leases, or fair market value if Cost is materially
more than fair market value. The Cost of the Leases will include a
portion of the Managing General Partner's reasonable, necessary and
actual expenses for geological, geophysical, engineering, interest
expense, legal, and other like services allocated to the Partnership's
Leases determined using industry guidelines which are set forth in
"Proposed Activities - Acquisition of Leases". The Managing General
Partner will not retain any Overriding Royalty Interest for itself from
such Leases. Assuming all of the Leases are in the Mercer County area
and the Partnership acquires 100% of the Working Interest in 4.49
Prospects if the minimum Partnership Subscription is received, 35.9
Prospects if the maximum Partnership Subscription is received, and 44.9
Prospects if the Managing General Partner increases the size of the
offering to $10,000,000, it is estimated that Atlas' credit for Lease
costs at $3,600 per Prospect will range from $16,165, to $129,240, to
$161,654, respectively. (See "Proposed Activities - Acquisition of
Leases".)
Such contributions could create conflicts of interest for the Managing
General Partner. The majority of the wells will be drilled by the
Partnership to test the Clinton/Medina geologic formation, a blanket
geological formation prevalent in Ohio and Pennsylvania. A Prospect will
be deemed to consist of the drilling or spacing unit on which such well
will be drilled if the Clinton/Medina geological formation to which such
well will be drilled contains Proved Reserves and the drilling or
spacing unit protects against drainage. The development of wells on such
acreage may provide Atlas with offset sites by allowing it to ascertain
at the Partnership's expense the value of adjacent acreage in which the
Partnership would not have any right to participate in developing. (See
"Conflicts of Interest - Conflicts Involving Acquisition of Leases,"
"Conflicts of Interest - Other Activities of the Managing General
Partner, the Operator and their Affiliates" and "Proposed Activities".)
ADMINISTRATIVE COSTS. The Managing General Partner and its Affiliates
will receive an unaccountable, fixed payment reimbursement for their
Administrative Costs determined by the Managing General Partner to be an
amount equal to $75 per well per month, which will be proportionately
reduced to the extent the Partnership acquires less than 100% of the
Working Interest in the well. The unaccountable, fixed payment
reimbursement of $75 per well per month will not be increased in amount
during the term of the Partnership and will not be received for plugged
and abandoned wells. Further, Atlas, as Managing General Partner, will
not be reimbursed for any additional Partnership Administrative Costs
and the unaccountable, fixed payment reimbursement of $75 per well per
month will be the entire payment to reimburse Atlas for the
Partnership's Administrative Costs. See "Estimate of Administrative
Costs and Direct Costs to Be Borne by the Partnership" for an estimate
of those costs in the first twelve months.
DRILLING CONTRACTS. The Partnership will enter into a drilling contract
with Atlas to drill and complete the Partnership Wells at a competitive
industry rate. For each well completed and placed into production in
the Appalachian Basin, the Partnership will pay Atlas an amount equal to
$37.39 per foot to the depth of the well at its deepest penetration. For
each well which the Partnership elects not to complete, the Partnership
will pay Atlas an amount equal to $20.60 per foot to the depth of the
well. The footage contract will cover all costs other than the cost of
a pumping unit for an oil well, which is not anticipated, and the cost
of a third completion and Frac, which means, in general, treating a
third potentially productive geological formation in an attempt to
enhance the gas production from the well. (See "Definitions".) Such
costs will be charged at Cost plus 10% if provided by third parties and
at competitive rates in the area if provided by Atlas or its Affiliates.
The cost of the well will be proportionately reduced to the extent the
Partnership acquires less than 100% of the Working Interest. (See the
Drilling and Operating Agreement, Exhibit (II) to the Partnership
Agreement.)
The amount of compensation which Atlas could earn as a result of these
arrangements is dependent upon many factors, including the actual cost
of the wells and the number of wells drilled. Atlas anticipates that in
the Mercer County area of the Appalachian Basin it will have
reimbursement of general and administrative overhead of $3,600 per well
and a profit of approximately 15% ($33,960) per well for a well drilled
to a depth of 6,150 feet. Assuming the Partnership acquires 100% of the
Working Interest in 4.49 Prospects if the minimum Partnership
Subscription is received, 35.9 Prospects if the maximum Partnership
Subscription is received and 44.9 Prospects if the Managing General
Partner increases the size of the offering to $10,000,000 and all of the
wells are situated in the Mercer County area and drilled to 6,150 feet
and completed, it is estimated that Atlas' general and administrative
reimbursement and profit will be approximately $168,644 if the minimum
Partnership Subscription is received, $1,348,404 if the maximum
Partnership Subscription is received, and $1,686,444 if the Managing
General Partner increases the size of the offering to $10,000,000.
PER WELL CHARGES. When the wells have commenced production Atlas, as
Operator, will be reimbursed at actual cost for all direct expenses
incurred on behalf of the Partnership and will receive well supervision
fees for operating and maintaining the wells during producing operations
at a competitive rate. In the Appalachian Basin the competitive rate is
currently $275 per well per month subject to an annual adjustment for
inflation. Assuming the Partnership acquires 100% of the Working
Interest in 4.49 Prospects if the minimum Partnership Subscription is
received, 35.9 Prospects if the maximum Partnership Subscription is
received, and 44.9 Prospects if the Managing General Partner increases
the size of the offering to $10,000,000, and all of the wells are
situated in the Appalachian Basin and drilled and completed, it is
estimated that these costs will be approximately $14,817 if the minimum
Partnership Subscription is received, $118,470 if the maximum
Partnership Subscription is received, and $148,170 if the Managing
General Partner increases the size of the offering to $10,000,000, for
the Partnership's first twelve months of operations. The well
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<PAGE>21
supervision fees will be proportionately reduced to the extent the
Partnership acquires less than 100% of the Working Interest in the well.
TRANSPORTATION AND MARKETING FEES. Mercer Gas Gathering, Inc., an
Affiliate of Atlas, will deliver natural gas produced by the Partnership
to either industrial end-users in the area or interstate pipeline
systems and local distribution companies. Atlas Gas Marketing, Inc., an
Affiliate of Atlas, will provide marketing services to the Partnership.
The Partnership will pay a combined transportation and marketing charge
at a competitive rate, which is currently 29 cents per MCF. The actual
amount to be paid cannot be quantified because the amount of gas that
will be produced from the Wells cannot be predicted. (See
"Management".)
DEALER-MANAGER FEES. The Dealer-Manager will receive from the
Partnership on each Unit sold to an investor a 2.5% Dealer-Manager fee,
a 7.5% Sales Commission and a .5% reimbursement of the Selling Agents'
accountable due diligence expenses. If the minimum Partnership
Subscription of $1,000,000 is received the Dealer-Manager will receive
$105,000, if the maximum Partnership Subscription is received the
Dealer-Manager will receive $840,000 and if the offering is increased
to $10,000,000 the Dealer-Manager will receive $1,050,000. The 7.5%
Sales Commission and the .5% accountable due diligence expense will be
reallowed to the Selling Agents and the 2.5% Dealer-Manager fee will be
reallowed to the wholesalers.
OTHER COMPENSATION. Atlas or an Affiliate will be reimbursed by the
Partnership for any loan Atlas or an Affiliate may make to or on behalf
of the Partnership and will have the right to charge a competitive rate
of interest on any such loan. If Atlas provides equipment, supplies and
other services to the Partnership it may do so at competitive industry
rates. (See "Conflicts of Interest".)
ESTIMATE OF ADMINISTRATIVE COSTS AND
DIRECT COSTS TO BE BORNE BY THE PARTNERSHIP
The Managing General Partner estimates that the unaccountable, fixed
payment reimbursement for Administrative Costs allocable to the
Partnership's first twelve months of operation will not exceed
approximately $4,041 if the minimum Partnership Subscription is received
(4.49 wells at $75 per well per month), approximately $32,310 if the
maximum Partnership Subscription is received (35.9 wells at $75 per well
per month), and approximately $40,410 if the Managing General Partner
increases the size of the offering to $10,000,000 (44.9 wells at $75 per
well per month). Administrative Costs are all customary and routine
expenses incurred for the conduct of Partnership administration,
including: legal, finance, accounting, secretarial, travel, office rent,
telephone, data processing and other items of a similar nature. No
Administrative Costs charged will be duplicated under any other category
of expense or cost.
Minimum Maximum If Managing
General
Partnership Partnership Partner Increases
Subscription Subscription Offering
Unaccountable, fixed payment
reimbursement for
Administrative Costs $4,041 $32,310 $40,410
Direct Costs will be billed directly to and paid by the Partnership to
the extent practicable. The anticipated Direct Costs set forth below
for the Partnership's first twelve months of operation may vary from the
estimates shown for numerous reasons which cannot accurately be
predicted, such as the number of Participants, the number of wells
drilled, the Partnership's degree of success in its activities, the
extent of any production problems, inflation and various other factors
involving the administration of the Partnership.
Minimum Maximum If Managing
General
Partnership Partnership Partner Increases
Subscription Subscription Offering
DIRECT COSTS
External Legal $ 6,000 $ 6,000 $6,000
Audit Fees 2,500 6,000 6,000
Independent Engineering Reports 1,500 3,000 3,000
TOTAL $10,000 $15,000 $15,000
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<PAGE>22
TERMS OF THE OFFERING
SUBSCRIPTION TO THE PARTNERSHIP
The Partnership will offer a minimum of 100 Units and a maximum of 800
Units. However, if subscriptions for all 800 Units being offered are
obtained, the Managing General Partner, in its sole discretion, may
offer not more than 200 additional Units and increase the maximum
aggregate subscriptions with which the Partnership may be funded to not
more than 1,000 Units ($10,000,000). Units in the Partnership are
offered at a subscription price of $10,000 per Unit. The minimum
subscription per investor is one Unit; however, the Managing General
Partner, in its discretion, may accept one-half Unit ($5,000)
subscriptions. Larger Agreed Subscriptions will be accepted in $1,000
increments.
The Managing General Partner will have exclusive management authority
for the Partnership. Subscribers who purchase Units as Investor General
Partners or as Limited Partners will serve as Participants of the
Partnership.
PAYMENT OF SUBSCRIPTIONS
Agreed Subscriptions are payable 100% in cash at the time of
subscribing.
PARTNERSHIP CLOSINGS AND ESCROW
Subject to the receipt of the minimum Partnership Subscription of
$1,000,000, the Managing General Partner may close the offering period
on or before December 31, 1997 (the "Offering Termination Date"). No
subscriptions to the Partnership will be accepted after receipt of the
maximum Partnership Subscription (including the additional 200 Units
which may be offered) or the Offering Termination Date, whichever event
occurs first. Pending receipt of the minimum Partnership Subscription,
subscription deposits in the escrow account will earn interest at
National City Bank of Pennsylvania's variable market rate for short-
term deposits. If subscriptions for $1,000,000 are not received by
December 31, 1997, the sums deposited in the escrow account will be
returned to the subscribers with interest thereon. Although the
Managing General Partner and its Affiliates may buy up to 10% of the
Units, which will not be applied towards the minimum Partnership
Subscription required for the Partnership to begin operations, the
Managing General Partner currently does not anticipate that it and its
Affiliates will purchase any Units. (See "Conflicts of Interest -
Conflicts Between Participants.")
Subscription payments will be held in a separate interest bearing
escrow account at National City Bank of Pennsylvania pending the
receipt of the minimum Partnership Subscription. Subject to the
receipt of the minimum partnership Subscription, there will be two
closings which are tentatively set for December 1, 1997 ("Initial
Closing Date"), and December 31, 1997. The Partnership will begin all
activities, including drilling, after the Initial Closing Date. A
Participant will receive interest on his Agreed Subscription up until
the Offering Termination Date at the market rate paid by National City
Bank of Pennsylvania. Any interest earned on Agreed Subscriptions will
be credited to the accounts of the respective subscribers and paid
approximately eight weeks after the Offering Termination Date.
Subscriptions will not be commingled with the funds of the Managing
General Partner or its Affiliates nor shall subscriptions be subject to
the claims of their creditors.
Subscription proceeds will be invested during the escrow period only in
institutional investments comprised of or secured by securities of the
United States government. The funds in the Partnership account, pending
their use for Partnership operations, may be temporarily invested in
income producing short-term, highly liquid investments, where there is
appropriate safety of principal, such as U.S. Treasury Bills. In the
event that the Managing General Partner determines that the Partnership
may be deemed an investment company under the Investment Company Act of
1940, such investment activity will cease.
OFFERING PERIOD
The offering period will commence on the date of this Prospectus and
will terminate on a date to be determined by the Managing General
Partner, in its sole discretion. In no event, however, will the
offering period extend beyond the earlier of December 31, 1997, or the
receipt of Partnership subscriptions for $10,000,000.
ACCEPTANCE OF SUBSCRIPTIONS
The execution of the Subscription Agreement by a subscriber constitutes
a binding offer to buy Units in the Partnership and an agreement to
hold the offer open until the Agreed Subscription is accepted or
rejected by the Managing General Partner. Once an investor subscribes
he will not have any revocation rights. The Managing General Partner
has the discretion to refuse to accept any Agreed Subscription without
liability to the subscriber. Agreed Subscriptions will be accepted or
rejected by the Partnership within thirty days of their receipt; if
rejected, all funds will be returned to the subscriber immediately.
Upon the original sale of Units, the Participants will be admitted as
Partners not later than fifteen days after the release from escrow of
Participants' funds to the Partnership, and thereafter Participants
will be admitted into the Partnership not later than the last day of
the calendar month in which their Agreed Subscriptions were accepted by
the Partnership.
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<PAGE>23
The execution of the Subscription Agreement and its acceptance by the
Managing General Partner also constitutes the execution of the
Partnership Agreement and an agreement to be bound by the terms thereof
as a Participant, including the granting of a special power of attorney
to the Managing General Partner appointing it as the Participant's
lawful representative and attorney in-fact to make, execute, sign, swear
to and file an Amended Certificate of Limited Partnership from time to
time, governmental reports and certifications, and other matters. (See
the Partnership Agreement, Exhibit (A) to this Prospectus.)
DRILLING PERIOD
Although it is anticipated that the Partnership will spend the entire
Partnership Subscription soon after the Offering Termination Date, the
Partnership will have a period of one year from the termination of the
offering period to use or commit funds to drilling activities. If,
within such one year period, the Partnership has not used, or committed
for use, as evidenced by a written agreement, the net subscription
proceeds, then the Managing General Partner will cause the remainder of
such net subscription proceeds, except for necessary operating capital
and amounts reserved for identified activities, to be distributed pro
rata to the Participants in the ratio of their Agreed Subscriptions as a
return of capital, together with interest earned thereon after the
Offering Termination Date, and the Managing General Partner will
reimburse the Participants for selling or other offering expenses
allocable to the return of capital.
INTEREST OF PARTICIPANTS IN THE PARTNERSHIP
See "Participation in Costs and Revenues - Allocation and Adjustment
Among Participants" regarding the Participants' share of revenues,
gains, costs, credits, expenses, losses and other charges and
liabilities.
QUALIFICATION OF THE PARTNERSHIP
The Managing General Partner has elected for the Partnership to be
governed by the partnership laws of Pennsylvania and has filed the
Certificate of Limited Partnership. The Managing General Partner will
take all other actions necessary to qualify the Partnership to do
business as a limited partnership or cause the limited partnership
status of the Partnership to be recognized in other jurisdictions.
SUITABILITY STANDARDS
IN GENERAL. It is the obligation of persons selling Units to make every
reasonable effort to assure that the Units are suitable for investors,
based on the investor's investment objectives and financial situation,
regardless of the investor's income or net worth. This is not an
appropriate investment for IRAs, Keogh plans and qualified retirement
plans. The Managing General Partner shall maintain for a period of at
least six years a record of each investor's suitability.
Units will be sold only to an investor who has a minimum net worth of
$225,000 or a minimum net worth of $60,000 and had during the last tax
year or estimates that he 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 Units. Net worth will be determined exclusive
of home, home furnishings and automobiles. Additional suitability
requirements are applicable to residents of certain states. (See "-
Purchasers of Limited Partner Units" and "- Purchasers of Investor
General Partner Units", below.)
Also, the transferability of Participants' interest is limited, both by
express provision of the Partnership Agreement and the provisions of
state and federal securities laws. (See "Risk Factors - Special Risks
of the Partnership - Illiquid Investment and Restrictions on
Transferability of Participants' Interests.") For example, California
residents generally may not transfer Units without the consent of the
California Commissioner of Corporations, and the Commissioner of
Securities of Missouri classifies the Units as being ineligible for any
transactional exemption under the Missouri Uniform Securities Act
(Section 409.402(b), RSMo. 1969). Therefore, unless the Units are again
registered, the offer for sale or resale of Units by a Participant in
the State of Missouri may be subject to the sanctions of the act. Other
state securities law limitations on the transferability of Participants'
interests will be applicable in other states.
PURCHASERS OF LIMITED PARTNER UNITS. A resident of California must (i)
have a net worth of not less than $250,000 (exclusive of home,
furnishings, and automobiles) and expect to have gross income in the
current tax year of $65,000 or more, or (ii) have a net worth of not
less than $500,000 (exclusive of home, furnishings, and automobiles), or
(iii) have a net worth of not less than $1,000,000, or (iv) expect to
have gross income in the current tax year of not less than $200,000.
A Michigan or North Carolina resident must have either: (i) a net worth
of not less than $225,000 (exclusive of home, furnishings, and
automobiles), or (ii) a net worth of not less than $60,000 (exclusive of
home, furnishings, and automobiles) and estimated current tax year
taxable income as defined in Section 63 of the Internal Revenue Code of
1986 of $60,000 or more without regard to an investment in the
Partnership. In addition, a resident of Michigan, Ohio or Pennsylvania
shall not make an investment in the Partnership in excess of 10% of his
net worth (exclusive of home, furnishings and automobiles).
PURCHASERS OF INVESTOR GENERAL PARTNER UNITS. A resident of Alabama,
Maine, Massachusetts, Minnesota, North Carolina, Pennsylvania, Tennessee
or Texas must represent that he (i) has an individual or joint net worth
with his or her spouse of $225,000 or more, without regard to the
investment in the Partnership (exclusive of home, furnishings, and
automobiles), and a combined gross
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<PAGE>24
income of $100,000 or more for the
current year and for the two previous years; or (ii) has an individual
or joint net worth with his or her spouse in excess of $1,000,000,
inclusive of home, home furnishings and automobiles; or (iii) has an
individual or joint net worth with his or her spouse in excess of
$500,000, exclusive of home, home furnishings, and automobiles; or (iv)
has a combined "gross income" as defined in Code Section 61 in excess of
$200,000 in the current year and the two previous years.
A resident of Arizona, Indiana, Iowa, Kansas , Kentucky, Michigan,
Missouri, Mississippi, New Hampshire, New Mexico, Ohio, Oklahoma,
Oregon , South Dakota, Vermont or Washington must represent that he (i)
has an individual or joint net worth with his or her spouse of $225,000
or more, without regard to the investment in the Partnership (exclusive
of home, furnishings, and automobiles), and a combined "taxable income"
of $60,000 or more for the previous year and expects to have a combined
"taxable income" of $60,000 or more for the current year and for the
succeeding year; or (ii) has an individual or joint net worth with his
or her spouse in excess of $1,000,000, inclusive of home, home
furnishings and automobiles; or (iii) has an individual or joint net
worth with his or her spouse in excess of $500,000, exclusive of home,
home furnishings, and automobiles; or (iv) has a combined "gross income"
as defined in Code Section 61 in excess of $200,000 in the current year
and the two previous years. In addition, a resident of Michigan, Ohio
or Pennsylvania shall not make an investment in the Partnership in
excess of 10% of his net worth (exclusive of home, furnishings and
automobiles).
A resident of California must represent that he (i) has a net worth of
not less than $250,000 (exclusive of home, furnishings, and automobiles)
and expects to have gross income in the current tax year of $120,000 or
more, or (ii) has a net worth of not less than $500,000 (exclusive of
home, furnishings, and automobiles), or (iii) has a net worth of not
less than $1,000,000 or (iv) expects to have gross income in the current
tax year of not less than $200,000.
MISCELLANEOUS. In the case of sales to fiduciary accounts, all of the
suitability standards set forth above and for the appropriate state
shall 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 interests if the donor or grantor is the fiduciary.
Investors are required to execute their own Subscription Agreements. The
Managing General Partner will not accept any Subscription Agreement that
has been executed by someone other than the investor, unless such person
has been given the legal power of attorney to sign on the investor's
behalf and the investor meets all of the conditions herein.
The Managing General Partner may not complete a sale of Units to an
investor until at least five business days after the date the investor
receives a final prospectus. In addition, the Managing General Partner
will send each investor a confirmation of purchase.
Transferees of Units seeking to become substituted Partners must meet
the requirements imposed by the Partnership Agreement. (See
"Transferability of Units".)
SUBSCRIPTION BY MANAGING GENERAL PARTNER
Atlas will serve as Managing General Partner of the Partnership and is
required to make certain contributions to the Partnership. The Managing
General Partner and its officers and directors and Affiliates may also
subscribe for Units in the Partnership on the same basis as Limited
Partners or Investor General Partners, except that they are not required
to pay the Dealer-Manager fee, Sales Commissions and due diligence
reimbursements. Also, the Managing General Partner and its Affiliates
may buy up to 10% of the Units, which will not be applied towards the
minimum Partnership Subscription required for the Partnership to begin
operations, although the Managing General Partner currently does not
anticipate that it and its Affiliates will purchase any Units. Subject
to the foregoing, any subscription by the Managing General Partner or
its officers, directors or Affiliates will dilute the voting rights of
the Participants; however, they are prohibited from voting with respect
to certain matters. (See "Summary of Partnership Agreement - Voting
Rights.")
CONFLICTS OF INTEREST
IN GENERAL
Conflicts of interest are inherent in oil and gas drilling programs
involving non-industry participants because transactions are entered
into without arms' length negotiation. The interests of the Participants
and those of Atlas and its Affiliates may be inconsistent in some
respects or in certain instances. The following discussion describes
certain possible conflicts of interest that may arise for Atlas and its
Affiliates in the course of the Partnership and certain limitations
which are designed to reduce, but which will not eliminate, the
conflicts. It should be noted, however, that the following discussion is
not intended to be all inclusive and that other transactions or dealings
may arise in the future that could result in conflicts of interest for
Atlas and its Affiliates. (See "Fiduciary Responsibility of the Managing
General Partner".)
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
The Managing General Partner is accountable to the Partnership as a
fiduciary and consequently has a duty to exercise good faith and to deal
fairly with the Participants in handling the affairs of the Partnership.
While the Managing General Partner will endeavor to avoid conflicts of
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<PAGE>25
interest to the extent possible, such conflicts nevertheless may occur
and, in such event, the actions of the Managing General Partner may not
be most advantageous to the Partnership. Because Atlas makes a
significant Capital Contribution to the Partnership, this conflict of
interest will be reduced. Nevertheless, in the event the Managing
General Partner should breach its fiduciary responsibilities, a
Participant would be entitled to an accounting and to recover any
economic losses caused by such breach. (See "Fiduciary Responsibility of
the Managing General Partner".)
TRANSACTIONS WITH ATLAS AND ITS AFFILIATES
Although Atlas and its Affiliates believe that the items of compensation
and reimbursement that it and its Affiliates will receive in connection
with the Partnership are reasonable, the items of compensation have been
determined solely by Atlas and are not the result of any negotiation or
agreement between Atlas and any person dealing at arms' length and
having no affiliation between them. Atlas will be entitled to receive
items of compensation and reimbursement in connection with the
Partnership even though it is possible that the Partnership's activities
could result in little or no profit, or a loss to Participants. Although
such fees must be competitive with the prices of other unaffiliated
persons in the same geographic area engaged in similar businesses, the
entity or person providing the services or equipment can be expected to
profit from such transactions. It may be to the best interests of Atlas
to first enter into contracts with itself and its Affiliates and second
with nonaffiliated parties even though the contract terms, or skill and
experience, offered by the nonaffiliated parties to the Partnership may
be comparable to that available from Atlas and its Affiliates.
The Managing General Partner and any Affiliate will 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 such person
is engaged, independently of the Partnership and as an ordinary and
ongoing business, in the business of rendering such services or selling
or leasing such equipment and supplies to a substantial extent to other
persons in the oil and gas industry in addition to the partnerships in
which the Managing General Partner or an Affiliate has an interest; and
the compensation, price or rental therefor will be 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 such person is not engaged in such a
business then such compensation, price or rental will be the Cost of
such services, equipment or supplies to such person or the competitive
rate which could be obtained in the area, whichever is less.
Any services not otherwise described in this Prospectus for which the
Managing General Partner or any of its Affiliates are to be compensated
will be embodied in a written contract which precisely describes the
services to be rendered and the compensation to be paid. Such
compensation, if any, will be reported to Participants in the
Partnership's annual and semiannual reports pursuant to 4.03(b)(1)(b)
of the Partnership Agreement and a copy of any such contract will be
provided to a Participant upon request pursuant to 4.03(b)(5) of the
Partnership Agreement. Such contracts are cancelable without penalty
upon sixty days written notice by Participants whose Agreed
Subscriptions equal a majority of the Partnership Subscription. With
respect to Units owned by the Managing General Partner or its
Affiliates, the Managing General Partner and its Affiliates may not vote
or consent regarding any transactions between the Partnership and the
Managing General Partner or its Affiliates, and their Units will not be
included for purposes of determining a majority of the Partnership
Subscription with respect to such contracts.
CONFLICT REGARDING THE DRILLING AND OPERATING AGREEMENT
It is anticipated that all of the wells developed by the Partnership
will be drilled and operated pursuant to the Drilling and Operating
Agreement. As the Managing General Partner of the Partnership, Atlas
will be required to monitor and enforce, on behalf of the Partnership,
its own compliance with the provisions of the Drilling and Operating
Agreement, which creates a continuing conflict of interest. (See
"Proposed Activities".)
CONFLICTS REGARDING SHARING OF COSTS AND REVENUES
The share of revenues that Atlas will receive pursuant to the
Partnership Agreement will be "Carried" in that Atlas will contribute
total Capital Contributions to the Partnership in an amount less than
the Partnership's revenues which it will receive. This may create a
conflict of interest between the Managing General Partner and the
Participants regarding the determination of which Leases will be
acquired by the Partnership and the profit potential associated with the
Leases.
In addition, the allocation of all of the Intangible Drilling Costs to
the Participants and 14% of the Tangible Costs to Atlas of the wells
developed by the Partnership involves conflicts of interest between the
Participants and Atlas where completion of a marginally productive well
might prove beneficial to the Participants but not to Atlas. At the
time a completion decision is made the Participants will have already
paid the majority of their costs so they will want to complete the well
if there is any opportunity to recoup any of their costs. Conversely,
the Managing General Partner will not have paid any money prior to this
time and it will only want to pay such costs if it is assured of
recouping its money and making a profit. Based upon its past
experience, however, Atlas anticipates that all Partnership Wells in the
Clinton/Medina geological formation will be required to be completed
before a determination can be made as to the well's productivity. In
any event, Atlas will not cause any well to be plugged and abandoned by
the Partnership without a completion attempt having been made unless
Atlas determines that such well should be plugged and abandoned in
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<PAGE>26
accordance with the generally accepted and customary oil and gas field
practices and techniques then prevailing in the geographic area of the
well location.
TAX MATTERS PARTNER
Atlas will be the Partnership's "Tax Matters Partner" and, as such, will
have broad authority to act on behalf of the Partnership and the
Participants in any administrative or judicial proceeding involving the
IRS. The possession of such authority by the Tax Matters Partner may
involve conflicts of interest such as whether or not to expend
Partnership funds to contest a proposed adjustment by the IRS, if any,
to the amount of the Partnership's deduction for Intangible Drilling
Costs which is allocated 100% to the Participants, or to contest a
proposed decrease by the IRS, if any, in the amount of the Managing
General Partner's credit to its Capital Account for contributing the
Leases to the Partnership which would decrease the Managing General
Partner's Distribution Interest in the Partnership. There also may be
conflicts of interest with respect to the Partnership's reimbursement of
expenses incurred by the Managing General Partner in its role as the
Partnership's Tax Matters Partner. (See "Tax Aspects".)
OTHER ACTIVITIES OF THE MANAGING GENERAL PARTNER, THE OPERATOR AND THEIR
AFFILIATES
Atlas will be required to devote to the Partnership such time and
attention as Atlas considers to be necessary or appropriate for the
proper supervision and management of the operations and activities of
the Partnership. Atlas has sponsored and continues to manage other
Programs (see "Prior Activities"), and Atlas expects to organize and
manage additional Programs, which may be concurrent. In addition, Atlas
and its Affiliates will be free to engage in other oil and gas related
business activities, either for their own account or on behalf of other
Programs, partnerships, joint ventures, corporations or other entities
in which they have an interest. They may, therefore, be expected to have
conflicts of interest in allocating management time, services and other
functions among the Partnership and such other oil and gas Programs,
partnerships and ventures.
Subject to its fiduciary duties, Atlas will not be restricted in any
manner from participating in other businesses or activities, despite the
fact that such other businesses or activities may be competitive with
the operations and activities of the Partnership and may operate in the
same areas as the Partnership. Notwithstanding, 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 such opportunity either
cannot be pursued by the Partnership because of insufficient funds or
because it is not appropriate for the Partnership under the existing
circumstances.
CONFLICTS INVOLVING THE ACQUISITION OF LEASES
Atlas will select, in its sole discretion, the Prospects to be developed
by the Partnership. Conflicts of interest may arise concerning which
Prospects Atlas will assign to the Partnership and which Atlas will
assign to other drilling Programs to be organized by Atlas or where
Atlas serves as driller/operator. It may prove to Atlas' or its
Affiliates' advantage to have the Partnership bear the costs and risks
of drilling a particular Prospect rather than another Program. These
potential conflicts of interest will be increased to some extent by the
fact that Atlas expects to be organizing and allocating Prospects to
more than one drilling Program at a time including a year-end Program in
which Affiliates of the Managing General Partner invest. There can be
no assurance that the activities of the Partnership and those of other
drilling Programs to be organized by Atlas will not conflict.
To reduce this conflict of interest the Managing General Partner
generally takes a similar interest in other Programs where it serves as
Managing General Partner and/or driller/operator.
In Pennsylvania and Ohio the assignments of the Leases will be limited
to a depth of from the surface through the Clinton/Medina geological
feature to the top of the Queenston formation, and Atlas will retain the
drilling rights below the Clinton/Medina geological formation. Although
the retention of the deep drilling rights may create a conflict of
interest between the Partnership and Atlas, Atlas believes that the
Partnership's drilling to the Clinton/Medina geological formation will
not provide any geologic information that would prove up or assist in
evaluating drilling to formations deeper than the Clinton/Medina
geological formation. Further, the amount of the credit Atlas receives
for the Partnership Leases does not include any value allocable to the
deep drilling rights retained by Atlas.
No procedures, other than the guidelines set forth below, have been
established by the Managing General Partner to handle or to resolve any
of the conflicts which may arise in this or another context; however,
the Managing General Partner owes a fiduciary duty to the Participants
in the operation and management of the Partnership and is restricted
from engaging in certain transactions with Affiliates and others under
the terms of the Partnership Agreement. The Managing General Partner,
its Affiliates and the Partnership will abide by the guidelines set
forth below.
(1) FAIR AND REASONABLE. Neither the Managing General Partner nor
any Affiliate will sell, transfer, or convey any property to or
purchase any property from the Partnership, directly or indirectly,
except pursuant to 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.
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<PAGE>27
(2) TRANSFERS AT COST. The Leases acquired from the Managing General
Partner or its Affiliates must be contributed to the Partnership at
the Cost of such Lease, unless the Managing General Partner shall
have cause to believe that Cost is materially more than the fair
market value of such property, in which case the credit for such
contribution will be made for a price not in excess of its fair
market value. A determination of fair market value must be supported
by an appraisal from an Independent Expert. Such opinion and any
associated supporting information must be maintained in the
Partnership's records for at least six years.
(3) LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND
ITS AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. During a period
of five years from 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 such
proposed acquisition, the following conditions shall apply
(a) 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
(b) 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 own 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 consummate 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) TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS
AFFILIATE'S 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 will not be made unless the interest
retained by the Managing General Partner or the Affiliate is a
proportionate Working Interest, 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 the Managing General Partner's
interest in revenues does not exceed the amount proportionate to its
retained Working Interest. Neither the Managing General Partner nor
any Affiliate will retain any Overriding Royalty Interests or other
burdens on an interest sold by it to the Partnership. With respect to
its retained interest the Managing General Partner will not Farmout a
Lease for the primary purpose of avoiding payment of its costs
relating to drilling the Lease. This paragraph 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.
(5) 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 oil, gas or other mineral interests or
property to the Partnership, it must, at the same time, sell 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 such well will be
drilled by the Partnership if the geological feature to which such
well will be drilled contains Proved Reserves and the drilling or
spacing unit protects against drainage. With respect to an oil and
gas Prospect located in Ohio and Pennsylvania on which a well will be
drilled by the Partnership to test the Clinton/Medina geologic
formation a Prospect shall be deemed to consist of the drilling and
spacing unit if it meets the test in the preceding sentence.
It is anticipated that most of the Prospects which will be
developed by the Partnership will develop the Clinton/Medina geologic
formation. The development of wells on such acreage may provide the
Managing General Partner with offset sites by allowing it to
ascertain at the Partnership's expense the value of adjacent acreage
in which the Partnership would not have any right to participate in
developing. See the Production Map in "Proposed Activities -
Information Regarding Currently Proposed Prospects" for the acreage
owned by the Managing General Partner in the area surrounding the
currently proposed Prospects. To reduce this conflict of interest
neither the Managing General Partner nor its Affiliates may drill any
well within 1,650 feet of an existing Partnership Well in the
Clinton/Medina formation in Pennsylvania, or within 1,100 feet of an
existing Partnership Well in Ohio, within five years of the drilling
of the Partnership Well. In the event the Partnership abandons its
interest in a well, this restriction will continue for one year
following the abandonment.
- --------------------------------------------------------------
<PAGE>28
(6) SUBSEQUENTLY ENLARGING PROSPECT. If the area constituting the
Partnership's Prospect is subsequently enlarged to encompass any area
wherein 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, such
separate property interest or a portion thereof shall be sold,
transferred or conveyed to the Partnership in accordance with
Sections 2, 4 and 5, above, if the activities of the Partnership were
material in establishing the existence of Proved Undeveloped Reserves
which are attributable to such separate property interest.
Notwithstanding, Prospects in the Clinton/Medina geological formation
will 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 Clinton/Medina geological formation and the drilling
or spacing unit protected against drainage.
(7) TRANSFER OF LEASES TO THE MANAGING GENERAL PARTNER. The Managing
General Partner and its Affiliates will not purchase any producing or
non-producing oil and gas properties from the Partnership.
(8) TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The
Partnership shall not purchase properties from or sell properties to
any other Affiliated partnership. This prohibition, however, shall
not apply to joint ventures among such Affiliated partnerships,
provided that the respective obligations and revenue sharing of all
parties to the transaction are substantially the same and 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.
(9) NO FARMOUTS. The Partnership shall not farmout its Leases.
(10) LEASES ONLY FOR STATED PURPOSE OF THE PARTNERSHIP. 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 unless the acquisition is made after
a well has been drilled to a depth sufficient to indicate that such
an acquisition would be in the Partnership's best interest.
CONFLICTS BETWEEN PARTICIPANTS
The Managing General Partner and its officers and directors and
Affiliates may also subscribe for Units in the Partnership on the same
basis as Limited Partners or Investor General Partners, except that they
are not required to pay Dealer-Manager fees, Sales Commissions or due
diligence reimbursements. Also, the Managing General Partner and its
Affiliates may buy up to 10% of the Units, which will not be applied
towards the minimum Partnership Subscription required for the
Partnership to begin operations, although the Managing General Partner
currently does not anticipate that it and its Affiliates will purchase
any Units. Subject to the foregoing, any subscription by the Managing
General Partner or its officers, directors or Affiliates will dilute the
voting rights of the Participants and there may be a conflict with
respect to certain matters. However, the Managing General Partner and
its officers, directors and Affiliates also are prohibited from voting
with respect to certain matters. (See "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. Prospective Participants have not
been separately represented by legal counsel, which might include the
negotiation of certain more favorable terms in the Partnership
Agreement and the Drilling and Operating Agreement on behalf of
prospective Participants. Although Anthem Securities, Inc., which is
affiliated with the Managing General Partner, as Dealer-Manager will
receive reimbursement of accountable due diligence expenses for certain
due diligence investigations conducted by the Selling Agents which will
be reallowed to the Selling Agents, the Dealer-Manager's due diligence
examination concerning this offering cannot be considered to be
independent. There was not an extensive in-depth "due diligence"
investigation of the existing and proposed business activities of the
Partnership and the Managing General Partner which would be provided by
independent underwriters. However, Anthem Securities, Inc. in
conjunction with Atlas Group has contracted with Nationwide Financial
Network, a due diligence entity, to prepare and maintain an independent
due diligence report for their network of independent broker-dealers
which may request it. (See "Plan of Distribution".)
CONFLICTS CONCERNING LEGAL COUNSEL
It is anticipated that legal counsel to Atlas will also serve as legal
counsel to the Partnership and that such dual representation will
continue in the future. However, should a future dispute arise between
the Participants and Atlas, or should counsel advise Atlas that counsel
reasonably believes its representation of the Partnership will be
adversely affected by counsel's responsibilities to Atlas, Atlas will
cause the Participants to retain separate counsel for such matters.
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<PAGE>29
CONFLICTS REGARDING REPURCHASE OBLIGATION
The Participants' right to present their Units to Atlas for repurchase
creates a conflict of interest between the Participants and the Managing
General Partner in the suspension of the repurchase obligation and in
arriving at the amount which will be paid by the Managing General
Partner for the Participants' interests. The Managing General Partner
may suspend its repurchase obligation if it does not have the necessary
cash flow or it cannot borrow the funds on terms which the Managing
General Partner deems reasonable, which is a subjective determination.
The Managing General Partner will also determine the repurchase price
based upon a reserve report prepared by the Managing General Partner and
reviewed by an Independent Expert chosen by the Managing General
Partner. Furthermore, the formula for arriving at the repurchase price
has some subjective determinations within the control of the Managing
General Partner. (See "Repurchase Obligation".)
OTHER CONFLICTS
A conflict of interest is created with the Participants by the Managing
General Partner's right to hypothecate its interest or withdraw an
interest in the Partnership Wells with respect to the Managing General
Partner's subordination obligation. A further conflict of interest is
created by the Managing General Partner's right to determine the order
of priority and the construction of pipelines which may be required in
order to connect certain Prospects into the Atlas transmission network.
(See "Risk Factors - Special Risks of the Partnership - Borrowings by
the Managing General Partner Could Reduce Funds Available for Its
Subordination Obligation" and "Summary of Partnership Agreement -
Withdrawal of Managing General Partner".)
PROCEDURES TO REDUCE CONFLICTS OF INTEREST
The Managing General Partner and its Affiliates have adopted the
following procedures and conditions to reduce some of the conflicts of
interest inherent in oil and gas drilling programs and to assure that
transactions between the Managing General Partner or its Affiliates, on
the one hand, and the Partnership, on the other hand, are fair and
reasonable. The Managing General Partner has no other conflict of
interest resolution procedures. Consequently, conflicts of interest
between the Managing General Partner and the Participants may not
necessarily be resolved in the best interests of the Participants.
(1) NO COMMINGLING. The funds of the Partnership will be kept in
separate accounts and will not be commingled with the funds of the
Managing General Partner, any Affiliate or any other entity.
(2) NO COMPENSATING BALANCES. Neither the Managing General Partner
nor any Affiliate will use the Partnership's funds as compensating
balances for its own benefit.
(3) FUTURE PRODUCTION. Neither the Managing General Partner nor any
Affiliate will commit the future production of a well developed by
the Partnership exclusively for its own benefit.
(4) MARKETING ARRANGEMENTS. All benefits from marketing arrangements
or other relationships affecting property of the Managing General
Partner or its Affiliates and the Partnership will be fairly and
equitably apportioned according to the respective interests of each
in such property. The Managing General Partner shall treat all wells
in a geographic area equally concerning to whom and at what price
the Partnership's gas will be sold and to whom and at what price the
gas of other oil and gas Programs which the Managing General Partner
has sponsored or will sponsor will be sold. The Managing General
Partner calculates a weighted average selling price for all of the
gas sold in a geographic area by taking all money received from the
sale of all of the gas sold to its customers in a geographic area
and dividing by the volume of all gas sold from the wells in that
geographic area.
Notwithstanding, the Managing General Partner and its Affiliates
are parties to, and contract for, the sale of natural gas with
industrial end-users and will continue to enter into such contracts
on their own behalf, and the Partnership will not be a party to such
contracts. The Managing General Partner and its Affiliates also have
a substantial interest in certain pipeline facilities and
compression facilities which access interstate pipeline systems,
which it is anticipated will be used to transport the Partnership's
gas production as well as Affiliated partnership and third-party gas
production, and the Partnership will not receive any interest in the
Managing General Partner's and its Affiliates' pipeline or gathering
system or compression facilities. (See "Proposed Activities - Sale
of Oil and Gas Production - In General".)
(5) ADVANCE PAYMENTS. Advance payments by the Partnership to the
Managing General Partner and its Affiliates are prohibited, except
where advance payments are required to secure tax benefits of
prepaid drilling costs and for a business purpose. These payments,
if any, will not include nonrefundable payments for completion costs
prior to the time that a decision is made that the well or wells
warrant a completion attempt.
(6) NO PROFIT IN CONTRAVENTION OF FIDUCIARY DUTY. The Managing
General Partner will not profit by drilling in contravention of its
fiduciary obligation to the Participants.
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<PAGE>30
(7) DISCLOSURE. Any agreement or arrangement which binds the
Partnership must be fully disclosed in the Prospectus.
(8) LOANS FROM THE PARTNERSHIP. The Partnership will not loan money
to the Managing General Partner or any Affiliate.
(9) LOANS TO THE PARTNERSHIP. Neither the Managing General Partner
nor any Affiliate will loan money to the Partnership where the
interest to be charged exceeds the Managing General Partner's or the
Affiliate's interest cost or where the interest to be charged
exceeds 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, and neither the Managing
General Partner nor any Affiliate will receive points or other
financing charges or fees, regardless of the amount, although the
actual amount of such charges incurred from third-party lenders may
be reimbursed to the Managing General Partner or the Affiliate.
(10) 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.
(11) SALE OF ASSETS. The sale of all or substantially all of the
assets of the Partnership (including without limitation, Leases,
wells, equipment and production) can only be made with the consent
of Participants (including Atlas and its Affiliates with respect to
any Units purchased by them) whose Agreed Subscriptions equal a
majority of the Partnership Subscription (including Units purchased
by Atlas and its Affiliates).
(12) PARTICIPATION IN OTHER PARTNERSHIPS. If the Partnership
participates in other partnerships or joint ventures (multi-tier
arrangements), the terms of any such arrangements shall not result
in the circumvention of any of the requirements or prohibitions
contained in the Partnership Agreement, including the following:
(i) there will be no duplication or increase in organization and
offering expenses, the Managing General Partner's compensation,
Partnership expenses or other fees and costs; (ii) there will be no
substantive alteration in the fiduciary and contractual relationship
between the Managing General Partner and the Participants; and (iii)
there will be no diminishment in the voting rights of the
Participants.
(13) INVESTMENTS. Partnership funds may not be invested in the
securities of another person except in the following instances: (i)
investments in Working Interests or undivided Lease interests made
in the ordinary course of the Partnership's business; (ii) temporary
investments in income producing short-term highly liquid
investments, where there is appropriate safety of principal, such as
U.S. Treasury Bills; (iii) multi-tier arrangements meeting the
requirements of (12) above; (iv) investments involving less than 5%
of the Partnership Subscription 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, in such instances duplicative fees and expenses shall be
prohibited.
POLICY REGARDING ROLL-UPS
It is possible at some indeterminate time in the future that the
Partnership will become involved in a "Roll-Up". The complete definition
of "Roll-Up" is set forth in "Definitions." In general, a Roll-Up means
a transaction involving the acquisition, merger, conversion, or
consolidation of the Partnership with or into another partnership,
corporation or other entity (the "Roll-Up Entity") and the issuance of
securities by the Roll-Up Entity to Participants. A Roll-Up will also
include any change in the rights, preferences, and privileges of the
Participants in the Partnership; such changes could include increasing
the compensation of the Managing General Partner, amending the voting
rights of the Participants, listing the Units on a national securities
exchange or on NASDAQ, changing the fundamental investment objectives of
the Partnership, or materially altering the duration of the Partnership.
The Partnership Agreement provides various policies in the event that a
Roll-Up should occur in the future. These policies include: (i) an
appraisal of all Partnership assets will be from a competent Independent
Expert, and a summary of the appraisal will be included in a report to
the Participants in connection with a proposed Roll-Up; (ii) any
Participant who votes "no" on the proposal will be offered a choice of
(a) accepting the securities of the Roll-Up Entity offered in the
proposed Roll-Up; (b) remaining a Participant in the Partnership and
preserving his interests in the Partnership on the same terms and
conditions as existed previously; or (c) receiving cash in an amount
equal to his pro-rata share of the appraised value of the Partnership's
net assets; and (iii) the Partnership will not participate in a proposed
Roll-Up (a) which would result in the diminishment of a Participant's
voting rights under the Roll-Up Entity's chartering agreement; (b) in
which the Participants' right of access to the records of the Roll-Up
Entity would be less than those provided by the Partnership Agreement;
or (c) in which any of the costs of the transaction would be borne by
the Partnership if the proposed Roll-Up is not approved by 75% in
interest of the Participants.
- ------------------------------------------------------------------------------
<PAGE>31
The Partnership Agreement further provides that the Partnership will not
participate in a Roll-Up transaction unless the Roll-Up transaction is
approved by Participants whose Agreed Subscriptions equal 75% of the
Partnership Subscription. (See 4.03(d)(16) of the Partnership
Agreement.) With respect to Units owned by the Managing General Partner
and its Affiliates, the Managing General Partner and its Affiliates will
not vote or consent with respect to a proposed Roll-Up, and in
determining the required percentage interest of Units necessary to
approve any proposed Roll-Up, any Units owned by the Managing General
Partner and its Affiliates will not be included.
CERTAIN TRANSACTIONS
As of July 15, 1997, previous limited partnerships sponsored by the Managing
General Partner and its Affiliates had made payments to the Managing General
Partner and its Affiliates as set forth below.
PROSPECTIVE INVESTORS SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PROGRAMS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIP.
Leasehold Cumulative
Drilling Reimbursement
Non- and Cumulative of General and
Investor -recurring Completion Operator's Administrative
Subscriptions Management Costs(1)(2) Charges Overhead
Program Fee
Atlas L.P. #1-1985 $600,000 0 $600,000 $151,205 $33,500
A.E. Partners 1986 631,250 0 631,250 113,309 45,508
A.E. Partners 1987 721,000 0 721,000 119,214 48,451
A.E. Partners 1988 617,050 0 617,050 94,885 43,599
A.E. Partners 1989 550,000 0 550,000 76,495 41,343
A.E. Partners 1990 887,500 0 887,500 121,709 43,378
A.E. Nineties-10 2,200,000 0 2,200,000 272,670 43,820
A.E. Nineties-11 750,000 0 761,802 102,809 64,866
A.E. Partners 1991 868,750 0 867,500 93,964 52,797
A.E. Nineties-12 2,212,500 0 2,272,017 289,882 63,113
A.E. Nineties-JV 92 4,004,813 0 4,157,700 418,445 89,124
A.E. Partners 1992 600,000 0 600,000 52,715 24,075
A.E. Nineties-P #1 2,988,960 0 3,026,348 189,778 48,499
A.E. Nineties-93 Ltd 3,753,937 0 3,480,656 302,543 57,046
A.E. Partners 1993 700,000 0 689,940 52,794 18,975
A.E. Nineties-P #2 3,323,920 0 3,324,668 196,130 36,658
A.E. Nineties-14 9,940,045 0 9,512,015 610,680 113,491
A.E. Partners 1994 892,500 0 892,500 30,977 15,638
A.E. Nineties-P#3 5,799,750 0 5,799,750 228,632 45,020
A.E. Nineties-15 10,954,715 0 9,859,244 358,132 66,851
A.E. Partners 1995 600,000 0 600,000 14,751 2,588
A.E. Nineties-P#4 6,991,350 0 6,991,350 191,459 31,415
A.E. Nineties-16 10,955,465 0 10,955,465 135,712 18,482
A.E. Partners 1996 800,000 0 800,000 1,737 488
A.E. Nineties-P#5 7,992,240 0 7,992,240 14,677 3,075
A.E. Nineties-17 (3) 4,628,750 0 4,628,750 0 0
- --------------------------------
(1) Excluding the Managing General Partner's Capital Contributions.
(2) Includes additional drilling costs paid with production revenues.
(3) This program had its first closing on June 25, 1997.
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
GENERAL
The Managing General Partner is vested with the power and authority to manage
the Partnership and its assets. Consequently, it is accountable to the
Participants as a fiduciary and must exercise good faith and act with
integrity in handling the affairs of the Partnership. 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, and the Managing General
- -----------------------------------------------------------------------------
<PAGE> 32
Partner may not employ, or permit another to employ, such funds or assets in
any manner except for the exclusive benefit of the Partnership. Neither the
Partnership Agreement nor any other agreement between the Managing General
Partner and the Partnership may contractually limit any fiduciary duty
owed to the Participants by the Managing General Partner under applicable law
except as set forth in 4.01, 4.02, 4.04, 4.05 and 4.06 of the Partnership
Agreement. This is a rapidly expanding and changing area of the law and
Participants who have questions concerning the duties of the Managing
General Partner should consult their 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 will not be liable to the Partnership or the
Participants 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 the Managing General Partner, the
Operator and their Affiliates determined in good faith that such course of
conduct was in the best interest of the Partnership; the
Managing General Partner, the Operator and their Affiliates were acting on
behalf of, or performing services for, the Partnership; and such course of
conduct did not constitute negligence or misconduct of the Managing
General Partner, the Operator or their Affiliates. Therefore, Participants may
have a more limited right of action than they would have had absent these
limitations in the Partnership Agreement. These limitations, however, do not
apply to Participants' rights under the federal securities laws,
and Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription may vote to remove the Managing General Partner
and/or the Operator. (See "Summary of Partnership Agreement - Voting Rights"
and "- Removal of Operator.")
In addition, the Partnership Agreement provides for indemnification of the
Managing General Partner, the Operator and their Affiliates by the Partnership
against any losses, judgements, liabilities, expenses and amounts paid in
settlement of any claims sustained by them in connection with the Partnership
provided that 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; the Managing
General Partner, the Operator and their Affiliates were acting on behalf of,
or performing services for the Partnership; and such course of conduct was not
the result of negligence or misconduct of the Managing
General Partner, the Operator or their Affiliates.
Payments arising from such indemnification or agreement to hold harmless are
recoverable only out of the tangible net assets of the Partnership including
insurance proceeds.
Notwithstanding the above, the Managing General Partner, the Operator and
their Affiliates and any person acting as a broker-dealer may not be
indemnified for any losses, liabilities, or expenses arising from or out of an
alleged violation of federal or state securities laws unless (i) there has
been a successful adjudication on the merits of each count involving alleged
securities law violations as to a particular indemnity, (ii) such claims have
been dismissed with prejudice on the merits by a court of competent
jurisdiction as to a particular indemnity, or (iii) a court of competent
jurisdiction approves a settlement of the claims as to a particular indemnity
and finds that indemnification of the settlement and related costs should be
made, and the court considering the request for indemnification has been
advised of the position of the Securities and Exchange Commission, the
Massachusetts Securities Division, the states which are specifically set forth
in the Partnership Agreement, and the position of any state securities
regulatory authority in which the plaintiff claims he was offered or sold
Partnership Units, with respect to the issue of indemnification for violation
of securities laws.
LIMITATIONS ON MANAGING GENERAL PARTNER INDEMNIFICATION
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, Participants should be aware that, in the
opinion of the Securities and Exchange Commission, such indemnification is
contrary to public policy and therefore unenforceable. In any event,
Participants and their advisers should review closely the provisions of the
Partnership Agreement concerning exculpation and indemnification of the
Managing General Partner and consult their own attorneys if they have any
questions.
The Partnership will not incur the cost of the portion of any insurance which
insures any party against any liability as to which such party is prohibited
from being indemnified.
The advancement of Partnership funds to the Managing General Partner or its
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 such 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.
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<PAGE>33
PRIOR ACTIVITIES
The following tables, other than Table 5, reflect certain historical data with
respect to twenty-one private drilling programs in which Atlas served as
Managing General Partner, which raised a total of $49,068,405, and five public
drilling programs in which Atlas served as Managing General Partner which
raised a total of $27,096,220.
FOR SEVERAL REASONS, INCLUDING DIFFERENCES IN PROGRAM STRUCTURE, PROPERTY
LOCATIONS, PROGRAM SIZE AND ECONOMIC CONSIDERATIONS, IT SHOULD NOT BE ASSUMED
THAT PARTICIPANTS IN THE OFFERING COVERED BY THIS PROSPECTUS WILL EXPERIENCE
RETURNS, IF ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS IN SUCH
PRIOR DRILLING PROGRAMS. THE RESULTS OF SUCH PRIOR DRILLING PROGRAMS SHOULD BE
VIEWED ONLY AS A MEASURE OF THE LEVEL OF ACTIVITY AND EXPERIENCE OF ATLAS WITH
RESPECT TO DRILLING PROGRAMS.
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<PAGE>43
Table 1 sets forth certain sales information of previous limited partnerships
sponsored by the Managing General Partner and its Affiliates.
PROSPECTIVE INVESTORS SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PROGRAMS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIP.
<TABLE>
EXPERIENCE IN RAISING FUNDS
As of July 15, 1997
Date of
Com- Years
mence- Date of Wells Pre-
Number Investor Atlas ment of First In vious
of Subscrip- Invest- Total Opera- Distri- Produc- Assess-
Investors ment Capital tions butions tion ments.
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <S>
Atlas L.P. #1-1985 19 600,000 114,800 714,800 12/31/85 07/02/86 11.55 -0-
A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 10.55 -0-
A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 9.55 -0-
A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 8.55 -0-
A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 7.55 -0-
A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 6.55 -0-
A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 6.33 -0-
A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 5.50 -0-
A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 5.33 -0-
A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 5.25 -0-
A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 4.08 -0-
A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 4.58 -0-
A.E. Nineties-P#1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 3.83 -0-
A.E. Nineties-1993 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 3.50 -0-
A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 3.25 -0-
A.E. Nineties-P#2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 3.00 -0-
A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 2.50 -0-
A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 2.25 -0-
A.E. Nineties-P#3 391 5,799,750 928,546 6,728,296 12/31/94 06/05/95 2.25 -0-
A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 06/15/95 02/07/96 1.42 -0-
A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96 1.00 -0-
A.E. Nineties-P#4 324 6,991,350 1,287,782 8,279,132 12/31/95 07/08/96 1.25 -0-
A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 0.58 -0-
A.E. Partners 1996 21 800,000 349,992 1,149,992 12/31/96 07/02/97 0.25 -0-
A.E. Nineties-P#5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 0.25 -0-
A.E. Nineties-17 (1) 105 4,628,750 1,133,917 5,762,667 N/A 1997 N/A -0-
(1) This program had its first closing on June 25, 1997.
</TABLE>
- ------------------------------------------------------------------------------
<PAGE>35
<TABLE>
Table 2 reflects the drilling activity of previous limited partnerships
sponsored by the Managing General Partner and its Affiliates. All of the wells
were Development Wells.
PROSPECTIVE INVESTORS SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PROGRAMS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIP.
WELL STATISTICS - DEVELOPMENT WELLS
As of July 15, 1997
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 (4) 0 7 1 0 3.15 0.25
A.E. Partners 1986 0 8 0 0 3.50 0.00
A.E. Partners 1987 0 9 0 0 4.10 0.00
A.E. Partners 1988 0 9 0 0 3.80 0.00
A.E. Partners 1989 0 10 0 0 3.30 0.00
A.E. Partners 1990 0 12 0 0 5.00 0.00
A.E. Nineties-10 0 12 0 0 11.50 0.00
A.E. Nineties-11 0 14 0 0 4.30 0.00
A.E. Partners 1991 0 12 0 0 4.95 0.00
A.E. Nineties-12 0 14 0 0 12.50 0.00
A.E. Nineties-JV 92 0 52 0 0 24.44 0.00
A.E. Partners 1992 0 7 0 0 3.50 0.00
A.E. Nineties-Public #1 0 14 0 0 14.00 0.00
A.E. Nineties-1993 Ltd. (4) 0 20 2 0 19.40 2.00
A.E. Partners 1993 0 8 0 0 4.00 0.00
A.E. Nineties-Public #2 0 16 0 0 15.31 0.00
A.E. Nineties-14 0 55 1 0 55.00 1.00
A.E. Partners 1994 (4) 0 12 0 0 5.00 0.00
A.E. Nineties-Public #3 0 27 0 0 26.00 0.00
A.E. Nineties-15 (4) 0 61 0 0 55.50 0.00
A.E. Partners 1995 0 6 0 0 3.00 0.00
A.E. Nineties-Public #4 0 31 0 0 30.50 0.00
A.E. Nineties-16 (4) 0 57 0 0 47.50 0.00
A.E. Partners 1996 0 13 0 0 4.44 0.00
A.E. Nineties-Public #5 0 36 0 0 35.91 0.00
A.E. Nineties-17
TOTALS 0 522 4 0 399.60 .25
(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. 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 without a completion attempt because the Operator has
determined that it will not be productive of gas and/or oil in commercial
quantities.
(4) Atlas L.P. #1-1985 had 1 gross well (.25 net well) which was completed
but non-commercial; A.E. Nineties-1993 Ltd. had 1 gross well (1 net well)
which was completed but non-commercial; A.E. Nineties-14 had 2
gross wells (2 net wells) which were completed but non-commercial; A.E.
Partners-1994 had 1 gross well (.25 net well) which were completed but non-
commercial; A.E. Nineties-15 had 1 gross well (1 net well)
which was completed but non-commercial and A.E. Nineties-16 had 5 gross wells
(4.5 net wells) which were completed but non-commercial.
- -----------------------------------------------------------------------------
<PAGE>36
Table 3 provides information concerning the operating results of previous
the Managing General Partner and its Affiliates.
PROSPECTIVE INVESTORS SHOULD NOT ASSUME THAT THE PAST
PERFORMANCE OF PRIOR PROGRAMS IS INDICATIVE OF THE FUTURE RESULTS OF THE
PARTNERSHIP.
</TABLE>
<TABLE>
INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
as of July 15, 1997
Cash
Total Costs -on- Average Latest Quarterly
---------------------------- Cash Yearly Cash Distribution
Program Capitalization(1) Operating Admn. Direct Distributions(2) Return Return as of 7/15/97
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 $ 600,000 $127,012 $28,140 6,361 $1,228,961 205% 18% $10,040
A.E. Partners 1986 631,250 95,180 38,227 5,326 575,337 91% 9% 5,995
A.E. Partners 1987 721,000 92,534 37,608 5,469 483,516 67% 7% 3,276
A.E. Partners 1988 617,050 71,771 32,978 5,091 432,263 70% 8% 3,373
A.E. Partners 1989 550,000 62,726 33,901 3,846 565,563 103% 14% 6,325
A.E. Partners 1990 887,500 91,282 43,378 4,457 666,176 75% 11% 13,221
A.E. Nineties-10 2,200,000 204,502 43,820 17,399 1,190,163 54% 9% 22,316
A.E. Nineties-11 750,000 71,966 45,406 29,194 705,084 94% 17% 16,338
A.E. Partners 1991 868,750 70,473 52,797 12,648 671,870 77% 15% 21,509
A.E. Nineties-12 2,212,500 202,917 44,179 97,912 1,321,083 60% 11% 32,364
A.E. N -JV 92 (3) 4,004,813 280,358 59,713 185,156 2,217,254 55% 14% 95,605
A.E. Partners 1992 600,000 39,536 24,075 2,755 465,131 78% 17% 20,487
A.E. Nineties-P#1 2,988,960 144,231 36,859 68,629 1,387,107 46% 12% 45,623
A.E. Ni1993 Ltd. 3,753,937 211,780 39,932 24,081 1,450,142 39% 11% 56,440
A.E. Partners 1993 700,000 39,595 18,975 2,185 465,738 67% 20% 27,464
A.E. Nineties-P#2 3,323,920 149,059 27,860 27,729 1,083,221 32% 11% 79,873
A.E. Nineties-14 9,940,045 409,156 76,039 12,665 2,605,629 26% 10% 155,174
A.E. Partners 1994 892,500 23,233 15,638 1,593 347,929 39% 17% 39,354
A.E. Nineties-P#3 5,799,750 171,474 33,765 31,042 1,600,227 28% 12% 147,830
A.E. Nineties-15 10,954,715 250,692 46,796 9,862 2,460,670 22% 16% 302,259
A.E. Partners 1995 600,000 11,063 2,588 1,048 149,330 25% 25% 21,433
A.E. Nineties-P#4 6,991,350 143,594 23,561 18,711 1,009,362 14% 11% 175,000
A.E. Nineties-16 10,955,465 106,534 14,508 10,676 758,339 7% 12% 289,527
A.E. Partners 1996 800,000 1,303 488 5,592 6,115 1% 4% 6,115
A.E. Nineties-P#5 7,992,240 11,008 2,306 8,433 88,678 1% 4% 88,678
A.E. Nineties-17 (4) 4,628,750 0 0 0 0 0% 0% 0
- --------------------------------------
(1) There have been no Partnership borrowings other than from Atlas. The approximate principal
amounts of such borrowings were as follows: A.E. Nineties-10 - $330,000, A.E. Nineties-11 - $112,500, A.E.
Nineties-12 - $331,875. A portion of each program's cash distributions was used to repay that program's
loan.
(2) All cash distributions were from the sale of gas, and not sales of properties.
(3) A portion of the cash distributions was used to drill three reinvestment wells at a cost of $333,860
in accordance with the terms of the offering.
(4) This program had its first closing on June 25, 1997.
- -----------------------------------------------------------------------------
</TABLE
<PAGE>37
</TABLE>
<TABLE>
Table 3A provides information concerning the operating results of previous limited partnerships sponsored by the Managing
General Partner and its Affiliates.
PROSPECTIVE INVESTORS SHOULD NOT ASSUME THAT THE PAST
PERFORMANCE OF PRIOR PROGRAMS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIP.
MANAGING GENERAL PARTNER
OPERATING RESULTS - INCLUDING EXPENSES
as of July 15, 1997
Cash
Total Costs -on- Latest Quarterly
--------------------------- Cash Cash Cash Distribution
Program Capitalization Operating Admn. Direct Distributions(1) Return as of 7/15/97
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 114,800 24,193 5,360 1,212 232,637 203% 1,912
A.E. Partners 1986 120,400 18,129 7,281 1,014 109,917 91% 1,142
A.E. Partners 1987 158,269 26,680 10,843 1,577 121,674 77% 945
A.E. Partners 1988 135,450 23,114 10,621 1,640 104,949 77% 1,086
A.E. Partners 1989 120,731 13,769 7,442 844 129,779 107% 1,388
A.E. Partners 1990 244,622 30,427 0 0 257,116 105% 4,970
A.E. Nineties-10 484,380 68,168 0 0 417,128 86% 8,150
A.E. Nineties-11 268,003 30,843 19,460 7,454 295,453 110% 7,002
A.E. Partners 1991 318,063 23,491 0 0 299,619 94% 8,079
A.E. Nineties-12 791,833 86,965 18,934 16,455 566,178 72% 13,870
A.E. Nineties-JV 92 1,414,917 138,087 29,411 9,657 788,970 56% 2,195
A.E. Partners 1992 176,100 13,179 0 0 232,741 132% 7,288
A.E. Nineties-P#1 528,934 45,547 11,640 9,866 365,283 69% 14,407
A.E. Nineties-1993 1,264,183 90,763 17,114 6,738 317,836 25% 0
A.E. Partners 1993 219,600 13,199 0 0 174,765 80% 9,463
A.E. Nineties-P#2 587,340 47,071 8,798 8,756 199,268 34% 0
A.E. Nineties-14 3,584,027 201,524 37,452 6,238 1,103,820 31% 76,429
A.E. Partners 1994 231,500 7,744 0 0 122,365 53% 13,584
A.E. Nineties-P#3 928,546 57,158 11,255 10,347 533,409 57% 49,277
A.E. Nineties-15 3,435,936 107,440 20,055 4,226 1,048,297 31% 123,365
A.E. Partners 1995 244,725 3,688 0 0 36,869 15% 7,379
A.E. Nineties-P#4 1,287,752 47,865 7,854 6,237 317,298 25% 39,177
A.E. Nineties-16 1,643,320 29,178 3,974 1,560 168,821 10% 78,607
A.E. Partners 1996 349,992 434 0 0 4,065 1% 4,065
A.E. Nineties-P#5 1,654,740 3,669 769 2,811 0 0% 0
A.E. Nineties-17 (2) 1,133,917 0 0 0 0 0% 0
(1) All cash distributions were from the sale of gas and not sales of properties.
(2) This program had its first closing on June 25, 1997.
</TABLE>-
- ----------------------------------------------------------------------------
<PAGE>38
<TABLE>
Table 4 sets forth the aggregate cash distributions and estimated federal tax savings to investors in
Atlas' prior programs, based on the maximum marginal tax rate in each year, as reported in the partnerships'
tax returns and such share of tax deductions as a percentage of their subscriptions. PROSPECTIVE
SUBSCRIBERS ARE URGED TO CONSULT WITH THEIR OWN TAX ADVISORS CONCERNING THEIR SPECIFIC TAX SITUATIONS AND SHOULD NOT
ASSUME THAT THE PAST PER21`FORMANCE OF PRIOR PROGRAMS IS INDICATIVE OF THE FUTURE RESULTS OF THE
PARTNERSHIP.
SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
as of July 15, 1997
1st Year Eff. 1st Year Section Distribution Total Cash Dist.
Investor Tax Tax I.D.C. Depletion 29 Tax as of date Dist, & Tax Savings
Program Capital Deduct-2 Rate Deduct-3 Allowance Depre. Credit-4 Total of table-5 TaxSavings to Date
<S> <C> <C> <C> <C> <C> <C> <C> <S> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 600,000 99% 50.0% 298,337 103,036 N/A 55,915 $457,288 1,228,961 1,686,249 281%
A.E. Partners 1986 631,250 99% 50.0% 312,889 54,288 N/A 13,507 380,684 575,337 956,021 151%
A.E. Partners 1987 721,000 99% 38.5% 356,895 40,243 N/A N/A 397,138 483,516 880,654 122%
A.E. Partners 1988 617,050 99% 33.0% 244,351 35,613 N/A N/A 279,964 432,263 712,227 115%
A.E. Partners 1989 550,000 99% 33.0% 179,685 50,165 N/A N/A 229,850 565,563 795,413 145%
A.E. Partners 1990 887,500 99% 33.0% 275,125 61,702 N/A 178,026 514,853 666,176 1,181,029 133%
A.E. Nineties-10 2,200,000 100% 33.0% 726,000 113,583 N/A 333,688 1,173,271 1,190,163 2,363,434 107%
A.E. Nineties-11 750,000 100% 31.0% 232,500 64,811 N/A 213,136 510,447 705,084 1,215,531 162%
A.E. Partners 1991 868,750 100% 31.0% 269,313 70,107 N/A 188,068 527,488 671,870 1,199,358 138%
A.E. Nineties-12 2,212,500 100% 31.0% 685,875 134,29 N/A 390,962 1,211,130 1,321,083 2,532,213 114%
A.E. Nineties-JV 92 4,004,813 92.5%31.0% 1,313,629208,589 N/A 551,396 2,073,614 2,217,254 4,290,868 107%
A.E. Partners 1992 600,000 100% 31.0% 186,000 52,423 N/A 139,670 378,093 465,131 843,224 141%
A.E. Nineties-P#1 2,988,960 80.5%36.0% 877,511 132,109 177,302 N/A 1,186,922 ,387,107 2,574,029 86%
A.E. Nineties-1993 3,753,937 92.5%39.6% 1,378,377 140,580 N/A N/A 1,518,957 ,450,142 2,969,099 79%
A.E. Partners 1993 700,000 100% 39.6% 273,216 46,004 N/A N/A 319,220 465,738 784,958 112%
A.E. Nineties-P#2 3,323,920 78.7%39.6% 1,036,343 95,886 178,420 N/A 1,310,649 1,083,221 2,393,870 72%
A.E. Nineties-14 9,940,045 95% 39.6% 3,739,445 250,589 N/A N/A 3,990,034 2,605,629 6,595,663 66%
A.E. Partners 1994 892,500 100% 39.6% 353,430 28,433 N/A N/A 381,863 347,929 729,792 82%
A.E. Nineties-P#3 5,799,750 76.2%39.6% 1,752,761 146,427 255,021 N/A 2,154,209 1,600,227 3,754,436 65%
A.E. Nineties-15 10,954,71590% 39.6% 3,904,261 228,401 N/A N/A 4,132,662 2,460,670 6,593,332 60%
A.E. Partners 1995 600,000 100% 39.6% 237,600 7,199 N/A N/A 244,799 149,330 394,129 66%
A.E. Nineties-P#4 6,991,350 80% 39.6% 2,214,860 111,407 127,016 N/A 2,453,283 1,009,362 3,462,645 50%
A.E. Nineties-16 10,955,46581.5%39.6% 3,361,289 47,379 162,100 N/A 3,570,768 758,339 4,329,107 40%
A.E. Partners 1996 800,000 100% 39.6% 316,800 876 N/A N/A 317,676 6,115 323,791 40%
A.E. Nineties-P#5 7,992,240 81.7%39.6% 2,530,954 5,702 50,000 N/A 2,586,656 88,678 2,675,334 33%
A.E. Nineties-17 (6) 4,628,750 84.8%39.6% 1,555,092 0 N/A N/A 1,555,092 0 1,555,092 34%
(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) It is anticipated that approximately 80% of an Investor General Partner's subscription to
the Partnership will be deductible in 1997.
(3) The I.D.C. Deductions, Depletion Allowance and MCRS 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. See footnotes 1 and 3 of Table 3.
(6) This program had its first closing on June 25, 1997.
</TABLE>
- ------------------------------------------------------------------------------
<PAGE>39
<TABLE>
Table 5 sets forth programs in which Atlas and Atlas Energy served as operator and/or drilling
contractor for third party general partners as well as the partnerships where Atlas served as managing general
partner. The table includes Atlas' share of costs and revenues set forth in Table 3A, above. Atlas has drilled
approximately 1,600 wells over the 25 year period from 1972 to 1996 and during this time it has
completed 97% of the wells. In the current primary area of interest in Mercer County Atlas has completed 98% of
more than approximately 780 wells drilled. These results are summarized below.
ATLAS RESOURCES, INC. AND ITS AFFILIATES' HISTORICAL PRODUCTION RECORD
As of July 15, 1997 (4)
Last 3 Mo.
Year Wells Total Total Amount Total Distribution
Were Placed Total MCF's Invested In Amount Cum % Return Ending As of
Into Production Wells-1 Produced Wells-2 Returned-2 Cash on Cash Date of table
<C> <C> <C> <C> <C> <C> <C>
1973 6 2,441,694 576,000 3,907,035 678% 37,326
1974 18 2,848,015 2,387,200 3,805,024 159% 25,403
1975 21 4,075,086 2,814,200 6,482,504 230% 48,128
1976 14 2,828,717 1,819,200 4,302,987 237% 18,533
1977 26 8,983,554 3,912,600 15,879,600 406% 131,170
1978 78 7,660,988 12,399,900 18,690,770 151% 130,336
1979 46 8,917,660 7,404,000 19,253,887 260% 139,172
1980 41 5,559,636 6,561,100 13,325,338 203% 96,972
1981 77 6,139,674 15,382,850 16,729,747 109% 128,745
1982 63 2,395,909 12,438,500 5,667,380 46% 39,783
1983 22 1,222,687 6,725,480 2,899,136 43% 39,191
1984 47 4,436,586 10,663,250 9,892,277 93% 130,279
1985 39 4,658,218 8,971,200 9,866,478 110% 132,865
1986 45 5,249,261 9,649,100 10,178,561 105% 176,572
1987 12 1,472,294 2,425,800 2,608,755 108% 31,266
1988 37 3,560,747 7,688,386 5,918,573 77% 197,622
1989 48 3,584,254 9,967,768 6,485,873 65% 152,001
1990 46 4,593,458 9,038,238 8,463,126 94% 261,430
1991 99 7,285,288 16,034,382 13,491,108 84% 725,545
1992 64 6,736,695 14,250,032 12,132,989 85% 817,353
1993 107 8,779,450 21,958,681 14,574,633 66% 1,206,148
1994 94 4,993,425 20,418,366 8,124,620 40% 1,081,664
1995 105 4,506,764 22,350,889 7,677,238 34% 1,767,313
1996 114 2,429,705 25,396,708 4,302,161 17% 2,237,994
1997 50 160,643 10,977,861 285,186 3% 285,186
TOTAL 1,319 115,520,408 262,211,691 224,944,986 86% 10,037,997
(1) The above numbers do not include information for: (a) 87 wells drilled for General Motors
from 1971 to 1973 which were subsequently purchased by General Motors; (b) 25 wells successfully drilled in
1981 and 1982 for an industrial customer which requested that the wells be capped and not placed into
production; (c) 127 wells drilled from 1980 to 1985 which were sold in 1993 and are no longer
operated by Atlas; and (d) wells which were drilled recently but are not yet in production.
(2) The column "Total Amount Invested in Wells" only includes funds paid to Atlas or Atlas Energy
as operator and/or drilling contractor for drilling and completing the designated wells. This column
does not include all of the costs paid by investors to the third party managing general partner and/or
sponsor of the program because such information is generally not available to Atlas or Atlas Energy.
Similarly, the column "Total Amount Returned" only includes amounts paid by Atlas or Atlas Energy as operator of
the wells to the third party managing general partner and/or sponsor of the program. This column does not
set forth the revenues which were actually received by the investors from the third party managing
general partner and/or sponsor because such information is generally not available to Atlas or Atlas Energy.
Notwithstanding, the columns "Total Amount Invested in Wells" and "Total Amount Returned" also include
the partnerships where Atlas serves as managing general partner and are presented on the same basis
as the third party partnerships.
(3) This column reflects total cash distributions beginning with the first production from the
well, as a percentage of the total amount invested in the well, and includes the return of the investors'
capital.
(4) THE RESULTS OF TABLE 5 SHOULD BE VIEWED ONLY AS A MEASURE OF THE LEVEL OF ACTIVITY AND
EXPERIENCE OF ATLAS WITH RESPECT TO DRILLING PROGRAMS.
</TABLE>
- -------------------------------------------------------------------------
<PAGE>40
- -MANAGEMENT MANAGING GENERAL PARTNER AND OPERATOR
Atlas, a Pennsylvania corporation, was incorporated in 1979 and Atlas
Energy, an Ohio corporation, was incorporated in 1973. As of December
31, 1996, Atlas and Atlas Energy operated approximately 1,172 oil or
natural gas wells located in Ohio and Pennsylvania. Atlas and Atlas
Energy have acted as operator with respect to the drilling of a total
of approximately 1,611 gas wells, approximately 1,562 of which were
capable of production in commercial quantities. Atlas' primary offices
are located at 311 Rouser Road, Moon Township, Pennsylvania 15108, near
the Pittsburgh International Airport.
Atlas has previously sponsored five public and twenty-one private
Development Drilling programs formed since 1985 to conduct natural gas
drilling and development activities in Pennsylvania and Ohio. In
addition, as operator, Atlas acted as general contractor with respect
to the drilling and completion of such partnerships' natural gas wells
located in Pennsylvania and is responsible for operating such wells.
Atlas Energy acted in the same capacity as operator of such
partnerships' wells located in Ohio. (See "Prior Activities".)
Atlas and its Affiliates employ a total of approximately ninety-nine
persons, consisting of three geologists (one of whom is an exploration
geologist), five landmen, five engineers, thirty-three operations
staff, eight accounting, one legal, eight gas marketing, and eighteen
administrative personnel. The balance of the personnel are engineering,
pipeline and field supervisors.
Atlas and Atlas Energy are wholly owned subsidiaries of AIC, Inc., a
corporation formed in July, 1995, which is a wholly owned subsidiary of
The Atlas Group, Inc. ("Atlas Group") that was formerly known as AEG
Holdings, Inc. ("AEGH"), a corporation which was also formed in July,
1995. The other subsidiaries of AIC, Inc. are: (i) Atlas Gas
Marketing, Inc., a gas marketing company; (ii) Mercer Gas Gathering,
Inc., a gas gathering company which gathers gas from Atlas' wells in
Mercer County, Pennsylvania, and delivers such gas directly to
industrial end-users or to interstate pipelines and local distribution
companies; (iii) Pennsylvania Industrial Energy, Inc., which sells
natural gas to industrial end-users in Pennsylvania; (iv) Transatco,
Inc., which owns a 50% interest in Topico which operates a pipeline in
Ohio; (v) Atlas Energy Corporation, which serves as managing general
partner of exploratory programs and driller and operator; and (vi)
Anthem Securities, Inc. which is a registered broker-dealer and member
firm of the NASD. Anthem Securities, Inc., which became an NASD member
firm in April, 1997, is the Dealer-Manager of the offering in all
states other than Minnesota and New Hampshire. Anthem Securities was
formed for the purpose of serving as Dealer-Manager of Atlas sponsored
Programs. In addition, Atlas is the sole owner of ARD Investments,
Inc., a corporation formed in July, 1995, and Atlas Energy is the sole
owner of AED Investments, Inc., a corporation formed in July, 1995.
Prior to July, 1995, all of the Atlas companies were wholly owned by
Atlas Energy. The purpose of forming Atlas Group, AIC, Inc., ARD
Investments, Inc. and AED Investments, Inc. was to achieve more
efficient concentration of funds of the Atlas group of companies,
thereby minimizing transaction costs and maximizing returns on
investment vehicles.
Atlas and its Affiliates have constructed for their use over 600 miles
of gas transmission lines and produce in excess of nine billion cubic
feet of natural gas annually from wells they operate, which they market
directly to end users or to interstate pipelines and local distribution
companies, and also purchase an additional eight billion cubic feet of
natural gas annually from third party producers locally and in the
south/southwest United States and resell the production to more than
100 customers.
<TABLE>
<CAPTION>
Organizational Diagram
AEG HOLDINGS,INC.
:
AIC, INC
:
.........................................................................................- - - -
: : : : : : : :
ATLAS MERCER GAS PENNSYLVANIA ATLAS ENERGY TRANSATCO ATLAS GAS ANTHEM ATLAS ENERGY
RESOURCES GATHERING INDUSTRIAL CORPORATION INC.,WHICH MARKETING SECURITIES GROUP, INC.
GENERAL GATHERING ("PIE") OPERATOR IN TOPICO (MARKETS OPERATOR IN
PARTNER, COMPANY) (SELLS GAS TO WV AND (OPERATES NATURAL OHIO
DRILLER PENNSYLVANIA MANAGING PIPELINE GAS) :
AND OPERATOR) INDUSTRY) GENERAL IN OHIO :
: :
: :
ARD AED
INVESTMENTS, INC. INVESTMENTS, INC.
<C> <C> <C> <C> <C> <C> <C>
1 2 3 4 5 6 6
</TABLE>
The audited financial statements of Atlas and AEGH, now known as Atlas
Group, as of July 31, 1996 and 1995, are included in "Financial
Information Concerning the Managing General Partner, Atlas Group and the
Partnership".
- -------------------------------------------------------------------------------
<PAGE>41
OFFICERS, DIRECTORS AND KEY PERSONNEL
The directors of Atlas serve until Atlas' next annual meeting of
stockholders in October, 1997, or until their successors are elected.
All officers serve until the regular meeting of directors immediately
following the annual meeting of stockholders and until their successors
are elected.
The officers, directors and key personnel of Atlas, who are also
officers, directors and key personnel of Atlas Group and Atlas Energy,
are as follows:
Charles T. Koval 63 Chairman of the Board and a Director
James R. O'Mara 53 President, Chief Executive Officer and a
Director
Bruce M. Wolf 48 General Counsel, Secretary and a Director
James J. Kritzo 62 Vice President of the Land Department
Donald P. Wagner 55 Vice President of Operations
Frank P. Carolas 37 Vice President of Geology
Tony C. Banks 42 Vice President of Finance and Chief
Financial
Officer
Barbara J. Krasnicki 52 Vice President of Administration
Jacqueline B. Poloka 46 Controller
John A. Ranieri 37 Director of Gas Marketing
Eric D. Koval 32 President of Anthem Securities, Inc.
Joseph R. Sadowski 66 Director
CHARLES T. KOVAL. Chairman of the Board and a director. From 1955 to
1963, Mr. Koval served as a pilot in the U.S. Marine Corps and the
Pennsylvania National Guard, attaining the rank of captain. He
co-founded Atlas Energy. Prior to the formation of Atlas Energy, he was
involved in the securities business initially with a national firm,
Federated Investors, and then with his own firm, Allegheny Planned
Income, both headquartered in Pittsburgh, Pennsylvania. Mr. Koval is
serving and has served as a director of Imperial Harbors since 1980.
Mr. Koval received a Bachelor of Science Degree from Pennsylvania State
University in 1955.
JAMES R. O'MARA. President, chief executive officer and a director.
Mr. O'Mara served with the United States Army Security Agency (ASA) and
is a Vietnam veteran. Mr. O'Mara is a Certified Public Accountant and
had been associated with Coopers and Lybrand, a national accounting
firm, and Teledyne, Inc., a large conglomerate, before joining Atlas
Energy in 1975. He is a member of the Pennsylvania Institute of
Certified Public Accountants and the President of Mercer Gas Gathering,
Inc. Mr. O'Mara received a Bachelor of Science Degree in Accounting
from Gannon University in 1968.
BRUCE M. WOLF. General Counsel, Secretary and a director. Mr. Wolf
received a Bachelor of Arts Degree from Washington and Jefferson
College in 1970 and his law degree in 1975 from the University of
Pittsburgh. From 1975 until his association with Atlas Energy in
January, 1980, he was a member of the staff of Price Waterhouse and
Company, a national accounting firm. Mr. Wolf is a member of the Bars
of Pennsylvania, the U.S. Tax Court, the Allegheny County Bar
Association and its respective Taxation and Natural Resources Sections.
He is also a member of the Board of Trustees and currently President of
the Independent Oil and Gas Association of Pennsylvania, a trade
association representing Pennsylvania natural gas producers. Mr. Wolf
is the President of Atlas Gas Marketing, Inc., AIC, Inc., ARD
Investments, Inc. and AED Investments, Inc.
JAMES J. KRITZO. Vice President of the Land Department. Mr. Kritzo
attended Indiana University of Pennsylvania. From 1956 to 1963 he was
employed by R.J. Reynolds Company in Sales and Marketing. In 1964 he
joined the Sherwin Williams Company as a Regional Sales Representative,
later being appointed Operations Manager of the Pittsburgh District
Service Center. In 1979 he joined the Land Department of Atlas Energy.
Mr. Kritzo is a member of the Association of Petroleum Landmen and the
Benedum Chapter of the A.A.P.L.
DONALD P. WAGNER. Vice President of Operations. Mr. Wagner, who has
over 32 years experience in all phases of gas and oil field operations,
was President of Energy Well Services, Inc., from 1971 through 1979
when he joined Atlas Energy. Mr. Wagner is a member of the Society of
Petroleum Engineers as well as a member of the Pennsylvania Oil and Gas
Association.
FRANK P. CAROLAS. Vice President of Geology. Mr. Carolas is a
certified petroleum geologist and has been with Atlas Energy 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.
TONY C. BANKS. Vice President and Chief Financial Officer. Mr. Banks
has over twenty years of finance, accounting and administrative
experience in the oil and gas industry, all with various subsidiaries
of Consolidated Natural Gas Company.
- ------------------------------------------------------------------------------
<PAGE>42
He started as an accounting clerk
with CNG's parent company in 1974 and progressed through various
positions with CNG's Appalachian producer, northeast gas marketer and
southwest producer to his last position as Treasurer of CNG's national
energy marketing subsidiary. Mr. Banks served on CNG's corporate-wide
Financial Accounting and Planning, Energy Price Risk and Information
Services Steering committees and has chaired the Financial Advisory and
Accounting Research committees. In 1989, Mr. Banks was a seminar
instructor for the University of Tulsa, and over the years has given
presentations to industry groups on topics including energy
derivatives, accounting for Appalachian gas imbalances and post
regulation credit review and evaluation. He received a Bachelor of
Science Degree in Accounting/Computers from Point Park College in
Pittsburgh and passed the Pennsylvania Certified Public Accountant
examination in 1988. Mr. Banks joined Atlas Group in 1995 and is Vice
President of AIC,Inc, ARD Investments, Inc. and AED Investments, Inc.
BARBARA J. KRASNICKI. Vice President of Administration. Ms. Krasnicki
has been with Atlas Energy since its inception in 1971. She was the
Office and Personnel Manager for Atlas Energy during that time. She
served as Office Manager of Allegheny Planned Income from 1965 to 1971.
Ms. Krasnicki has an Associate in Science Degree from Point Park
College, Pittsburgh, Pennsylvania.
JACQUELINE B. POLOKA. Controller. Ms. Poloka began her career with
Atlas Energy in 1980 as Administrative Assistant. She was promoted to
Production Accounting Manager in 1987 and subsequently to Controller in
1994. Ms. Poloka graduated from Carlow College,Pittsburgh,
Pennsylvania with a Bachelor of Science Degree in Accounting. Ms.
Poloka is a member of the American Society of Women Accountants,
Independent Oil and Gas Associations Tax Committee, Delta Epsilon Sigma
Honor Society and Strathmore's Who's Who.
JOHN A. RANIERI. Director of Gas Marketing for Atlas Gas Marketing,
Inc. Mr. Ranieri graduated from Northwestern University in 1981 with a
Bachelor of Science Degree in Chemical Engineering. He joined the
Columbia Gas Distribution Companies as a marketing engineer; first in
Charleston, West Virginia, and later in Mansfield, Ohio. In 1984, he
was promoted to Gas Procurement Manager of Columbia Gas of Pennsylvania
with responsibility for all Appalachian purchases. In 1988 he helped
start a new marketing affiliate for the parent company and remained
with that organization until joining Atlas in July, 1990.
ERIC D. KOVAL. President of Anthem Securities, Inc. Mr. Koval
graduated from Pennsylvania State University with a degree in Petroleum
and Natural Gas Engineering in 1987. While attending Penn State, he
was employed by Mobil Oil Company in Oklahoma, and Union Oil of
California (UNOCAL), offshore Santa Barbara, California. His
experience also includes working five years for Marathon Oil Company
(USX-Marathon) in various production and reservoir engineering
assignments in four different basins throughout the United States. He
has graduate credits from Ball State University, Indiana, and Bowling
Green State University, Ohio, in their Masters of Business Degree
programs. Mr. Koval joined Atlas in 1993 as a production engineer
specializing in acquisitions and dispositions. He subsequently moved
into the Investor Relations Department in 1994. Mr. Koval is a
registered Broker/Dealer Principal, member of the Society of Petroleum
Engineers, and lifetime member of Penn State Alumni Association. Mr.
Koval is the son of Charles Koval.
JOSEPH R. SADOWSKI. A director. He co-founded Atlas Energy and served
as an executive officer until he resigned as such in 1996. Mr. Sadowski
has been involved in the securities business with Revere Management and
Oppenheimer Management Company. From 1966 until 1971, he managed his
own brokerage firm, Whitman Securities in Cherry Hill, New Jersey. Mr.
Sadowski has served as a director of Dixon Ticonderoga since 1987 and
is a past director of Northeast Ohio Operating Companies, Inc.,
Canonsburg Hospital Foundation and the Verland Foundation. Mr. Sadowski
received a Bachelor of Arts Degree in Industrial Management from
LaSalle College in 1954 and attended Temple University from September,
1957 to June, 1958.
The officers and directors of AIC, Inc., which owns 100% of the common
stock of Atlas, are as follows: Bruce M. Wolf, President and a
director, Tony C. Banks, Vice President, Secretary and a director, and
Norman J. Shuman, Vice President, Treasurer and a director. The
biographies of Messrs. Wolf and Banks are set forth above.
REMUNERATION
No officer or director of the Managing General Partner will receive any
direct remuneration or other compensation from the Partnership. Such
persons will receive compensation solely from Atlas and its Affiliated
companies.
The aggregate remuneration paid during the fiscal year ended July 31,
1996, to the five most highly compensated persons who are executive
officers of Atlas and whose aggregate remuneration exceeded $100,000
and to all executive officers of Atlas as a group, for services in all
capacities while acting as executive officers of Atlas and its
Affiliates, was as follows
- -----------------------------------------------------------------------------
<PAGE>43
<TABLE>
(A) (B) (C) (D) (E)
NAME OF CAPACITIES IN CASH COMPENSATION COMPENSTION AGGREGATE OF
INDIVIDUAL OR WHICH SERVED (4) PURSUANT TO CONTINGIGENT
NUMBER OF PLANS (2) FORMS OF
PERSONS IN REMUNERATION
GROUP (3)
- ---------------------------------------------------------------------------------------
<S> <C> <S> <C> <C> <C> <S>
James R. O'Mara President, $305,300 $12,066 -
Chief Executive
Officer and a Director
Charles T. Koval Chairman of $296,500 $5,281 -
the Board and
a Director
Bruce M. Wolf General $217,150 $11,735 -
Counsel,
Secretary and
a Director
Donald P. Wagner Vice President $125,604 $5,281 -
of Operations
Tony C. Banks Vice President $124,000 $3,926 -
and Chief
Financial
Officer
Executive Officers as a $1,383,530 $70,703 -
Group (8 persons)
</TABLE>
(1) The amounts indicated were composed of salaries and all cash
bonuses for services rendered to Atlas and its Affiliates during
the last fiscal year, including compensation that would have been
paid in cash but for the fact the payment of such compensation was
deferred. (See "- Security Ownership of Certain Beneficial Owners
and Managers - Agreements Affecting Ownership of Atlas Group
Stock," below.)
(2) Atlas and its Affiliates have a retirement plan described under
"-Security Ownership of Certain Beneficial Owners and Managers -
ESOP," below, and a 401(K) plan which allowed employees to
contribute the lesser of 15% of their compensation or $9,500 for
the calendar year 1996 or $9,240 for the calendar year 1995. Atlas
Energy contributed an amount equal to 50% and 30% of each
employee's contribution for the calendar years July 31, 1996 and
1995, respectively.
(3) There were no stock options granted or exercised during the
fiscal year ended July 31, 1996, to the above individuals. (See
"- Security Ownership of Certain Beneficial Owners and Managers -
Agreements Affecting Ownership of Atlas Group Stock," below.)
(4) During the fiscal year ended July 31, 1996, each director was
paid a director's fee of $12,000 for the year. There are no other
arrangements for remuneration of directors.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGERS
Atlas Group owns 100% of the common stock of AIC, Inc., which owns 100%
of the common stock of Atlas. The following table sets forth, as of
July 31, 1996, information as to the beneficial ownership of common
stock of Atlas Group by each person known to Atlas Group to own
beneficially 5% or more of the outstanding common stock of Atlas Group,
by directors and nominees, naming them individually, and by all
directors and officers of Atlas Group as a group:
SHARES OF
COMMON PERCENT OF
CLASS
Charles T. Koval 109,391 26.445%
Joseph R. Sadowski 109,142 26.384%
James R. O'Mara 95,164 (1) 23.005%
Bruce M. Wolf 44,710 (2) 10.808%
Directors and Officers as a Group (9 persons) 377,654 (1)(2) 91.344%
(1) Includes 22,164 shares of Atlas Group issuable upon the grant
and exercise of stock options held by Mr. O'Mara.
(2) Includes 14,210 shares of Atlas Group issuable upon the grant
and exercise of stock options held by Mr. Wolf.
ESOP. Atlas Group has adopted Atlas Energy's existing Employee Stock
Ownership Plan ("ESOP") for the benefit of its employees, other than
Messrs. Koval and Sadowski, to which it will contribute annually
approximately 6% of annual compensation in the form of shares of Atlas
Group. Atlas Group anticipates that it will contribute approximately
3,000 shares of its stock in the ESOP each year.
- -----------------------------------------------------------------------------
<PAGE>44
AGREEMENTS AFFECTING OWNERSHIP OF ATLAS GROUP STOCK. Pursuant to
agreements between Atlas Group and its shareholders to accommodate the
desire of Messrs. Sadowski and Koval to gradually liquidate a majority
of their stock ownership in Atlas Group in preparation for their
retirement from Atlas Group, it is anticipated that by the year 2003
the stock ownership of Atlas Group by Messrs. Koval and Sadowski will
be reduced through a series of stock redemptions to approximately 15%
each. The stock ownership of certain of the remaining officers will be
increased to approximately 60%, in the aggregate, and the stock
ownership of the ESOP will be approximately 10%.
The stock redemptions require Atlas Group to execute promissory notes,
from time to time, in favor of Messrs. Koval and Sadowski, the first of
which, in the original principal amount of $4,974,340 each, plus
interest at 13.5%, were executed by Atlas Energy and were assumed by
Atlas Group and are reflected in the audited balance sheet of Atlas
Group and its subsidiaries dated July 31, 1995. These promissory notes
are totally subordinated to Atlas Group's obligations to banks, the
ESOP and any and all other debts or obligations of Atlas Group,
including its indemnification obligations and Atlas' drilling
obligation to the Partnership. If Atlas Group defaults on a promissory
note, Messrs. Koval and Sadowski are entitled to purchase up to
approximately an additional 1,500,000 shares of Atlas Group to regain
management control. (See "Financial Information Concerning the
Managing General Partner, Atlas Group and the Partnership".)
Atlas views the transactions discussed above as a natural transition
which will have no adverse effect on the operations or activities of
Atlas or the Partnership. In 1990, Messrs. Koval and Sadowski entered
into five year employment agreements with Atlas Energy, which
agreements have been transferred to Atlas Group, renewable for an
additional five year term and on an annual basis after the first 10
years. In this regard, Mr. Sadowski retired other than as a director
in 1996. The terms and provisions of the employment agreements with
Mr. Koval are subject to negotiation at the time of each renewal, and
currently do not provide for any severance payments. Also, during the
terms of the promissory notes Messrs. Koval and Sadowski have the
right to serve as directors of Atlas Group and as one of the two
trustees of the ESOP.
On November 8, 1990, Atlas Energy entered into a Stock Option Agreement
which established a management employee stock option plan to provide
incentive compensation for certain of its key employees to acquire up to
47,578 shares of common stock of Atlas Energy. Pursuant to the plan,
Messrs. O'Mara and Wolf were granted stock options for 22,164 and 14,210
shares, respectively. The options are 100% vested with an option price
of $1.00 per share and may be exercised when the promissory notes to
Messrs. Koval and Sadowski have been satisfied and will terminate on
August 15, 2012. The issuance of future options will be determined at a
later date. On November 14, 1990, Atlas Energy granted 92,098 shares of
restricted common stock to certain management investors of the company,
which was valued at the time by Atlas Energy at $2,695,708. The
restrictions lapsed with respect to 25% of the shares on November 14,
1990, 1991, 1992 and 1993. (See "Financial Information Concerning the
Managing General Partner, Atlas Group and the Partnership".) The Stock
Option Agreement and the outstanding stock options have been converted
from Atlas Energy to Atlas Group. The shareholders are also subject to
a Shareholders Agreement which provides, among other things, that such
shareholders may not transfer their shares in Atlas Group unless the
shares have first been offered to Atlas Group and the other
shareholders.
Atlas Group and its Affiliates have in the past, are presently, and will
in the future explore ways to enhance shareholder value. This could
include acquisitions, dispositions, mergers or the sale of the equity of
The Atlas Group or any of its Affiliates during the term of the
Partnership. Also, Atlas Group and its Affiliates may be participants
in unrelated business ventures for their own account or for the account
of others.
TRANSACTIONS WITH MANAGEMENT AND AFFILIATES
Atlas, its officers, directors and Affiliates have in the past invested,
and may in the future invest, as participants in Programs sponsored by
Atlas on the same terms as unrelated investors. The Managing General
Partner, its officers and directors and Affiliates may also subscribe
for Units in the Partnership on the same basis as Limited Partners or
Investor General Partners, except that they are not required to pay the
Dealer-Manager fees, Sales Commissions or due diligence reimbursements.
Also, the Managing General Partner and its Affiliates may buy up to 10%
of the Units, which will not be applied towards the minimum Partnership
Subscription required for the Partnership to begin operations, although
the Managing General Partner currently does not anticipate that it and
its Affiliates will purchase any Units. Subject to the foregoing, any
subscription by the Managing General Partner or its officers, directors
or Affiliates will dilute the voting rights of the Participants.
However, the Managing General Partner and its officers, directors and
Affiliates are prohibited from voting with respect to certain matters.
(See "Summary of Partnership Agreement - Voting Rights.")
Atlas, its officers, directors and Affiliates have also participated in
the past, and may in the future participate, as Working Interest owners
in wells in which Atlas or its Programs have an interest. Frequently,
such participation has been on more favorable terms than the terms which
were available to unrelated investors and Atlas Group has loaned to its
officers and directors amounts in excess of $60,000 from time to time as
necessary for participation in such wells or Programs. Prior to 1996
such loans either were non-interest bearing or accrued interest at
variable rates, but since 1995 all new loans for such purposes are
required to bear interest. Currently, no such loans are outstanding.
See "Conflicts of Interest - Certain Transactions" for further
- -------------------------------------------------------------------------
<PAGE>45
information concerning prior activities between Atlas and its Affiliates
and the partnerships where Atlas serves as Managing General Partner.
INVESTMENT OBJECTIVES
Except for the historical information contained herein, the matters
discussed below are forward looking statements that involve risks and
uncertainties, including the risk that the Wells are productive but do
not produce enough revenue to return the investment made, Dry Holes,
uncertainties concerning the price of gas, and the other risks detailed
below. The actual results that the Partnership achieves may differ
materially from the objectives set forth below due to such risks and
uncertainties. The Partnership's principal investment objectives are to
invest the Partnership Subscription in natural gas Development Wells
which will:
(1) Provide quarterly cash distributions until the wells are
depleted, (historically 20+ years) with a preferred annual cash flow
of 10% during the first five years based on the original
subscription amount. (See "Risk Factors - Special Risks of the
Partnership - Risk of Unproductive Wells in Development Drilling,"
"Prior Activities" and "Participation in Costs and Revenues -
Subordination of Portion of Managing General Partner's Net Revenue
Share".)
(2) Obtain tax deductions in 1997 from intangible drilling and
development costs to offset a portion of the Participants' taxable
income (subject to the passive activity rules in the case of Limited
Partners). One Unit will produce a 1997 tax deduction of $8,000
against ordinary income for Investor General Partners and against
passive income for Limited Partners. For an investor in either the
39.6% or 36% tax bracket, one Unit will save $3,168 or $2,880
respectively in federal taxes this year. Most states also allow
this type of a deduction against the state income tax.
(3) Offset a portion of any taxable income generated by the
Partnership with tax deductions from percentage depletion, presently
16% (estimated to be 18% on net revenue). Atlas estimates that this
feature should reduce an investor's effective tax rate from 39.6% to
33.3% (i.e., 84% of 39.6%) on Partnership net revenues.
(4) Obtain tax deductions of the remaining 20% of the initial
investment from 1998 through 2005. The investor will receive an
additional $2,000 tax deduction per Unit generated through the
remaining depreciation over a seven-year cost recovery period of the
Partnership's equipment costs for the wells.
ATTAINMENT OF THE PARTNERSHIP'S INVESTMENT OBJECTIVES WILL DEPEND ON
MANY FACTORS, INCLUDING THE ABILITY OF THE MANAGING GENERAL PARTNER TO
SELECT SUITABLE PROSPECTS WHICH WILL BE PRODUCTIVE AND PRODUCE ENOUGH
REVENUE TO RETURN THE INVESTMENT MADE. THE SUCCESS OF THE PARTNERSHIP
DEPENDS LARGELY ON FUTURE ECONOMIC CONDITIONS, ESPECIALLY THE FUTURE
PRICE OF NATURAL GAS WHICH IS VOLATILE AND MAY DECREASE.
THERE CAN BE NO GUARANTEE THAT THE FOREGOING OBJECTIVES WILL BE
ATTAINED.
PROPOSED ACTIVITIES
IN GENERAL
The Partnership will be funded to drill wells which are located
primarily in the Mercer County area of Pennsylvania, although the
Managing General Partner has reserved the right to use up to 15% of the
Partnership Subscription to drill Development Wells on Prospects in
other areas of the United States. Atlas anticipates that all of the
Partnership's wells will be classified as gas wells which may produce a
small amount of oil. (See "- Information Regarding Currently Proposed
Prospects" and "Prior Activities".)
The wells drilled by the Partnership will be Development Wells which
will primarily test the Clinton/Medina geological formation in
Pennsylvania and Ohio. It is anticipated that the Clinton/Medina
formation to be tested by the Partnership will normally be found between
5,900 to 6,800 feet in depth. The number of Prospects in which the
Partnership will acquire interests and on which the Partnership will
drill wells will depend on the amount of the Partnership Subscription
received and the Partnership's aggregate percentage of the Working
Interest in the wells. Assuming the Partnership acquires 100% of the
Working Interest in the Prospects and all of the Prospects are situated
in the Mercer County area, the Participants would participate in
developing approximately 4 to 5 Prospects if the minimum Partnership
Subscription of $1,000,000 is received, 35 to 36 Prospects if the
maximum Partnership Subscription of $8,000,000 is received, and 44 to 45
Prospects if the Managing General Partner increases the size of the
offering to $10,000,000. The actual amount of the Working Interest in
each Prospect acquired by the Partnership and the number of Prospects
developed by the Partnership may vary from these estimates.
The Managing General Partner may not, without the vote of a majority in
interest of Participants, change the investment and business purpose of
the Partnership or cause the Partnership to engage in activities outside
the stated business purposes of the Partnership through joint ventures
with other entities.
- ------------------------------------------------------------------------
<PAGE>46
INTENDED AREAS OF OPERATIONS
Prospects located in Pennsylvania and drilled to the Clinton/Medina
geological formation will consist of approximately 50 acres, subject to
adjustment to take into account Lease boundaries. Wells in Pennsylvania
will not be drilled closer than approximately 1,650 feet to each other,
which is greater than the minimum area permitted by state law (660 feet)
or local practice to protect against drainage from adjacent wells.
Prospects located in Ohio and drilled to the Clinton/Medina geological
formation will consist of approximately 40 acres subject to adjustment
to take in to account Lease boundaries, and will not be drilled closer
than approximately 1,100 feet to each other. In addition, the
assignments will be limited to a depth of from the surface to the top of
the Queenston formation, and Atlas will retain the drilling rights below
the Clinton/Medina geological feature. The Partnership will not acquire
the deep drilling rights because it is a Development Drilling program
which will not allocate any money to seismic or to drilling Exploratory
Wells which would be the case with Horizons deeper than the
Clinton/Medina. Notwithstanding, in the future seismic could be run on
the Horizons below the Clinton/Medina geological feature which might
provide a basis for Atlas drilling an Exploratory Well. The Partnership
would not share in the profits, if any, from these activities. (See "-
Acquisition of Leases" and "- Information Regarding Currently Proposed
Prospects", below.)
The wells in Pennsylvania and Ohio will test the Clinton/Medina
geological formation, a blanket sandstone found throughout most of the
northwestern edge of the Appalachian Basin. The Clinton/Medina is
described in petroleum industry terms as a "tight" sandstone with
porosity ranging from 6% to 12% and with very low permeability. Porosity
is the percentage of void space between sand grains that is available
for occupancy by either liquids or gases. Permeability is the property
of porous rock that allows fluids or gas to flow through it. Geological
features such as structure and faulting are not generally factors in
finding productive Clinton/Medina deposits, instead, sand quality in
terms of net pay zone thickness and porosity and the effectiveness of
fracture stimulation appear to be the governing factors in generating
commercial production. A well drilled in the Clinton/Medina usually
requires hydraulic Fracturing of the formation to stimulate productive
capacity. Based on the results of Atlas' previous programs, it is
anticipated that all of the Partnership's Wells will be completed and
Fraced in two different zones of the Clinton/Medina geological feature.
Generally, gas from Clinton/Medina wells is produced at rates which
decline rapidly during the first few years of operation. Although
Clinton/Medina wells can produce for many years, a proportionately
larger amount of the production can be expected within the first several
years. See "- Information Regarding Currently Proposed Prospects" and
the model decline curve included in the geological report prepared by
United Energy Development Consultants, Inc. ("UEDC"), an independent
geological and engineering firm, ("UEDC Geological Report").
The Managing General Partner also has reserved the right to use up to
15% of the Partnership Subscription to drill Development Wells in other
areas of the United States.
ACQUISITION OF LEASES
Atlas will have the right, in its sole discretion, to select the
Prospects which the Partnership will participate in developing. The
currently proposed Prospects are set forth in "- Information Regarding
Currently Proposed Prospects", and represent the necessary Prospects if
80% of the potential maximum Partnership Subscription of $10,000,000 is
raised and the Partnership takes 100% of the Working Interest. It is
anticipated that the Prospects will be transferred to the Partnership,
but not immediately recorded, beginning upon or after the Initial
Closing Date subject to Atlas' right of substitution of such Prospects
depending upon, among other things, the amount of the Partnership
Subscription, the latest geological data available, potential title
problems, approvals by federal and state departments or agencies,
agreements with other Working Interest owners and continuing review of
other properties which may be available and if no other circumstances
occur which in Atlas' opinion diminish the relative attractiveness of
the Prospects. It is not anticipated that such Prospects will be
selected in the order in which they are set forth. Atlas has the right,
in its sole discretion, to substitute other Prospects not identified,
provided that such other Prospects meet the same general criteria for
development potential as the currently proposed Prospects. However, most
of the Partnership's Development Wells will have as their objective the
Clinton/Medina formation discussed in the UEDC Geological Report and
will be located in areas where Atlas or its Affiliates have previously
conducted drilling operations. Nevertheless, the Managing General
Partner has reserved the right to use up to 15% of the Partnership
Subscription to drill wells in other areas of the United States.
In the event any of the currently proposed Prospects are substituted,
the Partnership takes a lesser percentage of the Working Interest in the
Prospects, more than $8,000,000 is raised, or Prospects will be drilled
in areas of the United States other than the currently proposed
locations, the Prospects will be selected by Atlas primarily from Leases
included in the existing leasehold inventory of Atlas or its Affiliates
and to a lesser extent, from Leases hereafter acquired by Atlas or its
Affiliates or from Leases owned by independent third parties.
Consequently, for additional or substituted Leases prospective
subscribers will not have the opportunity to evaluate for themselves the
relevant geological, economic or other information regarding those
Prospects. Atlas has not authorized any party to make any
representations concerning the possible inclusion of any other Prospects
in the Partnership and no such information will be shown or provided to
any person for the purpose of deciding whether to invest in the
Partnership. Any representations to the contrary are erroneous and shall
be disregarded. Accordingly, prospective Participants should not base
any investment decision on any oral representation by any party or on
the existence of any such inventory.
- ---------------------------------------------------------------------------
<PAGE>47
As of the date of this Prospectus, Atlas and its Affiliates owned
approximately 80,500 net and gross acres of undeveloped leasehold
acreage in Pennsylvania, 18,000 net acres and 20,000 gross acres of
undeveloped lease acreage in western West Virginia and 14,300 net acres
and 16,100 gross acres of undeveloped lease acreage in eastern Kentucky.
Most, if not all, of the leases in eastern Kentucky and western West
Virginia are held by production. Atlas and its Affiliates are engaged
in a program to acquire additional leasehold acreage in Pennsylvania and
other areas of the United States. Atlas believes that it and its
Affiliates' leasehold inventory will be sufficient to provide all of the
Prospects to be developed by the Partnership.
Before selecting a Prospect for development by the Partnership, Atlas
will review all available geologic data including logs, completion
reports and plugging reports for wells located in the vicinity of the
proposed Prospect. Atlas has obtained the UEDC Geological Report with
respect to the development of the Clinton/Medina geological formation in
the primary area where the Partnership will conduct its activity. It
has been Atlas' experience that oil and gas production from wells
drilled to the Clinton/Medina geologic formation is reasonably
consistent within close proximity, although from time to time great
disparity in well performance can occur in wells located in close
proximity. (See "Conflicts of Interest - Conflicts Involving the
Acquisition of Leases".) Production information relating to the wells
which are in the general area of the proposed Prospects is set forth in
"- Information Regarding Currently Proposed Prospects". Atlas believes
that the production information is reliable, although as to certain of
the Prospects the production information is incomplete because there was
a third party operator and production information is not available.
Also, some of the wells have only been producing for a short period of
time or are not yet completed or on-line. In reviewing the production
information, prospective subscribers are cautioned to carefully read the
general comments set forth in "- Information Regarding Currently
Proposed Prospects" regarding the production information.
It is anticipated that the Leases comprising each Prospect will be
acquired from the Managing General Partner or its Affiliates and
credited to the Managing General Partner as a part of its required
Capital Contribution at its Cost unless the Managing General Partner has
reason to believe that Cost is materially more than the fair market
value of such property in which case the price will not exceed the fair
market value of such property. Production and revenues from a well
drilled on a Prospect will be net of the applicable Landowner's Royalty
Interest (typically 1/8th (12.5%) of gross production), and any other
applicable Overriding Royalty Interests, which, in the aggregate, are
not expected to exceed 1/32 of 8/8th (3.125%) in respect of any Prospect
in the Mercer County area. Neither Atlas nor its Affiliates will
receive any Royalty or Overriding Royalty Interest.
It is anticipated that the Partnership will have an 87.5% Net Revenue
Interest in each Lease in the Mercer County area as shown by the
summary
of the Royalty and Overriding Royalty Interests burdening each Lease
location for 32 of the currently proposed Prospects set forth in "-
Information Regarding Currently Proposed Prospects" and an 84.375% Net
Revenue Interest in the Leases covering three of the currently proposed
Prospects. (See "- Interests of Parties".) The Leases in areas of the
United States other than the Mercer County area may also be subject to
greater Overriding Royalty Interests, third party net profits interests,
carried interests, production payments, reversionary interests or other
retained or carried interests. With respect to certain conflicts of
interest between the Managing General Partner and the Partnership with
respect to the acquisition of Leases, see "Conflicts of Interest -
Conflicts Involving Acquisition of Leases".
Because Atlas will assign to the Partnership only such number of
Prospects as Atlas believes are necessary for the drilling operations of
the Partnership, the Partnership will not Farmout any undeveloped
Prospects.
TITLE TO PROPERTIES
Title to all Leases acquired by the Partnership will be held in the name
of the Partnership. However, it is possible that initially title to such
Leases will be held in the name of the Managing General Partner or its
Affiliates, or in the name of any nominee designated by the Managing
General Partner, in order to facilitate the acquisition of the Leases.
Title to the Leases will be transferred to the Partnership from time to
time after the Initial Closing Date, and filed for record following
drilling.
It is not the practice in the oil and gas industry to obtain title
insurance on leaseholds and the Managing General Partner will not obtain
title insurance with respect to the Working Interests in the Leases to
be assigned to the Partnership. Also, in the oil and gas industry
leasehold assignments generally do not contain a warranty as to the
title to the leasehold. However, a favorable formal title opinion with
respect to the Working Interest in each Lease composing the acreage on
which the well is situated will be obtained before each well is drilled.
Nevertheless, if the title to the Working Interest in a Lease is
defective, the Partnership will not have the right to recover against
the transferor (the Managing General Partner or its Affiliates) on a
title warranty theory and there is no assurance that the Partnership
will not experience losses from title defects excluded from or not
disclosed by the formal title opinion. The Managing General Partner will
take such steps as it deems necessary to assure that the Partnership has
acceptable title for its purposes, however, the Managing General Partner
is free to use its own judgment in waiving title requirements and will
not be liable for any failure of title of Leases transferred to the
Partnership.
FORMATION OF THE PARTNERSHIP AND POWERS OF THE MANAGING GENERAL PARTNER
Atlas will serve as the Managing General Partner of the Partnership and
the Operator of the wells in Pennsylvania, Atlas Energy will serve as
the Operator of any wells in Ohio, and Atlas or an Affiliate will serve
as Operator of any wells located in other areas of the United States.
Atlas' authority as Managing General Partner in conducting the affairs
of the Partnership is virtually unlimited.
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<PAGE>48
However, Participants are
expressly granted certain rights and certain express restrictions are
placed on the Managing General Partner by the Partnership Agreement. As
to the removal of the Managing General Partner and the Operator, and the
appointment of successors, see "Summary of Partnership Agreement" and
"Summary of Drilling and Operating Agreement".
DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS
Under the Drilling and Operating Agreements the responsibility for
drilling and completing (or plugging) Partnership wells will be on Atlas
on Prospects located in Pennsylvania, Atlas Energy on Prospects located
in Ohio and Atlas or an Affiliate on any Prospects located in other
areas of the United States. The Partnership will pay the drilling and
completion costs to Atlas, Atlas Energy or an Affiliate as incurred,
except that the Partnership is permitted to make advance payments to
Atlas, Atlas Energy or an Affiliate where necessary to secure tax
benefits of prepaid intangible drilling and development costs and there
is a valid business reason.
Wells will be drilled at competitive industry rates to a depth
sufficient to test thoroughly the objective geological formation. The
Partnership will bear its proportionate share of the cost of drilling
and completing or drilling and abandoning the Partnership's wells. In
the Appalachian Basin the Partnership will pay for each well completed
and placed into production an amount equal to the depth of the well in
feet at its deepest penetration as recorded by the drilling contractor
multiplied by $37.39 per foot or, for each well which the Partnership
elects not to complete, an amount equal to $20.60 per foot multiplied by
the depth of the well, as specified above. To the extent that the
Partnership acquires less than 100% of a Prospect, its drilling and
completion costs of that well will be proportionately decreased. In the
event the foregoing rates exceed competitive rates available from other
non-affiliated persons in the area engaged in the business of rendering
or providing comparable services or equipment, the foregoing rates will
be adjusted to an amount equal to that competitive rate. The Managing
General Partner may not benefit by interpositioning itself between the
Partnership and the actual provider of drilling contractor services.
(See "Compensation".)
The footage price includes all ordinary costs of drilling, testing and
completing such well including the cost of a second completion and Frac
where Atlas considers it to be justified and installing gathering lines
and other necessary facilities for the production of natural gas.
Although the following costs are possible, it is not anticipated that
such costs will be incurred, and the footage rate will not include the
cost of completion procedures, equipment or any facilities necessary or
appropriate for the production and sale of oil or other liquids and
equipment or materials (except salt water collection tanks, separators,
siphon string and tubing, which are included) necessary or appropriate
to collect, lift or dispose of liquids for efficient gas production. The
footage rate will also not include the cost of a third completion and
Frac which means, in general, treating a third potentially productive
geological formation in an attempt to enhance the gas production from
the well. (See "Definitions".) Such extra costs will be charged at the
Operator's standard charges for services performed directly by it
(exclusive of services in supervision of third party services) or the
Operator's invoice costs of third party services performed and materials
and equipment purchased plus 10% to cover supervisory services and
overhead. Atlas expects to subcontract some of the actual drilling and
completion of Partnership wells to third parties selected by it.
Atlas, as Operator, will determine whether or not to complete each well;
provided that a well may be completed only if Atlas determines in good
faith that there is a reasonable probability of obtaining commercial
quantities of gas. Based upon its past experience, Atlas anticipates
that all Partnership Wells drilled to the Clinton/Medina geological
formation will be required to be completed before a determination can be
made as to the well's productivity. In the event that Atlas determines
that a well should not be completed, the well will be plugged and
abandoned and the footage rate will be adjusted.
Atlas' duties as Operator will include (i) making necessary arrangements
for the drilling and completing of Partnership wells and related
facilities for which it has responsibility under the Drilling and
Operating Agreement; (ii) managing and conducting all field operations
in connection with the drilling, testing, equipping, operation and
production of such wells; (iii) making technical decisions required in
drilling, completing and operating such wells; (iv) maintaining such
wells, equipment and facilities in good working order during the useful
life thereof; and (v) performing necessary accounting and administrative
functions.
During producing operations Atlas, as Operator, will receive a monthly
well supervision fee based upon competitive rates for each producing
well for which it has responsibility under the Drilling and Operating
Agreement. In the Appalachian Basin the well supervision fee will be
$275 for each producing well and will be proportionately reduced to the
extent the Partnership does not acquire 100% of the Working Interest.
This fee may be adjusted on the first day of January of each year
beginning January 1, 1999, by an amount which shall not exceed the
percentage increase since the previous adjustment date in average
earnings of oil and gas industry workers as published by a bureau of the
U.S. Department of Labor. In the event the foregoing rates exceed
competitive rates available from other non-affiliated persons in the
area engaged in the business of rendering or providing comparable
services or equipment, the foregoing rates will be adjusted to an amount
equal to that 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 shall any
consideration received for operator services be duplicative of any
consideration or reimbursement received pursuant to the Partnership
Agreement. (See "Compensation".)
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<PAGE>49
The well supervision fee covers all normal and regularly recurring
operating expenses for the production, delivery and sale of gas, such as
well tending, routine maintenance and adjustment, reading meters,
recording production, pumping, maintaining appropriate books and
records, preparing reports to the Partnership and to government
agencies, and collecting and disbursing revenues. The well supervision
fees do not include costs and expenses related to the production and
sale of oil, purchase of equipment, materials or third party services,
brine disposal, and rebuilding of access roads, all of which will be
billed at the invoice cost of materials purchased or third party
services performed. The Drilling and Operating Agreement contains a
number of other material provisions which should be carefully reviewed
and understood by prospective Participants. (See "Summary of Drilling
and Operating Agreement".)
In the unlikely event that Atlas, Atlas Energy or an Affiliate is not
the actual operator of the well during producing operations, Atlas, as
Managing General Partner, will review the performance of the third party
operator and the costs and expenses charged by it, and will monitor the
accounting and production records for the Partnership. The actual
operator of the wells will be responsible for performing such services
for each well as are customarily performed to operate a gas well in the
same general area as where such well is located. When Atlas, Atlas
Energy or an Affiliate is not the actual operator of the well during
producing operations it will not receive well supervision fees. The
third party operator will be reimbursed for its direct costs and will
receive either reimbursement of its administrative overhead or well
supervision fees pursuant to an operating agreement. Such fees will be
subject to an annual adjustment for inflation and will be
proportionately reduced to the extent the Partnership does not acquire
100% of the Working Interest.
It is anticipated that the Partnership generally will own 100% of the
Working Interest in each Prospect but the Partnership has reserved the
right to take as little as 25% of the Working Interest. Therefore, it is
possible that the Partnership may engage in joint activities on some of
the Prospects with third parties, which would decrease the Partnership's
Working Interest in the well but increase the diversification of the
Partnership's drilling activities. Any other Working Interest owner in
such Prospect may have a separate agreement with Atlas with respect to
the drilling and operation of a well thereon with differing terms and
conditions from those contained in the Drilling and Operating
Agreement. However, Atlas will be the operator or have the right to
replace the operator of all Partnership Wells and will control all
drilling and producing operations including operations with any third
parties.
SALE OF OIL AND GAS PRODUCTION
IN GENERAL. The Managing General Partner is responsible for selling the
Partnership's gas and oil production. Atlas' 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 Partnership, concerning to whom and at what price the gas will be
sold. Atlas calculates a weighted average selling price for all of the
gas sold in the geographic area, such as the Mercer County area. To
arrive at the average weighted selling price the money received from the
sale of all of the gas sold to its customers is divided by the volume of
all gas sold from the wells in the area. During 1995, Atlas received an
average selling price of $2.28 per Mcf for gas sold in the Mercer County
area and during 1996 Atlas received an average selling price of $2.58
per Mcf. The average price paid after deducting all expenses, including
transportation expenses, was $2.01 per Mcf in 1995 and $2.29 per Mcf
in 1996. On occasion, Atlas has reduced the amount of production it
normally sells on the spot market until the spot market price increased.
Atlas, however, has not voluntarily restricted its gas production in the
past two years because of a lack of a profitable market.
In the Mercer County area Atlas estimates that a portion of the
Partnership's gas will be transported through Atlas' own pipeline system
and sold directly to industrial end-users in the area where the wells
will be drilled. It is anticipated that approximately 10% to 30% of the
gas produced by Atlas and its Affiliates, including Atlas' previous
Programs, in the Mercer County area will be sold to industrial end-
users. This will generally result in the Partnership receiving higher
prices for the gas than if the gas were transported a farther distance
through interstate pipelines because of increased transportation
charges. The remainder of the Partnership's gas will be transported
through Atlas' pipelines to the interconnection points maintained with
Tennessee Gas Transmission Co., National Fuel Gas Supply Corporation,
National Fuel Gas Distribution Company, East Ohio Natural Gas Company,
and Peoples Natural Gas Company. These delivery points are utilized by
Atlas Gas Marketing, Inc. to service its end-user markets in the
northeast United States which include in excess of 100 customers. Atlas
is currently delivering an average 27,000 MCF of natural gas per day
from the Mercer County area to all of the aforementioned markets and has
the capacity of delivering 33,000 MCF per day from the Mercer County
area. Atlas anticipates that Wheatland Tube Company and Carbide
Graphite will each purchase approximately 10% to 15% of the
Partnership's gas production in 1998 pursuant to gas contracts between
them and an Affiliate of Atlas, and it is possible that other purchasers
of the Partnership's gas production may account for 10% or more of the
Partnership's gas sales revenues in 1998.
In order to optimize the price it receives for the sale of natural gas,
Atlas markets portions of the gas through long term contracts, short
term contracts and monthly spot sales. The marketing of natural gas
production has been influenced by the availability of certain financial
instruments, such as gas futures contracts, options and swaps which,
when properly utilized as hedge instruments, provide producers or
consumers of gas with the ability to lock in the price which will
ultimately be paid for the future deliveries of gas. Atlas is utilizing
financial instruments to hedge the price risk of a portion of all of its
Programs' gas production, which would include the Partnership. To
assure that the financial instruments will be used solely for hedging
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<PAGE>50
price risks and not for speculative purposes, Atlas has established an
Energy Price Risk Committee comprised of the President, General Counsel,
Chief Financial Officer (chairperson) and Director of Marketing, whose
responsibility will be to ascertain that all financial trading is done
in compliance with hedging policies and procedures. Atlas does not
intend to contract for positions that it cannot offset with actual
production.
TRANSPORTATION OF GAS. One factor in determining the return to the
Partnership is the proximity of the well to the industrial end-user or
to an existing pipeline system or local distribution company. It is
anticipated that Mercer Gas Gathering, Inc., an Affiliate of Atlas, will
transport and compress the natural gas produced by the Partnership into
the various pipelines or directly to industrial end-users. In addition,
Atlas Gas Marketing, Inc., an Affiliate of Atlas, will have the
responsibility to market that portion of gas delivered to the various
interconnection points maintained with the interstate pipelines and
local distribution companies to its 100 customer base. The Partnership
will pay a combined transportation and marketing charge for these
services at a competitive rate, which is currently 29 cents per MCF.
(See "Compensation" and "Management".)
MARKETING OF PRODUCTION FROM WELLS IN OTHER AREAS OF THE UNITED STATES.
In the event any wells are drilled in areas of the United States other
than the Mercer County area, Atlas expects that gas produced from such
wells will be supplied to industrial end-users, local distribution
companies and/or interstate pipelines.
CRUDE OIL. Any crude oil produced from the wells may 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 such crude oil. Therefore, crude oil usually does not present
any transportation problem. Atlas anticipates selling any oil produced
by the wells in the Mercer County area to Quaker State Oil Refining
Company ("Quaker State") in spot sales. Atlas was receiving
approximately $15.50 per barrel in December, 1995, and approximately
$21.50 per barrel in December, 1996, from Quaker State for oil produced
in the Mercer County area. Over the past eight years, the price of oil
has declined from approximately $38 to as low as $10 per barrel. There
can be no assurance as to the price of oil during the term of the
Partnership and the actions of OPEC increase the volatility of the price
of oil.
INTERESTS OF PARTIES
The Managing General Partner, Participants and unaffiliated third
parties (including landowners) share revenues from production of gas
from wells in which the Partnership has an interest. The following chart
expresses such interests in gross revenues derived from the wells based
on 32 of the currently proposed Prospects set forth below in "-
Information Regarding Currently Proposed Prospects". In the event the
Partnership acquires less than a 100% Working Interest, the percentages
available to the Partnership will decrease proportionately.
THIRD PARTY ROYALTIES
PARTNERSHIP AND OVERRIDING 87.5 %
PARTNERSHIP NET
Managing General Partner 25% Partnership Interest 21.875%
Participants 75% Partnership Interest 65.625%
Third Parties 12.5% Landowner Royalty 100.000%
__________________________
(1) On three of the currently proposed Prospects the Net Revenue
Interest to the Partnership would be 84.375%, which would reduce the
Participants' interest to 63.281%. The Leases in areas of the Unites
States other than the Mercer County area may also be subject to
greater Overriding Royalty Interests, third party net profits
interests, carried interests, production payments, reversionary
interests or other retained or carried interests.
INSURANCE
Since 1972, Atlas and its Affiliates have been involved in the drilling
of approximately 1,600 wells in Ohio, Pennsylvania and other areas of
the Appalachian Basin and no blow-out, fire or similar hazard has
occurred with respect to any of these wells. Therefore, Atlas and its
Affiliates have not made any insurance claims in Ohio, Pennsylvania and
other areas of the Appalachian Basin with respect to such hazards.
Atlas will obtain and maintain for the benefit of itself and the
Partnership insurance coverage in such amounts, with provisions for such
deductible amounts and for such purposes, as would be carried by a
reasonable, prudent general contractor and operator in accordance with
industry standards. The Partnership will be named as an additional
insured under such policies. In addition, Atlas 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 $1,000,000 combined single limit
for bodily injury and property damage in any one occurrence or accident.
Atlas' current insurance coverage satisfies the following
specifications:
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<PAGE>51
(a) worker's compensation insurance in full compliance with
the laws of the Commonwealth of Pennsylvania and any other
applicable state laws;
(b) liability insurance (including automobile) which has a
$1,000,000 combined single limit for bodily injury and
property damage in any one occurrence or accident and in
the aggregate; and
(c) excess liability insurance as to bodily injury and
property damage with combined limits of $50,000,000 during
drilling operations, per occurrence or accident and in the
aggregate, which includes $250,000 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 an accident. Such excess liability
insurance will be in place and effective no later than the
Initial Closing Date.
The excess liability insurance will be for the benefit of the
Partnership and other Programs in which Atlas serves as Managing General
Partner until the Investor General Partners are converted to Limited
Partners, at which time the Partnership will continue to enjoy the
benefit of Atlas' $11,000,000 liability insurance on the same basis as
Atlas and its Affiliates, including other Programs in which Atlas serves
as Managing General Partner. (See "Competition, Markets and Regulation -
State Regulations" and "- Environmental Regulation".)
These policies will have terms, including exclusions, standard for the
oil and gas industry. (See "Risk Factors - General Risks of the Oil and
Gas Business - Drilling Hazards May Be Encountered".) Upon the request
of any prospective Participant, Atlas will provide to such prospective
Participant or his representatives a copy of Atlas' insurance policies.
Atlas will use its best efforts to maintain insurance coverage which
meets or exceeds its current coverage but may ultimately be unsuccessful
in such efforts because such coverage may become unavailable or cost
prohibitive.
The Managing General Partner will notify all Participants at least
thirty days prior to the effective date of any adverse material change
in the Partnership's insurance coverage. If the insurance coverage will
be materially reduced, which is not anticipated, the Investor General
Partners will have the right to convert their Units into Limited Partner
interests prior to such reduction by giving written notice to the
Managing General Partner. (See "Tax Aspects - Limitations on Passive
Activities".)
USE OF CONSULTANTS AND SUBCONTRACTORS
Although not anticipated with respect to producing operations in the
Mercer County area, the Partnership Agreement authorizes the Managing
General Partner to employ and utilize the services of independent
outside consultants and subcontractors. Such persons will normally be
compensated through payment on a per diem or other cash fee basis. Such
services will be charged to the Partnership as a Direct Cost or as a
direct expense pursuant to the Drilling and Operating Agreement,
attached as Exhibit (II) to the Partnership Agreement, and will be in
addition to the unaccountable, fixed payment reimbursement paid to Atlas
and its Affiliates for Administrative Costs, and well supervision fees
paid to Atlas as Operator. (See "Compensation" and "Management".)
INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS
Set forth below is information relating to Prospects which have been
currently proposed for assignment to the Partnership upon the Offering
Termination Date and from time to time thereafter subject to Atlas'
right to withdraw such Prospects and to substitute other Prospects. The
specified Prospects represent the necessary Prospects if 80% of the
potential maximum Partnership Subscription of $10,000,000 is raised and
the Partnership takes 100% of the Working Interest. Atlas has not
proposed any other Prospects if more than this amount is raised, if the
Partnership takes a lesser Working Interest in the Prospects, if the
Prospects are substituted and/or if Prospects will be drilled in areas
of the United States other than the currently proposed locations.
The assignment of the currently proposed Prospects will be dependent on
the non-materialization of any circumstances occurring which, in Atlas'
opinion, would diminish the relative attractiveness of the Prospects.
Any substituted and/or additional Prospects will meet the same general
criteria for development potential as the currently proposed Prospects;
however, prospective subscribers will not have the opportunity to
evaluate for themselves the relevant geophysical, geological, economic
or other information regarding such Prospects. However, most of the
Partnership's wells will have as their objective the Clinton/Medina
geological formation discussed in the UEDC Geological Report and will be
located in areas where Atlas or its Affiliates have previously conducted
drilling operations. (See "- Acquisition of Leases".)
The purpose of the information regarding the currently proposed
Prospects is to assist prospective subscribers in analyzing and
evaluating the currently proposed Prospects, including production
information for wells in the general area. Atlas believes that
production information with respect to wells in the general area is an
important indicator in evaluating the economic potential of any Prospect
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<PAGE>52
to be developed by the Partnership. However, there can be no assurance
that a well drilled by the Partnership will experience production
comparable to the production experienced by wells in the surrounding
area since the geological conditions in the Clinton/Medina geological
formation can change in a short distance.
Prospective subscribers are cautioned and urged to analyze carefully all
production information for each well offsetting or in the general area
of a specified Prospect and, in the process of doing so, to take the
factors set forth below into consideration.
1. The length of time which the well has been on line and
the period of time for which production information is
shown.
2. The impact of "flush" production of a well which usually
occurs in the early period of well operations. This period
can vary depending on the location of the well and the
manner in which the well is operated.
3. Production declines at various rates throughout the life
of a well and decline curves vary depending on the
geological location of the well and the manner in which the
well is operated.
4. The production information with respect to some wells is
incomplete and with other wells very limited. The
designation "N/A" means the production was not available to
Atlas or if Atlas was the Operator then the well was not
completed or on line as of the date of the report.
5. It should be noted that production information for wells
located in close proximity to a Prospect tends to be more
relevant than production information for wells located at a
great distance from a Prospect, although from time to time
great disparity in well performance can occur in wells
located in close proximity.
6. Consistency in production among wells tends to confirm
the reliability and predictability of such production.
All of the specified Prospects are subject to the factors set forth
below:
1. There are no Overriding Royalty Interests or other
burdens in favor of Atlas or its Affiliates.
2. Atlas or its Affiliates will act as driller and operator
for all the wells. It is anticipated that the Partnership
generally will be transferred 100% of the Working Interest
but the Partnership has reserved the right to take as
little as 25% of the Working Interest.
3. Atlas and its Affiliates own acreage in the vicinity of
the Prospects. (See "Conflicts of Interest - Conflicts
Involving Acquisition of Leases".)
4. The Leases are being contributed to the Partnership at
Atlas' Cost of such Lease, unless the Managing General
Partner has reason to believe that Cost is materially more
than the fair market value of such property, in which case
the price will not exceed the fair market value.
5. All wells will be drilled through the Clinton/Medina
formation to the top of the Queenston formation. The wells
will have no secondary objectives.
6. All of the wells will be gas wells. See the Production
Map for the location of Atlas' pipeline. Also, see "- Sale
of Oil and Gas Production" concerning a discussion of the
marketing arrangements for the Partnership's gas.
Included for the Prospects is certain information set forth below which
is designed to assist the prospective subscriber in becoming familiar
with the Prospect location.
1. A map of western Pennsylvania and eastern Ohio showing
their counties.
2. Prospect Lease information.
3. A Location and Production Map showing the Prospects and
the wells in the area.
4. Production data.
5. United Energy Development Consultants, Inc.'s geological
report. See "Experts" in the Prospectus.
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<PAGE>53
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<PAGE>54
MAP OF WESTERN PENNSYLVANIA
AND
EASTERN OHIO
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<PAGE>55
PROSPECT LEASE INFORMATION
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<PAGE>56
EXHIBIT A
ATLAS ENERGY FOR THE NINETIES - - PUBLIC #6 LTD
Prospect Name County Effective Expiration LRI NRI ORI Acres
Date Date Assigned to
Partnership
1. Bentley #1 Mercer 06/10/96 06/10/99 12.50%87.50% 50
2. Bentley #2 Mercer 06/10/96 06/10/99 12.50%87.50% 50
3. Burke #1 Mercer 05/02/96 05/02/99 12.50%87.50% 50
4. Byler #18 Lawrence 10/10/96 10/10/99 12.50%87.50% 50
5. Byler #19 Lawrence 10/02/96 10/02/99 12.50%87.50% 50
6. Detweiler #4 Lawrence 07/29/96 07/29/98 12.50%87.50% 50
7. Ferris #1 Mercer 01/13/97 01/13/00 12.50%87.50% 50
8. George #2 Mercer 09/20/94 09/20/97 12.50%87.50% 50
9. Hissom #2 Mercer 05/23/96 HBP 12.50%87.50% 50
10. Jenkins #2 Mercer 09/05/95 09/05/98 12.50% 87.50% 50
11. Kaltenbaugh #2Mercer 07/24/95 07/24/98 12.50% 84.375% 3.125% 50
12. Kempf #1 Mercer 02/20/97 02/20/00 12.50% 87.50% 50
13. Kennedy #2 Mercer 08/28/95 08/28/98 12.50% 87.50% 50
14. Kingery #2 Lawrence 05/08/97 05/08/00 12.50% 87.50% 50
15. McCartney #1 Mercer 02/12/97 02/12/02 12.50% 87.50% 50
16. McDowell #16 Mercer 10/20/96 HBP 12.50% 87.50% 50
17. McDowell #17 Mercer 10/20/96 HBP 12.50% 87.50% 50
18. McKean #2 Mercer 05/17/97 05/17/00 12.50% 87.50% 50
19. McKean #3 Mercer 05/17/97 05/17/00 12.50% 87.50% 50
20. Oakes #3 Mercer 02/21/97 02/21/99 12.50% 87.50% 50
21. Palmer #2 Mercer 06/17/96 06/17/99 12.50% 87.50% 50
22. Piepenhagen #2Mercer 06/10/96 06/10/99 12.50% 87.50% 50
23. Plants #1 Mercer 06/03/93 06/03/98 12.50% 84.375% 3.125% 50
24. Plummer #1 Mercer 07/02/95 07/02/98 12.50% 87.50% 50
25. Rick #1 Mercer 07/30/93 07/30/98 12.50% 87.50% 50
26. Roman #1 Mercer 06/12/95 06/12/98 12.50% 87.50% 50
27. Root #2 Mercer 06/02/97 06/02/00 12.50% 87.50% 50
28. Shardy #1 Mercer 04/24/95 04/24/98 12.50% 87.50% 50
29. Sines #4 Mercer 05/06/96 05/06/99 12.50% 87.50% 50
30. Stallsmith #1 Mercer 06/02/93 06/02/98 12.50% 84.375% 3.125% 35
31. Tenney U. #1 Mercer 06/01/94 06/01/99 12.50% 87.50% 50
32. Wiese #1 Mercer 01/09/97 01/09/00 12.50% 87.50% 50
33. Whyte #4 Mercer 03/28/96 03/28/99 12.50% 87.50% 50
34. Williams #4 Mercer 08/05/91 08/05/97 12.50% 87.50% 50
35. Winder #3 Mercer 12/12/95 12/12/98 12.50% 87.50% 50
- * 3.125% Overriding Royalty Interest to a third party.
- HBP - Held by Production
- ------------------------------------------------------------------------------
<PAGE>57
to
<PAGE>63
LOCATION AND PRODUCTION MAP
Maps showing the locations of each prospect in relation to other wells
Located in Mercer and Lawrence Counties, Pennsylvania.
- ------------------------------------------------------------------------------
<PAGE>64
to
<PAGE>68
PRODUCTION DATA
THE PRODUCTION DATA PROVIDED IN THE TABLE BELOW IS NOT INTENDED TO IMPLY
THAT THE WELLS TO BE DRILLED BY THE PARTNERSHIP WILL HAVE THE SAME
RESULTS, ALTHOUGH IT IS AN IMPORTANT INDICATOR IN EVALUATING THE
ECONOMIC POTENTIAL OF ANY PROSPECT TO BE DEVELOPED BY THE PARTNERSHIP.
Date: May 31, 1997
<TABLE>
ID WELL DATE MOS TOT. LOG LATEST 30
NUMBER OPERATOR NAME COMP. ON-LINE MCF DEPTH DAY PROD
<C> <S> <C> <S><C> <C> <C> <S> <C> <C> <S>
21231 Capital Oil & Gas Cox, Joan 1 12/23/91 N/A N/A 6100 N/A
21497 Capital Oil & Gas Byler, S. & M. 2 12/02/92 N/A N/A 6210 N/A
21498 Capital Oil & Gas Hostetler, M. & D. 3 10/29/92 N/A N/A 6154 N/A
21121 Capital Oil & Gas Hostetler, M. & D. 1 11/11/90 N/A N/A 6140 N/A
20155 Atlas Resources, Inc. Kurtz #1 10/05/96 5 10780 6266 1809
20159 Atlas Resources, Inc. Kurtz #2 02/28/97 3 6915 6235 3195
20157 Atlas Resources, Inc. Hostetler #3 02/20/97 3 6738 6195 3422
20161 Atlas Resources, Inc. Byler #14 03/07/97 3 5611 6200 3156
21161 Atlas Resources, Inc. Algeo #1 11/10/90 78 39013 5737 325
20154 Atlas Resources, Inc. Byler #11 02/13/97 3 7576 6329 3379
21510 Capital Oil & Gas Cyphert C. #1 10/09/92 N/A N/A 6242 N/A
20156 Atlas Resources, Inc. Byler #12 11/19/96 5 15798 6328 3468
20158 Atlas Resources, Inc. Lowry #1 09/28/96 7 19928 6243 1432
20727 Atlas Resources, Inc. Smith-Tetrick #1 09/13/85 113 48497 5725 252
20640 Atlas Resources, Inc. Tomko #1 11/27/84 113 43244 5724 228
20625 Atlas Resources, Inc. Thompson Un. #1 08/13/84 113 19160 5768 194
20721 Atlas Resources, Inc. Root Un. #1 08/15/85 113 34571 5739 221
22281 Atlas Resources, Inc. Bartholomew #5 02/19/97 3 10235 5819 4444
22282 Atlas Resources, Inc. Bartholomew #6 09/08/96 8 15485 5824 1866
21863 Atlas Resources, Inc. Bartholomew #3 01/28/94 35 76908 5813 1499
22352 Atlas Resources, Inc. Rueberger Un. #1 02/26/97 1 1597 5851 1597
21948 Atlas Resources Inc. Mills #7 08/22/94 32 133349 5654 3055
21967 Atlas Resources, Inc. Humes Un. #3 09/19/94 31 108508 5630 2321
21966 Atlas Resources, Inc. Humes #2 09/25/94 31 83346 5780 1768
21991 Atlas Resources, Inc. Branca Un. #1 10/01/94 30 38827 5778 938
21421 Atlas Resources, Inc. Hoagland #1 03/07/92 62 130643 5751 901
22011 Atlas Resources, Inc. Hoagland Un. #2 12/11/94 29 73184 5890 2510
21451 Atlas Resources, Inc. Firth #2 03/01/92 63 62733 5873 600
21407 Atlas Resources, Inc. Firth #1 01/05/92 63 17839 5872 82
21599 Atlas Resources, Inc. Diegan #2 10/17/92 54 11836 5748 84
22249 Atlas Resources, Inc. Lutes #1 03/23/97 2 4394 5791 3499
22168 Atlas Resources, Inc. Eperthener Un. #2 02/26/96 14 34511 5953 1272
22178 Atlas Resources, Inc. Rabold #1 01/28/96 16 24289 5993 782
22179 Atlas Resources, Inc. Thompson #4 01/21/96 16 55149 5921 2165
22111 Atlas Resources, Inc. Romain #4 10/20/95 19 164177 5906 4204
22074 Atlas Resources, Inc. Graham #2 03/28/95 25 79105 5916 2526
22308 Atlas Resources, Inc. Kloos #4 01/08/97 5 13251 5955 3489
22267 Atlas Resources, Inc. Kloos #1 10/31/96 7 2651 5899 598
22207 Atlas Resources, Inc. Kloos #2 03/11/96 15 24849 5882 1324
22348 Atlas Resources, Inc. Vogan #3 03/12/97 2 3638 5903 2042
22214 Atlas Resources, Inc. Struthers #5 03/18/96 15 115063 5849 5254
20699 Atlas Resources, Inc. Struthers #1 07/10/85 70 1735 5832 0
22313 Atlas Resources, Inc. Rains #1 01/17/97 5 6806 5944 985
22254 Atlas Resources, Inc. Struthers #7 08/19/96 8 3535 5835 413
22250 Atlas Resources, Inc. Oehlbeck Un. #1 07/31/96 Plugged & Abandoned 5829
22176 Atlas Resources, Inc. Struthers #4 03/06/96 14 10306 5957 448
22252 Atlas Resources, Inc. Struthers #6 08/13/96 8 21851 5921 2813
21484 Atlas Resources, Inc. Struthers Un. #3 02/25/92 Plugged & Abandoned 5849
21315 Atlas Resources, Inc. Kelso Un. #2 08/11/91 69 81766 5786 785
21340 Atlas Resources, Inc. Kelso #1 11/11/91 66 46030 5827 445
21307 Atlas Resources, Inc. Marsh #3 09/04/91 69 77064 5700 1037
22234 Atlas Resources, Inc. Wasser #2 09/09/96 8 13331 5754 1415
22279 Atlas Resources, Inc. Kingerski #1 11/06/96 6 9098 5823 1014
22241 Atlas Resources, Inc. Kingerski #2 01/09/97 5 7493 5801 1967
21269 Atlas Resources, Inc. Sealand #1 04/08/91 73 77010 5858 663
21305 Atlas Resources, Inc. Marsh #1 08/02/91 70 29314 5831 200
21312 Atlas Resources, Inc. Marsh #2 09/18/91 68 68629 5873 618
21313 Atlas Resources, Inc. Mercer Vo-Tech #2 07/26/91 70 33711 5905 419
21394 Atlas Resources, Inc. Marsh Un. #4 11/06/91 67 67923 5811 533
21337 Atlas Resources, Inc. Monske #1 08/19/91 69 53001 5620 570
20696 Viking Resources Worley #1 07/01/85 N/A N/A 5734 N/A
22233 Atlas Resources, Inc. Wasser #1 09/01/96 8 29341 5823 3923
22359 Atlas Resources, Inc. Hileman #1 04/02/97 Plugged & Abandoned 5829
22351 Atlas Resources, Inc. Barber #2 03/04/97 2 3091 5844 2789
22320 Atlas Resources, Inc. Steele #1 01/18/97 4 7599 5797 1820
22319 Atlas Resources, Inc. Babcock #1 01/26/97 4 5485 5791 1805
21327 Atlas Resources, Inc. Cresswell #1 08/28/91 69 76169 5688 805
22314 Atlas Resources, Inc. Tait #3 02/17/97 3 8615 5857 3538
22289 Atlas Resources, Inc. Tait #2 10/10/96 Plugged & Abandoned 5861
22295 Atlas Resources, Inc. Mandell Un. #2 10/02/96 8 17521 5859 1986
22357 Atlas Resources, Inc. McCullough #10 03/21/97 2 4458 5882 2642
22294 Atlas Resources, Inc. McCullough #9 10/17/96 7 20978 5849 3606
22327 Atlas Resources, Inc. Court #1 02/03/97 4 5929 5919 2006
22270 Atlas Resources, Inc. McCullough #8 08/24/96 8 14330 5927 1589
22335 Atlas Resources, Inc. Cornelius #4 02/23/97 3 7587 5951 3457
22248 Atlas Resources, Inc. Cornelius #2 08/02/96 8 15813 5944 1417
22246 Atlas Resources, Inc. Cornelius #3 07/26/96 8 22066 5911 1887
22235 Atlas Resources, Inc. Boyer #2 03/24/97 2 2724 5900 2000
22217 Atlas Resources, Inc. McDowell #8 03/26/96 14 59028 5941 2883
22332 Atlas Resources, Inc. Hissom #1 02/03/97 4 9637 5681 3341
22334 Atlas Resources, Inc. Sines #3 02/10/97 4 9480 5738 3436
22288 Atlas Resources, Inc. Philson #4 09/16/96 8 26578 5821 3380
22297 Atlas Resources, Inc. North #1 09/23/96 8 25744 5838 3566
22355 Atlas Resources, Inc. Morley Un. #1 03/15/97 1 1875 5743 1875
22346 Atlas Resources, Inc. Clark #5 03/01/97 2 4745 5787 2683
22220 Petroleum Dev. Corp. Byler #12 02/26/96 N/A N/A 5830 N/A
22195 Vista Resources Coblentz #2 02/17/96 N/A N/A 5706 N/A
22321 Atlas Resources, Inc. Kelly #2 02/23/97 3 4858 5769 2173
22328 Atlas Resources, Inc. Black #2 02/16/97 3 7661 5806 2623
22205 Petroleum Dev. Corp. Kacir #1 03/04/96 N/A N/A 5832 N/A
22242 Atlas Resources, Inc. Jenkins #1 07/11/96 8 18721 5949 2454
22247 Atlas Resources, Inc. Taylor #2 01/18/97 4 1927 5932 577
22236 Atlas Resources, Inc. Taylor #1 06/27/96 8 19641 5992 2480
22356 Atlas Resources, Inc. McDowell #14 03/12/97 2 1920 5949 1273
22255 Atlas Resources, Inc. McDowell #9 08/07/96 8 21580 5821 2691
22256 Atlas Resources, Inc. Gildersleve Un. #1 07/25/96 8 7801 5978 648
22216 Atlas Resources, Inc. Baun Un. #3 07/03/96 8 17936 5992 1747
22238 Atlas Resources, Inc. Williams #5 08/20/96 8 8605 5942 926
22251 Atlas Resources, Inc. Morrow Un. #1 07/18/96 8 7149 5936 845
22271 Atlas Resources, Inc. Gatewood #1 08/27/96 8 7787 5963 659
22231 Atlas Resources, Inc. Hall #1 01/11/97 5 4839 5965 1055
22226 Atlas Resources, Inc. Baun #2 03/25/96 14 15865 5945 780
22152 Atlas Resources, Inc. Irwin #2 03/03/96 15 15986 6057 761
22316 Atlas Resources, Inc. Peterka #2 02/01/97 2 918 6010 705
22245 Atlas Resources, Inc. Peterka Un. #1 08/14/96 8 5189 5985 570
22305 Atlas Resources, Inc. Vernam #1 01/25/97 4 2745 5941 514
22333 Atlas Resources, Inc. Dye #1 02/07/97 4 5430 5995 1385
22330 Atlas Resources, Inc. McCullough #11 01/27/97 4 9292 5897 3114
22350 Atlas Resources, Inc. Mong #1 03/07/97 2 2582 5873 2365
22129 Atlas Resources, Inc. Rabold #4 10/29/95 16 33623 5838 1175
22180 Atlas Resources, Inc. Philson #3 01/28/96 16 19440 5948 649
22123 Atlas Resources, Inc. Philson #2 11/21/95 16 69333 5887 2356
22127 Atlas Resources, Inc. Eagle #1 08/30/95 19 48593 5938 1757
22121 Atlas Resources, Inc. Duffola Un. #1 09/04/95 19 39937 5929 1185
22172 Atlas Resources, Inc. Irwin #1 01/24/96 15 13945 5965 620
22151 Atlas Resources, Inc. Polick #3 02/12/96 15 22265 5969 1027
22156 Atlas Resources, Inc. Kalansky #1 02/18/96 15 23141 5971 950
22213 Atlas Resources, Inc. Hamilton #3 03/16/96 14 15536 5971 590
22329 Atlas Resources, Inc. Andrews #1 03/27/97 1 733 5687 733
21386 Cabot Oil & Gas Mowry Ralph E. 11/14/91 Dry Hole 5883
22360 Atlas Resources, Inc. Winger #1 03/21/97 1 2503 5743 2503
22299 Atlas Resources, Inc. Burnette #1 10/18/96 7 19294 5725 3703
22296 Atlas Resources, Inc. Cousins Un. #3 11/02/96 6 13303 5476 2469
22312 Vista Resources McQuiston #2-C 02/25/97 N/A N/A 5390 N/A
22315 Vista Resources McQuiston #1-C 01/11/97 N/A N/A 5300 N/A
22326 Vista Resources Miller Un. #2 03/05/97 N/A N/A 5367 N/A
22303 Atlas Resources, Inc. Fairlamb Un. #1 11/10/96 6 12472 5432 2532
22218 Vista Resources Sprinkle Un. #3 09/16/96 N/A N/A 5500 N/A
22259 Vista Resources Sprinkle Un. #2 09/07/96 N/A N/A 5500 N/A
22260 Vista Resources Sprinkle #1 01/27/97 N/A N/A 5411 N/A
22325 Vista Resources Miller Un. #1 02/05/97 N/A N/A 5375 N/A
</TABLE>
<PAGE>69
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<PAGE>78
=============================================================================
Page 1
GEOLOGIC EVALUATION
of
ATLAS - ENERGY FOR THE NINETIES - PUBLIC #6 LTD.
DRILLING PROGRAM
Southeastern Mercer Prospect Area,
Pennsylvania
Program proposed by:
ATLAS RESOURCES, INC.
311 Rouser Road
P.O. Box 611
Moon Township, PA 15108
Report submitted by:
UEDC
United Energy Development Consultants, Inc.
404 Pine Villa Dr.
Gibsonia, PA 15044
For:
ATLAS - ENERGY FOR THE NINETIES - PUBLIC #6 LTD.
Drilling Program by:
ATLAS RESOURCES, INC.
311 Rouser Rd.
P.O. Box 611
Moon Township, PA 15108
- -----------------------------------------------------------------------------
Page 2
LOCATION MAP - AREA OF INTEREST
TABLE OF CONTENTS
INVESTIGATION SUMMARY 3
OBJECTIVE 3
AREA OF INVESTIGATION 3
METHODOLOGY 3
SOUTHEASTERN MERCER PROSPECT AREA 3
DRILLING ACTIVITY 3
GEOLOGY 4
STRATIGRAPHY, LITHOLOGY & DEPOSITION 4
RESERVOIR CHARACTERISTICS 6
PRODUCTION CURVE 8
POTENTIAL MARKETS AND PIPELINES 8
STATEMENTS 9
CONCLUSION 9
DISCLAIMER 9
NON-INTEREST 9
- -----------------------------------------------------------------------------
Page3
INVESTIGATION SUMMARY
OBJECTIVE
The purpose of the following investigation is to evaluate the
geologic feasibility and further development of the Southeastern Mercer
Prospect Area (consisting of Butler, Lawrence, and Mercer Counties) as
proposed by Atlas Resources, Inc.
AREA OF INVESTIGATION
A portion of this prospect area, herein identified as the Atlas-
Energy for the Nineties-Public #6 Ltd. Drilling Program, contains
acreage in Jackson, Coolspring, Deer Creek, Fairview, Lackawannock,
Wilmington, and Mill Creek Townships in Mercer County, Wilmington
Township in Lawrence County. All counties are located in Pennsylvania.
Thirty five (35) drilling prospects designated for this program will be
targeted to produce natural gas from Clinton-Medina Group Reservoirs,
found at an average depth of approximately 5,900 to 6,500 feet beneath
the earth's surface.
METHODOLOGY
The data incorporated into this report was provided by Atlas
Resources, Inc. and the in-house archives of UEDC, Inc. Geological
mapping and the interpretations by Atlas geologists were also examined.
Available "electric" log, completion, and production data on wells
offsetting prospect locations and other "key" wells within and adjacent
to the defined prospect area were utilized to determine productive and
depositional trends.
SOUTHEASTERN MERCER PROSPECT AREA
DRILLING ACTIVITY
The proposed drilling area lies within a region of northwestern
- -------------------------------------------------------------------------
Page4
Pennsylvania which has been very active for the past decade in terms of
exploration for, and exploitation of natural gas reserves. Development
within and adjacent to the Southeastern Mercer Prospect Area has
escalated since 1986, with Atlas Resources, Inc. and it's affiliates
drilling over eight hundred (800) wells during this period. Atlas
Resources, Inc. has encountered favorable drilling and production
results while solidifying a strong acreage position, as Atlas Resources,
Inc. continues to identify and extend productive trends. Drilling is
ongoing as of the date of this report with recent wells displaying
favorable initial drilling and completion results. Competitive activity
has begun both south and east of the prospect area, confirming the
Clinton-Medina Group of Lower Silurian age as a viable target for the
further development of economic quantities of natural gas.
GEOLOGY
STRATIGRAPHY, LITHOLOGY & DEPOSITION
Regionally, the Clinton-Medina Group was deposited in tide-
dominated shoreline, deltaic, and shelf environments and is
lithologically comprised of alternating sandstones, siltstones and
shales. Productive sandstones are composed of siliceous to dolomitic
subarkoses, sublitharenites, and quartz arenites. Reservoir quality
sands occur throughout the delta-complex from eastern Ohio through
northwestern Pennsylvania and western New York. The Clinton-Medina
Group, deposited during the Lower Silurian, overlies the Upper
Ordovician age Queenston shale and is capped by the Middle Silurian
Reynales Formation. This dolomitic limestone "cap" is known locally to
drillers as the "Packer Shell".
Stratigraphically, in descending order, the potentially productive
units of the Clinton-Medina Group consist of the: 1) Thorold, 2)
Grimsby, 3) Cabot Head, and 4) Whirlpool members. These stratigraphic
relationships are illustrated in the following diagram:
- ------------------------------------------------------------------------
Page4
The Whirlpool is a light gray quartzose sandstone to siltstone
ranging in thickness from five (5) to twenty (20) feet. Average
porosity values for this sand member range from five (5) to ten (10)
percent regionally. Within the area of investigation, porosities in
excess of twelve (12) percent occur within localized trends targeted for
further development.
The Cabot Head is a dark green to black shale, most likely of
marine origin. Within the investigated area a Cabot Head sandstone has
been encountered in numerous wells. This formation has been found to
contribute natural gas when Reservoir characteristics, including
evidence of enhanced permeability, warrant completion. This sand member
is considered a secondary target.
The Grimsby is the thickest sandstone member of the Clinton-Medina
Group. Sand development ranges from ten (10) to forty-five (45) feet
within an interval comprised of fine to very fine, light gray to red
- -------------------------------------------------------------------------
Page6
sandstones and siltstones broken up by thin dark gray silty shale
layers. Average porosity values for the Grimsby are approximately six
(6) to (10) percent over the pay interval regionally. Permeability may
be enhanced locally by the presence of naturally occurring micro-
fractures. Future development focuses on established production trends.
The Thorold sandstone is the uppermost producing interval of the
Clinton-Medina sequence. This interbedded ferric sand, silt and shale
interval averages forty (40) feet. Where pay sand development occurs,
porosities are in the typical Clinton-Medina group range of six (6) to
(10) percent. Permeability may be enhanced locally by the presence of
naturally occurring micro-fractures.
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable
barrier trapping natural gas of commercial quantities in a more
permeable medium. In the Clinton-Medina, this occurs either
stratigraphically when a permeable sand containing hydrocarbons
encounters an impermeable shale or when a permeable sand changes
gradually into a non-permeable sand by a cementation process known as
"diagenesis". Thus, this type of trap represents cemented-in
hydrocarbon accumulations.
Electric well logs can be used in conjunction with production to
interpret Reservoir parameters. When sandstones in the Thorold,
Grimsby, Cabot Head or Whirlpool develop porosity in excess of 6%, or a
bulk density of 2.55 or less, the permeability of the reservoir (which
ranges from <0.l to >0.2 mD) can become great enough to allow commercial
production of natural gas. Small, naturally occurring cracks in the
formation, referred to as micro-fractures, can also enhance
permeability. A gamma, bulk density, density porosity and neutron log
suite showing sand development in the Grimsby, Cabot Head and Whirlpool
is illustrated on the following page.
- ------------------------------------------------------------------------
Pagee7
Two other phenomena detected by well logs can occur which are
indicators of enhanced permeability. These indicators used to detect
productive intervals are:
Mudcake buildup across the zone of interest - after loading the
wellbore with brine fluid and circulating, an interval with
enhanced permeability will accept fluid, filtering out the solids
and leaving behind a buildup (or mudcake) on the formation wall.
This is detectable with a caliper log.
Invasion profile - during circulation, a brine that has a high
conductivity (or low resistivity) that is accepted into the
formation (as described above) will change the electrical
conductivity of the reservoir rock near and around the wellbore.
The resistivity will be low nearest to the wellbore and will
increase away from the wellbore. A dual laterolog can be used to
detect this profile created by a permeable zone - it records
resistivity near the wellbore as well as deeper into the formation.
A zone with enhanced permeability will show a separation between
the shallow and deep laterologs, while a zone with little or no
permeability would cause the two resistivity measurements to read
exactly the same. An example follows:
- -------------------------------------------------------------------------
Page8
GAMMA RAY LOG RESISTIVITY LOG
PRODUCTION CURVE
A model decline curve for the Southeastern Mercer Prospect Area was
created, based on production histories from over 600 wells in the mature
portion of the field. The percentage of gas recovery per year is
illustrated by the diagram below:
POTENTIAL MARKETS AND PIPELINES
In the area of this drilling program, there are a number of
potential purchasers and transporters of natural gas. These include
Wheatland Tube Company, Tenneco, National Fuel Supply, National Fuel
Distribution and the People's Natural Gas Company.
- ------------------------------------------------------------------------
Page9
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the Atlas-Energy
for the Nineties-Public #6 Ltd. Drilling Program, which will consist of
developmental drilling of the Clinton-Medina Group sands in Mercer,
Lawrence and Butler Counties, Pennsylvania. It is the professional
opinion of UEDC that the drilling of wells within this program is
supported by sufficient geologic and engineering data.
DISCLAIMER
For the purpose of this evaluation, UEDC did not visit any
leaseholds or inspect any of the associated production equipment.
Likewise, UEDC has no knowledge as to the validity of title,
liabilities, or corporate matters affecting these properties. UEDC does
not warrant individual well performance.
NON-INTEREST
We hereby confirm that UEDC is an independent consulting firm and
that neither this firm or any of its employees, contract consultants, or
officers has, or is committed to acquire any interest, directly or
indirectly, in Atlas Resources, Inc.; nor is this firm, or any employee,
contract consultant, or officer thereof, otherwise affiliated with Atlas
Resources, Inc. We also confirm that neither the employment of, nor
payment of compensation received by UEDC in connection with this report,
is on a contingent basis.
Respectfully submitted,
UEDC, Inc.
- -----------------------------------------------------------------------------
<PAGE>79
COMPETITION, MARKETS AND REGULATION
COMPETITION
There are many companies, partnerships and individuals engaged in
natural gas exploration, development and operations in the areas where
the Partnership is expected to conduct its activities. The industry is
highly competitive in all of its phases, including acquiring suitable
properties for development and the marketing of natural gas. The
Partnership will be competing with other companies, and the sale of the
production from the wells in the Mercer County area will compete with
the sale of production from the other wells that have already been
drilled or are being operated by Atlas in the area. However, to reduce
and/or eliminate this conflict of interest it is Atlas' policy to treat
all wells in a geographic area equally as to pipeline access and access
to Atlas' gas supply agreements. (See "Proposed Activities - Sale of Oil
and Gas Production".)
Current economic conditions indicate that the costs of exploration and
development are increasing gradually; however, the oil and gas industry
historically has experienced periods of rapid cost increases from time
to time.
MARKETING
Natural gas and oil, if any, produced by the wells developed by the
Partnership must be marketed in order for the Participants to realize
revenues from such production. In recent years natural gas and oil
prices have been volatile.
The marketing of natural gas and oil production, if any, will be
affected by numerous factors beyond the control of the Partnership and
the effect of which cannot be accurately predicted. These factors
include the availability and proximity of adequate pipeline or other
transportation facilities; the amount of domestic production and foreign
imports of oil and gas; competition from other energy sources such as
coal and nuclear energy; local, state and federal regulations regarding
production and the cost of complying with applicable environmental
regulations; and fluctuating seasonal supply and demand. For example,
the demand for natural gas is greater in the winter months than in the
summer months, which is reflected in a higher spot market price paid for
such gas. Also, increased imports of oil and natural gas have occurred
and are expected to continue. The free trade agreement between Canada
and the United States has eased restrictions on imports of Canadian gas
to the United States. Additionally, the passage in November, 1993, of
the North American Free Trade Agreement ("NAFTA") will have some impact
on the American gas industry by eliminating trade and investment
barriers in the United States, Canada and Mexico. In the past the
reduced demand for natural gas and/or an excess supply of gas has
resulted in a lower price paid for the gas. It has also resulted in some
purchasers curtailing or restricting their purchases of natural gas,
renegotiating existing contracts to reduce both take-or-pay levels and
the price paid for delivered gas, and other difficulties in the
marketing of production. (See "Proposed Activities - Sale of Oil and Gas
Production".)
The Federal Energy Regulatory Commission ("FERC") has sought to promote
greater competition in natural gas markets by encouraging open access
transportation by interstate pipelines, with the goal of expanding
opportunities for producers to contract directly with local distribution
companies and end-users. FERC Order No. 500 affects the transportation
and marketability of natural gas. Traditionally, natural gas has been
sold by producers to pipeline companies, which then resold the gas to
end-users. FERC Order No. 500 alters this market structure by requiring
interstate pipelines that transport gas for others to provide
transportation service to producers, distributors and all other shippers
of natural gas on a nondiscriminatory, "first-come, first-served" basis
("open access transportation"), so that producers and other shippers can
sell natural gas directly to end-users. FERC Order No. 500 contains
additional provisions intended to promote greater competition in natural
gas markets. FERC Order 636 which became effective May 18, 1992,
requires gas 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 gas
suppliers. The premise behind FERC Order 636 was that the gas pipeline
companies had an unfair advantage over other gas suppliers because they
could bundle their sales and transportation services together. FERC
Order 636 is designed to create a regulatory environment in which no gas
seller has a competitive advantage over another gas seller because it
also provides transportation services. It is difficult to assess the
effect of the order on the Partnership.
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". Atlas believes the
amendments ultimately will have a beneficial effect on natural gas
markets and prices.
STATE REGULATIONS
Oil and gas operations are regulated in Pennsylvania by the Department
of Environmental Resources, and any other states where Partnership Wells
may be situated impose a comprehensive statutory and regulatory scheme
with respect to oil and gas operations. Among other things, such
regulations involve (a) new well permit and well registration
requirements, procedures and fees, (b) minimum well spacing
requirements, (c) restrictions on well locations and underground gas
storage, (d) certain well site restoration, groundwater protection and
safety measures, (e) landowner notification requirements, (f) certain
bonding or other security measures, (g) various reporting requirements,
(h) well plugging standards and procedures, and (i) broad enforcement
powers.
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These state regulatory agencies have been granted broad regulatory and
enforcement powers which are likely to create additional financial and
operational burdens on oil and gas operations like those of the
Partnership in such states. Pennsylvania and the other states also have
in place other pollution and environmental control laws which have
become increasingly burdensome in recent years. Enforcement efforts with
respect to oil and gas operations have recently increased and it can be
anticipated that such regulation will expand and have a greater impact
on future oil and gas operations.
ENVIRONMENTAL REGULATION
Various federal, state and local laws covering the discharge of
materials into the environment, or otherwise relating to the protection
of the environment, may affect the Partnership's operations and costs.
The Partnership may generally be liable for cleanup costs to the United
States Government under the Federal Clean Water Act for oil or hazardous
substance pollution and under the Comprehensive Environmental Response,
Compensation and Liability Act of 1980 ("CERCLA" or Superfund) for
hazardous substance contamination. Such liability is unlimited in cases
of willful negligence or misconduct, and there is also no limit on
liability for environmental cleanup costs or damages with respect to
claims by the state or private persons or entities. In addition, the
Environmental Protection Agency will require the Partnership to prepare
and implement spill prevention control and countermeasure plans relating
to the possible discharge of oil into navigable waters and will further
require permits to authorize the discharge of pollutants into navigable
waters. State and local permits or approvals will also be needed with
respect to wastewater discharges and air pollutant emissions.
Violations of environment-related Lease conditions or environmental
permits can result in substantial civil and criminal penalties as well
as potential court injunctions curtailing operations. Such enforcement
liabilities can result from either governmental or citizen prosecution.
Compliance with these statutes and regulations may cause delays in
producing natural gas and oil from the wells and may substantially
increase the cost of producing such natural gas and oil. However, such
laws and regulations are constantly being revised and changed, and Atlas
is unable to predict the ultimate costs of complying with present and
future environmental laws and regulations. See "Risk Factors - Special
Risks of the Partnership - Unlimited Liability of Investor General
Partners" and "Proposed Activities - Insurance," concerning the Managing
General Partner's inability to obtain insurance to protect against
environmental claims.
CRUDE OIL REGULATION
The price of oil is not regulated and is subject only to supply, demand,
competitive factors, the gravity of the crude oil, sulfur content
differentials and other factors. Certain federal reporting requirements
are still in effect under U. S. Department of Energy regulations.
FEDERAL GAS REGULATION
The sale of natural gas is subject to regulation of production and
transportation by governmental regulatory agencies. Generally, the
regulatory agency in the state where a producing natural gas well is
located supervises production activities and the transportation of
natural gas sold into intrastate markets. FERC regulates the interstate
transportation of natural gas and pricing of natural gas sold for resale
interstate; and under the Natural Gas Policy Act of 1978 ("NGPA"), the
price of intrastate gas. However, price controls for natural gas
production from new wells were deregulated on December 31, 1992. Such
deregulated gas production may be sold at market prices determined by
supply, demand, BTU content, pressure, location of the wells, and other
factors. The Managing General Partner anticipates that all of the gas
produced by the Partnership Wells will be price decontrolled gas and
will be sold at fair market value.
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 oil and natural gas
industry. Such proposals involve, among other things, the imposition of
new taxes on natural gas and limiting the disposal of waste water from
wells. At the present time, it is impossible to accurately predict what
proposals, if any, will be enacted by Congress or the legislatures and
agencies of various states and what effect any proposals which are
enacted will have on the activities of the Partnership.
PARTICIPATION IN COSTS AND REVENUES
IN GENERAL
A tabular summary of the following discussion appears below. Please
refer to "Definitions" for a description of the items of revenue and
cost included in the terms used herein.
COSTS
1. ORGANIZATION AND OFFERING COSTS. Organization and Offering Costs
will be allocated and charged 100% to the Managing General Partner.
Notwithstanding, Organization and Offering Costs in excess of 15% of
the Partnership Subscription will be paid by the Managing General
Partner, without recourse to the Partnership, and the Managing
General Partner will not be credited with such amounts towards its
required Capital Contribution.
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<PAGE>81
2. LEASE COSTS. The Leases will be contributed to the Partnership by
the Managing General Partner at its Cost, unless the Managing General
Partner has cause to believe that Cost is materially more than fair
market value, in which case the credit for such contribution will be
made at a price not in excess of fair market value.
3. INTANGIBLE DRILLING COSTS AND TANGIBLE DRILLING COSTS.
Intangible Drilling Costs will be allocated and charged 100% to the
Participants. Tangible Costs will be allocated and charged 14% to
the Managing General Partner and 86% to the Participants. 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 will be charged 100% to the Participants who are
admitted to the Partnership in such closing and will 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, each Participant will pay
the same amount of such costs regardless of when he subscribes.
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 will be allocated
and charged 75% to the Participants and 25% to the Managing General
Partner. However, in the event Atlas has to subordinate a part of its
Partnership revenues in an amount up to 10% of the Partnership Net
Production Revenues, Operating Costs, Direct Costs, Administrative
Costs and all other Partnership costs not specifically allocated will
be charged to the parties in the same ratio as the related production
revenues are being credited. (See "- Subordination of Portion of
Managing General Partner's Net Revenue Share," below.)
In addition, the Managing General Partner's aggregate Capital
Contributions to the Partnership (including credit for the cost of
the Leases contributed) will not be less than 16.5% of all Capital
Contributions to the Partnership. Any payments by the Managing
General Partner in excess of the other costs charged to it under the
Partnership Agreement will be used to pay Partnership costs which
would otherwise be charged to the Participants. Such Capital
Contributions must be paid by the Managing General Partner at the
time such costs are required to be paid by the Partnership, but, in
no event, later than December 31, 1998.
REVENUES
1. PROCEEDS FROM THE SALE OF LEASES. If the Partners' Capital
Accounts are adjusted under the Partnership Agreement to reflect the
simulated depletion of an oil or gas property of the Partnership, the
portion of the total amount realized by the Partnership upon the
taxable disposition of such property that represents recovery of its
simulated tax basis therein is allocated to the Partners in the same
proportion as the aggregate adjusted tax basis of such property was
allocated to such Partners (or their predecessors in interest). If
the Partners' Capital Accounts are adjusted under the Partnership
Agreement to reflect the actual depletion of an oil or gas property
of the Partnership, the portion of the total amount realized by the
Partnership upon the taxable disposition of such property that equals
the Partners' aggregate remaining adjusted tax basis therein is
allocated to the Partners in proportion to their respective remaining
adjusted tax bases in such property. In addition, proceeds will be
allocated to Atlas to the extent of the pre-contribution appreciation
in value of such property, if any. Any excess will be credited to the
parties in the ratio in which oil and gas production revenues of the
Partnership are credited as provided in 4, below.
2. INTEREST PROCEEDS. Interest earned on Agreed Subscriptions up
until the Offering Termination Date will be credited to the accounts
of the respective subscribers and paid approximately eight weeks
after the Offering Termination Date. If a subscription is refunded
any interest allocated thereto will also be refunded. After the
Offering Termination Date and until proceeds from the offering are
invested in the Partnership's oil and gas operations any interest
income from temporary investments will be allocated pro rata to the
Participants providing such Agreed Subscription. 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 such equipment in the ratio in which such costs were charged.
4. PRODUCTION REVENUES. All other revenues of the Partnership,
including production revenues, will be credited 75% to the
Participants and 25% to the Managing General Partner. (See "-
Subordination of Portion of Managing General Partner's Net Revenue
Share," below and "Tax Aspects".)
5. LIQUIDATION PROCEEDS. Upon liquidation of the Partnership each
Participant will receive his Distribution Interest in the
Partnership. "Distribution Interest" means an undivided interest in
the assets of the Partnership after payments to creditors of the
Partnership or the creation of a reasonable reserve therefor, in the
ratio the positive balance of a party's Capital Account bears to the
aggregate positive balance of the Capital Accounts of all of the
parties determined after taking into account all Capital Account
adjustments for the taxable year during which liquidation occurs
(other than those made pursuant to liquidating distributions or
restoration of deficit Capital Account balances); provided, however,
after the Capital Accounts of all of the parties have been reduced to
zero, such interest in the remaining assets of the Partnership will
equal a party's interest in the related revenues of the Partnership
as set forth in 5.01 and its subsections of the Partnership
Agreement.
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<PAGE>82
Any in kind property distributions to the Participants must be made to a
liquidating trust or similar entity for the benefit of the Participants,
unless at the time of the distribution:
(a) the Managing General Partner offers the individual
Participants the election of receiving in kind property
distributions and the Participants accept such offer after
being advised of the risks associated with such direct
ownership; or
(b) 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 the
Partnership properties.
It will be presumed that a Participant has refused such consent if the
Managing General Partner has not received such consent within thirty
days after the Managing General Partner mailed the request for such
consent. Any Partnership asset which would otherwise be distributed in
kind to a Participant, but for the failure or refusal of such
Participant to give his written consent to such 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.
SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET REVENUE SHARE
The Partnership is structured to provide preferred cash distributions to
the Participants equal to a minimum of 10% of their Agreed Subscriptions
in each of the first five twelve-month periods of Partnership
operations. To help insure the Participants achieve this investment
feature, Atlas will subordinate a part of its Partnership revenues in an
amount up to 10% of the Partnership Net Production Revenues to the
receipt by Participants of cash distributions from the Partnership equal
to 10% of their Agreed Subscriptions in each of the first five twelve-
month periods of Partnership operations. (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.) The subordination will be determined
commencing with the first distribution of revenues to the Participants
by debiting or crediting current period Partnership revenues to the
Managing General Partner as may be necessary to provide such
distributions to the Participants. See 5.01(b)(4) of the Partnership
Agreement for details on the subordination.
Atlas anticipates that the Participants will benefit from the
subordination if the price of gas received by the Partnership and/or the
results of the Partnership's drilling activities are unable to provide
the required return to the Participants. Notwithstanding, if the wells
produce gas in small amounts and/or the price of gas declines then even
with subordination the cash flow to the Participants may be very small
and they may not receive a return of their entire investment. (See
"Risk Factors - Special Risks of the Partnership - Borrowings by the
Managing General Partner Could Reduce Funds Available for Its
Subordination Obligation".)
PARTICIPATION IN COSTS AND REVENUES
The following table sets forth the participation in costs and revenues
of the Partnership between the Managing General Partner and the
Participants. Gross revenues from the sale of the Partnership's gas
will be reduced by Landowner Royalties and any other burdens on the
Leases. (See "Proposed Activities - Interests of Parties" and
"Definitions".)
MANAGING
GENERAL
PARTNERSHIP COSTS
Organization and Offering Costs (2) 100% 0%
Lease Costs (3) 100% 0%
Intangible Drilling Costs (4) 0% 100%
Tangible Costs 14% 86%
Operating Costs, Administrative Costs,
Direct Costs and All
Other Costs (5)(6)(10) 25% 75%
PARTNERSHIP REVENUES
Interest Income (7) (7)
Equipment Proceeds (8) (8)
All other Revenues including
Production Revenues (5)(9)(11) 25% 75%
PARTICIPATION IN DEDUCTIONS
Intangible Drilling Costs 0% 100%
Depreciation 14% 86%
Depletion Allowances 25% 75%
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<PAGE>83
(1) Atlas and its Affiliates have the option of subscribing for up to
10% of the Units, which will not be applied towards the minimum
Partnership Subscription. To the extent of such optional
subscriptions the Managing General Partner and its Affiliates are
deemed Participants in the Partnership. (See "Terms of the
Offering".)
(2) In the event the Managing General Partner pays any Organization and
Offering Costs in excess of 15% of the Partnership Subscription,
such payments will be without recourse to the Partnership, and the
Managing General Partner will not be credited with such amounts
towards its required Capital Contribution.
(3) Leases will be contributed to the Partnership by the Managing
General Partner at its Cost, unless the Managing General Partner has
cause to believe that Cost is materially more than fair market
value, in which case the credit for such contribution will be made
at a price not in excess of fair market value, and applied towards
its required Capital Contribution to the Partnership.
(4) More specifically, 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 will be charged
100% to the Participants who are admitted to the Partnership in such
closing and will 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,
each Participant will pay the same amount of such costs regardless
of when he subscribes.
(5) In the event Atlas has to subordinate a part of its Partnership
revenues in an amount up to 10% of Partnership Net Production
Revenues, then Operating Costs, Direct Costs, Administrative Costs
and all other Partnership costs not specifically allocated will be
charged to the parties in the same ratio as the related production
revenues are being credited. (See "- Subordination of a Portion of
Managing General Partner's Net Revenue Share," above and "Risk
Factors - Special Risks of the Partnership - Borrowings by the
Managing General Partner Could Reduce Funds Available for Its
Subordination Obligation".)
(6) Includes any other Partnership costs which are not otherwise
specifically allocated.
(7) Interest earned on Agreed Subscriptions up until the Offering
Termination Date will be credited to the accounts of the respective
subscribers and paid approximately eight weeks after the Offering
Termination Date. If a subscription is refunded any interest
allocable thereto will also be refunded. After the Offering
Termination Date and until proceeds from the offering are invested
in the Partnership's oil and gas operations any interest income from
temporary investments will be allocated pro rata to the Participants
providing such Agreed Subscription. All other interest income,
including interest earned on the deposit of operating revenues, will
be credited as oil and gas production revenues are credited.
(8) Proceeds from the sale or other disposition of equipment will be
credited to the parties charged with the costs of such equipment in
the ratio in which such costs were charged.
(9) (See "- Revenues - Proceeds from the Sale of Leases" and "-
Subordination of Portion of Managing General Partner's Net Revenue
Share," above and "- Allocation and Adjustment Among Participants,"
below.)
(10) The Managing General Partner's aggregate Capital Contributions to
the Partnership (including Leases contributed) will not be less than
16.5% of all Capital Contributions to the Partnership. Any payments
by the Managing General Partner in excess of the other costs charged
to it under the Partnership Agreement will be used to pay
Partnership costs which would otherwise be charged to the
Participants. Such Capital Contributions must be paid by the
Managing General Partner at the time such costs are required to be
paid by the Partnership, but, in no event, later than December 31,
1998.
(11) 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.
Sales proceeds of Leases are subject to special provisions. (See "-
Revenues - Proceeds from the Sale of Leases", above.)
ALLOCATION AND ADJUSTMENT AMONG PARTICIPANTS
The Participants' share of revenues, gains, credits, costs, expenses,
losses and other charges and liabilities will be charged and credited,
as among them, pro rata in accordance with their respective Agreed
Subscriptions taking into account any Investor General Partner's status
as a defaulting Investor General Partner. (See "Summary of the
Offering - Actions to be Taken by Managing General Partner to Reduce
Risks of Additional Payments by Investor General Partners" and
"Capitalization and Source of Funds and Use of Proceeds".)
Subscription proceeds from each Partnership closing generally will be
used to drill different wells. However, production revenues from all
Partnership Wells will be commingled and the Participants' share of
such revenues will be allocated among all Participants in accordance
with their Agreed Subscriptions regardless of which wells were paid for
by the respective Participants. (See 5.01 of the Partnership
Agreement.)
DISTRIBUTIONS
The Managing General Partner will review the accounts of the Partnership
at least quarterly to determine whether cash distributions are
appropriate and the amount to be distributed, if any. The Partnership
will distribute funds to the Managing General Partner and the
Participants allocated to their accounts which the Managing General
Partner deems unnecessary to be retained by the Partnership. In no
event, however, will funds be advanced or borrowed for purposes of
distributions, if the amount of such distributions would exceed the
Partnership's accrued and received revenues for the previous four
quarters, less paid and accrued Operating Costs with respect to such
revenues. The determination of such revenues and costs shall be made in
accordance with generally accepted accounting principles, consistently
applied. Cash distributions from the Partnership to the Managing General
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<PAGE>84
Partner shall only be made in conjunction with distributions to
Participants and only out of funds properly allocated to the Managing
General Partner's account. (See "Summary of Drilling and Operating
Agreement.")
TAX ASPECTS
SUMMARY OF TAX OPINION
The Managing General Partner has received the tax opinion of Special
Counsel, Kunzman & Bollinger, Inc., Oklahoma City, Oklahoma, which is
included as Exhibit (8) to the Registration Statement. While Special
Counsel has prepared this section of the Prospectus entitled "Tax
Aspects," the opinion of Special Counsel will be limited to those
opinions set forth in its Tax Opinion which are summarized below. The
Tax Opinion represents only Special Counsel's best legal judgment, and
has no binding effect or official status. No assurance can be given that
the conclusions expressed in the opinion would be upheld by a court if
challenged by the IRS. Such tax opinion is based upon Special Counsel's
review of the Registration Statement for Atlas-Energy for the
Nineties-Public #6 Ltd., corporate records, certificates, agreements,
instruments and other documents, existing statutes, rulings and
regulations (which are subject to change and could result in different
tax consequences), and certain representations from Atlas. Included
among such representations are the following:
(1) The Partnership Agreement will be duly executed and recorded.
(2) No election will be made for the Partnership to be excluded from
the application of the partnership provisions of the Code or
classified as a corporation for tax purposes.
(3) The Partnership will own record or legal title to the Working
Interest in all of its Prospects.
(4) The respective amounts that will be paid to Atlas or its
Affiliates pursuant to the Partnership Agreement and the Drilling
and Operating Agreement are amounts that would ordinarily be paid
for similar services in similar transactions between Persons
having no affiliation and dealing with each other "at arms'
length."
(5) The Partnership will elect to deduct currently all intangible
drilling and development costs.
(6) The Partnership will have a calendar year taxable year.
(7) The Drilling and Operating Agreement and any amendments thereto
entered into by and between Atlas and the Partnership will be duly
executed and will govern the drilling and, if warranted, the
completion and operation of the wells in accordance with its
terms.
(8) Based upon Atlas' review of its previous drilling programs for the
past several years and upon the intended operations of the
Partnership, Atlas reasonably believes that the aggregate
deductions, including depletion deductions, and 350% of the
aggregate credits, if any, which will be claimed by Atlas and the
Participants, will not during the first five tax years following
the funding of the Partnership exceed twice the amounts invested
by Atlas and the Participants, respectively.
(9) The Investor General Partner Units will not be converted to
Limited Partner interests before substantially all of the
Partnership Wells have been drilled and completed.
(10) The Units will not be traded on an established securities market.
In rendering its opinions, Special Counsel has further assumed that (1)
each of the Participants has an objective to carry on the business of
the Partnership for profit; (2) any amount borrowed by a Participant and
contributed to the Partnership will not be borrowed from a Person who
has an interest in the Partnership (other than as a creditor) or a
related person, as defined in 465 of the Code, to a person (other than
the Participant) having such interest and such Participant will be
severally, primarily, and personally liable for such amount, and (3) no
Participant will have protected himself from loss for amounts
contributed to the Partnership through nonrecourse financing,
guarantees, stop loss agreements or other similar arrangements.
Special Counsel believes that its opinion letter addresses all material
federal income tax issues associated with an investment in the Units by
an individual Participant who is a resident citizen of the United
States. Special Counsel considers material those issues which would
affect significantly a Participant's deductions, credits or losses
arising from his investment in the Units and with respect to which,
under present law, there is a reasonable possibility of challenge by the
IRS, or those issues which are expected to be of fundamental importance
to a Participant but as to which a challenge by the IRS is unlikely. The
issues which involve a reasonable possibility of challenge by the IRS
have not been definitely resolved by statute, rulings or regulations, as
interpreted by judicial or administrative bodies. Subject to the
foregoing, however, in Special Counsel's opinion it is more likely than
not that the following tax treatment will be upheld if challenged by the
IRS and litigated.
PARTNERSHIP CLASSIFICATION. The Partnership will be classified as a
partnership for federal income tax purposes, and not as an association
taxable as a corporation; the Partnership, as such, will not pay any
federal income taxes; and all items of income, gain, loss, deduction,
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<PAGE>85
and credit of the Partnership will be reportable by the Partners in the
Partnership. (See "- Partnership Classification".)
INTANGIBLE DRILLING AND DEVELOPMENT COSTS. Intangible drilling and
development costs ("Intangible Drilling Costs") paid by the Partnership
under the terms of bona fide drilling contracts for the Partnership's
wells will be deductible in the taxable year in which the payments are
made and the drilling services are rendered, assuming such amounts are
fair and reasonable consideration and subject to certain restrictions
summarized below (including basis and "at risk" limitations and the
passive activity loss limitation with respect to the Limited Partners).
(See "- Intangible Drilling and Development Costs" and "- Drilling
Contracts".)
PREPAYMENTS OF INTANGIBLE DRILLING AND DEVELOPMENT COSTS. Depending
primarily on when the Partnership Subscription is received, it is
anticipated that the Partnership will prepay in 1997 most, if not all,
of the intangible drilling and development costs related to Partnership
Wells the drilling of which will be commenced in 1998. Assuming that
such amounts are fair and reasonable, and based in part on the factual
assumptions set forth below, in our opinion such prepayments of
intangible drilling and development costs will be deductible for the
1997 taxable year even though all Working Interest owners in the well
may not be required to prepay such amounts, subject to certain
restrictions summarized in "Tax Aspects" (including basis and "at risk"
limitations, and the passive activity loss limitation with respect to
the Limited Partners). (See "- Drilling Contracts," below.)
The foregoing opinion is based in part on the assumptions that: (1) such
costs will be required to be prepaid in 1997 for specified wells
pursuant to the Drilling and Operating Agreement; (2) pursuant to the
Drilling and Operating Agreement the wells are required to be, and
actually are, Spudded on or before March 31, 1998, and continuously
drilled thereafter until completed, if warranted, or abandoned; and (3)
the required prepayments are not refundable to the Partnership and any
excess prepayments are applied to intangible drilling and development
costs of substitute wells.
NOT A PUBLICLY TRADED PARTNERSHIP. Assuming that no more than 10% of the
Units are transferred in any taxable year of the Partnership (other than
in private transfers described in Treas. Reg. 1.7704-1(e), it is more
likely than not that the Partnership will not be treated as a "publicly
traded partnership" under the Code. (See "- Limitations on Passive
Activities".)
PASSIVE ACTIVITY CLASSIFICATION. Oil and gas production income generated
by the Partnership's oil and gas properties held as Working Interests,
together with gain, if any, from the disposition of such properties and
allocable to Limited Partners who are individuals, estates, trusts,
closely held corporations or personal service corporations more likely
than not will be characterized as income from a passive activity which
may be offset by passive activity losses. Income or gain attributable to
investments of working capital of the Partnership will be characterized
as portfolio income, which cannot be offset by passive activity losses.
To the extent the Partnership's oil and gas properties are held as
Working Interests, it is more likely than not that the passive activity
limitations on losses under 469 will not be applicable to Investor
General Partners prior to the conversion of Investor General Partner
Units to Limited Partner interests. (See "- Limitations on Passive
Activities".)
TAX BASIS OF PARTICIPANT'S INTEREST. Each Participant's adjusted tax
basis in his Partnership interest will be increased by his total Agreed
Subscription. (See "- Tax Basis of Participants' Interests".)
AT RISK LIMITATION ON LOSSES. Each Participant initially will be "at
risk" to the full extent of his Agreed Subscription. (See "- `At Risk'
Limitation For Losses".)
DEPLETION ALLOWANCE, The greater of cost depletion or percentage
depletion will be available to qualified Participants as a current
deduction against Partnership income from oil and gas production
revenues on properties of the Partnership, subject to certain
restrictions summarized below. (See "- Depletion Allowance".)
ACRS. The Partnership's reasonable costs for recovery property (tangible
depreciable property used in a trade or business or held for the
production of income) which cannot currently be deducted but must be
capitalized will be eligible for cost recovery deductions under the
modified Accelerated Cost Recovery System, generally over a seven year
"cost recovery period," subject to certain restrictions summarized below
(including basis and "at risk" limitations and the passive activity loss
limitation in the case of the Limited Partners). (See "- Depreciation -
Accelerated Cost Recovery System".)
AVAILABILITY OF CERTAIN DEDUCTIONS. Business expenses, including
payments for personal services actually rendered in the taxable year in
which accrued, which are reasonable, ordinary and necessary and do not
include amounts for items such as Lease acquisition costs, organization
and syndication fees and other items which are required to be
capitalized, are currently deductible. (See "-1997 Expenditures," "-
Availability of Certain Deductions" and "- Partnership Organization and
Syndication Fees".)
ALLOCATIONS. Assuming the effect of the allocations of income, gain,
loss, deduction and credit (or items thereof) set forth in the
Partnership Agreement, including the allocations of basis and amount
realized with respect to oil and gas properties, is substantial in light
of a Participant's tax attributes that are unrelated to the Partnership,
it is more likely than not that such allocations will have "substantial
economic effect" and will govern each Participant's distributive share
of such items to the extent such allocations do not cause or increase
deficit balances in the Participants' Capital Accounts. (See "-
Allocations".)
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<PAGE>86
AGREED SUBSCRIPTION. No gain or loss will be recognized by the
Participants on payment of their Agreed Subscriptions.
PROFIT MOTIVE. Based on the Managing General Partner's representation
that the Partnership will be conducted as described in the Prospectus,
it is more likely than not that the Partnership will possess the
requisite profit motive and will not be properly characterized as a tax
shelter for purposes of the tax shelter registration requirement. (See
"- Disallowance of Deductions Under Section 183 of the Code".)
IRS ANTI-ABUSE RULE. Based on the Managing General Partner's
representation that the Partnership will be conducted as described in
the Prospectus, it is more likely than not that the Partnership will not
be subject to the anti-abuse rule set forth in Treas. Reg. 1.701-2.
(See "- IRS Anti-Abuse Rule".)
OVERALL EVALUATION OF TAX BENEFITS. Based on Special Counsel's
conclusion that substantially more than half of the material tax
benefits of the Partnership, in terms of their financial impact on a
typical investor, more likely than not will be realized if challenged by
the IRS, the tax benefits of the Partnership, in the aggregate, which
are a significant feature of an investment in the Partnership by a
typical original Participant more likely than not will be realized as
contemplated by the Prospectus.
IN GENERAL
The following is a summary of some of the principal features under
present federal income tax law which will apply to the Partnership and
typical Participants. However, there is no assurance that the present
laws or regulations will not be changed and adversely affect a
Participant. The IRS may challenge the deductions claimed by the
Partnership or a Participant, or the taxable year in which such
deductions are claimed, and no guaranty can be given that any such
challenge would not be upheld if litigated. The practical utility of the
tax aspects of any investment depends largely on the income tax position
of the particular Participant 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, except as
otherwise noted, different tax considerations may apply to foreign
persons, corporations, partnerships, trusts and other prospective
Participants which are not treated as individuals for federal income tax
purposes. EACH PROSPECTIVE PARTICIPANT SHOULD SATISFY HIMSELF AS TO THE
TAX CONSEQUENCES OF PARTICIPATING IN THE PARTNERSHIP BY OBTAINING ADVICE
FROM HIS OWN TAX ADVISOR.
PARTNERSHIP CLASSIFICATION
For federal income tax purposes, a partnership is not a taxable entity
but rather a conduit through which all items of income, gain, loss,
deduction, credit and tax preference are passed through to the partners
and are required to be reported on their federal income tax returns for
the taxable years in which or with which the partnership's taxable year
ends. The Managing General Partner has received the opinion of Special
Counsel that, under currently existing laws, rules and regulations, all
of which are subject to change with or without retroactive application,
the Partnership will be treated as a partnership for federal income tax
purposes and not as an association taxable as a corporation. Under new
regulations a business entity with two or more members is classified
for federal tax purposes as either a corporation or a partnership.
Treas. Reg. 301.7701-2(a). The term corporation includes a business
entity organized under a State statute which describes the entity as a
corporation, body corporate, body politic, joint-stock company or
joint-stock association. Treas. Reg. 301.7701-2(b). The Partnership
was formed under the Pennsylvania Revised Uniform Limited Partnership
Act which describes the Partnership as a "partnership". Consequently,
the Partnership is not required to be classified as a corporation under
Treas. Reg. 301.7701-2(b) and will be automatically classified as a
partnership unless it affirmatively elects to be classified as a
corporation. In this regard, the Managing General Partner has
represented that no election for the Partnership to be classified as a
corporation will be filed with the IRS.
LIMITATIONS ON PASSIVE ACTIVITIES
Under the passive activity rules, all income of a taxpayer who is
subject to the rules is categorized as: (i) income from passive
activities such as limited partners' interests in a business; (ii)
active income (e.g., salary, bonuses, etc.); or (iii) portfolio income
(e.g., dividends, royalties and interest not derived 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.
Passive activities include any trade or business in which the taxpayer
does not materially participate. Material participation is defined as
involvement in the operations of the activity on a regular, continuous,
and substantial basis. Under the Partnership Agreement, Limited Partners
will not have material participation in the Partnership and generally
will be subject to the passive activity rules.
A taxpayer who holds a working interest in an oil and gas property that
is burdened with the cost of developing and operating the property is
excepted from the passive activity rules, whether or not he materially
participates in the activity. However, a taxpayer who holds a working
interest directly or indirectly through an entity (e.g., a limited
partnership interest or S corporation shares) which limits the liability
of the taxpayer with respect to such interest is not treated as owning a
working interest. Consequently, the exception is not available to
Limited Partners in the Partnership, but more likely than not the
exception will be available to Investor General Partners prior to their
conversion to Limited Partners to the extent the Partnership acquires
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<PAGE>87
Working Interests in its Leases, except as noted above. Contractual
limitations on the liability of Investor General Partners under the
Partnership Agreement (e.g. insurance, limited indemnification, etc.)
will not prevent Investor General Partners from claiming deductions
under the working interest exception to the passive activity rules.
Suspended losses and credits may be carried forward (but not back) and
used to offset future years' passive activity income. A suspended loss
(but not a credit) is allowed in full when the entire interest is sold
to an unrelated third party in a taxable transaction. Upon such
disposition the excess of suspended losses and any loss from the
activity for the tax year (plus any loss on the sale) over net income or
gain for the tax year from all passive activities (determined without
regard to such losses) is not treated as a passive loss. Capital losses
are limited to the amount of capital gain, plus $3,000 (in the case of
married individuals filing joint returns).
Net losses and credits of a partner from each publicly traded
partnership are suspended and carried forward to be netted against
income from that publicly traded partnership only. In addition, net
losses from other passive activities may not be used to offset net
income from a publicly traded partnership. However, it is more likely
than not that the Partnership will not be characterized as a publicly
traded partnership under the Code so long as no more than 10% of the
Units are transferred in any taxable year of the Partnership (other than
in private transfers described in Treas. Reg 1.7704-1(e)).
CHARACTERIZATION OF THE PARTNERSHIP'S INCOME. Income (e.g., interest)
earned on working capital is treated as portfolio income which cannot be
offset with passive losses by Limited Partners. "Portfolio income"
consists of (i) interest, dividends and royalties (unless earned in the
ordinary course of a trade or business); and (ii) gain or loss not
derived in the ordinary course of a trade or business on the sale of
property that generates portfolio income or is held for investment.
In the opinion of Special Counsel, it is more likely than not that the
Partnership's income from the Leases (excluding income attributable to
investment of working capital), held as Working Interests, together with
gain, if any, from the disposition of such property, will be
characterized as passive income rather than portfolio income with
respect to Limited Partners subject to the passive activity limitations.
CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER. Investor
General Partner Units will be converted to Limited Partner interests
after substantially all of the Partnership Wells have been drilled and
completed, which is anticipated to be in the late summer of 1998.
Thereafter, each Investor General Partner will be deemed a Limited
Partner in the Partnership and will enjoy the limited liability provided
to limited partners under the Revised Uniform Limited Partnership Act of
Pennsylvania with respect to his interest in the Partnership's oil and
gas properties.
Concurrently, the Investor General Partner will lose the availability of
the working interest exception to the passive activity limitations.
Except as provided below, an Investor General Partner's conversion of
his Partnership interest into a Limited Partner interest should not have
adverse tax consequences unless the Investor General Partner's 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 such partner, which reduces the
basis of the partner's interest in the partnership and is taxable to the
extent it exceeds such basis.
In addition, any net income from a Partnership Well allocable to an
Investor General Partner will continue to be characterized as
non-passive income which cannot be offset with passive losses, even
after such Investor General Partner has converted to Limited Partner
status.
TAXABLE YEAR
The Partnership intends to adopt a calendar year taxable year.
1997 EXPENDITURES
It is anticipated that all of the Partnership's subscription proceeds
will be expended in 1997 and that the income and deductions generated
pursuant thereto will be reflected on the Participants' federal income
tax returns for that period. (See "Capitalization and Source of Funds
and Use of Proceeds" and "Participation in Costs and Revenues".)
Depending primarily on when the Partnership Subscription is received, it
is anticipated that the Partnership will prepay in 1997 most, if not
all, of the intangible drilling and development costs for wells the
drilling of which will be commenced in 1998. The deductibility in 1997
of such advance payments cannot be guaranteed. (See "- Drilling
Contracts," below.)
AVAILABILITY OF CERTAIN DEDUCTIONS
The ordinary and necessary expenses of carrying on any trade or
business, including a reasonable allowance for salaries or other
compensation for personal services actually rendered, are deductible in
the year incurred. The Managing General Partner has represented to
counsel that the amounts payable to the Managing General Partner and its
Affiliates, including the amounts paid to Atlas or its Affiliates as
general drilling contractor, are the amounts which would ordinarily be
paid for similar services in similar transactions. (See "- Drilling
Contracts," below.) The fees paid to the Managing General Partner and
its Affiliates will not be currently deductible to the extent it is
determined that they are in excess of reasonable compensation, are
properly characterized as organization or syndication fees, other
capital costs such as the acquisition cost of the Leases, or not
"ordinary and necessary" business expenses, or the services were
rendered in tax years other than the tax year in which such fees were
deducted by the Partnership. (See "- Partnership Organization and
Syndication Fees," below.) In the event of an audit, payments to the
Managing General Partner and its Affiliates by the Partnership will be
scrutinized by the IRS to a greater extent than payments to an unrelated
party.
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<PAGE>88
INTANGIBLE DRILLING AND DEVELOPMENT COSTS
Assuming a proper election and subject to the passive activity loss
rules in the case of Limited Partners, each Participant will be entitled
to deduct his share of intangible drilling and development costs
("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. (See "Participation in Costs and
Revenues" and "- Limitations on Passive Activities," above.) Such costs
generally will be subject to ordinary income recapture if a property is
sold at a gain and the amount to be recaptured is not reduced by the
amount of additional depletion that could have been claimed if such
costs had been capitalized and amortized. (See "- Sale of the
Properties," below.) The amount of the deduction for intangible drilling
and development costs is limited for integrated oil companies, i.e., (i)
those taxpayers who directly or through a related person engage in the
retail sale of oil or gas and whose gross receipts for the calendar year
from such activities exceed $5,000,000, or (ii) those taxpayers and
related persons who have refinery production in excess of 50,000 barrels
on any day during the taxable year. Also, productive-well intangible
drilling and development costs may subject a Participant to an
alternative minimum tax in excess of regular tax unless an election is
made to deduct them on a straight line basis over a 60 month period.
(See "- Minimum Tax - Tax Preferences," below.)
In the preparation of the Partnership's informational tax returns, Atlas
will allocate Partnership costs paid by Atlas and the Participants among
Intangible Drilling Costs, Tangible Costs, Direct Costs, Administrative
Costs, Organization and Offering Costs and Operating Costs based upon
guidance from advisors to Atlas. Atlas has allocated approximately 77%
of the footage price to be paid by the Partnership for a completed well
in the Appalachian Basin to intangible drilling and development costs.
The IRS could challenge the characterization of costs claimed by the
Partnership to be deductible intangible drilling and development costs
and recharacterize such costs as some other item which may be
non-deductible; however, this would have no effect on the allocation and
payment of such costs under the Partnership Agreement. Where a Lease is
acquired subject to an obligation to pay an excessive drilling price,
such excess amounts may not qualify as deductible intangible drilling
and development costs but may be treated as Lease acquisition costs or
some other non-deductible expense.
DRILLING CONTRACTS
The Partnership will enter into the Drilling and Operating Agreement
with Atlas or its Affiliates, as a third-party general drilling
contractor, to drill and complete the Partnership's Development Wells on
a footage basis of $37.39 per foot for each well that is drilled and
completed in the Appalachian Basin, and at a competitive rate for wells,
if any, drilled in other areas of the United States. Under the footage
drilling contracts for wells situated in the Mercer County area of the
Appalachian Basin, Atlas anticipates that it will have reimbursement of
general and administrative overhead of $3,600 per well and a profit of
approximately 15% per well assuming the well is drilled to 6,150 feet.
However, the actual cost of the drilling of the wells may be more or
less than the estimated amount, due primarily to the uncertain nature of
drilling operations. Atlas believes the Drilling and Operating Agreement
is at competitive rates in the proposed areas of operation.
Nevertheless, the amount of the profit realized by Atlas under the
drilling contract, if any, could be challenged by the IRS as
unreasonable and disallowed as a deductible intangible drilling and
development cost. (See "- Intangible Drilling and Development Costs,"
above, "Proposed Activities" and "Compensation".)
Depending primarily on when the Partnership Subscription is received, it
is anticipated that the Partnership will prepay in 1998 most, if not
all, of the intangible drilling and development costs for Partnership
Wells the drilling of which will be commenced in 1998. In , 79 T.C. 7
(1982), . 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: (1) the expenditure must be a payment
rather than a refundable deposit; and (2) the deduction must not result
in a material distortion of income taking into substantial consideration
the business purpose aspects of the transaction. The Partnership will
attempt to comply with the guidelines set forth in with respect to any
prepaid intangible drilling and development costs. The Drilling and
Operating Agreement will require the Partnership to prepay in 1997
intangible drilling and development costs for specified wells the
drilling of which will be commenced in 1998. Although the Partnership is
not required to prepay completion costs of a well prior to the time a
decision has been made to complete the well, it is anticipated that all
Partnership Wells will be required to be completed before an evaluation
can be made as to their potential productivity. Prepayments should not
result in a loss of current deductibility where there is a legitimate
business purpose for the required prepayment, the contract is not merely
a sham to control the timing of the deduction and there is an
enforceable contract of economic substance. The Drilling and Operating
Agreement will require the Partnership to prepay the intangible drilling
and development costs of the wells in order to enable the Operator to
commence site preparation for the wells, obtain suitable subcontractors
at the then current prices and insure the availability of equipment and
materials. Under the Drilling and Operating Agreement excess prepaid
amounts, if any, will not be refundable to the Partnership but will be
applied to intangible drilling and development costs to be incurred in
drilling substitute wells. Under , such a provision for substitute
wells should not result in the prepayments being characterized as
refundable deposits.
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<PAGE89
The likelihood that prepayments will be challenged by the IRS on the
grounds that there is no business purpose for the prepayment is
increased in the event prepayments are not required with respect to 100%
of the Working Interest. It is possible that less than 100% of the
Working Interest will be acquired by the Partnership in one or more
wells and prepayments may not be required of all holders of the Working
Interest. However, in the view of Special Counsel, a legitimate business
purpose for the required prepayments may exist under the guidelines set
forth in , even though prepayment is not required, or actually received,
by the drilling contractor with respect to a portion of the Working
Interest.
In addition to the foregoing, a current deduction for prepaid intangible
drilling and development costs is available only if the drilling of the
wells is commenced before the close of the 90th day after the close of
the taxable year. The Managing General Partner will attempt to cause
prepaid Partnership Wells to be Spudded on or before March 31, 1998.
However, the Spudding of any Partnership Well may be delayed due to
circumstances beyond the control of the Partnership or the drilling
contractor. Such circumstances include the unavailability of drilling
rigs, weather conditions, inability to obtain drilling permits or access
right to the drilling site, or title problems. Due to the foregoing
factors, no guaranty can be given that all prepaid Partnership Wells
required by the Drilling and Operating Agreement to be Spudded on or
before March 31, 1998, will actually be commenced by such date. In that
event, deductions claimed in 1997 for prepaid intangible drilling and
development costs would be disallowed and deferred to the 1998 taxable
year.
No assurance can be given that on audit the IRS will not disallow the
current deductibility of a portion or all of any prepayments of
intangible drilling and development costs under the Partnership's
drilling contracts, thereby decreasing the amount of deductions
allocable to the Participants for the current taxable year, or that such
a challenge would not ultimately be sustained. In the event of
disallowance, the deduction will be available in the year the work is
actually performed.
DEPLETION ALLOWANCE
Proceeds from the sale of oil and gas production will constitute
ordinary income. A certain portion of such income will not be taxable by
virtue of 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.
Cost depletion for any year is determined by dividing the adjusted tax
basis for the property by the total units of gas or oil expected to be
recoverable therefrom and then multiplying the resultant quotient by the
number of units actually sold during the year. Cost depletion cannot
exceed the adjusted tax basis of the property to which it relates.
Percentage depletion generally is available to taxpayers other than
integrated oil companies. (See "- Intangible Drilling and Development
Costs," above.) Percentage depletion generally is based on the
Participant's share of gross income from the oil and gas producing
property. Generally, percentage depletion is available with respect to 6
million cubic feet of average daily production of natural gas or 1,000
barrels of average daily production of domestic crude oil. 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 oil and gas 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
(90 MCF of natural gas) per producing well on the property in the
calendar year. The rate of percentage depletion for marginal production
presently is 16%. (See the model decline curve included in the UEDC
Geological Report in "Proposed Activities - Information Regarding
Currently Proposed Prospects".)
Also, percentage depletion may not exceed 100% of the net income from
each oil and gas property before the deduction for depletion and is
limited to 65% of the taxpayer's taxable income for a year computed
without regard to deductions for percentage depletion, net operating
loss carrybacks and capital loss carrybacks. With respect to marginal
properties, however, the 100% of net income property limitation is
suspended for 1998 and 1999. On disposition of an oil and gas property
there is recapture of the lesser of: (i) the amounts that were deducted
as intangible drilling and development costs rather than added to basis,
plus depletion deductions that reduced the basis of the property; or
(ii) the amount realized in the case of a sale, exchange or involuntary
conversion or fair market value in all other cases, minus the property's
adjusted basis.
Availability of percentage depletion must be computed separately for
each Participant and not by the Partnership, or for Participants as a
whole. Potential Participants are urged to consult their own tax
advisors with respect to the availability of percentage depletion to
them.
DEPRECIATION - ACCELERATED COST RECOVERY SYSTEM
Tangible Costs and the related depreciation deductions are allocated and
charged under the Partnership Agreement 14% to the Managing General
Partner and 86% to the Participants. The cost of most equipment placed
in service by the Partnership 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. Only a half-year of depreciation is allowed for the year
recovery property is placed in service or disposed of and in the case of
a short tax year, the ACRS deduction is prorated on a 12-month basis.
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<PAGE>90
No distinction is made between new and used property and salvage value
is disregarded. An alternative depreciation system is used to compute
the depreciation preference subject to the alternative minimum tax
(using the 150% declining balance method, switching to straight-line,
for most personal property). (See "- Minimum Tax - Tax Preferences,"
below.) A taxpayer may elect to recover the cost of assets using the
straight-line method or the alternative depreciation system for regular
tax purposes to avoid creating a tax preference. All gain on a
disposition of tangible personal property is treated as ordinary income
to the extent of ACRS deductions claimed by the taxpayer and deductions
allowed under 179 of the Code, which provides an election to expense up
to $18,000 of the cost of certain tangible personal property placed in
service in 1997. The deductible amount is reduced by the cost of
qualifying property in excess of $200,000 and cannot exceed the taxable
income derived from the active conduct by the taxpayer of the trade or
business in which the property is used. These limitations are applied at
both the partnership and the partner level.
LEASEHOLD COSTS AND ABANDONMENT
The costs of acquiring oil and gas Lease interests, together with the
related cost depletion deduction and any abandonment loss, are allocated
under the Partnership Agreement 100% to Atlas, which will contribute the
Leases to the Partnership as a part of its Capital Contribution.
TAX BASIS OF PARTICIPANTS' INTERESTS
The adjusted basis for federal income tax purposes of a Participant's
interest in the Partnership will be adjusted (but not below zero) for
any gain or loss to the Participant from a disposition by the
Partnership of an oil or gas property, and will be increased by his cash
subscription payment and his share of Partnership income.
The adjusted basis of a Participant's interest in the Partnership will
be reduced by: his share of Partnership losses; his depletion deduction
(but not below zero); and cash distributions from the Partnership to
him. The reduction in a Participant's share of Partnership liabilities
is considered a cash distribution. Should cash distributions exceed the
tax basis of the Participant's interest in the Partnership, taxable gain
would result to the extent of the excess.
A Participant's distributive share of Partnership loss is allowable only
to the extent of the adjusted basis of such Participant's interest in
the Partnership at the end of the Partnership's taxable year.
DISTRIBUTIONS FROM A PARTNERSHIP
Generally, a cash distribution from a partnership to a partner in excess
of the adjusted basis of such partner's interest in the partnership
immediately before the distribution is treated as gain from the sale or
exchange of his interest in the partnership to the extent of the excess.
No loss is recognized by the partners on these types of distributions.
Other distributions of cash, disproportionate distributions of
property, and liquidating distributions may result in taxable gain
or loss. (See "- Disposition of Partnership Interests" and "-
Termination of a Partnership," below.)
SALE OF THE PROPERTIES
Generally, on assets purchased before 2001:
(i) a noncorporate taxpayer's ordinary income and short-term gains on
the sale of assets held for a year or less are taxed at a maximum
rate of 39.6%;
(ii) net mid-term capital gains of a noncorporate taxpayer on the sale
of assets held more than a year but not more than 18 months are
taxed at a maximum rate of 28%; and
(iii) net long-term capital gains of a noncorporate taxpayer on the
sale of assets held more than 18 months are taxed at a maximum
rate of 20% (10% if they would be subject to tax at a rate of 15%
if they were not eligible for long-term capital gains treatment).
These rates also apply for purposes of the alternative minimum tax.
(See " - Minimum Tax - Tax Preferences", below.) The annual capital
loss limitation for noncorporate taxpayers is the amount of capital
gains plus the lesser of $3,000 ($1,500 for married persons filing
separate returns) or the excess of capital losses over capital gains.
Gains or losses from sales of oil and gas properties held for more than
twelve months would be, except to the extent of depreciation recapture
on equipment and recapture of any intangible drilling and development
costs, depletion deductions and certain other losses, treated as a mid-
term or long-term capital gain depending on the holding period
while a net loss will be an ordinary deduction. Other gains and
losses on sales of oil and gas properties will generally result in ordinary
gains or losses.
DISPOSITION OF PARTNERSHIP INTERESTS
The sale or exchange of all or part of a Participant's interest in the
Partnership held by him for more than twelve months will generally
result in a recognition of mid-term or long-term capital gain or loss
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<PAGE>91
except to the extent of ordinary income or loss, if any, from
Partnership 751 assets (which consist of unrealized receivables or
inventory). See " - Sale of the Properties," above, for the tax rates
on capital gains. In the event the interest is held for twelve months
or less, such gain or loss will generally be short-term gain or loss.
The recapturable portions of depreciation, depletion and intangible
drilling and development costs constitute ordinary income. A portion of
any gain recognized by a Limited Partner on the sale or other
disposition of his interest in the Partnership will also be
characterized as portfolio income under the passive activity rules to
the extent the gain is itself attributable to portfolio income (e.g.
interest on investment of working capital). A Participant's pro rata
share of the Partnership's nonrecourse liabilities, if any, as of the
date of the sale or exchange must be included in the amount realized.
Therefore, the gain recognized may result in a tax liability greater
than the cash proceeds, if any, from such disposition. A gift of an
interest in the Partnership may result in federal and/or state income
tax and gift tax liability of the donor.
A Participant who sells or exchanges all or part of his interest in the
Partnership is required by the Code to notify the Partnership within 30
days or by January 15 of the following year, if earlier. Other
dispositions of a Participant's interest, including a repurchase of the
interest by Atlas, may or may not result in recognition of taxable gain.
However, no gain should be recognized by an Investor General Partner
whose interest in the Partnership is converted to a Limited Partner
interest so long as there is no change in his share of the Partnership's
liabilities or certain Partnership assets as a result of the conversion.
No disposition of an interest in the Partnership (including repurchase
of the interest by Atlas) should be made by any Participant prior to
consultation with his tax advisor.
MINIMUM TAX - TAX PREFERENCES
For taxpayers other than integrated oil companies (see "- Intangible
Drilling and Development Costs"), the 1992 National Energy Bill repealed
(1) the preference for excess intangible drilling and development costs
and (2) the excess percentage depletion preference for oil and gas. The
repeal of the excess intangible drilling and development costs
preference, however, 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 and development costs preference had
not been repealed. These rules are summarized below.
The alternative minimum tax is intended to insure that no one with
substantial income can avoid tax liability by using deductions and
credits, including the deductions for intangible drilling and
development costs and accelerated depreciation. Generally, the
alternative minimum tax rate for individuals is 26% on alternative
minimum taxable income up to $175,000 ($87,500 for married individuals
filing separate returns) and 28% thereafter. See " - Sale of the
Properties," above, for the tax rates on capital gains. Regular tax
personal exemptions are not available for purposes of the alternative
minimum tax, however, alternative minimum taxable income may be reduced
by certain itemized deductions, exemption amounts and net operating
losses.
Under the prior rules, the amount of intangible drilling and development
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 oil and gas properties. Excess intangible drilling costs is
the regular intangible drilling and development 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 for costs of nonproductive wells and with
respect to productive wells taxpayers can elect to amortize the year's
intangible drilling and development costs ratably over a 60 month period
for all tax purposes and then such costs are not treated as an item of
tax preference.
The likelihood of a Participant incurring, or increasing, any minimum
tax liability by virtue of an investment in the Partnership must be
determined on an individual basis, and requires consultation by a
prospective Participant with his personal tax advisor.
LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST
Investment interest is deductible by a noncorporate taxpayer only to the
extent of net investment income each year (with an indefinite
carryforward of disallowed investment interest). An Investor General
Partner's share of any interest expense incurred by the Partnership will
be subject to the investment interest limitation. In addition, an
Investor General Partner's income and losses (including intangible
drilling and development costs) from the Partnership will be considered
investment income and losses. Losses allocable to an Investor General
Partner will reduce his net investment income and may affect the
deductibility of his investment interest expense, if any.
No item of income or expense subject to the passive activity loss rules
is treated as investment income or investment expense.
ALLOCATIONS
The Partnership Agreement allocates to each Partner his share of the
income, gains, credits and deductions (including the deductions for
intangible drilling and development costs and depreciation) generated by
the Partnership. (See "Participation in Costs and Revenues".) The
Capital Accounts of the Partners are adjusted to reflect such
allocations and the Capital Accounts, as adjusted, will be given effect
in distributions made to the Partners upon liquidation of the
Partnership or any Partner's interest in the Partnership. Generally, a
Participant's Capital Account is increased by the amount of money he
contributes to the Partnership and allocations to him of income and
gain, and decreased by the value of property or cash distributed to him
and allocations to him of loss and deductions.
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<PAGE>92
It should be noted that each Partner's share of Partnership items of
income, gain, loss, deduction and credit must be taken into account
whether or not there is any distributable cash. A Participant's share of
Partnership revenues applied to the repayment of loans or the reserve
for plugging wells will be included in his gross income in a manner
analogous to an actual distribution of the income to him. Thus, a
Participant may have taxable income from the Partnership for a
particular year in excess of any cash distributions from the Partnership
to him with respect to that year. To the extent the Partnership has cash
available for distribution, however, it is Atlas' policy that
Partnership distributions will not be less than the Participants'
estimated income tax liability with respect to Partnership income.
No assurance can be given that, on audit, the IRS will not take the
position that a portion of the deductions allocable to the Participants
is not allowable to them. If such a position is taken, there can be no
assurance that any resulting deficiency will not ultimately be
sustained. However, assuming the effect of the special allocations set
forth in the Partnership Agreement is substantial in light of a
Participant's tax attributes that are unrelated to the Partnership, in
the opinion of Special Counsel it is more likely than not that such
allocations will govern each Participant's distributive share of such
items to the extent such allocations do not cause or increase deficit
balances in the Participants' Capital Accounts.
If any allocation under the Partnership Agreement is not recognized for
federal income tax purposes, each Participant's distributive share of
the items subject to such allocation generally will be determined in
accordance with his interest in the Partnership, determined by
considering relevant facts and circumstances. To the extent such
deductions, as allocated by the Partnership Agreement, exceed deductions
which would be allowed pursuant to such a reallocation Participants may
incur a greater tax burden.
"AT RISK" LIMITATION FOR LOSSES
Subject to the limitations on "passive losses" generated by the
Partnership in the case of Limited Partners and a Participant's basis in
the Partnership, each Participant may use his share of the Partnership's
losses to offset income from other sources. (See "- Limitations on
Passive Activities" and " - Tax Basis of Participants' Interests,"
above.) However, any individual taxpayer who sustains a loss in
connection with the Partnership may deduct such loss only to the extent
of the amount he has "at risk" in the Partnership at the end of a
taxable year. The amount "at risk" is limited to the amount of money and
the adjusted basis of other property the taxpayer has contributed to the
activity, and any amount he has borrowed with respect thereto for which
he is personally liable or with respect to which he has pledged property
other than property used in the activity; limited, however, to the net
fair market value of his interest in such pledged property. However,
amounts borrowed will not be considered "at risk" if such amounts are
borrowed from any person who has an interest (other than as a creditor)
in such activity or from a related person to a person (other than the
taxpayer) having such an interest.
In addition, the amount the taxpayer has "at risk" may not include the
amount of any loss that the taxpayer is protected against through
nonrecourse loans, guarantees, stop loss agreements, or other similar
arrangements. The amount of any such loss that is disallowed in any
taxable year will be carried over to the first succeeding taxable year,
to the extent a Participant is "at risk." Further, a taxpayer's "at
risk" amount in subsequent taxable years with respect to the activity
involved will be reduced by that portion of the loss which is allowable
as a deduction.
Participants' Agreed Subscriptions are funded by a payment of cash
(usually "at risk").
PARTNERSHIP ORGANIZATION AND SYNDICATION FEES
Expenses connected with the sale of interests in a partnership are not
deductible. Although certain organization expenses of a partnership may
be deducted and amortized over a period of not less than 60 months, such
expenses are charged 100% to the Managing General Partner as part of the
Partnership's Organization and Offering Costs and any related deductions
will be allocated to the Managing General Partner.
TAX ELECTIONS
The Code permits partnerships to elect to adjust the basis of
partnership property on the transfer of an interest in a partnership by
sale or exchange or on the death of a partner, and on the distribution
of property by the partnership to a partner (the 754 election). The
general effect of such an election is that transferees of the
partnership interests 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 such purposes, upon certain
distributions to partners, as though it had newly acquired an interest
in the partnership assets and therefore acquired a new cost basis for
such assets. The Partnership Agreement provides that the Partnership may
make the 754 election. Taxpayers may elect to capitalize and amortize
"start-up expenditures" over a 60-month period. Such items include
amounts: (1) paid or incurred in connection with: (i) investigating and
creating an active trade or business; or (ii) 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 such activity
becoming an active trade or business; and (2) which would be allowed as
a deduction if paid or incurred in connection with the expansion of an
existing business. Start-up expenditures do not include amounts paid or
incurred in connection with the sale of partnership interests. If it is
ultimately determined that any of the Partnership's expenses constituted
start-up expenditures and not deductible business expenses, the
Partnership's deductions would be reduced.
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DISALLOWANCE OF DEDUCTIONS UNDER SECTION 183 OF THE CODE
A Participant's ability to deduct his share of the Partnership's losses
could be lost if the Partnership lacks the appropriate profit motive as
determined from an examination of all facts and circumstances at the
time. There is a presumption that an activity is engaged in for profit,
if, in any three of five consecutive taxable years, the gross income
derived from such activity exceeds the deductions attributable to such
activity. Thus, if the Partnership fails to show a profit in at least
three out of five consecutive years, this presumption will not be
available. In that instance, the possibility that the IRS could
successfully challenge the deductions claimed by a Participant would be
substantially increased.
The fact that the possibility of ultimately obtaining profits is
uncertain, standing alone, does not appear to be sufficient grounds for
the denial of losses. Based on Atlas' representation that the
Partnership will be conducted as described in this Prospectus, in the
opinion of Special Counsel it is more likely than not that the
Partnership will possess the requisite profit motive.
TERMINATION OF A PARTNERSHIP
A partnership will be considered as terminated for federal income tax
purposes if within a twelve month period there is a sale or exchange of
50% or more of the total interest in partnership capital and profits. A
partner will realize taxable gain on a termination of the partnership to
the extent that money regarded as distributed to him exceeds the
adjusted basis of his partnership interest. The conversion of Investor
General Partner Units to Limited Partner interests will not result in a
termination of the Partnership.
LACK OF REGISTRATION AS A TAX SHELTER
An organizer of a "tax shelter" must obtain an identification number
which must be included on the tax returns of investors in such a tax
shelter. For this purpose, a "tax shelter" includes investments with
respect to which any person could reasonably infer that the ratio that
(1) the aggregate amount of the potentially allowable deductions and
350% of the potentially allowable credits with respect to the investment
during the first five years of the investment bears to (2) the amount of
money and the adjusted basis of property contributed to the investment
exceeds 2 to 1, determined without reduction for gross income derived
from the investment.
Atlas does not believe that the Partnership will have a tax shelter
ratio greater than 2 to 1. Also, because the purpose of the Partnership
is to locate, produce and market natural gas on an economic basis, Atlas
does not believe that the Partnership will be a "potentially abusive tax
shelter." Accordingly, Atlas does not intend to cause the Partnership to
register with the IRS as a tax shelter.
If it is subsequently determined that the Partnership was required to be
registered with the IRS as a tax shelter, Atlas would be subject to
certain penalties and each Participant would be liable for a $250
penalty for failure to include the tax shelter registration number on
his tax return, unless such failure was due to reasonable cause. A
Participant also would be liable for a penalty of $100 for failing to
furnish the tax shelter registration number to any transferee of his
interest in the Partnership. However, based on the representations of
the Managing General Partner, Special Counsel has expressed the opinion
that the Partnership, more likely than not, is not required to register
with the IRS as a tax shelter.
Issuance of a registration number does not indicate that an investment
or the claimed tax benefits have been reviewed, examined, or approved by
the IRS.
INVESTOR LISTS. Any person who organizes a tax shelter required to be
registered with the IRS must maintain a list of each investor in the tax
shelter. For the reasons described above, Atlas does not believe the
Partnership is a tax shelter for this purpose. If this determination is
wrong there is a penalty of $50 for each person, unless the failure is
due to reasonable cause.
TAX RETURNS AND AUDITS
IN GENERAL. The tax treatment of all partnership items is generally
determined at the partnership, rather than the partner, level; and the
partners are generally required to treat partnership items on their
individual returns in a manner which is consistent with the treatment of
such partnership items on the partnership return.
Generally, the IRS must conduct an administrative determination as to
partnership items at the partnership level before conducting deficiency
proceedings against a partner, and the partners must file a request for
an administrative determination before filing suit for any credit or
refund. The period for assessing tax against a Partner attributable to a
partnership item may be extended as to all partners by agreement between
the IRS and Atlas, which will serve as the Partnership's representative
("Tax Matters Partner") in all administrative and judicial proceedings
conducted at the partnership level. The Tax Matters Partner generally
may enter into a settlement on behalf of, and binding upon, partners
owning less than a 1% profits interest in partnerships having more than
100 partners. In addition, a partnership with at least 100 partners may
elect to be governed under simplified tax reporting and audit rules as
an "electing large partnership". These rules also facilitate the
matching of partnership items with individual partner tax returns by the
IRS. The Managing General Partner does not anticipate that the
Partnership will make this election. By executing the Partnership
Agreement, each Participant agrees that he 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.
TAX RETURNS. The preparation and filing of each Participant's federal,
state and local income tax returns are the responsibility of the
Participant. The Partnership will provide each Participant with the tax
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<PAGE>94
information applicable to his investment in the Partnership necessary to
prepare such returns; however, the treatment of the tax attributes of
the Partnership may vary among Participants. The Managing General
Partner, its Affiliates and Special Counsel assume no responsibility for
the tax consequences of this transaction to a Participant, nor for the
disallowance of any proposed deductions. EACH PARTICIPANT IS URGED TO
SEEK QUALIFIED, PROFESSIONAL ASSISTANCE IN THE PREPARATION OF HIS
FEDERAL, STATE AND LOCAL TAX RETURNS.
PENALTIES AND INTEREST
IN GENERAL. Interest (based on the applicable Federal short-term rate
plus 3 percentage points) is charged on underpayments of tax and various
civil and criminal penalties are included in the Code.
PENALTY FOR NEGLIGENCE OR DISREGARD OF RULES OR REGULATIONS. If any
portion of an underpayment of tax is attributable to negligence or
disregard of rules or regulations, 20% of such portion is added to the
tax. Negligence is strongly indicated if a partner fails to treat
partnership items on his tax return in a manner that is consistent with
the treatment of such items on the partnership's return or to notify the
IRS of the inconsistency.
VALUATION MISSTATEMENT PENALTY. There is an addition to tax of 20% of
the amount of any underpayment of tax of $5,000 or more which is
attributable to a substantial valuation misstatement. There is a
substantial valuation misstatement if the value or adjusted basis of any
property claimed on a return is 200% or more of the correct amount; or
if the price for any property or services (or for the use of property)
claimed on a return is 200% or more (or 50% or less) of the correct
price. If there is a gross valuation misstatement (400% or more of the
correct value or adjusted basis or the undervaluation is 25% or less of
the correct amount) the penalty is 40%.
SUBSTANTIAL UNDERSTATEMENT PENALTY. There is also an addition to tax of
20% of any underpayment if the difference between the tax required to be
shown on the return over the tax actually shown on the return, exceeds
the greater of 10% of the tax required to be shown on the return, or
$5,000.
The amount of any understatement generally will be reduced to the extent
it is attributable to the tax treatment of an item supported by
substantial authority, or adequately disclosed on the taxpayer's return
and there is a reasonable basis for the tax treatment of such item by
the taxpayer. However, in the case of "tax shelters," the understatement
may be reduced only if the tax treatment of an item attributable to a
tax shelter was supported by substantial authority and the taxpayer
established that he reasonably believed that the tax treatment claimed
was more likely than not the proper treatment. A "tax shelter" for this
purpose is any entity which has as a significant purpose the avoidance
or evasion of federal income tax.
IRS ANTI-ABUSE RULE. Under Treas. Reg. 1.701-2, 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 to remedy the abuse. For illustration purposes,
the following factors may indicate that a partnership is being used in a
prohibited manner: (i) the partners' aggregate federal income tax
liability is substantially less than had the partners owned the
partnership's assets and conducted its activities directly; (ii) the
partners' aggregate federal income tax liability is substantially less
than if purportedly separate transactions are treated as steps in a
single transaction; (iii) one or more partners are needed to achieve the
claimed tax results and have a nominal interest in the partnership or
are substantially protected against risk; (iv) substantially all of the
partners are related to each other; (v) income or gain are allocated to
partners who are not expected to have any federal income tax liability;
(vi) the benefits and burdens of ownership of property nominally
contributed to the partnership are retained in substantial part by the
contributing party; and (vii) the benefits and burdens of ownership of
partnership property are in substantial part shifted to the distributee
partners before or after the property is actually distributed to the
distributee partners. Based on the Managing General Partner's
representation that the Partnership will be conducted as described in
this Prospectus, in the opinion of Special Counsel it is more likely
than not that the Partnership will not be subject to the anti-abuse rule
set forth in Treas. Reg. 1.701-2.
STATE AND LOCAL TAXES
The Partnership will operate in states and localities which impose a tax
on its assets or its income, or on each Participant. Deductions which
are available to Participants for federal income tax purposes may not be
available for state or local income tax purposes.
Under Pennsylvania law, the Partnership is required to withhold state
income tax at the rate of 2.8% of Partnership income allocable to
Participants who are not residents of Pennsylvania. Prospective
Participants should consult with their own tax advisors concerning the
possible effect of various state and local taxes on their personal tax
situations.
SEVERANCE, FRANCHISE, AND AD VALOREM (REAL ESTATE) TAXES
The Partnership may incur various ad valorem or severance taxes imposed
by state or local taxing authorities. Currently, there is no such tax
liability in Mercer County, Pennsylvania.
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<PAGE>95
SOCIAL SECURITY BENEFITS AND SELF-EMPLOYMENT TAX
A Limited Partner's share of income or loss from the 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 the Partnership will constitute "net earnings from
self-employment" for these purposes. For 1997 the ceiling for social
security tax of 12.4% is $65,400 and there is no ceiling for medicare
tax of 2.9%. Self-employed individuals can deduct one-half of their
self-employment tax.
FOREIGN PARTNERS
The Partnership will be required to withhold and pay to the IRS tax at
the highest rate under the Code applicable to Partnership income
allocable to foreign partners, even if no cash distributions are made to
such partners. A purchaser of a foreign Partner's Units may be required
to withhold a portion of the purchase price and the Managing General
Partner may be required to withhold with respect to taxable
distributions of real property to a foreign Partner. The withholding
requirements described above do not obviate United States tax return
filing requirements for foreign Partners. In the event of
overwithholding, a foreign Partner must file a United States tax return
to obtain a refund.
ESTATE AND GIFT TAXATION
There is no federal tax on lifetime or testamentary transfers of
property between spouses. The gift tax annual exclusion is $10,000 per
donee. The maximum estate and gift tax rate is 55% (subject to a 5%
surtax on amounts in excess of $10,000,000); and estates of $600,000
(which increases in stages to $1,000,000 by 2006) or less generally are
not subject to federal estate tax. In the event of the death of a
Participant, the fair market value of his interest as of the date of
death (or as of the alternate valuation date) will be included in his
estate for federal estate tax purposes. The decedent's heirs will, for
federal income tax purposes, take as their basis for the interest the
value as so determined for federal estate tax purposes.
CHANGES IN LAW
The Partnership and the Participants could be adversely affected by any
further changes in tax laws that may result through future Congressional
action, Tax Court or other judicial decisions, or interpretations by the
IRS. The Managing General Partner cannot predict what, if any, changes
in the tax law may become law in the future or even if adopted, would
apply to the Partnership.
THE FOREGOING ANALYSIS IS NOT INTENDED AS A SUBSTITUTE FOR CAREFUL TAX
PLANNING. IT IS NOT POSSIBLE TO PREDICT THE EFFECT OF THE TAX LAWS ON
INDIVIDUAL PARTICIPANTS. ACCORDINGLY, EACH PARTICIPANT IS URGED TO SEEK,
AND SHOULD DEPEND UPON, THE ADVICE OF HIS OWN TAX ADVISORS WITH RESPECT
TO HIS INVESTMENT IN THE PARTNERSHIP WITH SPECIFIC REFERENCE TO HIS OWN
TAX SITUATION AND POTENTIAL CHANGES IN THE APPLICABLE LAW.
DEFINITIONS
TERMS DEFINED
As used in this Prospectus, the following terms have the meanings
hereinafter set forth:
(1) "Administrative Costs" means all customary and routine expenses
incurred by the Sponsor for the conduct of Partnership
administration, including: legal, finance, accounting, secretarial,
travel, office rent, telephone, data processing and other items of a
similar nature. No Administrative Costs charged will be duplicated
under any other category of expense or cost. No portion of the
salaries, benefits, compensation or remuneration of controlling
persons of Atlas will be reimbursed by the Partnership as
Administrative Costs. Controlling persons include directors,
executive officers and those holding five percent 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 (a) any person
directly or indirectly owning, controlling, or holding with power to
vote 10 per cent or more of the outstanding voting securities of
such specified person; (b) any person 10 per cent or more of whose
outstanding voting securities are directly or indirectly owned,
controlled, or held with power to vote, by such specified person;
(c) any person directly or indirectly controlling, controlled by, or
under common control with such specified person; (d) any officer,
director, trustee or partner of such specified person; and (e) if
such specified person is an officer, director, trustee or partner,
any person for which such person acts in any such capacity.
(4) "AIC, Inc." means AIC, Inc., a wholly owned subsidiary of Atlas
Group and the sole shareholder of Atlas, whose principal executive
offices are located at 311 Rouser Road, Moon Township, Pennsylvania,
15108.
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<PAGE>96
(5) "Agreed Subscription" means that amount so designated on the
Subscription Agreement executed by the Participant, or, in the case
of the Managing General Partner, its subscription under 3.03(b) and
its subsections of the Partnership Agreement.
(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 Energy" means Atlas Energy Group, Inc., an Ohio corporation,
whose principal executive offices are located at 311 Rouser Road,
Moon Township, Pennsylvania 15108.
(9) "Atlas Group" means The Atlas Group, Inc., a Pennsylvania
corporation, whose principal executive offices are located at 311
Rouser Road, Moon Township, Pennsylvania 15108. Atlas Group was
formerly known as AEGH or AEG Holdings, Inc.
(10) "Capital Account" or "account" means the account established for
each party to the Partnership Agreement, maintained as provided in
5.02 and its subsections of the Partnership Agreement.
(11) "Capital Contribution" means the amount agreed to be contributed to
the Partnership by a party pursuant to 3.04 and 3.05 and their
subsections of the Partnership Agreement.
(12) "Carried Interest" means an equity interest in a program issued to a
person without consideration, in the form of cash or tangible
property, in an amount proportionately equivalent to that received
from Participants.
(13) "Code" means the Internal Revenue Code of 1986, as amended.
(14) "Cost", when used with respect to the sale of property to the
Partnership, means (a) the sum of the prices paid by the seller to
an unaffiliated person for such property, including bonuses; (b)
title insurance or examination costs, brokers' commissions, filing
fees, recording costs, transfer taxes, if any, and like charges in
connection with the acquisition of such property; (c) a pro rata
portion of the seller's actual necessary and reasonable expenses for
seismic and geophysical services; and (d) rentals and ad valorem
taxes paid by the seller with respect to such property to the date
of its transfer to the buyer, interest and points actually incurred
on funds used to acquire or maintain such property, and such portion
of the seller'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 (d) hereof shall
have been incurred not more than 36 months prior to the purchase by
the Partnership. When used with respect to services, "cost" means
the reasonable, necessary and actual expense incurred by the seller
on behalf of the Partnership in providing such 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., a wholly owned
subsidiary of AIC, Inc. and the broker-dealer which will manage the
offering and sale of the Units in all states except Minnesota and
New Hampshire, and Bryan Funding, Inc., the broker-dealer which will
manage the offering and sale of Units in Minnesota and New
Hampshire.
(16) "Development Drilling" means drilling a Development Well.
(17) "Development Well" means a well drilled within the proved area of an
oil or gas reservoir to the depth of a stratigraphic Horizon known
to be productive.
(18) "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
shall 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.
Direct Costs may include the cost of services provided by the
Sponsor or its Affiliates if such services are provided pursuant to
written contracts and in compliance with 4.03(d)(7) of the
Partnership Agreement.
(19) "Drilling and Operating Agreement" means the proposed Drilling and
Operating Agreement between Atlas, Atlas Energy or an Affiliate as
Operator, and the Partnership as Developer, a copy of the proposed
form of which is attached as Exhibit (II) to the Partnership
Agreement.
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<PAGE>97
(20) "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.
(21) "Exploratory Drilling" means drilling an Exploratory Well.
(22) "Exploratory Well" means a well drilled to find commercially
productive hydrocarbons in an unproved area, to find a new
commercially productive Horizon in a field previously found to be
productive of hydrocarbons at another Horizon, or to significantly
extend a known prospect.
(23) "Farmout" means an agreement whereby the owner of the leasehold or
Working Interest agrees to assign his interest in certain specific
acreage 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.
(24) "Final Terminating Event" means any one of the following: (i) the
expiration of the fixed term of the Partnership; (ii) the giving of
notice to the Participants by the Managing General Partner of its
election to terminate the affairs of the Partnership; (iii) the
giving of notice by the Participants to the Managing General Partner
of their similar election through the affirmative vote of
Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription; or (iv) the termination of the Partnership
under 708(b)(1)(A) of the Code or the Partnership ceases to be a
going concern.
(25) "Fracturing" or "Frac" means a treatment to a potentially productive
geological formation intended to enhance the ability of oil or gas
to migrate through the formation to the well hole. Fracturing may
involve the application of hydraulic pressure to the reservoir
formation or the use of explosive devices to create or enlarge
fractures through which oil or gas may move.
(26) "Horizon" means a zone of a particular formation; that part of a
formation of sufficient porosity and permeability to form a
petroleum reservoir.
(27) "Independent Expert" means a person with no material relationship to
the Sponsor or its Affiliates who is qualified and who is in the
business of rendering opinions regarding the value of oil and gas
properties based upon the evaluation of all pertinent economic,
financial, geologic and engineering information available to the
Sponsor or its Affiliates.
(28) "Initial Closing Date" means the date, on or before the Offering
Termination Date, but after the minimum Partnership Subscription has
been received, that the Managing General Partner, in its sole
discretion, elects for the Partnership to begin business activities,
including the drilling of wells. It is anticipated that this date
will be December 1, 1997.
(29) "Intangible Drilling Costs" or "Non-Capital Expenditures" means
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; and includes all expenditures made with respect
to any well prior to 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
such well and the preparation thereof for the production of oil or
gas, that are currently deductible pursuant to Section 263(c) of the
Code and Treasury Reg. Section 1.612-4, which are generally termed
"intangible drilling and development costs," including the expense
of plugging and abandoning any well prior to a completion attempt.
(30) "Interim Closing Date" means such date(s) after the Initial Closing
Date of the Partnership, but prior to the Offering Termination Date,
that the Managing General Partner, in its sole discretion, applies
additional Agreed Subscriptions to additional Partnership
activities, including drilling activities.
(31) "Investor General Partners" means the persons signing the
Subscription Agreement as Investor General Partners and the Managing
General Partner to the extent of any optional subscription under
3.03(b)(2) of the Partnership Agreement. All Investor General
Partners will be of the same class and have the same rights.
(32) "IRS" means the United States Internal Revenue Service.
(33) "Landowner's Royalty Interest" means an interest in production, or
the proceeds therefrom, to be received free and clear of all costs
of development, operation, or maintenance, reserved by a landowner
upon the creation of an oil and gas Lease.
(34) "Leases" means full or partial interests in oil and gas leases, oil
and gas mineral rights, fee rights, licenses, concessions, or other
rights under which the holder is entitled to explore for and produce
oil and/or gas, and further includes any contractual rights to
acquire any such interest.
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<PAGE>98
(35) "Limited Partners" means the persons signing the Subscription
Agreement as Limited Partners, the Managing General Partner to the
extent of any optional subscription under 3.03(b)(2) of the
Partnership Agreement, the Investor General Partners upon the
conversion of their Investor General Partner Units to Limited
Partner interests pursuant to 6.01 (c) of the Partnership
Agreement, and any other persons who are admitted to the Partnership
as additional or substituted Limited Partners. All Limited Partners
will be of the same class and have the same rights; provided,
however, Limited Partners who were formerly Investor General
Partners remain liable for Partnership obligations incurred prior to
the conversion of their Investor General Partner Units to Limited
Partner interests in the Partnership, as set forth in the
Partnership Agreement.
(36) "Managing General Partner" means Atlas Resources, Inc. or any Person
admitted to the Partnership as a general partner other than as an
Investor General Partner pursuant to the Partnership Agreement who
is designated to exclusively supervise and manage the operations of
the Partnership.
(37) "MCF" means one thousand cubic feet of natural gas.
(38) "Net Revenue Interest" means that percentage of revenues
attributable to the oil and gas rights subject to a particular Lease
which a party acquiring a Lease is entitled to receive by virtue of
its interest therein.
(39) "Offering Termination Date" means the date after the minimum
Partnership Subscription has been received on which the Managing
General Partner determines, in its sole discretion, the
Partnership's subscription period is closed and the acceptance of
subscriptions ceases, which shall not be later than December 31,
1997.
(40) "Operating Costs" means expenditures made and costs incurred in
producing and marketing oil or gas from completed wells, including,
in addition to labor, fuel, repairs, hauling, materials, supplies,
utility charges and other costs incident to or therefrom, ad valorem
and severance taxes, insurance and casualty loss expense, and
compensation to well operators or others for services rendered in
conducting such operations. Subject to the foregoing, Operating
Costs also include reworking, workover, subsequent equipping and
similar expenses relating to any well.
(41) "Operator" means Atlas, as operator of Partnership Wells in
Pennsylvania, Atlas Energy as operator of Partnership Wells in Ohio
and Atlas or an Affiliate as operator of Partnership Wells in other
areas of the United States.
(42) "Organization Costs" means all costs of organizing the offering,
including, but not limited to, expenses for printing, engraving,
mailing, charges of transfer agents, registrars, trustees, escrow
holders, depositaries, engineers and other experts, expenses of
qualification of the sale of the securities under Federal and State
law, including taxes and fees, accountants' and attorneys' fees and
other front-end fees.
(43) "Organization and Offering Costs" means all costs of organizing and
selling the offering including, but not limited to, total
underwriting and brokerage discounts and commissions (including fees
of the underwriters' attorneys), 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, expenses of qualification
of the sale of the securities under federal and state law, including
taxes and fees, accountants' and attorneys' fees and other front-end
fees.
(44) "Overriding Royalty Interest" means an interest in the oil and gas
produced pursuant to a specified oil and gas lease or leases, 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.
(45) "Participants" means the Managing General Partner to the extent of
its optional subscription under 3.03(b)(2) of the Partnership
Agreement, the Limited Partners and the Investor General Partners.
(46) "Partners" means the Managing General Partner, the Investor General
Partners and the Limited Partners.
(47) "Partnership" means Atlas-Energy for the Nineties-Public #6 Ltd.,
the Pennsylvania limited partnership formed pursuant to the
Partnership Agreement.
(48) "Partnership Agreement" means the Amended and Restated Certificate
and Agreement of Limited Partnership, including all Exhibits
thereto, as set forth in Exhibit (A) to this Prospectus.
(49) "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.
(50) "Partnership Subscription" means the aggregate Agreed Subscriptions
of the parties to the Partnership Agreement; provided, however, with
respect to Participant voting rights under the Partnership
Agreement, the term "Partnership Subscription" shall be deemed not
to include the Managing General Partner's required subscription
under 3.03(b)(1) of the Partnership Agreement.
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<PAGE>99
(51) "Partnership Well" means a well, some portion of the revenues from
which is received by the Partnership.
(52) "Person" means a natural person, partnership, corporation,
association, trust or other legal entity.
(53) "Program" means one or more limited or general partnerships or other
investment vehicles formed, or to be formed, for the primary purpose
of exploring for oil, gas and other hydrocarbon substances or
investing in or holding any property interests which permit the
exploration for or production of hydrocarbons or the receipt of such
production or the proceeds thereof.
(54) "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 designated by the Managing General Partner in writing prior
to the conduct of Partnership operations and shall be 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.
A "Prospect" with respect to 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 if
the well to be drilled by the Partnership is to a Horizon containing
Proved Reserves. Subject to the foregoing sentence, with respect to
the Clinton/Medina geological formation in Ohio and Pennsylvania
"Prospect" shall be deemed the drilling or spacing unit.
(55) "Proved Reserves" means the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes
in existing prices provided only by contractual arrangements, but
not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility
is supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes (a)
that portion delineated by drilling and defined by gas-oil
and/or oil-water contacts, if any; and (b) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
(a) oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves"; (b)
crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as
to geology, reservoir characteristics, or economic factors; (c)
crude oil, natural gas, and natural gas liquids, that may occur
in undrilled prospects; and (d) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales,
coal, gilsonite and other such sources.
(56) "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.
(57) "Proved Undeveloped Reserves" means reserves that are expected to be
recovered from new wells on undrilled acreage, or 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.
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<PAGE>100
(58) "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. Such
term does not include: (a) a transaction involving securities of the
Partnership that have been listed for at least twelve months on a
national exchange or traded through the National Association of
Securities Dealers Automated Quotation National Market System; or
(b) 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: voting rights, the term of existence of the
Partnership, the Managing General Partner's compensation and the
Partnership's investment objectives.
(59) "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.
(60) "Sales Commissions" means all underwriting and brokerage discounts
and commissions incurred in the sale of Units in the Partnership
payable to registered broker-dealers, excluding the Dealer-Manager
fee, reimbursement for bona fide accountable due diligence expenses
and wholesaling fees.
(61) "Selling Agents" means those broker-dealers selected by the Dealer-
Manager which will participate in the offer and sale of the Units.
(62) "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. "Sponsor" includes 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. "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. Whenever the context so requires, the term "sponsor" shall be
deemed to include its affiliates.
(63) "Spud" means with respect to any well the commencement of the first
boring of the hole for the well for which a "spudding bit" may be
used, or such other meaning as is generally accepted in the oil and
gas industry.
(64) "Shut-In" means temporary cessation of operation of a producing
well; such as down time for repair and maintenance or due to the
lack of market for production or as a result of a decrease in the
price of gas the Managing General Partner has ceased producing all
or a portion of the gas from the well.
(65) "Subscription Agreement" means an execution and subscription
instrument in the form attached as Exhibit (I-B) to the Partnership
Agreement.
(66) "Subordinated Interest" means an equity interest in a program issued
to a person, without payment of full consideration, after the
attainment of certain specified performance by the program.
(67) "Tangible Costs"or "Capital Expenditures" means those costs
associated with the drilling and completion of oil and gas wells
which are generally accepted as capital expenditures pursuant to the
provisions of the Internal Revenue Code; and includes all costs of
equipment, parts and items of hardware used in drilling and
completing a well, and those items necessary to deliver acceptable
oil and gas production to purchasers to the extent installed
downstream from the wellhead of any well and which are required to
be capitalized pursuant to applicable provisions of the Code and
regulations promulgated thereunder.
(68) "Tax Matters Partner" means the Managing General Partner.
(69) "Units" or "Units of Participation" means the Limited Partner
interests and the Investor General Partner interests purchased by
Participants in the Partnership under the provisions of 3.03 and
its subsections of the Partnership Agreement.
(70) "Working Interest" means an interest in an oil and gas leasehold
which is subject to some portion of the Cost of development,
operation, or maintenance.
SUMMARY OF PARTNERSHIP AGREEMENT
NOTE: THE RIGHTS AND OBLIGATIONS OF THE MANAGING GENERAL PARTNER AND THE
PARTICIPANTS ARE GOVERNED BY THE PARTNERSHIP AGREEMENT, A COPY OF WHICH
IS ATTACHED AS EXHIBIT (A) TO THIS PROSPECTUS
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<PAGE>101
NO PROSPECTIVE
PARTICIPANT SHOULD SUBSCRIBE TO THE PARTNERSHIP WITHOUT FIRST THOROUGHLY
REVIEWING SUCH PARTNERSHIP AGREEMENT. THE FOLLOWING IS A SUMMARY OF
CERTAIN PROVISIONS IN THE PARTNERSHIP AGREEMENT NOT COVERED ELSEWHERE IN
THIS PROSPECTUS.
RESPONSIBILITY OF MANAGING GENERAL PARTNER
The Managing General Partner will have the exclusive management and
control of all aspects of the business of the Partnership. (See 4.02(b)
of the Partnership Agreement.) No Participant, including the Investor
General Partners, will have any voice in the day-to-day business
operations of the Partnership. (See 4.03(a)(2) of the Partnership
Agreement.) The Managing General Partner is authorized to delegate and
subcontract its duties under the Partnership Agreement to others,
including entities related to it. (See 4.02(c)(3)(a) of the Partnership
Agreement.)
LIABILITIES OF GENERAL PARTNERS, INCLUDING INVESTOR GENERAL PARTNERS
General Partners, including Investor General Partners, will not be
protected by limited liability for Partnership activities. The Investor
General Partners will be jointly and severally liable for all
obligations and liabilities to creditors and claimants, whether arising
out of contract or tort, in the conduct of Partnership operations. (See
4.05(b) of the Partnership Agreement.)
If an Investor General Partner is called upon to pay an additional
Capital Contribution to the Partnership and fails to pay such required
Capital Contribution when due, the remaining Investor General Partners,
pro rata, must pay such defaulting Investor General Partner's share of
Partnership liabilities and obligations. In that event, the remaining
Investor General Partners will 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;
will be entitled to receive 100% of the defaulting Investor General
Partner's cash distributions directly from the Partnership until the
amount in default is recovered in full plus interest at the legal rate;
and may commence legal action to collect the amount due plus interest at
the legal rate. (See 3.05(b) of the Partnership Agreement.)
The Managing General Partner maintains general liability insurance. (See
4.02(c)(1)(vi) of the Partnership Agreement.) In addition, the Managing
General Partner and Atlas Group have agreed to indemnify each of the
Investor General Partners for obligations related to casualty and
business losses which exceed available insurance coverage and
Partnership net assets. (See 4.05(b) of the Partnership Agreement.)
LIABILITY OF LIMITED PARTNERS
The Partnership will be governed by the Pennsylvania Revised Uniform
Limited Partnership Act under which a Limited Partner will not be liable
to third parties for the obligations of the Partnership unless he is
also an Investor General Partner or, in addition to the exercise of his
rights and powers as a Limited Partner, such person takes part in the
control of the business of the Partnership. (See 4.05(c) of the
Partnership Agreement.)
Under Pennsylvania law, the Limited Partners should have no liability to
the Partnership in excess of their respective Capital Contributions to
the Partnership and their share of the Partnership's assets and
undistributed income, except generally to the extent of (i) a failure to
make a required Capital Contribution, and (ii) for a period of two
years, any Capital Contributions "wrongfully" returned to a Limited
Partner in violation of the Partnership Agreement or Pennsylvania law,
with interest thereon, including but not limited to any distribution to
the Limited Partners to the extent that, after giving effect to such
distribution, all liabilities of the Partnership, other than liabilities
to the Participants on account of their contributions and to the
Managing General Partner, exceed Partnership assets. Participants will
not be obligated to restore any negative balances which exist in their
Capital Accounts after liquidation of their interests in the
Partnership. (See 3.04(a) of the Partnership Agreement.)
AMENDMENTS
Amendments to the Partnership Agreement may be proposed by the Managing
General Partner or by Participants whose Agreed Subscriptions equal 10%
or more of the Partnership Subscription and adopted upon the affirmative
vote of Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription. The Partnership Agreement may also be amended
by the Managing General Partner for certain purposes, but no amendment
materially and adversely affecting the Participants can be made without
the consent of the Participants who are so affected. In addition, the
Managing General Partner may not, without the affirmative vote of
Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription, change the investment and business purpose of
the Partnership or cause the Partnership to engage in activities outside
the stated business purposes of the Partnership through joint ventures
with other entities. (See 1.04 and 8.05 of the Partnership Agreement.)
NOTICE
Notice to Participants runs from the date of mailing and is binding on
the Participants irrespective of whether or not the notice is in fact
received by them. The notice periods are frequently quite short (a
minimum of 15 business days) and apply to matters which may seriously
affect the Participants' rights. Except where the Partnership Agreement
expressly requires affirmative approval, any Participant who fails to
timely respond to a request by the Managing General Partner for approval
of or concurrence in a proposed action will conclusively be deemed to
have approved such action. (See 8.01(d) and 8.01(e) of the Partnership
Agreement.)
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<PAGE>102
VOTING RIGHTS
Generally, Participants will be entitled to vote with respect to any and
all Partnership matters at any time a meeting of the Partners is called
by the Managing General Partner or Participants owning 10% or more of
the Partnership Subscription. Provided, however, except for the special
voting rights discussed below, the exercise by Limited Partners of these
voting rights is subject to the prior legal determination that the
limited liability of the Limited Partners will not be adversely
affected, unless in the opinion of counsel to the Partnership, such
legal determination is not necessary to maintain the limited liability
of the Limited Partners. The Investor General Partners may exercise
these rights, whether or not the Limited Partners can participate in the
vote, if they represent the requisite percentage of the Participants
necessary to take such action. (See 4.03(c) of the Partnership
Agreement.)
Each Unit is entitled to one vote on all matters; each fractional Unit
is entitled to that fraction of one vote equal to the fractional
interest in the Unit. In addition to the foregoing, at any time upon the
request of Participants whose Agreed Subscriptions equal 10% or more of
the Partnership Subscription, Participants whose Agreed Subscriptions
equal a majority of the Partnership Subscription may, without the
concurrence of the Managing General Partner or its Affiliates, vote
without a meeting to:
(1) amend the Partnership Agreement; provided however, any such
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 such Participant or the Managing
General Partner. Furthermore, any such amendment may not affect
the classification of Partnership income and loss for federal
income tax purposes without the unanimous approval of all
Participants;
(2) dissolve the Partnership;
(3) remove the Managing General Partner and elect a new Managing
General Partner;
(4) elect a new Managing General Partner if the Managing General
Partner elects to withdraw from the Partnership;
(5) remove the Operator and elect a new Operator;
(6) approve or disapprove the sale of all or substantially all of
the assets of the Partnership; and
(7) cancel any contract for services with the Managing General
Partner, or the Operator or their Affiliates without penalty
upon 60 days notice.
The Managing General Partner and its officers and directors and
Affiliates may also subscribe for Units in the Partnership on the same
basis as Limited Partners or Investor General Partners, except that they
are not required to pay the Dealer-Manager fee, Sales Commissions or due
diligence reimbursements. Also, the Managing General Partner and its
Affiliates may buy up to 10% of the Units, which will not be applied
towards the minimum Partnership Subscription required for the
Partnership to begin operations, although the Managing General Partner
currently does not anticipate that it and its Affiliates will purchase
any Units. Subject to the foregoing, any subscription by the Managing
General Partner or its officers, directors or Affiliates will dilute the
voting rights of the Participants. However, any Units owned by the
Managing General Partner or its Affiliates will not be included with
respect to the issues set forth in (3) and (5) above, and any other
transaction between the Managing General Partner or its Affiliates and
the Partnership. 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. (See 4.03(c)(1) of the Partnership Agreement.)
ACCESS TO RECORDS
Participants will have access to all records of the Partnership
including a list of the Participants, after adequate notice, at any
reasonable time, except that logs, well reports and other drilling and
operating data may be kept confidential for reasonable periods of time.
A Participant's ability to obtain the Participant List is subject to
additional requirements set forth in the Partnership Agreement. (See
4.03(b)(5) and 4.03(b)(6) of the Partnership Agreement.)
WITHDRAWAL OF MANAGING GENERAL PARTNER
At any time commencing ten years after the Offering Termination Date and
the Partnership's primary drilling activities, the Managing General
Partner may voluntarily withdraw as Managing General Partner for
whatever reason upon giving 120 days' written notice of withdrawal to
the Participants. The withdrawing Managing General Partner is not
required to provide a substitute Managing General Partner. However, a
new Managing General Partner may be substituted by the affirmative vote
of Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription.
If Atlas would withdraw as Managing General Partner of the Partnership
and the Participants failed to elect to continue the Partnership and to
designate a substituted Managing General Partner of the Partnership, the
Partnership would terminate and dissolve and adverse tax and other
consequences could result. If the Partnership was dissolved the
Participants may receive a distribution of direct property interests.
As joint interest owners, Limited Partners would have joint and several
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<PAGE>103
liability for the obligations or liabilities arising out of joint owner
operations and might find it desirable to obtain insurance protection or
dispose of the property interests, which may be difficult. To reduce
this risk the Managing General Partner will attempt upon liquidation and
dissolution to use its best efforts to sell the Partnership's properties
or to cause some type of entity which would preserve the limited
liability of the former Limited Partners, such as a liquidating trust,
to be established to hold the Partnership's properties. However, even if
the properties were transferred to a liquidating trust upon dissolution
of the Partnership, it might be difficult for the liquidating trust to
deal with such assets and realize their full value. For example, to
replace the management provided by the Managing General Partner, the
trustee of the liquidating trust would need the services of professional
operators. Further, after dissolution and the completion of payments to
third party creditors, the Managing General Partner has priority in
liquidation for any claims of indebtedness before the Participants.
Such distributions may also have adverse income tax consequences to the
Participants. (See Risk Factors - Special Risks of the Partnership -
Unlimited Liability of Investor General Partners" and "Tax Aspects -
Disposition of Partnership Interests".)
The Managing General Partner may not partially 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 unless such withdrawal is necessary to
satisfy the bona fide request of its creditors or approved by
Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription. (See 4.04(a)(3) and 6.03 of the Partnership
Agreement.)
REMOVAL OF OPERATOR
The Operator may be replaced at any time upon 60 days advance written
notice to the outgoing Operator by the Managing General Partner acting
on behalf of the Partnership upon the affirmative vote of Participants
whose Agreed Subscriptions equal a majority of the Partnership
Subscription. (See 4.04(a)(4) of the Partnership Agreement and "Summary
of Drilling and Operating Agreement".)
TERM AND DISSOLUTION
The Partnership will continue in existence for 50 years unless earlier
terminated by certain Final Terminating Events, including an election by
the Managing General Partner or the affirmative vote of Participants
whose Agreed Subscriptions equal a majority of the Partnership
Subscription. The Partnership may terminate on the occurrence of various
events, other than a Final Terminating Event, but a successor limited
partnership will automatically be formed under those circumstances. (See
7.01 and 7.02 of the Partnership Agreement.)
SUMMARY OF DRILLING AND OPERATING AGREEMENT
Atlas will serve as the Operator pursuant to the Drilling and Operating
Agreement, Exhibit (II) to the Partnership Agreement, for wells situated
in Pennsylvania, Atlas Energy will serve as the Operator for any wells
situated in Ohio and Atlas or an Affiliate will serve as the Operator
for any wells situated in other areas of the United States. The Operator
may be replaced at any time upon sixty days advance written notice to
the outgoing Operator by the Managing General Partner acting on behalf
of the Partnership upon the affirmative vote of Participants whose
Agreed Subscriptions equal a majority of the Partnership Subscription.
The Drilling and Operating Agreement provides a number of material
provisions, including, without limitation, those set forth below.
(1) The right of the Operator to resign after five years.
(2) The right of the Operator of a Partnership well beginning
three years after the well is placed into production to retain $200
per month to cover future plugging and abandonment of such well,
although Atlas historically has never done this after only three
years.
(3) 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 the Partnership.
(4) The prescribed insurance coverage to be maintained by the
Operator.
(5) Limitations on the Operator's authority to incur
extraordinary costs with respect to producing wells in excess of
$5,000 per well.
(6) Restrictions on the Partnership's ability to transfer its
interest in fewer than all wells, unless such transfer is of an
equal undivided interest in all wells.
(7) The limitation of the Operator's liability except for
violations of law, negligence or misconduct by it, its employees,
agents or subcontractors and breach of the Drilling and Operating
Agreement.
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<PAGE>104
(8) The excuse for nonperformance by the Operator due to force
majeure.
The foregoing is only a summary of some of the many provisions of the
proposed form of Drilling and Operating Agreement, and is qualified in
its entirety by reference to such form attached to the Partnership
Agreement as Exhibit (II). No prospective Participant should subscribe
to the Partnership without first thoroughly reviewing the Drilling and
Operating Agreement.
REPORTS TO INVESTORS
The Partnership will provide the reports set forth below to investors
and to the state securities commissions which request the reports.
(1) Commencing with the 1997 calendar year, the Partnership will
provide each Participant an annual report within 120 days after the
close of the calendar year, and commencing with the 1998 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 following information:
(a) Audited financial statements of the Partnership, including
a balance sheet and statements of income, cash flow and
Partners' equity prepared in accordance with generally
accepted accounting principles. Semiannual reports need not
be audited. (See 4.03(b)(1)(a) of the Partnership
Agreement.)
(b) A summary of the total fees and compensation paid by 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 payment reimbursements for Administrative Costs bears
to annual Partnership revenues. (See 4.03(b)(1)(b) of the
Partnership Agreement.)
(c) A description of each Prospect owned by the Partnership,
including the cost, location, number of acres and the
Working Interest except succeeding reports need contain
only material changes, if any. (See 4.03(b)(1)(c) of the
Partnership Agreement.)
(d) A list of the wells drilled or abandoned by the Partnership
(indicating whether each of such wells has or has not been
completed), and a statement of the cost of each well
completed or abandoned. (See 4.03(b)(1)(d) of the
Partnership Agreement.)
(e) A description of all farmins and joint ventures. (See
4.03(b)(1)(e) of the Partnership Agreement.)
(f) A schedule reflecting the total Partnership costs, the
costs paid by the Managing General Partner and the costs
paid by the Participants, the total Partnership revenues,
the revenues received or credited to the Managing General
Partner and the revenues received or credited to the
Participants. (See 4.03(b)(1)(f) of the Partnership
Agreement.)
(2) The Partnership will, within 75 days after the end of each
fiscal year, transmit to each Partner such information as may be
needed to enable such Partner to file his federal and state income
tax returns. (See 4.03(b)(2) of the Partnership Agreement.)
(3) Beginning January 1, 1999, and every year thereafter, Atlas
shall provide a computation of the total oil and gas Proved
Reserves of the Partnership and the dollar value thereof. The
reserve computations shall be based upon engineering reports
prepared by the Managing General Partner and reviewed by an
Independent Expert. (See 4.03(b)(3) of the Partnership Agreement.)
(4) The cost of all such reports described above will be paid by
the Partnership as Direct Costs. (See 4.03(b)(4) of the
Partnership Agreement.)
REPURCHASE OBLIGATION
Beginning in 2001, Participants may present their interests for purchase
by the Managing General Partner but are not obligated to do so. The
Managing General Partner is obligated to purchase up to 5% of the Units
in each calendar year unless the Managing General Partner determines, in
its sole discretion, that it does not have the necessary cash flow or it
is unable to borrow funds for such purpose on terms it deems reasonable,
in which case the Managing General Partner may suspend its repurchase
obligation by so notifying the Participants. Following such notice, if
such notice is given, the Managing General Partner will not be
contractually obligated to purchase any interests presented for
repurchase. In addition, the Managing General Partner's repurchase of
Units may be conditioned, in the Managing General Partner's sole
discretion, on the receipt of an opinion of counsel that such transfers
will not cause the Partnership to be treated as a "publicly traded
partnership" under the Code.
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<PAGE>105
The Managing General Partner will not purchase less than one Unit of a
Participant's interest unless such lesser amount represents the entire
amount of the Participant's interest. If less than all interests
presented at any time are to be purchased, the Participants whose
interests are to be purchased will be selected by lot and in any
calendar year the Managing General Partner will not purchase more than
5% of the Units. The Managing General Partner may waive these
limitations in its sole discretion, other than the limitations on its
purchasing more than 5% of the Units in any calendar year.
The Managing General Partner's obligation to purchase interests
presented for purchase may be discharged for the benefit of the Managing
General Partner by a third party or an Affiliate. The interests 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 interests, together with such other documentation as the Managing
General Partner may reasonably request.
The Managing General Partner will make a written offer to repurchase a
Participant's interest in cash in every year beginning in 2001 within
120 days of the Partnership reserve report prepared by the Managing
General Partner and reviewed by an Independent Expert (the "Reserve
Report") discussed below. A Participant may accept the repurchase offer
by a written acceptance; and no presentment will be considered effective
until after the payment has been made to the Participant in cash. In
addition, in accordance with Treas. Reg. 1.7704-1(f), no repurchase
shall occur until at least 60 calendar days after the Participant
notifies the Partnership in writing of the Participant's intention to
exercise the repurchase right.
The amount attributable to Partnership reserves will be determined based
upon the last Reserve Report. Beginning in 1999 and every year
thereafter, the reserve computations will be based on an engineering
report prepared by the Managing General Partner and reviewed by an
Independent Expert. The Participants will be provided a computation of
the total oil and gas Proved Reserves of the Partnership and the present
worth thereof as determined by the Managing General Partner. In making
this estimate of the present worth of future net revenues, the Managing
General Partner will employ a discount rate equal to 10%, use a constant
price for the oil and base the price of gas upon the existing gas
contract(s) at the time of the repurchase.
The purchase price to be paid to the Participant will be based upon the
Participant's share of the net assets and liabilities of the Partnership
and allocated pro rata to each Participant based upon his Agreed
Subscription. The purchase price will include the sum of the following
items: (i) an amount based on 70% of the present worth of future net
revenues from the Partnership's Proved Reserves, determined as described
above, (ii) Partnership cash on hand, (iii) prepaid expenses and
accounts receivable of the Partnership, less a reasonable amount for
doubtful accounts, and (iv) the estimated market value of all assets of
the Partnership not separately specified above, determined in accordance
with standard industry valuation procedures. There will be deducted
from the foregoing sum the following items: (i) an amount equal to all
Partnership 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; provided, however, that
if any cash distributed was derived from the sale, subsequent to the
request, of oil, gas or other mineral production or of a producing
property owned by the Partnership, for purposes of determining the
reduction of the purchase price, such 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 (see
above). The purchase price may be further adjusted by the Managing
General Partner for estimated changes therein from the date of the
Reserve Report to the date of payment of the purchase price to the
Participants: (i) by reason of production or sales of, or additions to,
reserves and lease and well equipment, sale or abandonment of Leases,
and similar matters occurring prior to payment of the purchase price to
the selling Participant, and (ii) by reason of any of the following
occurring prior to payment of the purchase price to the selling
Participant: changes in well performance, increases or decreases in the
market price of oil, gas or other minerals, revision of regulations
relating to the importing of hydrocarbons, changes in income, ad
valorem and other tax laws (e.g., material variations in the provisions
for depletion) and similar matters.
Because of the difficulty in accurately estimating oil and gas reserves,
the purchase price may not reflect the full value of the Partnership
property to which it relates. Such estimates are merely appraisals of
value and may not correspond to realizable value. There can be no
assurance that the revenues received by the Participant prior to the
repurchase offer and the purchase price paid for the interests will be
equal to the original price paid for such interests. The Participants
are not obligated to tender their Units for repurchase and a Participant
should recognize that he may realize a greater return if he retains
rather than sells the Units as provided herein. The Managing General
Partner has and will incur similar presentment obligations in connection
with other Programs which it or its Affiliates may sponsor. There can be
no assurance that the Managing General Partner will have any funds
available to repurchase any interests presented. Also, the sale of
interests pursuant to the Managing General Partner's repurchase
obligation will be a taxable event for the Participants, and gain or
loss generally will be recognized for federal income tax purposes. (See
"Tax Aspects - Disposition of Partnership Interests".)
TRANSFERABILITY OF UNITS
IN GENERAL
Transferability of the Units is restricted. The restrictions on
transferability are as follows: (i) no sale, exchange, transfer or
assignment may be made if it would, in the opinion of counsel for the
Partnership, result in the termination of the Partnership within the
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<PAGE>106
meaning of Section 708 of the Code, or would result in materially
adverse tax consequences to the Partnership or the Partners; and (ii) no
sale, assignment, pledge, hypothecation or transfer of a Partnership
interest other than by operation of law may be made in the absence of an
effective registration of the Units under the Securities Act of 1933, as
amended, and qualification under applicable state securities law or an
opinion of counsel acceptable to the Managing General Partner that such
registration and qualification are not required. The Managing General
Partner and the Partnership have no obligation to register the Units for
resale by any Participant. The Managing General Partner will not
consent to a transfer and substitution of a Participant if doing so
would result in a violation of the securities laws or cause the
Partnership to be terminated or treated as a publicly traded partnership
for tax purposes. (See "Tax Aspects - Limitations on Passive
Activities" and " - Termination of a Partnership".)
Subject to the foregoing and to the consent of the Managing General
Partner the Partnership will recognize the assignment of one or more
whole Units unless the Participant owns less than a whole Unit, in which
case his entire fractional interest must be assigned. The Managing
General Partner may delay the recognition of the assignment until the
last day of the calendar month in which it is made.
Such assignment must be properly executed by the assignor and assignee
on a form satisfactory to the Managing General Partner and its terms
must not contravene those of the Partnership Agreement. An assignee of
Units only has the right to receive all or part of the share of profit,
loss, income, gain, cash distributions or return of capital to which the
assignor of the Units would otherwise be entitled. The Costs associated
with a transfer or assignment are to be borne by the assignor Partner.
An assignee may become a substituted Limited Partner or Investor General
Partner only upon meeting certain further conditions, which include: (i)
the assignor gives the assignee such right; (ii) the Managing General
Partner consents to such substitution, which consent shall be in the
Managing General Partner's absolute discretion; (iii) the assignee pays
to the Partnership all costs and expenses incurred in connection with
such substitution; and (iv) the assignee executes and delivers such
instruments, in form and substance satisfactory to the Managing General
Partner, necessary or desirable to effect such substitution and to
confirm the agreement of the assignee to be bound by all terms and
provisions of the Partnership Agreement. A substitute Limited Partner
or Investor General Partner is entitled to all of the rights
attributable to full ownership of the assigned Units, including the
right to vote.
The Partnership will amend its records at least once each calendar year
to effect the substitution of substituted Participants. Any transfer
permitted where the assignee does not become a substituted Limited
Partner or Investor General Partner will be effective as of midnight of
the last day of the calendar month in which it is made, or, at the
Managing General Partner's election, 7:00 A.M. of the following day.
CONVERSION OF UNITS BY INVESTOR GENERAL PARTNERS
The Investor General Partners will have their Units automatically
converted into Limited Partner interests and thereafter become Limited
Partners of the Partnership after substantially all of the Partnership
Wells have been drilled and completed. (See "Summary of the Offering -
Actions to be Taken by Managing General Partner to Reduce Risks of
Additional Payments by Investor General Partners".)
PLAN OF DISTRIBUTION
COMMISSIONS
The Units will be offered on a "best efforts" basis by Anthem
Securities, Inc., a registered broker-dealer which is a member of the
NASD and a wholly-owned subsidiary of Atlas Group, acting as Dealer-
Manager in all states other than Minnesota and New Hampshire, and by
other selected registered broker-dealers, which are members of the
NASD, acting as Selling Agents. Anthem Securities became an NASD
member firm in April, 1997, and has participated as Dealer-Manager in
one other Atlas sponsored Program. Bryan Funding, Inc., a member of
the NASD, will serve as Dealer-Manager in the states of Minnesota and
New Hampshire, and will receive the same compensation as Anthem
Securities, Inc. with respect to sales in those states. Best efforts
means that the Dealer-Manager and broker-dealers will not guarantee the
sale of a certain amount of Units.
The Dealer-Manager will manage and oversee the offering of the Units as
described above and will receive from the Partnership on each Unit sold
to investors a 2.5% Dealer-Manager fee, a 7.5% Sales Commission and a
.5% reimbursement of the Selling Agents' bona fide accountable due
diligence expenses. The 7.5% Sales Commission and the .5% reimbursement
of accountable due diligence expenses will be reallowed to the Selling
Agents. Atlas is also utilizing the services of three wholesalers: Mr.
Eric Koval, Mr. Bruce Bundy and Mr. Robert Gourlay. Mr. Koval is
associated with Anthem Securities, Inc., and Messrs. Bundy and Gourlay
are associated with Bryan Funding, Inc. The 2.5% Dealer-Manager fee will
be reallowed to the wholesalers for Agreed Subscriptions obtained
through such wholesalers' effort.
The offering will be made in compliance with Rule 2810 of the NASD
Conduct Rules and all compensation to broker-dealers and wholesalers,
regardless of the source, will be limited to 10% of the gross proceeds
of the offering, plus the reimbursement for bona fide accountable due
diligence expenses of .5% on each Agreed Subscription.
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<PAGE>107
All Dealer-Manager fees, Sales Commissions, due diligence reimbursements
and wholesaling fees will be aggregated and paid by the Managing General
Partner as a part of Organization and Offering Costs and will not be
deducted from subscription proceeds. Notwithstanding, the broker-dealers
and officers and directors of the Managing General Partner may purchase
Units in the offering on the same terms and conditions as other
investors net of Dealer-Manager fees, Sales Commissions, due diligence
reimbursements and wholesaling fees. Any Units purchased by the Managing
General Partner and its Affiliates will be held for investment and not
for resale.
Subject to the receipt of the minimum Partnership Subscription and the
checks having cleared the banking system, Dealer-Manager fees, Sales
Commission and accountable due diligence reimbursements will be paid to
the broker-dealers approximately every two weeks until the Offering
Termination Date. (See "Terms of the Offering - Partnership Closings and
Escrow".)
INDEMNIFICATION
The Dealer-Managers may be deemed underwriters as that term is defined
in the Securities Act of 1933, as amended, and the Sales Commissions and
Dealer-Manager fees may be deemed underwriting compensation. Atlas 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 Securities Act of 1933, as amended.
SALES MATERIAL
The Managing General Partner will utilize sales material in addition to
the Prospectus in connection with the offering of the Units. The sales
material will consist of a brochure entitled "Atlas-Energy for the
Nineties-Public #6 Ltd." and The Atlas Group, Inc.'s corporate profile.
(See "Management".) 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. Sales material must be preceded or accompanied
by this Prospectus. Although the information contained in the sales
material does not conflict with any of the information set forth herein,
such material does not purport to be complete. Sales material should not
be considered a part of or incorporated into this Prospectus or the
Registration Statement of which this Prospectus is a part.
ATLAS ALSO HAS NOT AUTHORIZED ANY PERSON TO MAKE ANY REPRESENTATION OR
STATEMENT TO BROKER-DEALERS, CONSULTANTS, ANY PROSPECTIVE SUBSCRIBER OR
ANY OTHER PERSON WHICH IS NOT CONSISTENT WITH THIS PROSPECTUS.
ACCORDINGLY, PROSPECTIVE SUBSCRIBERS SHOULD NOT BASE ANY INVESTMENT
DECISION ON ANY SUCH REPRESENTATION BY ANY PERSON.
LEGAL OPINIONS
Kunzman & Bollinger, Inc., has issued its opinion to the Managing
General Partner regarding the validity and due issuance of the Units
offered hereby and its opinion on material tax consequences to
individual investors in the Partnership, including an opinion that,
under current federal income tax law, it is more likely than not that
the Partnership will be classified as a partnership for federal income
tax purposes and not as an association taxable as a corporation.
Notwithstanding, the factual statements herein are those of 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
Partnership, Atlas Group (formerly AEGH) and subsidiaries as of July 31,
1996 and 1995, and for Atlas as of July 31, 1996 and 1995, have been
audited by McLaughlin & Courson, as of the date indicated in their
reports thereon which appear elsewhere herein. The financial statements
have been included in reliance on their reports given on their authority
as experts in auditing and accounting.
The geological report of United Energy Development Consultants, Inc.,
which is not affiliated with Atlas and its Affiliates, appearing in
"Proposed Activities - Information Regarding Currently Proposed
Prospects" has been included herein in reliance upon the authority of
United Energy Development Consultants, Inc. as an expert with respect to
the matters covered by such report and in the giving of such report.
LITIGATION
The Managing General Partner knows of no litigation pending or
threatened to which the Managing General Partner or the Partnership is
subject or may be a party, which it believes would have a material
adverse effect upon the Partnership or its business, and no such
proceedings are known to be contemplated by governmental authorities or
other parties. Notwithstanding, on November 22, 1995, Winston
Management Services Corporation ("Winston") and Professional Planning &
Technologies, Inc. ("PPT")
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<PAGE>108
filed a complaint in the United States
District Court for the District of Rhode Island against Atlas Resources,
Inc., Atlas Energy Group, Inc., and others. The gist of the complaint
is for the alleged breach of contract relating to the interpretation of
broker-dealer agreements entered into between Winston and PPT and Atlas
and Atlas Energy for the marketing of interests in limited partnerships
in 1987, 1988, 1989 and 1990. The complaint seeks compensatory damages
in an unspecified amount in excess of $50,000 plus an unspecified amount
of punitive damages together with interest and costs of the lawsuit.
Atlas believes the lawsuit is without merit and intends to fight it
vigorously.
ADDITIONAL INFORMATION
A Registration Statement (together with amendments thereto, hereinafter
referred to as the "Registration Statement") on Form SB-2 with respect
to the Units offered hereby has been filed on behalf of the Partnership
with the Securities and Exchange Commission, Washington, D.C. 20549,
under the Securities Act of 1933, as amended. This Prospectus does not
contain all of the information set forth in the Registration Statement,
certain portions of which have been omitted pursuant to the rules and
regulations of the Securities and Exchange Commission. Reference is made
to such Registration Statement, including exhibits, for further
information. Statements contained in this Prospectus as to the contents
of any document are not necessarily complete, and, in each instance,
reference is hereby made to the copy of such document filed as an
exhibit to the Registration Statement for full statements of the
provisions thereof, and each such statement in this Prospectus is
qualified in all respects by this reference. Copies of any materials
filed as a part of the Registration Statement, including the Tax Opinion
as set forth on Exhibit 8, may be obtained from the Securities and
Exchange Commission by payment of the requisite fees therefor and may be
examined in the offices of the Commission without charge. In addition, a
copy of the Tax Opinion may be obtained by prospective investors or
their advisors from the Managing General Partner at no cost. The
delivery of this Prospectus at any time does not imply that the
information contained herein is correct as of any time subsequent to the
date hereof.
Atlas is fully aware of its obligations under Rule 13e-4 of the
Securities Exchange Act of 1934. It is fully the intention of Atlas to
comply with Rule 13e-4 and to cause the Partnership to comply with Rule
13e-4.
FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL
PARTNER, ATLAS GROUP AND THE PARTNERSHIP
Financial information concerning the Partnership, Atlas and Atlas Group
(formerly AEGH) is reflected in the following financial statements. The
financial statements of Atlas Group are included in this Prospectus
because both Atlas and Atlas Group have agreed to indemnify each
Investor General Partner from any liability incurred in connection with
the Partnership which is in excess of such Investor General Partner's
share of Partnership assets. Since July, 1995, Atlas is the wholly
owned subsidiary of AIC, Inc. which is the wholly owned subsidiary of
Atlas Group. (See "Management".)
THE SECURITIES OFFERED BY THIS PROSPECTUS ARE NOT SECURITIES OF, NOR IS
THE INVESTOR ACQUIRING AN INTEREST IN ATLAS, ATLAS ENERGY, ATLAS GROUP,
THEIR AFFILIATES, OR ANY OTHER ENTITY OTHER THAN THE PARTNERSHIP.
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<PAGE>109
AUDITED FINANCIAL STATEMENT
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP JULY 1, 1997
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<PAGE>110
McLaughlin & Courson
Certified Public Accounts
2002 Law & Finance Building
Pittsburgh, PA 15219
INDEPENDENT AUDITORS' REPORT
To the Partners
Atlas-Energy for the Nineties-Public #6 Ltd.
A Pennsylvania Limited Partnership
We have audited the accompanying statement of assets and partner's
capital of Atlas-Energy for the Nineties-Public #6 Ltd., A Pennsylvania
Limited Partnership as of July 1, 1997. This financial statement is the
responsibility of the Partnership's management. Our responsibility is
to express an opinion on this financial statement based on our audit.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statement is free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statement. An audit also includes
assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable basis for
our opinion.
In our opinion, the financial statement referred to above presents
fairly, in all material respects, the financial position of AtlasEnergy
for the Nineties-Public #6 Ltd., A Pennsylvania Limited Partnership as
of July 1, 1997 in conformity with generally accepted accounting
principles.
/s/ McLaughlin & Courson
McLaughlin & Courson
Pittsburgh, Pennsylvania
July 11, 1997
BALANCE SHEET
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP
JULY 1, 1997
ASSETS
Receivable from managing general partner $100
PARTNER'S CAPITAL
Partner's capital $100
See notes to financial statement
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<PAGE>111
NOTES TO FINANCIAL STATEMENT
ORGANIZATION AND DESCRIPTION OF BUSINESS
Atlas-Energy for the Nineties-Public #6 Ltd. (the "Partnership"),
is a Pennsylvania limited partnership which will include Atlas
Resources, Inc. ("Atlas"), of Pittsburgh, Pennsylvania, as Managing
General Partner and Operator, and subscribers to Units as either Limited
Partners or Investor General Partners. The Partnership will be funded
to drill gas wells which are proposed to be located primarily in
Mercer County, Pennsylvania, although the Managing General Partner has
reserved the right to use up to 15% of the Partnership Subscription to
drill wells in other areas of the United States.
Subscriptions at a cost of $10,000 per unit will be sold through
wholesalers and broker-dealers including Anthem Securities, Inc., an
affiliated company which will be compensated in an amount equal to 10%
of the subscription cost plus a .5% accountable due diligence fee.
Commencement of Partnership operations is subject to the receipt of
minimum Partnership subscriptions of $1,000,000 (to a maximum of
$10,000,000 by December 31, 1997).
PROPOSED ACCOUNTING POLICIES
Financial statements are to be prepared in accordance with
generally accepted accounting principles.
The Partnership proposes to 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
are capitalized.
Capitalized costs are to be expensed at unit cost rates calculated
annually based on the estimated volume of recoverable gas and the
related costs.
FEDERAL INCOME TAXES
The Partnership is not treated as a taxable entity for federal
income tax purposes. Any item of income, gain, loss, deduction or
credit flows through to the partners as though each partner had incurred
such item directly. As a result, each partner must take into account
his pro rata share of all items of partnership income and deductions in
computing his federal income tax liability. Many provisions of the
federal income tax laws are complex and subject to various
interpretations.
PARTICIPATION IN REVENUES AND COSTS
Atlas and the other partners will generally participate in
revenues and costs in the following manner:
OTHER
ATLAS PARTNERS
Organization and offering costs 100 % 0 %
Lease costs 100 % 0 %
Revenues 25 % 75 %
Direct operating costs 25 % 75 %
Intangible drilling costs 0 % 100 %
Tangible costs 14 % 86 %
Tax deductions:
Intangible drilling and development costs 0 % 100 %
Depreciation 14 % 86 %
Depletion allowances 25 % 75 %
TRANSACTIONS WITH ATLAS AND ITS AFFILIATES
The Partnership intends to enter into the following significant
transactions with Atlas and its affiliates for wells in the Mercer
County Area.
Drilling contracts to drill and complete Partnership wells at
an anticipated cost of $37.39 per foot on completed wells.
Administrative costs at $75 per well per month
Well supervision fees initially of $275 per well per month
plus the cost of third party materials and services
Gas transportation and marketing charges at competitive rates
which currently is 29 cents per MCF
Anthem Securities is an affiliated company.
PURCHASE COMMITMENT
Subject to certain conditions, investor partners may present their
interests beginning in 2001 for purchase by Atlas. Atlas is not
obligated to purchase more than 5% of the units in any calendar year.
SUBORDINATION OF MANAGING GENERAL PARTNER'S REVENUE SHARE
Atlas will subordinate a part of its partnership revenues in an
amount up to 10% of production revenues of the Partnership net of
related operating costs, administrative costs and well supervision fees
to the receipt by participants of cash distributions from the
Partnership equal to at least 10% of their agreed subscriptions,
determined on a cumulative basis, in each of the first five years of
Partnership operations, commencing with the first distribution of
revenues to the Participants.
INDEMNIFICATION
In order to limit the potential liability of the investor general
partners, Atlas and The Atlas Group, Inc. (parent company of Atlas) have
agreed to indemnify each investor general partner from any liability
incurred which exceeds such partner's share of Partnership assets.
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<PAGE>112
AUDITED CONSOLIDATED BALANCE SHEETS
ATLAS RESOURCES, INC.
JULY 31, 1996
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<PAGE>113
McLaughlin & Courson
Certified Public Accounts
2002 Law & Finance Building
Pittsburgh, PA 15219
INDEPENDENT AUDITORS' REPORT
Board of Directors Atlas Resources, Inc.
Coraopolis, Pennsylvania
We have audited the accompanying consolidated balance sheets of
Atlas Resources, Inc. and subsidiary as of July 31, 1996 and 1995. 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 generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the balance
sheets are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
balance sheets. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall balance sheet presentation. We believe that our
audits of the balance sheets provide a reasonable basis for our opinion.
In our opinion, the consolidated balance sheets referred to above
present fairly, in all material respects, the financial position of
Atlas Resources, Inc. as of July 31, 1996 and 1995, in conformity with
generally accepted accounting principles.
/s./ McLaughlin & Courson
McLaughlin & Courson
Pittsburgh, Pennsylvania
November 11, 1996
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<PAGE>114
CONSOLIDATED BALANCE SHEETS
ATLAS RESOURCES, INC.
JULY 31, 1996 AND 1995
ASSETS
1996 1995
CURRENT ASSETS
Cash $ 9,303,958 $ 1,717,898
Trade accounts and notes receivable 2,080,317 1,639,274
Costs in excess of billings of $-0- in
1996 and 1995 on uncompleted contracts 244,856 291,379
Inventories 449,193 495,063
Prepaid expenses and other current assets 214,174 145,602
---------- ---------
TOTAL CURRENT ASSETS 12,292,498 4,289,216
OIL AND GAS PROPERTIES
Oil and gas wells and leases 28,359,364 23,195,675
Less accumulated depreciation, depletion and
amortization 9,108,310 6,454,328
--------- -----------
19,251,054 16,741,347
PROPERTY, PLANT AND EQUIPMENT
Land 161,000 161,000
Building 1,636,990 1,636,990
Equipment 778,844 778,237
Gathering lines 983,560 994,953
--------- ---------
3,560,394 3,571,180
Less accumulated depreciation 2,022,300 1,838,518
--------- ---------
1,538,094 1,732,662
---------- ---------
$33,081,646 $22,763,225
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses $ 2,053,489 $2,428,135
Working interests and royalties payable 3,501,547 1,741,474
Billings in excess of costs of $1,851,449
in 1996 and $1,486,813 in 1995 on
uncompleted contracts 10,405,362 5,455,355
Current maturities on long-term debt 185,714 246,014
---------- ---------
TOTAL CURRENT LIABILITIES 16,146,112 9,870,978
LONG-TERM DEBT, net of current maturities 928,572 1,114,286
OTHERLONG-TERM LIABILITIES 191,804 40,880
ADVANCES FROM PARENT COMPANY 4,491,561 4,548,448
STOCKHOLDERS' EQUITY
Capital stock - stated value $10
per share: Authorized - 500
shares; issued and outstanding - 200 shares 2,000 2,000
Retained earnings 11,321,597 7,186,633
---------- ---------
11,323,597 7,188,633
$33,081,646 $22,763,225
=========== ===========
See notes to financial statements
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<PAGE>115
NOTES TO AUDITED CONSOLIDATED BALANCE SHEETS
ATLAS RESOURCES, INC.
1. DESCRIPTION OF BUSINESS
Atlas Resources, Inc. (the Company) and its subsidiary ARD
Investments, are engaged in the exploration
for development, production, and marketing of natural gas and oil
primarily in the Appalachian Basin Area.
In addition, the Company performs contract drilling and well operation
services.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
AFFILIATED COMPANIES
Atlas Resources, Inc. is a wholly owned subsidiary of AIC,
Inc. which is a wholly owned subsidiary
of AEG Holdings, Inc. (AEGH) formerly Atlas Energy Group, Inc. (parent
company) and is affiliated with other
companies controlled by AEGH. The Company's operations are dependent
upon the resources and services
provided by the parent company.
INVESTMENT IN OIL AND GAS PARTNERSHIPS
The Company's proportionate share of the assets and
liabilities of affiliated oil and gas
partnerships are included in the balance sheets.
INVENTORIES
Inventories, consisting of oil and gas field materials and
supplies, are stated at the lower offirst-in, first-out cost or market.
METHOD OF ACCOUNTING FOR OIL AND GAS PROPERTIES
The Company uses the successful efforts method of accounting
for oil and gas producing activities. Property acquisition costs are
capitalized when incurred. Geological and geophysical costs and delay
rentals are expensed when incurred. Development costs, including
equipment and intangible drilling costs related to both producing wells and
developmental dry holes, are capitalized. All capitalized costs are
generally depreciated and depleted on the unit-of-production method
using estimates of proven reserves. Oil and gas properties are periodically
assessed and when unamortized costs exceed expected future net cash
flows, a loss is recognized by recording a charge to income.
On the sale or retirement of oil and gas properties, the cost
and related accumulated depreciation, depletion and amortization are eliminated
from the property accounts, and the resultant gainor loss is recognized.
For tax purposes, intangible drilling costs are being written
off as incurred. The greater of cost or percentage depletion as defined by the
Internal Revenue Code, is used as a deduction from income.
PROPERTY, PLANT AND EQUIPMENT
Land, building, equipment and gathering lines are recorded at
cost. Major additions and betterments are charged to the property accounts
while replacements, maintenance and repairs which do not improve or extend the
life of the respective assets are expensed currently. As property is retired
or otherwise disposed of, the cost of the property is removed from the asset
account, accumulated depreciation
is charged with an amount equivalent to the depreciation provided, and
the difference, if any, is charged or credited to income. Depreciation is
computed over the estimated useful life of the assets generally by the
straight-line method.
REVENUE RECOGNITION
The Company sells interests in oil and gas wells and retains
therefrom a working interest and/or an overriding royalty in the producing
wells. The income from the working interests and royalties is
recorded when the natural gas and oil are produced.
The Company also contracts to drill oil and gas wells. The
income from these contracts is recorded upon substantial completion of the
well.
Contract costs include all direct material and labor costs and
those indirect costs related to contract performance, such as indirect labor,
supplies, tools, repairs, and depreciation costs. General and
administrative costs are charged to expense as incurred. Provisions for
estimated losses on uncompleted contracts are made in the period in which such
losses are determined.
Costs in excess of amounts billed are classified as current
assets under costs in excess of billings on uncompleted contracts. Billings in
excess of costs are classified under current liabilities as
billings in excess of costs on uncompleted contracts. Contract
retentions are included in accountsreceivable.
USE OF ESTIMATES
The preparation of financial statements in conformity with
generally accepted accounting principles 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.
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<PAGE>116
3. INCOME TAXES
Atlas Resources, Inc. and its subsidiary file a consolidated
federal income tax return with AEG Holdings, Inc. (parent company). Atlas
Resources, Inc.'s allocations for federal income taxes are included
in advances from parent company.
4. LONG-TERM DEBT
Long-term debt on Atlas Resources, Inc.'s books at July 31, 1996
and 1995 consists of the following:
1996 1995
Note payable to bank in monthly installments
through August 2002 of $15,476, plus interest at or below
prime rate plus one-half percent (1/2%) (7.88% and 8.125%
at July 31, 1996 and 1995, respectively). Secured by
building and equipment having a net book value of
$1,245,216 at July 31, 1996. The July 31, 1995 balance
sheet has been reclassified to reflect the transfer
of this liability to Atlas Resources, Inc. $1,114,286 $1,300,000
Other -0- 60,300
1,114,286 1,360,300
Less current maturities (185,714) (246,014)
$ 928,572 $1,114,286
Aggregate maturities on long-term debt are as follows:
YEAR ENDING JULY 31
1997 185,714
1998 185,714
1999 185,714
2000 185,715
2001 185,715
-------
$928,572
========
5. REVOLVING CREDIT AND TERM LOAN AGREEMENT
A revolving credit and term loan agreement enables the Company or
AEGH to borrow $5,000,000 on a revolving credit basis until August 1, 1997. A
commitment fee at a rate of three-eights of one percent
(3/8%) is charged on the unused portion. During the revolving credit
period, loans bear interest at or below prime rate plus one-quarter percent
(1/4%). The interest rate at July 31, 1996 was 8.50%. The Company may convert
any outstanding borrowings into a 5-year term loan, repayable in equal monthly
installments, plus interest at or below prime rate plus one-half percent
(1/2%). At July 31, 1996 AEGH (parent company) had borrowed $4,750,000 under
the revolving credit line.
The revolving credit line and term loan agreements are secured by
certain assets of the Company.
6. OPTION ON BUILDING
AEGH (parent company) has granted the majority shareholders of AEGH
an option to acquire the land and building utilized as the Company's
headquarters for a period of six months commencing on August 15, 2003 and
ending February 15, 2004 for $500 ,000.
7. COMMITMENTS
Atlas Resources, Inc., as general partner in several oil and gas
limited partnerships, and AEGH have agreed to indemnify each investor general
partner from any liability incurred which exceeds such partner's
share of partnership assets. Management believes that any such
liabilities that may occur will be covered by insurance and, if not covered by
insurance, will not result in a significant loss to AEGH and its
subsidiaries.
Subject to certain conditions, investor general partners in certain
oil and gas limited partnerships may present their interests beginning in 1996
for purchase by Atlas Resources, Inc., as managing general
partner. Atlas Resources, Inc. is not obligated to purchase more than
5% of the units in any calendar year.
Atlas Resources, Inc., as managing general partner in a certain oil
and gas limited partnership, has also agreed to subordinate its share of
production revenues to the receipt by investor partners of cash
distributions equal to at least 10% of their subscriptions in each of
the first five years of partnership operations.
- ----------------------------------------------------------------------------
<PAGE>117
8. FUTURES CONTRACTS
The Company enters into natural gas futures contracts to hedge its
exposure to changes in natural gas prices. At any point in time, such
contracts may include regulated
NYMEX
futures contracts and non- regulated over-the-counter futures contracts with
qualified counterparties. The futures contracts employed
by the Company are commitments to purchase or sell natural gas at a
future date and generally cover one month periods for up to 18 months in the
future. Realized gains (losses) are recorded in the income
accounts in the month(s) that the futures contracts are intended to
hedge. Unrealized gains (losses) are deferred until realized. Deferred gains
(losses) were $115,240 and $- 0 at July 31, 1996 and 1995, respectively.
9. IMPAIRMENT OF ASSETS
In 1996 the Company evaluated the carrying value of long-lived
assets for impairment of value in accordance with the Statement of Financial
Accounting Standards No. 121 "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of." The
Company recognized a noncash write-down in the carrying value of oil and gas
properties of $1,700,000 which primarily was a result of the sustained
decrease in gas and oil prices. The write-down was determined based
upon the estimated future net cash flows from the properties.
10. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
The supplementary information summarized below presents the results
of natural gas and oil activities in accordance with SFAS No. 69, "Disclosures
About Oil and Gas Producing Activities."
(1) PRODUCTION COSTS
The following table presents the costs incurred relating to natural
gas and oil production activities:
1996 1995
Capitalized costs at July 31:
Capitalized costs $28,359,364 $23,195,675
Accumulated depreciation and depletion (9,108,310) (6,454,328)
----------- ----------
Net capitalized costs $19,251,054 $16,741,347
Costs incurred during the year ended July 31:
Property acquisition costs -
proved undeveloped properties
$ $ 15,000 $ -0-
=========== ===========
Development costs $ 6,863,689 $ 4,669,626
=========== ===========
Property acquisition costs include costs
to purchase, lease or otherwise acquire a property.
Development costs include costs to gain access to and prepare
development well locations for drilling, to drill and equip development wells
and to provide facilities to extract, treat, gather and store oil and gas.
(2) RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
The following table presents the results of operations related to
natural gas and oil production for
the years ended July 31, 1996 and 1995:
1996 1995
Revenues $ 4,011,924 $ 2,991,813
Production costs (248,743) (185,356)
Depreciation and depletion (2,653,982) (1,072,962)
Income tax expense (122,726) (364,315)
---------- ------------
Results of operations from
producing activities $986,473 $ 1,369,180
========== ===========
Depreciation, depletion and amortization of natural gas and oil
properties are provided on the unit- of-production method.
- -----------------------------------------------------------------------------
<PAGE>118
10. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
(3) RESERVE INFORMATION
The information presented below represents estimates of proved
natural gas and oil reserves. Proved
developed reserves represent only those reserves expected to be
recovered from existing wells and support
equipment. Proved undeveloped reserves represent proved reserves
expected to be recovered from new wells
after substantial development costs are incurred. All reserves are
located in Eastern Ohio and Western
Pennsylvania.
1996 1995
NATURAL GAS OIL NATURAL GAS OIL
(MCF) (BARRELS) (MCF) (BARRELS)
(BARRELS)
Proved developed and undeveloped reserves:
Beginning of period 57,211,350 13,596 50,226,287 7,386
Revision of
previous estimates 2,320,454 (5,713) (684,821) 6,816
Extensions,
discoveries and
other additions 11,720,742 -0- 21,535,654 -0-
Production (1,720,056) (1,551) (1,499,244) (606)
Sales of
minerals in place (12,673,528) -0- (12,366,526) -0-
----------- ------ ---------- ------
End of period 56,858,962 6,332 57,211,350 13,596
Proved =========== ======= ========= ======
developed reserves:
Beginning of period 17,378,470 13,596 14,603,407 7,386
============= ======= ========== ======
End of period 20,276,092 6,332 17,378,470 13,596
============= ======= ========== ======
(4) STANDARD MEASURE OF DISCOUNTED FUTURE CASH FLOWS
Management cautions that the standard measure of discounted future
cash flows should not be viewed as
an indication of the fair market value of natural gas and oil producing
properties, nor of the future cash
flows expected to be generated therefrom. The information presented
does
not give recognition to future
changes in estimated reserves, selling prices or costs and has been
discounted at an arbitrary rate of 10%.
Estimated future net cash flows from natural gas and oil reserves based
on selling prices and costs at July
31, 1996 and July 31, 1995 price levels are as follows:
1996 1995
Future cash inflows $121,474,607 $128,363,532
Future production costs (27,878,540) (27,812,401)
Future development costs (34,814,000) (41,574,000)
Future income tax expense (11,560,671) (11,406,096)
------------- -------------
Future net cash flow 47,221,396 47,571,035
10% annual discount for
estimated timing of cash flows
(32,795,257) (35,761,224)
------------- ------------
Standardized measure of
discounted future net cash flows $14,426,139 $ 11,809,811
============== ============
Summary of changes in the standardized measure of discounted future
net cash flows:
1996 1995
Sales of gas and oil produced - net $ (986,473) $(1,369,180)
Net changes in prices,
production and development costs (3,426,850) (3,969,631)
Extensions, discoveries, and
improved recovery, less
related costs 178,794 58,615
Development costs incurred 4,686,481 5,081,411
Revisions of previous quantity estimates 1,555,239 (330,491)
Sales of minerals in place (464,705) (1,216,889)
Accretion of discount 1,633,496 1,006,878
Net change in income taxes (559,654) 676,087
------------- -----------
Net increase (decrease) 2,618,328 (63,200)
Beginning of period 11,809,811 11,873,011
------------ -----------
End of period $ 14,426,139 $11,809,811
============= ===========
- --------------------------------------------------------------------------
<PAGE>119
ATLAS RESOURCES, INC., ,
CONSOLIDATED BALANCE SHEET (UNAUDITED), ,
AS OF MAY 31, 1997,
- --------------------------------------------------------------------------
<PAGE>120
1997 1996
ASSETS
CURRENT ASSETS, ,
Cash and cash equivalents, $420,980 , $332,109
Trade accounts receivable, 2,742,332 , 2,866,783
Accounts receivable from affiliates, 2,143,125 , 0
Costs in excess of billings on
uncompleted contracts, 0 , 407,849
Inventories, 7,498 , 496,391
Other current assets, 97,936 , 20,701
TOTAL CURRENT ASSETS, 5,621,871 , 4,123,833
, ,
OIL AND GAS PROPERTIES, ,
Oil and gas wells and leases, 30,552,053 ,28,558,094
Less accumulated depreciation,
depletion and amortization, 11,255,305 , 7,700,321
NET OIL & GAS PROPERTIES, 19,296,748 ,20,857,773
, ,
OTHER ASSETS, 133,123 , 2,613
, ,
PROPERTY, PLANT AND EQUIPMENT, ,
Land, 174,385 , 161,000
Buildings, 2,371,519 , 1,641,671
Equipment, 864,954 , 779,253
Gathering Lines, 1,050,124 , 978,879
Sub-total, 4,460,982 , 3,560,803
Less accumulated depreciation, 2,155,348 , 1,974,462
NET PROPERTY, PLANT & EQUIPMENT, 2,305,634 , 1,586,341
, ,
TOTAL ASSETS, $27,357,376 $26,570,560
, , =======================
, ,
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES, ,
Accounts payable and accrued expenses, $2,985,198 $3,705,281
Working interests and royalties payable, 5,527,672 4,900,058
Billings in excess of costs
on uncompleted contracts, 950,425 , 1,356,043
Current maturities on long-term debt:, 185,714 , 185,714
Income taxes payable, 538,145 , 885,868
TOTAL CURRENT LIABILITIES, 10,187,154 11,032,964
, ,
LONG-TERM DEBT, net of current maturities, 773,810 , 959,524
, ,
ADVANCES FROM AFFILIATED COMPANIES, 1,650,000 , 584,193
, ,
DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES, 83,000 , 708,801
, ,
STOCKHOLDERS' EQUITY, ,
Capital stock, stated value $10.00:
Authorized - 500 shs; Issued - 200 shs., 2,000 , 2,000
Retained earnings, 14,661,412 ,13,283,078
TOTAL STOCKHOLDERS' EQUITY, 14,663,412 ,13,285,078
, ,
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY, $27,357,376 $26,570,560
, =======================
- ----------------------------------------------------------------------
<PAGE>121
ATLAS RESOURCES, INC., ,
CONSOLIDATED STATEMENT OF INCOME (UNAUDITED), ,
TEN MONTHS ENDED MAY 31, 1997, ,
INCOME 1997 1996
Sales-gas wells, $16,682,188 , $16,302,706
Purchased gas revenues, 3,765 , 1,470
Well operating fees, 1,707,477 , 1,841,788
Working interest and royalties, 3,778,551 , 3,213,021
Non-recurring income (Note 2), 0 , 2,059,179
Interest Income, 72,635 , 84,495
Other, 351,404 , 542,066
TOTAL INCOME, 22,596,020 , 24,044,725
, ,
COST OF SALES AND OTHER EXPENSES, ,
Costs of sales-gas wells, 13,278,965 , 11,881,671
Cost of purchased gas, 2,189 , 1,365
Cost of well operations, 744,887 , 298,533
General and administrative, 892,997 , 2,003,215
Interest expense, 133,192 , 181,431
Depreciation, depletion and amortization, 2,200,745 , 1,381,937
TOTAL COST OF SALES AND OTHER EXPENSES, 17,252,975 , 15,748,152
, ,
INCOME BEFORE INCOME TAXES, 5,343,045 , 8,296,573
, ,
INCOME TAXES, 1,503,230 , 2,202,302
, ,
NET INCOME, $3,839,815 , $6,094,271
, , ========== ==========
, ,
, ,
ATLAS RESOURCES, INC., ,
CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED), ,
TEN MONTHS ENDED MAY 31, 1997, ,
, ,
1997 1996
NET CASH PROVIDED BY OPERATING ACTIVITIES, $(2,293,378), $ 8,144,146
, ,
CASH FLOW FROM INVESTING ACTIVITIES:, ,
Investment in oil and gas wells
and property, plant and equipment, (3,093,277), (5,352,042)
, ,
CASH FLOWS USED IN FINANCING ACTIVITIES:, ,
Borrowings from banks, (154,762), 1,084,938
Repayment of advances from affiliates, (2,841,561), (5,262,831)
Dividends to parent company, (500,000), 0
Net cash used in financing activities, (3,496,323), (4,177,893)
, ,
Net increase (decrease) in cash and
cash equivalents, (8,882,978), (1,385,789)
, ,
Cash and cash equivalents at beginning of year, 9,303,958 , 1,717,898
, ,
Cash and cash equivalents at end of period, $420,980 , $332,109
, , ============= ===========
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<PAGE>122
ATLAS RESOURCES, INC.
NOTE TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
MAY 31, 1997
1. INTERIM FINANCIAL STATEMENTS
The consolidated financial statements as of May 31, 1997 and for the ten
months then ended have been prepared by the management of the Company, without
audit, pursuant to the rules and regulations of the Securities and Exchange
Commission. Certain information and foot note disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been omitted pursuant to such rules and regulations,
although the Company believes that the disclosures are adequate to
make the information presented not misleading. These consolidated
financial statements should be read in conjunction with the audited July 31,
1996 and 1995 consolidated financial statements. In the opinion of
management, all adjustments (consisting of only normal recurring
accruals) considered necessary for presentation have been included.
2. The non-recurring income item in the period ended May 31, 1996
pertains to a settlement of certain claims with Columbia Gas Transmission
Corporation.
- -------------------------------------------------------------------------------
<PAGE>123
AUDITED CONSOLIDATED FINANCIAL STATEMENTS
AEG HOLDINGS, INC.
JULY 31, 1996
<PAGE>124
McLaughlin & Courson
Certified Public Accountants
2002 Law & Finance Building
Pittsburgh, PA 15219
INDEPENDENT AUDITORS' REPORT
Board of Directors
AEG Holdings, Inc.
Coraopolis, Pennsylvania
We have audited the accompanying consolidated statements of
financial position of AEG Holdings, Inc. and subsidiaries as of July 31, 1996
and 1995, and the related consolidated statements of income 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 generally accepted
auditing standards. 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 financial position of AEG Holdings, Inc.
as of July 31, 1996 and 1995, and the results of its operations
and its cash flows for the years then ended in conformity with generally
accepted accounting principles.
/s/McLaughlin & Courson
McLaughlin & Courson
Pittsburgh, Pennsylvania
November 11, 1996
- --------------------------------------------------------------------------
<PAGE>125
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AEG HOLDINGS, INC.
JULY 31, 1996 AND 1995
ASSETS
1996 1995
CURRENT ASSETS
Cash and cash equivalents $13,914,902 $8,224,721
Trade accounts and notes receivable
, less allowance for doubtful
accounts of $200,000 in 1996 and
$100,000 in 1995 6,073,523 3,278,178
Other receivables 253,159 501,174
Costs in excess of billings of $-0- in
1996 and 1995 on uncompleted contracts 238,555 293,372
Inventories 449,193 495,063
Prepaid expenses and other current assets 792,573 409,969
---------- ----------
TOTAL CURRENT ASSETS 21,721,905 13,202,477
OIL AND GAS PROPERTIES
Oil and gas wells and leases 31,927,784 28,185,190
Less accumulated depreciation,
depletion and amortization
12,211,283 10,518,131
---------- ----------
19,716,501 17,667,059
OTHER ASSETS 308,127 294,851
PROPERTY, PLANT AND EQUIPMENT
Land 380,568 359,193
Buildings 1,805,471 1,785,776
Equipment 1,168,561 1,025,609
Gathering lines 18,444,239 16,666,091
---------- ----------
21,798,839 19,836,669
Less accumulated depreciation 13,331,940 11,695,999
---------- ----------
8,466,899 8,140,670
---------- ----------
$50,213,432 $39,305,057
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses $ 6,008,372 $5,007,209
Working interests and royalties payable 4,077,102 2,217,294
Billings in excess of costs of $2,011,277
in 1996 and $1,636,992
in 1995 on uncompleted contracts 10,412,624 5,472,266
Current maturities on long-term debt:
Subordinated notes payable to
stockholders 1,669,661 1,461,795
Other 185,714 246,014
Income taxes payable 998,873 234,057
---------- ----------
TOTAL CURRENT LIABILITIES 23,352,346 14,638,635
DEFERRED INCOME TAXES 655,000 1,330,000
LONG-TERM DEBT, net of current maturities:
Subordinated notes payable to stockholders 3,255,273 4,924,934
Other 5,678,572 5,864,286
OTHER LONG-TERM LIABILITIES 310,046 265,640
STOCKHOLDERS' EQUITY
Capital stock, no par; authorized
2,000,000 shares; issued 500,000
shares 1,250 1,250
Paid-in capital 560,093 560,093
Retained earnings 21,892,247 17,351,614
Treasury stock, at cost
(137,419 shares and 140,919 shares,
respectively) (5,491,395) (5,631,395)
----------- ----------
16,962,195 12,281,562
----------- -----------
$50,213,432 $39,305,057
b =========== ===========
See notes to consolidated financial statements
- ---------------------------------------------------------------------------
<PAGE>126
CONSOLIDATED STATEMENTS OF INCOME
AEG HOLDINGS, INC.
YEARS ENDED JULY 31, 1996 AND 1995
1996 1995
INCOME
Sales - gas wells $20,482,825 $22,707,513
Purchased gas revenues 47,293,957 12,602,845
Well operating fees 3,262,835 3,132,886
Gathering line charges 2,605,816 1,970,964
Working interests and royalties 4,796,736 3,903,888
Interest 236,210 151,749
Non-recurring income 4,370,000 -0
Other 426,225 198,925
----------- ------------
83,474,604 44,668,770
COSTS OF SALES AND OTHER EXPENSES
Costs of sales - gas wells 16,898,962 19,216,912
Cost of purchased gas 47,326,785 12,987,224
Gathering line operation and maintenance 1,856,801 1,592,691
General and administrative 3,677,756 3,221,659
Interest:
Subordinated notes payable to
stockholders 749,469 925,139
Other 304,973 268,162
Depreciation, depletion and amortization 3,961,725 2,711,514
Impairment of assets 2,370,000 -0-
---------- ----------
77,146,471 40,923,301
----------- ----------
INCOME BEFORE INCOME TAXES 6,328,133 3,745,469
INCOME TAXES
Current:
Federal 1,850,000 380,000
State 630,000 240,000
Deferred (675,000) 230,000
--------- -------
1,805,000 850,000
--------- -------
NET INCOME $ 4,523,133 $ 2,895,469
=========== ===========
See notes to consolidated financial statements
- ---------------------------------------------------------------------------
<PAGE>127
CONSOLIDATED STATEMENTS OF CASH FLOWS
AEG HOLDINGS, INC.
YEARS ENDED JULY 31, 1996 AND 1995
1996 1995
Cash flows from operating activities:
Net income $ 4,523,133 $ 2,895,469
Adjustments to reconcile net income to
net cash provided by
operating activities:
Depreciation, depletion and amortization 3,961,725 2,711,514
Impairment of assets 2,370,000 -0-
Expense funded by issuance of
capital stock 157,500 172,200
Other, net 14,700 (3,579)
Change in assets and liabilities:
Receivables (2,547,330) 1,180,462
Inventories 45,870 73,492
Prepaid expenses and other current assets (382,604) (144,242)
Accounts payable and accrued expenses and
working interests and royalties payable 2,860,971 183,252
Uncompleted contract billings, net 4,995,175 515,791
Income taxes payable 764,816 (176,295)
Deferred income taxes (675,000) 230,000
Long-term liabilities 44,406 (88,481)
---------- ---------
Net cash provided by operating activities 16,133,362 7,549,583
Cash flows used in investing activities:
Proceeds from sale of assets -0- 47,000
Investment in oil and gas wells and leases (6,745,226) (4,753,547)
Liquidations of other assets, net (13,276) 6,091
Gathering line additions (1,778,148) (1,218,666)
Other property additions (184,022) (196,250)
----------- -----------
Net cash used in investing activities (8,720,672) (6,115,372)
Cash flows (used in) provided by
financing activities:
Proceeds from long-term borrowings 4,750,000 6,050,000
Principal payments on long-term borrowings(4,935,714) (4,000,000)
Principal payments on notes payable
to stockholders (1,461,795) (1,279,808)
Principal payments on other term loans (75,000) (475,000)
Net cash (used in) provided ---------- ----------
by financing activities
(1,722,509) 295,192
------------ -----------
Net increase in cash and cash equivalents 5,690,181 1,729,403
Cash and cash equivalents at beginning of year 8,224,721 6,495,318
Cash and cash equivalents at end of year $13,914,902 $8,224,721
=========== ==========
Additional Cash Flow Information:
Cash paid during the year for:
Interest $ 1,045,235 $ 1,196,345
Income taxes 1,715,184 796,295
See notes to consolidated financial statements
- -----------------------------------------------------------------------------
<PAGE>128
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AEG HOLDINGS, INC.
1. DESCRIPTION OF BUSINESS
AEG Holdings, Inc. (AEGH) was formed in July, 1995 to hold, through
its wholly owned subsidiary AIC,Inc. also formed in July, 1995, Atlas Energy
Group and its subsidiaries,including Atlas Resources, Inc. and
Atlas Gas Marketing, Inc. The purpose of the reorganization is to
achieve more efficient concentration offunds of the Atlas group of companies,
thereby minimizing transaction costs and maximizing returns on
investment vehicles. No changes in the consolidated assets, liabilities
or stockholders' equity occurred as a result of the reorganization.
AEGH and subsidiaries are engaged in the exploration for,
development, production, and marketing of natural gas and oil primarily in the
Appalachian Basin area. In addition, the Company performs contract
drilling and well operation services.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of
AEG Holdings, Inc., and its subsidiaries. All significant intercompany
accounts and transactions have been eliminated in consolidation.
INVENTORIES
Inventories, consisting of oil and gas field materials and
supplies, are stated at the lower of first-in, first-out cost or market.
METHOD OF ACCOUNTING FOR OIL AND GAS PROPERTIES
The Company uses the successful efforts method of accounting
for oil and gas producing activities.
Property acquisition costs are capitalized when incurred. Geological
And geophysical costs and delay rentals are expensed when incurred.
Development costs, including equipment and intangible drilling costs
related to both producing wells and developmental dry holes, are
capitalized. All capitalized costs are generally depreciated and depleted on
the unit-of-production method using estimates of proven reserves. Oil
and gas properties are periodically assessed and when unamortized costs
exceed expected future net cash flows, a loss is recognized by recording a
charge to income.
On the sale or retirement of oil and gas properties, the cost
and related accumulated depreciation, depletion and amortization are eliminated
from the property accounts, and the resultant gain or loss is recognized.
For tax purposes, intangible drilling costs are being written
off as incurred. The greater of cost or percentage depletion as defined by the
Internal Revenue Code, is used as a deduction from income.
PROPERTY, PLANT AND EQUIPMENT
Land, buildings, equipment and gathering lines are recorded at
cost. Major additions and betterments are charged to the property accounts
while replacements, maintenance and repairs which do not
improve or extend the life of the respective assets are expensed
currently. As prope rty is retired or otherwise disposed of, the cost of the
property is removed from the asset
account, accumulated depreciation is charged with an amount equivalent to the
depreciation provided, and the difference, if any, is charged or
credited to income. Depreciation is computed over the estimated useful
life of the assets generall y by the straight-line method.
REVENUE RECOGNITION
The Company sells interests in oil and gas wells and retains
therefrom a working interest and/or overriding royalty in the producing wells.
The income from the working interests is recorded when the
natural gas and oil are produced.
The Company also contracts to drill oil and gas wells. The
income from these contracts is recorded upon substantial completion of the
well.
Contract costs include all direct material and labor costs and
those indirect costs related to contract performance, such as indirect labor,
supplies, tools, repairs, and depreciation costs. General and
administrative costs are charged to expense as incurred. Provisions for
estimated losses on uncompleted contracts are made in the period in which such
losses are determined.
Costs in excess of amounts billed are classified as current assets
under costs in excess of
billings on uncompleted contracts. Billings in excess of costs are
classified under current liabilities as billings in excess of costs on
uncompleted contracts. Contract retentions are included in accounts
receivable.
WORKING INTERESTS AND ROYALTIES
Revenues from working interests and royalties are recognized
when the natural gas and oil are produced. For the year ended July 31, 1996,
the Company recognized working interest income of $3,800,437
and royalty income of $996,299. Working interest and royalty income
during the year ended July 31, 1995 amounted to $3,008,027 and $895,861,
respectively.
- ------------------------------------------------------------------------
<PAGE>129
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
CASH EQUIVALENTS
For purposes of the statements of cash flows, the Company
considers all highly liquid investments purchased with a maturity of three
months or less to be cash equivalents.
USE OF ESTIMATES
The preparation of financial statements in conformity with
generally accepted accounting principles 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. AFFILIATED OIL AND GAS PARTNERSHIPS
In connection with the sponsorship of oil and gas partnerships,
the Company is reimbursed by the partnerships for certain operating and
overhead costs incurred on their behalf. These reimbursements
totalled approximately $320,000 and $265,000 during the years ended July
31, 1996 and 1995, respectively. In addition, as part of its duties as well
operator, the Company receives proceeds from the sale of oil and
gas and makes distributions to investors according to their working
interest in the related oil and gas properties.
4. PLAN OF REORGANIZATION
On November 8, 1990 the Company adopted a plan of reorganization
whereby a substantial portion of the common stock of the two majority
shareholders would be purchased by the Company and shares of the Company's
stock would be granted to certain key employees of the Company
(Management Investors) giving the Management Investors control of the Company.
PURCHASE OF TREASURY SHARES AND NOTES PAYABLE TO STOCKHOLDERS
On November 14, 1990 the Company entered into an agreement
effective as of August 16, 1990 to purchase 248,717 shares of common stock from
its two majority shareholders at $40.00 per share ($9,948,680).
The purchase price is evidenced by promissory notes bearing
interest at 13.5%. Quarterly principal payments range from $100,574 on
November 15, 1991 to a final payment of $856,103 on November 15,
1998. Payments may be deferred or accelerated under certain
circumstances. Principal payments totaled $1,461,795 and $1,279,808 during the
years ended July 31, 1996 and 1995 respectively. Interest expense
amounted to $749,469 and $925,139 for the years ended July 31, 1996 and
1995, respectively.
The notes are subordinate to all direct and indirect debt,
past, present or future and all obligations, if any, to make contributions to
any employee stock ownership plan now in existence or
hereinafter created .
The promissory notes are secured by warrants on the common
stock of the Company that are exercisable upon an uncorrected event of default.
At July 31, 1996 and 1995, the following warrants were
outstanding:
1996 1995
Number of shares 382,668 643,824
Exercise price 12.87 9.92
The Company has options to purchase, and the majority
shareholders had options to sell 131,425 shares of the Company's common stock
at per share prices ranging from $63.25 to $74.10 commencing on the
earlier of the satisfaction of all the Company's obligations under the
foregoing promissory notes or November 14, 1999. The shareholders also had an
option on November 14, 2004 to sell 87,356 shares to the
Company. The shareholder options to sell the 218,781 shares of common
stock to the Company were waived on November 24, 1992 and the waiver has been
retroactively applied in the accompanying financial statements.
- -----------------------------------------------------------------------------
<PAGE>130
STOCK GRANTS
The Company has established a management employee stock option
consisting of an aggregate of options to acquire 47,578 shares of common stock
at $1.00 per share. No options have been granted as of
July 31, 1996. The option will terminate August 15, 2012.
There are restrictions on the sale of the vested Management
Investor and ESOP shares of common stock which include among other
restrictions, that shares may not be sold until obligations to the majority
shareholders are satisfied. Shares offered for sale must first be
offered to the Company and then to other shareholders before being offered to a
third party. Further conditions apply to sales that would result in
a third party owning 5% or more of the total shares of the Company.
5. OTHER LONG-TERM DEBT AND CREDIT FACILITY
Long-term debt at July 31, 1996 and 1995 consists of the following:
1996 1995
Revolving credit loan payable to bank $4,750,000 $4,750,000
Note payable to bank in monthly installments through August 2002
of $15,476, plus interest at or below prime rate plus one-half
percent (1/2%) (7.88% and 8.125% at July 31, 1996 and 1995,
respectively). Secured by building and equipment having a net
book value of $1,245,216 at July 31, 1996 1,114,286 1,300,000
Other -0- 60,300
---------- ---------
5,864,286 6,110,300
Less current maturities (185,714) (246,014)
----------- --------
$5,678,572 $5,864,286
========== ==========
The revolving credit and term loan agreement enables the
Company to borrow $5,000,000 on a revolving basis until August 1, 1997. A
commitment fee at a rate of three-eights of one percent (3/8%) is
charged on the unused portion. During the revolving credit period,
loans bear interest at or below prime rate plus one-quarter percent (1/4%).
The interest rate at July 31, 1996 was 8.50%. The agreement provides
that the Company may convert any outstanding borrowings into a 5 year
term loan, payable in equal monthly installments, plus interest at or below
prime rate plus one-half percent (1/2%).
The loan agreements are secured by certain assets of the
Company.
6. MATURITIES ON LONG-TERM DEBT
Aggregate maturities on long-term debt at July 31, 1996 for the
next five fiscal years are as follows:
FISCAL SUBORDINATED OTHER
YEAR NOTES PAYABLE LONG-TERM
ENDING TO STOCKHOLDERS DEBT TOTAL
1997 $1,669,661 $ 185,714 $1,855,375
1998 1,907,084 1,135,714 3,042,798
1999 1,348,189 1,135,714 2,483,903
2000 -0- 1,135,714 1,135,714
2001 -0- 1,135,714 1,135,714
7. INCOME TAXES
Net deferred tax liabilities consist of the following:
JULY 31,
1996 1995
Exploration and development costs expensed
for income tax reporting $1,210,000 $1,782,000
Tax credits (280,000) (601,000)
Other (275,000) 149,000
----------- -----------
$ 655,000 $1,330,000
========== ==========
A reconciliation between the Company's effective tax rate and the
U.S. statutory rate is as follows:
1996 1995
U.S. statutory rate 34.0 % 34.0 %
State income taxes net of federal
income tax benefit 4.5 5.8
Depletion (3.5) (7.0)
Nonconventional fuels and
alternative minimum tax credits (9.2) (10.0)
Other 2.7 (0.1)
Effective tax rate 28.5 % 22.7 %
- ---------------------------------------------------------------------------
<PAGE>131
8. PROFIT SHARING PLAN
The Company maintains a defined contribution 401 (K) profit sharing
plan covering substantially all of its employees. The Plan Administrator set
the maximum allowable employee contribution at the lesser of 15%
of their compensation or $9,500 and $9,240 for the calendar years 1996
and 1995, respectively. The Company matches employee contributions by
contributing an amount equal to 50% and 30% of each employee's
contribution for the calendar years 1996 and 1995, respectively.
Pension expense under the 401 (K) profit sharing plan was $118,083 and $67,974
for the years July 31, 1996 and 1995, respectively.
9. OPTION ON BUILDING
The majority shareholders were granted an option to acquire the
land and building utilized as the Company's headquarters for a period of six
months commencing on August 15, 2003 and ending February 15, 2004
for $500,000.
10. CHANGES IN STOCKHOLDERS' EQUITY
Changes in stockholders' equity during the years ended July31, 1996 and 1995
were as follows:
CAPITAL PAID-IN RETAINED TREASURY
STOCK CAPITAL EARNINGS STOCK
BALANCE AT JULY 31, 1994 $1,250 $560,093 $14,451,945 $(5,784,760)
Treasury stock issued to ESOP
(3,000 shares) 3,000 120,000
Other (700 shares net) 1,200 33,365
Net income for the year 2,895,469
----------------------------------------------------
BALANCE AT JULY 31, 1995 1,250 560,093 17,351,614 (5,631,395)
Treasury stock issued to ESOP
(3,000 shares) 15,000 120,000
Other (500 shares) 2,500 20,000
------------------------------------------------------
Net income for the year 4,523,133
$1,250 $560,093 $21,892,247 $(5,491,395)
======= ======== =========== ============
11. EMPLOYEE STOCK OWNERSHIP PLAN
Effective August 1, 1990 the Company established a non-
contributory employee stock ownership plan (ESOP) covering substantially all
employees except the Company's two majority shareholders. The Company
contributed 3,000 shares of common stock with a fair market value of
$45.00 ($135,000) and $41.00 ($123,000) to the plan during the years ended July
31, 1996 and 1995, respectively. The Company also contributed
$28,134 and $26,418 in cash during the years ended July 31, 1996 and
1995, respectively. Employee benefits vest after five years of service,
including service prior to establishment of the plan. There are
restrictions on the sale of the stock (see Plan of Reorganization).
12. FUTURES CONTRACTS
The Company enters into natural gas futures contracts to hedge
its exposure to changes in natural gas prices. At any point in time, such
contracts may include regulated NYMEX futures contracts and non-
regulated over-the-counter futures contracts with qualified
counterparties. The futures contracts employed by the Company are commitments
to purchase or sell natural gas at a future date and generally cover one
month periods for up to 18 months in the future. Realized gains
(losses) are recorded in the income accounts in the month(s) that the futures
contracts are intended to hedge. Unrealized gains (losses) are
deferred until realized. Deferred gains (losses) were ($3,190) and $-
0at July 31, 1996 and 1995, respectively.
13. COMMITMENTS
Atlas Resources, Inc., as general partner in several oil and
gas limited partnerships, and AEG Holdings, Inc. have agreed to indemnify each
investor general partner from any liability incurred which
exceeds such partner's share of partnership assets. Management believes
that such liabilities that may occur will be covered by insurance and, if not
covered by insurance, will not result in a significant loss
to AEG Holdings, Inc. and its subsidiaries.
Subject to certain conditions, investor general partners in
certain oil and gas limited
partnerships may present their interests beginning in 1996 for purchase
by Atlas Resources, Inc., as managing general partner. Atlas Resources, Inc.
is not obligated to purchase more than 5% of the units in
any calendar year.
Atlas Resources, Inc., as managing general partner in certain
oil and gas limited partnerships has also agreed to subordinate its share of
production revenues to the receipt by investor partners of cash
distributions equal to at least 10% of their subscriptions in each of
the first five years of partnership operations.
14. NON-RECURRING INCOME
The non-recurring income item pertains to a settlement of
certain claims with Columbia Gas Transmission Corporation.
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<PAGE>132
15. IMPAIRMENT OF ASSETS
In 1996 the Company evaluated the carrying value of long-lived
assets for impairment of value in accordance with the Statement of Financial
Accounting Standards No. 121 "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of." The
Company recognized a noncash write-down in the carrying value of assets of
$2,370,000 which primarily was a result of the sustained decrease in gas
and oil prices. The write-down includes $1,930,000 in oil and gas
properties and $440,000 in gathering lines. The write-down was determined
based upon the estimated future net cash flows from the properties.
16. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
The supplementary information summarized below presents the
results of natural gas and oil activities in accordance with SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities."
(1) PRODUCTION COSTS
The following table presents the costs incurred relating
to natural gas and oil production
activities:
1996 1995
Capitalized costs at July 31:
Capitalized costs $31,927,784 $28,185,190
Accumulated depreciation
and depletion
(12,211,283) (10,518,131)
----------- ------------
Net capitalized costs $19,716,501 $17,667,059
Costs incurred during the =========== ============
year ended July 31:
roperty acquisition costs
- proved undeveloped
properties $ 15,000 $ 500
============ ==========
Developed costs $ 6,745,226 $ 4,753,047
Property acquisition costs include costs to purchase,
lease or otherwise acquire a property. Development costs include costs to gain
access to and prepare development well locations for drilling, to
drill and equip development wells and to provide facilities to extract,
treat, gather and store oil and gas.
(2) RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
The following table presents the results of operations related
to natural gas and oil production
for the years ended July 31, 1996 and 1995:
1996 1995
Revenues $ 4,796,736 $ 3,903,888
Production costs (296,133) (230,256)
Depreciation and depletion (2,765,784) (1,313,993)
Income tax expense (310,189) (631,545)
Results ---------- -----------
of operations from producing activities $1,424,630 $ 1,728,094
Depreciation, depletion and ========== ===========
amortization of natural gas and
oilproperties are provided on the
unit-of- production method.
(3) RESERVE INFORMATION
The information presented below represents estimates of proved
natural gas and oil reserves. Proved developed reserves represent only those
reserves expected to be recovered from existing wells and
support equipment. Proved undeveloped reserves represent proved
reserves expected to be recovered from new wells after substantial development
costs are incurred. All reserves are located in Eastern Ohio and
Western Pennsylvania.
1996 1995
NATURAL GAS OIL NATURAL GAS OIL
(MCF) (BARRELS) (MCF) (BARRELS)
Proved developed and undeveloped reserves:
Beginning of period 60,946,963 91,260 55,084,369 86,390
Revision of previous estimates 2,579,747 (10,327) (1,604,824) (1,833)
Extensions, discoveries
and other additions 11,720,742 -0- 22,723,456 121,285
Production (2,065,738) (9,414) (1,875,795) (6,728)
les of minerals in place (12,673,528) -0- (13,380,243)(107,854)
End of period 60,508,186 71,519 60,946,963 91,260
Proved developed reserves:========== ======= =========== =======
Beginning of period 21,114,083 91,260 19,461,489 86,390
========== ====== ========== ======
End of period 23,925,316 71,519 21,114,083 91,260
========= ====== ========== ======
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<PAGE>133
16. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
(4) STANDARD MEASURE OF DISCOUNTED FUTURE CASH FLOWS
Management cautions that the standard measure of discounted
future cash flows should not be viewedas an indication of the fair market value
of natural gas and oil producing properties, nor of the future
cash flows expected to be generated therefrom. The information
presented does not give recognition to future changes in estimated reserves,
selling prices or costs and has been discounted at an arbitrary rate
of 10%. Estimated future net cash flows from natural gas and oil
reserves based on selling prices and costs at July 31, 1996 and July 31, 1995
price levels are as follows:
1996 1995
Future cash inflows $131,532,670 $139,389,034
Future production costs (30,793,378) (30,822,109)
Future development costs (34,814,000) (41,574,000)
Future income tax expense (13,669,546) (13,691,210)
------------ ------------
Future net cash flow 52,255,746 53,301,715
10% annual discount for estimated
timing of cash flows
(35,246,698) (38,511,020)
Standardized measure of discounted ------------ ------------
future net cash flows $17,009,048 $ 14,790,695
=========== ============
Summary of changes in the standardized measure of discounted future
net cash flows:
1996 1995
Sales of gas and oil produced - net $(1,424,630) $(1,728,094)
Net changes in prices, production and
development costs (4,256,259) (4,087,588)
Extensions, discoveries, and improved recovery,
less related costs 178,794 792,963
Development costs incurred 4,686,481 5,081,411
Revisions of previous quantity estimates 1,951,236 (961,361)
Sales of minerals in place (464,705) (1,843,660)
Accretion of discount 1,930,851 1,376,058
Net change in income taxes (383,415) 703,049
------------ ----------
Net (decrease) increase 2,218,353 (667,222)
Beginning of period 14,790,695 15,457,917
----------- -------------
End of period $17,009,048 $ 14,790,695
=========== ============
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<PAGE>134
THE ATLAS GROUP, INC.
CONSOLIDATED BALANCE SHEET (UNAUDITED)
AS OF MAY 31, 1997
- ------------------------------------------------------------------------------
<PAGE>135
ASSETS 1997 1996
CURRENT ASSETS
Cash and cash equivalents $2,736,884 $ 6,021,315
Trade accounts and notes receivable
, less allowance for
doubtful accounts of $246,000 6,225,103 6,411,167
Other receivables 144,868 828,880
Costs in excess of billings on
uncompleted contracts 0 403,989
Inventories 592,055 496,391
Prepaid expenses and other current
assets TOTAL CURRENT ASSETS OIL AND GAS PROPERTIES
Oil and gas wells and leases 34,560,372 33,548,231
Less accumulated depreciation,
depletion and amortization
NET OIL & GAS PROPERTIES OTHER
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Land 407,093 365,568
Buildings 2,550,415 1,790,457
Equipment 1,406,646 1,153,733
Gathering Lines Sub-total 24,610,016 21,533,085
Less accumulated depreciation
TOTAL PROPERTY, PLANT & EQUIPMENT
TOTAL ASSETS $40,871,874 $45,671,705
===========================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILTIIES
Accounts payable and accrued expenses $5,333,605 $8,014,373
Working interests and royalties payable 4,200,202 3,629,596
Billings in excess of costs on
uncompleted contracts 1,493,951 1,386,987
Current maturities on long-term debt:
Subordinated notes payable to
stockholders 1,907,084 1,669,661
Other 185,714 185,714
Income taxes payable TOTAL
CURRENT LIABILITIES
DEFERRED INCOME TAXES
LONG-TERM DEBT, net of current maturities
Notes Payable to Banks 5,523,810 5,709,524
Subordinated notes payable to
stockholders TOTAL LONG-TERM DEBT
DEFERRED REVENUE AND OTHER LONG-TERM LIABILITIES
STOCKHOLDERS' EQUITY
Capital stock, no par; authorized 2,000,000 shares;
issued 500,000 shares 1,250 1,250
Paid-in capital 560,093 560,093
Retained earnings 24,594,574 23,342,993
Treasury stock, at cost
(133,919 and 137,419 shares, respectively)
TOTAL STOCKHOLDERS' EQUITY
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $40,871,874 $45,671,705
- ------------------------------------------------------------------------
<PAGE>138
THE ATLAS GROUP, INC.
CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
TEN MONTHS ENDED MAY 31, 1997
INCOME 1997 1996
Sales-gas wells $16,682,188 $16,302,706
Purchased gas revenues 26,865,659 34,917,254
Well operating fees 2,689,834 2,685,711
Gathering line charges 2,112,752 2,172,349
Working interest and royalties 4,590,002 3,858,537
Gain on sale of assets 164,582 8,148
Interest 201,133 198,529
Non-recurring Income (Note 2) 0 2,924,146
Other TOTAL INCOME
COST OF SALES AND OTHER EXPENSES
Costs of sales-gas wells 14,203,478 13,693,934
Cost of purchased gas 27,526,168 34,932,992
Gathering line operation and maintenance 1,471,075 1,183,033
Exploration Expense 250,748 128,983
General and administrative 3,075,483 2,471,129
Interest:
Subordinated notes payable to stockholders 462,852 638,658
Other 122,371 345,292
Depreciation, depletion and amortization TOTAL EXPENSES
INCOME BEFORE INCOME TAXES 3,587,928 8,046,728
INCOME TAXES
NET INCOME $ 2,688,208 $5,976,379
==========================
THE ATLAS GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)
TEN MONTHS ENDED MAY 31, 1997
CASH FLOWS FROM OPERATING ACTIVITIES: 1997 1996
Net Income $2,688,208 $5,976,379
Adjustments to reconcile net income
to net cash provided
by (used in) operating activities:
Depreciation, depletion and amortization 3,164,635 2,469,995
(Increase) Decrease in Current assets 572,004 (3,999,761)
Increase (Decrease) in Current liabilities (10,066,269) 1,112,218
Other assets and liabilities, net Net cash provided by operating
activities
CASH FLOW USED IN INVESTING ACTIVITIES:
Investment in oil and gas wells and leases(2,632,588) (5,363,041)
Investment in Gathering Facilities (1,801,623) (1,557,236)
Other property additions Net cash used in investment activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on notes payable
to stockholders (1,669,661) (1,461,794)
Principal payments on other long-term borrowings Net cash from
financing activities
Net increase (decrease) in cash and cash
equivalents (11,178,018) (2,203,406)
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of period $2,736,884 $6,021,315
=======================
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<PAGE>137
THE ATLAS GROUP, INC.
NOTE TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
MAY 31, 1997
1. INTERIM FINANCIAL STATEMENTS
The consolidated financial statements as of May 31, 1997 and for the ten
months then ended have beenprepared by the management of the Company, without
audit, pursuant to the rules and regulations of the
Securities and Exchange Commission. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been omitted
pursuant to such rules and regulations, although the Company believes
that the disclosures are adequate to make the information presented not
misleading. These consolidated financial statements should be read in
conjunction with the audited July 31, 1996 and 1995 consolidated
financial statements. In the opinion of management, all adjustments
(consisting of only normal recurring accruals) considered necessary for
presentation have been included.
2. The non-recurring income item in the period ended May 31, 1996
pertains to a settlement of certain claims with Columbia Gas Transmission
Corporation.
- --------------------------------------------------------------------------
<PAGE>137
EXHIBIT (A)
AMENDED AND RESTATED CERTIFICATE
AND
AGREEMENT OF LIMITED PARTNERSHIP
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
TABLE OF CONTENTS
SECTION NO. DESCRIPTION
PAGE
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 1
III. SUBSCRIPTIONS AND FURTHER
CAPITAL CONTRIBUTIONS
3.01 Designation of Managing
General Partner and
Participants 7
3.02 Participants 7
3.03 Subscriptions to the
Partnership 7
3.04 Capital Contributions
8
3.05 Payment of Subscriptions
9
3.06 Partnership Funds 9
IV. CONDUCT OF OPERATIONS
4.01 Acquisition of Leases
10
4.02 Conduct of Operations
11
4.03 General Rights and
Obligations of the
Participants and Restricted
and Prohibited Transactions
14
4.04 Designation, Compensation
and Removal of Managing
General Partner
and Removal of Operator
20
4.05 Indemnification and
Exoneration 21
4.06 Other Activities 22
V. PARTICIPATION IN COSTS AND
REVENUES, CAPITAL ACCOUNTS,
ELECTIONS AND DISTRIBUTIONS
5.01 Participation in Costs and
Revenues 23
5.02 Capital Accounts and
Allocations
Thereto 25
5.03 Allocation of Income,
Deductions and
Credits 25
5.04 Elections 27
5.05 Distributions 27
VI. TRANSFER OF INTERESTS
6.01 Transferability 28
6.02 Special Restrictions on
Transfers 28
6.03 Right of Managing General
Partner to Hypothecate
and/or Withdraw Its
Interests 29
6.04 Repurchase Obligation
29
VII. DURATION, DISSOLUTION, AND
WINDING
UP
7.01 Duration 30
7.02 Dissolution and Winding Up
31
VIII. MISCELLANEOUS PROVISIONS
8.01 Notices 31
8.02 Time 31
8.03 Applicable Law 31
8.04 Agreement in Counterparts
32
8.05 Amendment 32
8.06 Additional Partners 32
8.07 Legal Effect 32
EXHIBITS
EXHIBIT (I-A) - Managing
General Partner
Signature Page
EXHIBIT (I-B) -
Subscription Agreement
EXHIBIT (II) -
Drilling and
Operating
Agreement
AMENDED AND RESTATED CERTIFICATE AND
AGREEMENT OF LIMITED PARTNERSHIP
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
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
, 1997, by and among Atlas Resources, Inc., hereinafter 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, such parties hereinafter sometimes referred
to as "Limited Partners," or for Investor General Partner Units,
such parties hereinafter sometimes referred to as "Investor
General Partners".
ARTICLE I
FORMATION
1.01. FORMATION. The parties hereto form a limited partnership
pursuant to the Pennsylvania Revised Uniform Limited Partnership
Act, upon the terms and conditions set forth herein.
1.02. CERTIFICATE OF LIMITED PARTNERSHIP. This document shall
constitute not only the agreement among the parties hereto, but
also shall constitute the Amended and Restated Certificate and
Agreement of Limited Partnership of the Partnership and shall be
filed or recorded in such public offices as is 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 such public offices as
required under applicable law or deemed advisable in the
discretion of the Managing General Partner.
1.03. NAME, PRINCIPAL OFFICE AND RESIDENCE. The name of the
Partnership is Atlas-Energy for the Nineties-Public #6 Ltd. The
residence of Atlas shall be 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 each such party. All such
addresses shall be subject to change upon notice to the parties.
The name and address of the agent for service of process shall be
Mr. J.R. O'Mara at Atlas Resources, Inc., 311 Rouser Road, Moon
Township, Pennsylvania 15108.
1.04. PURPOSE. The Partnership shall engage in all phases of the
oil and gas business, including, without limitation, exploration
for, development and production of oil and gas upon the terms and
conditions hereinafter set forth and any other proper purpose
under the Pennsylvania Revised Uniform Limited Partnership Act.
The Managing General Partner may not, without the affirmative vote
of Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription, change the investment and business
purpose of the Partnership or cause the Partnership to engage in
activities outside the stated business purposes of the Partnership
through joint ventures with other entities.
ARTICLE II
DEFINITION OF TERMS
2.01. DEFINITIONS. As used in this Agreement, the following terms
shall have the meanings hereinafter set forth:
1. "Administrative Costs" shall mean all customary and
routine expenses incurred by the Sponsor for the conduct
of Partnership administration, including: legal, finance,
accounting, secretarial, travel, office rent, telephone,
data processing and other items of a similar nature. No
Administrative Costs charged shall be duplicated under any
other category of expense or cost. No portion of the
salaries, benefits, compensation or remuneration of
controlling persons of Atlas will be reimbursed by the
Partnership as Administrative Costs. Controlling persons
include directors, executive officers and those holding
five percent 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" shall mean the official or agency
administering the securities laws of a state.
3. "Affiliate" shall mean with respect to a specific person
(a) any person directly or indirectly owning, controlling,
or holding with power to vote 10 per cent or more of the
outstanding voting securities of such specified person;
(b) any person 10 per cent or more of whose outstanding
voting securities are directly or indirectly owned,
controlled, or held with power to vote, by such specified
person; (c) any person directly or indirectly controlling,
controlled by, or under common control with such specified
person; (d) any officer, director, trustee or partner of
such specified person; and (e) if such specified person is
an officer, director, trustee or partner, any person for
which such person acts in any such capacity.
4. "Agreed Subscription" shall mean that amount so designated
on the Subscription Agreement executed by the Participant,
or, in the case of the Managing General Partner, its
subscription under 3.03(b) and its subsections.
5. "Agreement" shall mean this Amended and Restated
Certificate and Agreement of Limited Partnership,
including all exhibits hereto.
6. "Assessments" shall mean additional amounts of capital
which may be mandatorily required of or paid voluntarily
by a Participant beyond his subscription commitment.
7. "Atlas" shall mean Atlas Resources, Inc., a Pennsylvania
corporation, whose principal executive offices are located
at 311 Rouser Road, Moon Township, Pennsylvania 15108.
8. "Atlas Energy" shall mean Atlas Energy Group, Inc., an
Ohio corporation, whose principal executive offices are
located at 311 Rouser Road, Moon Township, Pennsylvania
15108.
9. "Atlas Group" shall mean The Atlas Group, Inc., a
Pennsylvania corporation, whose principal executive
offices are located at 311 Rouser Road, Moon Township,
Pennsylvania 15108. Atlas Group was formerly known as
AEGH or AEG Holdings, Inc.
10. "Capital Account" or "account" shall mean the account
established for each party hereto, maintained as provided
in 5.02 and its subsections.
11. "Capital Contribution" shall mean the amount agreed to be
contributed to the Partnership by a party pursuant to3.04 and 3.05 and their
subsections.
12. "Carried Interest" shall mean 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.
13. "Code" shall mean the Internal Revenue Code of 1986, as
amended.
14. "Cost", when used with respect to the sale of property to
the Partnership, shall mean (a) the sum of the prices paid
by the seller to an unaffiliated person for such property,
including bonuses; (b) title insurance or examination
costs, brokers' commissions, filing fees, recording costs,
transfer taxes, if any, and like charges in connection
with the acquisition of such property; (c) a pro rata
portion of the seller's actual necessary and reasonable
expenses for seismic and geophysical services; and (d)
rentals and ad valorem taxes paid by the seller with
respect to such property to the date of its transfer to
the buyer, interest and points actually incurred on funds
used to acquire or maintain such property, and such
portion of the seller'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 (d) hereof shall have been incurred not
more than 36 months prior to the purchase by the
Partnership. When used with respect to services, "cost"
shall mean the reasonable, necessary and actual expense
incurred by the seller on behalf of the Partnership in
providing such services, determined in accordance with
generally accepted accounting principles. As used
elsewhere, "cost" shall mean the price paid by the seller
in an arm's-length transaction.
15. "Dealer-Manager" shall mean Anthem Securities, Inc., a
wholly owned subsidiary of AIC, Inc. and the broker-dealer
which will manage the offering and sale of the Units in
all states except Minnesota and New Hampshire, and Bryan
Funding, Inc., the broker-dealer which will manage the
offering and sale of Units in Minnesota and New Hampshire.
16. "Development Well" shall mean a well drilled within the
proved area of an oil or gas reservoir to the depth of a
stratigraphic Horizon known to be productive.
17. "Direct Costs" shall mean 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 shall 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.
Direct Costs may include the cost of services provided by
the Sponsor or its Affiliates if such services are
provided pursuant to written contracts and in compliance
with 4.03(d)(7).
18. "Distribution Interest" shall mean an undivided interest
in the assets of the Partnership after payments to
creditors of the Partnership or the creation of a
reasonable reserve therefor, in the ratio the positive
balance of a party's Capital Account bears to the
aggregate positive balance of the Capital Accounts of all
of the parties determined after taking into account all
Capital Account adjustments for the taxable year during
which liquidation occurs (other than those made pursuant
to liquidating distributions or restoration of deficit
Capital Account balances); provided, however, after the
Capital Accounts of all of the parties have been reduced
to zero, such interest in the remaining assets of the
Partnership shall equal a party's interest in the related
revenues of the Partnership as set forth in 5.01 and its
subsections of this Agreement.
19. "Drilling and Operating Agreement" shall mean the proposed
Drilling and Operating Agreement between Atlas, Atlas
Energy or an Affiliate as Operator, and the Partnership as
Developer, a copy of the proposed form of which is
attached hereto as Exhibit (II).
20. "Exploratory Well" shall mean a well drilled to find
commercially productive hydrocarbons in an unproved area,
to find a new commercially productive Horizon in a field
previously found to be productive of hydrocarbons at
another Horizon, or to significantly extend a known
prospect.
21. "Farmout" shall mean an agreement whereby the owner of the
leasehold or Working Interest agrees to assign his
interest in certain specific acreage 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" shall mean any one of the
following: (i) the expiration of the fixed term of the
Partnership; (ii) the giving of notice to the Participants
by the Managing General Partner of its election to
terminate the affairs of the Partnership; (iii) the giving
of notice by the Participants to the Managing General
Partner of their similar election through the affirmative
vote of Participants whose Agreed Subscriptions equal a
majority of the Partnership Subscription; or (iv) the
termination of the Partnership under 708(b)(1)(A) of the
Code or the Partnership ceases to be a going concern.
23. "Horizon" shall mean a zone of a particular formation;
that part of a formation of sufficient porosity and
permeability to form a petroleum reservoir.
24. "Independent Expert" shall mean a person with no material
relationship to the Sponsor or its Affiliates who is
qualified and who is in the business of rendering opinions
regarding the value of oil and gas properties based upon
the evaluation of all pertinent economic, financial,
geologic and engineering information available to the
Sponsor or its Affiliates.
25. "Initial Closing Date" shall mean the date, on or before
the Offering Termination Date, but after the minimum
Partnership Subscription has been received, that the
Managing General Partner, in its sole discretion, elects
for the Partnership to begin business activities,
including the drilling of wells. It is anticipated that
this date will be December 1, 1997.
26. "Intangible Drilling Costs"or "Non-Capital Expenditures"
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; and includes all expenditures made with respect
to any well prior to 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 such well and the
preparation thereof for the production of oil or gas, that
are currently deductible pursuant to Section 263(c) of the
Code and Treasury Reg. Section 1.612-4, which are
generally termed "intangible drilling and development
costs," including the expense of plugging and abandoning
any well prior to a completion attempt.
27. "Interim Closing Date" shall mean such date(s) after the
Initial Closing Date of the Partnership, but prior to the
Offering Termination Date, that the Managing General
Partner, in its sole discretion, applies additional Agreed
Subscriptions to additional Partnership activities,
including drilling activities.
28. "Investor General Partners" shall mean the persons signing
the Subscription Agreement as Investor General Partners
and the Managing General Partner to the extent of any
optional subscription under 3.03(b)(2). All Investor
General Partners shall be of the same class and have the
same rights.
29. "Landowner's Royalty Interest" shall mean an interest in
production, or the proceeds therefrom, to be received free
and clear of all costs of development, operation, or
maintenance, reserved by a landowner upon the creation of
an oil and gas Lease.
30. "Leases" shall mean full or partial interests in oil and
gas leases, oil and gas mineral rights, fee rights,
licenses, concessions, or other rights under which the
holder is entitled to explore for and produce oil and/or
gas, and further includes any contractual rights to
acquire any such interest.
31. "Limited Partners" shall mean the persons signing the
Subscription Agreement as Limited Partners, the Managing
General Partner to the extent of any optional subscription
under 3.03(b)(2), the Investor General Partners upon the
conversion of their Investor General Partner Units to
Limited Partner interests pursuant to 6.01(c), and any
other persons who are admitted to the Partnership as
additional or substituted Limited Partners. Except as
provided in 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" shall mean Atlas Resources,
Inc. or any Person admitted to the Partnership as a
general partner other than as an Investor General Partner
pursuant to this Agreement who is designated to
exclusively supervise and manage the operations of the
Partnership.
33. "Managing General Partner Signature Page" shall mean an
execution and subscription instrument in the form attached
as Exhibit (I-A) to this Agreement, which is incorporated
herein by reference.
34. "Offering Termination Date" shall mean the date after the
minimum Partnership Subscription has been received on
which the Managing General Partner determines, in its sole
discretion, the Partnership's subscription period is
closed and the acceptance of subscriptions ceases, which
shall not be later than December 31, 1997.
35. "Operating Costs" shall mean expenditures made and costs
incurred in producing and marketing oil or gas from
completed wells, including, in addition to labor, fuel,
repairs, hauling, materials, supplies, utility charges and
other costs incident to or therefrom, ad valorem and
severance taxes, insurance and casualty loss expense, and
compensation to well operators or others for services
rendered in conducting such operations. Subject to the
foregoing, Operating Costs also include reworking,
workover, subsequent equipping and similar expenses
relating to any well.
36. "Operator" shall mean Atlas, as operator of Partnership
Wells in Pennsylvania, Atlas Energy as operator of
Partnership Wells in Ohio and Atlas or an Affiliate as
Operator of Partnership Wells in other areas of the United
States.
37. "Organization and Offering Costs" shall mean all costs of
organizing and selling the offering including, but not
limited to, total underwriting and brokerage discounts and
commissions (including fees of the underwriters'
attorneys), 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,
expenses of qualification of the sale of the securities
under federal and state law, including taxes and fees,
accountants' and attorneys' fees and other front-end fees.
38. "Overriding Royalty Interest" shall mean an interest in
the oil and gas produced pursuant to a specified oil and
gas lease or leases, or the proceeds from the sale
thereof, carved out of the working interest, to be
received free and clear of all costs of development,
operation, or maintenance.
39. "Participants" shall mean the Managing General Partner to
the extent of its optional subscription under 3.03(b)(2);
the Limited Partners, and the Investor General Partners.
40. "Partners" shall mean the Managing General Partner, the
Investor General Partners and the Limited Partners.
41. "Partnership" shall mean Atlas-Energy for the
Nineties-Public #6 Ltd., the Pennsylvania limited
partnership formed pursuant to this Agreement.
42. "Partnership Net Production Revenues" shall mean gross
revenues after deduction of the related Operating Costs,
Direct Costs, Administrative Costs and all other
Partnership costs not specifically allocated.
43. "Partnership Subscription" shall mean the aggregate Agreed
Subscriptions of the parties to this Agreement; provided,
however, with respect to Participant voting rights under
this Agreement, the term "Partnership Subscription" shall
be deemed not to include the Managing General Partner's
required subscription under 3.03(b)(1).
44. "Partnership Well" shall mean a well, some portion of the
revenues from which is received by the Partnership.
45. "Person" shall mean a natural person, partnership,
corporation, association, trust or other legal entity.
46. "Program" shall mean one or more limited or general
partnerships or other investment vehicles formed, or to be
formed, for the primary purpose of exploring for oil, gas
and other hydrocarbon substances or investing in or
holding any property interests which permit the
exploration for or production of hydrocarbons or the
receipt of such production or the proceeds thereof.
47. "Prospect" shall mean 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 designated by the Managing General
Partner in writing prior to the conduct of Partnership
operations and shall be 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. A "Prospect" with respect to 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 if the well to be drilled by the Partnership is to a
Horizon containing Proved Reserves. Subject to the
foregoing sentence, with respect to the Clinton/Medina
geological formation in Ohio and Pennsylvania "Prospect"
shall be deemed the drilling or spacing unit.
48. "Proved Reserves" shall mean the estimated quantities of
crude oil, natural gas, and natural gas liquids which
geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions.
(i) Reservoirs are considered proved if economic
producibility is supported by either actual production
or conclusive formation test. The area of a reservoir
considered proved includes (a) that portion delineated
by drilling and defined by gas-oil and/or oil-water
contacts, if any; and (b) the immediately adjoining
portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of
available geological and engineering data. In the
absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically
through application of improved recovery techniques
(such as fluid injection) are included in the "proved"
classification when successful testing by a pilot
project, or the operation of an installed program in
the reservoir, provides support for the engineering
analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the
following: (a) oil that may become available from
known reservoirs but is classified separately as
"indicated additional reserves"; (b) crude oil,
natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics,
or economic factors; (c) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled
prospects; and (d) crude oil, natural gas, and natural
gas liquids, that may be recovered from oil shales,
coal, gilsonite and other such sources.
49. "Proved Developed Oil and Gas Reserves" shall mean
reserves that can be expected to be recovered through
existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained
through the application of fluid injection or other
improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be
included as "proved developed reserves" only after testing
by a pilot project or after the operation of an installed
program has confirmed through production response that
increased recovery will be achieved.
50. "Proved Undeveloped Reserves" shall mean reserves that
are expected to be recovered from new wells on undrilled
acreage, or 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.
51. "Roll-Up" shall mean 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. Such term does
not include: (a) a transaction involving securities of the
Partnership that have been listed for at least twelve
months on a national exchange or traded through the
National Association of Securities Dealers Automated
Quotation National Market System; or (b) 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: voting
rights; the term of existence of the Partnership; the
Managing General Partner's compensation; and the
Partnership's investment objectives.
52. "Roll-Up Entity" shall mean a partnership, trust,
corporation or other entity that would be created or
survive after the successful completion of a proposed
roll-up transaction.
53. "Sales Commissions" shall mean all underwriting and
brokerage discounts and commissions incurred in the sale
of Units in the Partnership payable to registered
broker-dealers, excluding the Dealer-Manager fee, the
reimbursement for bona fide accountable due diligence
expenses and wholesaling fees.
54. "Selling Agents" shall mean those broker-dealers selected
by the Dealer-Manager which will participate in the offer
and sale of the Units.
55. "Sponsor" shall mean 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.
"Sponsor" includes 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. "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. Whenever the context so requires, the term
"sponsor" shall be deemed to include its affiliates.
56. "Subscription Agreement" shall mean an execution and
subscription instrument in the form attached as Exhibit
(I-B) to this Agreement, which is incorporated herein by
reference.
57. "Tangible Costs"or "Capital Expenditures" shall mean those
costs associated with the drilling and completion of oil
and gas wells which are generally accepted as capital
expenditures pursuant to the provisions of the Internal
Revenue Code; and includes all costs of equipment, parts
and items of hardware used in drilling and completing a
well, and those items necessary to deliver acceptable oil
and gas production to purchasers to the extent installed
downstream from the wellhead of any well and which are
required to be capitalized pursuant to applicable
provisions of the Code and regulations promulgated
thereunder.
58. "Tax Matters Partner" shall mean the Managing General
Partner.
59. "Units" or "Units of Participation" shall mean the Limited
Partner interests and the Investor General Partner
interests purchased by Participants in the Partnership
under the provisions of 3.03 and its subsections.
60. "Working Interest" shall mean an interest in an oil and
gas leasehold which is subject to some portion of the Cost
of development, operation, or maintenance.
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 3.03(b)(2). Limited Partners
and Investor General Partners, including Affiliates of the
Managing General Partner, shall serve as Participants; and except
as provided under the Pennsylvania Revised Uniform Limited
Partnership Act, the Limited Partners shall not be bound by the
obligations of the Partnership.
3.02. PARTICIPANTS.
3.02(a). LIMITED PARTNER AT FORMATION. Atlas Energy Group, Inc.,
as Original Limited Partner, has acquired one Unit and has made a
Capital Contribution of $100. Upon the admission of Limited
Partners and Investor General Partners pursuant to 3.02(c)
below, the Partnership shall return to such Original Limited
Partner its Capital Contribution and shall reacquire its Unit and
such Original Limited Partner shall cease to be a Limited Partner
in the Partnership with respect to such Unit.
3.02(b). OFFERING OF INTERESTS. The Partnership is authorized to
admit to the Partnership after the receipt of the minimum
Partnership Subscription and at or prior to the Offering
Termination Date additional Limited Partners and Investor General
Partners whose Agreed Subscriptions for Units are accepted by the
Managing General Partner if, after the admission of such
additional Limited Partners and Investor General Partners, the
Agreed Subscriptions of all Limited Partners and Investor General
Partners do not exceed the number of Units set forth in
3.03(c)(1). The Managing General Partner may refuse to admit any
person as a Limited Partner or Investor General Partner for any
reason whatsoever pursuant to 3.03(d).
3.02(c). ADMISSION OF LIMITED PARTNERS AND/OR INVESTOR GENERAL
PARTNERS. No action or consent by the Participants shall be
required for the admission of additional Limited Partners and
Investor General Partners pursuant to 3.02(b). All subscribers'
funds shall be held by an independent interest bearing escrow
holder and shall not be released to the Partnership until the
receipt of the minimum Partnership Subscription in 3.03(c)(2).
Thereafter, subscriptions may be paid directly to the Partnership
Account.
3.02(d). MINIMUM CAPITALIZATION AND DURATION OF OFFERING. The
offering of Units shall be terminated not later than the earlier
of (i) December 31, 1997; or (ii) at such time as Agreed
Subscriptions for the maximum Partnership Subscription set forth
in 3.03(c)(1) shall have been received and accepted by the
Managing General Partner. The offering may be terminated earlier
at the option of the Managing General Partner. If at the time of
termination Agreed Subscriptions for fewer than 100 Units have
been received and accepted, all monies deposited by subscribers
shall be promptly returned to them with the interest earned
thereon from the date such monies were deposited in escrow through
the date of refund.
3.03. SUBSCRIPTIONS TO THE PARTNERSHIP.
3.03(a). SUBSCRIPTIONS BY PARTICIPANTS.
3.03(a)(1). AGREED SUBSCRIPTION. A Participant's Agreed
Subscription to the Partnership shall be the amount so designated
on his Subscription Agreement.
3.03(a)(2). SUBSCRIPTION PRICE AND MINIMUM AGREED SUBSCRIPTION.
The subscription price of a Unit in the Partnership shall be
$10,000, payable as set forth herein. The minimum Agreed
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 Agreed Subscriptions
shall be accepted in $1,000 increments.
3.03(a)(3). EFFECT OF SUBSCRIPTION. Execution of a Subscription
Agreement shall serve as an agreement by such Limited Partner or
Investor General Partner 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
Limited Partner or Investor General Partner, shall contribute to
the Partnership the Leases which will be drilled by the
Partnership on the terms set forth in 4.01(a)(3) and shall pay
the costs charged to it pursuant to 5.01(a). Such amounts shall
be paid as set forth in 3.05(a).
3.03(b)(2). MANAGING GENERAL PARTNER'S OPTIONAL ADDITIONAL
SUBSCRIPTION. In addition to the Managing General Partner's
required subscription under 3.03(b)(1), the Managing General
Partner may subscribe to up to 10% of the Units on the same basis
as a Participant may subscribe to Units under the provisions of
3.03(a) and its subsections, and, subject to the limitations on
voting rights set forth in 4.03(c)(1), to that extent shall be
deemed a Participant in the Partnership for all purposes under
this Agreement. Notwithstanding the foregoing, broker-dealers and
the Managing General Partner and its officers and directors and
Affiliates shall not be required to pay the Dealer-Manager fee,
any Sales Commission or any reimbursement of accountable due
diligence expenses.
3.03(b)(3). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing
General Partner has executed a Managing General Partner Signature
Page which evidences the Managing General Partner's required
subscription under 3.03(b)(1) and which may be amended to reflect
the amount of any optional subscription under 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 PARTNERSHIP SUBSCRIPTION.
3.03(c)(1). MAXIMUM PARTNERSHIP SUBSCRIPTION. The maximum
Partnership Subscription excluding the Managing General Partner's
required subscription under 3.03(b)(1) may not exceed $8,000,000
(800 Units). However, if subscriptions for all 800 Units being
offered are obtained, the Managing General Partner, in its sole
discretion, may offer not more than 200 additional Units and
increase the maximum aggregate subscriptions with which the
Partnership may be funded to not more than 1,000 Units
($10,000,000).
3.03(c)(2). MINIMUM PARTNERSHIP SUBSCRIPTION. The minimum
Partnership Subscription shall equal at least $1,000,000 (100
Units). The Managing General Partner and its Affiliates may
purchase up to 10% of the Partnership Subscription, none of which
shall be applied to satisfy the $1,000,000 minimum.
3.03(d). ACCEPTANCE OF SUBSCRIPTIONS. Acceptance of subscriptions
shall be discretionary with Atlas and Atlas may reject any
subscription for any reason it deems appropriate. A Participant's
subscription to the Partnership and Atlas' acceptance thereof
shall be evidenced by the execution of a Subscription Agreement by
the Limited Partner or the Investor General Partner and by Atlas.
Agreed Subscriptions shall be accepted or rejected by the
Partnership within thirty days of their receipt; if rejected, all
funds shall be returned to the subscriber immediately. Upon the
original sale of Units, the Participants shall be admitted as
Partners not later than fifteen days after the release from escrow
of Participants' funds to the Partnership, and thereafter
Participants shall be admitted into the Partnership not later than
the last day of the calendar month in which their Agreed
Subscriptions were accepted by the Partnership.
3.04. CAPITAL CONTRIBUTIONS.
3.04(a). CAPITAL CONTRIBUTIONS. Each Participant shall make a
Capital Contribution to the Partnership equal to the sum of: (i)
the Agreed Subscription of such Participant; and (ii) in the case
of Investor General Partners, but not the Limited Partners, the
additional Capital Contributions required in 3.05(b).
Participants shall not be required to restore any deficit balances
in their Capital Accounts except as set forth in 5.03(h).
3.04(b). ADDITIONAL MANAGING GENERAL PARTNER CAPITAL
CONTRIBUTIONS.
3.04(b)(1). ADDITIONAL CAPITAL CONTRIBUTIONS OF THE MANAGING
GENERAL PARTNER. In addition to any Capital Contribution required
of the Managing General Partner as provided in 3.03(b)(1) and any
optional Capital Contribution as a Participant as provided in
3.03(b)(2), the Managing General Partner shall further contribute
cash sufficient to pay all costs charged to it under this
Agreement to the extent such costs exceed: (i) its Capital
Contribution pursuant to 3.03(b); and (ii) its share of
undistributed revenues. In any event, the Managing General
Partner's aggregate Capital Contributions to the Partnership
(including Leases contributed pursuant to 3.03(b)(1)) shall not
be less than 16.5% of all Capital Contributions to the
Partnership. Any payments by the Managing General Partner in
excess of the costs set forth in 3.03(b)(1) shall be used to pay
Partnership costs which would otherwise be charged to the
Participants. Such Capital Contributions shall be paid by the
Managing General Partner at the time such costs are required to be
paid by the Partnership, but, in no event, later than December 31,
1998.
Upon liquidation of the Partnership or its interest in the
Partnership, the Managing General Partner shall contribute to the
Partnership any deficit balance in its Capital Account, determined
after taking into account all adjustments for the Partnership's
taxable year during which such 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 such
liquidation), to be paid to creditors of the Partnership or
distributed to the other parties hereto in accordance with 7.02
upon liquidation of the Partnership. The Managing General Partner
shall maintain a minimum Capital Account balance equal to 1% of
total positive Capital Account balances for the Partnership.
3.04(b)(2). INTEREST FOR CONTRIBUTIONS. The interest of the
Managing General Partner in the capital and revenues of the
Partnership is in consideration for, and is the only consideration
for, its Capital Contribution to the Partnership.
3.04(c). LIMITATION ON AMOUNT OF REQUIRED CAPITAL CONTRIBUTIONS
OF LIMITED PARTNERS. In no event shall a Limited Partner be
required to make contributions to the Partnership greater than his
required Capital Contribution under 3.04(a).
3.05. PAYMENT OF SUBSCRIPTIONS.
3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing
General Partner shall contribute to the Partnership the Leases
pursuant to 3.03(b)(1) and pay the costs charged to it when
incurred by the Partnership, subject to 3.04(b)(1). Any optional
subscription under 3.03(b)(2) shall be paid by the Managing
General Partner in the same manner as provided for the payment of
Participant subscriptions under 3.05(b).
3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL
CONTRIBUTIONS OF THE INVESTOR GENERAL PARTNERS. A Participant
shall pay his Agreed Subscription 100% in cash at the time of
subscribing. A Participant shall receive interest on his Agreed
Subscription up until the Offering Termination Date.
Investor General Partners are obligated to make Capital
Contributions to the Partnership when called by the Managing
General Partner, in addition to their Agreed 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 prior to the
conversion of Investor General Units to Limited Partner interests
pursuant to 6.01(c). The failure of an Investor General Partner
to timely make a required additional Capital Contribution pursuant
to this section results in his personal liability to the other
Investor General Partners for the amount in default. The remaining
Investor General Partners, pro rata, must pay such defaulting
Investor General Partner's share of Partnership liabilities and
obligations. In that event, the remaining Investor General
Partners 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;
shall be entitled to receive 100% of the defaulting Investor
General Partner's cash distributions directly from the Partnership
until the amount in default is recovered in full plus interest at
the legal rate; and 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 shall have
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, and the Managing
General Partner shall not employ, or permit another to employ,
such funds and assets in any manner except for the exclusive
benefit of the Partnership. Neither this Agreement nor any other
agreement between the Sponsor and the Partnership shall
contractually limit any fiduciary duty owed to the Participants by
the Sponsor under applicable law, except as provided in 4.01,
4.02, 4.04, 4.05 and 4.06 of this Agreement.
3.06(b). SPECIAL ACCOUNT AFTER THE RECEIPT OF THE MINIMUM
PARTNERSHIP SUBSCRIPTION. Following the receipt of the minimum
Partnership Subscription, 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. Partnership funds may not be invested in the
securities of another person except in the following instances:
(1) investments in Working Interests or undivided Lease interests
made in the ordinary course of the Partnership's business; (2)
temporary investments made as set forth below; (3) multi-tier
arrangements meeting the requirements of 4.03(d)(15); (4)
investments involving less than 5% of the Partnership Subscription
which are a necessary and incidental part of a property
acquisition transaction; and (5) investments in entities
established solely to limit the Partnership's liabilities
associated with the ownership or operation of property or
equipment, provided, in such instances duplicative fees and
expenses shall be prohibited.
After the Offering Termination Date and until proceeds from the
public offering are invested in the Partnership's operations, such
proceeds may be temporarily invested in income producing
short-term, highly liquid investments, where there is appropriate
safety of principal, such as U.S. Treasury Bills.
ARTICLE IV
CONDUCT OF OPERATIONS
4.01. ACQUISITION OF LEASES.
4.01(a). ASSIGNMENT TO PARTNERSHIP.
4.01(a)(1). 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 oil and gas industry, subject to the terms and conditions set
forth below. 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 unless the
acquisition is made after a well has been drilled to a depth
sufficient to indicate that such an 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). TERMS AND OBLIGATIONS. Subject to the provisions of
4.03(d) and its subsections, such acquisitions of Leases or other
property may be made under any terms and obligations, including
any limitations as to the Horizons to be assigned to the
Partnership, and subject to any burdens, as the Managing General
Partner deems necessary in its sole discretion. Provided, however,
that any Lease acquired from the Managing General Partner, the
Operator or their Affiliates shall be credited towards the
Managing General Partner's required Capital Contribution set forth
in 3.03(b)(1) at the Cost of such Lease, unless the Managing
General Partner shall have cause to believe that Cost is
materially more than the fair market value of such property, in
which case the credit for such contribution will be made at a
price not in excess of the fair market value. A determination of
fair market value must be supported by an appraisal from an
Independent Expert. Such opinion and any associated supporting
information must be maintained in the Partnership's records for
six years.
To the extent the Partnership does not acquire a full interest in
a Lease from the Managing General Partner, the remainder of the
interest in such Lease may be held by the Managing General Partner
which may either retain and exploit it for its own account or sell
or otherwise dispose of all or a part of such remaining interest.
Profits from such exploitation and/or disposition shall be for the
benefit of the Managing General Partner to the exclusion of the
Partnership.
4.01(a)(4). NO BREACH OF DUTY. Subject to the provisions of 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 the Managing General
Partner, the Operator, or their Affiliates to the Partnership or
the Participants.
4.01(b). OVERRIDING ROYALTY INTERESTS. Neither the Managing
General Partner nor any Affiliate shall acquire or retain any
Overriding Royalty Interest on the Lease interests 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 the Managing General Partner, the
Operator or their Affiliates or in the name of any nominee
designated by the Managing General Partner to facilitate the
acquisition of the properties.
4.01(c)(2). TITLE. The Managing General Partner shall take such
steps as 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. No operation shall be commenced on
Leases acquired by the Partnership unless the Managing General
Partner is satisfied that necessary title requirements have been
satisfied. The Managing General Partner shall be free, however, to
use its own best judgment in waiving title requirements and 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 may be provided in
the Drilling and Operating Agreement.
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 4.03 and
its subsections, and to any authority which may be granted the
Operator under 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 Leases are developed and which Leases
are abandoned, or at its sole discretion, 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 such operations or the implementation of the
powers granted it under this Agreement, including, without
limitation, the making of agreements for the conduct of
operations or the furnishing of equipment, facilities,
supplies and material, services, and personnel and the
exercise of any options, elections, or decisions under any
such agreements;
(iii) the exercise, on behalf of the Partnership or the
parties, in such manner as the Managing General Partner in
its sole judgment deems best, of all rights, elections and
options granted or imposed by any agreement, statute, rule,
regulation, or order;
(iv) the making of all decisions concerning the
desirability of payment, and the payment or supervision of
the payment, of all delay rentals and shut-in and minimum
or advance royalty payments;
(v) the selection of full or part-time employees and
outside consultants and contractors and the determination
of their compensation and other terms of employment or
hiring;
(vi) the maintenance of such insurance for the benefit of
the Partnership and the parties as it deems necessary, but,
subject to 6.01(c), in no event less in amount or type
than the following: (a) worker's compensation insurance in
full compliance with the laws of the Commonwealth of
Pennsylvania and any other applicable state laws; (b)
liability insurance (including automobile) which has a
$1,000,000 combined single limit for bodily injury and
property damage in any one accident or occurrence and in
the aggregate; and (c) such excess liability insurance as
to bodily injury and property damage with combined limits
of $50,000,000, per occurrence or accident and in the
aggregate, which includes $250,000 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 an accident. Such excess liability
insurance shall be in place and effective no later than the
Initial Closing Date and shall continue until the Investor
General Partners are converted to Limited Partners, at
which time the Partnership shall continue to enjoy the
benefit of Atlas' $11,000,000 liability insurance on the
same basis as Atlas and its Affiliates, including other
Programs in which Atlas serves as Managing General Partner;
(vii) the use of the funds and revenues of the
Partnership, and the borrowing on behalf of, and the loan
of money to, the Partnership, on any terms it sees fit, for
any purpose, including without limitation the conduct or
financing, in whole or in part, of the drilling and other
activities of the Partnership or the conduct of additional
operations, and the repayment of any such borrowings or
loans used initially to finance such operations or
activities;
(viii) the disposition, hypothecation, sale, exchange,
release, surrender, reassignment or abandonment of any or
all assets of the Partnership (including, without
limitation, the Leases, wells, equipment and production
therefrom) provided that the sale of all or substantially
all of the assets of the Partnership shall only be made as
provided in 4.03(d)(6);
(ix) the formation of any further limited or general
partnership, tax partnership, joint venture, or other
relationship which it deems desirable with any parties who
it, in its sole and absolute discretion, selects, including
any of its Affiliates;
(x) the control of any matters affecting the rights and
obligations of the Partnership, including the employment of
attorneys to advise and otherwise represent the
Partnership, the conduct of litigation and other incurring
of legal expense, and the settlement of claims and
litigation;
(xi) the operation of producing wells drilled on the
Leases owned by the Partnership, or on a Prospect which
includes any part of the Leases;
(xii) the exercise of the rights granted to it under the
power of attorney created pursuant to this Agreement; and
(xiii) the incurring of all costs and the making of all
expenditures in any way related to any of the foregoing.
4.02(c)(2). SCOPE OF POWERS. The Managing General Partner's
powers shall extend to any operation participated in by the
Partnership or affecting its Leases, or other property or assets,
irrespective of whether or not the Managing General Partner is
designated operator of such 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 hereunder
to any entity chosen by it, including an entity related to it, and
such party shall have the same powers in the conduct of such
duties as would the Managing General Partner; but such delegation
shall not relieve the Managing General Partner of its
responsibilities hereunder.
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, but such delegation shall not relieve the Managing
General Partner of its responsibilities hereunder. In no event
shall any consideration received for operator services be in
excess of the competitive rates or duplicative of any
consideration or reimbursements received pursuant to 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 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 4.02(c) and its subsections or
elsewhere in this Agreement, the Managing General Partner, where
specified, shall have the following additional express powers.
4.02(d)(1). DRILLING CONTRACTS. Partnership Wells drilled in
Pennsylvania and other areas of the Appalachian Basin may be
drilled pursuant to the Drilling and Operating Agreement on a
per-foot basis with Atlas or its Affiliates based on $37.39 per
foot or, with respect to a well which the Partnership elects not
to complete, $20.60 per foot. Partnership Wells in other areas of
the United States shall be drilled at competitive rates and in no
event shall Atlas or its Affiliates, as drilling contractor,
receive a per foot rate which is not competitive with the rates
charged by unaffiliated contractors in the same geographic region.
No turnkey drilling contracts shall be made between the Managing
General Partner or its Affiliates and the Partnership. Neither the
Managing General Partner nor its Affiliates shall profit by
drilling in contravention of its fiduciary obligations to the
Partnership. The Managing General Partner may not 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 party hereto hereby makes,
constitutes and 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:
1. to create, prepare, complete, execute, file, swear to,
deliver, endorse and record any and all documents,
certificates or other instruments required or necessary to
amend this Agreement as authorized under the terms of this
Agreement, or to qualify the Partnership as a limited
partnership or partnership in commendam and to conduct
business under the laws of any jurisdiction in which the
Managing General Partner elects to qualify the Partnership
or conduct business; and
2. 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 party hereto hereby
authorizes such attorney-in-fact to take any further action which
such attorney-in-fact shall consider necessary or advisable in
connection with any of the foregoing and acknowledges that the
power of attorney granted under this section is a special power of
attorney coupled with an interest and is irrevocable and shall
survive the assignment by a party of the whole or a portion of his
interest in the Partnership; except that where such assignment is
of such party's entire interest in the Partnership and the
purchaser, transferee or assignee thereof, with the consent of the
Managing General Partner, is admitted as a successor Limited
Partner or Investor General Partner, the power of attorney shall
survive the delivery of such assignment for the sole purpose of
enabling such attorney-in-fact to execute, acknowledge and file
any such agreement, certificate, instrument or document necessary
to effect such 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. If
additional funds over the Partners' Capital Contributions are
needed for Partnership operations, the Managing General Partner
may: (i) use Partnership revenues allocable to the accounts of the
Partners on whose behalf such Partnership revenues are expended
for such purposes; or (ii) the Managing General Partner and its
Affiliates may advance to the Partnership the funds necessary
pursuant to 4.03(d)(8)(b) which borrowings (other than credit
transactions on open account customary in the industry to obtain
goods and services) shall be without recourse to the Investor
General Partners and the Limited Partners except as otherwise
provided herein. Also, the amount that may be borrowed at any one
time (other than credit transactions on open account customary in
the industry to obtain goods and services) shall not exceed an
amount equal to 5% of the Partnership Subscription.
Notwithstanding, the Managing General Partner and it Affiliates
shall not be obligated to advance the funds to the Partnership.
4.02(e)(2). IMPLEMENTATION OF BORROWING PROVISIONS.
4.02(e)(2)(a). INDEMNIFICATION AND HOLD HARMLESS. Each party
hereto for whose account an interest in Partnership assets is
mortgaged, pledged or otherwise encumbered hereby indemnifies and
agrees to hold harmless every other party from any loss resulting
from such mortgage, pledge or encumbrance, limited to the amount
of his agreed Capital Contribution.
4.02(e)(2)(b). FORECLOSURE. Should a foreclosure of a mortgage,
pledge or security interest permitted hereunder occur, any
revenues, proceeds and all taxable gain or loss resulting from
such foreclosure shall be allocated entirely to the party for
whose account such interest was pledged; and such party's interest
in the remaining revenues of the Partnership shall be reduced to
take into account the foreclosure of the interests foreclosed.
4.02(f). DESIGNATION OF TAX MATTERS PARTNER. Atlas is hereby
designated the Tax Matters Partner of the Partnership pursuant to
6231(a)(7) of the Code and is authorized to act in such capacity
on behalf of the Partnership and the Participants and to take such
action, including settlement or litigation, as it in its sole
discretion deems to be in the best interest of the Partnership.
Costs incurred by the Tax Matters Partner shall be considered a
Direct Cost of the Partnership. The Tax Matters Partner shall
notify all Participants of any partnership administrative
proceedings commenced by the Internal Revenue Service, and
thereafter shall furnish all Participants periodic reports at
least quarterly on the status of such proceedings. Each Partner
agrees as follows: (1) 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 such term is defined in Section 6231(a)(3)
of Code) of the Partnership; (2) 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 (3) the Managing General
Partner is authorized to file a copy of this Agreement (or
pertinent portions hereof) with the Internal Revenue Service
pursuant to Section 6224(b) of the Code if necessary to perfect
the waiver of rights under this Subsection 4.02(f).
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
and shall not be personally liable for any debts of the
Partnership or any of the obligations or losses thereof beyond the
amount of their agreed Capital Contributions, except to the extent
such parties also subscribe to the Partnership as Investor General
Partners, or, in the case of Atlas, as Managing General Partner.
4.03(a)(2). NO MANAGEMENT AUTHORITY OF PARTICIPANTS.
Participants, as such, shall have no power over the conduct of the
affairs of the Partnership; and no Participant, as such, 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.
(1) Commencing with the 1997 calendar year, the
Partnership shall provide each Participant an annual report
within 120 days after the close of the calendar year, and
commencing with the 1998 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:
(a) Audited financial statements of the Partnership,
including a balance sheet and statements of income, cash
flow and Partners' equity, all of which shall be
prepared in accordance with generally accepted
accounting principles and accompanied by an auditor's
report containing an opinion of an independent public
accountant selected by the Managing General Partner
stating that his audit was made in accordance with
generally accepted auditing standards and that in his
opinion such financial statements present fairly the
financial position, results of operations, partners'
equity and cash flows in accordance with generally
accepted accounting principles. Semiannual reports need
not be audited.
(b) A summary itemization, by type and/or
classification of the total fees and compensation
including any unaccountable, fixed payment
reimbursements for Administrative Costs and Operating
Costs, paid by the Partnership, or indirectly on behalf
of the Partnership, to the Managing General Partner, the
Operator and their Affiliates. In addition, Participants
shall be provided the percentage that the annual
unaccountable, fixed fee reimbursement for
Administrative Costs bears to annual Partnership
revenues.
(c) A description of each Prospect in which the
Partnership owns an interest, including the cost,
location, number of acres under lease and the Working
Interest owned therein by the Partnership, except
succeeding reports need contain only material changes,
if any, regarding such Prospects.
(d) A list of the wells drilled or abandoned by the
Partnership during the period of the report (indicating
whether each of such wells has or has not been
completed), and a statement of the cost of each well
completed or abandoned. Justification shall be included
for wells abandoned after production has commenced.
(e) A description of all farmins and joint ventures,
made during the period of the report, including the
Managing General Partner's justification for the
arrangement and a description of the material terms.
(f) A schedule reflecting the total Partnership costs,
the costs paid by the Managing General Partner and the
costs paid by the Participants, the total Partnership
revenues, the revenues received or credited to the
Managing General Partner and the revenues received and
credited to the Participants and a reconciliation of
such expenses and revenues in accordance with the
provisions of Article V.
(2) The Partnership shall, by March 15 of each year,
prepare, or supervise the preparation of, and transmit to
each Partner such information as may be needed to enable
such Partner to file his federal income tax return, any
required state income tax return and any other reporting or
filing requirements imposed by any governmental agency or
authority.
(3) Annually, beginning January 1, 1999, a computation of
the total oil and gas Proved Reserves of the Partnership
and the present worth of such reserves determined using a
discount rate of 10%, a constant price for the oil and
basing the price of gas upon the existing gas contracts
shall be provided to each Participant along with each
Participant's interest therein. The reserve computations
shall be based upon engineering reports prepared by the
Managing General Partner and reviewed by an Independent
Expert. There shall also be included an estimate of the
time required for the extraction of such reserves and a
statement that because of the time period required to
extract such reserves the present value of revenues to be
obtained in the future is less than if immediately
receivable. In addition to the foregoing computation and
required estimate, as soon as possible, and in no event
more than ninety days after the occurrence of an event
leading to reduction of such reserves of the Partnership of
10% or more, excluding reduction as a result of normal
production, sales of reserves or product price changes, a
computation and estimate shall be sent to each Participant.
(4) The cost of all such reports described in this
4.03(b) shall be paid by the Partnership as Direct Costs.
(5) The Participants and/or their representatives shall be
permitted access to all records of the Partnership, after
adequate notice, at any reasonable time and may inspect and
copy any of them. The Managing General Partner will provide
a copy of this Agreement or other documents to the
Participants after the Partnership's documents have been
filed with the Commonwealth of Pennsylvania upon request.
The Managing General Partner shall maintain and preserve
during the term of the Partnership and for six years
thereafter all accounts, books and other relevant
documents, including a record that a Participant meets the
suitability standards established in connection with an
investment in the Partnership and of fair market value as
set forth in 4.01(a)(3). 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 such sources as are customary in the
industry or required by rule, regulation, or order of any
regulatory body.
(6) The following provisions apply regarding access to the
list of Participants: (a) 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") shall be maintained as a part
of the books and records of the Partnership and shall be
available for inspection by any Participant or its
designated agent at the home office of the Partnership upon
the request of the Participant; (b) the Participant List
shall be updated at least quarterly to reflect changes in
the information contained therein; (c) a copy of the
Participant List shall be mailed to any Participant
requesting the Participant List within ten days of the
written request. The copy of the Participant List shall be
printed in alphabetical order, on white paper, and in a
readily readable type size (in no event smaller than
10-point type). A reasonable charge for copy work shall be
charged by the Partnership; (d) 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 (e) 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 such refusal or neglect. It shall
be a defense that the actual purpose and reason for the
requests 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 such list or
information or copies thereof, 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 shall 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 hereunder 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.
(7) Concurrently with their transmittal to Participants,
and as required, the Managing General Partner shall file a
copy of each report provided for in this 4.03(b) with the
Arkansas Securities Department, the California Commissioner
of Corporations, the Kentucky Department of Financial
Institutions, the Virginia State Corporation Commission and
with the securities commissions of other states which
request the report.
4.03(c). MEETINGS OF PARTICIPANTS. Meetings of the Participants
may be called by the Managing General Partner or by Participants
whose Agreed Subscriptions equal 10% or more of the Partnership
Subscription for any matters for which Participants may vote. Such
call for a meeting shall be deemed to have been made upon receipt
by the Managing General Partner of a written request from holders
of the requisite percentage of Agreed Subscriptions stating the
purpose(s) of the meeting. The Managing General Partner shall
deposit in the United States mail within fifteen days after the
receipt of said request, written notice to all Participants of the
meeting and the purpose of such meeting, which shall be held on a
date not less than thirty days nor more than sixty days after the
date of the mailing of said notice, at a reasonable time and
place. Provided, however, that the date for notice of such a
meeting may be extended for a period of up to sixty days, if in
the opinion of the Managing General Partner such additional time
is necessary to permit preparation of proxy or information
statements or other documents required to be delivered in
connection with such meeting by the Securities and Exchange
Commission or other regulatory authorities. Participants shall
have the right to vote in person or by proxy at any meetings of
the Participants.
4.03(c)(1). SPECIAL VOTING RIGHTS. At the request of Participants
whose Agreed Subscriptions equal 10% or more of the Partnership
Subscription, the Managing General Partner shall call for a vote
by Participants. Each Unit is entitled to one vote on all matters;
each fractional Unit is entitled to that fraction of one vote
equal to the fractional interest in the Unit. Participants whose
Agreed Subscriptions equal a majority of the Partnership
Subscription may, without the concurrence of the Managing General
Partner or its Affiliates, vote to:
(a) amend this Agreement; provided however, any such
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 such Participant or the
Managing General Partner. Furthermore, any such amendment
may not affect the classification of Partnership income and
loss for federal income tax purposes without the unanimous
approval of all Participants;
(b) dissolve the Partnership;
(c) remove the Managing General Partner and elect a new
Managing General Partner;
(d) elect a new Managing General Partner if the Managing
General Partner elects to withdraw from the Partnership;
(e) remove the Operator and elect a new Operator;
(f) approve or disapprove the sale of all or
substantially all of the assets of the Partnership; and
(g) cancel any contract for services with the Managing
General Partner, or the Operator or their Affiliates,
without penalty upon sixty days notice.
With respect to Units owned by the Managing General Partner or its
Affiliates, the Managing General Partner and its Affiliates may
not vote or consent on the matters set forth in (c) or (e) above,
or regarding 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)(2). RESTRICTIONS ON LIMITED PARTNER VOTING RIGHTS. The
exercise by the Limited Partners of the rights granted
Participants under 4.03(c), except for the special voting rights
granted Participants under 4.03(c)(1), shall be subject to the
prior legal determination that the grant or exercise of such
powers will not adversely affect the limited liability of Limited
Partners, unless in the opinion of counsel to the Partnership,
such legal determination is not necessary under Pennsylvania law
to maintain the limited liability of the Limited Partners. A legal
determination under this paragraph may be made either pursuant to
an opinion of counsel, such counsel being independent of the
Partnership and selected upon the vote of Limited Partners whose
Agreed Subscriptions equal a majority of the Agreed Subscriptions
held by Limited Partners, or 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 such vote if the Investor
General Partners represent the requisite percentage of the
Participants necessary to take such action.
4.03(d). RESTRICTED AND PROHIBITED TRANSACTIONS.
4.03(d)(1). 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 oil, gas or
other mineral interests or property to the Partnership, it must,
at the same time, sell 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 such well will be drilled by the
Partnership if the geological feature to which such well will be
drilled contains Proved Reserves and the drilling or spacing unit
protects against drainage. With respect to an oil and gas Prospect
located in Ohio and Pennsylvania on which a well will be drilled
by the Partnership to test the Clinton/Medina geologic formation a
Prospect shall be deemed to consist of the drilling and spacing
unit if it meets the test in the preceding sentence. Neither the
Managing General Partner nor its Affiliates may drill any well
within 1,650 feet of an existing Partnership Well in the
Clinton/Medina formation in Pennsylvania or within 1,100 feet of
an existing Partnership Well in Ohio within five years of the
drilling of the Partnership Well. In the event the Partnership
abandons its interest in a well, 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 wherein 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, such
separate property interest or a portion thereof shall be sold,
transferred or conveyed to the Partnership as set forth in
4.01(a)(3), 4.03(d)(1) and 4.03(d)(2) if the activities of the
Partnership were material in establishing the existence of Proved
Undeveloped Reserves which are attributable to such separate
property interest. Notwithstanding, Prospects in the
Clinton/Medina geological formation 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
Clinton/Medina 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 the interest retained by the Managing General Partner or
the Affiliate is a proportionate Working Interest, 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
the Managing General Partner's interest in revenues does not
exceed the amount proportionate to its retained Working Interest.
Neither the Managing General Partner nor any Affiliate will retain
any Overriding Royalty Interests or other burdens on an interest
sold by it to the Partnership. With respect to its retained
interest the Managing General Partner shall not Farmout a Lease
for the primary purpose of avoiding payment of its costs relating
to drilling the Lease. 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). TRANSFER OF LEASES TO THE MANAGING GENERAL PARTNER.
The Managing General Partner and its Affiliates shall not purchase
any producing or non-producing oil and gas properties from the
Partnership.
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 from 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 such proposed
acquisition, the following conditions shall apply:
(a) 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
(b) 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 own 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 consummate 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 Partnership shall not purchase properties from
or sell properties to any other Affiliated partnership. This
prohibition, however, shall not apply to joint ventures among such
Affiliated partnerships, provided that the respective obligations
and revenue sharing of all parties to the transaction are
substantially the same and 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 Agreed
Subscriptions equal a majority of the Partnership Subscription.
4.03(d)(7). SERVICES. 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 such person is engaged,
independently of the Partnership and as an ordinary and ongoing
business, in the business of rendering such services or selling or
leasing such equipment and supplies to a substantial extent to
other persons in the oil and gas industry in addition to the
partnerships in which the Managing General Partner or an Affiliate
has an interest; and 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 such person is not engaged in such a business then
such compensation, price or rental will be the Cost of such
services, equipment or supplies to such person or the competitive
rate which could be obtained in the area, whichever is less. Any
such services for which the Managing General Partner or an
Affiliate is to receive compensation other than those described in
this Prospectus shall be embodied in a written contract which
precisely describes the services to be rendered and all
compensation to be paid. Such contracts are cancellable without
penalty upon sixty days written notice by Participants whose
Agreed Subscriptions equal a majority of the Partnership
Subscription.
4.03(d)(8). LOANS.
4.03(d)(8)(a). 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 where the interest to be charged exceeds the Managing
General Partner's or the Affiliate's interest cost or where the
interest to be charged exceeds 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, and 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 such charges incurred from
third-party lenders may be reimbursed to the Managing General
Partner or the Affiliate.
4.03(d)(9). FARMOUTS. The Partnership shall not Farmout its
Leases.
4.03(d)(10). COMPENSATING BALANCES. Neither the Managing General
Partner nor any Affiliate shall use the Partnership's funds as
compensating balances for its own benefit.
4.03(d)(11). FUTURE PRODUCTION. Neither the Managing General
Partner nor any Affiliate shall commit the future production of a
well developed by the Partnership exclusively for its own benefit.
4.03(d)(12). MARKETING ARRANGEMENTS. All benefits from marketing
arrangements or other relationships affecting 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 such property. The Managing
General Partner shall treat all wells in a geographic area equally
concerning to whom and at what price the Partnership's gas will be
sold and to whom and at what price the gas of other oil and gas
Programs which the Managing General Partner has sponsored or will
sponsor will be sold. The Managing General Partner calculates a
weighted average selling price for all of the gas sold in a
geographic area by taking all money received from the sale of all
of the gas sold to its customers in a geographic area and dividing
by the volume of all gas sold from the wells in that geographic
area. Notwithstanding, the Managing General Partner and its
Affiliates are parties to, and contract for, the sale of natural
gas with industrial end-users and will continue to enter into such
contracts on their own behalf, and the Partnership will not be a
party to such contracts. The Managing General Partner and its
Affiliates also have a substantial interest in certain pipeline
facilities and compression facilities which access interstate
pipeline systems, which it is anticipated will be used to
transport the Partnership's gas production as well as Affiliated
partnership and third-party gas production, and the Partnership
will not receive any interest in the Managing General Partner's
and its Affiliates' pipeline or gathering system or compression
facilities.
4.03(d)(13). ADVANCE PAYMENTS. Advance payments by the
Partnership to the Managing General Partner and its Affiliates are
prohibited, except where advance payments are required to secure
the tax benefits of prepaid drilling costs and for a business
purpose. These advance payments, if any, shall not include
nonrefundable payments for completion costs prior to the time that
a decision was made that the well or wells warrant a completion
attempt.
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), the terms of any such 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 expenses, 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. In connection with a proposed
Roll-Up, the following shall apply:
(a) 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, the appraisal shall be
filed with the Securities and Exchange Commission and the
Administrator as an exhibit to the registration statement
for the offering. Accordingly, 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 prior to the announcement of the proposed
Roll-Up transaction. The appraisal shall assume an orderly
liquidation of the Partnership's assets over a twelve 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.
(b) In connection with a proposed Roll-Up, Participants
who vote "no" on the proposal shall be offered the choice
of:
(1) accepting the securities of the Roll-Up Entity
offered in the proposed Roll-Up;
(2) remaining as Participants in the Partnership and
preserving their interests therein on the same terms and
conditions as existed previously; or
(3) receiving cash in an amount equal to the
Participants' pro rata share of the appraised value of
the net assets of the Partnership.
(c) 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 under4.03(c) and
4.03(c)(1) of this Agreement. If the Roll-Up Entity is a
corporation, the democracy rights of Participants shall
correspond to the democracy rights provided for in this
Agreement to the greatest extent possible.
(d) The Partnership shall not participate in any proposed
Roll-Up transaction which includes provisions which 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); nor shall the
Partnership 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.
(e) 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
4.03(b)(5) and 4.03(b)(6) of this Agreement.
(f) 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 less than
75% in interest of the Participants vote to approve the
proposed Roll-Up.
(g) The Partnership shall not participate in a Roll-Up
transaction unless the Roll-Up transaction is approved by
Participants whose Agreed Subscriptions equal 75% of the
Partnership Subscription.
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) FAIR AND REASONABLE. Neither the Managing General
Partner nor any Affiliate will sell, transfer, or convey any
property to or purchase any property from the Partnership,
directly or indirectly, except pursuant to 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 it is removed pursuant to
4.04(a)(3).
4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. Charges by
the Managing General Partner for goods and services must be fully
supportable as to the necessity thereof and the reasonableness of
the amount charged. All actual and necessary expenses incurred by
the Partnership may be paid out of the Partnership Subscription
and out of Partnership revenues.
In addition to the compensation set forth in 4.01(a)(3) and
4.02(d)(1) Atlas, as Managing General Partner, and its Affiliates
shall be reimbursed for all Direct Costs and credited pursuant to
5.01(a) for Organization and Offering Costs not exceeding 15% of
the Partnership Subscription; provided, however, Direct Costs
shall be billed directly to and paid by the Partnership to the
extent practicable. In addition, subject to the above paragraph,
Atlas shall receive an unaccountable, fixed payment reimbursement
for its Administrative Costs of $75 per well per month, which
shall be proportionately reduced to the extent the Partnership
acquires less than 100% of the Working Interest in the well. The
unaccountable, fixed payment reimbursement of $75 per well per
month shall not be increased in amount during the term of the
Partnership. Further, Atlas, as Managing General Partner, shall
not be reimbursed for any additional Partnership Administrative
Costs and the unaccountable, fixed payment reimbursement of $75
per well per month shall be the entire payment to reimburse Atlas
for the Partnership's Administrative Costs. Finally, Atlas, as
Managing General Partner, shall not receive the unaccountable,
fixed payment reimbursement of $75 per well per month for plugged
or abandoned wells.
Atlas and its Affiliates shall also receive a combined
transportation and marketing fee at a competitive rate for
transporting and marketing the Partnership's gas.
The Dealer-Manager will receive from the Partnership on each Unit
sold to investors, a 2.5% Dealer-Manager fee, a 7.5% Sales
Commission and a .5% reimbursement of the Selling Agents' bona
fide accountable due diligence expenses.
The Managing General Partner and its Affiliates may enter into
transactions pursuant to 4.03(d)(7) and shall be entitled to
compensation pursuant to such section. In addition, the Managing
General Partner and its Affiliates shall receive compensation as
set forth in the Drilling and Operating Agreement.
4.04(a)(3). REMOVAL OF MANAGING GENERAL PARTNER. The Managing
General Partner may be removed and a new Managing General Partner
or Managing General Partners may be substituted at any time upon
sixty days advance written notice to the outgoing Managing General
Partner, by the affirmative vote of Participants whose Agreed
Subscriptions equal a majority of the Partnership Subscription.
Should Participants vote to remove the Managing General Partner
from the Partnership, Participants must elect by an affirmative
vote of Participants whose Agreed Subscriptions equal a majority
of the Partnership Subscription either to terminate, dissolve and
wind up the Partnership or to continue as a successor limited
partnership under all the terms of this Partnership Agreement, as
provided in 7.01(c). If the Participants elect to continue as a
successor limited partnership, the Managing General Partner shall
not be removed until a substituted Managing General Partner has
been selected by an affirmative vote of Participants whose Agreed
Subscriptions equal a majority of the Partnership Subscription and
installed as such.
In the event the Managing General Partner is removed, the Managing
General Partner's interest in the Partnership shall be determined
by appraisal by a qualified Independent Expert selected by mutual
agreement between the removed Managing General Partner and the
incoming Managing General Partner, such appraisal to take into
account an appropriate discount, to reflect the risk of recovery
of oil and gas reserves, but not less than that utilized in the
most recent repurchase offer, if any. The cost of such appraisal
shall be borne equally by the removed Managing General Partner and
the Partnership. The incoming Managing General Partner shall have
the option to purchase 20% of the removed Managing General
Partner's interest for the value determined by the Independent
Expert.
The method of payment for such interest must be fair and must
protect the solvency and liquidity of the Partnership. Where 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.
Where 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. The removed Managing
General Partner, at the time of its removal shall cause, to the
extent it is legally possible, its successor to be transferred or
assigned all its rights, obligations and interests as Managing
General Partner of the Partnership in contracts entered into by it
on behalf of the Partnership. In any event, the removed Managing
General Partner shall cause its rights, obligations and interests
as Managing General Partner of the Partnership in any such
contract to terminate at the time of its removal. Notwithstanding
any other provision in this Agreement, the Partnership or the
successor Managing General Partner shall not be a party to any gas
purchase agreement that Atlas or its Affiliates enters into with a
third party and shall not have any rights pursuant to such gas
purchase agreement. Further, the Partnership or the successor
Managing General Partner shall not receive any interest in Atlas'
and its Affiliates' pipeline or gathering system or compression
facilities.
At any time commencing ten years after the Offering Termination
Date of the Partnership and the Partnership's primary drilling
activities, the Managing General Partner may voluntarily withdraw
as Managing General Partner upon giving 120 days' written notice
of withdrawal to the Participants and its interest in the
Partnership shall be determined as provided above with respect to
removal. Such interest shall be distributed to the Managing
General Partner as described above with respect to voluntary
removal, subject to the option of any successor Managing General
Partner to purchase 20% of such interest at the value determined
as described above with respect to removal.
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
pursuant to the conditions set forth in 6.03. The Managing
General Partner shall fully indemnify the Partnership against any
additional expenses which may result from a partial withdrawal of
its interests and such withdrawal may not result in a greater
amount of Direct Costs or Administrative Costs being allocated to
the Participants. The expenses of withdrawing shall be borne by
the withdrawing Managing General Partner.
4.04(a)(4). REMOVAL OF OPERATOR. The Operator may be removed and
a new Operator may be substituted at any time upon 60 days advance
written notice to the outgoing Operator by the Managing General
Partner acting on behalf of the Partnership upon the affirmative
vote of Participants whose Agreed Subscriptions equal a majority
of the Partnership Subscription. The Operator shall not be removed
until a substituted Operator has been selected by an affirmative
vote of Participants whose Agreed Subscriptions equal a majority
of the Partnership Subscription and installed as such.
4.05. INDEMNIFICATION AND EXONERATION.
4.05(a). GENERAL STANDARDS. The Managing General Partner, the
Operator and their Affiliates shall have no 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 the Managing General Partner, the Operator and their
Affiliates, determined in good faith that such course of conduct
was in the best interest of the Partnership, the Managing General
Partner, the Operator and their Affiliates were acting on behalf
of or performing services for the Partnership and such course of
conduct did not constitute negligence or misconduct of the
Managing General Partner, the Operator or their Affiliates.
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 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, the Managing General Partner, the Operator and their
Affiliates were acting on behalf of or performing services for the
Partnership and such 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
tangible net assets of the Partnership, including any insurance
proceeds.
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 (1) there has been a successful adjudication on the
merits of each count involving alleged securities law violations
as to the particular indemnitee; (2) such claims have been
dismissed with prejudice on the merits by a court of competent
jurisdiction as to the particular indemnitee, or (3) 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 Securities and Exchange Commission, the
Massachusetts Securities Division, and the position of any state
securities regulatory authority in which plaintiffs claim they
were offered or sold Partnership Units, with respect to the issue
of indemnification for violation of securities laws.
The advancement of Partnership funds to the Managing General
Partner or its 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: (1) the legal action relates to acts or omissions with
respect to the performance of duties or services on behalf of the
Partnership; (2) 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 such advancement; and (3) 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 the Managing
General Partner, the Operator or their Affiliates could not be
indemnified pursuant to the first two paragraphs of this 4.05(a).
4.05(b). LIABILITY OF PARTNERS. Pursuant to the Pennsylvania
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 hereby agree that
each shall be solely and individually responsible only for his pro
rata share of the liabilities and obligations of the Partnership.
In addition, Atlas and Atlas Group agree to use their corporate
assets and not the assets of the Partnership to indemnify each of
the Investor General Partners against all Partnership related
liabilities which exceed such Investor General Partner's interest
in the undistributed net assets of the Partnership and insurance
proceeds, if any. Further, Atlas and Atlas Group agree to
indemnify each Investor General Partner against any personal
liability as a result of the unauthorized acts of another Investor
General Partner. Upon such indemnification by Atlas and Atlas
Group, each Investor General Partner who has been indemnified
shall and does hereby transfer and subrogate his rights for
contribution from or against any other Investor General Partner to
Atlas and/or Atlas Group.
4.05(c). ORDER OF PAYMENT. Claims shall be paid first out of any
insurance proceeds, next out of the assets and revenues of the
Partnership, and finally by the Managing General Partner as
provided in 3.05(b) and 4.05(b). No Limited Partner shall be
required to reimburse the Managing General Partner, the Operator
or their Affiliates or the Investor General Partners for any
liability in excess of his agreed Capital Contribution, except for
a liability resulting from such Limited Partner's unauthorized
participation in Partnership management, or from some other breach
by such Limited Partner of this Agreement.
4.05(d). AUTHORIZED TRANSACTIONS. 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 to be entered into or taken with such party 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. 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 oil and gas
business, including, without limitation, the evaluation,
acquisition and sale of producing and nonproducing Leases, and
the exploration for and production of oil, gas, 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, such parties may
continue such 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; may
reserve partial interests in Leases being assigned to the
Partnership or any other interests not expressly prohibited by
this Agreement; may deal with the Partnership as independent
parties or through any other entity in which they may be
interested; may conduct business with the Partnership as set forth
herein; may participate in such other investor operations, as
investors or otherwise; and shall not be required to permit the
Partnership or the Participants to participate in any such
operations in which they may be interested or share in any profits
or other benefits therefrom. However, except as otherwise provided
herein, the Managing General Partner and any of 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 such opportunity either cannot be
pursued by the Partnership because of insufficient funds or
because it is not appropriate for the Partnership under the
existing circumstances. Atlas or its Affiliates may manage
multiple programs simultaneously. Notwithstanding any other
provision in this Agreement, the Partnership shall not be a party
to any gas supply agreement that Atlas or its Affiliates enters
into with a third party and shall not have any rights pursuant to
such gas supply agreement. Further, the Partnership shall not
receive any interest in Atlas' and its 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 5.01 and its subsections.
5.01(a). COSTS. Costs shall be charged as follows:
(1) Organization and Offering Costs shall be charged 100%
to the Managing General Partner. For purposes of sharing in
revenues, pursuant to 5.01(b)(4), the Managing General
Partner shall be credited with Organization and Offering
Costs up to and including 15% of the Partnership
Subscription which were paid by the Managing General
Partner. Notwithstanding, Organization and Offering Costs
in excess of 15% of the Partnership Subscription shall be
charged 100% to the Managing General Partner without
recourse to the Partnership and the Managing General
Partner shall not be credited with such amounts towards its
required Capital Contribution.
(2) Intangible Drilling Costs shall be charged 100% to the
Participants.
(3) Tangible Costs shall be charged 14% to the Managing
General Partner and 86% to the Participants.
(4) Operating Costs, Direct Costs, Administrative Costs
and all other Partnership costs not specifically allocated
shall be charged 75% to the Participants and 25% to the
Managing General Partner. Provided, however, in the event a
portion of the Managing General Partner's Partnership Net
Production Revenues are subordinated pursuant to
5.01(b)(4), all such Operating Costs, Direct Costs,
Administrative Costs and all other Partnership costs not
specifically allocated shall be charged between the
Managing General Partner and the Participants in the same
ratio as the related production revenues are being
credited.
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 such 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,
each Participant will pay the same amount of such costs regardless
of when he subscribes.
5.01(b). REVENUES. Revenues of the Partnership from all sources
and wells shall be commingled and credited as follows:
(1) If the Partners' Capital Accounts are adjusted to
reflect the simulated depletion of an oil or gas property
of the Partnership, the portion of the total amount
realized by the Partnership upon the taxable disposition of
such property that represents recovery of its simulated tax
basis therein shall be allocated to the Partners in the
same proportion as the aggregate adjusted tax basis of such
property was allocated to such Partners (or their
predecessors in interest). If the Partners' Capital
Accounts are adjusted to reflect the actual depletion of an
oil or gas property of the Partnership, the portion of the
total amount realized by the Partnership upon the taxable
disposition of such property that equals the Partners'
aggregate remaining adjusted tax basis therein shall be
allocated to the Partners in proportion to their respective
remaining adjusted tax bases in such property. Thereafter,
any excess shall be allocated to Atlas 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 such time.
Finally, any excess shall be credited to the parties in
accordance with the sharing ratios provided in (4), below.
In the event of a sale of developed oil and gas properties
with equipment thereon, the Managing General Partner may
make any reasonable allocation of proceeds between the
equipment and the Leases.
(2) Interest earned on Agreed Subscriptions before the
Offering Termination Date pursuant to 3.05(b) shall be
credited to the accounts of the respective subscribers who
paid such subscriptions to the Partnership and paid
approximately eight weeks after the Offering Termination
Date. After the Offering Termination Date and until
proceeds from the offering are invested in the
Partnership's oil and gas operations, any interest income
from temporary investments shall be allocated pro rata to
the Participants providing such Agreed Subscriptions. All
other interest income, including interest earned on the
deposit of production revenues, shall be credited as
provided in (4), below.
(3) Proceeds from the sale or disposition of equipment
shall be credited to the parties charged with the costs of
such equipment in the ratio in which such costs were
charged.
(4) All other revenues of the Partnership shall be
credited 75% to the Participants and 25% to the Managing
General Partner. Notwithstanding, the Managing General
Partner shall subordinate a part of its Partnership
production revenues in an amount up to 10% of the
Partnership's Net Production Revenues (which are net of
the related costs as provided in 5.01(a)(4)), to the
receipt by Participants of cash distributions from the
Partnership equal to 10% of their Agreed Subscriptions in
each of the first five twelve-month periods of Partnership
operations commencing with the first distribution of
revenues to the Participants. In this regard, however, the
Managing General Partner shall not subordinate an amount
greater than 10% of the Partnership's production revenues
net of the related costs as provided in 5.01(a)(4) in any
such distribution period. The subordination shall be
determined by:
(i) carrying forward to subsequent twelve-month
periods the amount, if any, by which cumulative cash
distributions to Participants (including any
subordination payments) are less than 10% of
Participants' Agreed Subscriptions in the first twelve-
month period, 20% of Participants' Agreed Subscriptions
in the second twelve-month period, 30% of Participants'
Agreed Subscriptions in the third twelve-month period,
or 40% of Participants' Agreed Subscriptions in the
fourth twelve-month period (no carry forward is
required if such distributions are less than 50% of
Participants' Agreed Subscriptions in the fifth twelve-
month period because the Managing General Partner's
subordination obligation terminates upon the expiration
of the fifth twelve-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 10%
of Participants' Agreed Subscriptions in the first
twelve-month period, 20% of Participants' Agreed
Subscriptions in the second twelve-month period, 30% of
Participants' Agreed Subscriptions in the third twelve-
month period, 40% of Participants' Agreed Subscriptions
in the fourth twelve-month period, or 50% of
Participants' Agreed Subscriptions in the fifth twelve-
month period.
The Managing General Partner's subordination obligation shall be
determined and paid at the time of each Partnership distribution
during the subordination period, and may be prorated in the
Managing General Partner's discretion (e.g. in the case of a
quarterly distribution, the Managing General Partner will not have
any subordination obligation if the distributions to Participants
equal 2.5% or more of their Agreed Subscriptions assuming there is
no subordination owed for any preceding periods). The Managing
General Partner shall not be required to return Partnership
distributions previously received by it, even though a
subordination obligation arises subsequent to such distributions,
and no subordination payments to Participants or reimbursements to
the Managing General Partner shall be made after the expiration of
the fifth twelve-month subordination period. Subject to the
foregoing provisions of this 5.01(b)(4), 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, such distributions to the
Participants and reimbursements to the Managing General Partner.
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 and revenues shared or credited
to the Participants as a group shall be allocated among the
Participants (including the Managing General Partner to the extent
of any optional subscription pursuant to 3.03(b)(2)) in the ratio
of their respective Agreed Subscriptions.
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 such
Partnership Well or additional operation are being charged or
credited.
5.01(c)(3). DISCRETION IN MAKING ALLOCATIONS. In determining the
proper method of allocating charges or credits among the parties,
or in making any other allocations hereunder, the Managing General
Partner may adopt any method of allocation which it, in its
reasonable discretion, selects, if, in its sole discretion based
on advice from its legal counsel or accountants, a revision to
such allocations is required for such allocations to be recognized
for federal income tax purposes either because of the promulgation
of Treasury Regulations or other developments in the tax law. Any
new allocation provisions shall be provided by an amendment to
this Agreement and shall be made in a manner that would result in
the most favorable aggregate consequences to the Participants as
nearly as possible consistent with the original allocations
described herein.
5.02. CAPITAL ACCOUNTS AND ALLOCATIONS THERETO.
5.02(a). CAPITAL ACCOUNTS. A single, separate Capital Account
shall be established for each party to this Agreement, regardless
of the number of interests owned by such party, the class of the
interests and the time or manner in which such interests were
acquired.
5.02(b). CHARGES AND CREDITS. Except as otherwise provided in
this Agreement, the Capital Account of each party shall be
determined and maintained in accordance with Treas. Reg.
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 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 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. 1.704-l(b)(2)(iv)(g), but excluding
income and gain described in Treas. Reg. 1.704-l(b)(4)(i); and
shall be decreased by (iv) the amount of money distributed to him
by the Partnership; (v) the fair market value of property
distributed to him (without regard to 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
752 of the Code); (vi) allocations to him of Partnership
expenditures described in 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.
1.704-l(b)(2)(iv)(g), but excluding items described in (vi)
above, and loss or deduction described in Treas. Reg.
1.704-l(b)(4)(i) or (iii). If Treas. Reg.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 Partners 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 Partners; 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 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 such payments.
5.02(d). DISCRETION OF MANAGING GENERAL PARTNER. 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 704 and other provisions of the Code and such
rules, regulations and interpretations relating thereto 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 Partners 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
704(c) of the Code and the regulations thereunder) on the
Partnership's books, in accordance with Treas. Reg.
1.704-l(b)(2)(iv)(f).
5.02(f). AMOUNT OF BOOK ITEMS. In cases where 704(c) of the Code
or 5.02(e) applies, Capital Accounts shall be adjusted in
accordance with Treas. Reg. 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 such property.
5.03. ALLOCATION OF INCOME, DEDUCTIONS AND CREDITS.
5.03(a). IN GENERAL. To the extent permitted by law and except as
otherwise provided in this Agreement, all deductions and credits,
including, but not limited to, intangible drilling and development
costs and depreciation, shall be allocated to the party who has
been charged with the expenditure giving rise to such deductions
and credits; and to the extent permitted by law, such parties
shall be entitled to such deductions and credits in computing
taxable income or tax liabilities to the exclusion of any other
party. 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 5.01(b) and its subsections.
5.03(b). TAX BASIS. Subject to 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 upon the capital interest in the Partnership
as to such property and the capital interest in the Partnership
for such purpose as to each property shall be considered to be
owned by the parties hereto in the ratio in which the expenditure
giving rise to the tax basis of such 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 oil
and gas property in accordance with the provisions of
613A(c)(7)D) of the Code, and the calculation of such gain or
loss shall consider the party's adjusted basis in his property
interest computed as provided in 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 such sale or other
disposition exceeds its contribution to the adjusted basis of the
property in the ratio that such excess bears to the sum of the
excesses of all parties having such 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 such sale,
abandonment or other disposition in the proportion that such
excess bears to the sum of the excesses of all parties having such
an excess.
5.03(f). RECAPTURE. Any recapture treated as an increase in
ordinary income by reason of 1245, 1250, or 1254 of the Code
shall be allocated to the parties in the amounts in which such
recaptured items were previously allocated to them; provided that
to the extent recapture allocated to any party is in excess of
such party's gain from the disposition of the property, such
excess shall be allocated to the other parties but only to the
extent of such 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 such year, then the Partners' interests in the Partnership
with respect to such credit (or the cost giving rise thereto)
shall be in the same proportion as such Partners' respective
distributive shares of such loss or deduction (and adjustments).
Identical principles shall apply in determining the Partners'
interests in the Partnership with respect to tax credits that
arise from receipts of the Partnership (whether or not taxable).
5.03(h). DEFICIT CAPITAL ACCOUNTS AND QUALIFIED INCOME OFFSET.
Notwithstanding any provisions of this Agreement to the contrary,
an allocation of loss or deduction which would result in a Partner
having a deficit Capital Account balance as of the end of the
taxable year to which such allocation relates, if charged to such
Partner, (to the extent such Partner is not required to restore
such deficit to the Partnership), taking into account: (i)
adjustments that, as of the end of such year, reasonably are
expected to be made to such Partner's Capital Account for
depletion allowances with respect to the Partnership's oil and gas
properties; (ii) allocations of loss and deduction that, as of the
end of such year, reasonably are expected to be made to such
Partner pursuant to 704(e)(2) and 706(d) of the Code and Treas.
Reg. 1.751-1(b)(2)(ii); and (iii) distributions that, as of the
end of such year, reasonably are expected to be made to such
Partner to the extent they exceed offsetting increases to such
Partner'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 such distributions
reasonably are expected to be made, shall be charged to the
Managing General Partner; provided further, the Managing General
Partner shall be credited with an additional amount of Partnership
income or gain equal to the amount of such loss or deduction as
quickly as possible (to the extent such chargeback does not cause
or increase deficit balances in the Partners' Capital Accounts
which are not required to be restored to the Partnership).
Notwithstanding any provisions of this Agreement to the contrary,
if such Partner 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
such Partner's Capital Account which is not required to be
restored to the Partnership, such Partner 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 such
year) in an amount and manner sufficient to eliminate such deficit
balance as quickly as possible.
5.03(i). PARTNERS' ALLOCABLE SHARES. Except as otherwise provided
in this Agreement, each Partner'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 Partners in the Partnership during the taxable
year. In the absence of such regulations or guidelines, except as
otherwise provided in this Agreement, such 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 Partner's varying interest in the Partnership
on each day during the taxable year.
5.04. ELECTIONS.
5.04(a). INTANGIBLES ELECTION. 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 provisions
of Subchapter K of the Code.
5.04(c). CONTINGENT INCOME. If it is determined that any taxable
income results to any party by reason of its entitlement to a
share of profits or revenues of the Partnership before such 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 such party.
5.04(d). 754 ELECTION. In the event of the transfer of an
interest in the Partnership, or upon the death of an individual
party hereto, or in the event of the distribution of property to
any party hereto, 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
by734 and 743 of the Code.
5.05. DISTRIBUTIONS.
5.05(a). IN GENERAL. The Managing General Partner shall review
the accounts of the Partnership at least quarterly to determine
whether cash distributions are appropriate and the amount to be
distributed, if any. 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. In no event, however, shall funds be
advanced or borrowed for purposes of distributions, if the amount
of such distributions would exceed the Partnership's accrued and
received revenues for the previous four quarters, less paid and
accrued Operating Costs with respect to such revenues. The
determination of such revenues and costs shall be made in
accordance with generally accepted accounting principles,
consistently applied. Cash distributions from the Partnership to
the Managing General Partner shall only be made in conjunction
with distributions to Participants and only out of funds properly
allocated to the Managing General Partner's account.
At any time after three years 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 said well. All such 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 such 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 twelve months of the Offering Termination Date
of the Partnership, except necessary operating capital, shall be
distributed pro rata to the Participants in the ratio of their
Agreed Subscriptions to the Partnership, as a return of capital
and the Managing General Partner shall reimburse the Participants
for the selling or other offering expenses allocable to the return
of capital. For purposes of this subsection, "committed for
expenditure" shall mean contracted for, actually earmarked for or
allocated by the Managing General Partner to the Partnership's
drilling operations, and "necessary operating capital" shall mean
those funds which, in the opinion of the Managing General Partner,
should remain on hand to assure continuing operation of the
Partnership.
5.05(c). DISTRIBUTIONS ON WINDING UP. Upon the winding up of the
Partnership distributions shall be made as provided in 7.02.
5.05(d). INTEREST AND RETURN OF CAPITAL. It is agreed among the
parties hereto that no party shall under any circumstances be
entitled to any interest on amounts retained by the Partnership,
and that 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). IN GENERAL. In addition to other restrictions on
transferability provided in this Agreement, interests in the
Partnership (and any rights to income or other attributes of Units
in the Partnership) shall be nontransferable except transfers to
or with the consent of the Managing General Partner where the
transfer of a Participant's interest is involved, and, except as
otherwise provided in this Agreement, the consent of Participants
whose Agreed Subscriptions equal a majority of the Partnership
Subscription where a transfer by the Managing General Partner is
involved. Unless an assignee becomes a substituted Partner in
accordance with the provisions set forth below, he shall not be
entitled to any of the rights granted to a Partner hereunder,
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). OBJECTIONS TO TRANSFER. Failure to notify the
transferring party of an objection to any proposed or completed
transfer of the transferor's interest hereunder within thirty days
following the receipt of notice thereof shall conclusively serve
as a consent to such transfer.
6.01(c). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED
PARTNER INTERESTS. After substantially all of the Partnership
Wells have been drilled and completed the Managing General Partner
shall file an amended certificate of limited partnership with the
Secretary of State of the Commonwealth of Pennsylvania for the
purpose of converting the Investor General Partner Units to
Limited Partner interests. Upon such 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 prior to the conversion of their Units as provided in
3.05(b). Such conversion shall not affect the allocation to any
Partner of any item of Partnership income, gain, loss, deduction
or credit or other item of special tax significance (other than
Partnership liabilities, if any) and shall not affect any
Partner's interest in the Partnership's oil and gas properties and
unrealized receivables.
Notwithstanding the foregoing, the Managing General Partner shall
notify all Participants at least thirty days prior to the
effective date of any adverse material change in the Partnership's
insurance coverage. If the insurance coverage is to be materially
reduced, the Investor General Partners shall have the right to
convert their Units into Limited Partner interests prior to such
reduction by giving written notice to the Managing General
Partner.
6.02. SPECIAL RESTRICTIONS ON TRANSFERS.
6.02(a). IN GENERAL. 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. The costs and expenses
associated with the assignment must be paid by the assignor
Partner and the assignment must be in a form satisfactory to the
Managing General Partner. The terms of the assignment must not
contravene those of this Agreement. Transfers of interest in the
Partnership are subject to the following additional restrictions.
6.02(a)(1). SECURITIES LAWS RESTRICTION. Subject to transfers
permitted by 6.04 and transfers by operation of law, no interest
in the Partnership shall be sold, assigned, pledged, hypothecated
or transferred in the absence of an effective registration of the
Units under the Securities Act of 1933, as amended and
qualification under applicable state securities laws or an opinion
of counsel acceptable to the Managing General Partner that such
registration and qualification are not required. Transfers are
also subject to any conditions contained in the Subscription
Agreement and Exhibit (B) to the Prospectus.
6.02(a)(2). TAX LAW RESTRICTIONS. No sale, exchange, transfer or
assignment shall be made which, in the opinion of counsel to the
Partnership, would result in the Partnership being considered to
have been terminated for purposes of Section 708 of the Code or
would result in materially adverse tax consequences to the
Partnership or the Partners.
6.02(a)(3). SUBSTITUTE PARTNER. An assignee of a Limited
Partner's or Investor General Partner's interest in the
Partnership shall become a substituted Limited Partner or Investor
General Partner entitled to all the rights of a Limited Partner or
Investor General Partner, as the case may be, if, and only if: (i)
the assignor gives the assignee such right; (ii) the Managing
General Partner consents to such substitution, which consent shall
be in the Managing General Partner's absolute discretion; (iii)
the assignee pays to the Partnership all costs and expenses
incurred in connection with such substitution; and (iv) the
assignee executes and delivers such instruments, in form and
substance satisfactory to the Managing General Partner, necessary
or desirable to effect such substitution and to confirm the
agreement of the assignee to be bound by all of the terms and
provisions of this Agreement. A substitute Limited Partner or
Investor General Partner 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. The Partnership shall amend its
records at least once each calendar quarter to effect the
substitution of substituted Participants. Any transfer permitted
hereunder where the assignee does not become a substituted Limited
Partner or Investor General Partner shall be effective as of
midnight of the last day of the calendar month in which it is
made, or, at the Managing General Partner's election, 7:00 A.M. of
the following day. No such transfer, including a transfer of less
than all of a party's rights hereunder or the transfer of rights
hereunder to more than one party, shall relieve the transferor of
its responsibility for its proportionate part of any expenses,
obligations and liabilities hereunder related to the interest so
transferred, whether arising prior or subsequent to such transfer,
nor shall any such transfer require an accounting by the Managing
General Partner, or the granting of rights hereunder as between
such parties and the remaining parties hereto, including the
exercise of any elections hereunder, to more than one party
unanimously designated by the transferees and, if he should have
retained an interest hereunder, the transferor.
Until a proper designation acceptable to it is received by the
Managing General Partner, it shall continue to account only to the
person to whom it was furnishing notices prior to such time
pursuant to 8.01 and its subsections; and such party shall
continue to exercise all rights applicable to the entire interest
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 hereunder), to hypothecate, pledge, or otherwise
encumber, on any terms it sees fit, its Partnership interest (or
an undivided interest in the assets of the Partnership equal to or
less than its respective interest in the revenues of the
Partnership) to obtain funds for use by it for its own general
purposes. All repayments of such borrowings and costs and interest
or other charges related thereto shall be borne and paid
separately by the Managing General Partner; and in no event shall
such repayments, costs, interest, or other charges be charged to
the account of the Participants. In addition, subject to a
required participation of not less than 1% of the Partnership
Subscription, the Managing General Partner may 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 if such withdrawal is
necessary to satisfy the bona fide request of its creditors or
approved by Participants whose Agreed Subscriptions equal a
majority of the Partnership Subscription.
6.04. REPURCHASE OBLIGATION.
6.04(a). IN GENERAL. Participants shall have the right to present
their interests to the Managing General Partner subject to the
conditions and limitations set forth in this section. The Managing
General Partner shall not purchase more than 5% of the Units in
any calendar year and shall not purchase less than one Unit of a
Participant's interests in the Partnership unless such lesser
amount represents the entire amount of the Participant's interest.
The Managing General Partner may waive these limitations in its
sole discretion other than the limitation that it shall not
purchase more than 5% of the Units in any calendar year. The
Participant is not obligated to accept such repurchase offer.
The Managing General Partner shall offer to repurchase a
Participant's interest in cash in every year beginning in 2001.
The commencement of the offer must be made within 120 days of the
reserve report set forth in 4.03(b)(3). A Participant may accept
the repurchase offer by a written acceptance. No repurchase shall
be considered effective until after the payment has been made to
the Participant in cash. In addition, in accordance with Treas.
Reg. 1.7704-1(f), no repurchase shall occur until at least 60
calendar days after the Participant notifies the Partnership in
writing of the Participant's intention to exercise the repurchase
right.
6.04(b). INDEPENDENT PETROLEUM CONSULTANT. The amount attributable
to Partnership reserves shall be determined based upon the last
reserve report of the Partnership prepared by the Managing General
Partner and reviewed by the 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, and in making this estimate, it shall employ a discount
rate equal to 10%, use a constant price for the oil and base the
price of gas upon the existing gas contracts at the time of the
repurchase. The calculation of the repurchase price shall be as
set forth in6.04(c).
6.04(c). CALCULATION OF REPURCHASE PRICE. The purchase price
shall be based upon the Participant's share of the net assets and
liabilities of the Partnership and allocated pro rata to each
Participant based upon his Agreed Subscription. The repurchase
price shall include the sum of the following items:
(i) an amount based on 70% of the present worth of future
net revenues from the Partnership's Proved Reserves
determined as described in 6.04(b);
(ii) Partnership cash on hand;
(iii) prepaid expenses and accounts receivable of the
Partnership, less a reasonable amount for doubtful
accounts; and
(iv) the estimated market value of all assets of the
Partnership, 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 Partnership 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; provided,
however, that if any cash distributed was derived from the
sale, subsequent to the request, of oil, gas or other
mineral production, or of a producing property owned by the
Partnership, for purposes of determining the reduction of
the purchase price, such 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.
The purchase price may be further adjusted by the Managing General
Partner for estimated changes therein from the date of such report
to the date of payment of the purchase price to the Participants:
(i) by reason of production or sales of, or additions to, reserves
and lease and well equipment, sale or abandonment of Leases, and
similar matters occurring prior to the request for repurchase, and
(ii) by reason of any of the following occurring prior to payment
of the purchase price to the selling Participants: changes in well
performance, increases or decreases in the market price of oil,
gas, or other minerals, revision of regulations relating to the
importing of hydrocarbons, changes in income, ad valorem, and
other tax laws (e.g. material variations in the provisions for
depletion) and similar matters.
6.04(d). SELECTION BY LOT. If less than all interests presented
at any time are to be purchased, the Participants whose interests
are to be purchased will be selected by lot. The Managing General
Partner's obligation to purchase such interests may be discharged
for the benefit of the Managing General Partner by a third party
or an Affiliate. The interests 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
interest, together with such other documentation as the Managing
General Partner may reasonably request.
6.04(e). 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 repurchase
obligations under this section.
6.04(f). SUSPENSION OF REPURCHASE OBLIGATION. The Managing
General Partner may suspend its repurchase obligation at any time
if it does not have sufficient cash flow or is unable to borrow
funds for such purpose on terms it deems reasonable, by so
notifying the Participants. In addition, the Managing General
Partner's repurchase obligation may be conditioned, in the
Managing General Partner's sole discretion, on the Managing
General Partner's receipt of an opinion of counsel that such
transfers will not cause the Partnership to be treated as a
"publicly traded partnership" under the Code. The Managing General
Partner shall hold such repurchased 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 fifty years from the effective date of
this Agreement unless sooner terminated as hereinafter set forth.
7.01(b). TERMINATION. The Partnership shall terminate following
the occurrence of a Final Terminating Event, or upon the
occurrence of any event which under the Pennsylvania Revised
Uniform Limited Partnership Act causes the dissolution of a
limited partnership.
7.01(c). CONTINUANCE OF PARTNERSHIP. Except upon 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. Such
successor limited partnership shall succeed to all of the assets
of the Partnership. As used throughout this Agreement, the term
"Partnership" shall include such successor limited partnerships
and the parties thereto.
7.02. DISSOLUTION AND WINDING UP. Upon 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 assets of the Partnership.
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 the end of the taxable
year in which liquidation occurs (determined without regard to
706(c)(2)(A) of the Code) or, if later, within ninety days after
the date of such liquidation. Provided, however, amounts withheld
for reserves reasonably required for liabilities of the
Partnership and installment obligations owed to the Partnership
need not be distributed within the foregoing time period so long
as such withheld amounts are distributed as soon as practicable.
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:
(1) the Managing General Partner shall offer the
individual Participants the election of receiving in kind
property distributions and the Participants accept such
offer after being advised of the risks associated with such
direct ownership; or
(2) 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.
It shall be presumed that a Participant has refused such consent
if the Managing General Partner has not received such consent
within thirty days after the Managing General Partner mailed the
request for such consent. Any Partnership asset which would
otherwise be distributed in kind to a Participant, but for the
failure or refusal of such Participant to give his written consent
to such 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.
ARTICLE VIII
MISCELLANEOUS PROVISIONS
8.01. NOTICES.
8.01(a). METHOD. Any notice required hereunder shall be in
writing, and given by mail or wire addressed to the party to
receive such notice at the address designated in 1.03.
8.01(b). CHANGE IN ADDRESS. The address of any party hereto may
be changed by written notice to the other parties hereto in the
event of a change of address by the Managing General Partner or to
the Managing General Partner in the event of a change of address
by a Participant. However, in the event of a transfer of rights
hereunder, no notice to any such transferee shall be required, nor
shall such transferee have any rights hereunder, until notice
thereof shall have been given to the Managing General Partner. Any
transfer of rights hereunder shall not increase the duty to give
notice, and in the event of a transfer of rights hereunder to more
than one party, notice to any owner of any interest in such rights
shall be notice to all owners thereof.
8.01(c). TIME NOTICE DEEMED GIVEN. Any notice shall be considered
given, and any applicable time shall run, from the date such
notice is placed in the mails or delivered to the telegraph
company as to any notice given by the Managing General Partner and
when received as to any notice given by any Participant.
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 whether or not such notice is
actually received, and irrespective of any disability or death on
the part of the noticee, whether or not known to the party giving
such notice.
8.01(e). FAILURE TO RESPOND. Except where this Agreement
expressly requires affirmative approval of a Participant, any
Participant who fails to respond in writing within the time
specified for such response (which time shall be not less than
fifteen business days from the date of mailing of such request) to
a request by the Managing General Partner for approval of or
concurrence in a proposed action shall be conclusively deemed to
have approved such action.
8.02. TIME. Time is of the essence of each part of this
Agreement.
8.03. APPLICABLE LAW. The terms and provisions hereof shall be
construed under the laws of the Commonwealth of Pennsylvania,
provided, however, this 8.03 shall not be deemed to limit causes
of action for violations of federal or state securities law to the
laws of the Commonwealth of Pennsylvania. 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 upon all parties executing
this or similar agreements from and after the date of execution by
each party.
8.05. AMENDMENT. No changes herein shall be binding unless
proposed in writing by the Managing General Partner, and adopted
with the consent of Participants whose Agreed Subscriptions equal
a majority of the Partnership Subscription; or unless proposed in
writing by Participants whose Agreed Subscriptions equal 10% or
more of the Partnership Subscription and approved by an
affirmative vote of Participants whose Agreed Subscriptions equal
a majority of the Partnership Subscription. However, the Managing
General Partner is authorized to amend this Agreement and its
exhibits without such consent in any way deemed necessary or
desirable by it: (i) to add or substitute (in the case of an
assigning party) additional Limited Partners or Investor General
Partners; (ii) to enhance the tax benefits of the Partnership to
the parties; and (iii) to satisfy any requirements, conditions,
guidelines, options, or elections contained in any opinion,
directive, order, ruling, or regulation of the Securities and
Exchange Commission, the Internal Revenue Service, or any other
federal or state agency, or in any federal or state statute,
compliance with which it deems to be in the best interest of the
Partnership. Notwithstanding the foregoing, no amendment
materially and adversely affecting the interests or rights of
Participants shall be made without the consent of the Participants
whose interests will be so affected.
8.06. ADDITIONAL PARTNERS. Each Participant hereby consents to
the admission to the Partnership of such additional Limited
Partners or Investor General Partners as the Managing General
Partner, in its discretion, chooses to admit.
8.07. LEGAL EFFECT. This Agreement shall be binding upon and
inure to the benefit of the parties, their heirs, devisees,
personal representatives, successors and assigns, and shall run
with the interests subject hereto. 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 and seal as
of the day and year hereinabove shown.
ATLAS: ATLAS RESOURCES, INC.
Managing General Partner
By:
Attest:
(SEAL) Secretary
- ------------------------------------------------------------------
EXHIBIT (I-A)
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-ENERGY
FOR THE NINETIES-PUBLIC #6 LTD.
The undersigned agrees:
1. to serve as the Managing General Partner of ATLAS-ENERGY
FOR THE NINETIES-PUBLIC #6 LTD. (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 3.03(b)(1) of the Partnership Agreement;
and
3. to subscribe to the Partnership as follows:
(a) $___________________ [________] Unit(s)] under
3.03(b)(2) of the Partnership Agreement as a Limited
Partner; or
(b) $___________________ [________] Unit(s)] under
3.03(b)(2) of the Partnership Agreement as an
Investor General Partner.
MANAGING GENERAL PARTNER:
Atlas Resources, Inc. Address:
By: ______________________________________ 311 Rouser Road
J.R. O'Mara, President and CEO Moon Township, Pennsylvania
15108
ACCEPTED this ________ day of __________________ , 1997.
ATLAS RESOURCES, INC.
MANAGING GENERAL
PARTNER
By:
______________________________________
J.R. O'Mara,
President and CEO
Attest
______________________________________________
(SEAL) Secretary
- ------------------------------------------------------------------
EXHIBIT (I-B)
SUBSCRIPTION AGREEMENT
ATLAS-ENERGY FOR THE NLNETLES-PUBLLC #6 LTD.
SUBSCRIPTION AGREEMENT
The undersigned hereby offers to purchase Units of Atlas-Energy for the
Nineties-Public #6 Ltd. in the amount set forth on the Signature Page
of this Subscription Agreement and on the terms described in the
current Prospectus for Atlas-Energy for the Nineties-Public #6 Ltd. (as
supplemented or amended from time to time). The undersigned
acknowledges and agrees that his execution of this Subscription
Agreement also constitutes his execution of the Amended and Restated
Certificate and Agreement of Limited Partnership (the "Partnership
Agreement") the form of which is attached as Exhibit (A) to the
Prospectus and the undersigned agrees to be bound by all of the terms
and conditions of the Partnership Agreement if his Agreed Subscription
is accepted by the Managing General Partner. The undersigned
understands and agrees that this offer may not be assigned or withdrawn
by the undersigned. The undersigned hereby irrevocably constitutes and
appoints Atlas Resources, Inc. (and its duly authorized agents) the
undersigned's agent and attorney-in-fact, in the undersigned's name,
place and stead, to make, execute, acknowledge, swear to, file, record
and deliver the Amended and Restated Certificate and Agreement of
Limited Partnership and any certificates related thereto.
In order to induce Atlas to accept this subscription, the undersigned
hereby represents, warrants, covenants and agrees as follows:
_____ The undersigned has received the Prospectus.
_____ The undersigned (other than Minnesota residents)
recognizes that prior to this offering there has been no public
market for the Units and that it is not likely that after the
offering there will be any such market. In addition, the
undersigned understands that the transferability of the Units
is restricted and that he cannot expect to be able to readily
liquidate his investment in the Units in case of emergency or
other change in circumstances.
_____ The undersigned is purchasing the Units for his own
account, for investment purposes and not for the account of
others and he is not purchasing the Units with the present
intention of reselling them.
_____ The undersigned, if he is an individual, is a citizen of
the United States of America and is at least twenty-one years of
age, or, if a partnership, corporation or trust, the members,
stockholders or beneficiaries thereof are citizens of the United
States and each is at least twenty-one years of age.
_____ The undersigned, if he is not an individual, is
empowered and duly authorized under a governing document, trust
instrument, pension plan, 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 the exhibits thereto.
_____ (a) The undersigned has: (i) a net worth of at least
$225,000 (exclusive of home, furnishings and automobiles);
or (ii) a net worth (exclusive of home, furnishings and
automobiles) of at least $60,000 and had during the last tax
year, or estimates that he 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.
(B) IN ADDITION, IF A RESIDENT OF ALABAMA, ARIZONA,
CALIFORNIA, KANSAS, INDIANA, IOWA, KENTUCKY, MAINE,
MASSACHUSETTS, MICHIGAN, MINNESOTA, MISSISSIPPI, MISSOURI,
NEW HAMPSHIRE, NEW MEXICO, NORTH CAROLINA, OHIO, OKLAHOMA,
OREGON, PENNSYLVANIA, SOUTH DAKOTA, TENNESSEE, TEXAS,
VERMONT OR WASHINGTON, THE UNDERSIGNED REPRESENTS THAT HE IS
AWARE OF AND MEETS THAT STATE'S QUALIFICATIONS AND
SUITABILITY STANDARDS SET FORTH IN EXHIBIT (B) TO THE
PROSPECTUS.
(c) If a fiduciary, I am purchasing for a person or
entity having the appropriate income and/or net worth
specified in (a) or (b) above.
(d) If a resident of Michigan or Ohio, the undersigned's
investment does not exceed 10% of his net worth (exclusive
of home, furnishings and automobiles).
_____ An Investor General Partner will have unlimited joint and
several liability for Partnership obligations and liabilities
including amounts in excess of his Agreed Subscription to the
extent such obligations and liabilities exceed the Partnership's
insurance proceeds, the Partnership's assets and indemnification
by the Managing General Partner and Atlas Group. Insurance may
be inadequate to cover such liabilities and there is no
insurance coverage for certain claims.
_____ Partnership losses allocable to a Limited Partner generally
may be used only to the extent of his net passive income from
passive activities in such year, with any excess losses being
deferred.
THE ABOVE REPRESENTATIONS DO NOT CONSTITUTE A WAIVER OF ANY RIGHTS THAT
I MAY HAVE UNDER THE ACTS ADMINISTERED BY THE SECURITIES AND EXCHANGE
COMMISSION OR BY ANY STATE REGULATORY AGENCY ADMINISTERING STATUTES
BEARING ON THE SALE OF SECURITIES.
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.
The Soliciting Dealer or registered representative is required to
inform potential investors of all pertinent facts relating to the
Units, including the following:
(a) the risks involved in the offering, including the
speculative nature of the investment and the speculative nature
of drilling for oil and gas;
(b) the financial hazards involved in the offering, including
the risk of losing the entire investment;
(c) the lack of liquidity of this investment;
(d) the restrictions on transferability of the Units;
(e) the background of the Managing General Partner and the
Operator;
(f) the tax consequences of the investment; and
(g) the unlimited joint and several liability of the Investor
General Partners.
Investors are required to execute their own Subscription Agreements.
The Managing General Partner will not accept any Subscription Agreement
that has been executed by someone other than the investor unless such
person has been given the legal power of attorney to sign on the
investor's behalf and the investor meets all of the conditions herein.
In the case of sales to fiduciary accounts, the minimum standards set
forth herein shall 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 interests if the donor or grantor is the
fiduciary.
The execution of the Subscription Agreement by a subscriber constitutes
a binding offer to buy Units in the Partnership and an agreement to
hold the offer open until the Agreed Subscription is accepted or
rejected by the Managing General Partner. Once an investor subscribes
he will not have any revocation rights. The Managing General Partner
has the discretion to refuse to accept any Agreed Subscription without
liability to the subscriber. Agreed Subscriptions will be accepted or
rejected by the Partnership within thirty days of their receipt; if
rejected, all funds will be returned to the subscriber immediately.
Upon the original sale of Units, the Participants will be admitted as
Partners not later than fifteen days after the release from escrow of
Participants' funds to the Partnership, and thereafter Participants
will be admitted into the Partnership not later than the last day of
the calendar month in which their Agreed Subscriptions were accepted by
the Partnership.
The Managing General Partner may not complete a sale of Units to an
investor until at least five business days after the date the investor
receives a final Prospectus. In addition, the Managing General Partner
will send each investor a confirmation of purchase.
NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain
respects from various requirements of Title 10 of the California
Administrative Code. These deviations include, but are not limited to
the following: the definition of Prospect in the Prospectus, unlike
Rule 260.140.127.2(b) and Rule 260.140.121(1) does not require
enlarging or contracting of the size of the area on the basis of
geological data in all cases.
If a resident of California the undersigned acknowledges the receipt of
California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus.
SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
The undersigned agrees to purchase ________ Units of Participation at
$10,000 per Unit in ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD. (the
"Partnership") as (check one):
INVESTOR GENERAL PARTNER AGREED SUBSCRIPTION
LIMITED PARTNER $ ___________________________
(______________________# Units)
Make check payable to: "National City Bank, Escrow Agent, Atlas Public
#6 Ltd."
Minimum Subscription: one Unit ($10,000), however, the Managing General
Partner, in its discretion, may accept one-half Unit ($5,000)
subscriptions; and Additional Subscriptions in $1,000 increments.
Subscriber (All individual investors must personally Address
sign this Signature Page.)
_________________________________________________
____________________________________________________
Print Name
_________________________________________________
____________________________________________________
Signature
_________________________________________________
____________________________________________________
Print Name
_________________________________________________
Signature
_________________________________________________
Name of Entity if a Trust, Corporation or Partnership is
Subscribing
Address for Distributions if
Different from Above
_______________________________
_______________________________
Date: __________________ Telephone No.: Business
______________________________ Home _________________________
Tax I.D. No. (Social Security No.):
_______________________________________________________________________
CHECK ONE): Calendar Year Taxpayer __________ Fiscal Year
Taxpayer __________
(CHECK ONE): OWNERSHIP - Tenants-in-Common ________
Partnership ________
Joint Tenancy ________ C Corporation
________
Individual ________ S Corporation
________
Trust ________ Community Property
________
Other ________
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.
_________________________________________________
____________________________________________________
Registered Representative Name and Number Name of Broker-Dealer
Registered Representative Office Address:
Company Name (if other than Broker-Dealer Name)
Phone Number; Facsimile Number
NOTICE TO BROKER-DEALER:
Send complete and signed and to:
Mr. Eric D. Koval
Anthem Securities, Inc.
P.O. Box 911
Coraopolis, Pennsylvania 15108-0911
(412) 262-1680
TO BE COMPLETED BY ATLAS RESOURCES, INC.
ACCEPTED THIS ______ day
of _________________ , 1997
Attest
(SEAL) Secretary
ATLAS RESOURCES, INC.,
MANAGING GENERAL PARTNER
By:
J.R. O'Mara, President
==================================================================
EXHIBIT (II)
DRILLING AND OPERATING AGREEMENT
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
INDEX
SECTION PAGE
1. Assignment of Well Locations; Representations;
Designation of Additional Well Locations;
Outside Activities 1
2. Drilling of Wells; Interest of Developer; Right
of Substitution 2
3. Operator - Responsibilities in General; Term 3
4. Operator's Charges for Drilling and Completing
Wells; Completion Determination 3
5. Title Examination of Well Locations; Liability for
Title Defects 4
6. Operations Subsequent to Completion of the Wells;
Price Determinations; Plugging and Abandonment 5
7. Billing and Payment Procedure with Respect to
Operation of Wells; Records, Reports and Information
6
8. Operator's Lien 6
9. Successors and Assigns; Transfers; Appointment of
Agent 7
10. Insurance; Operator's Liability 7
11. Internal Revenue Code Election, Relationship of
Parties; Right to Take Production in Kind 8
12. Force Majeure 8
13. Term 9
14. Governing Law and Invalidity 9
15. Integration 9
16. Waiver of Default or Breach 9
17. Notices 9
18. Interpretation 10
19. Counterparts 10
Signature Page 10
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 _______________, 1997, by and
between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter
referred to as "Atlas" or "Operator"),
and
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD., a Pennsylvania limited
partnership, (hereinafter referred to as the "Developer").
WITNESSETH THAT:
WHEREAS, Atlas, by virtue of the Oil and Gas Leases (the "Leases")
described on Exhibit A attached hereto and made a part hereof, has
certain rights to develop the ____________ (______) initial well
locations identified on the maps attached hereto as Exhibits A-l
through A-______ (the "Initial Well Locations");
WHEREAS, the Developer, subject to the terms and conditions hereof,
desires to acquire certain of Atlas' rights to develop the aforesaid
____________ (______) Initial Well Locations and to provide for the
development upon the terms and conditions herein set forth of
additional well locations ("Additional Well Locations") which the
parties may from time to time designate; and
WHEREAS, 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
(hereinafter collectively referred to as the "Well Locations") and to
operate the wells completed thereon, on the terms and conditions herein
set forth;
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. .
(a) Atlas 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 top of
the Queenston formation in Mercer County, Pennsylvania and Ohio. The
assignment shall be substantially in the form of Exhibit B attached
hereto and made a part hereof. The amount of acreage included in each
Initial Well Location and the configuration thereof are indicated on
the maps attached hereto as Exhibits A-l through A-______. The amount
of acreage included in each Additional Well Location and the
configuration thereof shall be indicated on the maps to be attached as
exhibits to the applicable addendum as provided in sub-section (c)
below.
(b) As of the date hereof, Atlas represents and warrants to
the Developer that Atlas is the lawful owner of said Lease and rights
and interest thereunder and of the personal property thereon or used in
connection therewith; that Atlas 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. The
foregoing representations and warranties shall also be made by Atlas at
the time of each recorded assignment of the acreage included in each
Initial Well Location and at the time of each recorded assignment of
the acreage included in each Additional Well Location designated
pursuant to sub-section (c) below, such representations and warranties
to be included in each recorded assignment substantially in the manner
set forth in the form of assignment attached hereto and made a part
hereof as Exhibit B. Atlas 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
aforesaid representations and warranties. It is understood and agreed
that, except as specifically set forth above, Atlas 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) In the event that the parties hereto desire to designate
Additional Well Locations to be developed in accordance with the terms
and conditions of this Agreement, each of said parties shall execute an
addendum substantially in the form of Exhibit C attached hereto and
made a part hereof specifying the undivided percentage of Working
Interest and the Oil and Gas Leases to be included as Leases hereunder,
specifying the amount and configuration of acreage included in each
such Additional Well Location on maps attached as exhibits to such
addendum and setting forth their agreement that such Additional Well
Locations shall be developed in accordance with the terms and
conditions of this Agreement.
(d) 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 described herein and to the Additional Well Locations
designated pursuant to sub-section (c) above. Nothing contained in this
Agreement shall be interpreted to restrict in any manner the right of
each of the parties hereto to conduct without the participation of any
other party hereto 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 aforesaid Initial and
Additional Well Locations or elsewhere.
2. .
(a) Operator, as Developer's independent contractor, agrees to
drill, complete (or plug) and operate ____________ (_____) natural gas
wells on the ____________ (______) Initial Well Locations in accordance
with the terms and conditions of this Agreement, and 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 hereof in proportion to the share of the Working
Interest owned by the Developer in the wells with respect to all
___________ (______) initial wells, it being expressly 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 hereunder.
(b) Operator will use its best efforts to commence drilling
the first well within thirty (30) days after the date of this Agreement
and to commence the drilling of each of said ______________ (_____)
initial wells for which payment is made pursuant to Section 4(b) of
this Agreement, on or before March 31, 1998. Subject to the foregoing
time limits, Operator shall determine the timing of and the order of
the drilling of said ____________ (______) Initial Well Locations.
(c) The ____________ (______) initial wells to be drilled on
the Initial Well Locations designated pursuant to this Agreement and
any additional wells drilled hereunder on any Additional Well Locations
designated pursuant to Section l(c) above shall be 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 shall be drilled to a
depth sufficient to test thoroughly the objective formation or the
deepest assigned depth, whichever is less.
(d) Except as otherwise provided herein, 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 1,500
feet on the Prospect, equipment, materials, and facilities acquired,
constructed or installed hereunder 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 hereunder shall be owned by the Developer
in proportion to the share of the Working Interest owned by the
Developer in the wells.
(e) Notwithstanding the provisions of sub-section (a) above,
in the event the Operator or Developer determines in good faith, with
respect to any Well Location, before operations commence hereunder with
respect to such Well Location, based upon the production (or failure of
production) of any other wells which may have been recently drilled in
the immediate area of such Well Location, or upon newly discovered
title defects, or upon such other evidence with respect to the Well
Location as may be obtained, that it would not be in the best interest
of the parties hereto to drill a well on such Well Location, then the
party making the determination shall notify the other party hereto of
such determination and the basis therefor and, unless otherwise
instructed by Developer, such well shall not be drilled. If such well
is not drilled, Operator shall promptly propose a new well location
(including such information with respect thereto as Developer may
reasonably request) within Pennsylvania or Ohio to be substituted for
such original Well Location and Developer shall thereafter have the
option for a period of seven (7) business days to either reject or
accept the proposed new well location. If the new well location is
rejected, Operator shall promptly propose another substitute well
location pursuant to the provisions hereof. 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 hereof.
3. .
(a) 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 hereunder, (i)
make the necessary arrangements for the drilling and completion of
wells and the installation of the necessary gas gathering line systems
and connection facilities; (ii) make the technical decisions required
in drilling, testing, completing and operating such wells; (iii) manage
and conduct all field operations in connection with the drilling,
testing, completing, equipping, operating and producing of the wells;
(iv) maintain all wells, equipment, gathering lines and facilities in
good working order during the useful life thereof; and (v) perform the
necessary administrative and accounting functions. In the performance
of 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) Operator covenants and agrees that (i) it shall perform
and carry on (or cause to be performed and carried on) its duties and
obligations hereunder 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 aforesaid Well
Locations; (ii) all drilling and other operations conducted by, for and
under the control of Operator hereunder 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 hereunder pursuant to a written estimate
shall conform to the technical specifications set forth in such written
estimate and all equipment and materials installed or incorporated in
the wells and facilities hereunder shall be new or used and of good
quality; (iv) in the course of conducting operations hereunder, it
shall comply with all terms and conditions of the Leases (and any
related assignments, amendments, subleases, modifications and
supplements) other than any minimum drilling commitments contained
therein; (v) it shall keep the Well Locations subject to this Agreement
and all wells, equipment and facilities located thereon, free and clear
of all labor, materials and other liens or encumbrances arising out of
operations hereunder; (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 which are the subject of this
Agreement; and (vii) it will provide competent and experienced
personnel to supervise the drilling, completing (or plugging), and
operating of 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 hereunder.
(c) Atlas shall serve as Operator hereunder until the earliest
of (i) the termination of this Agreement pursuant to Section 13 hereof;
(ii) the termination of Atlas as Operator by the Developer which may be
effected by the Developer at any time in its discretion, with or
without cause; upon sixty (60) days advance written notice to the
Operator; or (iii) the resignation of Atlas as Operator hereunder which
may occur upon ninety (90) days' written notice to the Developer at any
time after five (5) years from the date hereof, it being expressly
understood and agreed that Atlas shall have no right to resign as
Operator hereunder prior to the expiration of the aforesaid five-year
period. Any successor Operator hereunder shall be selected by the
Developer. Nothing contained in this sub-section (c) shall relieve or
release Atlas or the Developer from any liability or obligation
hereunder which accrued or occurred prior to Atlas' removal or
resignation as Operator hereunder. Upon any change in Operator pursuant
to 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
hereunder and owned by the Developer.
4. (a) All natural gas wells which are drilled and
completed hereunder shall be drilled and completed on a footage basis
for a price of $37.39 per foot to the depth of the well at its deepest
penetration as recorded by Operator. The aforesaid footage price for
each of said natural gas wells shall be set forth in an 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
such well for production of natural gas, including 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 examination,
logging, cementing, fracturing, casing, meters (other than utility
purchase meters), connection facilities, salt water collection tanks,
separators, siphon string, rabbit, tubing, an average of 1,500 feet of
gathering line per well, geological and engineering services and
completing two (2) zones; provided, that such footage price shall not
include the cost of (i) completing more than two (2) zones; (ii)
completion procedures, equipment, or any facilities necessary or
appropriate for the production and sale of oil and/or natural gas
liquids; and (iii) equipment or materials necessary or appropriate to
collect, lift or dispose of liquids for efficient gas production,
except that the cost of saltwater collection tanks, separators, siphon
string and tubing shall be included in the aforesaid footage price. Any
such extra costs shall be billed to Developer in proportion to the
share of the Working Interest owned by the Developer in the wells on a
direct cost basis equal to the sum of (i) Operator's invoice costs of
third party services performed and materials and equipment purchased
plus ten percent (10%) to cover supervisory services and overhead; and
(ii) Operator's standard charges for services performed directly by it.
(b) In order to enable Operator to commence site preparation
for ________________ (______) initial wells, to obtain suitable
subcontractors for the drilling and completion of such wells at
currently prevailing prices, and to insure the availability of
equipment and materials, 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 price for all
_________________ (______) initial wells upon execution of this
Agreement, such payment to be nonrefundable in all events, except that
Developer shall not be required to pay completion costs prior to the
time that a decision is made that the well warrants a completion
attempt and Atlas' share of such payments as Managing General Partner
of the Developer shall be paid within five (5) business days of notice
from Operator that such costs have been incurred. With respect to each
additional well drilled on the Additional Well Locations, if any, in
order to enable Operator to commence site preparation, to obtain
suitable subcontractors for the drilling and completion of such wells
at currently prevailing prices, and to insure the availability of
equipment and materials, Developer shall pay Operator, in proportion to
the share of the Working Interest owned by the Developer in the wells,
one hundred percent (100%) of the estimated price for such well upon
execution of the applicable addendum pursuant to Section l(c) above,
except that Developer shall not be required to pay completion costs
prior to the time that a decision is made that the well warrants a
completion attempt and Atlas' share of such payments as Managing
General Partner of the Developer shall be paid within five (5) business
days of notice from Operator that such costs have been incurred. With
respect to each well, Developer shall pay to Operator, in proportion to
the share of the Working Interest owned by the Developer in the wells,
all other costs for such well within five (5) business days of receipt
of notice from Operator that such well has been drilled to the
objective depth and logged and is to be completed. Developer shall pay,
in proportion to the share of the Working Interest owned by the
Developer in the wells, any extra costs incurred with respect to each
well pursuant to sub-section (a) above within ten (10) business days of
its receipt of Operator's statement therefor.
(c) Operator shall determine whether or not to run the
production casing for an attempted completion or to plug and abandon
any well drilled hereunder; provided, however, that 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) If Operator determines at any time during the drilling or
attempted completion of any well hereunder, 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 such well should not be completed, it shall promptly and properly
plug and abandon the same. In such event, such well shall be deemed a
dry hole and the dry hole footage price for each well drilled hereunder
shall be $20.60 per foot multiplied by the depth of the well, as
specified in sub-section (a) above, and shall be charged to the
Developer in proportion to the share of the Working Interest owned by
the Developer in the well. Any amounts paid by the Developer with
respect to such dry hole which exceed the aforesaid dry hole footage
price shall be retained by Operator and shall be applied to the costs
for an additional well or wells to be drilled on the Additional Well
Locations.
5. .
(a) The Developer hereby 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 hereby accepts the title to said 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 Atlas in Section l(b) hereof,
any loss, expense, cost or liability whatsoever caused by or related to
any defect or failure of such title shall be the sole responsibility of
and shall be borne entirely by the Developer.
(b) Prior to commencing the drilling of any well on any
Additional Well Location designated pursuant to this Agreement,
Operator shall conduct, or cause to be conducted, a title examination
of such 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 such Lease. The
results of such 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, and
no drilling shall be commenced until such 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 such 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 Atlas in Section l(b) of
this Agreement.
6. .
(a) Commencing with the month in which a well drilled
hereunder begins to produce, Operator shall be entitled to an operating
fee of $275 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, 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
such wells and related pipelines and facilities. Such operating fees
shall cover all normal, regularly recurring operating expenses for the
production, delivery and sale of natural gas, including without
limitation well tending, routine maintenance and adjustment, reading
meters, recording production, pumping, maintaining appropriate books
and records, preparing reports to the Developer and government
agencies, and collecting and disbursing revenues, but shall not cover
costs and expenses related to the (i) production and sale of oil, (ii)
collection and disposal of salt water or other liquids produced by the
wells, (iii) rebuilding of access roads, and (iv) 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 such
month subject to the aforesaid operating fee.
(b) The monthly operating fee set forth in sub-section (a)
above may in the following manner be adjusted annually as of the first
day of January (the "Adjustment Date") each year beginning January l,
1999. Such adjustment, if any, shall not exceed the percentage
increase in the average weekly earnings of "Crude Petroleum, Natural
Gas, and Natural Gas Liquids" workers, as published by the U.S.
Department of Labor, Bureau of Labor Statistics, and shown in
Employment and Earnings Publication, Monthly Establishment Data, Hours
and Earning Statistical Table C-2, Index Average Weekly Earnings of
"Crude Petroleum, Natural Gas, and Natural Gas Liquids" workers, SIC
Code #131-2, or any successor index thereto, since January l, 1996, in
the case of the first adjustment, and since the previous Adjustment
Date, in the case of each subsequent adjustment.
(c) 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 hereunder reasonably estimated to
result in an expenditure of more than $5,000, unless such project or
extraordinary cost is necessary to safeguard persons or property or to
protect the well or related facilities in the event of a sudden
emergency. In no event, however, shall the Developer be required to pay
for any project or extraordinary cost arising from the negligence or
misconduct of Operator, its agents, servants, employees, contractors,
licensees or invitees. All extraordinary costs incurred and the cost of
projects undertaken with respect to a well being produced hereunder
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 such project all or a portion of the estimated costs
thereof in proportion to the share of the Working Interest owned by the
Developer in the wells.
(d) Developer shall have no interest in the pipeline gathering
system, which gathering system shall remain the sole property of
Operator and shall be maintained at Operator's sole cost and expense.
(e) Notwithstanding anything herein to the contrary, the
Developer shall have full responsibility for and bear 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. Such 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 said Act and the
implementing state regulations. Operator agrees to furnish such
information and render such assistance as the Developer may reasonably
request in order to comply with said Act and the implementing state
regulations without charge for services performed by its employees.
(f) The Developer shall have the right to direct Operator to
plug and abandon any well which has been completed hereunder as a
producer, and Operator shall not plug and abandon any such well prior
to obtaining the written consent of the Developer; provided, however,
that if 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 such well
should be plugged and abandoned and makes a written request to the
Developer for authority to plug and abandon any such well and the
Developer fails to respond in writing to such request within forty-five
(45) days following the date of such request, then the Developer shall
be deemed to have consented to the plugging and abandonment of such
well(s). All costs and expenses related to plugging and abandoning the
wells which have been drilled and completed as producing wells
hereunder shall be borne and paid by the Developer in proportion to the
share of the Working Interest owned by the Developer in the wells. At
any time after three (3) years from the date each well drilled and
completed hereunder 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 operated hereunder up to $200, in proportion
to the share of the Working Interest owned by the Developer in the
wells, for the purpose of establishing a fund to cover the estimated
costs of plugging and abandoning said well. All such 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 such costs.
7. .
(a) 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, all severance taxes,
royalties, overriding royalties, operating fees, pipeline gathering
charges and other expenses and liabilities payable and incurred by
reason of its operation of the wells in accordance with this Agreement
and shall pay, in proportion to the share of the Working Interest owned
by the Developer in the wells, on or before the due date any third
party invoices rendered to Operator with respect to such costs and
expenses; provided, however, that Operator shall not be required to pay
and discharge as aforesaid any such costs and expenses which are being
contested in good faith by Operator. Operator shall deduct the
foregoing costs and expenses from the Developer's share of the proceeds
of the oil and/or gas sold from the wells operated hereunder and shall
keep an accurate record of the Developer's account hereunder, showing
expenses incurred and charges and credits made and received with
respect to each well. In the event that such proceeds are insufficient
to pay said costs and expenses, Operator shall promptly and timely pay
and discharge the same, 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 said costs and expenses, such
invoice to be accompanied by the form of statement specified in
sub-section (b) below. Any such invoice shall be paid by the Developer
within ten (10) business days of its receipt.
(b) 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 hereunder, less (i) the
amounts charged to the Developer under sub-section (a) hereof, and (ii)
such amount, if any, withheld by Operator for future plugging costs
pursuant to sub-section (f) of Section 6. Each such 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 thereof, (ii) the total proceeds received from any
sale thereof, and the Developer's share thereof, (iii) the costs and
expenses deducted from said proceeds and/or being billed to the
Developer pursuant to sub-section (a) above, (iv) the amount withheld
for future plugging costs, and (v) such other information as Developer
may reasonably request, including without limitation copies of all
third party invoices listed thereon for such period. Operator agrees to
deposit all proceeds from the sale of oil and/or gas sold from the
wells operated hereunder in a separate checking account maintained by
Operator, which account shall be used solely for the purpose of
collecting and disbursing funds constituting proceeds from the sale of
production hereunder.
(c) In addition to the statements required under sub-section
(b) above, Operator, within seventy-five (75) days after the completion
of each well drilled hereunder, shall furnish the Developer with a
detailed statement itemizing with respect to such well the total costs
and charges under Section 4(a) hereof and the Developer's share
thereof, and such information as is necessary to enable the Developer
(i) to allocate any extra costs incurred with respect to such well
between tangible and intangible and (ii) to determine the amount of
investment tax credit, if applicable.
(d) Upon request, Operator shall promptly furnish the
Developer with such additional information as it may reasonably
request, including without limitation geological, technical and
financial information, in such form as may reasonably be requested,
pertaining to any phase of the operations and activities governed by
this Agreement. The Developer and its authorized employees, agents and
consultants, including independent accountants shall, at Developer's
sole cost and expense, (i) upon at least ten (10) days' written notice
have access during normal business hours to all of Operator's records
pertaining to operations hereunder, including without limitation, the
right to audit the books of account of Operator relating to all
receipts, costs, charges and expenses under this Agreement, and (ii)
have access, at its sole risk, to any wells drilled by Operator
hereunder at all times to inspect and observe any machinery, equipment
and operations.
8. .
(a) The Developer hereby grants Operator a first and preferred
lien on and security interest in the interest of the Developer covered
by this Agreement, and in the Developer's interest in oil and gas
produced and the proceeds thereof, and upon the Developer's interest in
materials and equipment, to secure the payment of all sums due from
Developer to Operator under the provisions of this Agreement.
(b) In the event that the Developer fails to pay any amount
owing hereunder by it to the Operator within the time limit for payment
thereof, Operator, without prejudice to other existing remedies, is
authorized at its election to collect from any purchaser or purchasers
of oil or gas and retain the proceeds from the sale of the Developer's
share thereof 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 such delinquency, has been paid. Each purchaser of oil
or gas shall be entitled to rely upon Operator's written statement
concerning the amount of any default.
9. .
(a) This Agreement shall be binding upon and shall inure to
the benefit of the undersigned parties and their respective successors
and permitted assigns; provided, however, that 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 hereunder, without the prior written consent of the
Developer, except that such 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 such
assignment to Operator's subcontractors shall not in any manner relieve
or release Operator from any of its obligations and responsibilities
under this Agreement, or (ii) any lien, assignment, security interest,
pledge or mortgage arising under or pursuant to Operator's present or
future financing arrangements, or (iii) the liquidation, merger,
consolidation or sale of substantially all of the assets of Operator or
other corporate reorganization; and provided, further, that 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 hereby
unless such disposition encompasses either (i) the entire interest of
the Developer in all wells, production, equipment and leasehold
interests subject hereto or (ii) an equal undivided interest in all
such wells, production, equipment, and leasehold interests.
(b) 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 hereby shall be made (i) expressly subject to this
Agreement, (ii) without prejudice to the rights of the other party, and
(iii) in accordance with and subject to the provisions of the Lease.
(c) If at any time the interest of the Developer is divided
among or owned by co-owners, Operator may, at its discretion, require
such co-owners to appoint a single trustee or agent with full authority
to receive notices, reports and distributions of the proceeds from
production, to approve expenditures, to receive billings for and
approve and pay all costs, expenses and liabilities incurred hereunder,
to exercise any rights granted to such co-owners under this Agreement,
to grant any approvals or authorizations required or contemplated by
this Agreement, to 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 hereby, and to deal generally with, and with power to
bind, such co-owners with respect to all activities and operations
contemplated by this Agreement; provided, however, that all such
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 hereunder in accordance with
sub-section (c) of Section 11 hereof.
10. .
(a) Operator shall obtain and maintain at its own expense so
long as it is Operator hereunder 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 insurance shall include coverage for blow-outs and
total liability coverage of not less than $10,000,000. Subject to the
aforesaid 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 and all of Developer's
Investor General Partners as additional insured parties, 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 and its Investor General Partners; provided, that the
Developer shall reimburse Operator for the additional cost, if any, of
including it and its Investor General Partners as additional insured
parties under the Operator's insurance. Current copies of all policies
or certificates thereof shall be delivered to the Developer upon
request. It is understood and agreed that Operator's insurance coverage
may not adequately protect the interests of the Developer hereunder and
that the Developer shall carry at its expense such excess or additional
general public liability, property damage, and other insurance, if any,
as the Developer deems appropriate.
(b) 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 to the Developer as Operator
hereunder 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. .
(a) With respect to this Agreement, each of the parties hereto
elects, under the authority of Section 761 (a) of the Internal Revenue
Code of 1986, as amended, to be excluded from the application of all of
the provisions of Subchapter K of Chapter 1 of Sub Title A of the
Internal Revenue Code of 1986, as amended. If the income tax laws of
the state or states in which the property covered hereby is located
contain, or may hereafter contain, provisions similar to those
contained in the Subchapter of the Internal Revenue Code of 1986, as
amended, referred to under which a similar election is permitted, each
of the parties agrees that such election shall be exercised. Beginning
with the first taxable year of operations hereunder, each party agrees
that the deemed election provided by Section 1.761-2(b)(2)(ii) of the
Regulations under the Internal Revenue Code of 1986, as amended, will
apply; and no party will file an application under Section 1.761-2
(b)(3)(i) and (ii) of said Regulations to revoke such election. Each
party hereby agrees to execute such documents and make such filings
with the appropriate governmental authorities as may be necessary to
effect such election.
(b) It is not the intention of the parties hereto 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
herein or as otherwise directed by the Developer.
(c) Subject to the provisions of Section 8 hereof, 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 hereunder, exclusive of production which may be used in
development and producing operations, production unavoidably lost, and
production used to fulfill any free gas obligations under the terms of
the applicable Lease or Leases; and Operator shall not have any right
to sell or otherwise dispose of such 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 hereunder. Developer shall have no interest in any gas
purchase 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 hereunder. The Developer agrees to designate
Operator or Operator's designated bank agent as the Developer's
collection agent in any such contract. Upon request, Operator shall
render assistance in arranging such sale or disposition and shall
promptly provide the Developer with all relevant information which
comes to Operator's attention regarding opportunities for sale of
production. In the event Developer shall fail to make the arrangements
necessary to take in kind or separately dispose of its proportionate
share of the oil and gas produced hereunder, Operator shall have the
right, subject to the revocation at will by the Developer, but not the
obligation, to purchase such 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 such production, however,
Operator shall have no liability to Developer should Operator fail to
market such production. Any such 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
such reasonable periods of time as are consistent with the minimum
needs of the Industry under the particular circumstance, but in no
event for a period in excess of one (1) year.
12. .
(a) If Operator is rendered unable, wholly or in part, by
force majeure (as hereinafter defined) to carry out its obligations
under this Agreement, the Operator shall give to the Developer prompt
written notice of the force majeure with reasonably full particulars
concerning it; thereupon, 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. 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) 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 equipment or materials, plant
shut-downs, curtailments by purchasers and any other causes whether of
the kind specifically enumerated above or otherwise, which directly
precludes Operator's performance hereunder and is not reasonably within
the control of the Operator.
(c) 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 all such difficulties
shall be entirely within the discretion of the Operator.
13. .
This Agreement shall become effective when executed by Operator and the
Developer and, except as provided in sub-section (c) of Section 3,
shall continue and remain in full force and effect for the productive
lives of the wells being operated hereunder.
14. .
This Agreement shall be governed by, construed and interpreted in
accordance with the laws of the Commonwealth of Pennsylvania. The
invalidity or unenforceability of any particular provision of this
Agreement shall not affect the other provisions hereof, and this
Agreement shall be construed in all respects as if such invalid or
unenforceable provision were omitted.
15. .
This Agreement, including the Exhibits hereto, constitutes and
represents the entire understanding and agreement of the parties with
respect to the subject matter hereof and supersedes all prior
negotiations, understandings, agreements, and representations relating
to the subject matter hereof. 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 such change, waiver,
modification, or amendment is sought to be enforced.
16. .
No waiver by any party hereto 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. .
Unless otherwise provided herein, 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 Atlas, to:
Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
Attention: President
(ii) If to Developer, to:
Atlas-Energy for the Nineties-Public #6 Ltd.
c/o Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
Notices which are served by registered or certified mail upon the
parties hereto in the manner provided in this Section shall be deemed
sufficiently served or given for all purposes under this Agreement at
the time such notice shall be mailed as provided herein in any post
office or branch post office regularly maintained by the United States
Postal Service or any successor to the functions thereof. All payments
hereunder 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. Whenever this Agreement makes reference to "this Agreement" or
to any provision "hereof," or words to similar effect, such reference
shall be construed to refer to the within instrument unless the context
clearly requires otherwise. The titles of the Sections herein have been
inserted as a matter of convenience of reference only and shall not
control or affect the meaning or construction of any of the terms and
provisions hereof. As used in this Agreement, the plural shall include
the singular and the singular shall include the plural whenever
appropriate.
19. .
The parties hereto may execute this Agreement in any number of separate
counterparts, each of which, when executed and delivered by the parties
hereto, shall have the force and effect of an original; but all such
counterparts shall be deemed to constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have duly executed this
Agreement under their respective seals as of the day and year first
above written.
Attest
Secretary
[Corporate Seal]
Attest
Secretary
[Corporate Seal]
ATLAS RESOURCES, INC.
By:
President
ATLAS-ENERGY FOR NINETIES-PUBLIC #6 LTD.
By its Managing General Partner:
ATLAS RESOURCES, INC.
By:
President
- -------------------------------------------------------------------------
Exhibit A
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
___________________, 19_____.
(d) The Developer's interest in the leasehold estate constituting
this Well Location is an undivided % Working Interest to
those oil and gas rights from the surface to the bottom of the
Medina/Whirlpool Formation, subject to the landowner's royalty
interest and Overriding Royalty Interests.
Ehibit A
(Page 1)
- -------------------------------------------------------------------------
Exhibit B
STATE OF )
) ASSIGNMENT OF OIL AND GAS LEASE
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 ___________________________ 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 incumbrances, 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 ____________________, 19_____.
Signed and acknowledged in presence of
________________________________________
ACKNOWLEDGEMENT 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 offical seal,
at ______________________________. This _____ day of
____________________________, A.D. 19____.
____________________________________
Notary Public
CORPORATION ACKNOWLEDGEMENT
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 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 herewith set my hand and offical seal,
at ______________________________. This _____ day of
____________________________, A.D. 19____.
____________________________________
Notary Public
- -----------------------------------------------------------------------
- --
EXHIBIT (B)
SPECIAL SUITABILITY REQUIREMENTS
AND DISCLOSURES TO INVESTORS
SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS
Prospective investors, if a resident of one of the following
states, must meet that state's qualification and suitability
standards as follows:
SUBSCRIBERS TO LIMITED PARTNER UNITS.
If a Michigan or North Carolina resident (1) a net worth of not
less than $225,000 (exclusive of home, furnishings and
automobiles), or (2) a net worth of not less than $60,000
(exclusive of home, furnishings and automobiles) and estimated
current year taxable income as defined in Section 63 of the
Internal Revenue Code of 1986 of $60,000 or more without regard to
an investment in the Partnership. In addition, a resident of
Michigan, Ohio or Pennsylvania shall not make an investment in the
Partnership in excess of 10% of his net worth (exclusive of home,
furnishings and automobiles).
If a resident of California (1) a net worth of not less than
$250,000 (exclusive of home, furnishings and automobiles) and
expects to have gross income in the current year of $65,000 or
more, or (2) a net worth of not less than $500,000 (exclusive of
home, furnishings and automobiles), or (3) a net worth of not less
than $1,000,000, or (4) expects to have gross income in the
current year of not less than $200,000.
SUBSCRIBERS TO INVESTOR GENERAL PARTNER UNITS.
If a resident of California: (1) a net worth of not less than
$250,000 (exclusive of home, furnishings and automobiles) and
expects to have annual gross income in the current year of
$120,000 or more; or (2) a net worth of not less than $500,000
(exclusive of home, furnishings and automobiles); or (3) a net
worth of not less than $1,000,000; or (4) expects to have gross
income in the current year of not less than $200,000.
If a resident of Alabama, Maine, Massachusetts, Minnesota, North
Carolina, Pennsylvania, Tennessee, or Texas (1) an individual or
joint net worth with my 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 (2) an individual or joint net worth with my spouse in
excess of $1,000,000, inclusive of home, home furnishings and
automobiles; or (3) an individual or joint net worth with my
spouse in excess of $500,000, exclusive of home, home furnishings
and automobiles; or (4) 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.
If a resident of Arizona, Indiana, Iowa, Kansas, Kentucky,
Michigan, Missouri, Mississippi, New Hampshire, New Mexico, Ohio,
Oklahoma, Oregon, South Dakota, Vermont, or Washington: (1) an
individual or joint net worth with my 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 expects to
have a combined "taxable income" of $60,000 or more for the
current year and for the succeeding year; or (2) an individual or
joint net worth with my spouse in excess of $1,000,000, inclusive
of home, home furnishings and automobiles; or (3) an individual or
joint net worth with my spouse in excess of $500,000, exclusive of
home, home furnishings and automobiles; or (4) 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. In addition, a resident of Michigan, Ohio
or Pennsylvania shall not make an investment in the Partnership in
excess of 10% of his net worth (exclusive of home, furnishings and
automobiles).
If a resident of Missouri, I am aware that:
THESE SECURITIES ARE NOT ELIGIBLE FOR ANY TRANSACTIONAL EXEMPTION
UNDER THE MISSOURI UNIFORM SECURITIES ACT (SECTION 409.402(B),
R.S.MO.(1978). UNLESS THESE SECURITIES ARE AGAIN REGISTERED UNDER
THE ACT, THEY MAY NOT BE REOFFERED FOR SALE OR RESOLD IN THE STATE
OF MISSOURI (SECTION 409.301, R.S.MO.(1978)).
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:
(1) to the issuer;
(2) pursuant to the order or process of any court;
(3) to any person described in Subdivision (i) of Section
25102 of the Code or Section 260.105.14 of these rules;
(4) 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;
(5) to holders of securities of the same class of the
same issuer;
(6) by way of gift or donation inter vivos or on death;
(7) 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;
(8) 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;
(9) 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;
(10) 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;
(11) by a corporation or wholly-owned subsidiary of such
corporation, or by a wholly-owned subsidiary of a
corporation to such corporation;
(12) by way of an exchange qualified under Section
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;
(13) between residents of foreign states, territories or
countries who are neither domiciled nor actually present
in this state;
(14) to the State Controller pursuant to the Unclaimed
Property Law or to the administrator of the unclaimed
property law of another state;
(15) 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;
(16) by a trustee to a successor trustee when such
transfer does not involve a change in the beneficial
ownership of the securities;
(17) 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."
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.
==================================================================
TABLE OF CONTENTS
Page
Summary of the Offering 1
Risk Factors 8
Capitalization and Source of Funds and Use of
Proceeds 17
Compensation 19
Estimate of Administrative Costs and Direct
Costs to be Borne by the Partnership 21
Terms of the Offering 22
Conflicts of Interest 24
Fiduciary Responsibility of the Managing
General Partner 31
Prior Activities 33
Management 40
Investment Objectives 45
Proposed Activities 45
Competition, Markets and Regulation 79
Participation in Costs and Revenues 80
Tax Aspects 84
Definitions 95
Summary of Partnership Agreement 100
Summary of Drilling and Operating Agreement 103
Reports to Investors 104
Repurchase Obligation 104
Transferability of Units 105
Plan of Distribution 106
Sales Material 107
Legal Opinions 107
Experts 107
Litigation 107
Additional Information 108
Financial Information Concerning the
Managing General Partner, Atlas Group
and the Partnership 108
EXHIBIT (A) - Amended and Restated Certificate
and Agreement of Limited Partnership
EXHIBIT (I-A) - Managing General Partner Signa-
ture Page
EXHIBIT (I-B) - Subscription Agreement
EXHIBIT (II) - Drilling and Operating Agreement
EXHIBIT (B) - Special Suitability Requirements and
Disclosures to Investors
No dealer, salesman or other person has been authorized to give
any information or make any representations other than those
contained in this Prospectus in connection with this offering, and
if given or made, such information or representations must not be
relied upon as having been authorized by the Managing General
Partner. The delivery of this Prospectus at any time does not
imply that the information herein is correct as of any time
subsequent to its date of issue. This Prospectus does not
constitute an offer to buy any of these securities in any State to
any person to whom it is unlawful to make such offer or
solicitation in such State.
ATLAS-ENERGY FOR
THE NINETIES -
PUBLIC #6 LTD.
PROSPECTUS
September ____, 1997
Until December 31, 1997, all dealers effecting transactions in the
registered securities, whether or not participating in this
distribution, may be required to deliver a prospectus. This is in
addition to the obligation of dealers 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 22. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Section 1741 et seq. of the Pennsylvania Business Corporation Law
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 they determined in good faith that the
course of conduct which caused the loss or liability was in the
best interest of the Partnership, they were acting on behalf of or
performing services for the Partnership and such course of conduct
was not the result of their negligence or misconduct.
Paragraph 11 of the Dealer-Manager Agreement provides for the
indemnification of Atlas, the Partnership and control persons
under specified conditions by the Dealer-Manager and/or Selling
Agent.
ITEM 23. 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 $ 2,000.00 *
Legal Fees (including Blue Sky) 50,000.00 *
Printing 95,000.00 *
SEC Registration Fee 3,030.00
Blue Sky Filing Fees
(excluding legal fees) 25,916.00 *
NASD Filing Fee 1,500.00
Miscellaneous
Total $450,000.00 *
*Estimated
ITEM 24. 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 25. EXHIBITS.
1(a) Proposed form of Dealer-Manager Agreement with
Anthem Securities, Inc.
1(b) Proposed form of Dealer-Manager Agreement with
Bryan Funding, 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-
Energy for the Nineties-Public #6 Ltd.
4(b) Amended and Restated Certificate and Agreement of
Limited Partnership for Atlas-Energy for the Nineties-
Public #6 Ltd. (See Exhibit (A) to Prospectus)
4(c) Release from Shareholders
5 Opinion of Kunzman & Bollinger, Inc. as to the
legality of the Units registered hereby
8 Opinion of Kunzman & Bollinger, Inc. as to tax
matters
10(a) Proposed Form of Escrow Agreement
10(b) Drilling and Operating Agreement (See Exhibit
(II) to the Amended and Restated Certificate and
Agreement of Limited Partnership, Exhibit (A) to
Prospectus)
24(a) Consent of McLaughlin & Courson
24(b) Consent of United Energy Development
Consultants, Inc.
24(c) Consent of Kunzman & Bollinger, Inc. (See
Exhibits 5 and 8)
25 Power of Attorney
ITEM 26. UNDERTAKINGS.
(a) As required by Item 512(a) of Regulation S-B and Rule
415, 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 to:
(i) include any Prospectus required by Section
10(a)(3) of the Securities Act of 1933;
(ii) reflect in the Prospectus any facts or events
arising after the effective date of the
Registration Statement (or of the most recent
Post-Effective Amendment thereof) which,
individually or together, represent a fundamental
change in the information set forth in the
Registration Statement; and
(iii) 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;
(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; and
(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.
(e) The undersigned Registrant undertakes:
(1) Insofar as indemnification for liabilities arising
under the Securities Act of 1933 (the "Act") may be
permitted to Atlas and its directors, officers and
controlling persons pursuant to the foregoing
provisions, or otherwise, Atlas and the Registrant
have 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
of expenses incurred or paid by Atlas and its
directors, officers and controlling persons in the
successful defense of any action, suit or proceeding)
is asserted by such party in connection with the
securities being registered, 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 Act, and will be governed by final
adjudication of such issue.
SIGNATURES
In accordance with the requirements of the Securities Act of 1933, the
Registrant certifies that it has reasonable grounds to believe that it
meets all of the requirements for filing on Form SB-2 and has authorized
this Pre-Effective Amendment No. 1 to the Form SB-2 Registration
Statement to be signed on its behalf by the undersigned, thereto duly
authorized, in Moon Township, Pennsylvania, on the 8th day of September,
1997.
ATLAS-ENERGY FOR THE NINETIES-
PUBLIC #6 LTD.
(Registrant)
By: Atlas Resources, Inc.,
Managing General Partner
James R. O'Mara and Bruce M. Wolf, By: /s/ James R. O'Mara
pursuant to the Registration Statement, James R. O'Mara,
President, Chief Executive
have been granted Power of Attorney and are Officer and
Director
signing on behalf of the names shown below,
in the capacities indicated. By: /s/ Bruce M. Wolf
Bruce M. Wolf, General Counsel,
Secretary
and Director
In accordance with the requirements of the Securities Act of 1933, this
Pre-Effective Amendment No. 1 to the Form SB-2 Registration Statement
has been signed by the following persons in the capacities and on the
dates indicated.
SEPTEMBER 8, 1997
Signature and
Title
- -------------------
Charles T. Koval
Chairman of the
Board and a
Director
- -------------------
James. R. O'Mara
President, Chief
Executive Officer
and a Director
- ------------------
Bruce M. Wolf
General Counsel,
Secretary and a
Director
- ------------------
Donald P. Wagner
Vice President of
Operations
- ------------------
James J. Kritzo
Vice President of
the Land
Department
- -----------------
Tony C. Banks
Vice President of
Finance and Chief
Financial Officer
- -----------------
Frank P. Carolas
Vice President of
Geology
- -----------------
Barbara J. Kransicki
Vice President of
Administration
- -----------------
Joseph R. Sadowski
Director
- -----------------
As filed with the Securities and Exchange Commission on
September 12, 1997
Registration No. 333-31681
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
EXHIBITS
TO
PRE-EFFECTIVE AMENDMENT NO. 1
TO
FORM SB-2
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
(Exact name of Registrant as Specified in its Charter)
JAMES R. O'MARA, PRESIDENT
ATLAS RESOURCES, INC.
311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108
(412) 262-2830
(Name, Address and Telephone Number of Agent for Service)
Copies to:
WALLACE W. KUNZMAN, JR., ESQ. JAMES R. O'MARA
KUNZMAN & BOLLINGER, INC. ATLAS RESOURCES, INC.
5100 N. BROOKLINE, SUITE 600 311 ROUSER ROAD
SIXTH FLOOR MOON TOWNSHIP,
OKLAHIMA CITY, OKLAHOMA 73112 PENNSYLVANIA 15108
EXHIBIT INDEX
1(a)
Proposed form of Dealer-Manager Agreement for
Anthem Securities, Inc.*
1(b)
Proposed form of Dealer-Manager Agreement for
Bryan Funding, 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-
Energy for the Nineties-
Public #6 Ltd.*
4(b)
Amended and Restated Certificate and Agreement
of Limited
Partnership for Atlas-Energy for the Nineties-
Public #6 Ltd.
(See Exhibit (A) to Prospectus)
4(c)
Release from Shareholders*
5
Opinion of Kunzman & Bollinger, Inc. as to the
legality of the Units
registered hereby*
8
Opinion of Kunzman & Bollinger, Inc. as to tax
matters
10(a)
Escrow Agreement*
10(b)
Proposed form of Drilling and Operating
Agreement
(See Exhibit (II) to the Amended and Restated
Certificate and
Agreement of Limited Partnership, Exhibit (A)
to Prospectus)
24(a)
Consent of McLaughlin & Courson
24(b)
Consent of United Energy Development
Consultants, Inc.
24(c)
Consent of Kunzman & Bollinger, Inc. (See
Exhibits 5 and 8)
25
Power of Attorney*
* Previously submitted
OPINION OF KUNZMAN & BOLLINGER, INC.
AS TO TAX MATTERS
KUNZMAN & BOLLINGER, INC.
ATTORNEYS-AT-LAW
5100 N. BROOKLINE, SUITE 600
OKLAHOMA CITY, OKLAHOMA 73112
Telephone (405) 942-3501
Fax (405) 942-3527
Exhibit 8
September 12, 1997
Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
RE:
Gentlemen:
You have requested our opinions on the material federal income tax
issues pertaining to Atlas-Energy for the Nineties-Public #6 Ltd. (the
"Partnership"), a limited partnership formed under the Revised Uniform
Limited Partnership Act of Pennsylvania. We have acted as Special
Counsel to the Partnership with respect to the offering of interests in
the Partnership. Atlas Resources, Inc. ("Atlas") will be the Managing
General Partner of the Partnership. Terms used and not otherwise
defined herein have the respective meanings assigned to them in the
Prospectus under the caption "DEFINITIONS."
Our opinions are based upon our review of: (1) a certain
Registration Statement on Form SB-2 for Atlas-Energy for the Nineties-
Public #6 Ltd., as originally filed with the United States Securities
and Exchange Commission, and amendments thereto, including the
Prospectus, the Drilling and Operating Agreement and the Amended and
Restated Certificate and Agreement of Limited Partnership for the
Partnership (the "Partnership Agreement") included as exhibits to the
Prospectus; and (2) such corporate records, certificates, agreements,
instruments and other documents as we have deemed relevant and
necessary to review as a basis for the opinions herein provided.
Our opinions also are based upon our interpretation of existing
statutes, rulings and regulations, as presently interpreted by judicial
and administrative bodies. Such statutes, rulings, regulations and
interpretations are subject to change; and such changes could result in
different tax consequences than those set forth herein and could render
our opinions inapplicable.
In rendering our opinions, we have obtained from you certain
representations with respect to the Partnership. Any material
inaccuracy in such representations may render our opinions
inapplicable. Included among such representations are the following:
(1) The Partnership Agreement to be entered into by and
among Atlas, as Managing General Partner, and the
Participants will be duly executed by all parties
thereto. The Partnership Agreement will be duly
recorded in all places required under the Revised
Uniform Limited Partnership Act of Pennsylvania for the
due formation of the Partnership and for the
continuation thereof in accordance with the terms of
the Partnership Agreement. The Partnership will at all
times be operated in accordance with the terms of the
Partnership Agreement, the Prospectus, and the Revised
Uniform Limited Partnership Act of Pennsylvania.
- ---------------------------------------------------------------------
PAGE 2
(2) No election will be made by the Partnership or any
Partner for the Partnership to be excluded from the
application of the provisions of Subchapter K of the
Code or classified as a corporation for tax purposes.
(3) The Partnership will own record or legal title to the
Working Interest in all of its Prospects.
(4) The respective amounts that will be paid to Atlas or
its Affiliates pursuant to the Partnership Agreement
and the Drilling and Operating Agreement are amounts
that would ordinarily be paid for similar services in
similar transactions between Persons having no
affiliation and dealing with each other "at arms'
length."
(5) The Partnership will elect to deduct currently all
intangible drilling and development costs.
(6) The Partnership will have a calendar year taxable year.
(7) The Drilling and Operating Agreement and any amendments
thereto entered into by and between Atlas and the
Partnership will be duly executed and will govern the
drilling and, if warranted, the completion and
operation of the wells in accordance with its terms.
(8) Based upon Atlas' review of its previous drilling
programs for the past several years and upon the
intended operations of the Partnership, Atlas
reasonably believes that the aggregate deductions,
including depletion deductions, and 350% of the
aggregate credits, if any, which will be claimed by
Atlas and the Participants, will not during the first
five tax years following the funding of the Partnership
exceed twice the amounts invested by Atlas and the
Participants, respectively.
(9) The Investor General Partner Units will not be
converted to Limited Partner interests before
substantially all of the Partnership Wells have been
drilled and completed.
(10) The Units will not be traded on an established
securities market.
In rendering our opinions we have further assumed that (1) each of
the Participants has an objective to carry on the business of the
Partnership for profit; (2) any amount borrowed by a Participant and
contributed to the Partnership will not be borrowed from a Person who
has an interest in the Partnership (other than as a creditor) or a
related person, as defined in 465 of the Code, to a person (other than
the Participant) having such interest and such Participant will be
severally, primarily, and personally liable for such amount; and (3) no
Participant will have protected himself from loss for amounts
contributed to the Partnership through nonrecourse financing,
guarantees, stop loss agreements or other similar arrangements.
We have considered the provisions of the American Bar Association's
Revised Formal Opinion 346 on Tax Law Opinions ("ABA Opinion 346") and
31 CFR, Part 10, 10.33 (Treasury Department Circular No. 230) on tax
law opinions and we believe that this opinion letter addresses all
material federal income tax issues associated with an investment in the
Units by an individual Participant who is a resident citizen of the
United States. We consider material those issues which would affect
significantly a Participant's deductions, credits or losses arising
from his investment in the Units and with respect to which, under
present law, there is a reasonable possibility of challenge by the IRS,
or those issues which are expected to be of fundamental importance to a
Participant but as to which a challenge by the IRS is unlikely. The
issues which involve a reasonable possibility of challenge by the IRS
have not been definitely resolved by statute, rulings or regulations,
as interpreted by judicial or administrative bodies.
- -----------------------------------------------------------------------
PAGE 3
Subject to the foregoing, however, in our opinion it is more likely
than not that the following tax treatment will be upheld if challenged
by the IRS and litigated:
. The Partnership will be classified as a partnership for federal
income tax purposes, and not as an association taxable as a
corporation; the Partnership, as such, will not pay any federal income
taxes, and all items of income, gain, loss, deduction, and credit of
the Partnership will be reportable by the Partners in the Partnership.
(See "- Partnership Classification.")
. Intangible drilling and development costs paid by the Partnership
under the terms of bona fide drilling contracts for the Partnership's
wells will be deductible in the taxable year in which the payments are
made and the drilling services are rendered, assuming such amounts are
fair and reasonable consideration and subject to certain restrictions
summarized below (including basis and "at risk" limitations and the
passive activity loss limitation with respect to the Limited Partners).
(See "- Intangible Drilling and Development Costs" and "- Drilling
Contracts.")
. Depending primarily on when the Partnership Subscription is
received, it is anticipated that the Partnership will prepay in 1997
most, if not all, of the intangible drilling and development costs
related to Partnership Wells the drilling of which will be commenced in
1998. Assuming that such amounts are fair and reasonable, and based in
part on the factual assumptions set forth below, in our opinion such
prepayments of intangible drilling and development costs will be
deductible for the 1997 taxable year even though all Working Interest
owners in the well may not be required to prepay such amounts, subject
to certain restrictions summarized in "Tax Aspects" (including basis
and "at risk" limitations, and the passive activity loss limitation
with respect to the Limited Partners). (See "- Drilling Contracts",
below.)
The foregoing opinion is based in part on the assumptions that: (1)
such costs will be required to be prepaid in 1997 for specified wells
pursuant to the Drilling and Operating Agreement; (2) pursuant to the
Drilling and Operating Agreement the wells are required to be, and
actually are, Spudded on or before March 31, 1998, and continuously
drilled thereafter until completed, if warranted, or abandoned; and (3)
the required prepayments are not refundable to the Partnership and any
excess prepayments are applied to intangible drilling and development
costs of substitute wells.
. Assuming that no more than 10% of the Units are transferred in any
taxable year of the Partnership (other than in private transfers
described in Treas. Reg. 1.7704-1(e)), it is more likely than not that
the Partnership will not be treated as a "publicly traded partnership"
under the Code. (See "- Limitations on Passive Activities".)
. Oil and gas production income generated by the Partnership's oil
and gas properties held as Working Interests, together with gain, if
any, from the disposition of such properties and allocable to Limited
Partners who are individuals, estates, trusts, closely held
corporations or personal service corporations more likely than not will
be characterized as income from a passive activity which may be offset
by passive activity losses (as defined in 469(d) of the Code). Income
or gain attributable to investments of working capital of the
Partnership will be characterized as portfolio income, which cannot be
offset by passive activity losses. To the extent the Partnership's oil
and gas properties are held as Working Interests, it is more likely
than not that the passive activity limitations on losses under 469
will not be applicable to Investor General Partners prior to the
conversion of Investor General Partner Units to Limited Partner
interests. (See "- Limitations on Passive Activities.")
. Each Participant's adjusted tax basis in his Partnership interest
will be increased by his total Agreed Subscription. (See "- Tax Basis
of Participants' Interests.")
. Each Participant initially will be "at risk" to the full extent of
his Agreed Subscription. (See "- `At Risk' Limitation For Losses.")
- -----------------------------------------------------------------------
PAGE 4
. The greater of cost depletion or percentage depletion will be
available to qualified Participants as a current deduction against
Partnership income from oil and gas production revenues on properties
of the Partnership, subject to certain restrictions summarized below.
(See "- Depletion Allowance.")
. The Partnership's reasonable costs for recovery property (tangible
depreciable property used in a trade or business or held for the
production of income) which cannot currently be deducted but must be
capitalized will be eligible for cost recovery deductions under the
modified Accelerated Cost Recovery System, generally over a seven year
"cost recovery period", subject to certain restrictions summarized
below (including basis and "at risk" limitations and the passive
activity loss limitation in the case of Limited Partners). (See "-
Depreciation - Accelerated Cost Recovery System.")
. 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, organization and syndication fees and
other items which are required to be capitalized, are currently
deductible. (See "- 1997 Expenditures", "- Availability of Certain
Deductions" and "- Partnership Organization and Syndication Fees.")
. Assuming the effect of the allocations of income, gain, loss,
deduction and credit (or items thereof) set forth in the Partnership
Agreement, including the allocations of basis and amount realized with
respect to oil and gas properties, is substantial in light of a
Participant's tax attributes that are unrelated to the Partnership, it
is more likely than not that such allocations will have "substantial
economic effect" and will govern each Participant's distributive share
of such items to the extent such allocations do not cause or increase
deficit balances in the Participants' Capital Accounts. (See "-
Allocations.")
. No gain or loss will be recognized by the Participants on payment
of their Agreed Subscriptions.
. Based on the Managing General Partner's representation that the
Partnership will be conducted as described in the Prospectus, it is
more likely than not that the Partnership will possess the requisite
profit motive and will not be properly characterized as a tax
shelter for purposes of the tax shelter registration requirement.
(See " - Disallowance of Deductions Under Section 183 of the Code.")
. Based on the Managing General Partner's representation that the
Partnership will be conducted as described in the Prospectus, it is
more likely than not that the Partnership will not be subject to the
anti-abuse rule set forth in Treas. Reg. 1.701-2. (See "- Penalties
and Interest - IRS Anti-Abuse Rule.")
. Based on our conclusion that substantially more than half of the
material tax benefits of the Partnership, in terms of their financial
impact on a typical Participant, more likely than not will be realized
if challenged by the IRS, it is our opinion that the tax benefits of
the Partnership, in the aggregate, which are a significant feature of
an investment in the Partnership by a typical original Participant more
likely than not will be realized as contemplated by the Prospectus.
Special Counsel intends that the foregoing "more likely than not"
opinion also is a "probably will" opinion under the standard set forth
in ABA Opinion 346. The discussion in the Prospectus under the caption
"TAX ASPECTS," insofar as it contains statements of federal income tax
law, is correct in all material respects. (See "Tax Aspects" in the
Prospectus.)
- -----------------------------------------------------------------------
PAGE5
* * * * * * * * * * * * *
Our opinion is limited to the opinions expressed above. With respect
to some of the matters discussed in this opinion, existing law provides
little guidance. Although our opinions express what we believe a court
would probably conclude if presented with the applicable issues, there
is no assurance that the IRS will not challenge our interpretations or
that such a challenge would not be sustained in the courts and cause
adverse tax consequences to the Participants. It should be noted that
taxpayers bear the burden of proof to support claimed deductions and
opinions of counsel are not binding on the IRS or the courts.
The following is a summary of some of the principal features under
present federal income tax law which will apply to the Partnership and
typical Participants. However, there is no assurance that the present
laws or regulations will not be changed and adversely affect a
Participant. The IRS may challenge the deductions claimed by the
Partnership or a Participant, or the taxable year in which such
deductions are claimed, and no guaranty can be given that any such
challenge would not be upheld if litigated. The practical utility of
the tax aspects of any investment depends largely on the income tax
position of the particular Participant 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, except as
otherwise noted, different tax considerations may apply to foreign
persons, corporations partnerships, trusts and other prospective
Participants which are not treated as individuals for federal income
tax purposes. EACH PROSPECTIVE PARTICIPANT SHOULD SATISFY HIMSELF AS TO
THE TAX CONSEQUENCES OF PARTICIPATING IN THE PARTNERSHIP BY OBTAINING
ADVICE FROM HIS OWN TAX ADVISOR.
For federal income tax purposes, a partnership is not a taxable
entity but rather a conduit through which all items of income, gain,
loss, deduction, credit and tax preference are passed through to the
partners and are required to be reported on their federal income tax
returns for the taxable years in which or with which the partnership's
taxable year ends. I.R.C. 706(a). Thus, the partners, rather than
the partnership, receive any tax deductions and credits, as well as the
income, from the operations engaged in by the partnership. It is the
opinion of Special Counsel that, under currently existing laws, rules
and regulations, all of which are subject to change with or without
retroactive application, the Partnership will be treated as a
partnership for federal income tax purposes and not as an association
taxable as a corporation. Under new regulations a business entity with
two or more members is classified for federal tax purposes as either a
corporation or a partnership. Treas. Reg. 301.7701-2(a). The term
corporation includes a business entity organized under a State statute
which describes the entity as a corporation, body corporate, body
politic, joint-stock company or joint-stock association. Treas. Reg.
301.7701-2(b). The Partnership was formed under the Pennsylvania
Revised Uniform Limited Partnership Act which describes the Partnership
as a "partnership". Consequently, the Partnership is not required to be
classified as a corporation under Treas. Reg. 301.7701-2(b) and will
be automatically classified as a partnership unless it affirmatively
elects to be classified as a corporation. In this regard, the Managing
General Partner has represented that no election for the Partnership to
be classified as a corporation will be filed with the IRS.
Under the passive activity rules, all income of a taxpayer who is
subject to the rules is categorized as: (i) income from passive
activities such as limited partners' interests in a business; (ii)
active income (e.g., salary, bonuses, etc.); or (iii) portfolio income
(e.g., dividends, royalties and interest not derived 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.
- -----------------------------------------------------------------------
PAGE6
The passive activity rules apply to individuals, estates, trusts,
closely held C corporations (generally, if five or fewer individuals
own directly or indirectly more than 50% of the stock) and personal
service corporations (other than corporations where the owner-employees
together own less than 10% of the stock). However, a closely held C
corporation (other than a personal service corporation) may use passive
losses and credits to offset taxable income of the company figured
without regard to passive income or loss or portfolio income. Passive
activities include: (i) any trade or business in which the taxpayer
does not materially participate; and (ii) any rental activity, whether
or not the taxpayer materially participates, subject to certain
exceptions. Material participation is defined as involvement in the
operations of the activity on a regular, continuous, and substantial
basis. Under the Partnership Agreement, Limited Partners will not have
material participation in the Partnership and generally will be subject
to the passive activity rules.
A taxpayer who holds a working interest in an oil and gas property
that is burdened with the cost of developing and operating the property
is excepted from the passive activity rules, whether or not he
materially participates in the activity. However, a taxpayer who holds
a working interest directly or indirectly through an entity (e.g., a
limited partnership interest or S corporation shares) which limits the
liability of the taxpayer with respect to such interest is not treated
as owning a working interest. Consequently, the exception is not
available to Limited Partners in the Partnership, but in the opinion of
Special Counsel it is more likely than not that the exception will be
available to Investor General Partners prior to their conversion to
Limited Partners to the extent the Partnership acquires Working
Interests in its Leases, except as noted above. Contractual limitations
on the liability of Investor General Partners under the Partnership
Agreement (e.g. insurance, limited indemnification, etc.) will not
prevent Investor General Partners from claiming deductions under the
working interest exception to the passive activity loss rules.
Overriding royalties, production payments and contract rights to
extract or share in oil and gas profits without liability for a share
of production costs are excluded from the definition of a working
interest.
Deductions disallowed by the at-risk limitation on losses under 465
of the Code become subject to the passive loss limitation only if the
taxpayer's at-risk amount increases in future years. A taxpayer's
at-risk amount is reduced by losses allowed under465 even if the
losses are suspended by the passive loss limitation. (See "- `At Risk'
Limitation For Losses," below.) Similarly, a taxpayer's basis is
reduced by deductions even if the deductions are disallowed under the
passive loss limitation. (See "- Tax Basis of Participants' Interests,"
below.)
Suspended losses and credits may be carried forward (but not back)
and used to offset future years' passive activity income. A suspended
loss (but not a credit) is allowed in full when the entire interest is
sold to an unrelated third party in a taxable transaction and in part
upon the disposition of substantially all of the passive activity if
the suspended loss as well as current gross income and deductions can
be allocated to the part disposed of with reasonable certainty. Upon
such disposition the excess of suspended losses and any loss from the
activity for the tax year (plus any loss on the sale) over net income
or gain for the tax year from all passive activities (determined
without regard to such losses) is not treated as a passive loss.
Capital losses are limited to the amount of capital gain, plus $3,000
(in the case of married individuals filing joint returns). I.R.C.
1211. The capital-loss limit is applied before the determination is
made of the amount of passive losses made available by a disposition.
In an installment sale, passive losses become available in the same
ratio that gain recognized each year bears to the total gain on the
sale.
Any suspended losses remaining at a taxpayer's death are allowed as
deductions on his final return, subject to a reduction to the extent
the basis of the property in the hands of the transferee exceeds the
property's adjusted basis immediately prior to the decedent's death. If
a taxpayer makes a gift of his entire interest in a passive activity,
the donee's basis is increased by any suspended losses and no
deductions are allowed. If the interest is later sold at a loss, the
donee's basis is limited to the fair market value on the date the gift
was made.
- -----------------------------------------------------------------------
PAGE7
Net losses and credits of a partner from each publicly traded
partnership are suspended and carried forward to be netted against
income from that publicly traded partnership only. In addition, net
losses from other passive activities may not be used to offset net
income from a publicly traded partnership. I.R.C469(k)(2) and 7704.
However, it is more likely than not that the Partnership will not be
characterized as a publicly traded partnership under the Code, so long
as no more than 10% of the Units are transferred in any taxable year of
the Partnership (other than in private transactions described in Treas.
Reg.1.7704-1(e)).
. Income (e.g., interest) earned on working capital is treated as
portfolio income which cannot be offset with passive losses by Limited
Partners. "Portfolio income" consists of (i) interest, dividends and
royalties (unless earned in the ordinary course of a trade or
business); and (ii) gain or loss not derived in the ordinary course of
a trade or business on the sale of property that generates portfolio
income or is held for investment.
In the opinion of Special Counsel, it is more likely than not that
the Partnership's income from the Leases (excluding income attributable
to investment of working capital), held as Working Interests, together
with gain, if any, from the disposition of such property, will be
characterized as passive income rather than portfolio income with
respect to Limited Partners subject to the passive activity
limitations.
. Investor General Partner Units will be converted to Limited
Partner interests after substantially all of the Partnership Wells have
been drilled and completed, which is anticipated to be in the late
summer of 1998. Thereafter, each Investor General Partner will be
deemed a Limited Partner in the Partnership and will enjoy the limited
liability provided to limited partners under the Revised Uniform
Limited Partnership Act of Pennsylvania with respect to his interest in
the Partnership's oil and gas properties. Concurrently, the Investor
General Partner will lose the availability of the working interest
exception to the passive activity limitations. Except as provided
below, an Investor General Partner's conversion of his Partnership
interest into a Limited Partner interest should not have adverse tax
consequences unless the Investor General Partner's share of any
Partnership liabilities is reduced as a result of the conversion. Rev.
Rul. 84-52, 1984-1 C.B. 157 and Prop. Reg.1.1254-2. A reduction in a
partner's share of liabilities is treated as a constructive
distribution of cash to such partner, which reduces the basis of the
partner's interest in the partnership and is taxable to the extent it
exceeds such basis. In addition, if a taxpayer has a loss for a taxable
year from a working interest in an oil and gas property which is
treated as a loss which is not from a passive activity, then any net
income from such property for any succeeding taxable year will be
treated as income of the taxpayer which is not from a passive activity.
Consequently, if an Investor General Partner has a non-passive loss in
1997 with respect to the Partnership's Working Interests in the Leases,
which is anticipated, any net income from a Partnership Well allocable
to such Investor General Partner in any subsequent taxable year (even
though he may then be a Limited Partner) will be characterized as
non-passive income which cannot be offset with passive losses. For this
purpose the Partnership's Wells will be deemed to include any property
the value of which is directly enhanced by any drilling, logging, or
other activities any part of the costs of which were borne by the
Investor General Partners as a result of holding the Working Interests
in the Wells (and any property the basis of which is determined in
whole or in part by reference to the basis of the property receiving
the increase in value).
The Partnership intends to adopt a calendar year taxable year.
I.R.C. 706(b). The taxable year of the Partnership is important to a
prospective Participant because the Partnership's deductions, income
and other items of tax significance must be taken into account in
computing the Participant's taxable income for his taxable year within
or with which the Partnership's taxable year ends. The tax year of a
partnership generally must be the tax year of one or more of its
partners who have an aggregate interest in partnership profits and
capital of greater than 50%.
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PAGE 8
It is anticipated that all of the Partnership's subscription
proceeds will be expended in 1997 and that the income and deductions
generated pursuant thereto will be reflected on the Participants'
federal income tax returns for that period. (See "Capitalization and
Source of Funds and Use of Proceeds" and "Participation in Costs and
Revenues" in the Prospectus.) Depending primarily on when the
Partnership Subscription is received, it is anticipated that the
Partnership will prepay in 1997 most, if not all, of its intangible
drilling and development costs for wells the drilling of which will be
commenced in 1998. The deductibility in 1997 of such advance payments
cannot be guaranteed. (See "- Drilling Contracts", below.)
The ordinary and necessary expenses of carrying on any trade or
business, including a reasonable allowance for salaries or other
compensation for personal services actually rendered, are deductible in
the year incurred. The tests for deductibility in the case of
compensation payments are whether the payments are: (i) reasonable; and
(ii) purely for services actually rendered. Treasury Regulation
1.162-7(b)(3) provides that reasonable compensation is only such
amount as would ordinarily be paid for like services by like
enterprises under like circumstances. The Managing General Partner has
represented to counsel that the amounts payable to the Managing General
Partner and its Affiliates, including the amounts paid to Atlas or its
Affiliates as general drilling contractor, are the amounts which would
ordinarily be paid for similar services in similar transactions. (See
"- Drilling Contracts," below.)
The fees paid to the Managing General Partner and its Affiliates
will not be currently deductible to the extent it is determined that
they are in excess of reasonable compensation, are properly
characterized as organization or syndication fees, other capital costs
such as the acquisition cost of the Leases, or not "ordinary and
necessary" business expenses, or the services were rendered in tax
years other than the tax year in which such fees were deducted by the
Partnership. (See "- Partnership Organization and Syndication Fees,"
below.) In the event of an audit, payments to the Managing General
Partner and its Affiliates by the Partnership will be scrutinized by
the IRS to a greater extent than payments to an unrelated party.
Assuming a proper election and subject to the passive activity loss
rules in the case of Limited Partners, each Participant will be
entitled to deduct his share of intangible drilling and development
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. Treas. Reg.1.612-4(a). (See "Participation in Costs and
Revenues" in the Prospectus and "- Limitations on Passive Activities,"
above.) Such costs generally will be subject to ordinary income
recapture if a property is sold at a gain and the amount to be
recaptured is not reduced by the amount of additional depletion that
could have been claimed if such costs had been capitalized and
amortized. (See "- Sale of the Properties," below.) Also,
productive-well intangible drilling and development costs may subject a
Participant to an alternative minimum tax in excess of regular tax
unless an election is made to deduct them on a straight-line basis over
a 60 month period. (See "- Minimum Tax - Tax Preferences," below.)
In the preparation of the Partnership's informational tax returns,
Atlas will allocate Partnership costs paid by Atlas and the
Participants among Intangible Drilling Costs, Tangible Costs, Direct
Costs, Administrative Costs, Organization and Offering Costs and
Operating Costs based upon guidance from advisors to Atlas. Atlas has
allocated approximately 77% of the footage price paid by the
Partnership for a completed well in the Appalachian Basin to intangible
drilling and development costs ("Intangible Drilling Costs") which are
charged 100% to the Participants under the Partnership Agreement. The
IRS could challenge the characterization of costs claimed by Atlas to
be deductible intangible drilling and development costs and
recharacterize such costs as some other item which may be
non-deductible however, this would have no effect on the allocation and
payment of such costs under the Partnership Agreement. Where a Lease is
acquired subject to an obligation to pay an excessive drilling price,
such excess amounts may not qualify as deductible intangible drilling
and development costs but may be treated as Lease acquisition costs or
some other non-deductible expense.
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PAGE9
In the case of corporations, other than S corporations, which are
"integrated oil companies," the amount allowable as a deduction for
intangible drilling and development costs in any taxable year under
263(c) of the Code is reduced by 30%. I.R.C.291(b)(1). Integrated
oil companies are (i) those taxpayers who directly or through a related
person engage in the retail sale of oil or gas and whose gross receipts
for the calendar year from such activities exceed $5,000,000, or (ii)
those taxpayers and related persons who have refinery production in
excess of 50,000 barrels on any day during the taxable year. For these
purposes, two persons are "related" if either has a 5% interest in the
other or a third person has a 5% interest in both, determined under
special ownership attribution rules. Amounts disallowed as a current
deduction are allowable as a deduction ratably over the 60-month period
beginning with the month in which the costs are paid or incurred. The
portion of the adjusted basis of any property attributable to
intangible drilling and development costs disallowed under291(b)(1)
of the Code cannot be taken into account to determine depletion under
611. Any deductions of intangible drilling and development costs over
the 60-month period will be subject to recapture.
The Partnership will enter into the Drilling and Operating Agreement
with Atlas or its Affiliates, as a third-party general drilling
contractor, to drill and complete the Partnership's Development Wells
on a footage basis of $37.39 per foot for each well that is drilled and
completed in the Appalachian Basin, and at a competitive rate for
wells, if any, drilled in other areas of the United States. Under the
footage drilling contracts for wells situated in the Mercer County area
of the Appalachian Basin, Atlas anticipates that it will have
reimbursement of general and administrative overhead of $3,600 per well
and a profit of approximately 15% per well assuming the well is drilled
to 6,150 feet. However, the actual cost of the drilling of the wells
may be more or less than the estimated amount, due primarily to the
uncertain nature of drilling operations. Atlas believes the Drilling
and Operating Agreement is at competitive rates in the proposed areas
of operation. Nevertheless, the amount of the profit realized by Atlas
under the drilling contract, if any, could be challenged by the IRS as
unreasonable and disallowed as a deductible intangible drilling and
development cost. (See "- Intangible Drilling and Development Costs",
above, and "Proposed Activities" and "Compensation" in the Prospectus.)
Depending primarily on when the Partnership Subscription is
received, it is anticipated that the Partnership will prepay in 1997
most, if not all, of the intangible drilling and development costs for
drilling activities that will be conducted in 1998. In , 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: (1) the expenditure must be a payment
rather than a refundable deposit; and (2) the deduction must not result
in a material distortion of income taking into substantial
consideration the business purpose aspects of the transaction. The
drilling partnership in entered into footage and daywork drilling
contracts which permitted it to terminate the contracts at any time
without default by the driller, and receive a return of the prepaid
amounts less amounts earned by the driller. The Tax Court found that
the right to receive, by unilateral action, a refund of the prepayments
on such footage and daywork drilling contracts rendered such
prepayments deposits instead of payments. Therefore, the prepayments
were held to be nondeductible in the year they were paid to the extent
they had not been earned by the driller. The Tax Court further found
that the drilling partnership failed to show a convincing business
purpose for prepayments under the footage and daywork drilling
contracts.
The drilling partnership in Keller also entered into turnkey
drilling contracts which permitted it to stop work under the contract
at any time and apply the unearned balance of the prepaid amounts to
another well to be drilled on a turnkey basis. The Tax Court found that
such prepayments constituted "payments" and not nondeductible deposits,
despite the right of substitution. Further, the Tax Court noted that
the turnkey drilling contracts obligated "the driller to drill to the
contract depth for a stated price regardless of the time, materials or
expenses required to drill the well," thereby locking in prices and
shifting the risks of drilling from the drilling partnership to the
driller. Since the drilling partnership, a cash basis taxpayer,
received the benefit of the turnkey obligation in the year of
prepayment, the Tax Court found that the amounts prepaid on turnkey
drilling contracts clearly reflected income and were deductible in the
year of prepayment.
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page10
In , TC Memo 1983-586, a drilling program entered into nine separate
turnkey contracts with a general contractor (the parent corporation of
the drilling program's corporate general partner), to drill nine
program wells. Each contract identified the prospect to be drilled,
stated the turnkey price, and required the full price to be paid in
1974. The program paid the full turnkey price to the general contractor
on December 31, 1974; the receipt of which was found by the court to be
significant in the general contractor's financial planning. The program
had no right to receive a refund of any of such payments.
The actual drilling of the nine wells was subcontracted by the
general contractor to independent contractors who were paid by the
general contractor in accordance with their individual contracts. The
drilling of all wells commenced in 1975 and all wells were completed
that year. The amount paid by the general contractor to the independent
driller for its work on the nine wells was approximately $365,000 less
than the amount prepaid by the program to the general contractor.
The program claimed a deduction for intangible drilling and
development costs in 1974. The IRS challenged the timing of the
deduction, contending that there was no business purpose for the
payments in 1974, that the turnkey arrangements were merely "contracts
of convenience" designed to create a tax deduction in 1974, and that
the turnkey contracts constituted assets having a life beyond the
taxable year and that to allow a deduction for their entire costs in
1974 distorted income.
The Tax Court, relying on , held that the program could deduct the
full amount of the payments in 1974. The court found that the program
entered into turnkey contracts, paid a premium to secure the turnkey
obligations, and thereby locked in the drilling price and shifted the
risks of drilling to the general contractor. Further, the court found
that by signing and paying the turnkey obligation, the program got its
bargained-for benefit in 1974, therefore the deduction of the payments
in 1974 clearly reflected income.
The Partnership will attempt to comply with the guidelines set forth
in with respect to prepaid intangible drilling and development costs.
The Drilling and Operating Agreement will require the Partnership to
prepay in 1997 intangible drilling and development costs for specified
wells the drilling of which will be commenced in 1998. Although the
Partnership is not required to prepay completion costs of a well prior
to the time a decision has been made to complete the well, it is
anticipated that all Partnership Wells will be required to be completed
before an evaluation can be made as to their potential productivity.
Prepayments should not result in a loss of current deductibility where
there is a legitimate business purpose for the required prepayment, the
contract is not merely a sham to control the timing of the deduction
and there is an enforceable contract of economic substance. The
Drilling and Operating Agreement will require the Partnership to prepay
the intangible drilling and development costs of the wells in order to
enable the Operator to commence site preparation for the wells, obtain
suitable subcontractors at the then current prices and insure the
availability of equipment and materials. Under the Drilling and
Operating Agreement excess prepaid amounts, if any, will not be
refundable to the Partnership but will be applied to intangible
drilling and development costs to be incurred in drilling substitute
wells. Under , such a provision for substitute wells should not result
in the prepayments being characterized as refundable deposits.
The likelihood that prepayments will be challenged by the IRS on the
grounds that there is no business purpose for the prepayment is
increased in the event prepayments are not required with respect to
100% of the Working Interest. It is possible that less than 100% of the
Working Interest will be acquired by the Partnership in one or more
wells and prepayments may not be required of all holders of the Working
Interest.
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PAGE11
However, in the view of Special Counsel, a legitimate business
purpose for the required prepayments may exist under the guidelines set
forth in , even though prepayment is not required, or actually
received, by the drilling contractor with respect to a portion of the
Working Interest.
In addition to the foregoing, a current deduction for prepaid
intangible drilling and development costs is available only if the
drilling of the wells is commenced before the close of the 90th day
after the close of the taxable year. The Managing General Partner will
attempt to cause prepaid Partnership Wells to be Spudded on or before
March 31, 1998. However, the Spudding of any Partnership Well may be
delayed due to circumstances beyond the control of the Partnership or
the drilling contractor. Such circumstances include the unavailability
of drilling rigs, weather conditions, inability to obtain drilling
permits or access right to the drilling site, or title problems. Due to
the foregoing factors no guaranty can be given that all prepaid
Partnership Wells required by the Drilling and Operating Agreement to
be Spudded on or before March 31, 1998, will actually be commenced by
such date. In that event, deductions claimed in 1997 for prepaid
intangible drilling and development costs would be disallowed and
deferred to the 1998 taxable year.
No assurance can be given that on audit the IRS would not disallow
the current deductibility of a portion or all of any prepayments of
intangible drilling and development costs under the Partnership's
drilling contracts, thereby decreasing the amount of deductions
allocable to the Participants for the current taxable year, or that
such a challenge would not ultimately be sustained. In the event of
disallowance, the deduction would be available in the year the work is
actually performed.
The Partnership intends to own an economic interest in all
Partnership Wells that produce gas or oil. Proceeds from the sale of
oil and gas production will constitute ordinary income. A certain
portion of such income will not be taxable by virtue of 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. Accordingly, each
Participant will be entitled to take into account on his own federal
income tax return his share of allowable depletion as computed at the
individual partner level, rather than the partnership level.
Cost depletion for any year is determined by dividing the adjusted
tax basis for the property by the total units of gas or oil expected to
be recoverable therefrom and then multiplying the resultant quotient by
the number of units actually sold during the year. Cost depletion
cannot exceed the adjusted tax basis of the property to which it
relates.
Percentage depletion generally is available to taxpayers other than
integrated oil companies. (See "- Intangible Drilling and Development
Costs.") Percentage depletion generally is based on the Participant's
share of gross income from the oil and gas producing property.
Generally, percentage depletion is available with respect to 6 million
cubic feet of average daily production of natural gas or 1,000 barrels
of average daily production of domestic crude oil. Taxpayers who have
both oil and gas production may allocate the production limitation
between such production. 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 oil and gas 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 (90 MCF of
natural gas) per producing well on the property in the calendar year.
The rate of percentage depletion for marginal production presently is
16%. (See the model decline curve included in the United Energy
Development Consultants, Inc. Geological Report in "Proposed Activities
- - Information Regarding Currently Proposed Prospects" in the
Prospectus.)
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PAGE 12
Percentage depletion may not exceed 100% of the net income from each
oil and gas property before the deduction for depletion and is limited
to 65% of the taxpayer's taxable income for a year computed without
regard to percentage depletion, net operating loss carrybacks and
capital loss carrybacks. With respect to marginal properties,
however, the 100% of net income property limitation is suspended for
1998 and 1999.
On disposition of an oil and gas property there is recapture of the
lesser of: (i) the amounts that were deducted under 263 of the Code as
intangible drilling and development costs rather than added to basis,
plus depletion deductions that reduced the basis of the property; or
(ii) the amount realized in the case of a sale, exchange or involuntary
conversion or fair market value in all other cases, minus the
property's adjusted basis. Furthermore, the amount of recapturable
intangible drilling and development costs is not reduced by the amount
by which depletion would have been increased if the expensed intangible
drilling and development costs had been capitalized.
Availability of the percentage depletion allowance and limitations
thereon must be computed separately for each Participant and not by the
Partnership, or for Participants as a whole. Potential Participants are
urged to consult their own tax advisors with respect to the
availability of the percentage depletion allowance to them.
Tangible Costs and the related depreciation deductions are allocated
and charged under the Partnership Agreement 14% to the Managing General
Partner and 86% to the Participants. Most equipment placed in service
by the Partnership will be classified as "7-year" property and the cost
of such property generally will be recovered over a seven year cost
recovery period. I.R.C. 168(c). The depreciation method for property
in the 7-year class is 200% declining balance, with a switch to
straight-line to maximize the deduction. All property assigned to the
7-year class is treated as placed in service (or disposed of) in the
middle of the year and in the case of a short tax year the ACRS
deduction is prorated on a 12-month basis. The half-year convention
effectively adds another year onto the cost-recovery period.
No distinction is made between new and used property and salvage
value is disregarded. Component depreciation is prohibited and an
alternative depreciation system is used to compute the depreciation
preference subject to the alternative minimum tax (using the 150%
declining balance method, switching to straight-line, for most personal
property). (See "- Minimum Tax - Tax Preferences," below.) All gain on
a disposition of tangible personal property is treated as ordinary
income to the extent of ACRS deductions claimed by the taxpayer and
deductions allowed under 179 (expensing) are treated as depreciation
deductions for recapture purposes. As under prior law (unless otherwise
provided by regulations), the full amount of proceeds realized on a
disposition of property from a mass asset account is treated as
ordinary income (with no reduction for basis), however, no reduction is
made in the depreciable basis remaining in the account. Cost recovery
deductions allocable to the Participants in a taxable year may be
reduced under certain circumstances to the extent foreign persons or
tax-exempt entities subscribe to the Partnership.
Section 179 provides an election to expense a portion of the cost of
certain tangible personal property in the year such property is placed
in service. The amount allowable as a deduction in 1997 is $18,000.
However, the deductible amount is reduced dollar-for-dollar by the cost
of qualifying property in excess of $200,000 and the amount expensed
cannot exceed the taxable income derived from the active conduct by the
taxpayer of the trade or business in which the property is used. These
limitations are applied at both the partnership and the partner level.
I.R.C. 179(d)(8). Any excess expensed amount is carried forward. If
this special election to expense is made, the basis of the property
used to compute cost recovery deductions is reduced by the amount
expensed and is subject to recapture if the property is not used
predominately in a trade or business at any time. I.R.C. 179.
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PAGE 13
The costs of acquiring oil and gas Lease interests, together with
the related cost depletion deduction and any abandonment loss, are
allocated under the Partnership Agreement 100% to Atlas, which will
contribute the Leases to the Partnership as a part of its Capital
Contribution.
The adjusted basis for federal income tax purposes of a
Participant's interest in the Partnership will be adjusted (but not
below zero) for any gain or loss to the Participant from a disposition
by the Partnership of an oil or gas property, and will be increased by:
(i) his cash subscription payment and any additional Capital
Contributions paid in cash to the Partnership, (ii) his share of any
nonrecourse debt of the Partnership, (iii) his share of any recourse
debt of the Partnership, (iv) his share of the taxable income of the
Partnership; and (v) his share of tax exempt income of the Partnership.
(See "Partnership Borrowings," below.)
The adjusted basis of a Participant's interest in the Partnership
will be reduced by: (i) his share of Partnership losses; (ii) his share
of Partnership expenditures that are not deductible in computing its
taxable income and are not properly chargeable to capital account;
(iii) his deduction for depletion for any partnership oil and gas
property (but not below zero); and (iv) cash distributions from the
Partnership to him. The reduction in a Participant's share of recourse
or nonrecourse liabilities is considered a cash distribution. Should
cash distributions exceed the tax basis of the Participant's interest
in the Partnership, taxable gain would result to the extent of the
excess. (See "- Distributions From a Partnership," below.)
A Participant's distributive share of Partnership loss is allowable
only to the extent of the adjusted basis of such Participant's interest
in the Partnership at the end of the Partnership's taxable year.
Participants will not be personally liable on any Partnership loans;
however, Investor General Partners will be liable for other obligations
of the Partnership. (See "Risk Factors - Special Risks of the
Partnership - Unlimited Liability of Investor General Partners" in the
Prospectus.)
Generally, a cash distribution from a partnership to a partner in
excess of the adjusted basis of such partner's interest in the
partnership immediately before the distribution is treated as gain from
the sale or exchange of his interest in the partnership to the extent
of the excess. I.R.C. 731(a)(1). No loss is recognized by the partners
on these types of distributions. I.R.C. 731(a)(2). No gain or loss is
recognized by the Partnership on these types of distributions. I.R.C.
731(b). If property is distributed by the Partnership to the Managing
General Partner and the Participants, certain basis adjustments may be
made by the Partnership, the Managing General Partner and the
Participants. [Partnership Agreement, 5.04(d).] I.R.C. 732, 733,
734, and 754. Other distributions of cash, disproportionate
distributions of property, and liquidating distributions may result
in taxable gain or loss. (See "- Disposition of Partnership
Interests" and "- Termination of a Partnership," below.)
Generally, on assets purchased before 2001:
(i) a noncorporate taxpayer's ordinary income and short-term gains on
the sale of assets held for a year or less are taxed at a maximum
rate of 39.6%;
(ii) net mid-term capital gains of a noncorporate taxpayer on the sale
of assets held more than a year but not more than 18 months are
taxed at a maximum rate of 28%; and
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(iii) PAGE 14
net long-term capital gains of a noncorporate taxpayer on the
sale of assets held more than 18 months are taxed at a maximum
rate of 20% (10% if they would be subject to tax at a rate of 15%
if they were not eligible for long-term capital gains treatment).
These rates also apply for purposes of the alternative minimum tax.
(See " - Minimum Tax - Tax Preferences", below.) The annual capital
loss limitation for noncorporate taxpayers is the amount of capital
gains plus the lesser of $3,000 ($1,500 for married persons filing
separate returns) or the excess of capital losses over capital
gains.
Gains and losses from sales of oil and gas properties held for more
than twelve months and not held primarily for sale to customers would
be, except to the extent of depreciation recapture on equipment and
recapture of any intangible drilling and development costs, depletion
deductions and certain 1231 losses, gains and losses described in
1231 of the Code (in general, from sales or exchanges of real or
depreciable property used in a trade or business). A Participant's net
1231 gain will be treated as a mid-term or long-term capital
gain depending on the holding period while a net loss will be an
ordinary deduction. However, ordinary income will result to the extent
the net 1231 gain for any taxable year does not exceed the excess of
the aggregate amount of the net 1231 losses for the five most recent
preceding taxable years over the portion of such losses taken into
account in determining the portion of net 1231 gain to be treated as
ordinary income for such preceding taxable years. I.R.C. 1231(c).
Other gains and losses on sales of oil and gas properties will
generally result in ordinary gains or losses.
Intangible drilling and development costs that are incurred in
connection with an oil and gas property may be recaptured as ordinary
income when the property is disposed of by the Partnership. Generally,
the amount recaptured is the lesser of:
(1) the aggregate amount of expenditures which have been
deducted as intangible drilling and development costs with
respect to the property and which (but for being deducted)
would be reflected in the adjusted basis of the property; or
(2) the excess of (i) the amount realized (in the case of a
sale, exchange or involuntary conversion); or (ii) the fair
market value of the interest (in the case of any other
disposition) over the adjusted basis of the property. I.R.C.
1254(a).
In addition, the deductions for depletion which reduced the adjusted
basis of the property are subject to recapture as ordinary income.
The sale or exchange of all or part of a Participant's interest in
the Partnership held by him for more than twelve months will generally
result in a recognition of mid-term or long-term capital gain or
loss except to the extent of ordinary income or loss, if any, from
Partnership 751 assets (which consist of unrealized receivables or
inventory). I.R.C. 751. See " - Sale of the Properties," above, for
the tax rates on capital gains . In the event the interest is held
for twelve months or less, such gain or loss will generally be
short-term gain or loss. A portion of any gain recognized by a Limited
Partner on the sale or other disposition of his interest in the
Partnership will also be characterized as portfolio income under 469 to
the extent the gain is itself attributable to portfolio income (e.g.
interest on investment of working capital). The recapturable portions
of depreciation, depletion and intangible drilling and development
costs constitute unrealized receivables. A Participant's pro rata share
of the Partnership's nonrecourse liabilities, if any, as of the date of
the sale or exchange must be included in the amount realized.
Therefore, the gain recognized may result in a tax liability greater
than the cash proceeds, if any, from such disposition. A gift of an
interest in the Partnership may result in federal and/or state income
tax and gift tax liability of the donor.
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PAGE 15
A Participant who sells or exchanges all or part of his interest in
the Partnership is required by the Code to notify the Partnership
within 30 days or by January 15 of the following year, if earlier.
I.R.C. 6050K. After receiving such notice, the Partnership is required
to make a return with the IRS stating the name and address of the
transferor and the transferee and such other information as may be
required by the IRS. The Partnership must also provide each person
whose name is set forth in the return a written statement showing the
information set forth on the return with respect to such person.
If a partner sells or exchanges his entire interest in a
partnership, the taxable year of the partnership will close with
respect to such partner (but not the remaining partners) on the date of
sale or exchange, with a proration of partnership items for the
partnership's taxable year. If a partner sells less than his entire
interest in a partnership, the partnership year will not terminate with
respect to the selling partner, but his proportionate share of items of
income, gain, loss, deduction and credit will be determined by taking
into account his varying interests in the partnership during the
taxable year. Deductions or credits generally may not be allocated to a
partner acquiring an interest from a selling partner for a period prior
to the purchaser's admission to the partnership. I.R.C. 706(d).
Other dispositions of a Participant's interest, including a
repurchase of the interest by Atlas, may or may not result in
recognition of taxable gain. Interests in different partnerships do not
qualify for tax-free like-kind exchanges. I.R.C. 1031(a)(2)(D).
However, no gain should be recognized by an Investor General Partner
whose interest in the Partnership is converted to a Limited Partner
interest so long as there is no change in his share of the
Partnership's liabilities or 751 assets as a result of the conversion.
Rev. Rul. 84-52, 1984-1 C.B 157. No disposition of an interest in the
Partnership (including repurchase of the interest by Atlas) should be
made by any Participant prior to consultation with his tax advisor.
For taxpayers other than integrated oil companies (see "- Intangible
Drilling and Development Costs"), the 1992 National Energy Bill
repealed (1) the preference for excess intangible drilling and
development costs and (2) the excess percentage depletion preference
for oil and gas. The repeal of the excess intangible drilling and
development costs preference, however, 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 and
development costs preference had not been repealed. These rules are
summarized below.
The alternative minimum tax is intended to insure that no one with
substantial income can avoid tax liability by using deductions and
credits, including the deductions for intangible drilling and
development costs and accelerated depreciation. Generally , the
alternative minimum tax rate for individuals is 26% on alternative
minimum taxable income up to $175,000 ($87,500 for married individuals
filing separate returns) and 28% thereafter. See " - Sale of the
Properties," above, for the tax rates on capital gains. Individual
tax preferences may include, but are not limited to: accelerated
depreciation, intangible drilling and development costs, incentive
stock options and passive activity losses. The exemption amount is
$45,000 for married couples filing jointly and surviving spouses,
$33,750 for single filers, and $22,500 for married persons filing
separately, estates and trusts. These exemption amounts are reduced by
25% of the alternative minimum taxable income in excess of (1) $150,000
for joint returns and surviving spouses; (2) $75,000 for estates,
trusts and married persons filing separately, and (3) $112,500 for
single taxpayers. Married individuals filing separately must increase
alternative minimum taxable income by the lesser of: (i) 25% of the
excess of alternative minimum taxable income over $165,000; or (ii)
$22,500. Regular tax personal exemptions are not available for purposes
of the alternative minimum tax.
The only itemized deductions allowed for minimum tax purposes are
those for casualty and theft losses, gambling losses to the extent of
gambling gains, charitable deductions, medical deductions (to the
extent in excess of 10% of adjusted gross income), interest expenses
(restricted to qualified housing interest as defined in 56(e) of the
Code and investment interest expense not exceeding net investment
income), and certain estate taxes. The net operating loss for
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alternative minimum tax purposes generally is the same as for
regular tax purposes, except: (i) current year tax preference items are
added back to taxable income, and (ii) individuals may use only those
itemized deductions (as modified under 172(d)) allowable in computing
alternative minimum taxable income. Code sections suspending losses,
such as 465 and 704(d), are recomputed for minimum tax purposes and
the amount of the deductions suspended or recaptured may differ for
regular and minimum tax purposes.
Under the prior rules, the amount of intangible drilling and
development 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 oil and gas properties. Net oil and gas income
is determined for this purpose without subtracting excess intangible
drilling and development costs. Excess intangible drilling and
development costs is the regular intangible drilling and development
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 for costs of
nonproductive wells and the preference for intangible drilling and
development costs for productive wells is computed separately for each
property. Taxpayers can elect to amortize the year's intangible
drilling and development costs for productive wells ratably over a 60
month period for all tax purposes and then such costs are not treated
as an item of tax preference. The passive loss disallowance is
determined after all preferences ad adjustments have been computed, so
the suspended loss amount may be different for minimum and regular tax
purposes. I.R.C. 58(b).
The likelihood of a Participant incurring, or increasing, any
minimum tax liability by virtue of an investment in the Partnership,
and the impact of such liability on his personal tax situation, must be
determined on an individual basis, and requires consultation by a
prospective Participant with his personal tax advisor.
Investment interest is deductible by a noncorporate taxpayer only to
the extent of net investment income each year (with an indefinite
carryforward of disallowed investment interest). I.R.C. 163. Interest
subject to the limitation generally includes all interest (except
consumer interest and qualified residence interest) on debt not
incurred in a person's active trade or business, provided the activity
is not a "passive activity" under the passive loss rule. Accordingly,
an Investor General Partner's allocable share of any interest expense
incurred by the Partnership, will be subject to the investment interest
limitation. In addition, an Investor General Partner's income and
losses (including intangible drilling and development costs) from the
Partnership will be considered investment income and losses for
purposes of this limitation. Losses allocable to an Investor General
Partner will reduce his net investment income and may affect the
deductibility of his investment interest expense, if any.
Net investment income is the excess of investment income over
investment expenses. Investment income includes: gross income from
interest, dividends, rents, and royalties; portfolio income under the
passive activity rules (which includes working capital investment
income and possibly royalty income of the Partnership, if any, in the
case of Limited Partners); and income from a trade or business in which
the taxpayer does not materially participate if the activity is not a
"passive activity" under the passive loss rule (which includes the
Partnership, at least prior to the conversion of Investor General
Partner Units to Limited Partner interests, in the case of Investor
General Partners). Gain from the disposition of investment property
generally is not included unless the taxpayer elects to reduce the
amount of net capital gain that qualifies for the 28% ceiling.
Investment expenses include deductions (other than interest) that are
directly connected with the production of net investment income
(including actual depreciation or depletion deductions allowable). No
item of income or expense subject to the passive activity loss rules of
469 of the Code is treated as investment income or investment expense.
In determining deductible investment expenses, investment expenses
are subject to a rule limiting deductions for miscellaneous expenses to
those exceeding 2% of adjusted gross income, however, expenses that are
not investment expenses are intended to be disallowed before any
investment expenses are disallowed.
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The Partnership Agreement allocates to each Partner his share of the
income, gains, credits and deductions (including the deductions for
intangible drilling and development costs and depreciation) generated
by the Partnership. Allocations of certain items are made in ratios
that are different than allocations of other items. (See "Participation
in Costs and Revenues" in the Prospectus.) The Capital Accounts of the
Partners are adjusted to reflect such allocations and the Capital
Accounts, as adjusted, will be given effect in distributions made to
the Partners upon liquidation of the Partnership or any Partner's
interest in the Partnership. Generally, the basis of oil and gas
properties owned by the Partnership for computation of cost depletion
and gain or loss on disposition will be allocated and reallocated when
necessary in the ratio in which the expenditure giving rise to the tax
basis of each property was charged as of the end of the year.
[Partnership Agreement, 5.03(b).]
Special allocations (those made in a manner that is disproportionate
to the respective interests of the partners in a partnership), among
partners of any item of partnership income, gain, loss, deduction or
credit will not be given effect unless the special allocation has
"substantial economic effect." I.R.C. 704(b). An allocation generally
will have economic effect if throughout the term of the partnership:
(1) the partners' capital accounts are maintained in accordance
with rules set forth in the regulations (generally, tax
accounting principles);
(2) liquidation proceeds are distributed in accordance with the
partners' capital accounts; and
(3) any partner with a deficit balance in his capital account
following the liquidation of his interest in the partnership is
required to restore the amount of the deficit for distribution
to partners with positive capital account balances or to be
paid to creditors.
Generally, a Participant's Capital Account is increased by the amount
of money he contributes to the Partnership and allocations to him of
income and gain, and decreased by the value of property or cash
distributed to him and allocations to him of loss and deductions. The
regulations also require that there must be a reasonable possibility
that the allocation will affect substantially the dollar amounts to be
received by the partners from the partnership, independent of tax
consequences.
Although Participants are not required to restore deficit balances
in their Capital Accounts beyond the amount of their agreed Capital
Contributions, an allocation which is not attributable to nonrecourse
debt will be considered to have economic effect to the extent it does
not cause or increase a deficit balance in a Participant's Capital
Account, if requirements (1) and (2) described above are met and the
partnership agreement provides that a partner who unexpectedly incurs a
deficit balance in his Capital Account because of certain adjustments,
allocations, or distributions will be allocated income and gain
sufficient to eliminate such deficit balance as quickly as possible.
Treas. Reg. 1.704-l(b)(2)(ii)(d). (See 5.03(h) of the Partnership
Agreement.)
In the event of a sale or transfer of a Partnership Unit or the
admission of an additional Participant, Partnership income, gain, loss,
deductions and credits generally will be allocated among the Partners
on a daily basis according to their varying interests in the
Partnership during the taxable year. In addition, in the discretion of
the Managing General Partner Partnership property may be revalued upon
the admission of additional Participants, or if certain distributions
are made to the Partners, to reflect unrealized income, gain, loss or
deduction inherent in the Partnership's property for purposes of
adjusting the Partners' Capital Accounts. It should be noted that a
reduction in a Participant's interest in the Partnership upon the
admission of additional Participants could be viewed by the IRS as a
deemed sale or exchange by the Participant of his share of "751 assets"
under 751 of the Code, which provides that to the extent a partner
receives partnership property, including money, in exchange for all or
part of his interest in the partnership's unrealized receivables, which
includes any intangible drilling and development costs, depletion and
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PAGE 18
cost recovery deductions recapture, and inventory items ("751
assets"), the transaction will be considered a sale or exchange of the
property between the partner and the partnership. In Rev. Rul. 84-102,
1984-2 C.B. 119, the IRS ruled that upon the admission of a new partner
to an existing partnership having both unrealized receivables and
liabilities outstanding, the existing partners were considered to have
received distributions to which 751(b) applies and were taxable on the
gain resulting from such deemed sale.
It should also be noted that each Partner's share of Partnership
items of income, gain, loss, deduction and credit must be taken into
account whether or not there is any distributable cash. A Participant's
share of Partnership revenues applied to the repayment of loans or the
reserve for plugging wells will be included in his gross income in a
manner analogous to an actual distribution of the income to him. Thus,
a Participant may have taxable income from the Partnership for a
particular year in excess of any cash distributions from the
Partnership to him with respect to that year. To the extent the
Partnership has cash available for distribution, however, it is Atlas'
policy that Partnership distributions will not be less than the
Participants' estimated income tax liability with respect to
Partnership income.
No assurance can be given that, on audit, the IRS will not take the
position that a portion of the deductions allocable to the Participants
is not allowable to them. If such a position is taken, there can be no
assurance that any resulting deficiency will not ultimately be
sustained. However, assuming the effect of the special allocations set
forth in the Partnership Agreement is substantial in light of a
Participant's tax attributes that are unrelated to the Partnership, in
the opinion of Special Counsel it is more likely than not that such
allocations will have "substantial economic effect" and will govern
each Participant's distributive share of such items to the extent such
allocations do not cause or increase deficit balances in the
Participants' Capital Accounts.
If any allocation under the Partnership Agreement is not recognized
for federal income tax purposes, each Participant's distributive share
of the items subject to such allocation generally will be determined in
accordance with his interest in the Partnership, determined by
considering relevant facts and circumstances. To the extent such
deductions as allocated by the Partnership Agreement, exceed deductions
which would be allowed pursuant to such a reallocation, Participants
may incur a greater tax burden.
Subject to the limitations on "passive losses" generated by the
Partnership in the case of Limited Partners and a Participant's basis
in the Partnership, each Participant may use his share of the
Partnership's losses to offset income from other sources. (See "-
Limitations on Passive Activities" and "- Tax Basis of Participants'
Interests," above.) However, any taxpayer (other than a corporation
which is neither an S corporation nor a corporation in which five or
fewer individuals own more than 50% of the stock) who sustains a loss
in connection with his oil and gas activities may deduct such loss only
to the extent of the amount he has "at risk" in such activities at the
end of a taxable year. In determining whether five or fewer individuals
own 50% or more of the stock of a corporation, the attribution rules of
544 apply. The "at risk" limitation applies to each activity engaged
in and not on an aggregate basis for all activities. The amount "at
risk" is limited to the amount of money and the adjusted basis of other
property the taxpayer has contributed to the activity, and any amount
he has borrowed with respect thereto for which he is personally liable
or with respect to which he has pledged property other than property
used in the activity; limited, however, to the net fair market value
of his interest in such pledged property. I.R.C. 465(b)(1) and (2).
However, amounts borrowed will not be considered "at risk" if such
amounts are borrowed from any person who has an interest (other than as
a creditor) in such activity or from a related person to a person
(other than the taxpayer) having such an interest.
"Loss" is defined as being the excess of allowable deductions for a
taxable year from an activity over the amount of income actually
received or accrued by the taxpayer during such year from the activity.
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PAGE 19
The amount the taxpayer has "at risk" may not include the amount of
any loss that the taxpayer is protected against through nonrecourse
loans, guarantees, stop loss agreements, or other similar arrangements.
The amount of any such loss that is disallowed in any taxable year will
be carried over to the first succeeding taxable year, to the extent a
Participant is "at risk." Further, a taxpayer's "at risk" amount in
subsequent taxable years with respect to the activity involved will be
reduced by that portion of the loss which is allowable as a deduction.
Participants' Agreed Subscriptions are funded by a payment of cash
(usually "at risk"). Since income, gains, losses, and distributions of
the Partnership affect the amount considered to be "at risk," the
extent to which a Participant is "at risk" must be determined annually.
Further, conversion from recourse to nonrecourse liability would reduce
the amount "at risk" and could result in taxable income to the
Participant. Previously allowed losses must be recaptured (included in
gross income) when the "at risk" amount is reduced below zero. However,
the amount recaptured is limited by the amount the taxpayer's "at risk"
amount is reduced below zero, with special computations to reflect
previously recaptured losses. The amount included in income under this
recapture provision may be deducted in the first succeeding taxable
year to the extent of any increase in the amount which the Participant
has "at risk."
Under the Partnership Agreement, the Managing General Partner and
its Affiliates may make loans to the Partnership. The use of
Partnership revenues taxable to Participants to repay Partnership
borrowing will create income tax liability for such Participants in
excess of cash distributions to them, since repayments of principal are
not deductible for federal income tax purposes, and deductions for
payment of interest will be subject to the "investment interest" and
"passive loss" limitations previously discussed. In addition, interest
paid (or imputed at the applicable Federal rate) on such loans will not
be deductible unless such loans are bona fide loans that will not be
treated as Capital Contributions. In Revenue Ruling 72-135, 1972-1 C.B.
200, the IRS ruled that a nonrecourse loan from a general partner to a
limited partner or to a partnership engaged in oil and gas exploration
represented a capital contribution by the general partner rather than a
loan. Whether a "loan" to the Partnership represents in substance, debt
or equity is a question of fact to be determined from all the
surrounding facts and circumstances. (See , 46 T.C. 147 (1966); 43
T.C. 90 (1964).)
Expenses connected with the issuance and sale of interests in a
partnership (i.e., promotional expense, selling expense, commissions,
professional fees and printing costs) are not deductible. Further,
except for certain expenses, amounts incurred to organize a partnership
may not be claimed as deductions under the partnership provisions of
the Code. However, expenses incident to the creation of a partnership
which are chargeable to capital account and which, if expended in
connection with the creation of a partnership having an ascertainable
life, would be amortized over that period of time, may be deducted and
amortized over a period of not less than 60 months. Such amortizable
organization expenses are charged 100% to the Managing General Partner
as part of the Partnership's Organization and Offering Costs and any
related deductions will be allocated to the Managing General Partner.
The Code permits partnerships to elect to adjust the basis of
partnership property on the transfer of an interest in a partnership by
sale or exchange or on the death of a partner, and on the distribution
of property by the partnership to a partner (the 754 election). The
general effect of such an election is that transferees of the
partnership interests 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 such purposes, upon certain
distributions to partners, as though it had newly acquired an interest
in the partnership assets and therefore acquired a new cost basis for
such assets. Any such election, once made, may not be revoked without
the consent of the IRS. The Partnership Agreement, 5.04(d), provides
that the Partnership may make the 754 election.
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PAGE 20
The Partnership may also make various elections for federal tax
reporting purposes which could result in various items of income, gain,
loss, deduction and credit being treated differently for tax purposes
than for accounting purposes.
Code 195 permits taxpayers to elect to capitalize and amortize
"start-up expenditures" over a 60-month period. Such items include
amounts: (1) paid or incurred in connection with: (i) investigating the
creation or acquisition of an active trade or business, (ii) creating
an active trade or business, or (iii) 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 such activity
becoming an active trade or business; and (2) which would be allowed as
a deduction if paid or incurred in connection with the expansion of an
existing business. Start-up expenditures do not include amounts paid or
incurred in connection with the sale of partnership interests. If it is
ultimately determined that any of the Partnership's expenses
constituted start-up expenditures and not deductible expenses under
162, the Partnership's deductions would be reduced.
Under 183 of the Code, a Participant's ability to deduct his share
of the Partnership's losses on his federal income tax return could be
lost if the Partnership lacks the appropriate profit motive as
determined from an examination of all facts and circumstances at the
time. Section 183 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 such activity exceeds the deductions
attributable to such activity. Thus, if the Partnership fails to show a
profit in at least three out of five consecutive years, this
presumption will not be available. In that instance, the possibility
that the IRS could successfully challenge the deductions claimed by a
Participant would be substantially increased.
The fact that the possibility of ultimately obtaining profits is
uncertain, standing alone, does not appear to be sufficient grounds for
the denial of losses under 183. (See Treas. Reg. 1.183-2(c), Example
(5).) Based on Atlas' representation that the Partnership will be
conducted as described in the Prospectus, in the opinion of Special
Counsel it is more likely than not that the Partnership will possess
the requisite profit motive.
Pursuant to 708(b) of the Code, a partnership will be considered as
terminated for federal income tax purposes if within a twelve month
period there is a sale or exchange of 50% or more of the total interest
in partnership capital and profits. The closing of the partnership year
may result in more than twelve months' income or loss of the
partnership being allocated to certain partners for the year of
termination (i.e., in the case of partners using fiscal years other
than the calendar year). Under 731 of the Code, a partner will realize
taxable gain on a termination of the partnership to the extent that
money regarded as distributed to him exceeds the adjusted basis of his
partnership interest. The conversion of Investor General Partner Units
to Limited Partner interests will not result in a termination of the
Partnership under 708 of the Code. Rev. Rul. 84-52, 1984-1 C.B. 157.
Section 6111 of the Code generally requires an organizer of a "tax
shelter" to register the tax shelter with the Secretary of the
Treasury, and to obtain an identification number which must be included
on the tax returns of investors in such a tax shelter. For purposes of
these provisions, a "tax shelter" is generally defined to include
investments with respect to which any person could reasonably infer
that the ratio that (1) the aggregate amount of the potentially
allowable deductions and 350% of the potentially allowable credits with
respect to the investment during the first five years of the investment
bears to (2) the amount of money and the adjusted basis of property
contributed to the investment exceeds 2 to 1. Temporary Regulations
promulgated by the IRS provide that the aggregate amount of gross
deductions must be considered and determined without reduction for
gross income derived, or to be derived, from the investment
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PAGE 21
.
Atlas does not believe that the Partnership will have a tax shelter
ratio greater than 2 to 1. Also, because the purpose of the Partnership
is to locate, produce and market natural gas on an economic basis,
Atlas does not believe that the Partnership will be a "potentially
abusive tax shelter." Accordingly, Atlas does not intend to cause the
Partnership to register with the IRS as a tax shelter.
If it is subsequently determined that the Partnership was required
to be registered with the IRS as a tax shelter, Atlas would be subject
to certain penalties, including a penalty of 1% of the aggregate amount
invested in the Units of the Partnership for failing to register and
$100 for each failure to furnish a Participant a tax shelter
registration number, and each Participant would be liable for a $250
penalty for failure to include the tax shelter registration number on
his tax return, unless such failure was due to reasonable cause. A
Participant also would be liable for a penalty of $100 for failing to
furnish the tax shelter registration number to any transferee of his
interest in the Partnership. However, based on the representations of
the Managing General Partner, Special Counsel has expressed the opinion
that the Partnership, more likely than not, is not required to register
with the IRS as a tax shelter.
Issuance of a registration number does not indicate that an
investment or the claimed tax benefits have been reviewed, examined, or
approved by the IRS.
Section 6112 of the Code requires that any person who organizes a
tax shelter required to be registered with the IRS or who sells any
interest in such a shelter must maintain a list identifying each person
who was sold an interest in the shelter and setting forth other
required information. For the reasons described above, Atlas does not
believe the Partnership is subject to the requirements of 6112 If this
determination is wrong, 6708 of the Code provides for a penalty of $50
for each person with respect to whom there is a failure to meet any
requirements of 6112, unless the failure is due to reasonable cause.
. The tax treatment of all partnership items is generally determined at
the partnership, rather than the partner, level; and the partners are
generally required to treat partnership items on their individual
returns in a manner which is consistent with the treatment of such
partnership items on the partnership return. I.R.C. 6221 and 6222.
Regulations define "partnership items" for this purpose as including
distributive share items that must be allocated among the partners,
such as partnership liabilities, data pertaining to the computation of
the depletion allowance, and guaranteed payments. Treas. Reg.
301.6231(a)(3)-1.
Generally, the IRS must conduct an administrative determination as
to partnership items at the partnership level before conducting
deficiency proceedings against a partner, and the partners must file a
request for an administrative determination before filing suit for any
credit or refund. The period for assessing tax against a Partner
attributable to a partnership item may be extended as to all partners
by agreement between the IRS and Atlas, which will serve as the
Partnership's representative ("Tax Matters Partner") in all
administrative and judicial proceedings conducted at the partnership
level. The Tax Matters Partner generally may enter into a settlement on
behalf of, and binding upon, partners owning less than a 1% profits
interest in partnerships having more than 100 partners. In
addition, a partnership with at least 100 partners may elect to be
governed under simplified tax reporting and audit rules as an "electing
large partnership". These rules also facilitate the matching of
partnership items with individual partner tax returns by the IRS. The
Managing General Partner does not anticipate that the Partnership will
make this election. By executing the Partnership Agreement, each
Participant agrees that he 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 the event of an audit of the return of the Partnership, the Tax
Matters Partner, pursuant to advice of counsel, will take all actions
necessary, in its discretion, to preserve the rights of the
Participants. All expenses of such proceedings undertaken by the Tax
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PAGE 22
Matters Partner, which might be substantial, will be paid for by the
Partnership. The Tax Matters Partner is not obligated to contest
adjustments made by the IRS.
. The preparation and filing of each Participant's federal, state and
local income tax returns are the responsibility of the Participant. The
Partnership will provide each Participant with the tax information
applicable to his investment in the Partnership necessary to prepare
such returns; however, the treatment of the tax attributes of the
Partnership may vary among Participants. The Managing General Partner,
its Affiliates and Special Counsel assume no responsibility for the tax
consequences of this transaction to a Participant, nor for the
disallowance of any proposed deductions. EACH PARTICIPANT IS URGED TO
SEEK QUALIFIED, PROFESSIONAL ASSISTANCE IN THE PREPARATION OF HIS
FEDERAL, STATE AND LOCAL TAX RETURNS.
. Interest (based on the applicable Federal short-term rate plus 3
percentage points) is charged on underpayments of tax and various civil
and criminal penalties are included in the Code.
. If any portion of an underpayment of tax is attributable to
negligence or disregard of rules or regulations, 20% of such portion is
added to the tax. Negligence is strongly indicated if a partner fails
to treat partnership items on his tax return in a manner that is
consistent with the treatment of such items on the partnership's return
or to notify the IRS of the inconsistency. The term "disregard"
includes any careless, reckless or intentional disregard of rules or
regulations. There is no penalty, however, if the position is
adequately disclosed, or the position is taken with reasonable cause
and in good faith, or the position has a realistic possibility of being
sustained on its merits. Treas. Reg. 1.6662-3.
. There is an addition to tax of 20% of the amount of any
underpayment of tax of $5,000 or more ($10,000 in the case of
corporations other than S corporations or personal holding companies)
which is attributable to a substantial valuation misstatement. There is
a substantial valuation misstatement if the value or adjusted basis of
any property claimed on a return is 200% or more of the correct amount;
or if the price for any property or services (or for the use of
property) claimed on a return is 200% or more (or 50% or less) of the
correct price. If there is a gross valuation misstatement (400% or more
of the correct value or adjusted basis or the undervaluation is 25% or
less of the correct amount) the penalty is 40%. I.R.C. 6662(e) and (h).
. There is also an addition to tax of 20% of any underpayment if the
difference between the tax required to be shown on the return over the
tax actually shown on the return, exceeds the greater of 10% of the tax
required to be shown on the return, or $5,000 ($10,000 in the case of
corporations other than S corporations or personal holding companies).
I.R.C. 6662(d). The amount of any understatement generally will be
reduced to the extent it is attributable to the tax treatment of an
item supported by substantial authority, or adequately disclosed on the
taxpayer's return. However, in the case of "tax shelters," the
understatement may be reduced only if the tax treatment of an item
attributable to a tax shelter was supported by substantial authority
and the taxpayer establishes that he reasonably believed that
the tax treatment claimed was more likely than not the proper
treatment. Disclosure of partnership items should be made on the
Partnership's return; however, a taxpayer partner also may make
adequate disclosure on his individual return with respect to pass-
through items. Section 6662(d)(2)(C) provides that a "tax shelter" is
any entity which has as a significant purpose the avoidance or
evasion of federal income tax.
. Under Treas. Reg. 1.701-2, 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 to remedy the abuse. For illustration purposes, the
following factors may indicate that a partnership is being used in a
prohibited manner: (i) the partners' aggregate federal income tax
liability is substantially less than had the partners owned the
partnership's assets and conducted its activities directly;
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PAGE 23
(ii) the partners' aggregate federal income tax liability is
substantially less than if purportedly separate transactions are
treated as steps in a single transaction; (iii) one or more partners
are needed to achieve the claimed tax results and have a nominal
interest in the partnership or are substantially protected against
risk; (iv) substantially all of the partners are related to each other;
(v) income or gain are allocated to partners who are not expected to
have any federal income tax liability; (vi) the benefits and burdens of
ownership of property nominally contributed to the partnership are
related in substantial part by the contributing party; and (vii) the
benefits and burdens of ownership of partnership property are in
substantial part shifted to the distributee partners before or after
the property is actually distributed to the distributee partners. Based
on the Managing General Partner's representation that the Partnership
will be conducted as described in the Prospectus, in the opinion of
Special Counsel it is more likely than not that the Partnership will
not be subject to the anti-abuse rule set forth in Treas. Reg. 1.701-2.
The Partnership will operate in states and localities which impose a
tax on its assets or its income, or on each Participant. Deductions
which are available to Participants for federal income tax purposes may
not be available for state or local income tax purposes. A
Participant's distributive share of the net income or net loss of the
Partnership generally will be required to be included in determining
his reportable income for state or local tax purposes in the
jurisdiction in which he is a resident. To the extent that a
non-resident Participant pays tax to a state by virtue of Partnership
operations within that state, he may be entitled to a deduction or
credit against tax owed to his state of residence with respect to the
same income. To the extent that the Partnership operates in certain
jurisdictions, state or local estate or inheritance taxes may be
payable upon the death of a Participant in addition to taxes imposed by
his own domicile.
Under Pennsylvania law, the Partnership is required to withhold
state income tax at the rate of 2.8% of Partnership income allocable to
Participants who are not residents of Pennsylvania. This requirement
does not obviate Pennsylvania tax return filing requirements for
Participants who are not residents of Pennsylvania. In the event of
overwithholding, a Pennsylvania income tax return must be filed by
Participants who are not residents of Pennsylvania in order to obtain a
refund. Prospective Participants should consult with their own tax
advisors concerning the possible effect of various state and local
taxes on their personal tax situations.
The Partnership may incur various ad valorem or severance taxes
imposed by state or local taxing authorities. Currently, there is no
such tax liability in Mercer County, Pennsylvania.
A Limited Partner's share of income or loss from the 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 the Partnership will constitute "net earnings from
self-employment" for these purposes. I.R.C. 1402(a). For 1997 the
ceiling for social security tax of 12.4% is $65,400 and there is no
ceiling for medicare tax of 2.9%. Self-employed individuals can deduct
one-half of their self-employment tax.
The Partnership will be required to withhold and pay to the IRS tax
at the highest rate under the Code applicable to Partnership income
allocable to foreign partners, even if no cash distributions are made
to such partners. A purchaser of a foreign Partner's Units may be
required to withhold a portion of the purchase price and the Managing
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General Partner may be required to withhold with respect to taxable
distributions of real property to a foreign Partner. The withholding
requirements described above do not obviate United States tax return
filing requirements for foreign Partners. In the event of
overwithholding, a foreign Partner must file a United States tax return
to obtain a refund.
There is no federal tax on lifetime or testamentary transfers of
property between spouses. The gift tax annual exclusion is $10,000 per
donee. The maximum estate and gift tax rate is 55% (subject to a 5%
surtax on amounts in excess of $10,000,000); and estates of $600,000
(which increases in stages to $1,000,000 by 2006) or less generally are
not subject to federal estate tax. In the event of the death of a
Participant, the fair market value of his interest as of the date of
death (or as of the alternate valuation date) will be included in his
estate for federal estate tax purposes. The decedent's heirs will, for
federal income tax purposes, take as their basis for the interest the
value as so determined for federal estate tax purposes.
The Partnership and the Participants could be adversely affected by
any further changes in tax laws that may result through future
Congressional action, Tax Court or other judicial decisions, or
interpretations by the IRS. It is impossible to predict what, if any,
changes in the tax law may become law in the future or even if adopted,
would apply to the Partnership.
IT IS NOT POSSIBLE FOR US TO PREDICT THE EFFECT OF THE TAX LAWS ON
INDIVIDUAL PARTICIPANTS. EACH PARTICIPANT IS URGED TO SEEK, AND SHOULD
DEPEND UPON, THE ADVICE OF HIS OWN TAX ADVISORS WITH RESPECT TO HIS
INVESTMENT IN THE PARTNERSHIP WITH SPECIFIC REFERENCE TO HIS OWN TAX
SITUATION AND POTENTIAL CHANGES IN THE APPLICABLE LAW.
We consent to the use of this opinion letter as an exhibit to the
Registration Statement, and all amendments thereto, and to all
references to this firm in the Prospectus.
Very truly yours,
KUNZMAN & BOLLINGER, INC.
McLaughlin & Courson
2002 Law & Finance Building
Pittsburgh, PA 15219
CONSENT OF INDEPENDENT AUDITOR
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
The firm, as Independent Certified Public Accountants, hereby consents
to the use of the audit report dated July 11, 1997, on the balance
sheet of Atlas-Energy for the Nineties-Public #6 Ltd. as of July 1,
1997, the audit report dated November 11, 1996, on the consolidated
statements of financial position for the years ending July 31, 1996 and
1995, of AEG Holdings, Inc. and subsidiaries and the related
consolidated statements of income and cash flows for the years then
ended; and the audit report dated November 11, 1996, on the audited
balance sheets as of July 31, 1996 and 1995 of Atlas Resources, Inc. in
the Registration Statement, Pre-Effective Amendment No. 1, to the
Registration Statement, and any supplements thereto, including post-
effective amendments, for Atlas-Energy for the Nineties-Public #6 Ltd.
In addition, the firm hereby consents to all references to it as
having prepared such reports and to the reference to the firm under the
caption "Experts".
McLaughlin & Courson
Certified Public Accountants
/s/McLaughlin & Courson
McLaughlin & Courson
September 8, 1997
Pittsburgh, Pennsylvania
CONSENT OF UNITED ENERGY DEVELOPMENT CONSULTANTS, INC.
INDEPENDENT PETROLEUM ENGINEERING & GEOLOGICAL CONSULTING FIRM
UEDC, as an independent petroleum engineering and geological consulting
firm, hereby consents to the use of it's Geologic Evaluation, dated
July 9, 1997, in the Pre-Effective Amendments, for Atlas-Energy for the
Nineties-Public #6, Ltd., and to all references to UEDC as having
prepared such report and as an expert concerning such report.
UEDC, Inc.
/s/Isaias Ortiz
Isaias Ortiz September 4, 1997
President Ambridge, PA
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