<PAGE>
As filed with the Securities and Exchange Commission on October 1, 1999
Registration No. 333-82389
- -------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------------
PRE-EFFECTIVE AMENDMENT NO. 2
TO
FORM SB-2
REGISTRATION STATEMENT
Under
The Securities Act of 1933
----------------------------
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 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, PENNSYLVANIA 15108
OKLAHOMA CITY, OKLAHOMA 73112
------------------------------
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 continuous basis pursuant to Rule 415 under the Securities Act
of 1933, check the following box: /X/
-------------------------------
CALCULATION OF REGISTRATION FEE
<TABLE>
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<S> <C> <C> <C> <C>
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) $18,000,000 $10,000 $18,000,000 $5,310.00
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) "Units" means the limited partner interests and the investor general
partner interests offered to investors 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.
<PAGE>
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
CROSS REFERENCE SHEET
PURSUANT TO RULE 404
<TABLE>
<CAPTION>
Item of Form SB-2 Caption in Prospectus
----------------- ---------------------
<S> <C> <C>
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........................................ 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................................... 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................................ Proposed Activities
A. Issuers Engaged or to Be Engaged in Significant
Mining Operations............................... Not Applicable
B. Supplementing Financial Information about Oil
and Gas Producing Activities.................... 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 and the Partnership
23. Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure.................... Not Applicable
</TABLE>
<PAGE>
The information in this prospectus is not complete and may be changed. We
may not sell these securities until the registration statement filed with the
SEC is effective. This prospectus is not an offer to sell these securities
and it is not soliciting an offer to buy these securities in any state where
the offer or sale is not permitted.
Preliminary Prospectus (Subject to Completion) Dated ____________, 1999
Prospectus
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
- General and Limited Partner Interests at $10,000 per Unit
- $1,000,000 (100 Units) Minimum Aggregate Capital Contributions
- $18,000,000 (1,800 Units) Maximum Aggregate Capital Contributions
- - The units will be offered on a "best efforts" "minimum-maximum" basis.
This means the broker-dealers must sell at least 100 units in order for
this offering to close, and they are required to use only their best
efforts to sell the remaining 1,700 units. Therefore, this offering may
close even though all of the 1,800 units offered have not been sold. All
subscription proceeds will be held in an interest bearing escrow account
until 100 units have been sold. This offering will close on or before
December 31, 1999, and will not be extended. If subscriptions for
$1,000,000 are not received by December 31, 1999, then your subscription
will be promptly returned to you from the escrow account with interest
and without deduction for any fees.
- - Atlas-Energy for the Nineties-Public #8 Ltd., a limited partnership, is
managed by Atlas Resources, Inc. of Pittsburgh, Pennsylvania, and will be
funded to drill natural gas development wells.
- - The Offering
<TABLE>
<CAPTION>
Total Total
Per Unit Minimum Maximum
-------- ------- -------
<S> <C> <C> <C>
Public Price $ 10,000 $ 1,000,000 $18,000,000
Dealer-manager fee, sales $ 1,050 $ 105,000 $ 1,890,000
commis-sions, and reimburse-
ments (1)
Proceeds to partnership $ 10,000 $ 1,000,000 $18,000,000
</TABLE>
- -------------
(1) These fees and expenses will be paid by the managing general partner and
not from subscription proceeds.
--------------------------------
THESE SECURITIES ARE SPECULATIVE AND ARE SUBJECT TO CERTAIN RISKS. (See "Risk
Factors," Page 2.)
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF
THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS
A CRIMINAL OFFENSE.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C>
SUMMARY OF THE OFFERING........................................................1
Atlas-Energy for the Nineties-Public #8 Ltd................................1
Description of Units.......................................................1
RISK FACTORS...................................................................2
Special Risks of the Partnership...........................................2
No Guarantee of Return of Investment or Rate of Return
on Investment Because of Speculative Nature of
Drilling Gas Wells...................................................2
Risk That a Well Does Not Return the
Amount Paid to Drill and Complete It.................................2
Risk of Nonproductive Wells in Development
Drilling.............................................................2
Risks of Reduced Partnership Distributions
Because of Decrease in the Price of Gas..............................2
Risks Regarding the Partnership's Gas Market
Which Could Reduce Partnership Distributions.........................3
Risk of Reduced or Delayed Partnership
Distributions If Gas Production is Curtailed.........................3
If You Choose to Invest as a General Partner
for the Tax Benefits, Then You Have
Greater Risk Than a Limited Partner..................................3
Risk That the Managing General Partner Cannot
Meet Its Indemnification and Repurchase
Obligations Because Its Liquid Net Worth
Is Not Guaranteed....................................................4
Risk That the Managing General Partner Will
Not Devote the Necessary Time to the
Partnership Because Its Management
Obligations Are Not Exclusive........................................4
Risks of a Long-Term Investment Because
the Units Are Illiquid and Not Readily
Transferable.........................................................4
The Number of Partnership Wells Drilled
Depends Upon the Amount of Subscription
Proceeds.............................................................4
Risk Regarding Lack of Information Regarding
a Portion of the Wells...............................................5
There is a Risk That the Data Regarding Currently
Proposed Wells is Incomplete or Incorrect............................5
Managing General Partner's Subordination
is not a Guarantee of the Return of Any
of Your Investment...................................................5
Risk That Borrowings by the Managing
General Partner Could Reduce Funds
Available for Its Subordination Obligation...........................5
Compensation and Fees to the Managing General
Partner Regardless of Success of the
Partnership's Activities.............................................5
Risk of Circumstances Causing Distributions
to Investors to be Reduced or Delayed................................5
Risks Arising From Conflicts of Interest Between
Managing General Partner and the Investors...........................5
Risks That Presentment Obligation May Not
Be Funded and Repurchase Price May Not
Reflect Full Value...................................................5
Risk Regarding Participation with Third Parties
in Drilling Wells....................................................6
Risk of Prepaying Subscription Proceeds to
Managing General Partner.............................................6
Year 2000 Risks Could Adversely Affect
Partnership Operations, Revenues,
and Expenses.........................................................6
Tax Risks..................................................................6
You May Owe Taxes in Excess of Your Cash
Distributions from the Partnership...................................6
Your Deduction for Intangible Drilling Costs
May Be Limited for Purposes of the
Alternative Minimum Tax..............................................6
Investment Interest Deductions of Investor
General Partners May Be Limited......................................7
Lack of Tax Shelter Registration........................................7
ADDITIONAL INFORMATION.........................................................7
FORWARD LOOKING STATEMENTS AND
ASSOCIATED RISKS...............................................................7
INVESTMENT OBJECTIVES..........................................................8
ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS..........................................9
CAPITALIZATION AND SOURCE OF FUNDS
AND USE OF PROCEEDS...........................................................10
Source of Funds...........................................................10
Use of Proceeds...........................................................10
Subsequent Source of Funds and Borrowings.................................11
COMPENSATION..................................................................12
Oil and Gas Revenues......................................................12
Lease Costs...............................................................12
Drilling Contracts........................................................13
Per Well Charges..........................................................13
Gathering Fees............................................................14
Dealer-Manager Fees.......................................................14
Other Compensation........................................................15
Estimate of Administrative Costs and Direct Costs
to be Borne by the Partnership.........................................15
TERMS OF THE OFFERING.........................................................15
Subscription to the Partnership...........................................15
Partnership Closings and Escrow...........................................16
Acceptance of Subscriptions...............................................16
Drilling Period...........................................................17
Suitability Standards.....................................................17
PRIOR ACTIVITIES..............................................................19
MANAGEMENT....................................................................26
Managing General Partner and Operator.....................................26
Recent Merger of Managing General Partner's
Parent Company, Atlas Group............................................26
Organizational Diagram....................................................27
Officers, Directors and Key Personnel.....................................27
Remuneration..............................................................29
Security Ownership of Certain Beneficial Owners...........................30
Transactions with Management and Affiliates...............................30
PROPOSED ACTIVITIES...........................................................30
Intended Areas of Operations..............................................30
Acquisition of Leases.....................................................32
Interests of Parties......................................................32
Title to Properties.......................................................33
Drilling and Completion Activities; Operation
of Producing Wells.....................................................33
Sale of Oil and Gas Production............................................34
Insurance.................................................................36
Use of Consultants and Subcontractors.....................................37
Information Regarding Currently Proposed Wells............................37
COMPETITION, MARKETS AND REGULATION...........................................67
Competition and Markets...................................................67
Crude Oil Regulation......................................................68
Federal Gas Regulation....................................................68
State Regulations.........................................................68
Environmental Regulation..................................................69
Proposed Regulation.......................................................69
PARTICIPATION IN COSTS AND REVENUES...........................................70
In General................................................................70
Costs.....................................................................70
Revenues..................................................................70
Subordination of Portion of Managing General
Partner's Net Revenue Share............................................71
Table of Participation in Costs and Revenues..............................71
Allocation and Adjustment Among Investors.................................72
Distributions.............................................................72
Liquidation...............................................................72
ii
<PAGE>
TABLE OF CONTENTS
<CAPTION>
Page
<S> <C>
CONFLICTS OF INTEREST.........................................................73
In General................................................................73
Conflicts Regarding Transactions with the Managing
General Partner and its Affiliates.....................................73
Conflict Regarding the Drilling and Operating
Agreement..............................................................73
Conflicts Regarding Sharing of Costs and Revenues.........................74
Conflicts Regarding Tax Matters Partner...................................74
Conflicts Regarding Other Activities of the
Managing General Partner, the Operator and
Their Affiliates.......................................................74
Conflicts Involving the Acquisition of Leases.............................75
Conflicts Between Investors and the Managing
General Partner as an Investor.........................................77
Lack of Independent Underwriter and Due
Diligence Investigation................................................77
Conflicts Concerning Legal Counsel........................................77
Conflicts Regarding Presentment Feature...................................77
Conflicts Regarding Managing General Partner
Withdrawing an Interest................................................77
Conflicts Regarding Order of Pipeline Construction........................77
Procedures to Reduce Conflicts of Interest................................77
Policy Regarding Roll-Ups.................................................78
Certain Transactions......................................................80
FIDUCIARY RESPONSIBILITY OF THE
MANAGING GENERAL PARTNER......................................................80
In General................................................................80
Limitations on Managing General Partner Liability
as Fiduciary...........................................................81
TAX ASPECTS...................................................................81
Summary of Tax Opinion....................................................81
Partnership Classification................................................83
Limitations on Passive Activities.........................................83
Taxable Year..............................................................84
1999 Expenditures.........................................................84
Availability of Certain Deductions........................................84
Intangible Drilling Costs.................................................84
Drilling Contracts........................................................85
Depletion Allowance.......................................................86
Depreciation - Modified Accelerated Cost
Recovery System ("MACRS")..............................................86
Leasehold Costs and Abandonment...........................................86
Tax Basis of Investors' Interests.........................................86
"At Risk" Limitation for Losses...........................................87
Distributions from a Partnership..........................................87
Sale of the Properties....................................................87
Disposition of Partnership Interests......................................87
Minimum Tax - Tax Preferences.............................................88
Limitations on Deduction of Investment Interest...........................88
Allocations...............................................................88
Partnership Borrowings....................................................89
Partnership Organization and Syndication Fees.............................89
Tax Elections.............................................................89
Disallowance of Deductions under Section 183
of the Internal Revenue Code...........................................89
Termination of a Partnership..............................................89
Lack of Registration as a Tax Shelter.....................................89
Tax Returns and Audits....................................................90
Penalties and Interest....................................................90
State and Local Taxes.....................................................91
Severance and Ad Valorem (Real Estate) Taxes..............................91
Social Security Benefits and Self-Employment Tax..........................91
Foreign Partners..........................................................91
Estate and Gift Taxation..................................................91
SUMMARY OF PARTNERSHIP AGREEMENT..............................................91
Liability of Limited Partners.............................................92
Amendments................................................................92
Notice....................................................................92
Voting Rights.............................................................92
Access to Records.........................................................93
Withdrawal of Managing General Partner....................................93
SUMMARY OF DRILLING AND OPERATING
AGREEMENT.....................................................................93
REPORTS TO INVESTORS..........................................................94
PRESENTMENT FEATURE...........................................................95
TRANSFERABILITY OF UNITS......................................................97
Restrictions on Transfer Imposed by the Securities
and Tax Law ...........................................................97
Transfer Provisions.......................................................97
PLAN OF DISTRIBUTION..........................................................98
Commissions...............................................................98
Indemnification...........................................................98
SALES MATERIAL................................................................99
LEGAL OPINIONS................................................................99
EXPERTS.......................................................................99
LITIGATION...................................................................100
FINANCIAL INFORMATION CONCERNING THE
MANAGING GENERAL PARTNER AND
THE PARTNERSHIP..........................................................100
</TABLE>
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
<PAGE>
SUMMARY OF THE OFFERING
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
The partnership is a Pennsylvania limited partnership. Atlas Resources, Inc.,
311 Rouser Road, Moon Township, Pennsylvania 15108, (412) 262-2830, will
manage the partnership as managing general partner and supervise the
drilling, completion and operation of the wells to be drilled as operator.
The partnership will drill development wells, primarily in the Mercer County
area of Pennsylvania, which will test the Clinton/Medina geological
formation. However, up to 20% of the subscription proceeds may be used to
drill development wells in other areas of the United States, primarily in the
Appalachian Basin. A 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. The managing general partner anticipates that all the wells
will be classified as gas wells which may produce a small amount of oil.
DESCRIPTION OF UNITS
You may purchase either:
- investor general partner units; or
- limited partner units.
Regardless of which type of unit you buy, costs, revenues and cash
distributions will be allocated between you and the other investors pro rata
based upon the amount of your subscription. There are, however, material
differences in the federal income tax effects and liability associated with
each type of unit.
INVESTOR GENERAL PARTNER UNITS.
- TAX EFFECT. If you invest as an investor general partner, then
your share of the partnership's 1999 deduction for intangible
drilling costs will not be subject to the passive activity
limitations. This means that generally you may deduct
approximately 85% of your subscription, $8,500 per unit, in
1999. Intangible drilling costs generally means those costs of
drilling and completing a well that are currently deductible,
as compared to lease costs which must be recovered through the
depletion allowance and costs for equipment in the well which
must be recovered through depreciation deductions.
- LIABILITY. If you invest as an investor general partner, then
you will have unlimited liability regarding partnership
activities. This means if:
- the insurance proceeds,
- the managing general partner's indemnification,
and
- partnership assets
were not sufficient to satisfy a partnership liability for
which you and the other investor general partners were
also liable, then the managing general partner would call
upon you and the other investor general partners to make
additional capital contributions to the partnership from
your personal assets to satisfy the liability. You and the
other investor general partners do not have an option to
refuse to make this additional capital contribution. In
addition, you and the other investor general partners have
joint and several liability which means generally that a
person with a claim against the partnership may sue all or
any one or more of the partnership's general partners,
including you, for the entire amount of the liability.
1
<PAGE>
LIMITED PARTNER UNITS.
- TAX EFFECT. If you invest as a limited partner, then your
use of the partnership's deduction for intangible drilling
costs generally will be limited to net passive income from
"passive" trade or business activities. This generally
includes the partnership and other limited partner
investments. This means that you will not be able to
deduct your share of the partnership's intangible drilling
costs in 1999 unless you have passive income from
investments other than the partnership.
- LIABILITY. If you invest as a limited partner, then you
will have limited liability and generally will not be
liable for amounts beyond your initial investment and your
share of undistributed net profits.
RISK FACTORS
An investment in the partnership involves a high degree of risk and is suitable
only if you have substantial financial means and no need of liquidity in your
investment.
SPECIAL RISKS OF THE PARTNERSHIP
NO GUARANTEE OF RETURN OF INVESTMENT OR RATE OF RETURN ON INVESTMENT BECAUSE OF
SPECULATIVE NATURE OF DRILLING GAS WELLS. Gas exploration is an inherently
speculative activity. Before the drilling of a well the managing general partner
cannot predict with any certainty the amount of gas recoverable from the well or
the time it will take to recover the gas. There is a risk that you will not
recover all of your investment or if you do recover your investment that you
will not receive a rate of return on your investment which is competitive with
other types of investment. You will be able to recover your investment only
through the partnership's distributions of the sales proceeds from the
production of its gas reserves from productive wells. Gas reserves generally
deplete over time until the wells are no longer economical to operate. All of
these distributions to you may be considered a return of capital until you have
received 100% of your investment.
RISK THAT A WELL DOES NOT RETURN THE AMOUNT PAID TO DRILL AND COMPLETE IT. There
is a risk that even if a well is completed by the partnership and produces gas
in commercial quantities it will not produce enough gas to pay for the costs of
drilling and completing the well, even if tax benefits are considered. The
managing general partner has formed 32 partnerships since 1985, 27 of which were
formed in 1990 or subsequent years. All the partnerships are continuing to make
cash distributions, however, 29 of the 32 partnerships have not yet returned to
the investor 100% of his capital contributions without taking tax savings into
account.
RISK OF NONPRODUCTIVE WELLS IN DEVELOPMENT DRILLING. Although drilling
development wells reduces the risk of drilling nonproductive wells, there is a
risk that the partnership will drill some wells which are nonproductive and must
be plugged and abandoned. If one or more of the partnership's wells are
nonproductive, then the partnership's productive wells may not produce enough
revenues to offset the loss of investment in the nonproductive wells.
RISK OF REDUCED PARTNERSHIP DISTRIBUTIONS BECAUSE OF DECREASE IN THE PRICE OF
GAS. There is no assurance of the price at which the partnership's gas will be
sold. If gas prices decrease, then your share of partnership revenues will
decrease accordingly. The price will depend on supply and demand factors largely
beyond the control of the partnership. During most of the 1980's and 1990's gas
prices have been volatile and there is a risk that gas prices could decrease in
the future.
There is a further risk that the price of gas may decrease during the first
years of production when the wells achieve their greatest level of production.
This would have the greatest adverse affect on partnership distributions to you.
2
<PAGE>
RISKS REGARDING THE PARTNERSHIP'S GAS MARKET WHICH COULD REDUCE PARTNERSHIP
DISTRIBUTIONS. Difficulties in marketing the partnership's gas could result in
reduced distributions from the partnership to you and the other investors. The
managing general partner estimates that approximately 10% to 15% of the
partnership's gas production in the Mercer County area, which is the primary
area of interest, will be sold directly to an industrial end-user situated in
the area where the wells will be drilled. Selling gas to industrial end-users
can create risks that 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 filed Chapter 11 bankruptcy in 1987, it
continued to purchase most of the managing general partner's and its affiliates'
natural gas production in the Mercer County area until it filed a second Chapter
11 bankruptcy in 1992 owing monies to the managing general partner and the
partnerships.
The remainder of the partnership's gas from the Mercer County area, with certain
exceptions, will be sold under a 10-year agreement. This agreement provides that
the gas price may be adjusted upward or downward in accordance with the spot
market price and market conditions, and for the negotiation of the gas price
annually after either the first or second year depending upon the delivery
point. Thus, there is no assurance of a specific gas price for the term of the
agreement, and there is a risk that the price for the partnership's gas will be
decreased under the agreement because of market conditions. Also, in the past
low gas prices or other difficulties in marketing gas have resulted in some
purchasers renegotiating existing agreements to reduce the contract price for
gas. Finally, the revenues received by the partnership will be less the farther
the gas is transported because of the increased transportation costs.
RISK OF REDUCED OR DELAYED PARTNERSHIP DISTRIBUTIONS IF GAS PRODUCTION IS
CURTAILED. During the term of the partnership there is a risk that production
from the wells may be curtailed either because of limited demand or the managing
general partner awaits a better price. This would reduce or delay distributions
from the partnership to you and the other investors. For example, there are
seasonal marketing demands and gas prices are usually higher in the winter
months because of residential heating requirements than the summer months.
IF YOU CHOOSE TO INVEST AS A GENERAL PARTNER FOR THE TAX BENEFITS, THEN YOU HAVE
GREATER RISK THAN A LIMITED PARTNER. If you invest as an investor general
partner for the tax benefits instead of as a limited partner, then under
Pennsylvania law you will have unlimited liability for the partnership's
activities. This could result in you being required to make payments in addition
to your original investment in amounts that are impossible to predict because of
their uncertain nature. Under the terms of the partnership agreement, if you are
an investor general partner you agree to pay only your proportionate share of
the partnership's obligations and liabilities. This agreement, however, does not
eliminate your liability to third parties if another investor general partner
does not pay his proportionate share of the partnership's obligations and
liabilities.
Also, the partnership may own less than 100% of the interest in some of the
wells. If a court holds you and the other third party owners of the well to be
liable for the development and operation of a well and the third party well
owner does not pay its proportionate share of the costs and liabilities
associated with the well, then the partnership and you and the other investor
general partners would be liable to third parties for those costs and
liabilities.
The partnership will have the benefit of general and excess liability insurance
of $50,000,000 during drilling operations and $11,000,000 thereafter, per
occurrence and in the aggregate. Nevertheless, as an investor general partner
you may become subject to the following:
- contract liability which is not covered by insurance;
- liability for drilling hazards such as well blowouts, fires and
explosions resulting in property damage or injury or death to third
parties in excess of the amounts insured under the policies; and
3
<PAGE>
- 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.
If the insurance proceeds, partnership assets, and the managing general
partner's indemnification of you and the other investors general partners were
not sufficient to satisfy the liability, then your personal assets could be
required to be used to satisfy the liability. If this occurs, then you will not
have an option to refuse to contribute the additional funds called for by the
managing general partner to pay partnership liabilities.
RISK THAT THE MANAGING GENERAL PARTNER CANNOT MEET ITS INDEMNIFICATION AND
REPURCHASE OBLIGATIONS BECAUSE ITS LIQUID NET WORTH IS NOT GUARANTEED. The
managing general partner has made commitments to you and the other investors
regarding the following:
- indemnification of the investor general partners for liabilities in
excess of their pro rata share of partnership assets; and
- repurchasing the units.
A significant financial reversal for the managing general partner could
adversely affect its ability to honor these obligations. This would reduce the
value of the units.
The net worth of the managing general partner is based primarily on the
estimated value of its producing gas properties and is not available in cash
without borrowings or a sale of the properties. Also, if gas prices decrease the
estimated value of the properties and the net worth of the managing general
partner will be reduced. There is no assurance that the managing general partner
will have the necessary net worth, either currently or in the future, to meet
its financial commitments under the partnership agreement. These risks are
increased because the managing general partner has made and will make similar
financial commitments in other partnerships.
RISK THAT THE MANAGING GENERAL PARTNER WILL NOT DEVOTE THE NECESSARY TIME TO THE
PARTNERSHIP BECAUSE ITS MANAGEMENT OBLIGATIONS ARE NOT EXCLUSIVE. The managing
general partner must devote the amount of time to the partnership's affairs that
it determines is reasonably necessary. However, the managing general partner 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, including other partnerships. Thus, there is
a risk that the managing general partner will not devote the necessary time to
the partnership.
RISKS OF A LONG-TERM INVESTMENT BECAUSE THE UNITS ARE ILLIQUID AND NOT READILY
TRANSFERABLE. If you invest in the partnership, then you must assume the risks
of an illiquid investment. The transferability of the units is limited by the
partnership agreement and the state and federal securities laws. The units
cannot be readily liquidated, and there is no market for the sale of the units.
Also, a sale of your units could create adverse tax and economic consequences
for you.
THE NUMBER OF PARTNERSHIP WELLS DRILLED DEPENDS UPON THE AMOUNT OF SUBSCRIPTION
PROCEEDS. If all of the units offered are not sold, then fewer wells will be
drilled which decreases the partnership's ability to spread the risks of
drilling. The managing general partner anticipates that approximately 4.96 wells
will be drilled if the minimum required subscriptions of $1,000,000 are
received, and approximately 89.35 wells will be drilled if subscriptions for
$18,000,000 are received.
On the other hand, to the extent more than the minimum subscriptions are
received and the number of wells drilled increases, the partnership's overall
investment return may decrease if the managing general partner is unable to find
enough suitable wells to be drilled. Also, in a large partnership greater
demands will be placed on the management capabilities of the managing general
partner.
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RISK REGARDING LACK OF INFORMATION REGARDING A PORTION OF THE WELLS. The wells
currently proposed to be drilled represent approximately 66% of the wells that
will be drilled if all the units are sold. Also, the managing general partner
has reserved the right to substitute wells and to drill in other areas. Thus,
not all of the wells may be specified and you do not have any geological,
economic, or other information to evaluate any additional and/or substituted
wells. Instead, you must rely entirely on the managing general partner to select
those wells. Also, the partnership does not have the right of first refusal in
the selection of well locations from the inventory of the managing general
partner and its affiliates, and they may sell their well locations to other
partnerships, companies, joint ventures or other persons at any time.
THERE IS A RISK THAT THE DATA REGARDING CURRENTLY PROPOSED WELLS IS INCOMPLETE
OR INCORRECT. The information in this prospectus regarding the wells currently
proposed to be drilled has been prepared by the managing general partner from
sources which it believes are reliable. However, there is a risk that the data
does not reflect all the wells drilled in the area, or the amount of gas
production is not always accurate. Also, the production information for some of
the wells is incomplete because the information is unavailable to the managing
general partner or the wells have been producing for only a short period of time
or are not yet completed or on-line.
MANAGING GENERAL PARTNER'S SUBORDINATION IS NOT A GUARANTEE OF THE RETURN OF ANY
OF YOUR INVESTMENT. If your cash distributions are less than a 10% return for
each of the first five 12-month periods of partnership operations, then the
managing general partner has agreed to subordinate a portion of its share of the
partnership's net production revenues. However, if the wells produce only a
small gas volume, and/or gas prices decrease, then even with subordination your
cash flow may be very small and you may not receive a return of your entire
investment.
RISK THAT BORROWINGS BY THE MANAGING GENERAL PARTNER COULD REDUCE FUNDS
AVAILABLE FOR ITS SUBORDINATION OBLIGATION. The managing general partner
anticipates that it will pledge either its partnership interest and/or an
undivided interest in the assets of the partnership to secure borrowings for its
own corporate purposes. If there was a default to the lender under this pledge
arrangement, then this would reduce the amount of the partnership's net
production revenues available to the managing general partner for its
subordination obligation to you and the other investors.
COMPENSATION AND FEES TO THE MANAGING GENERAL PARTNER REGARDLESS OF SUCCESS OF
THE PARTNERSHIP'S ACTIVITIES. The managing general partner and its affiliates
can be expected to profit from the partnership even if partnership activities
result in little or no profit, or a loss to you.
RISK OF CIRCUMSTANCES CAUSING DISTRIBUTIONS TO INVESTORS TO BE REDUCED OR
DELAYED. There is a risk that you will not receive cash distributions every
quarter. Although the managing general partner intends to distribute the cash
quarterly, distributions may be deferred to the extent partnership revenues are
used for the following:
- costs related to completing some of the wells in a third zone;
- remedial work to improve a well's producing capability;
- reserves, including a reserve for the estimated costs of eventually
plugging and abandoning the wells; or
- indemnification of the managing general partner and its affiliates
by the partnership for losses or liabilities incurred in connection
with the partnership's activities.
RISKS ARISING FROM CONFLICTS OF INTEREST BETWEEN MANAGING GENERAL PARTNER AND
THE INVESTORS. There are conflicts of interest between you and the managing
general partner and its affiliates. Other than certain guidelines set forth in
"Conflicts of Interest," the managing general partner has no established
procedures to resolve a conflict of interest.
RISKS THAT PRESENTMENT OBLIGATION MAY NOT BE FUNDED AND REPURCHASE PRICE MAY NOT
REFLECT FULL VALUE. Subject to certain conditions, beginning in 2004 you may
present your units to the managing general partner for purchase. There is a risk
that the managing general partner will determine, in its sole discretion, that
it does not have the necessary cash flow or
5
<PAGE>
cannot arrange financing for these purposes on reasonable terms. In either
event the managing general partner is able to suspend the presentment
feature. This risk is further increased because the managing general partner
has and will incur similar presentment obligations in connection with other
partnerships.
There is a risk that the presentment price may not reflect the full value of the
partnership's property or your units because of the difficulty in accurately
estimating oil and gas reserves. The estimates are merely appraisals of value
and may not correspond to realizable value. Also, there can be no assurance that
the presentment price paid for your units and any revenues received by you
before the presentment will be equal to the purchase price of the units. You
might realize a greater return if you retain the units, which you may elect,
rather than selling the units to the managing general partner.
RISK REGARDING PARTICIPATION WITH THIRD PARTIES IN DRILLING WELLS. It is
anticipated that the partnership will own all of the interest in its wells
subject to royalties and any other burdens on the leases. However, the
partnership has reserved the right to own as little as 25% of the interest and
it is possible that third parties will participate with the partnership in
drilling some of the wells. Additional financial risks exist when the cost of
drilling, equipping, completing and operating wells is shared by more than one
person. If the partnership pays its share of the costs but another interest
owner does not, then the partnership would have to pay the costs of the
defaulting party.
RISK OF PREPAYING SUBSCRIPTION PROCEEDS TO MANAGING GENERAL PARTNER. Under the
drilling and operating agreement the partnership will be required to immediately
pay the managing general partner the investors' share of the entire contract
price for drilling and completing the partnership's wells. Thus, these funds
could be subject to claims of the managing general partner's creditors.
YEAR 2000 RISKS COULD ADVERSELY AFFECT PARTNERSHIP OPERATIONS, REVENUES, AND
EXPENSES. The "year 2000 issue" is the result of computer programs which cannot
distinguish between the year 2000 and the year 1900. This could result in
miscalculations or an inability to process transactions, send invoices, or
engage in similar normal business activities. Actions are being taken by the
managing general partner to respond to year 2000 remediation requirements. There
can be no assurance that those actions will be successful or adequate or that
any year 2000 problems that exist will be discovered or remedied in sufficient
time. The managing general partner and the partnership are also vulnerable to
potential losses of revenue, goods or services caused by failures of suppliers
and customers or other persons to remedy their year 2000 problems.
TAX RISKS
YOU MAY OWE TAXES IN EXCESS OF YOUR CASH DISTRIBUTIONS FROM THE PARTNERSHIP.
There is a risk that you may become subject to income tax liability in excess of
cash actually received from the partnership. For example:
- if the partnership borrows money your share of partnership revenues
used to pay principal on the loan will be included in your taxable
income from the partnership and will not be deductible;
- taxable income or gain may be allocated to you if there is a deficit
in your capital account even though you do not receive a
corresponding distribution of partnership revenues;
- partnership revenues may be retained by the managing general partner
for partnership costs or to establish a reserve for future estimated
costs, including a reserve for the estimated costs of eventually
plugging and abandoning the wells; and
- the taxable disposition of partnership property or your units may
result in income tax liability in excess of cash distributions.
YOUR DEDUCTION FOR INTANGIBLE DRILLING COSTS MAY BE LIMITED FOR PURPOSES OF
THE ALTERNATIVE MINIMUM TAX. You will be allocated a share of the
partnership's deduction for intangible drilling costs. However, alternative
minimum taxable income of most investors cannot be reduced by more than 40%
by the deduction for intangible drilling costs.
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<PAGE>
INVESTMENT INTEREST DEDUCTIONS OF INVESTOR GENERAL PARTNERS MAY BE LIMITED. An
investor general partner's share of the partnership's deduction for intangible
drilling costs will reduce his investment income and may adversely affect the
deductibility of his investment interest expense, if any.
LACK OF TAX SHELTER REGISTRATION. The managing general partner believes that the
partnership is not be a tax shelter required to register with the IRS. If it is
subsequently determined by the IRS or the courts that the partnership was
required to be registered with the IRS as a tax shelter, you would be liable for
a $250 penalty for failure to include a tax registration number of the
partnership on your tax return, unless this failure was due to reasonable cause.
ADDITIONAL INFORMATION
The partnership currently is not required to file reports with the SEC. However,
a registration statement on Form SB-2 has been filed on behalf of the
partnership with the SEC. Certain portions of the registration statement have
been deleted from this prospectus under SEC rules and regulations. Also,
statements in this prospectus concerning the contents of any document are
incomplete. You are urged to refer to the registration statement and exhibits
for further information including the provisions of any document referred to in
the prospectus.
You may read and copy any materials filed as a part of the registration
statement, including the tax opinion as set forth on Exhibit 8, at the SEC's
Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The
SEC maintains an internet world wide web site that contains registration
statements, reports, proxy statements and other information about issuers who
file electronically with the SEC, including the partnership. The address of
that site is http://www.sec.gov. Also, you may obtain information on the
operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
In addition, a copy of the tax opinion may be obtained by you or your
advisors from the managing general partner at no cost. The delivery of this
prospectus does not imply that its information is correct as of any time
after its date.
FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS
Statements, other than statements of historical facts, included in this
prospectus and its exhibits address activities, events or developments that the
managing general partner and the partnership anticipate will or may occur in the
future. These forward-looking statements include such things as:
- investment objectives,
- business strategy,
- estimated future capital expenditures,
- competitive strengths and goals,
- references to future success, and
- other similar matters.
These statements are based on certain assumptions and analyses made by the
partnership and the managing general partner in light of their experience and
their perception of historical trends, current conditions and expected future
developments. However, whether actual results will conform with these
expectations is subject to a number of risks and uncertainties, many of which
are beyond the control of the partnership, including:
7
<PAGE>
- general economic, market or business conditions,
- changes in laws or regulations,
- 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
- other risks.
Thus, all of the forward-looking statements made in this prospectus and its
exhibits are qualified by these cautionary statements. There can be no assurance
that actual results will conform with the managing general partner's and the
partnership's expectations.
INVESTMENT OBJECTIVES
The partnership's principal investment objectives are to invest the subscription
proceeds in natural gas development wells which will:
- Provide quarterly cash distributions to you until the wells are
depleted, historically 20+ years, with a preferred annual cash flow
of 10% during the first five years based on your original
subscription amount. A reserve and economic report dated 10/98
which was prepared by the managing general partner and reviewed
by Wright & Company, Inc., petroleum consultants, evaluated the
past history and estimated future production of 901 wells
drilled to the Clinton/Medina geological formation in the same
field as the partnership's proposed well locations. Based on
data in that report, approximately 835 of those wells are
expected by the managing general partner to produce more than 20
years.
- Obtain tax deductions in 1999 from intangible drilling costs and
depreciation of equipment costs to offset a portion of your taxable
income, subject to the passive activity rules if you invest as a
limited partner. One unit will produce a 1999 tax deduction of
$8,500, 85%, against ordinary income if you invest as an investor
general partner and against passive income if you invest as a
limited partner. If you are in either the 39.6% or 36% tax bracket,
then one unit will save you $3,366 or $3,000 respectively in federal
taxes this year. Most states also allow this type of a deduction
against the state income tax.
- Offset a portion of any taxable income generated by the partnership
with tax deductions from percentage depletion, which is 24% in 1999
and is estimated to be 26% on net revenue. The managing general
partner estimates that this feature should reduce your effective tax
rate from 39.6% to 29.3%, which is 74% of 39.6%, on partnership net
revenues.
- Obtain tax deductions of the remaining 15% of the initial investment
from 2000 through 2007. You will receive an additional $1,500 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 WELLS 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.
8
<PAGE>
ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS
You may choose to invest as an investor general partner so that you can receive
an immediate tax deduction against any type of income. To help reduce the risk
that you and other investor general partners could be required to make
additional payments to the partnership, the managing general partner will take
the following actions:
- INSURANCE. Fifty million dollars of liability coverage during
drilling operations and eleven million dollars after drilling
operations cease.
- CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER
INTERESTS. Your investor general partner units will be automatically
converted to limited partner interests after substantially all of
the partnership wells have been drilled and completed. Conversion is
anticipated to be in late summer of 2000.
After conversion you will have the lesser liability of a limited
partner under Pennsylvania law for obligations and liabilities
arising after the conversion. However, you will continue to have the
responsibilities of a general partner for partnership liabilities
and obligations incurred before the effective date of the
conversion. Thus, you might become liable for partnership
obligations in excess of your subscription during the time the
partnership is engaged in drilling activities and for environmental
claims that arose during drilling activities but were not discovered
until after conversion.
- NONRECOURSE DEBT. The partnership will be permitted to borrow funds
only from the managing general partner or its affiliates without
recourse against your non-partnership assets. Thus, if there is a
default under this loan arrangement you cannot be required to
contribute funds to the partnership. Any borrowings 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 investors' subscriptions. Because you do
not bear the risk of repaying these borrowings with non-partnership
assets, the borrowings will not increase the extent to which you are
allowed to deduct your individual shares of partnership losses.
To further protect you, during producing operations all third party
goods and services will be acquired by the managing general partner
and its affiliates, and the partnership will then acquire the goods
and services from the managing general partner and its affiliates at
their cost.
- INDEMNIFICATION. The managing general partner will indemnify you
from any liability incurred in connection with the partnership which
is in excess of:
- your interest in the undistributed net assets of the
partnership; and
- insurance proceeds, if any.
The managing general partner's indemnification obligation,
however, will not eliminate your potential liability if the
insurance is not sufficient or available to cover a liability and
the managing general partner's assets are insufficient to satisfy
its indemnification obligation. There can be no assurance that
the managing general partner's assets, including its liquid
assets, will be sufficient to satisfy its indemnification
obligation.
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<PAGE>
CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS
SOURCE OF FUNDS
Upon completion of the offering the capital contributions to the partnership of
you and the other investors will range from $1,000,000 if 100 units are sold to
$18,000,000 if 1,800 units are sold. The capital contributions of the managing
general partner will be not less than 22.15% of all capital contributions to the
partnership and will range from $284,436 if 100 units are sold, to $5,121,742 if
1,800 units are sold. The total amount of capital contributions available to the
partnership from both the managing general partner and you and the other
investors will range from $1,284,436 if 100 units are sold, to $23,121,742 if
1,800 units are sold.
USE OF PROCEEDS
All of the subscription proceeds will be used to pay 100% of the intangible
drilling costs and 56.25% of the equipment costs of drilling and completing the
partnership's wells. The managing general partner will pay 43.75% of the
equipment costs and all of the organization and offering costs, and contribute
all of the leases to the partnership covering the acreage on which the wells
will be drilled.
The following tables present information concerning the partnership's use of the
proceeds provided by both the investors and the managing general partner.
Substantially all of the proceeds available to the partnership will be expended
for the following purposes and in the following manner:
<TABLE>
<CAPTION>
INVESTOR CAPITAL
ENTITY
RECEIVING 100 UNITS 1,800 UNITS
PAYMENT NATURE OF PAYMENT SOLD % (1) SOLD % (1)
- ------- ----------------- ---- ----- ---- -----
<S> <S> <C> <C> <C> <C>
TOTAL INVESTOR CAPITAL $1,000,000 100% $18,000,000 100%
LESS: ORGANIZATION AND OFFERING EXPENSES
Broker-Dealers Dealer-manager fee, sales - 0 - - 0 - - 0 - - 0 -
commissions, reimbursement of
marketing expenses, and
reimbursement for bona fide
accountable due diligence expenses
Various Organization costs - 0 - - 0 - - 0 - - 0 -
AMOUNT AVAILABLE FOR INVESTMENT:
Managing General Partner Intangible drilling costs and $1,000,000 100% $18,000,000 100%
equipment
Managing General Partner Leases - 0 - - 0 - - 0 - - 0 -
</TABLE>
- --------------------------------------------
(1) The percentage is based upon total investor subscriptions and excludes
the managing general partner's capital contribution.
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<PAGE>
MANAGING GENERAL PARTNER CAPITAL
<TABLE>
<CAPTION>
ENTITY
RECEIVING 100 UNITS 1,800 UNITS
PAYMENT NATURE OF PAYMENT SOLD % (1) SOLD % (1)
- ------- ----------------- ---- ----- ---- -----
<S> <C> <C> <C> <C> <C>
TOTAL MANAGING GENERAL PARTNER CAPITAL $284,436 100% $5,121,742 100%
LESS: ORGANIZATION AND OFFERING EXPENSES
Broker-Dealers Dealer-manager fee, sales $105,000 36.9% $1,890,000 36.9%
commissions, reimbursement of
marketing expenses, and
reimbursement for bona fide
accountable due diligence expenses
Various Organization costs $45,000 15.8% $810,000 15.8%
AMOUNT AVAILABLE FOR INVESTMENT:
Managing General Partner Equipment costs $116,580 41.0% $2,100,082 41.0%
Managing General Partner Leases (2) $17,856 6.3% $321,660 6.3%
</TABLE>
- --------------------------------------
(1) The percentage is based upon the managing general partner's capital
contribution and excludes the investors' subscriptions.
(2) Instead of contributing cash for the leases, the managing general partner
will assign the leases to the partnership.
SUBSEQUENT SOURCE OF FUNDS AND BORROWINGS
It is anticipated that substantially all the partnership's initial capital will
be committed or expended after the offering. If the partnership requires
additional funds for completing some of the wells in a third zone, or additional
development or remedial work is required for a well after it begins producing,
then these funds may be provided by borrowings from the managing general partner
or its affiliates or retaining partnership revenues. The managing general
partner, however, does not anticipate that any borrowings will be required
before there are production revenues, and the managing general partner is not
contractually committed to loan money to the partnership. There will be no
borrowings from third parties.
The amount that may be borrowed by the partnership from the managing general
partner and its affiliates may not at any time exceed 5% of the investors'
subscriptions and must be without recourse to you and the other investors. The
partnership's repayment of any borrowings would be from partnership production
revenues and would reduce or delay your cash distributions. If the managing
general partner loans money to the partnership then:
- the interest charged to the partnership must not exceed the managing
general partner's interest cost or the interest that would be
charged to the partnership without reference to the managing general
partner's financial abilities or guarantees by unrelated lenders, on
comparable loans for the same purpose, and
- the managing general partner may not receive points or other
financing charges or fees although the actual amount of the charges
incurred from third-party lenders may be reimbursed to the managing
general partner.
Currently, the managing general partner participates in a $45 million revolving
credit facility at PNC Bank. The revolving credit facility has a term ending in
November 2002.
The revolving credit facility contains certain financial covenants of the
managing general partner, including maintaining a current ratio of .85 to 1, a
ratio of fixed charges to earnings of 1.5 to 1, increasing to 2.5 to 1 over the
next several years, and a leverage ratio, essentially a ratio of debt to equity,
of not less than 3.25 to 1, reducing to 3.00 to 1 in March 2000. The credit
facility also imposes the following limits:
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<PAGE>
- the managing general partner's exploration expense can be no more
than 20% of capital expenditures plus exploration expense, without
PNC Bank's consent;
- sales, leases or transfers of property by the managing general
partner are limited to $1 million without PNC Bank's consent; and
- the managing general partner cannot incur debt in excess of $2
million to lenders other than PNC Bank without PNC Bank's consent.
As of August 31, 1999, there was $27 million outstanding under the revolving
credit facility.
COMPENSATION
The items of compensation paid to the managing general partner and its
affiliates from the partnership are set forth below.
OIL AND GAS REVENUES
Under the partnership agreement the managing general partner will be allocated
29% of the oil and gas revenues of the partnership in return for paying
organization and offering costs equal to 15% of the investors' subscriptions,
43.75% of equipment costs, and contributing all leases to the partnership.
LEASE COSTS
Under the partnership agreement the managing general partner will contribute to
the partnership all the undeveloped leases necessary to drill the partnership's
wells. The managing general partner will receive a credit to its capital account
equal to the cost of the leases, or fair market value if the managing general
partner has reason to believe that 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 and engineering expenses,
- interest expense,
- legal expense, and
- expenses for other like services allocated to the partnership's
leases determined using industry guidelines.
In the Mercer County area, which is the partnership's primary area of interest,
the managing general partner's lease cost is approximately $3,600 per well
location. Assuming all the leases are situated in the Mercer County area and the
partnership acquires 100% of the interest, the managing general partner
estimates that its credit for lease costs will be:
- $17,856 if $1,000,000 is received, which is 4.96 wells at $3,600
per well; and
- $321,660 if $18,000,000 is received, which is 89.35 wells at $3,600
per well.
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<PAGE>
The development of wells on the acreage may provide the managing general partner
with offset drill sites by allowing it to determine at the partnership's expense
the value of adjacent acreage in which the partnership would not have any
interest.
DRILLING CONTRACTS
The partnership will enter into the drilling and operating agreement with the
managing general partner to drill and complete the partnership wells at a
competitive industry rate. 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 multiplied by $37.81 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. To the extent that the
partnership acquires less than a 100% interest in a well, its drilling and
completion costs of that well will be proportionately decreased. If 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, then the rates will be adjusted to the competitive rate.
The managing general partner expects to subcontract some of the actual drilling
and completion of the partnership's wells to third parties selected by it.
However, the managing general partner may not benefit by interpositioning itself
between the partnership and the actual provider of drilling contractor services.
The footage price includes all ordinary costs of drilling, testing and
completing the well. This includes the cost of a second completion and frac
which means, in general, treating a second potentially productive geological
formation in an attempt to enhance the gas production from the well. It also
includes installing gathering lines and other necessary facilities for the
production of natural gas. Although the following costs are possible, it is not
anticipated that these costs will be incurred, and the footage price will not
include the cost of a pumping unit for an oil well or the cost of a third
completion and frac. Each additional frac is anticipated to be approximately
$8,000. These extra costs will be paid from subscription proceeds or partnership
revenues and charged at invoice cost plus 10% if provided by third parties and
at competitive rates in the area if provided by the managing general partner or
its affiliates.
The amount of compensation which the managing general partner could earn as a
result of these arrangements depends on many factors, including the actual cost
of the wells and the number of wells drilled. The managing general partner
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% ($33,206) per well for a well drilled to a depth of
5,950 feet. Assuming all the wells are situated in the Mercer County area,
drilled and completed to a depth of 5,950 feet, and the partnership acquires
100% of the interest in the wells, it is estimated that the managing general
partner's general and administrative overhead reimbursement and profit will be:
- $182,558 if $1,000,000 is received, which is 4.96 wells at $36,806
profit and overhead per well; and
- $3,288,616 if $18,000,000 is received, which is 89.35 wells at
$36,806 profit and overhead per well.
PER WELL CHARGES
Under the drilling and operating agreement when the wells begin producing the
managing general partner, as operator of the wells, 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. The well supervision fees
will be proportionately reduced to the extent the partnership acquires less than
100% of the interest in the well. The fee may be adjusted for inflation annually
beginning January 1, 2001. If the foregoing rates exceed competitive rates
available from other non-affiliated persons in the area engaged in the business
of providing comparable services or equipment, then the rates will be adjusted
to the competitive rate. The managing general partner may not benefit by
interpositioning itself between the partnership and the actual provider of
operator services. In no event will any consideration received for operator
services be duplicative of any consideration or reimbursement received pursuant
to the partnership agreement.
The well supervision fee covers all normal and regularly recurring operating
expenses for the production, delivery and sale of gas, such as:
13
<PAGE>
- 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.
These costs will be charged at the invoice cost of the materials purchased, or
the third party services performed.
Assuming all the wells are drilled and completed in the Appalachian Basin and
the partnership acquires 100% of the interest in the wells, it is estimated that
the managing general partner will receive well supervision fees for the
partnership's first 12 months of operation of:
- $16,368 if $1,000,000 is received, which is 4.96 wells at $275 per
well per month; and
- $294,855 if $18,000,000 is received, which is 89.35 wells at $275
per well per month.
GATHERING FEES
The managing general partner and its affiliates, which may include a limited
partnership sponsored by an affiliate of Atlas America, will gather and deliver
natural gas produced by the partnership to either industrial end-users in the
area or interstate pipeline systems and local distribution companies. The
partnership will pay a gathering charge at a competitive rate, which is
currently 29 cents per MCF. MCF means one thousand cubic feet of natural gas.
The actual amount to be paid cannot be quantified because the amount of gas that
will be produced from the wells cannot be predicted.
DEALER-MANAGER FEES
The dealer-manager will receive on each unit sold to an investor a 2.5%
dealer-manager fee, a 7% sales commission, a .5% reimbursement of marketing
expenses, and a .5% reimbursement of the selling agents' bona fide accountable
due diligence expenses. The dealer-manager will receive:
- $105,000 if $1,000,000 is received; and
- $1,890,000 if $18,000,000 is received.
All or a portion of the sales commissions, reimbursement of marketing expenses,
and reimbursement of the selling agents' bona fide accountable due diligence
expenses will be reallowed to the selling agents. The 2.5% dealer-manager fee
will be reallowed to the three wholesalers who are associated with Anthem
Securities for subscriptions obtained through the wholesalers' effort.
14
<PAGE>
OTHER COMPENSATION
The managing general partner or an affiliate will be reimbursed by the
partnership for any loan it 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 loan. If the managing general partner provides equipment, supplies and other
services to the partnership, then it may do so at competitive industry rates.
ESTIMATE OF ADMINISTRATIVE COSTS AND DIRECT COSTS TO BE BORNE BY THE PARTNERSHIP
The managing general partner and its affiliates will receive an unaccountable,
fixed payment reimbursement for their administrative costs which has been
determined by the managing general partner to be $75 per well per month. This
fee will be proportionately reduced to the extent the partnership acquires less
than 100% of the interest in the well, and will not be received for plugged and
abandoned wells. The managing general partner estimates that the unaccountable,
fixed payment reimbursement for administrative costs allocable to the
partnership's first 12 months of operation will not exceed approximately:
- $4,464 if $1,000,000 is received, which is 4.96 wells at $75 per
well per month, and
- $80,415 if $18,000,000 is received, which is 89.35 wells at $75 per
well per month.
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 12 months of operation may vary from the estimates shown for
numerous reasons which cannot accurately be predicted. These reasons include:
- the number of investors,
- 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.
<TABLE>
<CAPTION>
Minimum Maximum
Subscriptions Subscriptions
($1,000,000) ($18,000,000)
------------ -------------
<S> <C> <C>
DIRECT COSTS
External Legal....................................................... $ 6,000 $ 6,000
Accounting Fees...................................................... 2,500 6,000
Independent Engineering Reports...................................... 1,500 3,000
------- -------
TOTAL ............................................................... $10,000 $15,000
------- -------
------- -------
</TABLE>
TERMS OF THE OFFERING
SUBSCRIPTION TO THE PARTNERSHIP
The partnership will offer a minimum of 100 units and a maximum of 1,800 units.
Units in the partnership are offered at a subscription price of $10,000 per
unit. Your minimum subscription is one unit. However, the managing general
partner, in its discretion, may accept one-half unit ($5,000) subscriptions from
you at any time. Larger subscriptions will be accepted in $1,000 increments. You
must pay your subscription 100% in cash at the time of subscribing.
The managing general partner will have exclusive management authority for the
partnership. You will have the election to purchase units as either an investor
general partner or a limited partner.
15
<PAGE>
PARTNERSHIP CLOSINGS AND ESCROW
The offering period will begin on the date of this prospectus, and will end on
or before December 31, 1999, as determined by the managing general partner, in
its sole discretion. The offering period will not be extended beyond December
31, 1999. Subject to the receipt of the minimum subscriptions of $1,000,000, the
managing general partner may close the offering period on or before December 31,
1999. No subscriptions to the partnership will be accepted after the first to
occur:
- the receipt of the maximum subscriptions, or
- the close of the offering by the managing general partner.
If subscriptions for $1,000,000 are not received by December 31, 1999, then the
sums deposited in the escrow account will be promptly returned to you and the
other subscribers with interest and without deduction for any fees. Although the
managing general partner and its affiliates may buy up to 10% of the units, they
do not currently anticipate purchasing any units. If they do buy units those
units will not be applied towards the minimum subscriptions required for the
partnership to begin operations.
Subscription proceeds will be held in a separate interest bearing escrow account
at National City Bank of Pennsylvania until receipt of the minimum
subscriptions. Upon receipt of the minimum subscriptions, the partnership will
break escrow. The partnership will begin all activities, including drilling,
after breaking escrow, however, it is not anticipated there will be any gas
production before the offering closes. After breaking escrow the partnership
funds and additional subscription payments will be paid directly to the
partnership account and will continue to earn interest until the offering
closes.
You will receive interest on your subscription up until the date the offering
closes at the market rate paid by National City Bank of Pennsylvania. The
interest will be paid to you approximately eight weeks after the offering
closes.
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, in which there is appropriate safety of
principal, such as U.S. Treasury Bills. If the managing general partner
determines that the partnership may be deemed an investment company under the
Investment Company Act of 1940, then the investment activity will cease.
Subscriptions will not be commingled with the funds of the managing general
partner or its affiliates nor will subscriptions be subject to the claims of
their creditors.
ACCEPTANCE OF SUBSCRIPTIONS
Your execution of your subscription agreement constitutes your offer to buy
units and to hold the offer open until either:
- your subscription is accepted or rejected by the managing general
partner or
- you withdraw your offer.
If you elect to withdraw your offer before it is accepted by the managing
general partner, then you must provide written notice to the managing general
partner. Your subscription will be accepted or rejected by the partnership
within 30 days of its receipt. Acceptance of subscriptions is discretionary with
the managing general partner. The managing general partner may reject any
subscription for any reason it deems appropriate and will not incur any
liability to you for this decision. If your subscription is rejected, then all
funds will be promptly returned to you.
If your subscription is accepted before breaking escrow, then you will be
admitted to the partnership not later than 15 days after the release from escrow
of the investors' funds to the partnership. If your subscription is accepted
after breaking escrow, then you will be admitted to the partnership not later
than the last day of the calendar month in which your subscription was accepted
by the partnership.
16
<PAGE>
Your execution of the subscription agreement and the managing general partner's
acceptance also constitutes the execution of the partnership agreement and your
agreement to be bound by its terms as a partner. This includes your grant of a
special power of attorney to the managing general partner to file amended
certificates of limited partnership, governmental reports and certifications,
and other matters.
DRILLING PERIOD
Although it is anticipated that the partnership will spend the entire
subscription proceeds soon after the offering closes, the partnership will have
a 12-month period after the offering closes to use or commit funds to drilling
activities. If, within the 12-month period, the partnership has not used, or
committed for use, the net subscription proceeds, then the managing general
partner will cause the remainder of the net subscription proceeds to be
distributed pro rata to you and the other investors as a return of capital. The
managing general partner will also reimburse you and the other investors for
selling or other offering expenses allocable to the return of capital.
SUITABILITY STANDARDS
IN GENERAL. It is the obligation of persons selling the units to make every
reasonable effort to assure that the units are suitable for you. This
suitability determination will be based on your investment objectives and
financial situation, regardless of your income or net worth. Subscriptions will
not be accepted from IRAs, Keogh plans and qualified retirement plans because
the partnership's income would be unrelated business taxable income.
Additionally, the managing general partner will not accept your subscription
until it has reviewed your apparent qualifications. The decision to accept or
reject your subscription will be made by the managing general partner, in its
sole discretion, and is final. The managing general partner will maintain during
the term of the partnership and for at least six years thereafter a record of
your suitability.
Units will be sold to you only if you have:
- a minimum net worth of $225,000; or
- a minimum net worth of $60,000 and had during the last tax year or
estimate that you will have during the current tax year "taxable
income" as defined in Section 63 of the Internal Revenue Code of at
least $60,000 without regard to an investment in the partnership.
Net worth will be determined exclusive of home, home furnishings and
automobiles.
However, if you are a resident of the states set forth below, then additional
suitability requirements are applicable to you.
PURCHASERS OF LIMITED PARTNER UNITS. If you are a resident of California and you
purchase limited partner units, then you must:
- 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
- have a net worth of not less than $500,000, exclusive of home,
furnishings, and automobiles; or
- have a net worth of not less than $1,000,000; or
- expect to have gross income in the current tax year of not less than
$200,000.
If you are a resident of Michigan or North Carolina and you purchase limited
partner units, then you must:
- have a net worth of not less than $225,000, exclusive of home,
furnishings, and automobiles; or
17
<PAGE>
- have 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
$60,000 or more without regard to an investment in the partnership.
In addition, if you are a resident of Michigan, Ohio or Pennsylvania, then you
must not make an investment in the partnership in excess of 10% of your net
worth, exclusive of home, furnishings and automobiles.
PURCHASERS OF INVESTOR GENERAL PARTNER UNITS. If you are a resident of Alabama,
Maine, Massachusetts, Minnesota, North Carolina, Ohio, Pennsylvania, Tennessee
or Texas and you purchase investor general partner units, then you must:
- have an individual or joint net worth with your spouse of $225,000
or more, without regard to the investment in the partnership,
exclusive of home, furnishings, and automobiles, and a combined
gross income of $100,000 or more for the current year and for the
two previous years; or
- have an individual or joint net worth with your spouse in excess of
$1,000,000, inclusive of home, home furnishings and automobiles; or
- have an individual or joint net worth with your spouse in excess of
$500,000, exclusive of home, home furnishings, and automobiles; or
- have a combined "gross income" as defined in Internal Revenue Code
Section 61 in excess of $200,000 in the current year and the two
previous years.
If you are a resident of Arizona, Indiana, Iowa, Kansas, Kentucky, Michigan,
Mississippi, Missouri, New Hampshire, New Mexico, Oklahoma, Oregon, South
Dakota, Vermont or Washington and you purchase investor general partner units,
then you must:
- have an individual or joint net worth with your spouse of $225,000
or more, without regard to the investment in the partnership,
exclusive of home, furnishings, and automobiles, and a combined
"taxable income" of $60,000 or more for the previous year and expect
to have a combined "taxable income" of $60,000 or more for the
current year and for the succeeding year; or
- have an individual or joint net worth with your spouse in excess of
$1,000,000, inclusive of home, home furnishings and automobiles; or
- have an individual or joint net worth with your spouse in excess of
$500,000, exclusive of home, home furnishings, and automobiles; or
- have a combined "gross income" as defined in Internal Revenue Code
Section 61 in excess of $200,000 in the current year and the two
previous years.
In addition, if you are a resident of Michigan, Ohio or Pennsylvania, then you
must not make an investment in the partnership in excess of 10% of your net
worth, exclusive of home, furnishings and automobiles.
If you are a resident of California and you purchase investor general partner
units, then you must:
- 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 $120,000 or more; or
- have a net worth of not less than $500,000, exclusive of home,
furnishings, and automobiles; or
- have a net worth of not less than $1,000,000; or
- expect to have gross income in the current tax year of not less than
$200,000.
18
<PAGE>
MISCELLANEOUS. In the case of sales to fiduciary accounts, all the suitability
standards set forth above must be met by the beneficiary, the fiduciary account,
or by the donor or grantor who directly or indirectly supplies the funds to
purchase the units if the donor or grantor is the fiduciary. Generally, you are
required to execute your own subscription agreement. The managing general
partner will not accept any subscription agreement that has been executed by
someone other than you unless you have given someone else the legal power of
attorney to sign on your behalf and you meet all of the conditions in this
prospectus. The managing general partner may not complete a sale of units to you
until at least five business days after the date you receive a final prospectus.
In addition, the managing general partner will send you a confirmation of
purchase.
PRIOR ACTIVITIES
The following tables, other than Table 5, reflect certain historical data with
respect to 25 private drilling partnerships which raised a total of $75,690,936,
and 7 public drilling partnerships which raised a total of $48,985,595, which
the managing general partner has sponsored.
FOR SEVERAL REASONS, INCLUDING:
- - DIFFERENCES IN PARTNERSHIP TERMS,
- - PROPERTY LOCATIONS,
- - PARTNERSHIP SIZE, AND
- - ECONOMIC CONSIDERATIONS,
IT SHOULD NOT BE ASSUMED THAT YOU AND THE OTHER INVESTORS WILL EXPERIENCE
RETURNS, IF ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS IN THE PRIOR
DRILLING PARTNERSHIPS. THE RESULTS OF THE PRIOR DRILLING PARTNERSHIPS SHOULD BE
VIEWED ONLY AS A MEASURE OF THE LEVEL OF ACTIVITY AND EXPERIENCE OF THE MANAGING
GENERAL PARTNER WITH RESPECT TO DRILLING PARTNERSHIPS.
19
<PAGE>
Table 1 sets forth certain sales information of previous development drilling
partnerships sponsored by the managing general partner and its affiliates.
TABLE 1
-------
EXPERIENCE IN RAISING FUNDS
As of January 15, 1999
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------
Date of
Com- Years
mence- Date of Wells
Number Investor Atlas ment of First In
of Subscrip- Invest- Total Opera- Distri- Produc- Previous
Partnership Investors tions ment Capital tions butions tion Assessments
- ----------- --------- --------- -------- ------- -------- -------- ------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 19 $ 600,000 $ 114,800 $ 714,800 12/31/85 07/02/86 13.05 -0-
A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 12.05 -0-
A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 11.05 -0-
A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 10.05 -0-
A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 9.05 -0-
A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 8.05 -0-
A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 7.83 -0-
A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 7.00 -0-
A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 6.83 -0-
A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 6.75 -0-
A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 5.58 -0-
A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 6.08 -0-
A.E. Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 5.33 -0-
A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 5.00 -0-
A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 4.75 -0-
A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 4.50 -0-
A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 4.00 -0-
A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 3.75 -0-
A.E. Nineties-Public #3 391 5,799,750 928,546 6,728,296 12/31/94 06/05/95 3.75 -0-
A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96 2.92 -0-
A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 01/02/96 2.50 -0-
A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96 2.75 -0-
A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 2.08 -0-
A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97 1.75 -0-
A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 1.75 -0-
A.E. Nineties-17 217 8,813,488 1,133,917 9,947,405 08/29/97 12/12/97 1.17 -0-
A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98 0.75 -0-
A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98 0.58 -0-
A.E. Nineties-18 225 11,391,673 1,767,949 13,159,622 07/31/98 01/07/99 0.08 -0-
A.E. Partners 1998 26 1,740,000 495,360 2,235,360 12/31/98 1999 N/A -0-
A.E. Nineties-Public #7 366 11,988,350 3,852,439 15,840,789 12/31/98 1999 N/A -0-
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
20
<PAGE>
Table 2 reflects the drilling activity of previous development drilling
partnerships sponsored by the managing general partner and its affiliates. All
the wells were development wells. YOU SHOULD NOT ASSUME THAT THE PAST
PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE
PARTNERSHIP.
TABLE 2
-------
WELL STATISTICS - DEVELOPMENT WELLS
As of January 15, 1999
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------
Gross Wells(l) Net Wells(2)
------------------------------------ --------------------------------------
Partnership Oil Gas Dry (3) Oil Gas Dry (3)
- ----------- --- --- ------- --- --- -------
<S> <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 (4) 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 4.84 0.00
A.E. Nineties-Public #5 0 36 0 0 35.91 0.00
A.E. Nineties-17 (4) 0 52 2 0 38.00 1.50
A.E. Partners 1997 0 6 0 0 2.81 0.00
A.E. Nineties-Public #6 0 55 0 0 44.45 0.00
A.E. Nineties-18 0 63 0 0 58.00 0.00
A.E. Partners 1998 0 0 0 0 0.00 0.00
A.E. Nineties-Public #7 0 0 0 0 0.00 0.00
--- --- --- --- ------ ----
TOTALS 0 698 6 0 543.26 4.75
=== === === === ====== ====
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
(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) (i) Atlas L.P. #1-1985 had 1 gross well (.25 net well) which was completed
but non-commercial; (ii) A.E. Nineties-1993 Ltd. had 1 gross well (1 net
well) which was completed but non-commercial; (iii) A.E. Nineties-14 had 2
gross wells (2 net wells) which were completed but non-commercial; (iv)
A.E. Partners-1994 had 1 gross well (.25 net well) which was completed but
non-commercial; (v) A.E. Nineties-15 had 1 gross well (1 net well) which
was completed but non-commercial; (vi) A.E. Nineties-16 had 5 gross wells
(4.5 net wells) which were completed but non-commercial; and (vii) A.E.
Nineties-17 had 3 gross wells (2.5 net wells) which were completed but
non-commercial.
21
<PAGE>
Table 3 provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates. YOU SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIP.
TABLE 3
INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
As of January 15, 1999
<TABLE>
<CAPTION>
Cash
Total Costs -on-
----------------------------------- Cash Cash
Partnership Capitalization(1) Operating Admin. Direct Distributions(2) Return
- ----------- ------------ --------- ------ ------ ---------------- ------
<S> <C> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 $ 600,000 $ 144,544 $ 31,920 $ 6,970 $ 1,285,745 214%
A.E. Partners 1986 631,250 109,569 45,565 5,872 608,431 96%
A.E. Partners 1987 721,000 107,552 42,585 5,993 501,239 70%
A.E. Partners 1988 617,050 84,616 38,667 5,583 455,232 74%
A.E. Partners 1989 550,000 78,352 40,470 4,400 600,273 109%
A.E. Partners 1990 887,500 113,037 54,066 5,147 745,095 84%
A.E. Nineties-10 2,200,000 249,874 53,711 19,190 1,319,682 60%
A.E. Nineties-11 750,000 90,889 57,429 32,483 799,329 107%
A.E. Partners 1991 868,750 91,483 68,050 13,273 788,510 91%
A.E. Nineties-12 2,212,500 258,194 55,557 101,020 1,510,809 68%
A.E. Nineties-JV 92 4,004,813 374,866 81,348 189,235 2,795,173(3) 70%
A.E. Partners 1992 600,000 52,769 32,175 3,365 551,535 92%
A.E. Nineties-Public #1 2,988,960 209,757 51,075 73,688 1,610,199 54%
A.E. Nineties-1993 Ltd. 3,753,937 284,827 55,470 27,852 1,730,647 46%
A.E. Partners 1993 700,000 58,495 24,338 2,775 596,673 85%
A.E. Nineties-Public #2 3,323,920 212,199 41,141 32,698 1,384,411 42%
A.E. Nineties-14 9,940,045 620,693 120,685 16,921 3,720,641 37%
A.E. Partners 1994 892,500 41,261 23,811 2,153 528,576 59%
A.E. Nineties-Public #3 5,799,750 282,557 57,187 36,739 2,241,446 39%
A.E. Nineties-15 10,954,715 480,379 97,549 14,115 3,739,100 34%
A.E. Partners 1995 600,000 25,578 6,638 1,593 218,442 36%
A.E. Nineties-Public #4 6,991,350 291,345 54,593 26,981 1,674,416 24%
A.E. Nineties-16 10,955,465 336,521 55,978 28,057 2,148,028 20%
A.E. Partners 1996 800,000 26,295 6,264 38,648 144,665 18%
A.E. Nineties-Public #5 7,992,240 203,143 35,891 15,782 1,385,828 17%
A.E. Nineties-17 8,813,488 141,975 25,428 86,268 1,160,367 13%
A.E. Partners 1997 506,250 5,691 1,200 24,745 28,607 6%
A.E. Nineties-Public #6 9,901,025 115,537 16,211 8,189 770,940 8%
A.E. Nineties-18 11,391,673 8,227 2,004 329 92,193 1%
A.E. Partners 1998 1,740,000 0 0 0 0 0%
A.E. Nineties-Public #7 11,988,350 0 0 0 0 0%
Average Latest Quarterly
Yearly Cash Distribution
Return As of Date of Table
------ -------------------
<S> <C> <C>
Atlas L.P. #1-1985 16% $ 9,835
A.E. Partners 1986 8% 5,237
A.E. Partners 1987 6% 1,624
A.E. Partners 1988 7% 2,755
A.E. Partners 1989 12% 4,453
A.E. Partners 1990 10% 11,411
A.E. Nineties-10 8% 16,698
A.E. Nineties-11 15% 11,535
A.E. Partners 1991 13% 14,762
A.E. Nineties-12 10% 21,136
A.E. Nineties-JV 92 13% 86,999
A.E. Partners 1992 15% 9,212
A.E. Nineties-Public #1 10% 30,184
A.E. Nineties-1993 Ltd. 9% 26,063
A.E. Partners 1993 18% 15,268
A.E. Nineties-Public #2 9% 35,849
A.E. Nineties-14 9% 127,274
A.E. Partners 1994 16% 24,980
A.E. Nineties-Public #3 10% 76,218
A.E. Nineties-15 12% 133,663
A.E. Partners 1995 15% 6,221
A.E. Nineties-Public #4 9% 71,529
A.E. Nineties-16 9% 213,707
A.E. Partners 1996 10% 17,791
A.E. Nineties-Public #5 10% 142,054
A.E. Nineties-17 11% 226,498
A.E. Partners 1997 10% 12,455
A.E. Nineties-Public #6 10% 303,970
A.E. Nineties-18 10% 92,193
A.E. Partners 1998 0% 0
A.E. Nineties-Public #7 0% 0
</TABLE>
(1) There have been no partnership borrowings other than from the managing
general partner. The approximate principal amounts of such borrowings were
as follows: (i) A.E. Nineties-10 - $330,000; (ii) A.E. Nineties-11 -
$112,500; and (iii) A.E. Nineties-12 - $331,875. A portion of each
partnership's cash distributions was used to repay that partnership's
loan.
(2) All cash distributions were from the sale of gas, and not sales of
properties.
(3) A portion of the cash distributions was used to drill three reinvestment
wells at a cost of $333,860 in accordance with the terms of the offering.
22
<PAGE>
Table 3A provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates.
TABLE 3A
MANAGING GENERAL PARTNER
OPERATING RESULTS - INCLUDING EXPENSES
As of January 15, 1999
<TABLE>
<CAPTION>
Total Costs
------------------------------------ Cash
Partnership Capitalization Operating Admin. Direct Distributions(1)
- ----------- -------------- --------- ------ ------ ----------------
<S> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 $ 114,800 $ 27,532 $ 6,080 $ 1,328 $ 243,453
A.E. Partners 1986 120,400 20,870 8,679 1,118 116,220
A.E. Partners 1987 158,269 31,010 12,278 1,728 126,784
A.E. Partners 1988 135,450 27,251 12,453 1,798 112,347
A.E. Partners 1989 120,731 17,199 8,884 966 137,398
A.E. Partners 1990 244,622 37,679 0 0 287,214
A.E. Nineties-10 484,380 83,291 0 0 464,194
A.E. Nineties-11 268,003 38,953 24,612 8,863 335,844
A.E. Partners 1991 318,063 30,494 0 0 343,792
A.E. Nineties-12 791,833 110,655 23,810 17,787 647,489
A.E. Nineties-JV 92 1,414,917 184,635 40,067 11,666 794,372
A.E. Partners 1992 176,100 17,590 0 0 264,445
A.E. Nineties-Public #1 528,934 66,239 16,129 11,463 440,664
A.E. Nineties-1993 Ltd. 1,264,183 122,069 23,773 8,354 317,836
A.E. Partners 1993 219,600 19,498 0 0 220,394
A.E. Nineties-Public #2 587,340 67,010 12,992 10,326 272,151
A.E. Nineties-14 3,584,027 305,714 59,442 8,334 1,113,680
A.E. Partners 1994 231,500 13,754 0 0 185,492
A.E. Nineties-Public #3 928,546 94,186 19,062 12,246 747,149
A.E. Nineties-15 3,435,936 205,877 41,807 6,049 1,602,370
A.E. Partners 1995 244,725 8,526 0 0 61,438
A.E. Nineties-Public #4 1,287,752 97,115 18,198 8,994 492,165
A.E. Nineties-16 1,643,320 92,168 15,332 2,879 422,624
A.E. Partners 1996 367,416 8,765 0 0 63,192
A.E. Nineties-Public #5 1,654,740 67,714 11,964 5,261 439,660
A.E. Nineties-17 1,133,917 51,188 9,168 1,759 447,708
A.E. Partners 1997 231,050 1,897 0 0 18,184
A.E. Nineties-Public #6 1,950,345 38,512 5,404 2,730 256,980
A.E. Nineties-18 1,767,949 3,783 921 151 42,395
A.E. Partners 1998 495,360 0 0 0 0
A.E. Nineties-Public #7 3,852,439 0 0 0 0
Cash
-on- Latest Quarterly
Cash Cash Distribution
Return As of Date of Table
------ -------------------
<S> <C> <C>
Atlas L.P. #1-1985 212% $ 1,873
A.E. Partners 1986 97% 998
A.E. Partners 1987 80% 468
A.E. Partners 1988 83% 887
A.E. Partners 1989 114% 977
A.E. Partners 1990 117% 4,404
A.E. Nineties-10 96% 6,116
A.E. Nineties-11 125% 4,943
A.E. Partners 1991 108% 5,771
A.E. Nineties-12 82% 9,058
A.E. Nineties-JV 92 56% 0
A.E. Partners 1992 150% 3,521
A.E. Nineties-Public #1 83% 9,532
A.E. Nineties-1993 Ltd. 25% 0
A.E. Partners 1993 100% 5,389
A.E. Nineties-Public #2 46% 11,321
A.E. Nineties-14 31% 1,938
A.E. Partners 1994 80% 8,795
A.E. Nineties-Public #3 80% 25,406
A.E. Nineties-15 47% 57,284
A.E. Partners 1995 25% 2,299
A.E. Nineties-Public #4 38% 12,623
A.E. Nineties-16 26% (45,489)
A.E. Partners 1996 17% 6,241
A.E. Nineties-Public #5 27% 25,068
A.E. Nineties-17 39% 81,663
A.E. Partners 1997 8% 7,665
A.E. Nineties-Public #6 13% 174,574
A.E. Nineties-18 2% 42,395
A.E. Partners 1998 0% 0
A.E. Nineties-Public #7 0% 0
</TABLE>
(1) All cash distributions were from the sale of gas and not sales of
properties.
23
<PAGE>
Table 4 sets forth the aggregate cash distributions and estimated federal tax
savings to investors in the managing general partner's prior development
drilling partnerships, based on the maximum marginal tax rate in each year, as
reported in the partnerships' tax returns and such share of tax deductions as a
percentage of their subscriptions. YOU ARE URGED TO CONSULT WITH YOUR OWN TAX
ADVISORS CONCERNING YOUR SPECIFIC TAX SITUATION AND SHOULD NOT ASSUME THAT THE
PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF
THE PARTNERSHIP.
TABLE 4
SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
As of January 15, 1999
<TABLE>
<CAPTION>
Estimated Federal Tax Savings From(1):
--------------------------------------
1st Year Eff. 1st Year
Investor Tax Tax I.D.C. Depletion Section 29
Partnership Capital Deduct(2) Rate Deduct(3) Allowance(3) Depreciation(3) Tax Credit(4)
- ----------- -------- --------- ---- --------- ------------ -------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 $ 600,000 99.0% 50.0% $ 298,337 $109,251 N/A $55,915
A.E. Partners 1986 631,250 99.0% 50.0% 312,889 58,666 N/A 13,507
A.E. Partners 1987 721,000 99.0% 38.5% 356,895 43,088 N/A N/A
A.E. Partners 1988 617,050 99.0% 33.0% 244,351 38,870 N/A N/A
A.E. Partners 1989 550,000 99.0% 33.0% 179,685 54,468 N/A N/A
A.E. Partners 1990 887,500 99.0% 33.0% 275,125 69,725 N/A 204,974
A.E. Nineties-10 2,200,000 100.0% 33.0% 726,000 127,070 N/A 377,382
A.E. Nineties-11 750,000 100.0% 31.0% 232,500 73,616 N/A 242,570
A.E. Partners 1991 868,750 100.0% 31.0% 269,313 80,940 N/A 227,733
A.E. Nineties-12 2,212,500 100.0% 31.0% 685,875 152,236 N/A 451,939
A.E. Nineties-JV 92 4,004,813 92.5% 31.0% 1,322,905 243,071 N/A 658,181
A.E. Partners 1992 600,000 100.0% 31.0% 186,000 61,099 N/A 169,353
A.E. Nineties-Public #1 2,988,960 80.5% 36.0% 877,511 156,090 211,416 N/A
A.E. Nineties-1993 Ltd. 3,753,937 92.5% 39.6% 1,378,377 159,360 N/A N/A
A.E. Partners 1993 700,000 100.0% 39.6% 273,216 58,280 N/A N/A
A.E. Nineties-Public #2 3,323,920 78.7% 39.6% 1,036,343 120,785 222,534 N/A
A.E. Nineties-14 9,940,045 95.0% 39.6% 3,739,445 319,177 N/A N/A
A.E. Partners 1994 892,500 100.0% 39.6% 353,430 44,117 N/A N/A
A.E. Nineties-Public #3 5,799,750 76.2% 39.6% 1,752,761 199,611 371,833 N/A
A.E. Nineties-15 10,954,715 90.0% 39.6% 3,904,261 340,946 N/A N/A
A.E. Partners 1995 600,000 100.0% 39.6% 237,600 13,393 N/A N/A
A.E. Nineties-Public #4 6,991,350 80.0% 39.6% 2,214,860 139,953 372,541 N/A
A.E. Nineties-16 10,955,465 86.8% 39.6% 3,361,289 168,993 492,710 N/A
A.E. Partners 1996 800,000 100.0% 39.6% 316,800 14,610 N/A N/A
A.E. Nineties-Public #5 7,992,240 84.9% 39.6% 2,530,954 111,196 185,032 N/A
A.E. Nineties-17 8,813,488 85.2% 39.6% 2,966,366 98,161 169,029 N/A
A.E. Partners 1997 506,250 100.0% 39.6% 200,475 4,194 N/A N/A
A.E. Nineties-Public #6 9,901,025 85.1% 39.6% 3,166,406 61,261 108,333 N/A
A.E. Nineties-18 11,391,673 90.0% 39.6% 4,030,884 7,084 10,417 N/A
A.E. Partners 1998 1,740,000 100.0% 39.6% 689,040 0 N/A N/A
A.E. Nineties-Public #7 11,988,350 85.0% 39.6% 4,043,670 0 0 N/A
Cumulative
Cash Percent of
Distribution Total Cash Cash Dist.
As of Dist. and and Tax
Date of Tax Savings Savings to
Partnership ( Total Table(5) Savings Date
- ----------- -------- -------- ------- ----
<S> <C> <C> <C> <C>
Atlas L.P. #1-1985 $ 463,503 $1,285,745 $1,749,248 292%
A.E. Partners 1986 385,062 608,431 993,493 157%
A.E. Partners 1987 399,983 501,239 901,222 125%
A.E. Partners 1988 283,221 455,232 738,453 120%
A.E. Partners 1989 234,153 600,273 834,426 152%
A.E. Partners 1990 549,824 745,095 1,294,919 146%
A.E. Nineties-10 1,230,452 1,319,682 2,550,134 116%
A.E. Nineties-11 548,686 799,329 1,348,015 180%
A.E. Partners 1991 577,986 788,510 1,366,496 157%
A.E. Nineties-12 1,290,050 1,510,809 2,800,859 127%
A.E. Nineties-JV 92 2,224,157 2,795,173 5,019,330 125%
A.E. Partners 1992 416,452 551,535 967,987 161%
A.E. Nineties-Public #1 1,245,017 1,610,199 2,855,216 96%
A.E. Nineties-1993 Ltd. 1,537,737 1,730,647 3,268,384 87%
A.E. Partners 1993 331,496 596,673 928,169 133%
A.E. Nineties-Public #2 1,379,662 1,384,411 2,764,073 83%
A.E. Nineties-14 4,058,622 3,720,641 7,779,263 78%
A.E. Partners 1994 397,547 528,576 926,123 104%
A.E. Nineties-Public #3 2,324,205 2,241,446 4,565,651 79%
A.E. Nineties-15 4,245,207 3,739,100 7,984,307 73%
A.E. Partners 1995 250,993 218,442 469,435 78%
A.E. Nineties-Public #4 2,727,354 1,674,416 4,401,770 63%
A.E. Nineties-16 4,022,992 2,148,028 6,171,020 56%
A.E. Partners 1996 331,410 144,665 476,075 60%
A.E. Nineties-Public #5 2,827,182 1,385,828 4,213,010 53%
A.E. Nineties-17 3,233,556 1,160,367 4,393,923 50%
A.E. Partners 1997 204,669 28,607 233,276 46%
A.E. Nineties-Public #6 3,336,000 770,940 4,106,940 41%
A.E. Nineties-18 4,048,385 92,193 4,140,578 36%
A.E. Partners 1998 689,040 0 689,040 40%
A.E. Nineties-Public #7 4,043,670 0 4,043,670 34%
</TABLE>
(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 85% of an investor general partner's
subscription to the partnership will be deductible in 1999.
(3) The I.D.C. Deductions, Depletion Allowance and MACRS depreciation
deductions have been reduced to credit equivalents.
(4) The Section 29 tax credit is not available with respect to wells drilled
after December 31, 1992. N/A means not applicable.
(5) These distributions were all from production revenues. See footnotes 1 and
3 of Table 3.
24
<PAGE>
Table 5 sets forth partnerships in which the managing general partner and its
affiliates served as operator and/or drilling contractor for third party general
partners as well as the partnerships in which Atlas served as managing general
partner. The table includes the managing general partner's share of costs and
revenues set forth in Table 3A, above. The managing general partner and its
affiliates have drilled more than 1,650 wells over the 27-year period from 1972
to 1999. In the current primary area of interest in Mercer County the managing
general partner and its affiliates have completed 97% of approximately 810 wells
drilled. These results are summarized below.
TABLE 5
ATLAS RESOURCES, INC. AND ITS AFFILIATES' HISTORICAL PRODUCTION RECORD
As of January 15, 1999 (4)
<TABLE>
<CAPTION>
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(l) Produced Wells(2) Returned(2) Cash-On-Cash(3) Date of Table
- --------------- ---------- ----------- ------------- ------------- --------------- -------------
<S> <C> <C> <C> <C> <C> <C>
1973 6 2,509,236 $ 576,000 $ 4,015,217 697% $ 17,511
1974 18 2,946,593 2,387,200 3,912,076 164% 14,114
1975 21 4,216,675 2,814,200 6,646,801 236% 23,861
1976 14 2,886,085 1,819,200 4,371,213 240% 10,801
1977 26 9,249,096 3,912,600 16,290,635 416% 68,048
1978 78 7,908,916 12,399,900 19,089,393 154% 63,033
1979 46 9,254,567 7,404,000 19,743,042 267% 73,953
1980 41 5,784,913 6,561,100 13,659,970 208% 49,642
1981 77 6,393,648 15,382,850 17,131,621 111% 34,003
1982 63 2,483,831 12,438,500 5,795,400 47% 7,885
1983 22 1,296,607 6,725,480 3,036,981 45% 19,580
1984 47 4,709,058 10,663,250 10,323,461 97% 54,893
1985 39 4,913,152 8,971,200 10,264,820 114% 60,477
1986 45 5,632,560 9,649,100 10,735,876 111% 70,547
1987 12 1,559,947 2,425,800 2,713,796 112% 11,405
1988 37 3,865,839 7,688,386 6,926,354 90% 42,001
1989 48 3,969,740 9,967,768 7,005,989 70% 59,191
1990 46 5,051,865 9,038,238 9,111,581 101% 58,587
1991 79 8,590,676 16,034,382 15,741,230 98% 188,043
1992 64 8,015,782 14,250,032 14,383,556 101% 184,915
1993 107 10,318,207 21,958,681 17,077,751 78% 127,435
1994 94 6,432,284 20,418,366 10,413,865 51% 266,316
1995 105 6,466,579 22,350,889 10,936,284 49% 365,915
1996 114 4,744,470 25,396,708 8,092,130 32% 380,867
1997 102 2,785,785 20,678,334 4,886,603 24% 701,383
1998 111 1,160,369 23,270,358 1,921,602 8% 803,657
---------- ----------- ------------- ------------- --------------- -------------
TOTAL 1,462 133,146,480 $295,182,522 $254,227,247 86% $3,758,065
---------- ----------- ------------- ------------- --------------- -------------
---------- ----------- ------------- ------------- --------------- -------------
</TABLE>
(1) The above numbers do not include information for: (i) 87 wells drilled for
General Motors from 1971 to 1973 which were subsequently purchased by
General Motors; (ii) 25 wells successfully drilled in 1981 and 1982 for an
industrial customer which requested that the wells be capped and not
placed into production; (iii) 127 wells drilled from 1980 to 1985 which
were sold in 1993 and are no longer operated by the managing general
partner; and (iv) wells which were drilled recently but are not yet in
production.
(2) (i) The column "Total Amount Invested in Wells" only includes funds paid
to the managing general partner or its affiliates 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 the managing general partner or
its affiliates. (ii) Similarly, the column "Total Amount Returned" only
includes amounts paid by the managing general partner or its affiliates 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 the managing general partner or its affiliates.
Notwithstanding, the columns "Total Amount Invested in Wells" and "Total
Amount Returned" also include the partnerships in which 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 THE MANAGING GENERAL PARTNER WITH RESPECT TO
DEVELOPMENT DRILLING PARTNERSHIPS.
25
<PAGE>
MANAGEMENT
MANAGING GENERAL PARTNER AND OPERATOR
The managing general partner, Atlas, a Pennsylvania corporation, was
incorporated in 1979, and its affiliate, Atlas Energy, an Ohio corporation, was
incorporated in 1973. As of December 31, 1998, the managing general partner and
its affiliates operated approximately 1,242 oil or natural gas wells located in
Ohio and Pennsylvania. The managing general partner and its affiliates have
acted as operator with respect to the drilling of a total of approximately 1,685
gas wells, approximately 1,624 of which were capable of production in commercial
quantities. The managing general partner and certain of its affiliates' primary
offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108, near
the Pittsburgh International Airport.
The managing general partner has previously sponsored 7 public and 25 private
partnerships formed since 1985 to conduct natural gas drilling and development
activities in Pennsylvania and Ohio. In addition, as operator, the managing
general partner acted as general contractor with respect to the drilling and
completion of the partnerships' natural gas wells located in Pennsylvania and is
responsible for operating these wells. An affiliate acted in the same capacity
as operator of the partnerships' wells located in Ohio.
RECENT MERGER OF MANAGING GENERAL PARTNER'S PARENT COMPANY, ATLAS GROUP
On September 29, 1998, Atlas Group, the former parent company of the managing
general partner, merged into Atlas America, Inc., a newly formed wholly-owned
subsidiary of Resource America, Inc. The merger was completed under an agreement
and plan of merger dated July 13, 1998, and amended on September 29, 1998, by
and among Resource America, Atlas America, Atlas Group and certain shareholders
of Atlas Group. Resource America is a publicly-traded company principally
engaged in real estate finance, equipment leasing and energy and energy finance.
Atlas America is continuing the existing business of Atlas Group and is
headquartered in the Pittsburgh offices. As of October 1, 1999, the Board of
Directors for Atlas America includes the following:
<TABLE>
<CAPTION>
NAME AGE POSITION OR OFFICE
- ------------------ --- -------------------------------
<S> <C> <C>
Edward E. Cohen 60 Chairman of the Board
James R. O'Mara 56 Vice Chairman
Tony C. Banks 45 President, Chief Executive Officer, and a Director
Michael L. Staines 50 Secretary and a Director
Jonathan Cohen 29 Director
John S. White 57 Director
JoAnn Bagnell 70 Director
Charles T. Koval 65 Director
</TABLE>
See " - Officers, Directors and Key Personnel," below, for biographical
information on certain of these individuals who are also officers and/or
directors of the managing general partner. Biographic information on the other
directors will be provided by the managing general partner upon request. Also,
there may be changes in the future in the directors and executive officers of
the managing general partner. Additionally, it is anticipated that current
Resource America, Atlas America or Resource Energy staff and directors of
Resource America will assume a variety of new operating responsibilities in
Atlas America. Although Resource Energy will maintain its separate corporate
existence, Atlas America will manage the employees and assets of Resource Energy
including sharing common employees.
The managing general partner and its affiliates under Atlas America employ a
total of approximately ninety-nine persons, consisting of three geologists, 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 America has been a leading participant in the energy finance industry for
more than 26 years, providing drilling, operating and supervisory services for
more than $380 million of independent investment now under Atlas America's
management.
26
<PAGE>
Atlas America and its affiliates manage more than 85 partnerships and joint
ventures, operates and holds interests in more than 2,500 wells and holds
mineral rights underlying more than 406,000 acres of land.
ORGANIZATIONAL DIAGRAM (1)(2)
This organizational diagram does not include all of the
subsidiaries of Resource America.
Resource America, Inc.
Atlas America, Inc.
AIC, Inc.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C>
Atlas Mercer Gas Pennsylvania Atlas Energy Transatco, Atlas Anthem Atlas Energy
Resources, Gathering, Industrial Corporation Inc., which Information Securities Group, Inc.
Inc., managing Inc., gas Energy, managing owns 50% of Management, Inc. driller and
general gathering Inc., general Topico, L.L.C., registered operator in
partner, company "PIE", partner of operates markets broker-dealer Ohio
driller and sells gas exploratory pipeline in information and
operator in to drilling Ohio and dealer-manager
Pennsylvania Pennsylvania partnerships technology
industry and driller services
and operator
ARD AED
Investments, Investments,
Inc. Inc.
</TABLE>
(1) Resource Energy, a subsidiary of Resource America, Inc., is also engaged
in the oil and gas business.
(2) Atlas Pipeline Partners LP is a limited partnership formed to acquire
gathering lines owned by Resource America and Atlas America. It is
anticipated that this entity will gather and deliver natural gas produced
by the partnership.
OFFICERS, DIRECTORS AND KEY PERSONNEL
The officers and directors of the managing general partner will serve until
their successors are elected. The officers, directors and key personnel of the
managing general partner are as follows:
<TABLE>
<CAPTION>
NAME AGE POSITION OR OFFICE
- ---- --- ------------------
<S> <C> <C>
Charles T. Koval 65 Chairman of the Board and a Director
James R. O'Mara 56 President, Chief Executive Officer and a Director
Tony C. Banks 45 Senior Vice President of Finance, Chief Financial Officer, and a
Director
Frank P. Carolas 40 Vice President of Land and Geology
Jeffrey C. Simmons 41 Vice President of Production
William R. Seiler 44 Vice President and Controller
Barbara J. Krasnicki 54 Secretary
Eric D. Koval 34 President of Anthem Securities, Inc.
</TABLE>
CHARLES T. KOVAL. Chairman of the Board and a Director. Mr. Koval is also a
director of Atlas America. 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. Before 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. Effective
October 1, 1999, Mr. O'Mara will serve as vice chairman of the managing general
partner and Atlas America and resign as president and chief executive officer.
Mr. O'Mara served with the United States Army Security Agency (ASA) and is a
Vietnam veteran. Mr. O'Mara is a Certified Public
27
<PAGE>
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 received a Bachelor of Science Degree in
Accounting from Gannon University in 1968.
TONY C. BANKS. Senior Vice President, Chief Financial Officer, and a
Director. Effective October 1, 1999, Mr. Banks will serve as President and
Chief Executive Officer of the managing general partner and Atlas America and
resign as Senior Vice President of Finance and Chief Financial Officer. Mr.
Banks has over 20 years of finance, accounting and administrative experience
in the oil and gas industry, all with various subsidiaries of Consolidated
Natural Gas Company. 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.
FRANK P. CAROLAS. Vice President of Land and Geology. Mr. Carolas is also
Vice President of Land and Geology of Atlas America. 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.
JEFFREY C. SIMMONS. Vice President of Production. Mr. Simmons is also Vice
President-Production of Atlas America. Mr. Simmons joined Resource America in
1986 as senior petroleum engineer. From 1988 through 1994 he served as director
of production and as president of Resource Well Services, Inc., a subsidiary of
Resource America. He was then promoted to vice president of Resource Energy, the
energy subsidiary of Resource America formed in 1993. In 1997 he was promoted to
executive vice president, chief operating officer and director of Resource
Energy, a position he currently holds. Before Mr. Simmons' career with Resource
America, he had worked with Core Laboratories, Inc., of Dallas, Texas, and PNC
Bank of Pittsburgh. Mr. Simmons received his Petroleum Engineering degree from
Marietta College and his Masters Degree in Business Administration from Ashland
University.
WILLIAM R. SEILER. Vice President and Controller. Effective October 1, 1999, Mr.
Seiler will serve as chief financial officer of the managing general partner and
Atlas America. Mr. Seiler has over 25 years of accounting, financial reporting,
financial analysis, and mergers and acquisitions experience in the oil and gas
industry with Consolidated Natural Gas Company before joining Atlas America and
the managing general partner in July of 1999. Mr. Seiler joined CNG's corporate
headquarters in 1974 as an accounting clerk and progressed to the final position
as an officer of CNG as corporate assistant controller. Additional assignments
with CNG's included corporate strategic financial planning department, manager
of strategic financial planning, corporate-wide financial and accounting
planning committee, and chaired the accounting research and financial
forecasting committees. Mr. Seiler also served on the American Gas Association's
statistics and load forecasting committee and was a member of the Bradford
School Accounting Advisory Board. Mr. Seiler earned a Bachelor of Science degree
in Accounting from Point Park College in Pittsburgh and holds a Masters Degree
in Business Administration from Duquesne University. He is also member of the
Beta Gamma Sigma Honor Society.
BARBARA J. KRASNICKI. Secretary. Ms. Krasnicki has been with Atlas America and
its predecessors since their inception in 1971. She was the office and personnel
manager. She was elected secretary of the managing general partner in August,
1999. Ms. Krasnicki has an Associate in Science Degree from Point Park College,
Pittsburgh, Pennsylvania.
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, 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.
28
<PAGE>
The officers and directors of AIC, Inc., which owns 100% of the common stock of
the managing general partner, are Tony C. Banks and Norman J. Shuman. The
biography of Mr. Banks is set forth above.
REMUNERATION
No officer or director of the managing general partner will receive any direct
remuneration or other compensation from the partnership. These persons will
receive compensation solely from the managing general partner and its affiliated
companies.
The aggregate remuneration paid during the year ended September 30, 1998, to the
five most highly compensated persons who are executive officers of the managing
general partner and whose aggregate remuneration exceeded $100,000 and to all
executive officers of the managing general partner as a group, for services in
all capacities while acting as executive officers of the managing general
partner and its affiliates, was as follows:
<TABLE>
<CAPTION>
(A) (B) (C) (D) (E)
NAME OF INDIVIDUAL OR CAPACITIES IN WHICH CASH COMPENSATION AGGREGATE OF
NUMBER OF PERSONS IN SERVED (4) COMPENSATION (1) PURSUANT TO CONTINGENT FORMS OF
GROUP (3) PLANS (2) REMUNERATION
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
James R. O'Mara President, Chief Executive $ 322,226 $ 5,000 --
Officer and a Director
Charles T. Koval Chairman of the Board and $ 306,468 $ 5,000 --
a Director
Tony C. Banks Senior Vice President, $ 144,280 $26,041 --
Chief Financial Officer,
and a Director
Frank P. Carolas Vice President of Land and $ 101,752 $22,521 --
Geology
Jeffrey C. Simmons Vice President of $ 92,442 $ 7,285 --
Operations
Executive Officers as a Group $1,032,172 $81,915 --
(6 persons)
- ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) The amounts indicated were composed of salaries and all cash bonuses for
services rendered to the managing general partner and its affiliates,
including compensation that would have been paid in cash but was deferred.
(2) Atlas Group and its affiliates had an Employee Stock Ownership Plan for
the benefit of its employees, other than Messrs. Koval and Joseph R.
Sadowski, a retired founder, to which it contributed annually
approximately 6% of annual compensation in the form of shares of Atlas
Group, and a 401(K) plan which allowed employees to contribute the lesser
of 15% of their compensation or $10,000 for the calendar year 1998 or
$10,000 for the calendar year 1997. Atlas Energy contributed an amount
equal to 50% of each employee's contribution for the calendar years 1998
and 1997.
(3) In addition, to the compensation set forth in (C) and (D) in connection
with the merger, Mr. O'Mara exercised Atlas Group stock options resulting
in $1,503,508 and Mr. Bruce Wolf, a retired director, exercised Atlas
Group stock options resulting in $994,916. Also, under the terms of the
merger, the following stock options in Resource America were issued at an
option price of $0.1069 per share:
<TABLE>
<CAPTION>
NAME STOCK OPTION
---------------- --------------
<S> <C>
Tony C. Banks 13,106
</TABLE>
(4) Each director was paid a director's fee of $9,000 for the year. There were
no other arrangements for remuneration of directors.
29
<PAGE>
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Resource America owns 100% of the common stock of Atlas America, which owns 100%
of the common stock of AIC, Inc., which owns 100% of the common stock of the
managing general partner.
TRANSACTIONS WITH MANAGEMENT AND AFFILIATES
Pursuant to the merger of Atlas Group into Atlas America, the merger
consideration paid to the shareholders of Atlas Group was 2,063,486 shares of
Resource America's common stock and in addition options of 120,213, which were
valued at $29,534,000 as of the date the definitive merger agreement was entered
into, cash of $7,814,000 and the assumption of Atlas Group debt of $45,968,000.
The exchange value of Resource America stock was based on a trading index using
prices before the merger and did not reflect the trading price of the stock on
the merger date. Atlas Group shareholders received certain "piggy-back"
registration rights, effective during the period from September 30, 1999 through
September 29, 2000, with respect to the shares of Resource America's common
stock received by them. Atlas Group shareholders are also eligible to receive
incentive compensation should Atlas Group's post-acquisition earnings exceed a
specified amount during the four years following the merger. The incentive
compensation is equal to 10% of Atlas Group's aggregate earnings in excess of
that amount equal to an annual, but uncompounded, return of 15% on $63 million
which is increased to include any amount paid by Resource America for any
post-merger energy acquisitions. Incentive compensation is payable, at Resource
America's option, in cash or in shares of Resource America's common stock,
valued at the average closing price of Resource America's common stock for the
10 trading days before September 30, 2003.
In addition, in November, 1990, Atlas Group and its shareholders had entered
into agreements with Messrs. Sadowski and Koval to gradually liquidate a
majority of their stock ownership in Atlas Group. The stock redemptions required
Atlas Group to execute promissory notes, from time to time, in favor of Messrs.
Koval and Sadowski. The first promissory notes had a principal amount of
$4,974,340 each, plus interest at 13.5%. Under the merger, Atlas Group
accelerated the promissory notes issued in the redemption, together with notes
issued in a prior redemption of shares owned by Messrs. Koval and Sadowski, and
these notes were paid in full at the time of closing of the merger.
Also, the managing general partner and its officers, directors and affiliates
have in the past invested, and may in the future invest, as investors in
partnerships sponsored by the managing general partner on the same terms as
unrelated investors. The managing general partner, its officers, directors, and
affiliates may also subscribe for units in the partnership.
PROPOSED ACTIVITIES
INTENDED AREAS OF OPERATIONS
The subscription proceeds will be used to drill development wells which are
located primarily in the Mercer County area of Pennsylvania. A 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. The managing general
partner may also use up to 20% of the subscription proceeds to drill development
wells in other areas of the United States primarily in the Appalachian Basin.
The managing general partner anticipates that all the partnership's wells will
be classified as gas wells which may produce a small amount of oil.
The number of development wells drilled by the partnership will depend on the
amount of subscription proceeds received and the partnership's aggregate
percentage of the interest in the wells. Assuming the partnership acquires 100%
of the interest in the wells and all wells are situated in the Mercer County
area, the partnership would participate in drilling approximately :
- 4.96 wells if the minimum partnership subscription of $1,000,000 is
received; and
- 89.35 wells if the maximum partnership subscription of $18,000,000
is received.
The actual amount of the interest in each well drilled by the partnership and
the number of wells drilled by the partnership may vary from these estimates.
The development wells drilled by the partnership 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.
30
<PAGE>
Wells 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, and
- will not be drilled closer than approximately 1,650 feet to each
other, which is greater than the 660 feet minimum area permitted by
state law or local practice to protect against drainage from
adjacent wells.
Wells located in Ohio and drilled to the Clinton/Medina geological formation:
- will consist of approximately 40 acres, subject to adjustment to
take into account lease boundaries, and
- will not be drilled closer than approximately 1,100 feet to each
other.
The lease assignments to the partnership will be limited to a depth of from the
surface to the top of the Queenston geological formation, and the managing
general partner will retain the drilling rights below the Clinton/Medina
geological feature. The partnership will not acquire the deeper drilling rights
because its objective is to conduct development drilling which would not be the
case with formations deeper than the Clinton/Medina geological feature. The
managing general partner, however, believes that the partnership's drilling to
the Clinton/Medina geological formation will not provide any geological
information that would assist in evaluating drilling to formations deeper than
the Clinton/Medina geological formation. Also, the amount of the credit the
managing general partner receives for the partnership leases does not include
any value allocable to the deeper drilling rights retained by it. If in the
future geophysical activity is undertaken by the managing general partner on the
formations below the Clinton/Medina geological feature and provides a basis for
the managing general partner drilling an exploratory well, the partnership would
not share in the profits, if any, from these activities.
The Clinton/Medina geological formation is a blanket sandstone found throughout
most of the northwestern edge of the Appalachian Basin. The Clinton/Medina is
described in petroleum industry terms as a "tight" sandstone with porosity
ranging from 6% to 12% and with very low permeability. 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, 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 managing general partner's experience, it is anticipated
that all 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 according to the model decline
curve included in the geologic evaluation prepared by United Energy Development
Consultants, Inc., an independent geological and engineering firm. The geologic
evaluation discusses the development of the Clinton/Medina geological formation
in the primary area where the partnership will conduct its activity.
Before selecting a well to be drilled by the partnership, the managing general
partner will review all available geologic data for wells located in the
vicinity of the proposed well including:
- logs,
- completion reports, and
- plugging reports.
31
<PAGE>
It has been the managing general partner's 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.
ACQUISITION OF LEASES
The managing general partner will have the right, in its sole discretion, to
select the wells which the partnership will drill. Currently, the Managing
General Partner has proposed approximately 66% of the wells to be drilled if all
the units are sold. The leases covering the acreage on which each well will be
drilled 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. It is anticipated that the leases will be transferred to the
partnership, but not immediately recorded, when the minimum subscriptions are
released from escrow subject to the managing general partner's right of
substitution of the wells depending upon various considerations.
It is anticipated that any additional and/or substituted wells will be selected
by the managing general partner primarily from leases included in its and its
affiliates existing leasehold inventory. To a lesser extent, the managing
general partner would select well locations from leases hereafter acquired by it
or its affiliates or from leases owned by independent third parties. Most of the
partnership's wells will be located in areas where the managing general partner
or its affiliates have previously conducted drilling operations and will meet
the same general criteria for drilling potential as the currently proposed
wells.
As of the date of this prospectus, the managing general partner and its
affiliates owned approximately:
- 70,241 net and gross acres of undeveloped leasehold acreage in
Pennsylvania and Ohio;
- 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.
The managing general partner and its affiliates are continually engaged in
acquiring additional leasehold acreage in Pennsylvania and other areas of the
United States. The managing general partner believes that its and its
affiliates' leasehold inventory will be sufficient to provide all the wells to
be drilled by the partnership.
Because the managing general partner will assign to the partnership only the
number of wells which it believes are necessary for the drilling operations of
the partnership, the partnership will not farmout any drilled acreage.
Generally, a farmout is an agreement where owner of the leasehold interest
agrees to assign his interest in certain specific acreage to the assignees,
retaining some interest such as an overriding royalty interest, subject to the
drilling of one or more specific wells as a condition of the assignment.
INTERESTS OF PARTIES
Generally, production and revenues from a well drilled in the Mercer County area
will be net of the applicable landowner's royalty interest which is typically
1/8th (12.5%) of gross production, and any third-party overriding royalty
interests. Landowner's royalty interest generally means an interest in oil and
gas production free and clear of all costs of development, operation, or
maintenance of the well, by the landowner when an oil and gas lease is created.
Overriding royalty interest generally means an interest of someone other than
the landowner in the oil and gas production pursuant to a lease free and clear
of all costs of development, operation, or maintenance of the well. It is
anticipated that the partnership will have an 87.5% net revenue interest in each
lease, although the partnership could have a lesser net revenue interest,
typically 84.375%, if there were third-party overriding royalty interests. Net
revenue interest generally means the percentage of revenues the owner of an
interest in a well is entitled to receive under the lease. Neither the managing
general partner nor its affiliates will receive any royalty or overriding
royalty interest on any well.
32
<PAGE>
The managing general partner, unaffiliated third parties, including landowners,
and you and the other investors will share the production revenues from the
partnership's wells. The following chart expresses the interests in gross
revenues derived from the wells based on all currently proposed wells in the
Mercer County area. If the partnership acquires less than a 100% interest in a
well, then the percentages available to the partnership will decrease
proportionately.
<TABLE>
<CAPTION>
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP
ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST(1)
- ------- -------------- ---------------- -----------------------
<S> <C> <C> <C>
Managing General Partner.................29% partnership interest 25.375%
Investors................................71% partnership interest 62.125%
Third Party..........................................................12.500% Landowner Royalty Interest 12.500%
--------
100.000%
--------
--------
</TABLE>
- ------------------------------
(1) It is possible that substituted or additional wells in the Mercer County
area could have a net revenue interest to the partnership as low as
84.375% which would reduce the investors' interest to 59.906%.
The leases in other areas of the United States may be subject to greater royalty
or overriding royalty interests or other arrangements in which the partnership
bears a greater share of the costs of the well than its share of the revenues
from the well. There is no minimum net revenue interest which the partnership is
required to own in wells outside of the Mercer County area.
TITLE TO PROPERTIES
Title to all leases acquired by the partnership will be held in the name of the
partnership. However, title to the leases may initially be held in the name of
the managing general partner, its affiliates, or any nominee designated by the
managing general partner, to facilitate the acquisition of the leases. Title to
the leases will be transferred to the partnership from time to time after the
minimum subscriptions are received and released from escrow. Title to the lease
will be filed for record following drilling.
It is not the practice in the oil and gas industry to obtain title insurance on
leases and the managing general partner will not obtain title insurance with
respect to its 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 interest in each lease composing the acreage on
which the well is situated will be obtained before each well is drilled.
However, if the title to the interest in a lease is defective, then the
partnership will not have the right to recover against the transferor, the
managing general partner or its affiliates, on a title warranty theory.
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 the steps it deems necessary to assure that the
partnership has acceptable title for its purposes. The managing general partner,
however, may use its own judgment in waiving title requirements and will not be
liable for any failure of title of leases transferred to the partnership.
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 the managing general
partner as the general drilling contractor on wells located in Pennsylvania, and
the managing general partner or an affiliate on any wells located in other areas
of the United States. The partnership will pay the drilling and completion costs
to the managing general partner or an affiliate as incurred, except that the
partnership is permitted to make advance payments to the managing general
partner or an affiliate if necessary to secure tax benefits of prepaid
intangible drilling 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.
The managing general partner, as operator, will determine whether or not to
complete each well. A well, however, may be completed only if the managing
general partner determines in good faith that there is a reasonable probability
of obtaining commercial quantities of gas. Based upon its past experience, the
managing general partner anticipates that all of the partnership's wells drilled
to the Clinton/Medina geological formation will be required to be completed
before a determination can be made as
33
<PAGE>
to the well's productivity. If the managing general partner determines that a
well should not be completed, then the well will be plugged and abandoned and
the footage price will be adjusted.
The managing general partner's duties as operator will include:
- 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;
- managing and conducting all field operations in connection with the
drilling, testing, equipping, operating and producing of the wells;
- making technical decisions required in drilling, completing and
operating the wells;
- maintaining the wells, equipment and facilities in good working
order during the useful life thereof; and
- performing necessary accounting and administrative functions.
During producing operations the managing general partner will be reimbursed for
its direct expenses and will receive well supervision at competitive rates for
operating and maintaining the wells. The drilling and operating agreement
contains a number of other material provisions which should be carefully
reviewed and understood by you and the other prospective investors.
In the unlikely event that the managing general partner or an affiliate is not
the actual operator of the well during producing operations, then the managing
general partner without receiving well supervision fees will review the
performance of the third party operator. This includes reviewing the costs and
expenses charged by the third party operator and monitoring the accounting and
production records for the partnership. The actual operator will perform
services for each well which are customarily performed to operate a well in the
same general area as where the well is located. 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. These 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 interest in the well.
It is anticipated that the partnership generally will own 100% of the interest
in each well, but it may own as little as 25% of the interest in one or more
wells. Thus, the partnership may engage in drilling some of the wells with third
parties. This will decrease the partnership's interest in the well but increase
the diversification of the partnership's drilling activities. Any other interest
owner in a well may have a separate agreement with the managing general partner
with respect to the drilling and operating of the well with differing terms and
conditions from those contained in the partnership's drilling and operating
agreement. However, the managing general partner will be the operator or have
the right to replace the operator of most, if not all, of the partnership's
wells and will control all drilling and producing operations on these wells.
SALE OF OIL AND GAS PRODUCTION
IN GENERAL. The managing general partner is responsible for selling the
partnership's gas and oil production. The managing general partner's 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. The
managing general partner 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 customers is divided by the volume of all gas sold from the
wells in the area. For gas sold in the Mercer County area the managing general
partner received an average selling price after deducting all expenses,
including transportation expenses, of $2.29 per MCF in 1996, $2.39 per MCF in
1997, and $2.22 per MCF in 1998.
On occasion, the managing general partner has reduced the amount of production
it normally sells on the spot market until the spot market price increased. The
managing general partner, however, has not voluntarily restricted its gas
production in the past four years because of a lack of a profitable market
price. If the managing general partner determines curtailment of production
would
34
<PAGE>
be in the best interests of its partnerships, then production will be
curtailed to the same degree in all the wells in the same geographic area. On
the other hand, if the managing general partner has not decided to curtail
production, but all the gas produced cannot be sold because of limited demand
for the gas, 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 partnerships own the wells. In this regard, the partnership
will have the benefit of the agreement with Northeast Ohio Gas Marketing, Inc.
to buy all of the gas produced by the managing general partner and its
affiliates, including the partnership, other than gas being supplied directly to
industrial end-users. Northeast Ohio Gas Marketing, Inc. is an affiliate of
First Energy Corporation, a company listed on the New York Stock Exchange.
With respect to the gathering of the partnership's gas in Mercer County, it is
anticipated that the managing general partner or an affiliate, which may include
a limited partnership sponsored by an affiliate of Atlas America, will gather,
transport and compress the natural gas produced by the partnership either
directly to an industrial end-user or into the various pipeline delivery points
as discussed below. The partnership will pay a gathering charge for these
services at a competitive rate, which is currently 29 cents per MCF. The
managing general partner and its affiliates are currently delivering an average
27,000 MCF of natural gas per day from the Mercer County area and have the
capacity of delivering 33,000 MCF per day from the Mercer County area. Based
on its experience drilling other wells in the Mercer County area, the
managing general partner believes this excess delivery capacity can easily
include all of the partnership's gas production even if all 1,800 units are
sold and approximately 89.35 wells are drilled. Upgrades are continually made
to increase the capacity of the gathering system in the Mercer County area as
new wells or new markets are established on the system. For example,
currently two smaller compressors are being replaced by three larger units to
reduce operating line pressures in the field and enhance deliverability.
Also, due to the normal production decline of the over 900 existing producing
wells on this system, the anticipated volumes from new drilling do not impact
available pipeline capacity on a one-for-one basis.
The managing general partner anticipates that approximately 10% to 15% of the
gas produced by the partnership and the managing general partner's previous
partnerships in the Mercer County area will be sold to Wheatland Tube, an
industrial end-user in the area where the wells will be drilled. The remainder
of the partnership's gas, with certain exceptions, will be sold to Northeast
Ohio Gas Marketing, Inc. as discussed below.
Northeast Ohio Gas Marketing has an agreement with the managing general partner
and its affiliates to buy all of the gas produced by the managing general
partner and its affiliates, including the partnership and its affiliated
partnerships, other than gas being sold to Wheatland Tube, CSC and Warren
Consolidated. The contracts with Wheatland Tube, CSC and Warren Consolidated
will continue to be serviced by the managing general partner and its affiliates
including the partnership and its affiliated partnerships, and currently provide
for a higher price to be paid than under the agreement with Northeast Ohio Gas
Marketing. However, the managing general partner does not anticipate that the
partnership will benefit from the higher prices under the contracts with CSC and
Warren Consolidated because they primarily buy gas in east Ohio. Wheatland Tube,
however, does buy gas from the Mercer County area where most, if not all, of the
partnership's wells will be drilled.
The agreement with Northeast Ohio Gas Marketing is for a 10-year term, beginning
on April 1, 1999, and provides that Northeast Ohio Gas Marketing must take all
of the gas produced by the managing general partner and its affiliates. The
agreement may be suspended for force majeure which means generally such things
as an act of God, strike, war, public riot, lightning, fire, storm, flood, and
explosion. One act of force majeure is if Carbide Graphite and/or Duferco
Farrell Corporation, which the managing general partner anticipates will
purchase between 20% and 40% of the gas from the Mercer County area from
Northeast Ohio Gas Marketing, permanently close their plants. If this happens,
then Northeast Ohio Gas Marketing is not required to continue to purchase the
gas that would otherwise have been sold to Carbide Graphite and/or Duferco
Farrell Corporation.
The agreement also sets the price to be paid for the gas at the delivery points
set forth below for either the first one or two years of the agreement depending
upon the delivery point. If, at the end of the applicable period, the managing
general partner and its affiliates and Northeast Ohio Gas Marketing cannot agree
to a new price for the gas, then the managing general partner and its affiliates
may arrange to sell their gas to third parties. The managing general partner,
however, must first give Northeast Ohio Gas Marketing notice and an opportunity
to match the price. Thereafter, Northeast Ohio Gas Marketing and the managing
general partner and its affiliates will set the prices annually each November 30
subject to the same terms. However, if there is no price agreement then the
partnership can sell to third parties.
The initial gas price for each delivery point under the agreement is determined
by a formula tied to the spot market price based on the location of the delivery
point. Each delivery point will have a different formula for calculating the
price to be paid by Northeast Ohio Gas Marketing for the gas. The delivery
points are East Ohio Gas, National Fuel Gas Distribution, National Fuel Gas
Supply, Peoples Natural Gas, Columbia Gas Transmission, and Tennessee Gas
Pipeline - Zone 4.
35
<PAGE>
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. The managing general partner is utilizing
financial instruments to hedge the price risk of a portion of its partnerships'
gas production, which would include the partnership. To assure that the
financial instruments will be used solely for hedging price risks and not for
speculative purposes, the managing general partner has established a committee
to assure that all financial trading is done in compliance with hedging policies
and procedures. The managing general partner does not intend to contract for
positions that it cannot offset with actual production.
MARKETING OF GAS PRODUCTION FROM WELLS IN OTHER AREAS OF THE UNITED STATES. For
wells drilled in areas of the United States other than the Mercer County area,
the managing general partner expects that gas produced from these wells will be
supplied to industrial end-users, local distribution companies and/or interstate
pipelines.
CRUDE OIL. Any crude oil produced from the wells will flow directly into storage
tanks where it will be picked up by the oil company, a common carrier or
pipeline companies acting for the oil company which is purchasing the crude oil.
Thus, crude oil does not present any transportation problem. The managing
general partner anticipates selling any oil produced by the wells in the Mercer
County area to Ergon and other purchasers in spot sales. Previously, the
managing general partner was receiving approximately $21.50 per barrel in
December, 1996, approximately $15.20 per barrel in December, 1997, and
approximately $13.00 per barrel in December, 1998, for oil produced in the
Mercer County area.
Over the past eight years, the price of oil has ranged from approximately $38 to
as low as $8 per barrel. There can be no assurance as to the price of oil during
the term of the partnership.
INSURANCE
Since 1972, the managing general partner and its affiliates have been involved
in the drilling of more than 1,600 wells in Ohio, Pennsylvania and other areas
of the Appalachian Basin. They have not incurred a blow-out, fire or similar
hazard with any of these wells, and thus have not made any insurance claims.
The managing general partner will obtain and maintain insurance coverage in
amounts and for purposes which would be carried by a reasonable, prudent general
contractor and operator in accordance with industry standards. The partnership
will be named as an additional insured under these policies. In addition, the
managing general partner requires all of its subcontractors to certify that they
have acceptable insurance coverage for worker's compensation and general, auto
and excess liability coverage. Major subcontractors are required to carry
general and auto liability insurance with a minimum of $1,000,000 combined
single limit for bodily injury and property damage in any one occurrence or
accident. The managing general partner's current insurance coverage satisfies
the following specifications:
- worker's compensation insurance in full compliance with the laws of
the Commonwealth of Pennsylvania and any other applicable state
laws;
- 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
- excess liability insurance as to bodily injury and property damage
with combined limits of $50,000,000 during drilling operations
and $10,000,000 thereafter, per occurrence or accident and in the
aggregate. This 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 interest in the well,
alleging seepage, pollution or contamination damage resulting
from an accident. The excess liability insurance will be in place
and effective no later than the date subscription proceeds are
first released from escrow.
36
<PAGE>
The excess liability insurance will insure the partnership and the managing
general partner's other partnerships until the investor general partners are
converted to limited partners. After conversion the partnership will have the
benefit of the managing general partner's $11,000,000 liability insurance on the
same basis as the managing general partner and its affiliates, including the
managing general partner's other partnerships. Because the managing general
partner is driller and operator of other partnerships there is a risk that the
insurance available to the partnership could be substantially less if there are
claims with respect to the other partnerships.
These policies will have terms, including exclusions and deductibles, standard
for the oil and gas industry. Upon request the managing general partner will
provide you or your representative a copy of its insurance policies. The
managing general partner will use its best efforts to maintain insurance
coverage which meets or exceeds its current coverage, but may ultimately be
unsuccessful because the coverage becomes unavailable or too expensive.
If you are an investor general partner and there is going to be an adverse
material change in the partnership's insurance coverage, then the managing
general partner will notify you at least 30 days before the effective date. If
the insurance coverage will be materially reduced, which is not anticipated,
then you will have the right to convert your units into limited partner
interests before the reduction by giving written notice to the managing general
partner.
USE OF CONSULTANTS AND SUBCONTRACTORS
The partnership agreement authorizes the managing general partner to use the
services of independent outside consultants and subcontractors, although this is
not anticipated by the managing general partner for producing operations in the
Mercer County area. These persons will normally be paid on a per diem or other
cash fee basis. The services will be charged to the partnership as either a
direct cost or as a direct expense pursuant to the drilling and operating
agreement. These charges will be in addition to the unaccountable, fixed payment
reimbursement paid to the managing general partner for administrative costs, and
well supervision fees paid to the managing general partner as operator.
INFORMATION REGARDING CURRENTLY PROPOSED WELLS
Set forth below is information relating to wells which have been currently
proposed to be drilled by the partnership when subscription proceeds are
released from escrow and from time to time thereafter subject to the managing
general partner's right to withdraw the wells and to substitute other wells. The
specified wells represent the necessary wells if approximately $12,000,000 is
raised and the partnership takes 100% of the interest in the wells. It is not
anticipated that the well locations will be selected in the order in which they
are set forth. The managing general partner has not proposed any other wells:
- if more than this amount is raised,
- if the partnership takes a lesser interest in the wells,
- if the wells are substituted, or
- if wells will be drilled in other areas of the United States.
The managing general partner has not authorized any person to make any
representations concerning the possible inclusion of any other wells in the
partnership and you and the other prospective investors should rely only on the
information in this prospectus.
The currently proposed wells will be assigned unless circumstances occur which,
in the managing general partner's opinion, lessen the relative suitability of
the wells. These considerations include:
- the amount of the subscription proceeds,
- the latest geological data available,
- potential title problems,
37
<PAGE>
- approvals by federal and state departments or agencies,
- agreements with other interest owners in the wells,
- continuing review of other properties which may be available, and
- if no other circumstances occur which in the managing general
partner's opinion diminish the relative attractiveness of the
proposed wells.
Any substituted and/or additional wells will meet the same general criteria for
development potential as the currently proposed wells. Also, most of the
substituted and/or additional wells will have the Clinton/Medina geological
formation as their objective, which is discussed in the geologic evaluation, and
will be located in areas where the managing general partner or its affiliates
have previously conducted drilling operations. Nevertheless, you will not have
the opportunity to evaluate for yourself the relevant geophysical, geological,
economic or other information regarding the substituted and/or additional wells.
The purpose of the information regarding the currently proposed wells is to
assist you in analyzing and evaluating the currently proposed wells, including
production information for wells in the general area. The managing general
partner believes that production information for wells in the general area is an
important indicator in evaluating the economic potential of any well to be
drilled. There, however, 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. The managing
general partner believes that the production information is reliable, although
as to certain of the wells the production information is incomplete because
there was a third party operator and production information is not available.
Also, some of the wells which have been drilled by the managing general
partner's other partnership's have only been producing for a short period of
time or are not yet completed or on-line.
You are cautioned and urged to analyze carefully all production information for
each well offsetting or in the general area of a well proposed to be drilled by
the partnership and, in the process of doing so, to take the factors set forth
below into consideration:
- The length of time which the well has been on line and the period of
time for which production information is shown.
- 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.
- 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.
- 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 the managing general partner or if
the managing general partner was the operator, then the well was not
completed or on line as of the date of the report.
- Production information for wells located in close proximity to a
proposed well tends to be more relevant than production information
for wells located at a great distance from a proposed well, although
from time to time great disparity in well performance can occur in
wells located in close proximity.
- Consistency in production among wells tends to confirm the
reliability and predictability of the production.
38
<PAGE>
To assist you in becoming familiar with the proposed wells the information set
forth below is included:
- A map of western Pennsylvania and eastern Ohio showing their
counties.
- Lease information.
- A Location and Production Map showing the proposed wells and the
wells in the area.
- Production data.
- United Energy Development Consultants, Inc.'s geologic evaluation.
39
<PAGE>
MAP OF WESTERN PENNSYLVANIA
AND
EASTERN OHIO
40
<PAGE>
[MAP]
41
<PAGE>
LEASE INFORMATION
42
<PAGE>
EXHIBIT A
ATLAS-ENERGY FOR THE NINETIES - PUBLIC #8 LTD.
<TABLE>
<CAPTION>
OVERRIDING
ROYALTY INTEREST TO
EFFECTIVE EXPIRATION LANDOWNER THE MANAGING
WELL NAME COUNTY DATE* DATE* ROYALTY GENERAL PARTNER
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1. Balog #1 Lawrence 4/6/98 4/6/01 12.50% 0%
2. Booher #1 Lawrence 10/1/98 10/1/01 12.50% 0%
3. Booher #2 Lawrence 10/1/98 10/1/01 12.50% 0%
4. Booher #3 Lawrence 10/1/98 10/1/01 12.50% 0%
5. Borzackilo #1 Lawrence 9/17/98 9/17/01 12.50% 0%
6. Braatz #1 Lawrence 10/30/98 10/30/01 12.50% 0%
7. Braatz #2 Lawrence 10/30/98 10/30/01 12.50% 0%
8. Byler #72 Lawrence 8/13/98 8/13/01 12.50% 0%
9. Clark #7 Lawrence 9/29/98 9/29/01 12.50% 0%
10. Daytner #1 Lawrence 8/24/98 8/24/01 12.50% 0%
11. Daytner #2 Lawrence 8/24/98 8/24/01 12.50% 0%
12. Elder #2 Lawrence 3/8/99 3/8/02 12.50% 0%
13. Hasely #1 Lawrence 7/20/98 7/20/01 12.50% 0%
14. Hogue #1 Lawrence 10/18/97 10/18/02 12.50% 0%
15. Kauffman #1 Lawrence 4/27/98 4/27/01 12.50% 0%
16. Kendall #1 Lawrence 8/28/98 8/28/01 12.50% 0%
17. Kendall #2 Lawrence 8/28/98 8/28/01 12.50% 0%
18. Miller #10 Lawrence 2/25/99 2/25/02 12.50% 0%
19. Miller #14 Lawrence 11/12/98 11/12/01 12.50% 0%
20. Mitcheltree #1 Lawrence 10/9/98 10/9/01 12.50% 0%
21. Shaffer #6 Lawrence 10/26/98 10/26/01 12.50% 0%
22. Slick #2 Lawrence 10/22/97 10/22/02 12.50% 0%
23. Slick #3 Lawrence 4/16/99 4/16/02 12.50% 0%
24. Stickle #1 Lawrence 8/14/98 8/14/01 12.50% 0%
25. Telesz #1 Lawrence 4/26/99 4/26/02 12.50% 0%
26. Wengerd #6 Lawrence 1/26/99 1/26/02 12.50% 0%
27. Wengerd #7 Lawrence 2/26/98 2/26/02 12.50% 0%
28. Whiting #6 Lawrence 10/23/97 10/23/02 12.50% 0%
29. Wilson #6 Lawrence 2/10/98 2/10/02 12.50% 0%
30. Bobish #1 Mercer 7/16/98 7/16/01 12.50% 0%
31. Byler #74 Mercer 10/9/97 10/9/00 12.50% 0%
32. Combine #1 Mercer 7/24/98 7/24/01 12.50% 0%
33. Czubek #2 Mercer 2/19/98 2/19/01 12.50% 0%
34. Gathers #1 Mercer 8/4/98 8/4/01 12.50% 0%
35. Gearhart #1 Mercer 6/3/98 6/3/01 12.50% 0%
36. Hardisky #1 Mercer 9/19/97 9/19/00 12.50% 0%
37. Hostetler #14 Mercer 10/9/97 10/9/00 12.50% 0%
38. Hostetler #15 Mercer 8/21/97 8/21/00 12.50% 0%
39. Knierman #1 Mercer 8/3/98 8/3/01 12.50% 0%
40. Leali #5 Mercer 1/30/98 1/30/01 12.50% 0%
41. Leali #6 Mercer 1/30/98 1/30/01 12.50% 0%
42. Lehto #1 Mercer 9/18/97 9/18/00 12.50% 0%
43. Lehto #2 Mercer 09/18/97 09/18/00 12.50% 0%
44. McFarland #14 Mercer 4/2/98 4/2/01 12.50% 0%
</TABLE>
<TABLE>
<CAPTION>
OVERRIDING
ROYALTY ACRES TO BE
INTEREST TO 3RD NET REVENUE NET ASSIGNED TO
WELL NAME PARTIES INTEREST ACRES PARTNERSHIP
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1. Balog #1 0% 87.5% 99 50
2. Booher #1 0% 87.5% 215 50
3. Booher #2 0% 87.5% 215 50
4. Booher #3 0% 87.5% 215 50
5. Borzackilo #1 0% 87.5% 88 50
6. Braatz #1 0% 87.5% 83 50
7. Braatz #2 0% 87.5% 83 50
8. Byler #72 0% 87.5% 72 50
9. Clark #7 0% 87.5% 45 45
10. Daytner #1 0% 87.5% 105 50
11. Daytner #2 0% 87.5% 105 50
12. Elder #2 0% 87.5% 148 50
13. Hasely #1 0% 87.5% 108 50
14. Hogue #1 0% 87.5% 38 38
15. Kauffman #1 0% 87.5% 92 50
16. Kendall #1 0% 87.5% 123 50
17. Kendall #2 0% 87.5% 123 50
18. Miller #10 0% 87.5% 60 50
19. Miller #14 0% 87.5% 85 50
20. Mitcheltree #1 0% 87.5% 103 50
21. Shaffer #6 0% 87.5% 52 50
22. Slick #2 0% 87.5% 113 50
23. Slick #3 0% 87.5% 56 50
24. Stickle #1 0% 87.5% 58 50
25. Telesz #1 0% 87.5% 95 50
26. Wengerd #6 0% 87.5% 54 50
27. Wengerd #7 0% 87.5% 95 50
28. Whiting #6 0% 87.5% 140 50
29. Wilson #6 0% 87.5% 50 50
30. Bobish #1 0% 87.5% 90 50
31. Byler #74 0% 87.5% 60 50
32. Combine #1 0% 87.5% 80 50
33. Czubek #2 0% 87.5% 50 50
34. Gathers #1 0% 87.5% 62 50
35. Gearhart #1 0% 87.5% 60 50
36. Hardisky #1 0% 87.5% 47 47
37. Hostetler #14 0% 87.5% 60 50
38. Hostetler #15 0% 87.5% 100 50
39. Knierman #1 0% 87.5% 155 50
40. Leali #5 0% 87.5% 225 50
41. Leali #6 0% 87.5% 225 50
42. Lehto #1 0% 87.5% 155 50
43. Lehto #2 0% 87.5% 155 50
44. McFarland #14 0% 87.5% 78 50
</TABLE>
43
<PAGE>
<TABLE>
<CAPTION>
OVERRIDING
ROYALTY INTEREST TO
EFFECTIVE EXPIRATION LANDOWNER THE MANAGING
WELL NAME COUNTY DATE* DATE* ROYALTY GENERAL PARTNER
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
45. McFarland #15 Mercer 10/8/97 10/8/00 12.50% 0%
46. McFarland #16 Mercer 04/02/98 04/02/01 12.50% 0%
47. Minner #10 Mercer 05/07/98 05/07/01 12.50% 0%
48. Minner #11 Mercer 04/09/98 04/09/02 12.50% 0%
49. Minner #4 Mercer 5/7/98 5/7/01 12.50% 0%
50. Minner #8 Mercer 05/07/98 05/07/01 12.50% 0%
51. Picirilli #1 Mercer 11/20/98 11/20/01 12.50% 0%
52. Sacewicz #1 Mercer 8/28/97 8/28/00 12.50% 0%
53. Scott #1 Mercer 4/29/98 4/29/01 12.50% 0%
54. Turner #3 Mercer 5/9/96 5/9/01 12.50% 0%
55. Wallace #2 Mercer 5/7/96 5/7/01 12.50% 0%
56. Yasnowski #1 Mercer 8/4/98 8/4/01 12.50% 0%
57. Yasnowsky #2 Mercer 08/04/98 08/04/01 12.50% 0%
58. Yoder #8 Mercer 10/9/97 10/9/00 12.50% 0%
59. Yoder #9 Mercer 5/29/96 5/29/01 12.50% 0%
</TABLE>
<TABLE>
<CAPTION>
OVERRIDING
ROYALTY ACRES TO BE
INTEREST TO 3RD NET REVENUE NET ASSIGNED TO
WELL NAME PARTIES INTEREST ACRES PARTNERSHIP
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
45. McFarland #15 0% 87.5% 79 50
46. McFarland #16 0% 87.5% 78 50
47. Minner #10 0% 87.5% 205 50
48. Minner #11 0% 87.5% 53 50
49. Minner #4 0% 87.5% 205 50
50. Minner #8 0% 87.5% 205 50
51. Picirilli #1 0% 87.5% 58 50
52. Sacewicz #1 0% 87.5% 25 25
53. Scott #1 0% 87.5% 89 50
54. Turner #3 0% 87.5% 145 50
55. Wallace #2 0% 87.5% 168 50
56. Yasnowski #1 0% 87.5% 180 50
57. Yasnowsky #2 0% 87.5% 180 50
58. Yoder #8 0% 87.5% 80 50
59. Yoder #9 0% 87.5% 70 50
</TABLE>
*HBP - Held by Production
44
<PAGE>
LOCATION AND PRODUCTION MAP
45
<PAGE>
[MAP]
46
<PAGE>
[MAP]
47
<PAGE>
[MAP]
48
<PAGE>
[MAP]
49
<PAGE>
[MAP]
50
<PAGE>
[MAP]
51
<PAGE>
[MAP]
52
<PAGE>
PRODUCTION DATA
53
<PAGE>
The production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of
any well to be drilled by the partnership.
<TABLE>
<CAPTION>
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
CLINTON/MEDINA DEPTH PROD.
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
22419 Vista Resources/Atlas Resources, Inc. Arbuckle Unit #2 11/25/97 17 12037 5359' 483
22420 Vista Resources Arbuckle, R. #1 11/24/97 N/A N/A N/A N/A
20551 Atlas Resources, Inc. Bartholomew, P. #1 05/18/84 136 48327 5795' 230
22559 Atlas Resources, Inc. Borowicz #1 09/22/98 7 11956 5955' 1431
20624 Atlas Resources, Inc. Buchanan-Oris Unit #1 08/02/84 136 33279 5791' N/A
20218 Atlas Resources, Inc. Buchowski #1 02/08/99 3 4006 6111' 2814
22496 Atlas Resources, Inc. Byers #2 03/19/98 11 13330 5893' 787
22492 Atlas Resources, Inc. Byler #25 03/25/98 11 17198 5848' 1344
22465 Atlas Resources, Inc. Byler #29 03/03/98 11 30861 6071' 1629
22466 Atlas Resources, Inc. Byler #31 03/12/98 12 36144 6034' 1865
22554 Atlas Resources, Inc. Byler #32 08/23/98 7 21577 5941' 2314
20195 Atlas Resources, Inc. Byler #33 01/11/99 3 8062 6098' 3159
20201 Atlas Resources, Inc. Byler #42 07/29/98 7 20302 6154' 2057
20217 Atlas Resources, Inc. Byler #43 01/09/99 3 8282 6080' 3982
22572 Atlas Resources, Inc. Byler #57 10/09/98 6 15809 5760' 3024
20225 Atlas Resources, Inc. Byler #60 03/03/99 2 2303 6102' 2029
21569 Tipka Oil & Gas Byler, J. & K. #1 09/19/92 N/A N/A 6036' N/A
22617 Atlas Resources, Inc. Cameron #2 03/10/99 1 1193 5843' N/A
21327 Atlas Resources, Inc. Cresswell #1 08/28/91 92 87272 5688' 197
22638 Atlas Resources, Inc. Cypher Unit #1 03/17/99 N/A N/A 5972' N/A
22586 Atlas Resources, Inc. Dick #2 03/02/99 2 1879 5868' 1879
22629 Atlas Resources, Inc. Dixon #4 03/16/99 1 39 5964' N/A
22570 Atlas Resources, Inc. Donner #1 10/05/98 6 11632 5902' 2476
22303 Atlas Resources, Inc. Fairlamb Unit #1 11/10/96 29 45418 5432' 1315
22628 Atlas Resources, Inc. Gall #1 02/24/99 N/A N/A 5310' N/A
22623 Atlas Resources, Inc. Hostetler #11 03/22/99 N/A N/A 5934' N/A
22575 Atlas Resources, Inc. Hostetler Unit #10 01/11/99 4 4628 6003' 1455
22579 Atlas Resources, Inc. Hostetler Unit #9 01/14/99 4 7060 6091' 1814
21582 Tipka Oil & Gas Janosky Unit #1 10/02/92 N/A N/A 5882' N/A
54
<PAGE>
<CAPTION>
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
CLINTON/MEDINA DEPTH PROD.
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
20229 Atlas Resources, Inc. Johnston #4 03/14/99 1 906 6133' N/A
22374 Atlas Resources, Inc. Jones #2 08/29/97 20 39986 5739' 1358
22488 Atlas Resources, Inc. Jordan #4 03/10/98 13 26521 5770' 2006
22610 Atlas Resources, Inc. Jovenall #1 03/02/99 1 1756 5889' N/A
21340 Atlas Resources, Inc. Kelso #1 11/11/91 89 55123 5827' 348
21315 Atlas Resources, Inc. Kelso Unit #2 08/11/91 92 92679 5786' 202
20220 Atlas Resources, Inc. Kempf #2 01/20/99 3 3544 6114' 1687
20216 Atlas Resources, Inc. Kempf #3 02/03/99 3 4774 6087' 2160
22463 Atlas Resources, Inc. Kennedy #2 03/12/98 13 34845 5750' 1907
22399 Atlas Resources, Inc. Klein #1 09/07/97 18 29551 5473' 1738
22487 Atlas Resources, Inc. Kurtz #7 07/14/98 7 24655 6020' 3423
21307 Atlas Resources, Inc. Marsh #3 09/04/91 92 92487 5700' 366
21394 Atlas Resources, Inc. Marsh Unit #4 11/06/91 90 79467 5811' 461
22630 Atlas Resources, Inc. Mast #6 03/28/99 N/A N/A 5976' N/A
21260 Atlas Resources, Inc. McAnallen #1 03/19/91 97 50455 5719' 314
22535 Atlas Resources, Inc. McFarland #4 08/15/98 7 11417 5914' 1210
21590 Tipka Oil & Gas McFarland Unit #1 10/20/92 N/A N/A 5864' N/A
22574 Atlas Resources, Inc. McQueen #1 10/17/98 6 10354 5938' 1373
22315 Vista Resources McQuiston #1-C 01/09/97 N/A N/A 5300' N/A
22312 Vista Resources McQuiston #2-C 02/23/97 N/A N/A 5390' N/A
22373 Vista Resources McQuiston, E. #3-C 07/31/97 N/A N/A 5359' N/A
20215 Atlas Resources, Inc. Mikloz #1 10/27/98 6 17567 6148' 3919
22325 Vista Resources Miller Unit #1 02/05/97 N/A N/A 5375' N/A
22326 Vista Resources Miller Unit #2 03/05/97 N/A N/A 5367' N/A
22585 Atlas Resources, Inc. Minner #1 03/10/99 1 34 5795' N/A
21337 Atlas Resources, Inc. Monske #1 08/19/91 92 63490 5620' 178
20234 Atlas Resources, Inc. Muscarella Unit #2 03/26/99 N/A N/A 5575' N/A
20604 Atlas Resources, Inc. Nych Unit #1 05/05/84 136 30447 5652' 119
21174 Atlas Resources, Inc. Pesek #1 11/26/90 101 120556 5692' 151
20626 Atlas Resources, Inc. Plymire #1 11/03/84 Plugged & Abandoned 5784' N/A
55
<PAGE>
<CAPTION>
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
CLINTON/MEDINA DEPTH PROD.
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
20185 Atlas Resources, Inc. Reed #4 08/03/98 7 13697 6144' 1902
20022 The Peoples Natural Gas Co. Sokevitz #1 12/14/79 Plugged & Abandoned 4202' N/A
22436 Atlas Resources, Inc. Stallsmith #1 02/05/98 14 26629 5495' 1427
20203 Atlas Resources, Inc. Teh #1 09/18/98 7 12878 5999' 1254
22546 Vista Resources Temple, L. #1 10/08/98 N/A N/A N/A N/A
22587 Vista Resources Temple, L. #2 01/12/99 N/A N/A 5242' N/A
22560 Atlas Resources, Inc. Thompson #9 10/22/98 5 4652 5781' 1209
20191 Atlas Resources, Inc. Troyer #1 08/02/98 7 10687 6052' 1366
22494 Atlas Resources, Inc. Vandervort #1 03/29/98 12 22945 5292' 2101
22234 Atlas Resources, Inc. Wasser #2 09/09/96 31 34174 5754' 652
22539 Atlas Resources, Inc. Wengerd #3 01/12/99 3 8372 6048' 3077
20187 Atlas Resources, Inc. Wengerd Unit #2A 03/22/98 11 16430 6075' 1057
22471 Atlas Resources, Inc. Winder #3 03/14/98 13 18859 5800' 1292
22632 Atlas Resources, Inc. Winner Unit #1 03/22/99 1 213 5981' N/A
</TABLE>
Note: Accurate through -------- Period Ending 4/99
56
<PAGE>
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
57
<PAGE>
GEOLOGIC EVALUATION
OF
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
DRILLING PROGRAM
SOUTHWESTERN MERCER PROSPECT AREA,
PENNSYLVANIA
PROGRAM PROPOSED BY:
ATLAS RESOURCES, INC.
311 ROUSER ROAD
PO BOX 611
MOON TOWNSHIP PA 15108
REPORT SUBMITTED BY:
UEDC
UNITED ENERGY DEVELOPMENT CONSULTANTS, INC.
1715 CRAFTON BLVD.
PITTSBURGH, PA 15205-3101
SEPTEMBER 27, 1999
FOR:
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
DRILLING PROGRAM BY:
ATLAS RESOURCES, INC.
311 ROUSER RD.
P.O. BOX 611
MOON TOWNSHIP, PA 15108
58
<PAGE>
LOCATION MAP - AREA OF INTEREST
[MAP]
TABLE OF CONTENTS
<TABLE>
<S> <C>
INVESTIGATION SUMMARY .............................................3
OBJECTIVE ....................................................3
AREA OF INVESTIGATION.........................................3
METHODOLOGY...................................................3
SOUTHWESTERN MERCER PROSPECT AREA .................................4
DRILLING ACTIVITY ............................................4
GEOLOGY ......................................................4
STRATIGRAPHY, LITHOLOGY & DEPOSITION ....................4
RESERVIOR CHARACTERISTICS ...............................6
PRODUCTION CURVE .............................................8
POTENTIAL MARKETS AND PIPELINES ..............................8
STATEMENTS ........................................................9
CONCLUSION ...................................................9
DISCLAIMER ...................................................9
NON-INTEREST .................................................9
</TABLE>
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
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<PAGE>
INVESTIGATION SUMMARY
OBJECTIVE
The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Southwestern Mercer Prospect Area
(consisting of 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 #8 Ltd. Drilling Program, contains acreage in the following
townships in Mercer and Lawrence Counties, located in Pennsylvania:
<TABLE>
<CAPTION>
Mercer County Lawrence County
--------------- ----------------
<S> <C>
Shenango Pulaski
Lackawannock Wilmington
Coolspring Hickory
Deer Creek Mahoning
Sandy Creek Neshannock
Wilmington Washington
Jackson
Delaware
Jefferson
</TABLE>
Fifty-nine (59) drilling prospects designated for this program will be
targeted to produce natural gas from Clinton-Medina Group reserviors, found at
depths ranging from approximately 5,800 to 6,200 feet beneath the earth's
surface.
METHODOLOGY
Atlas Resources, Inc. and the in-house archives of UEDC, Inc. provided the
data incorporated into this report. Geological mapping and the interpretations
by Atlas geologists were also examined. Available "electric" log, completion,
and production data on wells offsetting prospect locations and other "key" wells
within and adjacent to the defined prospect area were used to determine
productive and depositional trends.
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
3
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<PAGE>
SOUTHWESTERN MERCER PROSPECT AREA
DRILLING ACTIVITY
The proposed drilling area lies within a region of northwestern
Pennsylvania which has been very active for the past decade in terms of
exploration for, and exploitation of natural gas reserves. Development within
and adjacent to the Southwestern Mercer Prospect Area has escalated since
1986, with Atlas Resources, Inc. and it's affiliates drilling over nine
hundred (900) wells during this period. Atlas Resources, Inc. continues to
identify and extend productive trends. Drilling is ongoing as of the date of
this report. 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:
================================================================================
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STRATIGRAPHIC NAMES-NW PENNSYLVANIA
[DIAGRAM]
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
================================================================================
62
<PAGE>
fine, light gray to red sandstones and siltstones broken up by thin dark gray
silty shale layers. Average porosity values for the Grimsby are approximately
six (6) to ten (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 ten
(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 impermeable shale or when
permeable sand changes gradually into non-permeable sand by a cementation
process known as "diagenesis". Thus, this type of trap represents cemented-in
hydrocarbon accumulations.
Electric well logs can be used in conjunction with production to
interpret reservoir parameters. When sandstones in the Thorold, Grimsby,
Cabot Head or Whirlpool develop porosity in excess of 6%, or a bulk density
of 2.55 or less, the permeability of the reservoir (which ranges from
< 0.1 to > 0.2 mD) can become great enough to allow commercial production of
natural gas. Small, naturally occurring cracks in the formation, referred to
as micro-fractures, can also enhance permeability. A gamma, bulk density,
density porosity and neutron log suite showing sand development in the
Grimsby, Cabot Head and Whirlpool is illustrated on the following page.
================================================================================
63
<PAGE>
[ILLUSTRATION]
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, 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:
================================================================================
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<PAGE>
GAMMA RAY LOG RESISTIVITY LOG
NO SEPARATION -- >
SEPARATION -- >
NO SEPARATION -- >
PRODUCTION CURVE
A model decline curve for the Southwestern Mercer Prospect Area was
created, based on production histories from over 200 wells in the mature
portion of the field. The diagram below illustrates the percentage of gas
recovery per year:
CHART
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.
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<PAGE>
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the Atlas-Energy
for the Nineties-Public #8 Ltd. Drilling Program, which will consist of
developmental drilling of the Clinton-Medina Group sands in Mercer and
Lawrence 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 it's employees, contract consultants, or
officers has, or is committed to acquire any interest, directly or
indirectly, in Atlas Resources, Inc.; nor is this firm, or any employee,
contract consultant, or officer thereof, otherwise affiliated with Atlas
Resources, Inc. We also confirm that neither the employment of, nor payment
of compensation received by UEDC in connection with this report, is on a
contingent basis.
Respectfully submitted,
/s/ UEDC, Inc.
UEDC, Inc.
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<PAGE>
COMPETITION, MARKETS AND REGULATION
COMPETITION AND MARKETS
There are many companies engaged in natural gas drilling operations in the areas
where the partnership is expected to conduct its activities. The industry is
highly competitive in all phases, including acquiring suitable properties for
drilling and the marketing of natural gas. The partnership will compete with
entities having financial resources and staffs larger than those available to
the partnership.
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.
There is a risk that over the term of the partnership there will be fluctuating
or increasing costs in doing business. This would directly affect the managing
general partner's ability to operate the partnership's wells at acceptable price
levels.
Natural gas and oil, if any, produced by the partnership's wells must be
marketed in order for you to realize revenues. In recent years natural gas and
oil prices have been volatile. Reduced gas demand and/or excess gas supplies
will result in lower prices. The marketing of natural gas and oil production, if
any, will be affected by numerous factors beyond the control of the partnership
and which cannot be accurately predicted. These factors include, but are not
limited to, the following:
- 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, 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 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.
Additionally, new pipeline projects have been proposed to the Federal Energy
Regulatory Commission (the "FERC") which could substantially increase the
availability of Canadian gas to certain U.S. markets. These imports could have
an adverse effect on both the price and volume of gas sales from the
partnership's wells.
Members of the Organization of Petroleum Exporting Countries ("OPEC") establish
production quotas for petroleum products from time to time with the intent of
reducing the current global oversupply and maintaining or increasing price
levels. The managing general partner is unable to predict what, if any, effect
these actions will have on prices for the gas sold from the partnership's wells.
The accelerating deregulation of natural gas and electricity transmission has
caused, and will continue to cause, a coming together of the gas and electric
industries. Demand for natural gas by the electric power sector is expected to
increase modestly through the next decade. Increased competition in the electric
industry, coupled with the enforcement of stringent environmental regulations,
may lead to an increased reliance on natural gas by the electric industry.
Also, FERC has sought to promote greater competition in natural gas markets.
Traditionally, natural gas has been sold by gas producers to pipeline companies,
which then would resell the gas to end-users. FERC changed this market structure
by requiring interstate pipeline companies that transport gas for others to
provide transportation service to producers, distributors and all other shippers
of natural gas on a "first-come, first-served" basis. This permits producers and
other shippers to sell natural gas directly to end-users and local distribution
companies.
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<PAGE>
FERC Order 636 requires 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 or producers. The premise behind FERC Order 636 was that the pipeline
companies had an unfair advantage over other gas suppliers or producers because
they could bundle their sales and transportation services together. FERC Order
636 is designed to ensure that no gas seller has a competitive advantage over
another gas seller because it also provides transportation services. The effect
of FERC Order No. 636 has been to restructure the natural gas industry and
increase its competitiveness.
Although not anticipated by the managing general partner, it is possible that in
the future the partnership's gas may be sold to local distribution companies if
Northeast East Ohio Gas Marketing and the managing general partner cannot agree
upon a price for the partnership's gas. While in the past these purchases were
generally made on the spot market, as a result of FERC Order No. 636 long-term
market-based gas supply arrangements have become more important than they were
previously. Although the spot market is still used, it is less important as a
market-based supply source. Many local distribution companies are buying gas
directly from gas marketers and are buying their own reserves. They have
attempted to minimize their risks by foregoing spot market purchases and instead
are entering into longer-term gas supply contracts and attempting to diversify
their supplies.
FERC has also required pipeline companies to develop electronic bulletin boards
to ensure that the gas industry is more competitive. Through electronic bulletin
boards, pipeline companies provide standardized access to information concerning
capacity and prices. Local distribution companies and marketers are also working
to develop companies which can access and integrate all of the information
available on all pipelines' electronic bulletin boards and arrange gas supplies
and transportation on behalf of purchasers from large regions of the country in
order to create a national market. These systems, and the development of
information service companies, will allow rapid consummation of natural gas
transactions. Gas purchased in Kansas could, for example, be used in Seattle.
Although this system may initially lower prices because of increased
competition, it is anticipated to increase natural gas markets and the
reliability of the markets.
CRUDE OIL REGULATION
Oil prices are not regulated. The price of oil is subject 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, but no longer
regulates the price of gas. 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 the
partnership's gas production will be price decontrolled gas and sold at fair
market value.
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." The managing general partner
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. Pennsylvania and any other states where the
partnership's wells may be situated impose a comprehensive statutory and
regulatory scheme for oil and gas operations. Among other things, these
regulations involve:
- new well permit and well registration requirements, procedures and
fees;
- minimum well spacing requirements;
- restrictions on well locations and underground gas storage;
68
<PAGE>
- certain well site restoration, groundwater protection and safety
measures;
- landowner notification requirements;
- certain bonding or other security measures;
- various reporting requirements;
- well plugging standards and procedures; and
- broad enforcement powers.
These state regulatory agencies have been granted broad regulatory and
enforcement powers which may create additional financial and operational burdens
on oil and gas operations like those of the partnership.
Pennsylvania and the other states also have pollution and environmental control
laws which have become increasingly burdensome in recent years. Enforcement
efforts with respect to oil and gas operations have increased. It can be
anticipated that this 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 drilling and producing operations. 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,
the Superfund, for hazardous substance contamination. The liability is unlimited
in cases of willful negligence or misconduct, and there is no limit on liability
for environmental cleanup costs or damages for claims by the state or private
persons or entities. Although the managing general partner will not transfer any
lease to the partnership if it has actual knowledge that there is an existing
potential environmental liability on the lease, there will not be an independent
environmental audit of the leases before they are transferred to the
partnership. Thus, there is a risk that the leases will have potential
environmental liability even before drilling begins.
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. It will also 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. The enforcement liabilities can result from
either governmental or citizen prosecution. Compliance with these statutes and
regulations may cause delays or increase the cost of producing the natural gas
and oil. Because these laws and regulations are constantly being revised and
changed the managing general partner is unable to predict the ultimate costs of
complying with present and future environmental laws and regulations. The
managing general partner is unable to obtain insurance to protect against most
environmental claims.
PROPOSED REGULATION
From time to time there are a number of proposals considered in Congress and in
the legislatures and agencies of various states that if enacted would
significantly and adversely affect the oil and natural gas industry. The
proposals involve, among other things, limiting the disposal of waste water from
wells and changes in the tax laws. 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.
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<PAGE>
PARTICIPATION IN COSTS AND REVENUES
IN GENERAL
The partnership agreement provides for the sharing of costs and revenues among
the managing general partner and you and the other investors. A tabular summary
of the following discussion appears below.
COSTS
1. ORGANIZATION AND OFFERING COSTS. Organization and offering costs will be
charged 100% to the managing general partner. However, organization and
offering costs in excess of 15% of investor subscriptions will be paid by
the managing general partner, without recourse to the partnership, and the
managing general partner will not be credited with this amount towards its
required capital contribution. Organization and offering costs generally
means all costs of organizing and selling the offering, and includes sales
commissions and other compensation to the dealer-manager and the
broker-dealers.
2. LEASE COSTS. The leases will be contributed to the partnership by the
managing general partner. The managing general partner will be credited
with a capital contribution for each lease valued at its cost, unless the
managing general partner has reason to believe that cost is materially
more than fair market value. In this case the credit for the contribution
will be made at a price not in excess of fair market value.
3. INTANGIBLE DRILLING COSTS AND EQUIPMENT COSTS. Intangible drilling costs
will be allocated and charged 100% to you and the other investors.
Equipment costs will be allocated and charged 43.75% to the managing
general partner and 56.25% to you and the other investors.
Although subscription proceeds will be used to pay the costs of drilling
different wells depending on when the subscriptions are received, the
revenues from all partnership wells will be commingled. Accordingly,
regardless of when you subscribe you will share in the revenues from all
wells on the same basis as the other investors in proportion to your
subscription.
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
to the parties in the same ratio as the related production revenues are
being credited. These costs generally include all costs of partnership
administration and the costs of producing and maintaining the
partnership's wells.
5. THE MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTION. The managing
general partner's aggregate capital contributions to the partnership,
including its credit for the cost of the leases contributed, must not be
less than 22.15% of all capital contributions to the partnership. The
managing general partner's capital contributions must be paid at the time
the costs are required to be paid by the partnership, but not later than
December 31, 2000.
REVENUES
1. PROCEEDS FROM THE SALE OF LEASES. If a partnership well is sold, a portion
of the sales proceeds will be allocated to the partners in the same
proportion as their share of the adjusted tax basis of the property. In
addition, proceeds will be allocated to the managing general partner to
the extent of the pre-contribution appreciation in value of the property,
if any. Any excess will be credited 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 your subscription before the
offering closes will be credited to your account and paid approximately
eight weeks after the offering closes. If a subscription is refunded, then
any interest allocated thereto will also be refunded. After the offering
closes 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 investors providing the
subscriptions. All other interest income, including interest earned on the
deposit of production revenues, will be credited as provided in 4, below.
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3. EQUIPMENT PROCEEDS. Proceeds from the sale or other disposition of
equipment will be credited to the parties charged with the costs of the
equipment in the ratio in which the costs were charged.
4. PRODUCTION REVENUES. All other revenues of the partnership, including
production revenues, will be credited 71% to you and the other investors
and 29% to the managing general partner subject to the managing general
partner's subordination of a portion of its share of partnership net
production revenues, as described below.
SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET REVENUE SHARE
Under the partnership agreement the partnership is structured to provide you
with preferred cash distributions equal to a minimum of 10% of your subscription
in each of the first five 12-month periods of partnership operations. To help
achieve this investment feature, the managing general partner will subordinate
up to 40% of its 29% share of partnership net production revenues, which is up
to 11.6% of the partnership net production revenues, to your receipt of
partnership cash distributions equal to 10% of your subscription in each of the
first five 12-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 beginning with the first distribution of
partnership revenues by debiting or crediting current period partnership
revenues to the managing general partner as may be necessary to provide the
distributions to you and the other investors. The specific formula is set forth
in Section 5.01(b)(4)(a) of the partnership agreement.
The managing general partner anticipates you will benefit from the
subordination if the price of gas received by the partnership and the results
of the partnership's drilling activities are unable to provide the required
return. However, if the wells produce small gas volumes or gas prices
decrease, then even with subordination your cash flow may be very small and
you may not receive a return of your entire investment. As of January 15,
1999, all but five of the managing general partner's previous twelve limited
partnerships which currently have the subordination feature in effect are
achieving or exceeding the 10% preferred 12-month cash distributions. The
managing general partner has subordinated from time to time its partnership
revenues in all of its other partnerships which have this subordination
feature.
TABLE OF PARTICIPATION IN COSTS AND REVENUES
The following table sets forth the participation in partnership costs and
revenues between the managing general partner and you and the other investors
after deducting from the partnership's gross revenues the landowner royalties
and any other lease burdens.
<TABLE>
<CAPTION>
MANAGING
GENERAL
PARTNER INVESTORS
------- ---------
<S> <C> <C>
PARTNERSHIP COSTS
Organization and offering costs ................................... 100% 0%
Lease costs ....................................................... 100% 0%
Intangible drilling costs ......................................... 0% 100%
Equipment costs ................................................... 43.75% 56.25%
Operating costs, administrative costs, direct costs and all
other costs .................................................. (1) (1)
PARTNERSHIP REVENUES
Interest income ................................................... (2) (2)
Equipment proceeds ................................................ 43.75% 56.25%
All other revenues including production revenues (3) .............. 29% 71%
PARTICIPATION IN DEDUCTIONS
Intangible drilling costs ......................................... 0% 100%
Depreciation ...................................................... 43.75% 56.25%
Percentage depletion allowance (3)................................. 29% 71%
</TABLE>
71
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- --------------------
(1) These costs will be charged to the parties in the same ratio as the
related production revenues are being credited.
(2) Interest earned on your subscription before the offering closes will be
credited to your account and paid approximately eight weeks after the
offering closes. After the offering closes 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 investors providing the subscriptions. All other interest income,
including interest earned on the deposit of operating revenues, will be
credited as oil and gas production revenues are credited.
(3) These percentages may vary if a portion of the managing general partner's
partnership net production revenues is subordinated.
ALLOCATION AND ADJUSTMENT AMONG INVESTORS
The partnership's revenues, gains, income, costs, expenses, losses and other
charges and liabilities will be charged and credited, among you and the other
investors, pro rata in accordance with your respective subscriptions. These
charges and credits will take into account any investor general partner's status
as a defaulting investor general partner.
DISTRIBUTIONS
The managing general partner will review the partnership accounts at least
quarterly to determine whether cash distributions are appropriate and the amount
to be distributed, if any. The partnership will distribute funds which the
managing general partner does not believe are necessary to be retained by the
partnership. Also, funds will not be advanced or borrowed for purposes of
distributions if the amount of the distributions would exceed the partnership's
accrued and received revenues for the previous four quarters, less paid and
accrued operating costs with respect to the revenues. Any cash distributions
from the partnership to the managing general partner will only be made in
conjunction with investor distributions and only out of funds properly allocated
to the managing general partner's account.
LIQUIDATION
The partnership will continue in existence for 50 years unless it is terminated
earlier. An election to terminate the partnership may be made by either:
- the managing general partner; or
- the affirmative vote of investors whose subscriptions equal a
majority of the total subscriptions.
Although the partnership may terminate on the occurrence of other events which
cause the dissolution of a limited partnership under state law, a successor
limited partnership will automatically be formed under those circumstances.
Thus, only upon a final terminating event, which is in the election of the
managing general partner or investors as described above, the termination of the
partnership under Section 708(b)(1)(A) of the Internal Revenue Code or the
partnership ceases to be a going concern, will the partnership be liquidated.
Upon liquidation of the partnership you will receive your interest in the
partnership. Generally, this means an undivided interest in the assets of the
partnership after payments to creditors of the partnership in the ratio of the
partners' capital accounts. However, after capital accounts of all of the
partners have been reduced to zero, the interest in the remaining assets of the
partnership will equal a partner's interest in the related revenues of the
partnership.
Any in kind property distributions to you must be made to a liquidating trust or
similar entity, unless at the time of the distribution:
- the managing general partner offers you the election of receiving in
kind property distributions and you accept the offer after being
advised of the risks associated with the direct ownership; or
- there are alternative arrangements in place which assure that you
will not, at any time, be responsible for the operation or
disposition of the partnership properties.
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If the managing general partner has not received your written consent within 30
days after it is mailed, then it will be presumed that you have not consented.
The managing general partner may then sell the asset at the best price
reasonably obtainable from an independent third party. Also, if the partnership
is liquidated, the managing general partner will be repaid for any debts owed it
by the partnership before there are any payments to you and the other investors.
CONFLICTS OF INTEREST
IN GENERAL
Conflicts of interest are inherent in oil and gas partnerships involving
non-industry investors because the transactions are entered into without arms'
length negotiation. Your interests and those of the managing general partner and
its affiliates may be inconsistent in some respects or in certain instances, and
the managing general partner's actions may not be the most advantageous to you.
The following discussion describes certain possible conflicts of interest that
may arise for the managing general partner and its affiliates in the course of
the partnership, and certain limitations which are designed to reduce, but which
will not eliminate, the conflicts. The following discussion, however, is not
intended to be inclusive and other transactions or dealings may arise in the
future that could result in conflicts of interest for the managing general
partner and its affiliates.
CONFLICTS REGARDING TRANSACTIONS WITH THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES
Although the managing general partner believes that the compensation and
reimbursement that it and its affiliates will receive in connection with the
partnership are reasonable, the compensation has been determined solely by the
managing general partner and is not the result of any negotiation with any
unaffiliated third party dealing at arms' length. The managing general partner
will be entitled to receive compensation and reimbursement from the partnership
even if the partnership's activities result in little or no profit, or a loss to
you and the other investors. The managing general partner or its affiliates
providing the services or equipment can be expected to profit from the
transactions, and it may be in the managing general partner's best interest to
enter into contracts with itself and its affiliates rather than unaffiliated
parties even if the contract terms, or skill and experience, offered by the
unaffiliated third parties is comparable.
The partnership agreement provides that if the managing general partner and any
affiliate provide services or equipment to the partnership, then the fees
charged must be competitive with the fees charged by unaffiliated persons in the
same geographic area engaged in similar businesses. Also, before the managing
general partner and any affiliate may provide services or equipment to the
partnership they must be engaged, independently of the partnership and as an
ordinary and ongoing business, in rendering the services or selling or leasing
the equipment and supplies to a substantial extent to other persons in the oil
and gas industry. If the managing general partner and any affiliate is not
engaged in such a business, then the compensation must be the lesser of its cost
or the competitive rate which could be obtained in the area.
Any services not otherwise described in this prospectus for which the managing
general partner or an affiliate is to be compensated must be:
- set forth in a written contract which describes the services to be
rendered and the compensation to be paid, and
- cancelable without penalty upon 60 days written notice by investors
whose subscriptions equal a majority of the total subscriptions.
The compensation, if any, will be reported to you in the partnership's annual
and semiannual reports and a copy of the contract will be provided to you upon
request.
CONFLICT REGARDING THE DRILLING AND OPERATING AGREEMENT
It is anticipated that all the wells developed by the partnership will be
drilled and operated pursuant to the drilling and operating agreement. The
managing general partner 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.
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CONFLICTS REGARDING SHARING OF COSTS AND REVENUES
The managing general partner will receive a percentage of revenues greater than
the percentage of costs that it pays. This may create a conflict of interest
between the managing general partner and you and the other investors regarding
the determination of which wells will be drilled by the partnership and the
profit potential associated with the wells.
In addition, the allocation of all the intangible drilling costs to you and the
other investors and a portion of the equipment costs to the managing general
partner creates conflicts of interest between the managing general partner and
you and the other investors. For example, the completion of a marginally
productive well might prove beneficial to you and the other investors but not to
the managing general partner. When a completion decision is made you and the
other investors will have already paid the majority of your costs so you will
want to complete the well if there is any opportunity to recoup any of the
costs. On the other hand, the managing general partner will not have paid any
money before this time and it will only want to pay the costs if it is
reasonably certain of recouping its money and making a profit. Based upon its
past experience, however, the managing general partner 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, the managing general partner will not cause any partnership well
to be plugged and abandoned without a completion attempt unless it makes the
decision in accordance with generally accepted oil and gas field practices in
the geographic area of the well location.
CONFLICTS REGARDING TAX MATTERS PARTNER
The managing general partner will serve as the partnership's tax matters partner
and will represent the partnership before the IRS. The managing general partner
will have broad authority to act on behalf of you and the other investors in any
administrative or judicial proceeding involving the IRS, and this authority may
involve conflicts of interest. These potential conflicts include:
- 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
you and the other investors,
- whether or not to contest a proposed adjustment by the IRS, if any,
to 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, or
- the managing general partner's reimbursement from the partnership of
expenses incurred by it in its role as the partnership's tax matters
partner.
CONFLICTS REGARDING OTHER ACTIVITIES OF THE MANAGING GENERAL PARTNER, THE
OPERATOR AND THEIR AFFILIATES
The managing general partner will be required to devote to the partnership
the time and attention which it considers necessary for the proper management
of the partnership's activities. The managing general partner will determine
the allocation of its management time, services and other functions on an
as-needed basis consistent with its fiduciary duties among the partnership
and its other partnerships. The managing general partner, however, has
sponsored and continues to manage other partnerships, which may be
concurrent. Additionally, the managing general partner and its affiliates
will engage in other oil and gas activities and other unrelated business
activities, either for their own account or on behalf of other partnerships,
joint ventures, corporations or other entities in which they have an
interest. Thus, they will have conflicts of interest in allocating management
time, services and other activities.
Subject to its fiduciary duties, the managing general partner will not be
restricted in any manner from participating in other businesses or activities,
even if these other businesses or activities are competitive with the
partnership's activities and operate in the same areas as the partnership.
However, the managing general partner and its affiliates may pursue business
opportunities that are consistent with the partnership's investment objectives
for their own account only after they have determined that the opportunity
either:
- cannot be pursued by the partnership because of insufficient funds,
or
- because it is not appropriate for the partnership under the existing
circumstances.
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CONFLICTS INVOLVING THE ACQUISITION OF LEASES
The managing general partner will select, in its sole discretion, the wells to
be drilled by the partnership. Conflicts of interest may arise concerning which
wells will be drilled by the partnership, and which will be drilled by the
managing general partner's other partnerships to be organized by it or in which
it serves as driller/operator. It may be in the managing general partner's or
its affiliates' advantage to have the partnership bear the costs and risks of
drilling a particular well rather than another partnership. These potential
conflicts of interest will be increased if the managing general partner
organizes and allocates wells to more than one partnership at a time including a
year-end partnership in which affiliates of the managing general partner invest.
To lessen this conflict of interest the managing general partner generally takes
a similar interest in other partnerships when it serves as managing general
partner and/or driller/operator.
No procedures, other than the guidelines set forth below and in " - Procedures
to Reduce Conflicts of Interest," have been established by the managing general
partner to resolve any conflicts which may arise. The partnership agreement
provides that the managing general partner and its affiliates will abide by the
guidelines set forth below. However, with respect to (2), (3), (4) and (5) there
is an exception in the partnership agreement for another program in which the
interest of the managing general partner is substantially similar to or less
than its interest in the partnership.
(1) TRANSFERS AT COST. All leases will be acquired from the managing general
partner and credited towards its required capital contribution at the cost
of the lease, unless the managing general partner has a reason to believe
that cost is materially more than the fair market value of the property.
If the managing general partner believes cost is materially more than fair
market value, then the managing general partner's credit for the
contribution must be at a price not in excess of the fair market value. A
determination of fair market value must be supported by an appraisal from
an independent expert. This opinion and any associated supporting
information must be maintained in the partnership's records for at least
six years.
(2) EQUAL PROPORTIONATE INTEREST. When the managing general partner sells or
transfers an oil and gas interest to the partnership, it must, at the same
time, sell or transfer to the partnership an equal proportionate interest
in all its other property in the same prospect. The term "prospect"
generally means an area which is believed to contain commercially
productive quantities of gas or oil. However, a prospect will be limited
to the drilling or spacing unit on which one well will be drilled if the
following two conditions are met:
- the well is being drilled to a geological feature which contains
proved reserves; and
- the drilling or spacing unit protects against drainage.
The managing general partner believes that for an oil and gas prospect
located in Ohio and Pennsylvania on which a well will be drilled to test
the Clinton/Medina geologic formation, a prospect will consist of the
drilling and spacing unit because it will meet the test in the preceding
sentence. Proved reserves, generally, are the estimated quantities of
natural gas which have been demonstrated to be recoverable in future years
with reasonable certainty under existing economic and operating
conditions, I.E., prices and costs as of the date the estimate is made.
Proved reserves do not include proved undeveloped reserves which generally
are reserves expected to be recovered from existing wells where a
relatively major expenditure is required for recompletion or from new
wells on undrilled acreage.
It is anticipated that most of the wells drilled by the partnership will
develop the Clinton/Medina geologic formation. The drilling of wells on
the acreage may provide the managing general partner with offset sites by
allowing it to determine at the partnership's expense the value of
adjacent acreage in which the partnership would not have any interest. The
managing general partner owns acreage in the area surrounding the
currently proposed wells. To lessen this conflict of interest, for five
years the managing general partner may not 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. If the partnership abandons its interest in a well, then this
restriction will continue for one year following the abandonment.
(3) SUBSEQUENTLY ENLARGING PROSPECT. In areas where the wells are not being
drilled to the Clinton/Medina geological formation, if the area
constituting the partnership's prospect is subsequently enlarged based on
subsequent geological
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information then there are special provisions. If the prospect is
enlarged to cover any area where the managing general partner owns a
separate property interest and the partnership activities were material
in establishing the existence of proved undeveloped reserves which are
attributable to the separate property interest, then the separate
property interest or a portion thereof must be sold to the partnership in
accordance with (1), (2) and (4).
(4) TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS AFFILIATE'S
ENTIRE INTEREST. If the managing general partner sells or transfers to the
partnership less than all of its ownership in any prospect then it must
comply with the following conditions:
- the interest retained by the managing general partner must be a
proportionate interest;
- the managing general partner's obligations and the partnership's
obligations must be substantially the same after the sale of the
interest by the managing general partner or its affiliates; and
- the managing general partner's interest in revenues must not exceed
the amount proportionate to its retained interest.
For example, if the managing general partner transfers 50% of its interest
in a prospect to the partnership and retains a 50% interest, then the
partnership will not pay any of the costs associated with the managing
general partner's retained interest as a part of the transfer. This
limitation 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. For example, the
managing general partner may sell its retained interest to a third party
for a profit.
(5) LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. For a five year period
after the closing, if the managing general partner proposes to acquire an
interest from an unaffiliated person in a prospect in which the
partnership owns an interest or in a prospect in which the partnership's
interest has been terminated without compensation within one year before
the proposed acquisition, then the following conditions apply:
- if the managing general partner does not currently own property in
the prospect separately from the partnership, then the managing
general partner may not buy an interest in the prospect; and
- if the managing general partner currently owns a proportionate
interest in the prospect separately from the partnership, then the
interest to be acquired must be divided in the same proportion
between the managing general partner and the partnership as the
other property in the prospect. However, if the partnership does not
have the cash or financing to buy the additional interest, then the
managing general partner cannot buy an additional interest in the
prospect either.
(6) NO SALE 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.
(7) NO TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The
partnership will not purchase properties from or sell properties to any
other affiliated partnership. This prohibition, however, does not apply to
joint ventures among 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.
(8) LEASES WILL BE ACQUIRED ONLY FOR STATED PURPOSE OF THE PARTNERSHIP. The
partnership will acquire only leases that are reasonably expected to meet
the stated purposes of the partnership. No leases will be acquired for the
purpose of a
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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 INVESTORS AND THE MANAGING GENERAL PARTNER AS AN INVESTOR
Any subscription by the managing general partner, its officers, directors, or
affiliates will dilute the voting rights of you and the other investors and
there may be a conflict with respect to certain matters. The managing general
partner and its officers, directors and affiliates, however, are prohibited from
voting with respect to certain matters.
LACK OF INDEPENDENT UNDERWRITER AND DUE DILIGENCE INVESTIGATION
The terms of this offering, the partnership agreement and the drilling and
operating agreement were determined by the managing general partner without
arms' length negotiations. You and the other investors have not been separately
represented by legal counsel, who might have negotiated more favorable terms for
you and the other investors in the offering and the agreements.
Also, 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. Although
Anthem Securities, which is affiliated with the managing general partner, serves
as dealer-manager and will receive reimbursement of accountable due diligence
expenses for certain due diligence investigations conducted by the selling
agents which will be reallowed to the selling agents, its due diligence
examination concerning this offering cannot be considered to be independent.
However, Anthem Securities 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.
CONFLICTS CONCERNING LEGAL COUNSEL
It is anticipated that legal counsel to the managing general partner will also
serve as legal counsel to the partnership and that this dual representation will
continue in the future. If a future dispute arises between the managing general
partner and you and the other investors, then the managing general partner will
cause you and the other investors to retain separate counsel. Also, if counsel
advises the managing general partner that counsel reasonably believes its
representation of the partnership will be adversely affected by its
responsibilities to the managing general partner, then the managing general
partner will cause you and the other investors to retain separate counsel.
CONFLICTS REGARDING PRESENTMENT FEATURE
You and the other investors have the right to present your units to the managing
general partner for repurchase beginning in 2004. This creates the following
conflicts of interest between you and the managing general partner:
- - If the managing general partner does not have the necessary cash flow or
it cannot borrow the funds on terms which it deems reasonable, then the
managing general partner may suspend the presentment feature. Both of
these determinations are subjective and will be made in the managing
general partner's sole discretion.
- - The managing general partner will also determine the repurchase price
based upon a reserve report that it prepares and is reviewed by an
independent expert. The independent expert, however, will be chosen by the
managing general partner. Also, the formula for arriving at the repurchase
price has subjective determinations that are within the discretion of the
managing general partner.
CONFLICTS REGARDING MANAGING GENERAL PARTNER WITHDRAWING AN INTEREST
With respect to the managing general partner's subordination obligation a
conflict of interest is created with you and the other investors by the managing
general partner's right to hypothecate its interest or withdraw an interest in
the partnership's wells.
CONFLICTS REGARDING ORDER OF PIPELINE CONSTRUCTION
A conflict of interest is created by the right of the managing general partner's
affiliates to determine the order of priority and the construction of pipelines
which may be required to connect certain wells into the gathering system of the
managing general partner's affiliates. Also, as a part of the sale of the
gathering system to an affiliated partnership the managing general partner's
parent company has committed to the drilling of at least 225 wells by December
31, 2002, which includes the partnership's wells, within 2500 feet of the
gathering system.
PROCEDURES TO REDUCE CONFLICTS OF INTEREST
In addition to the procedures set forth in " - Conflicts Involving the
Acquisition of Leases," the managing general partner and its affiliates will
comply with the following procedures in the partnership agreement to reduce some
of the conflicts of
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interest with you and the other investors. The managing general partner does
not have any other conflict of interest resolution procedures. Thus, conflicts
of interest between the managing general partner and you and the other
investors may not necessarily be resolved in your best interests. However, the
managing general partner believes that its significant capital contribution to
the partnership will reduce the conflicts of interest.
(1) FAIR AND REASONABLE. The managing general partner will not sell, transfer,
or convey any property to, or purchase any property from, the partnership
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.
(2) NO COMPENSATING BALANCES. The managing general partner may not use the
partnership's funds as a compensating balance for its own benefit.
(3) FUTURE PRODUCTION. The managing general partner may not commit the future
production of a partnership well exclusively for its own benefit.
(4) DISCLOSURE. If an agreement or arrangement binds the partnership, then it
must be fully disclosed in the prospectus.
(5) NO LOANS FROM THE PARTNERSHIP. The partnership will not loan money to the
managing general partner.
(6) NO REBATES. The managing general partner may not participate in any
business arrangements which would circumvent these guidelines including
receiving rebates or give-ups.
(7) SALE OF ASSETS. The sale of all or substantially all of the assets of the
partnership may only be made with the consent of investors whose
subscriptions equal a majority of the total subscriptions.
(8) PARTICIPATION IN OTHER PARTNERSHIPS. If the partnership participates in
other partnerships or joint ventures then the terms of the arrangements
must not circumvent any of the requirements contained in the partnership
agreement, including the following:
- 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;
- there will be no substantive change in the fiduciary and contractual
relationship between the managing general partner and you and the
other investors; and
- there will be no diminishment in your voting rights.
(9) INVESTMENTS. Partnership funds may not be invested in the securities of
another person except in the following instances:
- investments in interests made in the ordinary course of the
partnership's business;
- temporary investments in income producing short-term highly liquid
investments, in which there is appropriate safety of principal, such
as U.S. Treasury Bills;
- multi-tier arrangements meeting the requirements of (8) above;
- investments involving less than 5% of the total subscriptions which
are a necessary and incidental part of a property acquisition
transaction; and
- investments in entities established solely to limit the
partnership's liabilities associated with the ownership or operation
of property or equipment, provided, that duplicative fees and
expenses are prohibited.
POLICY REGARDING ROLL-UPS
It is possible at some indeterminate time in the future that the partnership
will become involved in a roll-up. 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, and
the issuance of securities by the roll-up entity to you and the other investors.
A roll-up will also include any change in the rights, preferences, and
privileges of you and the other investors in the partnership. These changes
could include the following:
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- increasing the compensation of the managing general partner;
- amending your voting rights;
- 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 if a roll-up should occur in
the future. These policies include:
- an appraisal of all partnership assets must be acquired from an
independent expert, and a summary of the appraisal must be included
in a report to you and the other investors in connection with a
proposed roll-up;
- if you vote "no" on the roll-up proposal, then you will be offered a
choice of:
- accepting the securities of the roll-up entity;
- remaining a partner in the partnership and preserving your
interests in the partnership on the same terms and conditions
as existed previously; or
- receiving cash in an amount equal to your pro-rata share of
the appraised value of the partnership's net assets; and
- the partnership will not participate in a proposed roll-up:
- which is not approved by investors whose subscriptions equal
75% of the total subscriptions;
- which would result in the diminishment of your voting rights
under the roll-up entity's chartering agreement;
- in which your right of access to the records of the roll-up
entity would be less than those provided by the partnership
agreement; or
- in which any of the costs of the transaction would be borne by
the partnership if the proposed roll-up is not approved by
investors whose subscriptions equal 75% of the total
subscriptions.
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CERTAIN TRANSACTIONS
As of January 15, 1999, 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.
<TABLE>
<CAPTION>
Cumulative
Leasehold, Reimbursement of
Drilling and Cumulative General and
Investor Non-recurring Completion Operator's Administrative
Partnership Subscriptions Management Fee Costs (1) Charges Overhead
- ----------- ------------- -------------- --------- ------- --------
<S> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 $ 600,000 0 $ 600,000 $172,076 $ 38,000
A.E. Partners 1986 631,250 0 631,250 130,440 54,244
A.E. Partners 1987 721,000 0 721,000 138,563 54,863
A.E. Partners 1988 617,050 0 617,050 111,867 51,120
A.E. Partners 1989 550,000 0 550,000 95,551 49,354
A.E. Partners 1990 887,500 0 887,500 150,717 54,066
A.E. Nineties-10 2,200,000 0 2,200,000 333,165 53,711
A.E. Nineties-11 750,000 0 761,802 (2) 129,842 82,041
A.E. Partners 1991 868,750 0 867,500 121,977 68,050
A.E. Nineties-12 2,212,500 0 2,272,017 (2) 368,849 79,368
A.E. Nineties-JV 92 4,004,813 0 4,157,700 (2) 559,501 121,415
A.E. Partners 1992 600,000 0 600,000 70,358 32,175
A.E. Nineties-Public #1 2,988,960 0 3,026,348 (2) 275,996 67,204
A.E. Nineties-1993 Ltd. 3,753,937 0 3,480,656 (2) 406,896 79,243
A.E. Partners 1993 700,000 0 689,940 77,993 24,338
A.E. Nineties-Public #2 3,323,920 0 3,324,668 (2) 279,209 54,133
A.E. Nineties-14 9,940,045 0 9,512,015 (2) 926,407 180,127
A.E. Partners 1994 892,500 0 892,500 55,015 23,811
A.E. Nineties-Public #3 5,799,750 0 5,799,750 376,743 76,249
A.E. Nineties-15 10,954,715 0 9,859,244 (2) 686,256 139,355
A.E. Partners 1995 600,000 0 600,000 34,104 6,638
A.E. Nineties-Public #4 6,991,350 0 6,991,350 388,460 72,791
A.E. Nineties-16 10,955,465 0 10,955,465 428,689 71,309
A.E. Partners 1996 800,000 0 800,000 35,060 6,264
A.E. Nineties-Public #5 7,992,240 0 7,992,240 270,858 47,854
A.E. Nineties-17 8,813,488 0 8,813,488 193,163 34,596
A.E. Partners 1997 506,250 0 506,250 7,588 1,200
A.E. Nineties-Public #6 9,901,025 0 9,901,025 154,050 21,615
A.E. Nineties-18 11,391,673 0 11,391,673 12,010 2,925
A.E. Nineties-1998 1,740,000 0 1,740,000 0 0
A.E. Nineties-Public #7 11,988,350 0 11,988,350 0 0
</TABLE>
- ------------------------------------
(1) Excluding the managing general partner's capital contributions.
(2) Includes additional drilling costs paid with production revenues.
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
IN GENERAL
The managing general partner will manage the partnership and its assets. It is
accountable to you as a fiduciary and it must exercise good faith and deal
fairly with you and the other investors in conducting the affairs of the
partnership. If the managing general partner breaches its fiduciary
responsibilities, then you are entitled to an accounting and the recovery of any
economic loss caused by the breach.
The 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. Also, the managing general
partner may not employ, or permit another to employ, the 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
you and the other investors by the managing general partner under applicable law
except as set forth in Sections 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 if you have questions concerning the duties of the managing general partner
you should consult your own counsel.
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LIMITATIONS ON MANAGING GENERAL PARTNER LIABILITY AS FIDUCIARY
Under the terms of the partnership agreement, the managing general partner, the
operator, and their affiliates have limited their liability to the partnership
and to you and the other investors for any loss suffered by the partnership or
you and the other investors which arises out of any action or inaction on their
part if:
- they determined in good faith that the course of conduct was in the
best interest of the partnership;
- they were acting on behalf of, or performing services for, the
partnership; and
- their course of conduct did not constitute negligence or misconduct.
Thus, you and the other investors may have a more limited right of action than
you would have had without these limitations in the partnership agreement.
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 they meet the standards set forth above. However, there is a more
restrictive limitation for indemnification for losses arising from or out of an
alleged violation of federal or state securities laws. Also, to the extent that
any indemnification provision in the partnership agreement purports to include
indemnification for liabilities arising under the Securities Act of 1933, as
amended, you should be aware that, in the SEC's opinion, this indemnification is
contrary to public policy and therefore unenforceable.
Payments arising from the indemnification or agreement to hold harmless are
recoverable only out of the tangible net assets of the partnership including
insurance proceeds. Still, use of partnership funds or assets for
indemnification would reduce amounts available for partnership operations or for
distribution to you and the other investors. Also, the partnership will not pay
the cost of the portion of any insurance which insures the managing general
partner, the operator, or an affiliate against any liability for which they
cannot be indemnified. In addition, partnership funds can be advanced to them
for legal expenses and other costs incurred in any legal action for which
indemnification is being sought only if the partnership has adequate funds
available and certain conditions in the partnership agreement are met.
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. This section of the prospectus is
a summary of the tax opinion and all the material federal income tax
consequences of the purchase, ownership and disposition of the general and
limited partner interests. You are strongly urged to read the entire tax
opinion.
The tax opinion represents only special counsel's best legal judgment, and has
no binding effect or official status. It is only special counsel's prediction as
to the outcome of the issues addressed and the results are not certain. As
required by IRS regulations, special counsel's opinions state whether it is
"more likely than not" that the predicted outcome will occur. There is no
assurance that the present laws or regulations will not be changed and adversely
affect you. Also, the IRS may challenge the deductions claimed by the
partnership or you, 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. No advance ruling on any tax consequence of an investment in the
partnership will be requested from the IRS.
Different tax considerations than these addressed in this discussion may apply
to foreign persons, corporations, partnerships, trusts and other prospective
investors which are not treated as individuals for federal income tax purposes.
Also, the treatment of the tax attributes of the partnership may vary among
investors. Accordingly, you are urged to seek qualified, professional assistance
in the preparation of your federal, state and local tax returns with specific
reference to your own tax situation.
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.
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- - PARTNERSHIP CLASSIFICATION. The partnership will be classified as a
partnership for federal income tax purposes, and not as a corporation. The
partnership, as such, will not pay any federal income taxes, and all items
of income, gain, loss, and deduction of the partnership will be reportable
by the partners in the partnership.
- - PASSIVE ACTIVITY CLASSIFICATION. The partnership's oil and gas production
income, together with gain, if any, from the disposition of its oil and
gas properties, which is 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. Also, the passive activity limitations
on losses under Section 469, more likely than not, will not be applicable
to investor general partners before the conversion of investor general
partner units to limited partner interests.
- - 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. Section 1.7704-1(e), it is
more likely than not that the partnership will not be treated as a
"publicly traded partnership" under the Internal Revenue Code.
- - 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.
- - INTANGIBLE DRILLING 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 limited partners.
- - PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Depending primarily on when the
partnership subscriptions are received, the partnership will prepay in
1999 most, if not all, of the intangible drilling costs related to
partnership wells the drilling of which will begin in 2000. Assuming that
the amounts are fair and reasonable, and based in part on the factual
assumptions set forth below, in our opinion the prepayments of intangible
drilling costs will be deductible for the 1999 taxable year even though
all owners in the well may not be required to prepay such amounts, subject
to certain restrictions summarized below, including basis and "at risk"
limitations, and the passive activity loss limitation with respect to the
limited partners.
The foregoing opinion is based in part on the assumptions that:
- the intangible drilling costs will be required to be prepaid in 1999
for specified wells pursuant to the drilling and operating
agreement;
- pursuant to the drilling and operating agreement the drilling of the
wells is required to be, and actually is, begun on or before March
30, 2000, and the wells are continuously drilled thereafter until
completed, if warranted, or abandoned; and
- the required prepayments are not refundable to the partnership and
any excess prepayments are applied to intangible drilling costs of
substitute wells.
- - DEPLETION ALLOWANCE. The greater of cost depletion or percentage depletion
will be available to qualified investors as a current deduction against
the partnership's oil and gas production income, subject to certain
restrictions summarized below.
- - MACRS. The partnership's reasonable equipment costs for depreciable
property placed in the wells which cannot be deducted immediately will be
eligible for cost recovery deductions under the Modified Accelerated Cost
Recovery System ("MACRS"), 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.
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- - TAX BASIS OF INVESTOR'S INTEREST. Each investor's adjusted tax basis in
his partnership interest will be increased by his total subscription.
- - AT RISK LIMITATION ON LOSSES. Each investor initially will be "at risk" to
the full extent of his subscription.
- - ALLOCATIONS. Assuming the effect of the allocations of income, gain, loss
and deduction (or items thereof) set forth in the partnership agreement,
including the allocations of basis and amount realized with respect to
oil and gas properties, is substantial in light of an investor'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 investor's distributive share of such items to the
extent such allocations do not cause or increase deficit balances in the
investors' capital accounts.
- - SUBSCRIPTION. No gain or loss will be recognized by the investors on
payment of their subscriptions.
- - PROFIT MOTIVE AND NO TAX SHELTER REGISTRATION. 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 under Section 183 of
the Internal Revenue Code and is not required to register with the IRS as
a tax shelter.
- - 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. Section 1.701-2.
- - 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, it is the
special counsel's 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 investor more likely than not will be
realized as contemplated by the prospectus.
PARTNERSHIP CLASSIFICATION
For federal income tax purposes, a partnership is not a taxable entity. The
partners, rather than the partnership, receive any deductions and credits, as
well as the income, from the operations engaged in by the partnership. A
business entity with two or more members is classified for federal tax purposes
as either a corporation or a partnership. Because the partnership was formed
under the Pennsylvania Revised Uniform Limited Partnership Act which describes
the partnership as a "partnership," it will automatically be classified as a
partnership unless it 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:
- income from passive activities such as limited partners' interests
in a business;
- active income such as salary, bonuses, etc.; or
- portfolio income such as gain, interest, dividends and royalties
unless earned in the ordinary course of a trade or business.
Losses generated by "passive activities" can offset only passive income and
cannot be applied against active income or portfolio income. Suspended losses
and credits may be carried forward, but not back, and used to offset future
years' passive activity income.
Passive activities include any trade or business in which the taxpayer does not
materially participate on a regular, continuous, and substantial basis. Under
the partnership agreement, limited partners will not have material participation
in the partnership and generally will be subject to the passive activity
limitations.
Investor general partners also do not materially participate in the partnership.
However, because investor general partners do not have limited liability under
the Revised Uniform Limited Partnership Act of Pennsylvania until they are
converted to limited partners, their deductions generally will not be treated as
passive deductions before the conversion. However, if an
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investor general partner invests in the partnership through an entity which
limits his liability, for example, a limited partnership or S corporation, he
will be treated the same as a limited partner and generally will be subject
to the passive activity limitations. Contractual limitations on the liability
of investor general partners under the partnership agreement such as
insurance, limited indemnification, etc. will not cause investor general
partners to be subject to the passive activity limitations.
PUBLICLY TRADED PARTNERSHIP RULES. 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, in the opinion of special counsel it is
more likely than not that the partnership will not be characterized as a
publicly traded partnership under the Internal Revenue 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. Section 1.7704-1(e).
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 the managing
general partner anticipates will be in the late summer of 2000. Thereafter, each
investor general partner will have limited liability as a limited partner under
the Revised Uniform Limited Partnership Act of Pennsylvania with respect to his
interest in the partnership.
Concurrently, the investor general partner will become subject to the passive
activity limitations. However, his net income from the partnership's wells
following the conversion will continue to be characterized as non-passive income
which cannot be offset with passive losses. An investor general partner's
conversion of his partnership interest into a limited partner interest should
not have any other 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 his basis.
TAXABLE YEAR
The partnership intends to adopt a calendar year taxable year.
1999 EXPENDITURES
The managing general partner anticipates that all of the partnership's
subscription proceeds will be expended in 1999 and that your share of the income
and deductions generated pursuant thereto will be reflected on your federal
income tax return for that period. Depending primarily on when the partnership
subscriptions are received, the managing general partner anticipates that the
partnership will prepay in 1999 most, if not all, of its intangible drilling
costs for wells the drilling of which will begin in 2000. The deductibility in
1999 of such advance payments cannot be guaranteed.
AVAILABILITY OF CERTAIN DEDUCTIONS
Ordinary and necessary business expenses, including reasonable compensation for
personal services actually rendered, are deductible in the year incurred. The
managing general partner has represented to special counsel that the amounts
payable to the managing general partner and its affiliates, including the
amounts paid to the managing general partner or its affiliates as general
drilling contractor, are the amounts which would ordinarily be paid for similar
services in similar transactions. The fees paid to the managing general partner
and its affiliates will not be currently deductible if 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. 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.
INTANGIBLE DRILLING COSTS
Assuming a proper election and subject to the passive activity loss rules in the
case of limited partners, you will be entitled to deduct your share of
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. Such costs generally will be treated as ordinary income if a property is
sold at a gain. Also, productive-well intangible drilling costs may subject you
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.
The managing general partner has allocated approximately 76.12% of the footage
price to be paid by the partnership for a completed well in the Appalachian
Basin to intangible drilling costs which are charged 100% to you and the other
investors
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under the partnership agreement. The IRS could challenge the characterization
of costs claimed by you and the partnership to be deductible intangible
drilling 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.
The amount of the deduction for intangible drilling costs is limited for
integrated oil companies. Integrated oil companies are 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 those taxpayers and related persons who have refinery production
in excess of 50,000 barrels on any day during the taxable year.
DRILLING CONTRACTS
The partnership will enter into the drilling and operating agreement with the
managing general partner or its affiliates, as a third-party general drilling
contractor, to drill and complete the partnership's development wells on a
footage basis of $37.81 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, the managing
general partner 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 5,950 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.
The managing general partner believes the drilling and operating agreement is at
competitive rates in the proposed areas of operation. Nevertheless, the amount
of the profit realized by the managing general partner under the drilling
contract, if any, could be challenged by the IRS as unreasonable and disallowed
as a deductible intangible drilling cost.
Depending primarily on when the partnership subscriptions are received, the
managing general partner anticipates that the partnership will prepay in 1999
most, if not all, of the intangible drilling costs for drilling activities that
will begin in 2000. In Keller v. Commissioner, 79 T.C. 7 (1982), aff'd 725 F.2d
1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current
deductibility of prepaid intangible drilling costs. First, the expenditure must
be a payment rather than a refundable deposit. Second, 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 Keller
with respect to prepaid intangible drilling costs. The drilling and operating
agreement will require the partnership to prepay in 1999 intangible drilling
costs for specified wells the drilling of which will begin in 2000. 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, the managing general partner
anticipates that all of the partnership's 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 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 costs to be incurred in drilling substitute
wells. Under Keller, 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 the entire well. It is possible
that less than 100% of the interest will be acquired by the partnership in one
or more wells and prepayments may not be required of all owners of interests in
the wells. However, in the view of special counsel, a legitimate business
purpose for the required prepayments may exist under the guidelines set forth in
Keller, even though prepayment is not required, or actually received, by the
drilling contractor with respect to a portion of the interest in the wells.
In addition to the foregoing, a current deduction for prepaid intangible
drilling costs is available only if the drilling of the wells begins before the
close of the 90th day after the close of the taxable year. The managing general
partner will attempt to cause the drilling of all prepaid partnership wells to
begin on or before March 30, 2000. However, the drilling 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
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site, or title problems. Due to the foregoing factors no guaranty can be
given that the drilling of all prepaid partnership wells required by the
drilling and operating agreement to begin on or before March 30, 2000, will
actually begin by that date. In that event, deductions claimed in 1999 for
prepaid intangible drilling costs would be disallowed and deferred to the
2000 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
costs under the partnership's drilling contracts, thereby decreasing the amount
of deductions allocable to the investors 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.
DEPLETION ALLOWANCE
Proceeds from the sale of the partnership's 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. Depletion
deductions generally will be treated as ordinary income if a property is sold at
a gain.
Cost depletion for any year is determined by dividing the adjusted tax basis for
the property by the total units of 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. Percentage depletion is based on your share of the partnership's
gross production income from its oil and gas properties. The rate of percentage
depletion is 15%. However, percentage depletion for marginal production
increases 1%, up to a maximum increase of 10%, for each whole dollar that the
domestic wellhead price of crude oil for the immediately preceding year is less
than $20 per barrel without adjustment for inflation. The term "marginal
production" includes 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, which is 90 MCF of natural gas, per producing
well on the property in the calendar year. The rate of percentage depletion for
marginal production in 1999 is 24%.
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 carry-backs and capital loss
carry-backs. With respect to marginal properties, however, the 100% of net
income property limitation is suspended for 1999.
AVAILABILITY OF PERCENTAGE DEPLETION MUST BE COMPUTED SEPARATELY BY YOU, AND NOT
BY THE PARTNERSHIP OR FOR INVESTORS AS A WHOLE. YOU ARE URGED TO CONSULT YOUR
OWN TAX ADVISORS WITH RESPECT TO THE AVAILABILITY OF PERCENTAGE DEPLETION TO
YOU.
DEPRECIATION - MODIFIED ACCELERATED COST RECOVERY SYSTEM ("MACRS")
Equipment costs and the related depreciation deductions are allocated and
charged under the partnership agreement 43.75% to the managing general partner
and 56.25% to you and the other investors. These deductions are subject to
recapture as ordinary income rather than capital gain upon the disposition of
the property or an investor's interest in the partnership. 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. Smaller depreciation deductions are used for purposes of the
alternative minimum tax. 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 MACRS deduction is prorated on a 12-month basis. No
distinction is made between new and used property and salvage value is
disregarded.
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 the managing general partner, which will
contribute the leases to the partnership as a part of its capital contribution.
TAX BASIS OF INVESTORS' INTERESTS
Your distributive share of partnership loss is allowable only to the extent of
the adjusted basis of your interest in the partnership at the end of the
partnership's taxable year. The adjusted basis for federal income tax purposes
of your interest in the
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partnership will be adjusted, but not below zero, for any gain or loss to you
from a disposition by the partnership of an oil or gas property, and will be
increased by your cash subscription payment, your share of partnership income
and your share, if any, of partnership debt. The adjusted basis of your
interest in the partnership will be reduced by your share of partnership
losses, your depletion deduction, but not below zero, and cash distributions
from the partnership to you. The reduction in your share of partnership
liabilities, if any, is considered a cash distribution. Should cash
distributions exceed the tax basis of your interest in the partnership,
taxable gain would result to the extent of the excess.
"AT RISK" LIMITATION FOR LOSSES
Subject to the limitations on "passive losses" generated by the partnership in
the case of limited partners and your basis in the partnership, you may use your
share of the partnership's losses to offset income from other sources. However,
you may deduct the loss only to the extent of the amount you have "at risk" in
the partnership at the end of a taxable year. The amount "at risk" is limited to
the amount of money you have contributed to the partnership. In addition, the
amount you have "at risk" may not include the amount of any loss that you are
protected against through nonrecourse loans, guarantees, stop loss agreements,
or other similar arrangements.
DISTRIBUTIONS FROM A PARTNERSHIP
Generally, a cash distribution from a partnership to a partner in excess of the
adjusted basis of the 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.
SALE OF THE PROPERTIES
Generally, net long-term capital gains of a noncorporate taxpayer on the sale of
assets held more than a year are taxed at a maximum rate of 20%, or 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. The annual capital loss limitation for noncorporate taxpayers is
the amount of capital gains plus the lesser of $3,000, which is reduced to
$1,500 for married persons filing separate returns, or the excess of capital
losses over capital gains.
Gains or losses from sales of oil and gas properties held for more than twelve
months generally will be treated as a long-term capital gain, while a net loss
will be an ordinary deduction. However, on disposition of an oil and gas
property gain is treated as ordinary income to the extent of the lesser of:
- the amounts that were deducted as intangible drilling costs rather
than added to basis, plus depletion deductions that reduced the
basis of the property, depreciation deductions and certain losses,
if any, on previous sales of partnership assets; or
- 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.
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, including a repurchase by the managing general partner,
of all or part of your interest in the partnership held by you for more than
twelve months will generally result in a recognition of long-term capital
gain or loss. However, the recapturable portions of depreciation, depletion
and intangible drilling costs will constitute ordinary income. In the event
the interest is held for twelve months or less, the gain or loss will
generally be short-term gain or loss. Also, your pro rata share of the
partnership's liabilities, if any, as of the date of the sale or exchange
must be included in the amount realized. Therefore, the gain recognized may
result in a tax liability greater than the cash proceeds, if any, from such
disposition. In addition to gain from a passive activity, a portion of any
gain recognized by a limited partner on the sale or other disposition of his
interest in the partnership may be characterized as portfolio income.
A gift of your interest in the partnership may result in federal and/or state
income tax and gift tax liability to you, and interests in different
partnerships do not qualify for tax-free like-kind exchanges. Other dispositions
of your interest, 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. In addition, if you sell or exchange all
or part of your interest in the
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partnership you are required by the Internal Revenue Code to notify the
partnership within 30 days or by January 15 of the following year, if earlier.
NO DISPOSITION OF YOUR INTEREST IN THE PARTNERSHIP, INCLUDING REPURCHASE OF THE
INTEREST BY THE MANAGING GENERAL PARTNER, SHOULD BE MADE BY YOU PRIOR TO
CONSULTATION WITH YOUR TAX ADVISOR.
MINIMUM TAX - TAX PREFERENCES
With limited exceptions, all taxpayers are subject to the alternative minimum
tax. If your alternative minimum tax exceeds the regular tax, the excess is
payable in addition to the regular tax. The alternative minimum tax is intended
to insure that no one with substantial income can avoid tax liability by using
deductions and credits. The alternative minimum tax accomplishes this objective
by not treating favorably certain items that are treated favorably for purposes
of the regular tax, including the deductions for intangible drilling 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. The regular
tax rates on capital gains also apply for purposes of the alternative minimum
tax. 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.
For taxpayers other than integrated oil companies, the 1992 National Energy Bill
repealed the preference for excess intangible drilling costs and the excess
percentage depletion preference for oil and gas. The repeal of the excess
intangible drilling 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 costs preference had not been
repealed. Under the prior rules, the amount of intangible drilling costs which
is not deductible for alternative minimum tax purposes is the excess of the
"excess intangible drilling costs" over 65% of net income from oil and gas
properties. Excess intangible drilling costs is the regular intangible drilling
costs deduction minus the amount that would have been deducted under 120-month
straight-line amortization, or, at the taxpayer's election, under the cost
depletion method. There is no preference item for costs of nonproductive wells.
THE LIKELIHOOD OF YOU INCURRING, OR INCREASING, ANY MINIMUM TAX LIABILITY BY
VIRTUE OF AN INVESTMENT IN THE PARTNERSHIP MUST BE DETERMINED ON AN INDIVIDUAL
BASIS, AND REQUIRES YOU TO CONSULT WITH YOUR 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 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. These rules do not apply to
partnership income or expense subject to the passive activity loss limitations
for limited partners.
ALLOCATIONS
The partnership agreement allocates to you your share of the partnership's
income, gains, and deductions, including the deductions for intangible drilling
costs and depreciation. Your capital account will be adjusted to reflect these
allocations and your capital account, as adjusted, will be given effect in
distributions made to you upon liquidation of the partnership or your interest
in the partnership. Generally, your capital account will be increased by the
amount of money you contribute to the partnership and allocations to you of
income and gain, and decreased by the value of property or cash distributed to
you and allocations to you of loss and deductions.
It should be noted that your share of partnership items of income, gain, loss,
and deduction must be taken into account whether or not there is any
distributable cash. Your share of partnership revenues applied to the repayment
of loans or the reserve for plugging wells, for example, will be included in
your gross income in a manner analogous to an actual distribution of the income
to you. Thus, you may have tax liability from the partnership for a particular
year in excess of any cash distributions from the partnership to you with
respect to that year. To the extent the partnership has cash available for
distribution, however, it is the managing general partner's policy that
partnership distributions will not be less than the managing general partner's
estimate of the investors' income tax liability with respect to partnership
income.
If any allocation under the partnership agreement is not recognized for federal
income tax purposes, your distributive share of the items subject to that
allocation generally will be determined in accordance with your interest in the
partnership, determined
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by considering relevant facts and circumstances. To the extent the
deductions, as allocated by the partnership agreement, exceed deductions
which would be allowed pursuant to such a reallocation you may incur a
greater tax burden.
PARTNERSHIP BORROWINGS
Under the partnership agreement, the managing general partner and its affiliates
may make loans to the partnership. The use of partnership revenues taxable to
you to repay partnership borrowings could create income tax liability for you in
excess of your cash distributions from the partnership, since repayments of
principal are not deductible for federal income tax purposes. In addition,
interest on the loans will not be deductible unless the loans are bona fide
loans that will not be treated as capital contributions in light of all the
surrounding facts and circumstances.
PARTNERSHIP ORGANIZATION AND SYNDICATION FEES
Expenses connected with the sale of interests in a partnership are not
deductible. Although certain organization expenses of the partnership may be
amortized over a period of not less than 60 months, these expenses are paid by
the managing general partner as part of the partnership's organization and
offering costs and any related deductions, which the managing general partner
does not expect will be material in amount, will be allocated to the managing
general partner.
TAX ELECTIONS
The partnership may 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 general effect of this 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 these 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 the assets. Also, certain "start-up expenditures" must be
capitalized and can only be amortized over a 60-month period. 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 deferred.
DISALLOWANCE OF DEDUCTIONS UNDER SECTION 183 OF THE INTERNAL REVENUE CODE
Your ability to deduct your share of the partnership's losses could be lost if
the partnership lacks the appropriate profit motive. 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 of five consecutive years, this presumption will not
be available and the possibility that the IRS could successfully challenge the
partnership deductions claimed by you would be substantially increased.
The fact that the possibility of ultimately obtaining profits is uncertain,
standing alone, does not appear to be sufficient grounds for the denial of
losses. 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 possess the
requisite profit motive.
TERMINATION OF A PARTNERSHIP
The 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. In that event, you would
realize taxable gain on a termination of the partnership to the extent that
money regarded as distributed to you exceeds the adjusted basis of your
partnership interest. The conversion of investor general partner units to
limited partner interests, however, 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 the tax shelter. For this
purpose, a "tax shelter" includes investments with respect to which any person
could reasonably infer that the ratio that the aggregate amount of the
potentially allowable deductions and 350% of the potentially allowable credits
with respect to the investment during the first five years of the investment
bears to the amount of money and the adjusted basis of property contributed to
the investment exceeds 2 to 1, determined without reduction for gross income
derived from the investment.
The managing general partner 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,
the managing general partner
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does not believe that the partnership will be a "potentially abusive tax
shelter." Accordingly, the managing general partner does not intend to cause
the partnership to register with the IRS as a tax shelter.
If it is subsequently determined by the IRS or the courts that the partnership
was required to be registered with the IRS as a tax shelter, the managing
general partner would be subject to certain penalties and you would be liable
for a $250 penalty for failure to include the tax shelter registration number on
your tax return, unless the failure was due to reasonable cause. You also would
be liable for a penalty of $100 for failing to furnish the tax shelter
registration number to any transferee of your 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, the managing general partner 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 the 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 the
managing general partner, which will serve as the partnership's representative
in all administrative and judicial proceedings conducted at the partnership
level. The managing general 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, you agree that you will
not form or exercise any right as a member of a notice group and will not file a
statement notifying the IRS that the managing general partner does not have
binding settlement authority.
TAX RETURNS. Your income tax returns are your responsibility. The partnership
will provide you with the tax information applicable to your investment in the
partnership necessary to prepare your returns.
PENALTIES AND INTEREST
IN GENERAL. Interest is charged on underpayments of tax and various civil and
criminal penalties are included in the Internal Revenue 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,
which is 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
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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. If a principal purpose of a partnership is to reduce
substantially the partners' federal income tax liability in a manner that is
inconsistent with the intent of the partnership rules of the Internal Revenue
Code, based on all the facts and circumstances, the IRS is authorized to remedy
the abuse. 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 this rule.
STATE AND LOCAL TAXES
Under Pennsylvania law, the partnership is required to withhold state income tax
at the rate of 2.8% of partnership income allocable to investors who are not
residents of Pennsylvania. Also, the partnership will operate in states and
localities which impose a tax on its assets or its income, or on you. Deductions
which are available to you for federal income tax purposes may not be available
for state or local income tax purposes.
YOU SHOULD CONSULT WITH YOUR OWN TAX ADVISORS CONCERNING THE POSSIBLE EFFECT OF
VARIOUS STATE AND LOCAL TAXES ON YOUR PERSONAL TAX SITUATION.
SEVERANCE 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.
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 1999
the ceiling for social security tax of 12.4% is $72,600 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 Internal Revenue Code applicable to partnership income
allocable to foreign partners, even if no cash distributions are made to such
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, which will
be adjusted for inflation. Estates of $650,000, which increases in stages to
$1,000,000 by 2006, or less generally are not subject to federal estate tax.
SUMMARY OF PARTNERSHIP AGREEMENT
NOTE: THE RIGHTS AND OBLIGATIONS OF THE MANAGING GENERAL PARTNER AND YOU AND THE
OTHER INVESTORS ARE GOVERNED BY THE PARTNERSHIP AGREEMENT, A COPY OF WHICH IS
ATTACHED AS EXHIBIT (A) TO THIS PROSPECTUS. YOU SHOULD NOT INVEST IN THE
PARTNERSHIP WITHOUT FIRST THOROUGHLY REVIEWING THE PARTNERSHIP AGREEMENT. THE
FOLLOWING IS A SUMMARY OF MATERIAL PROVISIONS IN THE PARTNERSHIP AGREEMENT WHICH
ARE NOT COVERED ELSEWHERE IN THIS PROSPECTUS.
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LIABILITY OF LIMITED PARTNERS
The partnership will be governed by the Pennsylvania Revised Uniform Limited
Partnership Act. If you invest as a limited partner, then generally you will not
be liable to third parties for the obligations of the partnership. However,
there are the following exceptions:
- if you also invest as an investor general partner;
- if you take part in the control of the business of the partnership
in addition to the exercise of your rights and powers as a limited
partner;
- if you fail to make a required capital contribution to the extent of
the required capital contribution; or
- for a period of two years, any capital contributions "wrongfully"
returned to you in violation of the partnership agreement or
Pennsylvania law to the extent of the capital contribution
wrongfully returned to you, with interest thereon. This includes,
but is not limited to, any distribution to you and the other limited
tartners to the extent that, after giving effect to the
distribution, all liabilities of the partnership exceed partnership
assets.
AMENDMENTS
Amendments to the partnership agreement may be:
- proposed in writing by the managing general partner, and adopted
with the consent of investors whose subscriptions equal a majority
of the total subscriptions; or
- proposed in writing by investors whose subscriptions equal 10% or
more of the total subscriptions and adopted by an affirmative vote
of investors whose subscriptions equal a majority of the total
subscriptions.
The partnership agreement may also be amended by the managing general partner
for certain purposes. However, no amendment materially and adversely affecting
the investors can be made without the consent of the affected investors.
NOTICE
Any notice given to you by the managing general partner begins from the date of
mailing the notice. Also, the notice is binding on you even if you do not
receive the notice. The notice periods are frequently quite short, a minimum of
15 business days, and apply to matters which may seriously affect your rights.
If you fail to respond in the specified time to the managing general partner's
request for approval of or concurrence in a proposed action, then you will
conclusively be deemed to have approved the action unless the partnership
agreement expressly requires your affirmative approval.
VOTING RIGHTS
Generally, you will be entitled to vote with respect to all partnership matters
at any time a meeting is called by either:
- the managing general partner, or
- investors owning 10% or more of the total subscriptions.
For each unit you own you are entitled to one vote on the matters being voted
upon. If you own a fractional unit, then you are entitled to vote that fraction
of one vote equal to the fractional interest in the unit.
At any time upon the request of investors whose subscriptions equal 10% or more
of the total subscriptions, you and the other investors may vote without a
meeting and without the concurrence of the managing general partner or its
affiliates on the matters set forth below. Investors whose subscriptions equal a
majority of the total subscriptions may vote to:
- amend the partnership agreement; provided however, any amendment may
not increase the duties or liabilities of you or the managing
general partner or increase or decrease the profit or loss sharing
or required capital
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contribution of you or the managing general partner without the
approval of you or the managing general partner. Also, any
amendment may not affect the classification of partnership
income and loss for federal income tax purposes without the
unanimous approval of all investors;
- dissolve the partnership;
- remove the managing general partner and elect a new managing general
partner;
- elect a new managing general partner if the managing general partner
elects to withdraw from the partnership;
- remove the operator and elect a new operator;
- approve or disapprove the sale of all or substantially all of the
assets of the partnership; and
- cancel any contract for services with the managing general partner,
the operator or their affiliates without penalty upon 60 days
notice.
The managing general partner, its officers, directors, and affiliates may also
subscribe for units in the partnership on the same basis as you and the other
investors, and they may vote on all matters other than:
- the issues set forth in removing the managing general partner and
operator above; and
- any other transaction between the managing general partner or its
affiliates and the partnership.
Any units owned by the managing general partner and its affiliates will not be
included in determining the requisite 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.
ACCESS TO RECORDS
Generally, you will have access to all records of the partnership after notice,
and at a reasonable time. However, logs, well reports and other drilling and
operating data may be kept confidential for reasonable periods of time. Your
ability to obtain the list of investors is subject to additional requirements
set forth in the partnership agreement.
WITHDRAWAL OF MANAGING GENERAL PARTNER
After 10 years, the managing general partner may voluntarily withdraw as
managing general partner for whatever reason by giving 120 days' written notice
to you and the other investors. Although the withdrawing managing general
partner is not required to provide a substitute managing general partner, a new
managing general partner may be substituted by the affirmative vote of investors
whose subscriptions equal a majority of the total subscriptions. If the managing
general partner would withdraw and the investors failed to elect to continue the
partnership and to designate a substitute managing general partner, then the
partnership would terminate and dissolve. This could result in adverse tax and
other consequences.
Also, subject to a required participation of not less than 1% of the partnership
revenues, the managing general partner may partially withdraw a property
interest in the partnership's wells equal to or less than its revenue interest
if the withdrawal is:
- to satisfy the bona fide request of its creditors, or
- approved by investors whose subscriptions equal a majority of the
total subscriptions.
SUMMARY OF DRILLING AND OPERATING AGREEMENT
The managing general partner will serve as the operator pursuant to the drilling
and operating agreement, Exhibit (II) to the partnership agreement, for wells
situated in Pennsylvania, and the managing general partner 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 60 days
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advance written notice by the managing general partner acting on behalf of the
partnership upon the affirmative vote of investors whose subscriptions equal a
majority of the total subscriptions.
The drilling and operating agreement provides a number of material provisions,
including, without limitation, those set forth below:
- The operator's right to resign after five years.
- The operator's right beginning three years after a partnership well
begins producing to retain $200 per month to cover future plugging
and abandonment costs of the well, although the managing general
partner historically has never done this after only three years.
- 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.
- The prescribed insurance coverage to be maintained by the operator.
- Limitations on the operator's authority to incur extraordinary costs
with respect to producing wells in excess of $5,000 per well.
- Restrictions on the partnership's ability to transfer its interest
in fewer than all wells, unless the transfer is of an equal
undivided interest in all wells.
- 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.
- The excuse for nonperformance by the operator due to force majeure.
Force majeure generally means acts of God, catastrophes and other
causes which preclude the operator's performance and are beyond its
control.
THE FOREGOING IS A SUMMARY OF THE MATERIAL PROVISIONS OF THE PROPOSED FORM OF
DRILLING AND OPERATING AGREEMENT WHICH ARE NOT COVERED ELSEWHERE IN THIS
PROSPECTUS. IT IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO THE FORM ATTACHED
TO THE PARTNERSHIP AGREEMENT AS EXHIBIT (II). YOU SHOULD NOT SUBSCRIBE TO THE
PARTNERSHIP WITHOUT FIRST THOROUGHLY REVIEWING THE DRILLING AND OPERATING
AGREEMENT.
REPORTS TO INVESTORS
Under the partnership agreement the partnership will provide you and the other
investors the reports set forth below. The cost of all the reports will be paid
by the partnership as direct costs.
- Beginning with the 1999 calendar year, the partnership will provide
you an annual report within 120 days after the close of the calendar
year, and beginning with the 2000 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.
- Audited financial statements of the partnership prepared in
accordance with generally accepted accounting principles.
Semiannual reports need not be audited.
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- A summary of the total fees and compensation paid by the
partnership to the managing general partner, the operator and
their affiliates, including the percentage that the annual
unaccountable, fixed payment reimbursements for administrative
costs bears to annual partnership revenues.
- A description of each well location owned by the partnership,
including the cost, location, number of acres and the
interest.
- A list of the wells drilled or abandoned by the partnership,
indicating whether each of the wells has or has not been
completed, and a statement of the cost of each well completed
or abandoned.
- A description of all farmins and joint ventures.
- A schedule reflecting:
- the total partnership costs;
- the costs paid by the managing general partner and the
costs paid by the investors;
- the total partnership revenues; and
- the revenues received or credited to the managing
general partner and the revenues received or
credited to the investors.
- The partnership will, by March 15 of each year, send you the
information needed for you to file your federal and state income tax
returns.
- Beginning January 1, 2001, and every year thereafter, the managing
general partner will provide you a computation of the total oil and
gas proved reserves of the partnership and its dollar value. The
reserve computations will be based upon engineering reports prepared
by the managing general partner and reviewed by an independent
expert.
PRESENTMENT FEATURE
Under the partnership agreement you and the other investors may present your
units for repurchase by the managing general partner beginning in 2004. However,
you and the other investors are not required to present your units for
repurchase and you may receive a greater return if you retain your units. The
managing general partner may immediately suspend its repurchase obligation by
notice to you if it determines, in its sole discretion, that:
- it does not have the necessary cash flow, or
- cannot borrow funds for this purpose on terms it deems reasonable.
The managing general partner will not purchase less than one unit unless the
lesser amount represents your entire interest. If less than all interests
presented at any time are to be purchased, then the interests to be purchased
will be selected by lot. In any calendar year the managing general partner will
not purchase more than 5% of the units. The managing general partner may waive
these limits, other than the limit on its purchasing more than 5% of the units
in any calendar year.
The managing general partner's obligation to purchase the interests presented
may be discharged for its benefit by a third party or an affiliate. If you sell
your interest it will be transferred to the party who pays for it. Also, you
will be required to deliver an executed assignment of your interest along with
any other document that the managing general partner requests.
You may present your units in writing to the managing general partner beginning
in 2004. The presentment must be:
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- within 120 days of the partnership reserve report discussed below,
and
- in accordance with Treas. Reg. Section 1.7704-1(f), no repurchase
will be made until at least 60 calendar days after you notify the
partnership in writing of your intention to exercise your repurchase
right.
The repurchase will not be considered effective until a cash payment has been
made to you.
The amount attributable to partnership reserves will be determined based upon
the last reserve report prepared by the managing general partner and reviewed by
an independent expert. Beginning in 2001 the managing general partner will
estimate the present worth of future net revenues attributable to the
partnership's interest in proved reserves. In making this estimate, the managing
general partner will use:
- a 10% discount rate,
- a constant oil price, and
- base gas prices upon the existing gas contracts at the time of the
repurchase.
Your presentment price will be based upon your share of the net assets and
liabilities of the partnership. The presentment price will include the sum of
the following items:
- an amount based on 70% of the present worth of future net revenues
from the partnership's proved reserves, determined as described
above;
- partnership cash on hand;
- prepaid expenses and accounts receivable of the partnership, less a
reasonable amount for doubtful accounts; and
- 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:
- an amount equal to all partnership debts, obligations and other
liabilities, including accrued expenses; and
- any distributions made to you between the date of the request and
the actual payment. However, if any cash distributed was derived
from the sale, after the presentment request, of oil, gas or of a
producing property, for purposes of determining the reduction of the
presentment price, the distributions will be discounted at the same
rate used to take into account the risk factors employed to
determine the present worth of the partnership's proved reserves.
The amount may be further adjusted by the managing general partner for estimated
changes from the date of the reserve report to the date of payment of the
presentment price to you:
- because of the production or sales of, or additions to, reserves and
lease and well equipment, sale or abandonment of leases, and similar
matters occurring before the presentment request; and
- because of any of the following occurring before payment of the
presentment price to you:
- 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,
and
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- changes in income, ad valorem and other tax laws such as material
variations in the provisions for depletion and similar matters.
As of April 1, 1999, fewer than 10 units have been presented to the managing
general partner for repurchase in its previous seven public limited
partnerships.
TRANSFERABILITY OF UNITS
RESTRICTIONS ON TRANSFER IMPOSED BY THE SECURITIES AND TAX LAW
Your transferability of the units is restricted. Other than transfers under the
partnership's presentment feature and transfers by operation of law, both the
securities laws and tax laws impose restrictions on the transfer of your unit.
Under the securities laws you will not be able to sell, assign, pledge,
hypothecate or transfer your unit unless there is:
- an effective registration of the unit under the Securities Act 1933
and qualification under applicable state securities law; or
- an opinion of counsel acceptable to the managing general partner
that the registration and qualification are not required.
Also, the managing general partner and the partnership are not obligated to, and
do not intend to, register the units for resale.
Under the tax laws, you will not be able to sell, assign, exchange or transfer
your unit if it would, in the opinion of counsel for the partnership:
- result in the termination of the partnership for tax purposes, or
- result in the partnership being treated as a "publicly-traded"
partnership for tax purposes.
TRANSFER PROVISIONS
The managing general partner must consent to the transfer of your unit. The
partnership will recognize the assignment of one or more whole units unless you
own less than a whole unit, in which case your entire fractional interest must
be assigned. Any transfer that is consented to by the managing general partner
when the assignee of the unit does not become a substituted partner as described
below will be effective as of:
- midnight of the last day of the calendar month in which it is made,
or
- 7:00 A.M. of the following day at the managing general partner's
election.
Under the partnership agreement an assignee of a unit may become a substituted
partner only upon meeting certain further conditions. A substitute partner is
entitled to all of the rights of full ownership of the assigned units including
the right to vote. The conditions to become a substitute partner are as follows:
- the assignor of the unit gives the assignee the right;
- the managing general partner consents to the substitution;
- the assignee of the unit pays to the partnership all costs and
expenses incurred in connection with the substitution; and
- the assignee of the unit executes and delivers the instruments to
effect the substitution and to confirm his agreement to be bound by
all terms and provisions of the partnership agreement.
The partnership will amend its records at least once each calendar quarter to
effect the substitution of substituted partners.
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PLAN OF DISTRIBUTION
COMMISSIONS
The units will be offered on a "best efforts" basis by Anthem Securities, which
is an affiliate of the managing general partner, acting as dealer-manager in all
states other than Minnesota and New Hampshire, and by other selected registered
broker-dealers, which are members of the NASD, acting as selling agents. Anthem
Securities was formed for the purpose of serving as dealer-manager of
partnerships sponsored by the managing general partner and became an NASD member
firm in April, 1997. Anthem Securities has participated as dealer-manager in
five partnerships sponsored by the managing general partner. Bryan Funding,
Inc., a member of the NASD, will serve as dealer-manager for the offering in the
states of Minnesota and New Hampshire, and will receive the same compensation as
Anthem Securities for sales in those states. Best efforts means that the
dealer-manager and selling agents 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 on each unit sold:
- a 2.5% dealer-manager fee;
- a 7% sales commission;
- a .5% reimbursement of marketing expenses; and
- a .5% reimbursement of the selling agent's bona fide accountable due
diligence expenses.
All or a portion of the 7% sales commissions, the .5% reimbursement of marketing
expenses, and the .5% reimbursement of the selling agents' bona fide accountable
due diligence expenses will be reallowed to the selling agents.
The managing general partner is also using the services of three wholesalers,
Mr. Eric Koval, Mr. Bruce Bundy and Mr. Robert Gourlay who are employed by it
and associated with Anthem Securities. The 2.5% dealer-manager fee will be
reallowed to the affiliated wholesalers for subscriptions obtained through their
efforts. The dealer-manager will retain any sales commissions, reimbursement of
marketing expenses, and reimbursement of the selling agents' bona fide
accountable due diligence expenses not reallowed to the selling agents.
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
subscription. Also, the offering will be made in compliance with Rule
2810(b)(2)(C) of the NASD Conduct Rules and the broker-dealers and
wholesalers will not execute a transaction for the purchase of units in a
discretionary account without the prior written approval of the transaction
by the customer.
The managing general partner, its officers, directors and affiliates and the
selling agents may subscribe for units on the same basis as other investors but
without paying the dealer-manager fee, sales commissions, reimbursement of
marketing expenses, and due diligence reimbursements. Also registered investment
advisors and their clients may subscribe for units on the same basis as other
investors by paying the dealer-manager fee, but without paying sales
commissions, reimbursement of marketing expenses, and due diligence
reimbursements.
After the minimum subscriptions are received and the checks have cleared the
banking system, the dealer-manager fee, the sales commissions, reimbursement of
marketing expenses, and due diligence reimbursements will be paid to the
dealer-manager and broker-dealers approximately every two weeks until the
offering closes.
INDEMNIFICATION
The dealer-managers may be deemed underwriters as that term is defined in the
Securities Act of 1933 and the sales commissions and dealer-manager fees may be
deemed underwriting compensation. The managing general partner and the
dealer-managers have agreed to indemnify each other, and it is anticipated that
the dealer-managers and each selling agent will agree to indemnify each other
against certain liabilities, including liabilities under the Securities Act of
1933.
98
<PAGE>
SALES MATERIAL
In addition to the prospectus the managing general partner will use the
following sales material with the offering of the units:
- a brochure entitled "Atlas-Energy for the Nineties-Public #8 Ltd.",
and
- Atlas America, Inc.'s corporate profile.
The managing general partner has not authorized the use of other sales material
and the offering of units is made only by means of this prospectus. The sales
material 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, this 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.
In addition, supplementary materials, including prepared presentations for group
meetings, must be submitted to the state administrators before they are used and
their use must either be preceded by or accompanied by a prospectus. Also, all
advertisements of, and oral or written invitations to, "seminars" or other group
meetings at which units are to be described, offered or sold will clearly
indicate the following:
- that the purpose of the meeting is to offer the units for sale,
- the minimum purchase price of the units,
- the suitability standards to be employed, and
- the name of the person selling the units.
No cash, merchandise or other items of value may be offered as an inducement to
you or any prospective investor to attend the meeting. All written or prepared
audiovisual presentations including scripts prepared in advance for oral
presentations to be made at the meetings must be submitted to the state
administrators within a prescribed review period. These provisions, however,
will not apply to meetings consisting only of representatives of broker-dealers.
YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS IN MAKING
YOUR INVESTMENT DECISION. NO ONE IS AUTHORIZED TO PROVIDE YOU WITH INFORMATION
THAT IS DIFFERENT.
LEGAL OPINIONS
Kunzman & Bollinger, Inc., has issued its opinion to the managing general
partner regarding the validity and due issuance of the units in this prospectus
and its opinion on material tax consequences to individual investors in the
partnership. However, 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 managing general
partner and the partnership have been audited by Grant Thornton, L.L.P., as of
the date indicated in their reports which appear elsewhere in this prospectus.
The financial statements have been included in reliance on their reports given
on their authority as experts in auditing and accounting.
The geologic evaluation of United Energy Development Consultants, Inc., which is
not affiliated with the managing general partner and its affiliates, appearing
in this prospectus has been included in this prospectus upon the authority of
United Energy Development Consultants, Inc. as an expert with respect to the
matters covered by the report and in the giving of the report.
References in this prospectus to Wright & Company, Inc. and its analysis
relating to the 1998 oil and gas reserves at October 1, 1998 of Atlas
America, Inc. are made in reliance on Wright & Company, Inc.'s authority as
an expert in petroleum consulting.
99
<PAGE>
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.
However, on November 22, 1995, Winston Management Services Corporation
("Winston") and Professional Planning & Technologies, Inc. ("PPT") 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. The
managing general partner intends to fight the lawsuit vigorously.
FINANCIAL INFORMATION CONCERNING THE MANAGING
GENERAL PARTNER AND THE PARTNERSHIP
Financial information concerning the partnership and the managing general
partner is reflected in the following financial statements.
THE SECURITIES OFFERED BY THIS PROSPECTUS ARE NOT SECURITIES OF, NOR ARE YOU
ACQUIRING AN INTEREST IN THE MANAGING GENERAL PARTNER, ITS AFFILIATES, OR ANY
OTHER ENTITY OTHER THAN THE PARTNERSHIP.
100
<PAGE>
FINANCIAL STATEMENT AND REPORT OF
INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
ATLAS-ENERGY FOR THE NINETIES - PUBLIC #8 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP
JUNE 11, 1999
101
<PAGE>
[LETTERHEAD]
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Partners
ATLAS-ENERGY FOR THE NINETIES - PUBLIC #8 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP
We have audited the accompanying balance sheet of Atlas-Energy for The
Nineties - Public #8 Ltd., A Pennsylvania Limited Partnership, as of
June 11, 1999. 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 statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statement. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statement referred to above presents fairly, in
all material respects, the financial position of Atlas-Energy for The Nineties -
Public #8 Ltd. as of June 11, 1999, in conformity with generally accepted
accounting principles.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
June 30, 1999
102
<PAGE>
Atlas-Energy for the Nineties - Public #8 Ltd.
(A Pennsylvania Limited Partnership)
BALANCE SHEET
June 11, 1999
<TABLE>
<CAPTION>
ASSETS
<S> <C>
Cash $100
----------
----------
PARTNERS' CAPITAL
Partners' capital $100
----------
----------
</TABLE>
The accompanying notes are an integral part of this financial statement.
103
<PAGE>
Atlas-Energy for the Nineties - Public #8 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENT
June 11, 1999
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
Atlas-Energy for the Nineties - Public #8 Ltd. (the "Partnership") is a
Pennsylvania Limited Partnership in which Atlas Resources, Inc. ("Atlas"),
of Pittsburgh, Pennsylvania, (a wholly-owned subsidiary of Atlas America,
Inc.) will be Managing General Partner and Operator, and subscribers to
Units will be either Limited Partners or Investor General Partners
depending upon their election.
The Partnership will be funded to drill development 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 20% 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 $18,000,000) by
December 31, 1999.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The financial statements are prepared in accordance with generally accepted
accounting principles.
The Partnership will use the successful efforts method of accounting for
oil and gas producing activities. Costs to acquire mineral interests in oil
and gas properties and to drill and equip wells will be capitalized.
Depreciation and depletion will be computed on a field-by-field basis by
the unit-of-production method based on periodic estimates of oil and gas
reserves.
Undeveloped leaseholds and proved properties will be assessed periodically
or whenever events or circumstances indicate that the carrying amount of
these assets may not be recoverable. Proved properties will be assessed
based on estimates of future cash flows.
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.
104
<PAGE>
Atlas-Energy for the Nineties - Public #8 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENT - CONTINUED
JUNE 11, 1999
3. 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.
4. PARTICIPATION IN REVENUES AND COSTS
Atlas and the other partners will participate in revenues and costs in the
following manner:
<TABLE>
<CAPTION>
OTHER
ATLAS PARTNERS
--------- ----------
<S> <C> <C>
Organization and offering costs 100% 0%
Lease costs 100% 0%
Revenues 29% 71%
Operating costs, administrative costs,
direct costs and all other costs 29% 71%
Intangible drilling costs 0% 100%
Tangible costs 43.75% 56.25%
Tax deductions:
Intangible drilling and development costs 0% 100%
Depreciation 43.75% 56.25%
Depletion allowances 29% 71%
</TABLE>
105
<PAGE>
Atlas-Energy for the Nineties - Public #8 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENT - CONTINUED
June 11, 1999
5. TRANSACTIONS WITH ATLAS AND ITS AFFILIATES
The Partnership intends to enter into the following significant
transactions with Atlas and its affiliates as provided under the
Partnership agreement:
Drilling contracts to drill and complete Partnership wells at
an anticipated cost of $37.81 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.
Reimbursement of gas transportation and marketing charges at
competitive rates.
6. PURCHASE COMMITMENT
Subject to certain conditions, investor partners may present their
interests beginning in 2004 for purchase by Atlas. Atlas is not obligated
to purchase more than 5% of the units in any calendar year.
7. SUBORDINATION OF MANAGING GENERAL PARTNER'S REVENUE SHARE
Atlas will subordinate a part of its partnership revenues in an amount up
to 11.6% 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.
8. INDEMNIFICATION
In order to limit the potential liability of the investor general
partners, Atlas has agreed to indemnify each investor general partner
from any liability incurred which exceeds such partner's share of
Partnership assets.
106
<PAGE>
CONSOLIDATED BALANCE SHEET
AND REPORT OF
INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
ATLAS RESOURCES, INC.
September 30, 1998
107
<PAGE>
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Board of Directors
ATLAS AMERICA, INC.
We have audited the accompanying consolidated balance sheet of Atlas
Resources, Inc. (a Pennsylvania corporation) and Subsidiary as of September
30, 1998. This financial statement is the responsibility of the Company'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 statements are 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 consolidated balance sheet referred to above presents
fairly, in all material respects, the consolidated financial position of
Atlas Resources, Inc. and Subsidiary as of September 30, 1998, in conformity
with generally accepted accounting principles.
As discussed in Note B to the consolidated Balance Sheet, the Company's
former parent, The Atlas Group, Inc., merged into Atlas America, Inc. on
September 29, 1998. Accordingly, the assets acquired and liabilities assumed
were adjusted to their estimated fair values. As a result, the consolidated
balance sheet for periods subsequent to the merger are not comparable to the
consolidated balance sheets presented for prior periods.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
March 22, 1999
108
<PAGE>
Atlas Resources, Inc. and Subsidiary
CONSOLIDATED BALANCE SHEET
September 30, 1998
ASSETS
<TABLE>
<CAPTION>
<S> <C>
Current Assets
Cash $ 62,724
Accounts receivable 1,619,811
Inventories 160,890
Prepaid expenses and other current assets 1,346,161
-------------------
Total current assets 3,189,586
Oil and Gas Properties (Successful Efforts) 13,290,245
Property, Plant and Equipment
Land 361,000
Buildings 2,469,000
Equipment 209,964
-------------------
3,039,964
Contract rights and other intangibles 12,095,708
Goodwill 17,717,000
-------------------
$ 49,332,503
===================
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
Accounts payable and accrued liabilities 801,488
Working interests and royalties payable 4,723,751
Accounts payable to affiliates 1,414,897
Billings in excess of costs on uncompleted contracts 5,290,633
Current maturities of long-term debt 185,714
-------------------
Total current liabilities 12,416,483
Deferred Taxes 2,300,000
Long-Term Debt, net of current maturities 526,191
Stockholder's Equity
Capital stock - stated value $10 per share; authorized -
500 shares, issued and outstanding - 200 shares 2,000
Additional paid-in capital 34,087,829
-------------------
34,089,829
-------------------
$ 49,332,503
===================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THIS STATEMENT.
</TABLE>
109
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENT
September 30, 1998
NOTE A - SUMMARY OF ACCOUNTING POLICIES
A summary of significant accounting policies consistently applied in the
preparation of the accompanying consolidated balance sheet follows.
1. NATURE OF OPERATIONS
Atlas Resources, Inc. 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. PRINCIPLES OF CONSOLIDATION
The consolidated balance sheet includes the accounts of Atlas Resources, Inc.
and its wholly-owned subsidiary ARD Investments. Atlas Resources owns an
undivided interest in the assets and is separately liable for its share of
liabilities of partnerships in which it has an ownership interest. In
accordance with established practice in the oil and gas industry, Atlas
Resources includes its pro rata share of the assets and liabilities of such
partnerships in the consolidated balance sheet. All significant intercompany
transactions and balances have been eliminated.
3. AFFILIATED COMPANIES
Atlas Resources, Inc. (the Company) is a wholly-owned subsidiary of AIC, Inc.
which is a wholly-owned subsidiary of Atlas America, Inc. (formerly The Atlas
Group, Inc.). Atlas America, Inc. is a wholly-owned subsidiary of Resource
America, Inc. which is the parent company. The Company is affiliated to other
companies which are subsidiaries of AIC, Inc. The Company's operations are
dependent upon the resources and services provided by AIC, Inc. The company is
also the managing general partner of several oil and gas partnerships.
Accounts payable to affiliates represents the net balance due to other
subsidiaries of AIC, Inc. for reimbursement of Company expenses paid by an
affiliate and marketing fees paid to an affiliate for marketing the Company's
oil and gas production.
4. USE OF ESTIMATES
In preparing financial statements in conformity with generally accepted
accounting principles, management is required to make estimates and assumptions
that affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements, and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
110
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENT - CONTINUED
September 30, 1998
NOTE A - SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
5. INVENTORIES
Inventories, consisting of oil and gas field materials and supplies, are stated
at the lower of cost or market. Cost is determined by the first-in, first-out
method.
6. OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for its oil and
gas activities. In accordance with this method, the acquisition costs of
undeveloped leaseholds are capitalized. Exploration costs, including delay
rentals, are expensed. Development costs related to drilling and equipping
development wells are capitalized. Costs of drilling and equipping exploratory
oil and gas wells are capitalized pending determination of quantities of proved
reserves. If proved reserves are not found, such costs are charged to expense.
Costs of surrendered, expired and abandoned leases are charged to expense.
Depreciation and depletion of proved properties is computed on a field-by-field
basis by the unit-of-production method based on periodic estimates of oil and
gas reserves.
The Company charges maintenance and repairs directly to expense while
betterments and renewals are capitalized in the property accounts. Undeveloped
leaseholds and proved properties are assessed whenever events or circumstances
indicate that the carrying amount of these assets may not be recoverable. Proved
properties are assessed based on estimates of future cash flows. When property
is retired or otherwise disposed of, the cost and applicable accumulated
depreciation, depletion and valuation allowances are removed from the respective
accounts and the resulting gain or loss is recorded in operations.
On an annual basis, the Company estimates the costs of future dismantlement,
restoration, reclamation, and abandonment of its gas and oil producing
properties. Additionally, the Company evaluates the estimated salvage value of
equipment recoverable upon abandonment. At September 30, 1998 the Company's
evaluation of equipment salvage values was greater than or equal to the
estimated costs of future dismantlement, restoration, reclamation and
abandonment.
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, other than oil and gas properties, is stated at
their estimated fair value at the date of acquisition. Depreciation is provided
using the straight-line method over the following estimated useful lives once
the asset is put into productive use.
<TABLE>
<S> <C>
Equipment 7 years
Building 39 years
</TABLE>
111
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENT - CONTINUED
September 30, 1998
NOTE A - SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
8. LONG-LIVED ASSETS
Contract rights and other intangibles consist of contracts purchased to operate
wells and manage limited partnerships and the ongoing partnership syndication
business. Operating and management contracts are being amortized on a
straight-line basis over the lives of the respective partnerships (up to 13
years) while the syndication rights are being amortized on a straight-line basis
over 30 years.
Goodwill is the excess of cost over the fair value of net assets acquired and is
being amortized by the straight-line method over 30 years. The Company evaluates
both contract rights and goodwill periodically to determine potential impairment
by comparing the carrying value to the undiscounted estimated future cash flows
of the related assets.
9. BILLINGS IN EXCESS OF COSTS
Amounts billed that are in excess of costs incurred are classified as a current
liability under billings in excess of costs on uncompleted contracts. Contract
costs include all direct material and labor costs and those indirect costs
related to contract performance, such as indirect labor, supplies, repairs and
depreciation costs. Contract retentions are included in accounts receivable.
NOTE B - RELATED PARTY TRANSACTIONS
On September 29, 1998, Atlas America, Inc., a newly formed wholly-owned
subsidiary of Resource America, Inc., acquired all the common stock of The Atlas
Group, Inc., the former parent company of AIC, Inc., in exchange for 2,063,496
shares of Resource America, Inc. common stock worth approximately $29,534,000
and the assumption of debt. The acquisition was recorded under the purchase
method of accounting and accordingly the purchase price was allocated to assets
acquired and liabilities assumed based on their fair market values, at the date
of acquisition, as summarized below:
<TABLE>
<S> <C>
Fair value of assets acquired $ 74,635,000
Liabilities assumed (45,968,000)
Amounts due seller (9,191,000)
Common stock issued (29,534,000)
--------------
NET CASH ACQUIRED $ (10,058,000)
==============
</TABLE>
112
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENT - CONTINUED
September 30, 1998
NOTE B - RELATED PARTY TRANSACTIONS (CONTINUED)
The fair value of assets acquired includes goodwill and other
intangibles of approximately $41,491,000.
The major changes to the historical carrying value of assets acquired
as a result of the application of purchase accounting in accordance
with APB Opinion 16 is as follows:
<TABLE>
<CAPTION>
ASSET INCREASE (DECREASE)
LIABILITIES (INCREASE) DECREASE
-------------------------------
(IN THOUSANDS)
<S> <C>
Contract rights and other intangibles $12,095
Goodwill 17,717
Oil and gas properties (8,855)
Deferred tax liability (2,172)
Other (85)
-------------------------------
NET CHANGE IN STOCKHOLDER'S EQUITY $18,700
===============================
</TABLE>
NOTE C - INCOME TAXES
The Company is included in the consolidated U.S. Federal income tax
return filed by Resource America, Inc., the parent company. Allocation
of income tax provision or benefit is based on actual tax calculations
of the individual companies.
The Company records deferred tax assets and liabilities based on the
temporary differences between the financial statement and tax bases of
assets and liabilities. The net deferred tax liability at September 30,
1998 was primarily related to differences between book and tax bases of
oil and gas properties.
113
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENT - CONTINUED
September 30, 1998
NOTE D - LONG-TERM DEBT
Long-term debt consists of a note payable to a bank in the amount of
$711,905 which is payable in monthly installments of $15,476 plus
interest at or below the prime rate plus 1/2% (8.25% at September 30,
1998) and is due in August of 2002. The note is secured by a building
and certain equipment. Maturities of the note payable for the years
following September 30, 1998 are as follows:
<TABLE>
<CAPTION>
FISCAL YEAR ENDING
SEPTEMBER 30,
----------------------------------------
<S> <C> <C>
1999 $185,714
2000 185,714
2001 185,714
2002 154,763
--------------
711,905
Less current maturities 185,714
--------------
$526,191
==============
</TABLE>
NOTE E - REVOLVING CREDIT AND TERM LOAN AGREEMENT
Atlas America, Inc. (Atlas) maintains a $40.0 million credit facility
(with $27.0 million of permitted draws) at PNC Bank ("PNC"). The credit
facility is divided into two principal parts: a revolving credit
facility and a term loan facility. The revolving credit facility has
$20.0 million of permitted draws, with a term ending in 2001 and the
draws bearing interest at one of two rates (elected at borrower's
option) which increase as the amount outstanding under the facility
increases: (i) PNC prime rate plus between 0 to 50 basis points, or
(ii) LIBOR plus between 137.5 to 212.5 basis points. The term loan
facility has $7.0 million of permitted draws, with a term ending in
2003, and with draws bearing interest at one of two rates (elected at
borrower's option), which increase as the amount outstanding under the
facility increases: (i) PNC prime rate plus between 12.5 to 62.5 basis
points, or (ii) LIBOR plus between 150 to 225 basis points. The credit
facility contains certain financial covenants of Atlas and imposes the
following limits: (a) Atlas' exploration expense can be no more than
20% of capital expenditures plus exploration expense, without PNC's
consent; (b) sales, leases or transfers of property by Atlas are
limited to $1.0 million without PNC's consent; and (c) Atlas cannot
incur debt in excess of $2.0 million to lenders other than PNC without
PNC's consent. As of September 30, 1998, Atlas had $20.0 million
outstanding under the revolving credit facility and $7.0 million
outstanding under the term loan facility which are recorded on Atlas'
books. Borrowings under the credit facility are collateralized by
substantially all the oil and gas properties of the Company and Atlas.
114
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENT - CONTINUED
September 30, 1998
NOTE F - COMMITMENTS
The Company is the managing general partner in several oil and gas
limited partnerships, and Atlas America, Inc. has agreed to indemnify
each investor general partner from any liability 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
Atlas America, Inc. and its subsidiaries.
Subject to certain conditions, investor general partners in certain oil
and gas limited partnerships have the right to present their interests
for purchase by the Company, as managing general partner. The Company
is not obligated to purchase more than 5% or 10% of the units in any
calendar year.
The Company subordinates a part of its net partnership revenues to the
receipt by investor general partners of cash distributions from the
Partnership equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreement.
NOTE G - 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 future date and
generally cover one month periods for up to 18 months in the future.
Gains and losses on such contracts are deferred and recognized in the
month the gas is sold. The Company had no significant futures contracts
at September 30, 1998.
NOTE H - OIL AND GAS INFORMATION (UNAUDITED)
The estimates of the Company's proved and unproved gas reserves are
based upon evaluations verified by Wright & Company Inc., an
independent petroleum engineering firm, as of September 30, 1998. All
reserves are located in Pennsylvania. Reserves are estimated in
accordance with guidelines established by the Securities and Exchange
Commission and the Financial Accounting Standards Board which require
that reserve estimates be prepared under existing economic and
operating conditions with no provision for price and cost escalation
except by contractual arrangements. Proved reserves are estimated
quantities of oil and natural gas which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs. Proved developed reserves are those which are
expected to be recovered through existing wells with existing equipment
and operating methods.
115
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENT - CONTINUED
September 30, 1998
NOTE H - OIL AND GAS INFORMATION (UNAUDITED) (CONTINUED)
The components of capitalized costs related to the Company's oil and
gas producing activities are as follows:
<TABLE>
<S> <C>
Proved oil and gas properties $13,279,245
Unproved oil and gas properties 11,000
-----------------
NET CAPITALIZED COSTS AT
SEPTEMBER 30, 1998 $13,290,245
=================
</TABLE>
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents
estimates only and should not be construed as being exact. In addition,
the standarized measures of discounted future net cash flows may not
represent the fair market value of the Company's oil and gas reserves
or the present value of future cash flows of equivalent reserves, due
to anticipated future changes in oil and gas prices and in production
and development costs and other factors for which effects have not been
provided.
The standardized measure of discounted future net cash flows is
information provided for the financial statement user as a common base
for comparing oil and gas reserves of enterprises in the industry. The
following schedule presents the standardized measure of estimated
discounted future net cash flows from the Company's proved reserves.
Estimated future cash flows are determined by using the weighted
average price received for the month of September 1998 adjusted only
for fixed and determinable increases in natural gas prices provided by
contractual agreements. The standardized measure of future net cash
flows was prepared using the prevailing economic conditions existing at
September 30, 1998 and such conditions continually change. Accordingly,
such information should not serve as a basis in making any judgement on
the potential value of recoverable reserves or in estimating future
results of operations.
<TABLE>
<CAPTION>
GAS OIL
PROVED RESERVES AT SEPTEMBER 30, 1998 (MCF) (BBLS)
---------------------------------------------------- -------------------- -----------------
<S> <C> <C>
Proved developed reserves 25,360,750 4,574
Proved undeveloped reserves 40,015,460 -
-------------------- -----------------
65,376,210 4,574
==================== =================
</TABLE>
116
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENT - CONTINUED
September 30, 1998
NOTE H - OIL AND GAS INFORMATION (UNAUDITED) (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED RESERVES (UNAUDITED)
<TABLE>
<CAPTION>
<S> <C>
Future cash inflows $152,909,040
Future production and development costs (73,423,000)
------------
Future net cash flows before income taxes 79,486,040
Future income taxes 3,853,561
------------
Future net cash flows 75,632,479
10% annual discount for estimated timing
of cash flows 56,231,521
------------
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS $ 19,400,968
============
</TABLE>
117
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
ATLAS RESOURCES, INC.
JUNE 30, 1999
118
<PAGE>
ATLAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
<TABLE>
<CAPTION>
ASSETS 6/30/1999 9/30/1998
------------ ------------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 10,151,710 $ 62,724
Trade accounts receivable 2,954,114 1,619,811
Accounts receivable from affiliates - -
Other receivables - -
Costs in excess of billings on uncompleted contracts - -
Inventories 270,083 160,890
Other current assets 2,303,108 1,346,161
------------ ------------
TOTAL CURRENT ASSETS 15,679,015 3,189,586
------------ ------------
OIL AND GAS PROPERTIES
Oil and gas wells and leases 19,613,980 13,290,245
Less accumulated depreciation, depletion and amortization 1,048,474 -
NET OIL & GAS PROPERTIES 18,565,506 13,290,245
------------ ------------
OTHER ASSETS - -
------------ ------------
PROPERTY, PLANT AND EQUIPMENT
Land 361,000 361,000
Buildings 2,469,000 2,469,000
Equipment 217,702 209,964
------------ ------------
Gathering Lines - -
------------ ------------
Sub-total 3,047,702 3,039,964
Less accumulated depreciation 78,259 -
------------ ------------
NET PROPERTY, PLANT & EQUIPMENT 2,969,443 3,039,964
------------ ------------
Contract right and other intangibles (Net of accumulated amortization) 11,695,363 12,095,708
Goodwill (Net of accumulated amortization) 17,274,075 17,717,000
------------ ------------
TOTAL ASSETS $ 66,123,402 $ 49,332,503
------------ ------------
------------ ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 481,470 801,488
Working interests and royalties payable 4,349,246 4,723,751
Billings in excess of costs on uncompleted contracts 4,204,530 5,290,633
Accounts payable to affiliates 8,994,657 1,414,897
Current maturities on long-term debt 185,714 185,714
Income taxes payable 2,294,779 -
------------ ------------
TOTAL CURRENT LIABILITIES 20,510,396 12,416,483
------------ ------------
LONG-TERM DEBT, net of current maturities 5,811,905 526,191
------------ ------------
DEFERRED TAXES 2,300,000 2,300,000
------------ ------------
ADVANCES FROM PARENT COMPANY - -
------------ ------------
STOCKHOLDERS' EQUITY
Capital stock, stated value $10.00: Authorized - 500 shs: Issued - 200 sh 2,000 2,000
Additional Paid In Capital 34,087,829 34,087,829
Retained earnings - -
------------ ------------
TOTAL STOCKHOLDERS' EQUITY 34,089,829 34,089,829
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 62,712,130 $ 49,332,503
------------ ------------
------------ ------------
</TABLE>
119
<PAGE>
ATLAS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED JUNE 30
----------------------------
1999 1998
------------ ------------
<S> <C> <C>
INCOME
Sales-gas wells $ 24,669,120 $ 18,737,489
Purchased gas revenues - -
Well operating fees 1,980,255 1,741,710
Working interest and royalties 3,413,813 3,524,945
Interest income 27,580 13,996
Other 314,422 219,792
------------ ------------
TOTAL INCOME 30,405,190 24,237,932
------------ ------------
COST OF SALES AND OTHER EXPENSES
Costs of sales-gas wells 20,133,912 16,557,510
Cost of purchased gas - -
Well operating expense 737,791 815,828
Exploration expense 129,304 368,088
General and administrative 1,240,567 2,925,043
Interest expense 261,176 235,209
Depreciation, depletion and amortization 2,030,003 1,709,157
Other 126,944 23,802
------------ ------------
TOTAL COST OF SALES AND OTHER EXPENSES 24,659,697 22,634,637
------------ ------------
INCOME BEFORE INCOME TAXES 5,745,493 1,603,295
INCOME TAXES 2,534,221 651,371
------------ ------------
NET INCOME $ 3,411,272 $ 951,924
------------ ------------
------------ ------------
</TABLE>
ATLAS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED JUNE 30
----------------------------
1999 1998
------------ ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,411,272 $ 951,924
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 2,030,003 1,709,157
(Increase) Decrease in Current Assets (2,400,443) (118,669)
Increase (Decrease) in Current Liabilities 8,093,913 3,135,247
Other assets and liabilities, net - 35,610
------------ ------------
Net cash provided by operating activities 11,134,745 5,713,269
------------ ------------
CASH FLOW FROM INVESTING ACTIVITIES:
Investment in oil and gas wells and leases (6,323,735) (2,917,294)
Investment in other property, plant & equipment - (78,350)
------------ ------------
Net cash used in investing activities (6,323,735) (2,995,644)
------------ ------------
CASH FLOWS USED IN FINANCING ACTIVITIES:
Repayment of bank notes (139,286) (139,286)
Borrowings under revolving credit 5,425,000 -
------------ ------------
Dividends to parent company - -
------------ ------------
Net cash provided by (used in) financing activities 5,285,714 (139,286)
------------ ------------
Net increase in cash and cash equivalents 10,096,724 2,578,339
Cash and cash equivalents at beginning of year 62,724 1,525,975
------------ ------------
Cash and cash equivalents at end of period $ 10,159,448 $ 4,104,314
------------ ------------
------------ ------------
</TABLE>
120
<PAGE>
ATLAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
JUNE 30, 1999
1. INTERIM FINANCIAL STATEMENTS
The consolidated financial statements as of June 30, 1999 and for the nine
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 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 September
30, 1998 consolidated financial statements. In the opinion of management, all
adjustments (consisting of only normal recurring accruals) considered
necessary for presentation have been included.
2. CONSOLIDATED STATEMENTS OF CASH FLOWS
Supplemental disclosure of cash flow information:
<TABLE>
<CAPTION>
Nine Months Ended June 30,
1999 1998
<S> <C> <C>
Cash paid during the period for:
Interest $ 39,719 $ 53,803
Income taxes 266,000 401,000
</TABLE>
3. LONG-TERM DEBT
Long-term debt consists of a note payable to a bank in the amount of $572,619
which is payable in monthly installments of $15,476 plus interest at or below
the prime rate plus 1/2% (8.25% at June 30, 1999) and is due August of 2002.
The note is secured by a building and certain equipment. Maturities of the
note payable for the years following June 30, 1999 are as follows:
<TABLE>
<CAPTION>
Period Ending June 30,
<S> <C>
2000 $185,714
2001 185,714
2002 185,714
Final Maturity August, 2002 15,477
--------
572,619
Less current maturities 185,714
--------
$386,905
--------
--------
</TABLE>
As reported in the Notes to Consolidated Financial Statements for September
30, 1998, Atlas America, Inc., the parent company of Atlas Resources, Inc.,
maintains a $40.0 million credit facility (with $27.0 million of permitted
draws) at PNC Bank. As of June 30, 1999, Atlas Resources, Inc. had $5,425,000
outstanding under the revolving credit facility.
4. IMPACT ON ATLAS RESOURCES OF RESOURCE AMERICA ACQUISITION
As reported in the Notes to Consolidated Financial Statements for September
30, 1998, on September 29, 1998, Atlas America, Inc., a newly formed
wholly-owned subsidiary of Resource America, Inc., acquired all the common
stock of The Atlas Group, Inc., the former parent company of AIC, Inc., in
exchange for 2,063,496 shares of Resource America, Inc. common stock worth
approximately $29,534,000 and the assumption of debt. The acquisition was
recorded under the purchase method of accounting and accordingly the purchase
price was allocated to assets acquired and liabilities assumed based on their
fair market values at the date of acquisition. The
121
<PAGE>
impact of the acquisition on the September 30, 1998 balance sheet of Atlas
Resources reflecting push-down accounting was as follows:
<TABLE>
<CAPTION>
Debit (Credit)
(Thousands of Dollars)
<S> <C>
Trade accounts receivable $ 500
Net oil and gas properties (8,855)
Net property, plant and equipment 60
Contract rights and other intangibles 12,095
Goodwill 17,717
Accounts payable and accrued liabilities (645)
Deferred taxes (2,172)
Additional paid-in capital (34,087)
Retained earnings 15,387
</TABLE>
122
<PAGE>
EXHIBIT (A)
AMENDED AND RESTATED CERTIFICATE
AND
AGREEMENT OF LIMITED PARTNERSHIP
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
SECTION NO. DESCRIPTION PAGE
<S> <C> <C>
I. FORMATION
1.01 Formation............................................................1
1.02 Certificate of Limited Partnership...................................1
1.03 Name, Principal Office and Residence.................................1
1.04 Purpose..............................................................1
II. DEFINITION OF TERMS
2.01 Definitions..........................................................2
III. SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
3.01 Designation of Managing General Partner and Participants.............8
3.02 Participants.........................................................8
3.03 Subscriptions to the Partnership.....................................9
3.04 Capital Contributions...............................................10
3.05 Payment of Subscriptions............................................11
3.06 Partnership Funds...................................................12
IV. CONDUCT OF OPERATIONS
4.01 Acquisition of Leases...............................................12
4.02 Conduct of Operations...............................................13
4.03 General Rights and Obligations of the Participants and Restricted
and Prohibited Transactions.........................................17
4.04 Designation, Compensation and Removal of Managing General Partner
and Removal of Operator.........................................25
4.05 Indemnification and Exoneration.....................................27
4.06 Other Activities....................................................29
V. PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND
DISTRIBUTIONS
5.01 Participation in Costs and Revenues.................................30
5.02 Capital Accounts and Allocations Thereto............................32
5.03 Allocation of Income, Deductions and Credits........................33
5.04 Elections...........................................................35
5.05 Distributions.......................................................35
VI. TRANSFER OF INTERESTS
6.01 Transferability.....................................................36
6.02 Special Restrictions on Transfers...................................37
6.03 Right of Managing General Partner to Hypothecate and/or
Withdraw Its Interests..............................................38
6.04 Presentment.........................................................38
VII. DURATION, DISSOLUTION, AND WINDING UP
7.01 Duration............................................................40
7.02 Dissolution and Winding Up..........................................40
VIII. MISCELLANEOUS PROVISIONS
8.01 Notices.............................................................41
8.02 Time................................................................41
8.03 Applicable Law......................................................41
8.04 Agreement in Counterparts...........................................42
8.05 Amendment...........................................................42
8.06 Additional Partners.................................................42
8.07 Legal Effect........................................................42
EXHIBITS
EXHIBIT (I-A) - Managing General Partner Signature Page
EXHIBIT (I-B) - Subscription Agreement
EXHIBIT (II) - Drilling and Operating Agreement
</TABLE>
i
<PAGE>
AMENDED AND RESTATED CERTIFICATE AND
AGREEMENT OF LIMITED PARTNERSHIP
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 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 _____________________, 1999, 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, these parties
hereinafter sometimes referred to as "Limited Partners," or for Investor
General Partner Units, these 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. This document shall be filed or recorded in the public offices
required under applicable law or deemed advisable in the discretion of the
Managing General Partner. Amendments to the certificate of limited
partnership shall be filed or recorded in the public offices required under
applicable law or deemed advisable in the discretion of the Managing General
Partner.
1.03. NAME, PRINCIPAL OFFICE AND RESIDENCE.
1.03(a). NAME. The name of the Partnership is Atlas-Energy for the
Nineties-Public #8 Ltd.
1.03(b). RESIDENCE. The residence of the Managing General Partner 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 party.
All addresses shall be subject to change upon notice to the parties.
1.03(c). AGENT FOR SERVICE OF PROCESS. The name and address of the agent for
service of process shall be Mr. Tony C. Banks 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. This includes, 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.
1
<PAGE>
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 the Managing General
Partner shall 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:
(i) any person directly or indirectly owning, controlling,
or holding with power to vote ten percent or more of the
outstanding voting securities of such specified person;
(ii) any person ten percent or more of whose outstanding
voting securities are directly or indirectly owned,
controlled, or held with power to vote, by such
specified person;
(iii) any person directly or indirectly controlling,
controlled by, or under common control with such
specified person;
(iv) any officer, director, trustee or partner of such
specified person; and
(v) 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
Section 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. "Anthem Securities" shall mean Anthem Securities, Inc., whose
principal executive offices are located at 311 Rouser Road, P.O.
Box 926, Coraopolis, Pennsylvania 15108-0926.
7. "Assessments" shall mean additional amounts of capital which may
be mandatorily required of or paid voluntarily by a Participant
beyond his subscription commitment.
8. "Atlas" shall mean Atlas Resources, Inc., a Pennsylvania
corporation, whose principal executive offices are located at
311 Rouser Road, Moon Township, Pennsylvania 15108.
9. "Capital Account" or "account" shall mean the account
established for each party hereto, maintained as provided in
Section 5.02 and its subsections.
10. "Capital Contribution" shall mean the amount agreed to be
contributed to the Partnership by a party pursuant to
Sections 3.04 and 3.05 and their subsections.
11. "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.
2
<PAGE>
12. "Code" shall mean the Internal Revenue Code of 1986, as amended.
13. "Cost," when used with respect to the sale of property to the
Partnership, shall mean:
(i) the sum of the prices paid by the seller to an
unaffiliated person for such property, including
bonuses;
(ii) title insurance or examination costs, brokers'
commissions, filing fees, recording costs, transfer
taxes, if any, and like charges in connection with the
acquisition of such property;
(iii) a pro rata portion of the seller's actual necessary and
reasonable expenses for seismic and geophysical
services; and
(iv) 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 (iv) shall have been incurred not more
than 36 months prior to the purchase by the Partnership.
"Cost," when used with respect to services, 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.
14. "Dealer-Manager" shall mean Anthem Securities, Inc., an
Affiliate of the Managing General Partner and the broker-dealer
which will manage the offering and sale of the Units in all
states other than 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.
15. "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.
16. "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 the
services are provided pursuant to written contracts and in
compliance with Section 4.03(d)(7).
17. "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 Section 5.01 and its subsections of this Agreement.
18. "Drilling and Operating Agreement" shall mean the proposed
Drilling and Operating Agreement between the Managing General
Partner or an Affiliate as Operator, and the Partnership as
Developer, a copy of the proposed form of which is attached
hereto as Exhibit (II).
3
<PAGE>
19. "Exploratory Well" shall mean a well drilled:
(i) to find commercially productive hydrocarbons in an
unproved area;
(ii) to find a new commercially productive Horizon in a field
previously found to be productive of hydrocarbons at
another Horizon; or
(iii) to significantly extend a known prospect.
20. "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.
21. "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
Section 708(b)(1)(A) of the Code or the Partnership
ceases to be a going concern.
22. "Horizon" shall mean a zone of a particular formation; that part
of a formation of sufficient porosity and permeability to form a
petroleum reservoir.
23. "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.
24. "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 November 1, 1999.
25. "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.
26. "Interim Closing Date" shall mean those date(s) after the
Initial Closing Date of the Partnership, but before the Offering
Termination Date, that the Managing General Partner, in its sole
discretion, applies additional Agreed Subscriptions to
additional Partnership activities, including drilling
activities.
4
<PAGE>
27. "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 Section 3.03(b)(2). All Investor General
Partners shall be of the same class and have the same rights.
28. "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.
29. "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.
30. "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
Section 3.03(b)(2), the Investor General Partners upon the
conversion of their Investor General Partner Units to Limited
Partner interests pursuant to Section 6.01(b), and any other
persons who are admitted to the Partnership as additional or
substituted Limited Partners. Except as provided in
Section 3.05(b), with respect to the required additional Capital
Contributions of Investor General Partners, all Limited Partners
shall be of the same class and have the same rights.
31. "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.
32. "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.
33. "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, 1999.
34. "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.
35. "Operator" shall mean the Managing General Partner, as operator
of Partnership Wells in Pennsylvania and the Managing General
Partner or an Affiliate as Operator of Partnership Wells in
other areas of the United States.
36. "Organization and Offering Costs" 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.
37. "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.
38. "Participants" shall mean the Managing General Partner to the
extent of its optional subscription under Section 3.03(b)(2),
the Limited Partners, and the Investor General Partners.
39. "Partners" shall mean the Managing General Partner, the Investor
General Partners, and the Limited Partners.
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40. "Partnership" shall mean Atlas-Energy for the Nineties-Public #8
Ltd., the Pennsylvania limited partnership formed pursuant to
this Agreement.
41. "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.
42. "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 Section 3.03(b)(1).
43. "Partnership Well" shall mean a well, some portion of the
revenues from which is received by the Partnership.
44. "Person" shall mean a natural person, partnership, corporation,
association, trust or other legal entity.
45. "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.
46. "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.
47. "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.
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.
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(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 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.
50. "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:
(i) 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
(ii) a transaction involving the conversion to corporate,
trust or association form of only the Partnership if, as
a consequence of the transaction, there will be no
significant adverse change in any of the following:
voting rights; the term of existence of the Partnership;
the Managing General Partner's compensation; and the
Partnership's investment objectives.
51. "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.
52. "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, but excluding
the Dealer-Manager fee, a .5% reimbursement of marketing
expenses, and a .5% reimbursement for bona fide accountable due
diligence expenses.
53. "Selling Agents" shall mean those broker-dealers selected by the
Dealer-Manager which will participate in the offer and sale of
the Units.
54. "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,
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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.
55. "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.
56. "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.
57. "Tax Matters Partner" shall mean the Managing General Partner.
58. "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 Section 3.03 and its subsections.
59. "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 Section 3.03(b)(2).
Limited Partners and Investor General Partners, including Affiliates of the
Managing General Partner, shall serve as Participants.
The Limited Partners shall not be bound by the obligations of the Partnership
other than as provided under the Pennsylvania Revised Uniform Limited
Partnership Act.
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 one or more Limited Partners pursuant to Section 3.02(c)
below, the Partnership shall return to the Original Limited Partner its
Capital Contribution and shall reacquire its Unit. The Original Limited
Partner shall then cease to be a Limited Partner in the Partnership with
respect to the Unit.
3.02(b). OFFERING OF INTERESTS. The Partnership is authorized to admit to the
Partnership at the Initial Closing Date, any Interim Closing Date(s), and the
Offering Termination Date additional Participants whose Agreed Subscriptions
for Units are accepted by the Managing General Partner if, after the
admission of the additional Participants, the Agreed Subscriptions of all
Participants do not exceed the number of Units set forth in Section 3.03(c)(1).
3.02(c). ADMISSION OF PARTICIPANTS. No action or consent by the Participants
shall be required for the admission of additional Participants pursuant to
this Agreement.
All subscribers' funds shall be held by an independent interest bearing
escrow holder and shall not be released to the Partnership until the receipt
of the minimum Partnership Subscription in Section 3.03(c)(2). Thereafter,
subscriptions may be paid directly to the Partnership account.
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3.02(d). DURATION OF THE OFFERING AND MINIMUM CAPITALIZATION.
3.02(d)(1). DURATION OF OFFERING. The offering of Units shall be terminated
not later than the earlier of:
(i) December 31, 1999; or
(ii) at such time as Agreed Subscriptions for the maximum Partnership
Subscription set forth in Section 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.
3.02(d)(2). MINIMUM CAPITALIZATION. If at the time of termination Agreed
Subscriptions for fewer than 100 Units have been received and accepted, then
all monies deposited by subscribers shall be promptly returned to them. They
shall receive interest earned thereon from the date the 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 the Participant to be bound by each and every
term of this Agreement.
3.03(b). SUBSCRIPTIONS BY MANAGING GENERAL PARTNER.
3.03(b)(1). MANAGING GENERAL PARTNER'S REQUIRED SUBSCRIPTION. The Managing
General Partner, as a general partner and not as a Participant, shall:
(i) contribute to the Partnership the Leases which will be drilled
by the Partnership on the terms set forth in Section 4.01(a)(4);
and
(ii) pay the costs charged to it pursuant to Section 5.01(a).
These amounts shall be paid as set forth in Section 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
Section 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 Section 3.03(a) and its subsections, and, subject to the
limitations on voting rights set forth in Section 4.03(c)(3), to that extent
shall be deemed a Participant in the Partnership for all purposes under this
Agreement.
Notwithstanding the foregoing, Selling Agents, and the Managing General
Partner, its officers, directors, and Affiliates shall not be required to pay
the Dealer-Manager fee, Sales Commissions, the .5% reimbursement of marketing
expenses, and the .5% reimbursement of the Selling Agent's bona fide
accountable due diligence expenses. Also, Registered Investment Advisors and
their clients may subscribe by paying only the Dealer-Manager fee and not the
Sales Commissions, the .5% reimbursement of marketing expenses, and the .5%
reimbursement of the Selling Agents' bona fide 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
Section 3.03(b)(1) and which may be
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amended to reflect the amount of any optional subscription under
Section 3.03 (b)(2). Execution of the Managing General Partner Signature Page
serves as an agreement by the Managing General Partner to be bound by each and
every term of this Agreement.
3.03(c). MAXIMUM AND MINIMUM PARTNERSHIP SUBSCRIPTION.
3.03(c)(1). MAXIMUM PARTNERSHIP SUBSCRIPTION. The maximum Partnership
Subscription excluding the Managing General Partner's required subscription
under Section 3.03(b)(1) may not exceed $18,000,000 (1,800 Units).
3.03(c)(2). MINIMUM PARTNERSHIP SUBSCRIPTION. The minimum Partnership
Subscription shall equal at least $1,000,000 (100 Units). The Managing General
Partner, its officers, directors, and Affiliates may purchase up to 10% of the
Partnership Subscription, none of which will be applied to satisfy the
$1,000,000 minimum.
The Partnership shall begin drilling operations after the receipt of the minimum
Partnership Subscription and the Initial Closing Date.
3.03(d). ACCEPTANCE OF SUBSCRIPTIONS.
3.03(d)(1). DISCRETION BY THE MANAGING GENERAL PARTNER. Acceptance of
subscriptions shall be discretionary with the Managing General Partner. The
Managing General Partner may reject any subscription for any reason it deems
appropriate.
3.03(d)(2). TIME PERIOD IN WHICH TO ACCEPT SUBSCRIPTIONS. A Participant's
subscription to the Partnership and the Managing General Partner's acceptance
thereof shall be evidenced by the execution of a Subscription Agreement by the
Participant and by the Managing General Partner.
Agreed Subscriptions shall be accepted or rejected by the Partnership within 30
days of their receipt; if rejected, all funds shall be returned to the
subscriber immediately.
3.03(d)(3). ADMISSION TO THE PARTNERSHIP. Upon the original sale of Units, the
Participants shall be admitted as Participants not later than 15 days after the
release from escrow of Participants' funds to the Partnership. 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). PARTICIPANT CAPITAL CONTRIBUTIONS. Each Participant shall make a
Capital Contribution to the Partnership equal to the sum of:
(i) the Agreed Subscription of the Participant; and
(ii) in the case of Investor General Partners, but not the Limited
Partners, the additional Capital Contributions required in
Section 3.05(b)(2).
Participants shall not be required to restore any deficit balances in their
Capital Accounts except as set forth in Section 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 Section 3.03(b)(1) and any optional Capital
Contribution as a Participant as provided in Section 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 the costs exceed:
(i) its Capital Contribution pursuant to Section 3.03(b); and
(ii) its share of undistributed revenues.
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These Capital Contributions shall be paid by the Managing General Partner at the
time the costs are required to be paid by the Partnership, but, in no event,
later than December 31, 2000.
3.04(b)(2). MINIMUM AMOUNT OF MANAGING GENERAL PARTNER'S REQUIRED CONTRIBUTION.
The Managing General Partner's aggregate Capital Contributions to the
Partnership (including Leases contributed pursuant to Section 3.03(b)(1)) shall
not be less than 22.15% of all Capital Contributions to 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)(3). UPON LIQUIDATION THE MANAGING GENERAL PARTNER MUST CONTRIBUTE
DEFICIT BALANCE IN ITS CAPITAL ACCOUNT. 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. This shall be
determined after taking into account all adjustments for the Partnership's
taxable year during which the liquidation occurs (other than adjustments made
pursuant to this requirement), by the end of the taxable year in which its
interest in the Partnership is liquidated or, if later, within 90 days after the
date of such liquidation.
3.04(b)(4). 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
Section 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 Section
3.03(b)(1) and pay the costs charged to it when incurred by the Partnership,
subject to Section 3.04(b)(1).
Any optional subscription under Section 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 Section 3.05(b).
3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL CONTRIBUTIONS OF THE
INVESTOR GENERAL PARTNERS.
3.05(b)(1). PAYMENT OF AGREED SUBSCRIPTIONS. 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.
3.05(b)(2). ADDITIONAL REQUIRED CAPITAL CONTRIBUTIONS OF THE INVESTOR GENERAL
PARTNERS. 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 before the conversion of
Investor General Units to Limited Partner interests pursuant to Section 6.01(b).
3.05(b)(3). DEFAULT PROVISIONS. 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
the defaulting Investor General Partner's share of Partnership liabilities and
obligations. In that event, the remaining Investor General Partners:
(i) shall have a first and preferred lien on the defaulting Investor
General Partner's interest in the Partnership to secure payment
of the amount in default plus interest at the legal rate;
(ii) shall be entitled to receive 100% of the defaulting Investor
General Partner's cash distributions directly from the
Partnership until the amount in default is recovered in full
plus interest at the legal rate; and
(iii) may commence legal action to collect the amount due plus
interest at the legal rate.
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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. The Managing General Partner shall not employ, or permit another to
employ, the funds and assets in any manner except for the exclusive benefit
of the Partnership. Neither this Agreement nor any other agreement between
the Managing General Partner and the Partnership shall contractually limit
any fiduciary duty owed to the Participants by the Managing General Partner
under applicable law, except as provided in Sections 4.01, 4.02, 4.04, 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.
3.06(c)(1). INVESTMENTS IN OTHER ENTITIES. Partnership funds may not be invested
in the securities of another person except in the following instances:
(i) investments in Working Interests or undivided Lease interests
made in the ordinary course of the Partnership's business;
(ii) temporary investments made as set forth in Section 3.06(c)(2);
(iii) multi-tier arrangements meeting the requirements of
Section 4.03(d)(15);
(iv) investments involving less than 5% of the Partnership
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.
3.06(c)(2). PERMISSIBLE INVESTMENTS PRIOR TO INVESTMENT IN PARTNERSHIP
ACTIVITIES. After the Offering Termination Date and until proceeds from the
offering are invested in the Partnership's operations, the proceeds may be
temporarily invested in income producing short-term, highly liquid investments,
in which there is appropriate safety of principal, such as U.S. Treasury Bills.
ARTICLE IV
CONDUCT OF OPERATIONS
4.01. ACQUISITION OF LEASES.
4.01(a). ASSIGNMENT TO PARTNERSHIP.
4.01(a)(1). IN GENERAL. The Managing General Partner shall select, acquire and
assign or cause to have assigned to the Partnership full or partial interests in
Leases, by any method customary in the 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). MANAGING GENERAL PARTNER'S DISCRETION AS TO TERMS AND BURDENS OF
ACQUISITION. Subject to the provisions of Section 4.03(d) and its subsections,
the acquisitions of Leases or other property may be made under any terms and
obligations, including 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.
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4.01(a)(4). COST OF LEASES. All Leases shall be acquired from the Managing
General Partner or its Affiliates and shall be credited towards the Managing
General Partner's required Capital Contribution set forth in Section 3.03(b)(1)
at the Cost of the Lease, unless the Managing General Partner shall have cause
to believe that Cost is materially more than the fair market value of the
property, in which case the credit for the 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. This opinion and any associated supporting information must
be maintained in the Partnership's records for six years.
4.01(a)(5). THE MANAGING GENERAL PARTNER, OPERATOR OR THEIR AFFILIATES' RIGHTS
IN THE REMAINDER INTERESTS. To the extent the Partnership does not acquire a
full interest in a Lease from the Managing General Partner or its Affiliates,
the remainder of the interest in the Lease may be held by the Managing General
Partner or its Affiliates which may either retain and exploit it for its own
account or sell or otherwise dispose of all or a part of the remaining interest.
Profits from the exploitation and/or disposition of their retained interests in
the Leases shall be for the benefit of the Managing General Partner or its
Affiliates to the exclusion of the Partnership.
4.01(a)(6). NO BREACH OF DUTY. Subject to the provisions of Section 4.03 and its
subsections, acquisition of Leases from the Managing General Partner, the
Operator or their Affiliates shall not be considered a breach of any obligation
owed by the Managing General Partner, the Operator or their Affiliates to the
Partnership or the Participants.
4.01(b). NO OVERRIDING ROYALTY INTERESTS. Neither the Managing General Partner,
the Operator nor any Affiliate shall retain any Overriding Royalty Interest on
the 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, 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). MANAGING GENERAL PARTNER'S DISCRETION. The Managing General Partner
shall take the steps which are necessary in its best judgment to render title to
the Leases to be acquired by the Partnership acceptable for the purposes of the
Partnership. The Managing General Partner shall be free, however, to use its own
best judgment in waiving title requirements. The Managing General Partner shall
not be liable to the Partnership or to the other parties for any mistakes of
judgment; nor shall the Managing General Partner be deemed to be making any
warranties or representations, express or implied, as to the validity or
merchantability of the title to the Leases assigned to the Partnership or the
extent of the interest covered thereby except as otherwise provided in the
Drilling and Operating Agreement.
4.01(c)(3). COMMENCEMENT OF OPERATIONS. No operation shall be commenced on the
Leases acquired by the Partnership unless the Managing General Partner is
satisfied that necessary title requirements have been satisfied.
4.02. CONDUCT OF OPERATIONS.
4.02(a). IN GENERAL. The Managing General Partner shall establish a program of
operations for the Partnership. Subject to the limitations contained in Article
III of this Agreement concerning the maximum Capital Contribution which can be
required of a Limited Partner, the Managing General Partner, the Limited
Partners, and the Investor General Partners agree to participate in the program
so established by the Managing General Partner.
4.02(b). MANAGEMENT. Subject to any restrictions contained in this Agreement,
the Managing General Partner shall exercise full control over all operations of
the Partnership.
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4.02(c). GENERAL POWERS OF THE MANAGING GENERAL PARTNER.
4.02(c)(1). IN GENERAL. Subject to the provisions of Section 4.03 and its
subsections, and to any authority which may be granted the Operator under
Section 4.02(c)(3)(b), the Managing General Partner shall have full authority to
do all things deemed necessary or desirable by it in the conduct of the business
of the Partnership. Without limiting the generality of the foregoing, the
Managing General Partner is expressly authorized to engage in:
(i) the making of all determinations of which Leases, wells and
operations will be participated in by the Partnership, which
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 the 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 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,
during drilling operations and $10,000,000 thereafter,
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. The 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 the Managing General Partner's
$11,000,000 liability insurance on the same basis as the
Managing General Partner and its Affiliates, including
the Managing General Partner's other Programs;
(vii) the use of the funds and revenues of the Partnership, and the
borrowing on behalf of, and the loan of money to, the
Partnership, on any terms it sees fit, for any purpose,
including without limitation 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)
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provided that the sale of all or substantially all of the assets
of the Partnership shall only be made as provided in Section
4.03(d)(6);
(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 the operation by any outside persons
participating therein.
4.02(c)(3). DELEGATION OF AUTHORITY.
4.02(c)(3)(a). IN GENERAL. The Managing General Partner may subcontract and
delegate all or any part of its duties hereunder to any entity chosen by it,
including an entity related to it. The party shall have the same powers in the
conduct of the duties as would the Managing General Partner. The delegation,
however, shall not relieve the Managing General Partner of its responsibilities
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. This 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 Section
4.03 and its subsections, any transaction which the Managing General Partner
is authorized to enter into on behalf of the Partnership under the authority
granted in this section and its subsections, may be entered into by the
Managing General Partner with itself or with any other general partner, the
Operator or any of their Affiliates.
4.02(d). ADDITIONAL POWERS. In addition to the powers granted the Managing
General Partner under Section 4.02(c) and its subsections or elsewhere in this
Agreement, the Managing General Partner, when specified, shall have the
following additional express powers.
4.02(d)(1). DRILLING CONTRACTS. 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 the Managing General Partner or its
Affiliates based on $37.81 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 the Managing General Partner 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.
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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:
(i) 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
(ii) to create, prepare, complete, execute, file, swear to, deliver,
endorse and record any and all instruments, assignments,
security agreements, financing statements, certificates and
other documents as may be necessary from time to time to
implement the borrowing powers granted under this Agreement.
4.02(d)(2)(b). FURTHER ACTION. Each 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. Each
party 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 when the 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 Participant,
the power of attorney shall survive the delivery of the assignment for the sole
purpose of enabling such attorney-in-fact to execute, acknowledge and file any
agreement, certificate, instrument or document necessary to effect the
substitution.
4.02(d)(2)(c). POWER OF ATTORNEY TO OPERATOR. The Managing General Partner is
hereby authorized to grant a Power of Attorney to the Operator on behalf of the
Partnership.
4.02(e). BORROWINGS AND USE OF PARTNERSHIP REVENUES.
4.02(e)(1). POWER TO BORROW OR USE PARTNERSHIP REVENUES.
4.02(e)(1)(a). IN GENERAL. If additional funds over the Participants' Capital
Contributions are needed for Partnership operations, then the Managing General
Partner may:
(i) use Partnership revenues for such purposes; or
(ii) the Managing General Partner and its Affiliates may advance to
the Partnership the funds necessary pursuant to
Section 4.03(d)(8)(b).
4.02(e)(1)(b). LIMITATION ON BORROWING. The borrowings (other than credit
transactions on open account customary in the industry to obtain goods and
services) shall be without recourse to the Investor General Partners and the
Limited Partners except as otherwise provided herein.
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(f). TAX MATTERS PARTNER.
4.02(f)(1). DESIGNATION OF TAX MATTERS PARTNER. The Managing General Partner
is hereby designated the Tax Matters Partner of the Partnership pursuant to
Section 6231(a)(7) of the Code. The Managing General Partner is authorized to
act in this capacity on
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behalf of the Partnership and the Participants and to take any action,
including settlement or litigation, which it in its sole discretion deems to
be in the best interest of the Partnership.
4.02(f)(2). COSTS INCURRED BY TAX MATTERS PARTNER. Costs incurred by the Tax
Matters Partner shall be considered a Direct Cost of the Partnership.
4.02(f)(3). NOTICE TO PARTICIPANTS OF IRS PROCEEDINGS. The Tax Matters Partner
shall notify all Participants of any partnership administrative proceedings
commenced by the Internal Revenue Service, and thereafter shall furnish all
Participants periodic reports at least quarterly on the status of the
proceedings.
4.02(f)(4). PARTICIPANT RESTRICTIONS. Each Participant agrees as follows:
(i) he will not file the statement described in Section
6224(c)(3)(B) of the Code prohibiting the Managing General
Partner as the Tax Matters Partner for the Partnership from
entering into a settlement on his behalf with respect to
partnership items (as such term is defined in Section 6231(a)(3)
of Code) of the Partnership;
(ii) he will not form or become and exercise any rights as a member
of a group of Partners having a 5% or greater interest in the
profits of the Partnership under Section 6223(b)(2) of the Code;
and
(iii) the Managing General Partner is authorized to file a
copy of this Agreement (or pertinent portions 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).
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. Limited Partners 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 unless
they also subscribe to the Partnership as Investor General Partners, or, in the
case of the Managing General Partner if it purchases Limited Partner Units.
4.03(a)(2). NO MANAGEMENT AUTHORITY OF PARTICIPANTS. Participants, other than
the Managing General Partner if it buys Units, shall have no power over the
conduct of the affairs of the Partnership. No Participant, other than the
Managing General Partner if it buys Units, shall take part in the management of
the business of the Partnership, or have the power to sign for or to bind the
Partnership.
4.03(b). REPORTS AND DISCLOSURES.
4.03(b)(1). ANNUAL REPORTS AND FINANCIAL STATEMENTS. Commencing with the 1999
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
2000 calendar year, a report within 75 days after the end of the first six
months of its calendar year, containing except as otherwise indicated, at least
the information set forth below:
(i) Audited financial statements of the Partnership, including a
balance sheet and statements of income, cash flow and Partners'
equity, which shall be prepared 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 the financial statements
present fairly the financial position, results of operations,
partners' equity and cash flows in accordance with generally
accepted accounting principles. Semiannual reports need not be
audited.
(ii) A summary itemization, by type and/or classification of the
total fees and compensation including any unaccountable, fixed
payment reimbursements for Administrative Costs and Operating
Costs, paid by the Partnership, or indirectly on behalf of the
Partnership, to the Managing General Partner, the Operator and
their Affiliates. In addition, Participants shall be provided
the percentage that the annual unaccountable, fixed fee
reimbursement for Administrative Costs bears to annual
Partnership revenues.
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(iii) 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 the Prospects.
(iv) A list of the wells drilled or abandoned by the Partnership
during the period of the report (indicating whether each of the
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.
(v) 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.
(vi) A schedule reflecting:
(a) the total Partnership costs;
(b) the costs paid by the Managing General Partner and the
costs paid by the Participants;
(c) the total Partnership revenues;
(d) the revenues received or credited to the Managing
General Partner and the revenues received and credited
to the Participants; and
(e) a reconciliation of the expenses and revenues in
accordance with the provisions of Article V.
4.03(b)(2). TAX INFORMATION. The Partnership shall, by March 15 of each year,
prepare, or supervise the preparation of, and transmit to each Participant the
information needed for the Participant to file 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.
4.03(b)(3). RESERVE REPORT. Annually, beginning January 1, 2001, a computation
of the total oil and gas Proved Reserves of the Partnership and the present
worth of the 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 the reserves
and a statement that because of the time period required to extract the reserves
the present value of revenues to be obtained in the future is less than if
immediately receivable.
In addition to the foregoing computation and required estimate, as soon as
possible, and in no event more than 90 days after the occurrence of an event
leading to reduction of the 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.
4.03(b)(4). COST OF REPORTS. The cost of all reports described herein shall be
paid by the Partnership as Direct Costs.
4.03(b)(5). PARTICIPANT ACCESS TO RECORDS. The Participants and/or their
representatives shall be permitted access to all records of the Partnership. The
Participant may inspect and copy any of the records after giving adequate notice
at any reasonable time.
Notwithstanding the foregoing, the Managing General Partner may keep logs, well
reports and other drilling and operating data confidential for reasonable
periods of time. The Managing General Partner may release information concerning
the operations of the Partnership to the sources that are customary in the
industry or required by rule, regulation, or order of any regulatory body.
4.03(b)(6). REQUIRED LENGTH OF TIME TO HOLD RECORDS. The Managing General
Partner shall maintain and preserve during the term of the Partnership and for
six years thereafter all accounts, books and other relevant documents. This
includes 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 Section 4.01(a)(4).
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4.03(b)(7). PARTICIPANT LISTS. The following provisions apply regarding access
to the list of Participants:
(i) an alphabetical list of the names, addresses and business
telephone numbers of the Participants along with the number of
Units held by each of them (the "Participant List") 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;
(ii) the Participant List shall be updated at least quarterly to
reflect changes in the information contained therein;
(iii) a copy of the Participant List shall be mailed to any
Participant requesting the Participant List within 10 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;
(iv) the purposes for which a Participant may request a copy of the
Participant List include, without limitation, matters relating
to Participant's voting rights under this Agreement and the
exercise of Participant's rights under the federal proxy laws;
and
(v) if the Managing General Partner neglects or refuses to exhibit,
produce, or mail a copy of the Participant List as requested,
the Managing General Partner shall be liable to any Participant
requesting the list for the costs, including attorneys fees,
incurred by that Participant for compelling the production of
the Participant List, and for actual damages suffered by any
Participant by reason of 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.
4.03(b)(8). STATE FILINGS. Concurrently with their transmittal to Participants,
and as required, the Managing General Partner shall file a copy of each report
provided for in this Section 4.03(b) with the California Commissioner of
Corporations and with the securities commissions of other states which request
the report.
4.03(c). MEETINGS OF PARTICIPANTS.
4.03(c)(1). PROCEDURE FOR A PARTICIPANT MEETING.
4.03(c)(1)(a). MEETINGS MAY BE CALLED BY MANAGING GENERAL PARTNER OR
PARTICIPANTS. Meetings of the Participants may be called by the Managing General
Partner.
Also, meetings of the Participants may be called by Participants whose Agreed
Subscriptions equal 10% or more of the Partnership Subscription for any matters
for which Participants may vote. The call for a meeting by Participants 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.
4.03(c)(1)(b). NOTICE REQUIREMENT. The Managing General Partner shall deposit in
the United States mail within 15 days after the receipt of the request, written
notice to all Participants of the meeting and the purpose of the meeting. The
meeting shall be held on a date not less than 30 days nor more than 60 days
after the date of the mailing of the notice, at a reasonable time and place.
Notwithstanding the foregoing, the date for notice of the meeting may be
extended for a period of up to 60 days, if in the opinion of the Managing
General Partner the additional time is necessary to permit preparation of proxy
or information statements or other documents required to be delivered in
connection with the meeting by the Securities and Exchange Commission or other
regulatory authorities.
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4.03(c)(1)(c). MAY VOTE BY PROXY. Participants shall have the right to vote at
any Participant meeting either:
(i) in person; or
(ii) by proxy.
4.03(c)(2). SPECIAL VOTING RIGHTS. At the request of Participants whose 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, and 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:
(i) amend this Agreement; provided however, any amendment may not
increase the duties or liabilities of any Participant or the
Managing General Partner or increase or decrease the profit or
loss sharing or required Capital Contribution of any Participant
or the Managing General Partner without the approval of the
Participant or the Managing General Partner. Furthermore, any
amendment may not affect the classification of Partnership
income and loss for federal income tax purposes without the
unanimous approval of all Participants;
(ii) dissolve the Partnership;
(iii) remove the Managing General Partner and elect a new Managing
General Partner;
(iv) elect a new Managing General Partner if the Managing General
Partner elects to withdraw from the Partnership;
(v) remove the Operator and elect a new Operator;
(vi) approve or disapprove the sale of all or substantially all of
the assets of the Partnership; and
(vii) cancel any contract for services with the Managing General
Partner, the Operator, or their Affiliates without penalty upon
60 days notice.
4.03(c)(3). RESTRICTIONS ON MANAGING GENERAL PARTNER'S VOTING RIGHTS. With
respect to Units owned by the Managing General Partner or its Affiliates, the
Managing General Partner and its Affiliates may vote or consent on all matters
other than those matters set forth in Section 4.03(c)(2)(iii) and (v) 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)(4). RESTRICTIONS ON LIMITED PARTNER VOTING RIGHTS. The exercise by
the Limited Partners of the rights granted Participants under Section
4.03(c), except for the special voting rights granted Participants under
Section 4.03(c)(2), shall be subject to the prior legal determination that
the grant or exercise of the powers will not adversely affect the limited
liability of Limited Partners. Notwithstanding the foregoing, if in the
opinion of counsel to the Partnership, the legal determination is not
necessary under Pennsylvania law to maintain the limited liability of the
Limited Partners, then it shall not be required. A legal determination under
this paragraph may be made either pursuant to:
(i) an opinion of counsel, the counsel being independent of the
Partnership and selected upon the vote of Limited Partners whose
Agreed Subscriptions equal a majority of the Agreed
Subscriptions held by Limited Partners; or
(ii) a declaratory judgment issued by a court of competent
jurisdiction.
The Investor General Partners may exercise the rights granted to the
Participants whether or not the Limited Partners can participate in the vote
if the Investor General Partners represent the requisite percentage of the
Participants necessary to take the action.
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4.03(d). TRANSACTIONS WITH THE MANAGING GENERAL PARTNER.
4.03(d)(1). TRANSFER OF EQUAL PROPORTIONATE INTEREST. When the Managing
General Partner or an Affiliate (excluding another Program in which the
interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) sells, transfers
or conveys any oil, gas or other mineral interests or property to the
Partnership, it must, at the same time, sell, transfer or convey to the
Partnership an equal proportionate interest in all its other property in the
same Prospect. Notwithstanding, a Prospect shall be deemed to consist of the
drilling or spacing unit on which the well will be drilled by the Partnership:
(i) if the geological feature to which the well will be drilled
contains Proved Reserves; and
(ii) the drilling or spacing unit protects against drainage.
With respect to 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. If the Partnership
abandons its interest in a well, then this restriction will continue for one
year following the abandonment.
If the area constituting the Partnership's Prospect is subsequently enlarged
to encompass any area 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 and the
activities of the Partnership were material in establishing the existence of
Proved Undeveloped Reserves which are attributable to the separate property
interest, then the separate property interest or a portion thereof shall be
sold, transferred or conveyed to the Partnership as set forth in
Sections 4.01(a)(4), 4.03(d)(1) and 4.03(d)(2).
Notwithstanding the foregoing, 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:
(i) the interest retained by the Managing General Partner or the
Affiliate is a proportionate Working Interest;
(ii) the respective obligations of the Managing General Partner or
its Affiliates and the Partnership are substantially the same
after the sale of the interest by the Managing General Partner
or its Affiliates; and
(iii) the Managing General Partner's interest in revenues does not
exceed the amount proportionate to its retained Working
Interest.
Neither the Managing General Partner nor any Affiliate shall retain any
Overriding Royalty Interests or other burdens on an interest sold or
transferred 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). NO SALE 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.
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4.03(d)(4). LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. During a period of five
years 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:
(i) if the Managing General Partner or the Affiliate (excluding
another Program in which the interest of the Managing General
Partner or its Affiliates is substantially similar to or less
than their interest in the Partnership) does not currently own
property in the Prospect separately from the Partnership, then
neither the Managing General Partner nor the Affiliate shall be
permitted to purchase an interest in the Prospect; and
(ii) if the Managing General Partner or the Affiliate (excluding
another Program in which the interest of the Managing General
Partner or its Affiliates is substantially similar to or less
than their interest in the Partnership) currently owns a
proportionate interest in the Prospect separately from the
Partnership, then the interest to be acquired shall be divided
between the Partnership and the Managing General Partner or the
Affiliate in the same proportion as is the other property in the
Prospect. Provided, however, if cash or financing is not
available to the Partnership to enable it to 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 Affiliated partnerships, provided that:
(i) 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
(ii) 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.
4.03(d)(7)(a). COMPETITIVE RATES. The Managing General Partner and any Affiliate
shall not render to the Partnership any oil field, equipage or other services
nor sell or lease to the Partnership any equipment or related supplies unless:
(i) the person is engaged, independently of the Partnership and as
an ordinary and ongoing business, in the business of rendering
the services or selling or leasing the equipment and supplies
to a substantial extent to other persons in the oil and gas
industry in addition to the partnerships in which the Managing
General Partner or an Affiliate has an interest; and
(ii) the compensation, price or rental therefor is competitive with
the compensation, price or rental of other persons in the area
engaged in the business of rendering comparable services or
selling or leasing comparable equipment and supplies which could
reasonably be made available to the Partnership.
If the person is not engaged in such a business, then the compensation, price or
rental shall be the Cost of the services, equipment or supplies to the person or
the competitive rate which could be obtained in the area, whichever is less.
4.03(d)(7)(b). IF NOT DISCLOSED IN THE PROSPECTUS OR THIS AGREEMENT THEN
SERVICES BY THE MANAGING GENERAL PARTNER MUST BE DESCRIBED IN A SEPARATE
CONTRACT AND CANCELLABLE. Any services for which the Managing General Partner or
an Affiliate is to receive compensation other than those described in this
Agreement or the Prospectus shall be set forth in a
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written contract which precisely describes the services to be rendered and
all compensation to be paid. These contracts are cancellable without penalty
upon 60 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). NO LOANS FROM THE PARTNERSHIP. No loans or advances shall be
made by the Partnership to the Managing General Partner or any Affiliate.
4.03(d)(8)(b). LOANS TO THE PARTNERSHIP. Neither the Managing General Partner
nor any Affiliate shall loan money to the Partnership if the interest to be
charged exceeds the Managing General Partner's or the Affiliate's interest
cost, or if 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.
Neither the Managing General Partner nor any Affiliate shall receive points
or other financing charges or fees, regardless of the amount, although the
actual amount of the charges incurred from third-party lenders may be
reimbursed to the Managing General Partner or the Affiliate.
4.03(d)(9). NO FARMOUTS. The Partnership shall not Farmout its Leases.
4.03(d)(10). NO COMPENSATING BALANCES. Neither the Managing General Partner
nor any Affiliate shall use the Partnership's funds as compensating balances
for its own benefit.
4.03(d)(11). FUTURE PRODUCTION. Neither the Managing General Partner nor any
Affiliate shall commit the future production of a well developed by the
Partnership exclusively for its own benefit.
4.03(d)(12). MARKETING ARRANGEMENTS. All benefits from marketing arrangements
or other relationships affecting the property of the Managing General Partner
or its Affiliates and the Partnership shall be fairly and equitably
apportioned according to the respective interests of each in the property.
The Managing General Partner shall treat all wells in a geographic area
equally concerning to whom and at what price the Partnership's 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 the gas sold in a geographic area by taking all money received
from the sale of all 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 pipeline
facilities and compression facilities, 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 when
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 before the time a
decision is 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), then 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:
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(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.
4.03(d)(16)(a). REQUIREMENT FOR APPRAISAL AND ITS ASSUMPTIONS. In connection
with a proposed Roll-Up, an appraisal of all Partnership assets shall be
obtained from a competent Independent Expert. If the appraisal will be
included in a prospectus used to offer securities of a Roll-Up Entity, then
the appraisal shall be filed with the 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 before the
announcement of the proposed Roll-Up transaction. The appraisal shall assume
an orderly liquidation of the Partnership's assets over a 12-month period.
The terms of the engagement of the Independent Expert shall clearly state
that the engagement is for the benefit of the Partnership and the
Participants. A summary of the independent appraisal, indicating all material
assumptions underlying the appraisal, shall be included in a report to the
Participants in connection with a proposed Roll-Up.
4.03(d)(16)(b). RIGHTS OF PARTICIPANTS WHO VOTE AGAINST PROPOSAL. In
connection with a proposed Roll-Up, Participants who vote "no" on the
proposal shall be offered the choice of:
(i) accepting the securities of the Roll-Up Entity offered in the
proposed Roll-Up;
(ii) remaining as Participants in the Partnership and preserving
their interests therein on the same terms and conditions as
existed previously; or
(iii) receiving cash in an amount equal to the Participants' pro rata
share of the appraised value of the net assets of the
Partnership.
4.03(d)(16)(c). NO ROLL-UP IF DIMINISHMENT OF VOTING RIGHTS. The Partnership
shall not participate in any proposed Roll-Up which, if approved, would
result in the diminishment of any Participant's voting rights under the
Roll-Up Entity's chartering agreement.
In no event shall the democracy rights of Participants in the Roll-Up Entity
be less than those provided for under Sections 4.03(c)(1) and 4.03(c)(2) of
this Agreement. If the Roll-Up Entity is a corporation, then the democracy
rights of Participants shall correspond to the democracy rights provided for
in this Agreement to the greatest extent possible.
4.03(d)(16)(d). NO ROLL-UP IF ACCUMULATION OF SHARES WOULD BE IMPEDED. The
Partnership shall not participate in any proposed Roll-Up transaction which
includes provisions 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).
The Partnership shall not participate in any proposed Roll-Up transaction
which would limit the ability of a Participant to exercise the voting rights
of its securities of the Roll-Up Entity on the basis of the number of Units
held by that Participant.
4.03(d)(16)(e). NO ROLL-UP IF ACCESS TO RECORDS WOULD BE LIMITED. The
Partnership shall not participate in a Roll-Up in which Participants' rights
of access to the records of the Roll-Up Entity will be less than those
provided for under Sections 4.03(b)(5), 4.03(b)(6) and 4.03(b)(7) of this
Agreement.
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4.03(d)(16)(f). COST OF ROLL-UP. The Partnership shall not participate in any
proposed Roll-Up transaction in which any of the costs of the transaction
would be borne by the Partnership if Participants whose Agreed Subscriptions
equal 75% of the Partnership Subscription do not vote to approve the proposed
Roll-Up.
4.03(d)(16)(g). ROLL-UP APPROVAL. The Partnership shall not participate in a
Roll-Up transaction unless the Roll-Up transaction is approved by
Participants whose 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). TRANSACTIONS MUST BE 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 Section 4.04(a)(3)
or withdraws pursuant to Section 4.04(a)(3)(f).
4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. In addition to the
compensation set forth in Sections 4.01(a)(4) and 4.02(d)(1), the Managing
General Partner shall receive the compensation set forth in
Sections 4.04(a)(2)(b) through 4.04(a)(2)(g).
4.04(a)(2)(a). CHARGES MUST BE NECESSARY AND REASONABLE. Charges by the
Managing General Partner for goods and services must be fully supportable as
to
(i) the necessity thereof; and
(ii) 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.
4.04(a)(2)(b). DIRECT COSTS. The Managing General Partner shall be reimbursed
for all Direct Costs. Direct Costs, however, shall be billed directly to and
paid by the Partnership to the extent practicable.
4.04(a)(2)(c). ADMINISTRATIVE COSTS. The Managing General Partner shall
receive an unaccountable, fixed payment reimbursement for its Administrative
Costs of $75 per well per month, 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, the 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 the Managing General Partner for the Partnership's
Administrative Costs. Finally, the Managing General Partner shall not receive
the unaccountable, fixed payment reimbursement of $75 per well per month for
plugged or abandoned wells.
4.04(a)(2)(d). GAS GATHERING. The Managing General Partner and its Affiliates
(which may include a limited partnership sponsored by an Affiliate of Atlas
America, Inc.) shall receive a gathering fee at a competitive rate for
gathering and transporting the Partnership's gas.
4.04(a)(2)(e). DEALER-MANAGER FEE. Subject to Section 3.03(b)(2), the
Dealer-Manager shall receive on each Unit sold to investors:
(i) a 2.5% Dealer-Manager fee;
(ii) a 7% Sales Commission;
(iii) a .5% reimbursement of marketing expenses; and
(iv) a .5% reimbursement of the Selling Agent's bona fide accountable
due diligence expenses.
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4.04(a)(2)(f). DRILLING AND OPERATING AGREEMENT. The Managing General Partner
and its Affiliates shall receive compensation as set forth in the Drilling
and Operating Agreement.
4.04(a)(2)(g). OTHER TRANSACTIONS. The Managing General Partner and its
Affiliates may enter into transactions pursuant to Section 4.03(d)(7) with the
Partnership and shall be entitled to compensation pursuant to such section.
4.04(a)(3). REMOVAL OF MANAGING GENERAL PARTNER.
4.04(a)(3)(a). MAJORITY VOTE REQUIRED TO REMOVE THE MANAGING GENERAL PARTNER.
The Managing General Partner may be removed at any time upon 60 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. If Participants vote to remove the Managing General
Partner from the Partnership, then Participants must elect by an affirmative
vote of Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription either:
(i) to terminate, dissolve and wind up the Partnership; or
(ii) to continue as a successor limited partnership under all
the terms of this Partnership Agreement, as provided in
Section 7.01(c).
If the Participants elect to continue as a successor limited partnership,
then the Managing General Partner shall not be removed until a substituted
Managing General Partner has been selected by an affirmative vote of
Participants whose Agreed Subscriptions equal a majority of the Partnership
Subscription and installed as such.
4.04(a)(3)(b). VALUATION OF MANAGING GENERAL PARTNER'S INTEREST IN THE
PARTNERSHIP. If the Managing General Partner is removed, then the Managing
General Partner's interest in the Partnership shall be determined by
appraisal by a qualified Independent Expert. The Independent Expert shall be
selected by mutual agreement between the removed Managing General Partner and
the incoming Managing General Partner. The appraisal shall take into account
an appropriate discount, to reflect the risk of recovery of oil and gas
reserves, but not less than that utilized in the most recent presentment
offer, if any.
The cost of the appraisal shall be borne equally by the removed Managing
General Partner and the Partnership.
4.04(a)(3)(c). INCOMING MANAGING GENERAL PARTNER'S OPTION TO PURCHASE. The
incoming Managing General Partner shall have the option to purchase 20% of
the removed Managing General Partner's interest for the value determined by
the Independent Expert.
4.04(a)(3)(d). METHOD OF PAYMENT. The method of payment for the removed
Managing General Partner's interest must be fair and must protect the
solvency and liquidity of the Partnership. The method of payment shall be as
follows:
(i) when the termination is voluntary, the method of payment
shall be a non-interest bearing unsecured promissory note with
principal payable, if at all, from distributions which the
Managing General Partner otherwise would have received under
the Partnership Agreement had the Managing General Partner not
been terminated; and
(ii) when the termination is involuntary, the method of payment shall
be an interest bearing promissory note coming due in no less
than five years with equal installments each year. The interest
rate shall be that charged on comparable loans.
4.04(a)(3)(e). TERMINATION OF CONTRACTS. The removed Managing General
Partner, at the time of its removal shall cause, to the extent it is legally
possible, its successor to be transferred or assigned all its rights,
obligations and interests as Managing General Partner of the Partnership in
contracts entered into by it on behalf of the Partnership. In any event, the
removed Managing General Partner shall cause its rights, obligations and
interests as Managing General Partner of the Partnership in any such contract
to terminate at the time of its removal.
Notwithstanding any other provision in this Agreement, the Partnership or the
successor Managing General Partner shall not be a party to any gas purchase
agreement that the Managing General Partner 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
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Partner shall not receive any interest in the Managing General Partner's and
its Affiliates' pipeline or gathering system or compression facilities.
4.04(a)(3)(f). THE MANAGING GENERAL PARTNER'S RIGHT TO VOLUNTARILY WITHDRAW.
At any time beginning 10 years after the Offering Termination Date 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. If the
Managing General Partner withdraws, then the following conditions shall apply:
(i) the Managing General Partner's interest in the Partnership shall
be determined as described in Section 4.04(a)(3)(b) above with
respect to removal; and
(ii) the interest shall be distributed to the Managing General
Partner as described in Section 4.04(a)(3)(d)(i) above.
Any successor Managing General Partner shall have the option to purchase 20%
of the withdrawing Managing General Partner's interest in the Partnership at
the value determined as described above with respect to removal.
4.04(a)(3)(g). THE MANAGING GENERAL PARTNER'S RIGHT TO WITHDRAW PROPERTY
INTEREST. The Managing General Partner has the right at any time to withdraw
a property interest held by the Partnership in the form of a Working Interest
in the Partnership Wells equal to or less than its respective interest in the
revenues of the Partnership pursuant to the conditions set forth in
Section 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 the 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)(1). STANDARDS FOR THE MANAGING GENERAL PARTNER NOT INCURRING
LIABILITY TO THE PARTNERSHIP OR PARTICIPANTS. The Managing General Partner,
the Operator, and their Affiliates shall not have any liability whatsoever to
the Partnership or to any Participant for any loss suffered by the
Partnership or Participants which arises out of any action or inaction of the
Managing General Partner, the Operator, or their Affiliates if:
(i) the Managing General Partner, the Operator, and their Affiliates
determined in good faith that the course of conduct was in the
best interest of the Partnership;
(ii) the Managing General Partner, the Operator, and their Affiliates
were acting on behalf of, or performing services for, the
Partnership; and
(iii) the course of conduct did not constitute negligence or
misconduct of the Managing General Partner, the Operator, or
their Affiliates.
4.05(a)(2). STANDARDS FOR MANAGING GENERAL PARTNER INDEMNIFICATION. The
Managing General Partner, the Operator, and their Affiliates shall be
indemnified by the Partnership against any losses, judgments, liabilities,
expenses and amounts paid in settlement of any claims sustained by them in
connection with the Partnership, provided that:
(i) the Managing General Partner, the Operator, and their Affiliates
determined in good faith that the course of conduct which caused
the loss or liability was in the best interest of the
Partnership;
(ii) the Managing General Partner, the Operator, and their Affiliates
were acting on behalf of, or performing services for, the
Partnership; and
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(iii) the course of conduct was not the result of negligence or
misconduct of the Managing General Partner, the Operator, or
their Affiliates.
Provided, however, payments arising from such indemnification or agreement to
hold harmless are recoverable only out of the tangible net assets of the
Partnership, including any insurance proceeds.
4.05(a)(3). STANDARDS FOR SECURITIES LAW INDEMNIFICATION. Notwithstanding
anything to the contrary contained in the above, the Managing General
Partner, the Operator, and their Affiliates and any person acting as a
broker-dealer shall not be indemnified for any losses, liabilities or
expenses arising from or out of an alleged violation of federal or state
securities laws by such party unless:
(i) there has been a successful adjudication on the merits of each
count involving alleged securities law violations as to the
particular indemnitee;
(ii) the claims have been dismissed with prejudice on the merits by a
court of competent jurisdiction as to the particular indemnitee;
or
(iii) a court of competent jurisdiction approves a settlement of
the claims against a particular indemnitee and finds that
indemnification of the settlement and the related costs
should be made, and the court considering the request for
indemnification has been advised of the position of the
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.
4.05(a)(4). STANDARDS FOR ADVANCEMENT OF FUNDS TO THE MANAGING GENERAL
PARTNER AND INSURANCE. The advancement of Partnership funds to the Managing
General Partner, the Operator, or their Affiliates for legal expenses and
other costs incurred as a result of any legal action for which
indemnification is being sought is permissible only if the Partnership has
adequate funds available and the following conditions are satisfied:
(i) the legal action relates to acts or omissions with respect
to the performance of duties or services on behalf of the
Partnership;
(ii) the legal action is initiated by a third party who is not a
Participant, or the legal action is initiated by a Participant
and a court of competent jurisdiction specifically approves the
advancement; and
(iii) the Managing General Partner or its Affiliates undertake to
repay the advanced funds to the Partnership, together with the
applicable legal rate of interest thereon, in cases in which
such party is found not to be entitled to indemnification.
The Partnership shall not bear the cost of that portion of insurance which
insures the Managing General Partner, the Operator, or their Affiliates for
any liability for which the Managing General Partner, the Operator, or their
Affiliates could not be indemnified pursuant to Sections 4.05(a)(1) and
4.05(a)(2).
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, the Managing General Partner agrees to use its corporate assets
and not the assets of the Partnership to indemnify each of the Investor
General Partners against all Partnership related liabilities which exceed the
Investor General Partner's interest in the undistributed net assets of the
Partnership and insurance proceeds, if any. Further, the Managing General
Partner agrees to indemnify each Investor General Partner against any
personal liability as a result of the unauthorized acts of another Investor
General Partner.
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If the Managing General Partner provides indemnification, then 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 the Managing General Partner.
4.05(c). ORDER OF PAYMENT OF CLAIMS. Claims shall be paid as follows:
(i) first out of any insurance proceeds;
(ii) second out of the assets and revenues of the Partnership; and
(iii) last by the Managing General Partner as provided in
Sections 3.05(b)(2) and (3) and 4.05(b).
No Limited Partner shall be required to reimburse the Managing General Partner,
the Operator, or their Affiliates or the Investor General Partners for any
liability in excess of his agreed Capital Contribution, except:
(i) for a liability resulting from the Limited Partner's
unauthorized participation in Partnership management; or
(ii) from some other breach by the Limited Partner of this Agreement.
4.05(d). AUTHORIZED TRANSACTIONS ARE NOT DEEMED TO BE A BREACH. No
transaction entered into or action taken by the Partnership or the Managing
General Partner, the Operator, or their Affiliates, which is authorized by
this Agreement 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.
4.06(a). THE MANAGING GENERAL PARTNER MAY PURSUE OTHER OIL AND GAS ACTIVITIES
FOR ITS OWN ACCOUNT. The Managing General Partner, the Operator, and their
Affiliates are now engaged, and will engage in the future, for their own
account and for the account of others, including other investors, in all
aspects of the oil and gas business. This includes 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,
the Managing General Partner, the Operator, and their Affiliates may do the
following:
(i) may continue its activities, or initiate further such
activities, individually, jointly with others, or as a part of
any other limited or general partnership, tax partnership, joint
venture, or other entity or activity to which they are or may
become a party, in any locale and in the same fields, areas of
operation or prospects in which the Partnership may likewise be
active;
(ii) may reserve partial interests in Leases being assigned to the
Partnership or any other interests not expressly prohibited by
this Agreement;
(iii) may deal with the Partnership as independent parties or through
any other entity in which they may be interested;
(iv) may conduct business with the Partnership as set forth herein;
and
(v) may participate in such other investor operations, as investors
or otherwise.
The Managing General Partner and its Affiliates shall not be required to
permit the Partnership or the Participants to participate in any 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.
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4.06(b). MANAGING GENERAL PARTNER MAY MANAGE MULTIPLE PARTNERSHIPS. The
Managing General Partner or its Affiliates may manage multiple Programs
simultaneously.
4.06(c). PARTNERSHIP HAS NO INTEREST IN GAS CONTRACTS OR PIPELINES AND
GATHERING SYSTEMS. Notwithstanding any other provision in this Agreement, the
Partnership shall not be a party to any gas supply agreement that the
Managing General Partner, the Operator, or their Affiliates enter 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 the
Managing General Partner's, the Operator's, and their Affiliates' pipeline or
gathering system or compression facilities.
ARTICLE V
PARTICIPATION IN COSTS AND REVENUES,
CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS
5.01. PARTICIPATION IN COSTS AND REVENUES. Except as otherwise provided in
this Agreement, costs and revenues shall be charged and credited to the
Managing General Partner and the Participants as set forth in this
Section 5.01 and its subsections.
5.01(a). COSTS. Costs shall be charged as set forth below.
5.01(a)(1). ORGANIZATION AND OFFERING COSTS. Organization and Offering Costs
shall be charged 100% to the Managing General Partner. For purposes of
sharing in revenues, pursuant to Section 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. Any 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 these amounts towards its required Capital
Contribution.
5.01(a)(2). INTANGIBLE DRILLING COSTS. Intangible Drilling Costs shall be
charged 100% to the Participants.
5.01(a)(3). TANGIBLE COSTS. Tangible Costs shall be charged 43.75% to the
Managing General Partner and 56.25% to the Participants.
5.01(a)(4). OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER
COSTS. Operating Costs, Direct Costs, Administrative Costs, and all other
Partnership costs not specifically allocated shall be charged to the parties
in the same ratio as the related production revenues are being credited.
5.01(a)(5). ALLOCATION OF INTANGIBLE DRILLING COSTS AND TANGIBLE COSTS AT
PARTNERSHIP CLOSINGS. Intangible Drilling Costs and the Participants' share
of Tangible Costs of a well or wells to be drilled and completed with the
proceeds of a Partnership closing shall be charged 100% to the Participants
who are admitted to the Partnership in that closing and shall not be
reallocated to take into account other Partnership closings.
Although the proceeds of each Partnership closing will be used to pay the
costs of drilling different wells, each Participant will pay the same amount
of the costs regardless of when he subscribes.
5.01(a)(6). LEASE COSTS. The Leases shall be contributed to the Partnership
as set forth in Section 4.01(a)(4).
5.01(b). REVENUES. Revenues of the Partnership from all sources and wells
shall be commingled and credited as set forth below.
5.01(b)(1). ALLOCATION OF REVENUES UPON DISPOSITION OF PROPERTY. If the
Partners' Capital Accounts are adjusted to reflect the simulated depletion of
an oil or gas property of the Partnership, then 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,
then 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 the Managing General Partner in
an amount equal to the difference between the fair market value of the Lease
at the time it was contributed to the Partnership and its simulated or actual
adjusted tax basis at such time. Finally, any excess shall be credited to the
parties in accordance with the sharing ratios provided in Section 5.01(b)(4),
below.
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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.
5.01(b)(2). INTEREST. Interest earned on Agreed Subscriptions before the
Offering Termination Date pursuant to Section 3.05(b)(1) shall be credited to
the accounts of the respective subscribers who paid the 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 Section 5.01(b)(4),
below.
5.01(b)(3). SALE OR DISPOSITION OF EQUIPMENT. Proceeds from the sale or
disposition of equipment shall be credited to the parties charged with the
costs of such equipment in the ratio in which such costs were charged.
5.01(b)(4). OTHER REVENUES. All other revenues of the Partnership shall be
credited 71% to the Participants and 29% to the Managing General Partner
subject to Sections 5.01(b)(4)(a).
5.01(b)(4)(a). SUBORDINATION. The Managing General Partner shall subordinate
up to 40% of its 29% share of Partnership Net Production Revenues (i.e. up to
11.6% 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 12-month periods of
Partnership operations. The subordination shall begin with the first
distribution of revenues to the Participants. The Managing General Partner,
however, shall not subordinate an amount greater than 40% of its 29% share of
Partnership Net Production Revenues (I.E., net of the related costs as
provided in Section 5.01(a)(4)) in any such distribution period.
The subordination shall be determined by:
(i) carrying forward to subsequent 12-month periods the amount, if
any, by which cumulative cash distributions to Participants
(including any subordination payments) are less than:
(a) 10% of Participants' Agreed Subscriptions in the first
12-month period;
(b) 20% of Participants' Agreed Subscriptions in the second
12-month period;
(c) 30% of Participants' Agreed Subscriptions in the third
12-month period; or
(d) 40% of Participants' Agreed Subscriptions in the fourth
12-month period (no carry forward is required if such
distributions are less than 50% of Participants' Agreed
Subscriptions in the fifth 12-month period because the
Managing General Partner's subordination obligation
terminates upon the expiration of the fifth 12-month
period); and
(ii) reimbursing the Managing General Partner for any previous
subordination payments to the extent cumulative cash
distributions to Participants (including any subordination
payments) would exceed:
(a) 10% of Participants' Agreed Subscriptions in the first
12-month period;
(b) 20% of Participants' Agreed Subscriptions in the second
12-month period;
(c) 30% of Participants' Agreed Subscriptions in the third
12-month period;
(d) 40% of Participants' Agreed Subscriptions in the fourth
12-month period; or
(e) 50% of Participants' Agreed Subscriptions in the fifth
12-month period.
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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 after the distributions. Also, no subordination payments to
Participants or reimbursements to the Managing General Partner shall be made
after the expiration of the fifth 12-month subordination period.
Subject to the foregoing provisions of this Section 5.01(b)(4)(a), 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.
5.01(b)(5). COMMINGLING OF REVENUES FROM ALL PARTNERSHIP WELLS. The revenues
from all Partnership wells will be commingled, so regardless of when a
Participant subscribes he will share in the revenues from all wells on the
same basis as the other Participants.
5.01(c). ALLOCATIONS.
5.01(c)(1). ALLOCATIONS AMONG PARTICIPANTS. Except as provided otherwise in
this Agreement, costs and revenues charged 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
Section 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). MANAGING GENERAL PARTNER'S DISCRETION IN MAKING ALLOCATIONS FOR
FEDERAL INCOME TAX PURPOSES. In determining the proper method of allocating
charges or credits among the parties, or in making any other allocations
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 FOR EACH PARTY TO THE AGREEMENT. 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.
5.02(b)(1). GENERAL STANDARD. Except as otherwise provided in this Agreement,
the Capital Account of each party shall be determined and maintained in
accordance with Treas. Reg. Section 1.704-l(b)(2)(iv) and shall be increased
by:
(i) the amount of money contributed by him to the Partnership;
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(ii) the fair market value of property contributed by him (without
regard to Section 7701(g) of the Code) to the Partnership (net
of liabilities secured by the contributed property that the
Partnership is considered to assume or take subject to under
Section 752 of the Code); and
(iii) allocations to him of Partnership income and gain (or items
thereof), including income and gain exempt from tax and income
and gain described in Treas. Reg. Section 1.704-l(b)(2)(iv)(g),
but excluding income and gain described in Treas. Reg.
Section 1.704-l(b)(4)(i);
and shall be decreased by:
(iv) the amount of money distributed to him by the Partnership;
(v) the fair market value of property distributed to him (without
regard to Section 7701(g) of the Code) by the Partnership (net
of liabilities secured by the distributed property that he is
considered to assume or take subject to under Section 752 of the
Code);
(vi) allocations to him of Partnership expenditures described in
Section 705(a)(2)(B) of the Code; and
(vii) allocations to him of Partnership loss and deduction (or items
thereof), including loss and deduction described in Treas. Reg.
Section 1.704-l(b)(2)(iv)(g), but excluding items described in
(vi) above, and loss or deduction described in Treas. Reg.
Section 1.704-l(b)(4)(i) or (iii).
5.02(b)(2). EXCEPTION. If Treas. Reg. Section 1.704-l(b)(2)(iv) fails to
provide guidance, Capital Account adjustments shall be made in a manner that:
(i) maintains equality between the aggregate governing Capital
Accounts of the 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
Section 4.04(a)(2) only to the extent of the Managing General Partner's
distributive share of any Partnership deduction, loss, or other downward
Capital Account adjustment resulting from such payments.
5.02(d). DISCRETION OF MANAGING GENERAL PARTNER IN THE METHOD OF MAINTAINING
CAPITAL ACCOUNTS. Notwithstanding any other provisions of this Agreement, the
method of maintaining Capital Accounts may be changed from time to time, in
the discretion of the Managing General Partner, to take into consideration
Section 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 Section 704(c) of the Code and the regulations thereunder) on
the Partnership's books, in accordance with Treas. Reg.
Section 1.704-l(b)(2)(iv)(f).
5.02(f). AMOUNT OF BOOK ITEMS. In cases where Section 704(c) of the Code or
Section 5.02(e) applies, Capital Accounts shall be adjusted in accordance with
Treas. Reg. Section 1.704-l(b)(2)(iv)(g) for allocations of depreciation,
depletion, amortization and gain and loss, as computed for book purposes,
with respect to such property.
5.03. ALLOCATION OF INCOME, DEDUCTIONS AND CREDITS.
5.03(a). IN GENERAL.
5.03(a)(1). DEDUCTIONS ARE ALLOCATED TO PARTY CHARGED WITH EXPENDITURE. To
the extent permitted by law and except as otherwise provided in this
Agreement, all deductions and credits, including, but not limited to,
intangible drilling and development costs and depreciation, shall be
allocated to the party who has been charged with the expenditure giving rise
to
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the deductions and credits; and to the extent permitted by law, these parties
shall be entitled to the deductions and credits in computing taxable income
or tax liabilities to the exclusion of any other party. Also, any Partnership
deductions that would be nonrecourse deductions if they were not attributable
to a loan made or guaranteed by the Managing General Partner or its
Affiliates shall be allocated to the Managing General Partner to the extent
required by law.
5.03(a)(2). INCOME AND GAIN ALLOCATED IN ACCORDANCE WITH REVENUES. Except as
otherwise provided in this Agreement, all items of income and gain, including
gain on disposition of assets, shall be allocated in accordance with the
related revenue allocations set forth in Section 5.01(b) and its subsections.
5.03(b). TAX BASIS OF EACH PROPERTY. Subject to Section 704(c) of the Code,
the tax basis of each oil and gas property for computation of cost depletion
and gain or loss on disposition shall be allocated and reallocated when
necessary based upon the capital interest in the Partnership as to the
property and the capital interest in the Partnership for this purpose as to
each property shall be considered to be owned by the parties hereto in the
ratio in which the expenditure giving rise to the tax basis of the property
has been charged as of the end of the year.
5.03(c). GAIN OR LOSS ON OIL AND GAS PROPERTIES. Each party shall separately
compute its gain or loss on the disposition of each oil and gas property in
accordance with the provisions of Section 613A(c)(7)D) of the Code, and the
calculation of the gain or loss shall consider the party's adjusted basis in
his property interest computed as provided in Section 5.03(b) and the party's
allocable share of the amount realized from the disposition of the property.
5.03(d). GAIN ON DEPRECIABLE PROPERTY. Gain from each sale or other
disposition of depreciable property shall be allocated to each party whose
share of the proceeds from the sale or other disposition exceeds its
contribution to the adjusted basis of the property in the ratio that the
excess bears to the sum of the excesses of all parties having an excess.
5.03(e). LOSS ON DEPRECIABLE PROPERTY. Loss from each sale, abandonment or
other disposition of depreciable property shall be allocated to each party
whose contribution to the adjusted basis of the property exceeds its share of
the proceeds from the sale, abandonment or other disposition in the
proportion that the excess bears to the sum of the excesses of all parties
having an excess.
5.03(f). ALLOCATION IF RECAPTURE TREATED AS ORDINARY INCOME. Any recapture
treated as an increase in ordinary income by reason of Sections 1245, 1250, or
1254 of the Code shall be allocated to the parties in the amounts in which
the recaptured items were previously allocated to them; provided that to the
extent recapture allocated to any party is in excess of the party's gain from
the disposition of the property, the excess shall be allocated to the other
parties but only to the extent of the other parties' gain from the
disposition of the property.
5.03(g). TAX CREDITS. If a Partnership expenditure (whether or not
deductible) that gives rise to a tax credit in a Partnership taxable year
also gives rise to valid allocations of Partnership loss or deduction (or
other downward Capital Account adjustments) for the year, then the Partners'
interests in the Partnership with respect to the credit (or the cost giving
rise thereto) shall be in the same proportion as the Partners' respective
distributive shares of the 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 Participant having a
deficit Capital Account balance as of the end of the taxable year to which
the allocation relates, if charged to the Participant, (to the extent the
Participant is not required to restore the deficit to the Partnership),
taking into account:
(i) adjustments that, as of the end of the year, reasonably are
expected to be made to the Participant'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 the Participant
pursuant to Sections 704(e)(2) and 706(d) of the Code and Treas.
Reg. Section 1.751-1(b)(2)(ii); and
(iii) distributions that, as of the end of such year, reasonably are
expected to be made to the Participant to the extent they exceed
offsetting increases to the Participant's Capital Account
(assuming for this purpose that the fair
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market value of Partnership property equals its adjusted tax
basis) that reasonably are expected to occur during (or prior
to) the Partnership taxable years in which the distributions
reasonably are expected to be made,
shall be charged to the Managing General Partner. Further, the Managing
General Partner shall be credited with an additional amount of Partnership
income or gain equal to the amount of such loss or deduction as quickly as
possible (to the extent such chargeback does not cause or increase deficit
balances in the Participants' Capital Accounts which are not required to be
restored to the Partnership).
Notwithstanding any provisions of this Agreement to the contrary, if a
Participant unexpectedly receives an adjustment, allocation, or distribution
described in (i), (ii), or (iii) above, or any other distribution, which
causes or increases a deficit balance in the Participant's Capital Account
which is not required to be restored to the Partnership, the Participant
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). MINIMUM GAIN CHARGEBACK. To the extent there is a net decrease
during a Partnership taxable year in the minimum gain attributable to a
Partner nonrecourse debt, then any Partner with a share of the minimum gain
attributable to such debt at the beginning of such year shall be allocated
items of Partnership income and gain in accordance with Treas. Reg.
Section 1.704-2(i).
5.03(j). PARTNERS' ALLOCABLE SHARES. Except as otherwise provided in this
Agreement, each 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). ELECTION TO DEDUCT INTANGIBLE COSTS. The Partnership's federal
income tax return shall be made in accordance with an election under the
option granted by the Code to deduct intangible drilling and development
costs.
5.04(b). NO ELECTION OUT OF SUBCHAPTER K. No election shall be made by the
Partnership, any Partner, or the Operator for the Partnership to be excluded
from the application of the 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). SECTION 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 by Sections 734 and 743 of the Code.
5.05. DISTRIBUTIONS.
5.05(a). IN GENERAL.
5.05(a)(1). QUARTERLY REVIEW OF ACCOUNTS. The Managing General Partner shall
review the accounts of the Partnership at least quarterly to determine
whether cash distributions are appropriate and the amount to be distributed,
if any.
5.05(a)(2). DISTRIBUTIONS. The Partnership shall distribute funds to the
Managing General Partner and the Participants allocated to their accounts
which the Managing General Partner deems unnecessary to retain by the
Partnership.
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5.05(a)(3). NO BORROWINGS. 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 revenues and costs shall be made in accordance
with generally accepted accounting principles, consistently applied.
5.05(a)(4). DISTRIBUTIONS TO THE MANAGING GENERAL PARTNER. Cash distributions
from the Partnership to the Managing General Partner shall only be made in
conjunction with distributions to Participants and only out of funds properly
allocated to the Managing General Partner's account.
5.05(a)(5). RESERVE. 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
the 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 12 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. 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 Section 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. 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.
6.01(a)(1). CONSENT REQUIRED. In addition to other restrictions on
transferability provided in this Agreement, Units 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 written consent of the
Managing General Partner.
6.01(a)(2). RIGHTS OF ASSIGNEE. Unless an assignee becomes a substituted
Participant in accordance with the provisions set forth below, he shall not
be entitled to any of the rights granted to a Participant 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). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER
INTERESTS.
6.01(b)(1). AUTOMATIC CONVERSION. 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.
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6.01(b)(2). INVESTOR GENERAL PARTNERS SHALL HAVE CONTINGENT LIABILITY. Upon
conversion the Investor General Partners shall be Limited Partners entitled
to limited liability; however, they shall remain liable to the Partnership
for any additional Capital Contribution required for their proportionate
share of any Partnership obligation or liability arising before the
conversion of their Units as provided in Section 3.05(b)(2).
6.01(b)(3). CONVERSION SHALL NOT AFFECT ALLOCATIONS. The conversion shall not
affect the allocation to any Participant of any item of Partnership income,
gain, loss, deduction or credit or other item of special tax significance
(other than Partnership liabilities, if any). Further, the conversion shall
not affect any Participant's interest in the Partnership's oil and gas
properties and unrealized receivables.
6.01(b)(4). RIGHT TO CONVERT IF REDUCTION OF INSURANCE. Notwithstanding the
foregoing, the Managing General Partner shall notify all Participants at
least 30 days before the effective date of any adverse material change in the
Partnership's insurance coverage. If the insurance coverage is to be
materially reduced, then the Investor General Partners shall have the right
to convert their Units into Limited Partner interests before the 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 Participant 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 set forth in
Sections 6.02(a)(1) and 6.02(a)(2).
6.02(a)(1). SECURITIES LAWS RESTRICTION. Subject to transfers permitted by
Section 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. Subject to transfers permitted by
Section 6.04 and transfers by operation of law, no sale, exchange, transfer or
assignment shall be made which, in the opinion of counsel to the Partnership,
would result in:
(i) the Partnership being considered to have been terminated for
purposes of Section 708 of the Code; or
(ii) the Partnership being treated as a "publicly-traded" partnership
for purposes of Section 469(k) of the Code.
6.02(a)(3). SUBSTITUTE PARTICIPANT.
6.02(a)(3)(a). PROCEDURE TO BECOME SUBSTITUTE PARTICIPANT. An assignee of a
Participant's interest in the Partnership shall become a substituted Participant
entitled to all the rights of a Participant if, and only if:
(i) the assignor of the Unit gives the assignee the right;
(ii) the Managing General Partner consents to the substitution, which
consent shall be in the Managing General Partner's absolute
discretion;
(iii) the assignee of the Unit pays to the Partnership all costs and
expenses incurred in connection with the substitution; and
(iv) the assignee of the Unit executes and delivers the instruments
(in form and substance satisfactory to the Managing General
Partner) necessary or desirable to effect the substitution and
to confirm the agreement of the assignee to be bound by all of
the terms and provisions of this Agreement.
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6.02(a)(3)(b). RIGHTS OF SUBSTITUTE PARTICIPANT. A substitute Participant is
entitled to all of the rights attributable to full ownership of the assigned
Units including the right to vote.
6.02(b). EFFECT OF TRANSFER.
6.02(b)(1). AMENDMENT OF RECORDS. The Partnership shall amend its records at
least once each calendar quarter to effect the substitution of substituted
Participants.
Any transfer permitted hereunder when the assignee does not become a
substituted Participant 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.
6.02(b)(2). TRANSFER DOES NOT RELIEVE TRANSFEROR OF CERTAIN COSTS. No
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 before or after the transfer.
6.02(b)(3). TRANSFER DOES NOT REQUIRE AN ACCOUNTING. No transfer of a Unit
shall require an accounting by the Managing General Partner. Also, no
transfer shall grant rights hereunder (including the exercise of any
elections) as between the transferring parties and the remaining parties
hereto to more than one party unanimously designated by the transferees and,
if he should have retained an interest hereunder, the transferor.
6.02(b)(4). NOTICE. Until the Managing General Partner receives a proper
designation acceptable to it, the Managing General Partner shall continue to
account only to the person to whom it was furnishing notices before the time
pursuant to Section 8.01 and its subsections. That 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. In no event shall the repayments, costs, interest, or other charges
related to the borrowing be charged to the account of the Participants.
In addition, subject to a required participation of not less than 1% 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:
(i) the withdrawal is necessary to satisfy the bona fide request of
its creditors; or
(ii) the withdrawal is approved by Participants whose Agreed
Subscriptions equal a majority of the Partnership Subscription.
6.04. PRESENTMENT.
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. A Participant, however, is not
obligated to present his Units for repurchase.
The Managing General Partner shall not be obligated to 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.
38
<PAGE>
A Participant may present his Units in writing to the Managing General
Partner every year beginning in 2004. The presentment must be made within 120
days of the reserve report set forth in Section 4.03(b)(3). No repurchase
shall be considered effective until the payment has been made to the
Participant in cash.
In addition, in accordance with Treas. Reg. Section 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). REQUIREMENT FOR INDEPENDENT PETROLEUM CONSULTANT EVERY OTHER YEAR.
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 an Independent Expert. The Managing General
Partner shall estimate the present worth of future net revenues attributable
to the Partnership's interest in the Proved Reserves. In making this
estimate, the Managing General Partner shall use a discount rate equal to 10%
and 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 in
Section 6.04(c).
6.04(c). CALCULATION OF PRESENTMENT PRICE. The presentment 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 presentment 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 Section 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. However, 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 presentment price, the
distributions shall be discounted at the same rate used to take
into account the risk factors employed to determine the present
worth of the Partnership's Proved Reserves.
6.04(d). FURTHER ADJUSTMENT MAY BE ALLOWED. The presentment price may be
further adjusted by the Managing General Partner for estimated changes
therein from the date of such report to the date of payment of the
presentment 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 before the request for repurchase; and
(ii) by reason of any of the following occurring before payment of
the presentment 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(e). SELECTION BY LOT. If less than all interests presented at any time are
to be purchased, then the Participants whose interests are to be purchased will
be selected by lot.
39
<PAGE>
The Managing General Partner's obligation to purchase interests presented may be
discharged for its benefit 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(f). NO OBLIGATION OF THE MANAGING GENERAL PARTNER TO ESTABLISH A RESERVE.
The Managing General Partner shall have no obligation to establish any reserve
to satisfy the presentment obligations under this section.
6.04(g). SUSPENSION OF PRESENTMENT FEATURE. The Managing General Partner may
suspend this presentment feature by so notifying Participants at any time if:
(i) it does not have sufficient cash flow; or
(ii) it is unable to borrow funds for such purpose on terms it deems
reasonable.
In addition, the presentment feature may be conditioned, in the Managing General
Partner's sole discretion, on the Managing General Partner's receipt of an
opinion of counsel that 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 50 years from the effective date of this Agreement unless sooner terminated
as hereinafter set forth.
7.01(b). TERMINATION. The Partnership shall terminate following:
(i) the occurrence of a Final Terminating Event; or
(ii) 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 FINAL TERMINATING EVENT. 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.
7.02(a). FINAL TERMINATING EVENT. 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.
7.02(b). TIME OF LIQUIDATING DISTRIBUTION. To the extent practicable and in
accordance with sound business practices in the judgment of the Managing General
Partner, liquidating distributions shall be made by the end of the taxable year
in which liquidation occurs (determined without regard to Section
706(c)(2)(A) of the Code) or, if later, within 90 days after the date of such
liquidation.
Notwithstanding, the following amounts need not be distributed within the
foregoing time periods so long as such withheld amounts are distributed as soon
as practical:
(i) amounts withheld for reserves reasonably required for
liabilities of the Partnership; and
40
<PAGE>
(ii) installment obligations owed to the Partnership.
7.02(c). IN-KIND DISTRIBUTIONS. Any in kind property distributions to the
Participants shall be made to a liquidating trust or similar entity for the
benefit of the Participants, unless at the time of the distribution:
(i) the Managing General Partner shall offer the individual
Participants the election of receiving in kind property
distributions and the Participants accept the offer after being
advised of the risks associated with such direct ownership; or
(ii) there are alternative arrangements in place which assure the
Participants that they will not, at any time, be responsible for
the operation or disposition of Partnership properties.
It shall be presumed that a Participant has refused his consent if the Managing
General Partner has not received the consent within 30 days after the Managing
General Partner mailed the request for consent.
7.02(d). SALE IF NO CONSENT. Any Partnership asset which would otherwise be
distributed in kind to a Participant, except for the failure or refusal of the
Participant to give his written consent to the distribution, may instead be sold
by the Managing General Partner at the best price reasonably obtainable from an
independent third party who is not an Affiliate of the Managing General Partner.
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 the notice at the address
designated in Section 1.03. 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. If
there is a transfer of rights hereunder to more than one party, then notice to
any owner of any interest in such rights shall be notice to all owners thereof.
8.01(b). CHANGE IN ADDRESS. The address of any party hereto may be changed by:
(i) written notice to the Participants in the event of a change of
address by the Managing General Partner; or
(ii) to the Managing General Partner in the event of a change of
address by a Participant.
8.01(c). TIME NOTICE DEEMED GIVEN. If the notice is given by the Managing
General Partner, then the notice shall be considered given, and any applicable
time shall run, from the date the notice is place in the mails or delivered to
the telegraph company.
If the notice is given by any Participant, then the notice shall be considered
given and any applicable time shall run from the date the notice is received.
8.01(d). EFFECTIVENESS OF NOTICE. Any notice to a party other than the Managing
General Partner, including a notice requiring concurrence or nonconcurrence,
shall be effective, and any failure to respond binding, irrespective of whether
or not the notice is actually received, and irrespective of any disability or
death on the part of the noticee, even if the disability or death is known to
the party giving the notice.
8.01(e). FAILURE TO RESPOND. Except when this Agreement expressly requires
affirmative approval of a Participant, any Participant who fails to respond in
writing within the time specified to a request by the Managing General Partner
for approval of or concurrence in a proposed action shall be conclusively deemed
to have approved the action. The time period shall be not less than 15 business
days from the date of mailing of the request.
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
Section 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.
41
<PAGE>
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.
8.05(a). PROCEDURE FOR AMENDMENT. No changes herein shall be binding unless:
(i) 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
(ii) 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.
8.05(b). CIRCUMSTANCES UNDER WHICH THE MANAGING GENERAL PARTNER ALONE MAY AMEND.
The Managing General Partner is authorized to amend this Agreement and its
exhibits without the consent of Participants in any way deemed necessary or
desirable by it:
(i) to add or substitute (in the case of an assigning party)
additional Participants;
(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 additional Participants 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
42
<PAGE>
EXHIBIT (I-A)
MANAGING GENERAL PARTNER SIGNATURE PAGE
<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 #8 LTD.
The undersigned agrees:
1. to serve as the Managing General Partner of ATLAS-ENERGY FOR THE
NINETIES-PUBLIC #8 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 Section3.03(b)(1) of the Partnership Agreement; and
3. to subscribe to the Partnership as follows:
(a) $___________________ [________] Unit(s)] under
Section 3.03(b)(2) of the Partnership Agreement as a Limited
Partner; or
(b) $___________________ [________] Unit(s)] under
Section 3.03(b)(2) of the Partnership Agreement as an Investor
General Partner.
MANAGING GENERAL PARTNER:
Atlas Resources, Inc. Address:
By: ______________________________________ 311 Rouser Road
Moon Township, Pennsylvania 15108
ACCEPTED this ________ day of __________________ , 1999.
ATLAS RESOURCES, INC.
MANAGING GENERAL PARTNER
By: __________________________
Attest
- ----------------------------------------------
(SEAL) Secretary
<PAGE>
EXHIBIT (I-B)
SUBSCRIPTION AGREEMENT
<PAGE>
ATLAS-ENERGY FOR THE
NINETIES-PUBLIC #8 LTD.
SUBSCRIPTION AGREEMENT
The undersigned hereby offers to purchase Units of Atlas-Energy for the
Nineties-Public #8 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 #8 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, nor may it be withdrawn by the undersigned after it has been
accepted by the Managing General Partner. 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 the Managing General Partner to accept this subscription, the
undersigned hereby represents, warrants, covenants and agrees as follows:
INVESTOR'S INITIALS
_____ The undersigned has received the Prospectus.
_____ The undersigned (other than Minnesota residents) recognizes that
before this offering there has been no public market for the Units
and it is unlikely that after the offering there will be any such
market. 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:
- a net worth of at least $225,000 (exclusive of home,
furnishings and automobiles); or
- a net worth (exclusive of home, furnishings and
automobiles) of at least $60,000 and had during the
last tax year, or 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,
INDIANA, IOWA, KANSAS, KENTUCKY, MAINE, MASSACHUSETTS,
MICHIGAN, MINNESOTA, MISSISSIPPI, MISSOURI, NEW HAMPSHIRE,
NEW MEXICO, NORTH CAROLINA, OHIO, OKLAHOMA, OREGON,
PENNSYLVANIA, SOUTH DAKOTA, TENNESSEE, TEXAS, VERMONT OR
WASHINGTON, THEN 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 the undersigned is a fiduciary, then he is purchasing
for a person or entity having the appropriate income and/or
net worth specified in (a) or (b) above.
<PAGE>
INVESTOR'S INITIALS
_____ 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 the
obligations and liabilities exceed the Partnership's insurance
proceeds, the Partnership's assets and indemnification by the
Managing General Partner. Insurance may be inadequate to cover
these 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 THE
UNDERSIGNED 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 Selling Agent or registered representative is required to inform potential
investors of all pertinent facts relating to the Units, including the following:
- the risks involved in the offering, including the speculative
nature of the investment and the speculative nature of drilling
for oil and gas;
- the financial hazards involved in the offering, including the risk
of losing the entire investment;
- the lack of liquidity of this investment;
- the restrictions on transferability of the Units;
- the background of the Managing General Partner and the Operator;
- the tax consequences of the investment; and
- the unlimited joint and several liability of the Investor
General Partners.
You are required to execute your own Subscription Agreement. The Managing
General Partner will not accept any Subscription Agreement that has been
executed by someone other than you unless the person has been given the legal
power of attorney to sign on your behalf and you meet all of the conditions
herein. In the case of sales to fiduciary accounts, the minimum standards set
forth herein must be met by the beneficiary, the fiduciary account, or by the
donor or grantor who directly or indirectly supplies the funds to purchase the
Partnership interests if the donor or grantor is the fiduciary.
Your execution of the Subscription Agreement constitutes your binding offer to
buy Units in the Partnership. Once you subscribe you may withdraw your
subscription only by providing the Managing General Partner with written notice
of your withdrawal before your subscription is accepted by the Managing General
Partner. The Managing General Partner has the discretion to refuse to accept
your Agreed Subscription without liability to you. Agreed Subscriptions will be
accepted or rejected by the Partnership within 30 days of their receipt. If your
Agreed Subscription is rejected, then all of your funds will be returned to you
immediately.
If your Agreed Subscription is accepted before the first closing, then you will
be admitted as a Participant not later than 15 days after the release from
escrow of the investors' funds to the Partnership. If your Agreed Subscription
is accepted after the first closing, then you will be admitted into the
Partnership not later than the last day of the calendar month in which your
Agreed Subscription was accepted by the Partnership.
The Managing General Partner may not complete a sale of Units to you until at
least five business days after the date you receive a final Prospectus. In
addition, the Managing General Partner will send you a confirmation of purchase.
NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from
various requirements of Title 10 of the California Administrative Code. These
deviations include, but are not limited to the following: the definition of
Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule 260.140.121(1)
does not require enlarging or contracting 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.
2
<PAGE>
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 #8 LTD. (the "Partnership") as
(check one):
<TABLE>
<CAPTION>
<S> <C>
/ / INVESTOR GENERAL PARTNER AGREED SUBSCRIPTION
/ / LIMITED PARTNER $ ___________________________
(______________________# Units)
</TABLE>
Make check payable to: "Atlas Public #8 Ltd., Escrow Agent, National City Bank
of PA" Minimum Subscription: one Unit ($10,000), however, the Managing General
Partner, in its discretion, may accept one-half Unit ($5,000) subscriptions;
and Additional Subscriptions in $1,000 increments.
<TABLE>
<CAPTION>
<S> <C>
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
---------------------------------------------------
---------------------------------------------------
</TABLE>
Date: ______ Telephone No.: Business ________________ Home _________________
Tax I.D. No. (Social Security No.): __________________________________________
(CHECK ONE): Calendar Year Taxpayer _________ Fiscal Year Taxpayer ________
<TABLE>
<CAPTION>
<S> <C> <C>
(CHECK ONE): OWNERSHIP - Tenants-in-Common Partnership
---------- ----------
Joint Tenancy C Corporation
---------- ----------
Individual S Corporation
---------- ----------
Trust Community Property
---------- ----------
Other
----------
</TABLE>
3
<PAGE>
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.
<TABLE>
<CAPTION>
<S> <C>
_________________________________________________ ________________________________________
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
</TABLE>
NOTICE TO BROKER-DEALER:
Send complete and signed DOCUMENTS and THE CHECK to:
Mr. Eric D. Koval
Anthem Securities, Inc.
P.O. Box 911
Coraopolis, Pennsylvania 15108-0911
(412) 262-1680
FACSIMILE: (412) 262-7430
TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
ACCEPTED THIS ______ day ATLAS RESOURCES, INC.,
of _________________ , 1999 MANAGING GENERAL PARTNER
Attest By:______________________________
________________________________________
(SEAL) Secretary
4
<PAGE>
EXHIBIT (II)
DRILLING AND OPERATING AGREEMENT
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
(THIS DRILLING AND OPERATING AGREEMENT WILL BE APPROPRIATELY
MODIFIED FOR OTHER AREAS OF THE UNITED STATES.)
<PAGE>
<TABLE>
<CAPTION>
INDEX
SECTION PAGE
<S> <C>
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..............................4
5. Title Examination of Well Locations; Liability for Title Defects............................................5
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..........7
8. Operator's Lien.............................................................................................8
9. Successors and Assigns; Transfers; Appointment of Agent.....................................................8
10. Insurance; Operator's Liability.............................................................................9
11. Internal Revenue Code Election, Relationship of Parties; Right to Take Production in Kind...................9
12. Force Majeure..............................................................................................10
13. Term.......................................................................................................10
14. Governing Law and Invalidity...............................................................................11
15. Integration................................................................................................11
16. Waiver of Default or Breach................................................................................11
17. Notices....................................................................................................11
18. Interpretation.............................................................................................11
19. Counterparts...............................................................................................12
Signature Page.............................................................................................12
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
</TABLE>
<PAGE>
DRILLING AND OPERATING AGREEMENT
THIS AGREEMENT made this ______ day of _______________, 1999, by and
between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred
to as "Atlas" or "Operator"),
and
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD., a Pennsylvania limited
partnership, (hereinafter referred to as the "Developer").
WITNESSETH THAT:
WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the "Leases")
described on Exhibit A attached 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 the Operator's 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, the Operator is in the oil and gas exploration and development
business, and the Developer desires that Operator, as its independent
contractor, perform certain services in connection with its efforts to develop
the aforesaid Initial and Additional Well Locations (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. ASSIGNMENT OF WELL LOCATIONS; REPRESENTATIONS; DESIGNATION OF
ADDITIONAL WELL LOCATIONS; OUTSIDE ACTIVITIES.
(a) The Operator shall execute an assignment of an undivided percentage
of Working Interest in the Well Location acreage for each well to the Developer
as shown on Exhibit A attached hereto, which assignment shall be limited to a
depth from the surface to the top of the Queenston formation in 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, the Operator represents and warrants to the
Developer that the Operator 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 Operator 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 the Operator 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. The Operator agrees to indemnify, protect and hold the
Developer and its successors and assigns harmless from and against all costs
(including but not limited to reasonable attorneys' fees), liabilities, claims,
penalties, losses, suits, actions, causes of action, judgments or decrees
resulting from the breach of any of the aforesaid representations and
warranties. It is understood and agreed that, except as specifically set forth
above, the Operator makes no warranty or representation, express or implied, as
to its title or the title of the lessors in and to the lands or oil and gas
interests covered by said Leases.
(c) 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
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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. DRILLING OF WELLS; INTEREST OF DEVELOPER; RIGHT OF SUBSTITUTION.
(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. 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
30, 2000. 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, Ohio, or other areas of the Appalachian
Basin to be substituted for such original Well Location. 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.
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3. OPERATOR - RESPONSIBILITIES IN GENERAL; TERM.
(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
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(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. OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS; COMPLETION
DETERMINATION.
(a) All natural gas wells which are drilled and completed hereunder
shall be drilled and completed on a footage basis for a price of $37.81 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. 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. The payment to be
nonrefundable in all events, except that Atlas' share of such payments as the
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. The payment shall be nonrefundable in all
events, except that Atlas' share of such payments as the Managing General
Partner of the Developer shall be paid within five (5) business days of notice
from Operator that such costs have been incurred.
Subject to the above, with respect to each well and each additional
well, Developer shall pay to Operator, in proportion to the share of the Working
Interest owned by the Developer in the wells, the designated completion costs
for such well within
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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. TITLE EXAMINATION OF WELL LOCATIONS; LIABILITY FOR TITLE DEFECTS.
(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 the Operator 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 the Operator in Section l(b) of this
Agreement.
6. OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS; PRICE DETERMINATIONS;
PLUGGING AND ABANDONMENT.
(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.
This fee shall be in lieu of any direct charges by Operator for its services or
the provision by Operator of its equipment for normal superintendence and
maintenance of 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. The operating fees 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
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(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, 2001. 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, 1997, 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. In addition,
Operator shall not plug and abandon any such well prior to obtaining the written
consent of the Developer. However, if the Operator in accordance with the
generally accepted and customary oil and gas field practices and techniques then
prevailing in the geographic area of the well location, determines that any 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.
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7. BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS;
RECORDS, REPORTS AND INFORMATION.
(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. Operator shall also 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. Operator, however, 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. The invoice shall 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. This 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:
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(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. OPERATOR'S LIEN.
(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. SUCCESSORS AND ASSIGNS; TRANSFERS; APPOINTMENT OF AGENT.
(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;
(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.
Further, in order to maintain uniformity of ownership in the wells, production,
equipment, and leasehold interests covered by this Agreement, and
notwithstanding any other provisions to the contrary, the Developer shall not,
without the prior written consent of Operator, sell, assign, transfer, encumber,
mortgage or otherwise dispose of any of its interest in the wells, production,
equipment or leasehold interests covered 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.
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<PAGE>
(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. INSURANCE; OPERATOR'S LIABILITY.
(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 as an additional insured party;
and
(ii) provide that at least thirty (30) days' prior notice
of cancellation and any other adverse material change
in the policy shall be given to the Developer.
Provided, that the Developer shall reimburse Operator for the additional cost,
if any, of including it as an additional insured party under the Operator's
insurance.
Current copies of all policies or certificates 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. INTERNAL REVENUE CODE ELECTION; RELATIONSHIP OF PARTIES; RIGHT TO TAKE
PRODUCTION IN KIND.
(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
9
<PAGE>
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. FORCE MAJEURE.
(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. TERM.
This Agreement shall become effective when executed by Operator and the
Developer. Except as provided in sub-section (c) of Section 3, the Agreement
shall continue and remain in full force and effect for the productive lives of
the wells being operated hereunder.
10
<PAGE>
14. GOVERNING LAW AND INVALIDITY.
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. INTEGRATION.
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. WAIVER OF DEFAULT OR BREACH.
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. NOTICES.
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 the Operator, to:
Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
Attention: President
(ii) If to Developer, to:
Atlas-Energy for the Nineties-Public #8 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. INTERPRETATION.
Whenever this Agreement makes reference to "this Agreement" or to any
provision "hereof," or words to similar effect, the 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.
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<PAGE>
19. COUNTERPARTS.
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 ATLAS RESOURCES, INC.
_____________________________________ By:____________________________________
Secretary
[Corporate Seal]
ATLAS-ENERGY FOR NINETIES-PUBLIC #8 LTD.
Attest By its Managing General Partner:
_____________________________________ ATLAS RESOURCES, INC.
Secretary
[Corporate Seal] By:____________________________________
12
<PAGE>
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.
Exhibit A
(Page 1)
<PAGE>
WELL NAME, TWP.
COUNTY, STATE
ASSIGNMENT OF OIL AND GAS LEASE
STATE OF _____________________
COUNTY OF ____________________
KNOW ALL MEN BY THESE PRESENTS:
THAT the undersigned ____________________________ (hereinafter called
Assignor), for and in consideration of One Dollar and other valuable
consideration ($1.00 ovc), the receipt whereof is hereby acknowledged, does
hereby sell, assign, transfer and set over unto __________________________
______________________________________________ (hereinafter called Assignee),
an undivided __________________________ in, and to, the oil and gas lease
described as follows:
together with the rights incident thereto and the personal property thereto,
appurtenant thereto, or used, or obtained, in connection therewith.
And for the same consideration, the assignor covenants with the said
assignee his or its heirs, successors, or assigns that assignor is the lawful
owner of said lease and rights and interest thereunder and of the personal
property thereon or used in connection therewith; that the undersigned has
good right and authority to sell and convey the same, and that said rights,
interest and property are free and clear from all liens and encumbrances, and
that all rentals and royalties due and payable thereunder have been duly paid.
In Witness Whereof, The undersigned owner _____ and assignor _____
ha_____ signed and sealed this instrument the _____ day of _______________,
19___.
Signed and acknowledged in presence of ________________________________
________________________________ ________________________________
________________________________ ________________________________
EXHIBIT "B"
<PAGE>
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 official 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 that he
executed the same as the act of such corporation for the purposes and
consideration therein expressed, and in the capacity therein stated.
In testimony whereof, I have herewith set my hand and official seal at
_______________________, this _____ day of _____________, A.D., 19___.
____________________________
Notary Public
This instrument prepared by:
Atlas Resources, Inc.
311 Rouser Road
P.O. Box 611
Moon Township, PA 15108
EXHIBIT "B"
<PAGE>
ADDENDUM NO. __________
TO DRILLING AND OPERATING AGREEMENT
DATED ___________________ , 1999
THIS ADDENDUM NO. __________ made and entered into this ______ day of
________________, 1999, by and between ATLAS RESOURCES, INC., a Pennsylvania
corporation (hereinafter referred to as "Operator"),
and
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD., a Pennsylvania limited
partnership, (hereinafter referred to as the Developer).
WITNESSETH THAT:
WHEREAS, Operator and the Developer have entered into a Drilling and Operating
Agreement dated ___________________, 1999, (the "Agreement"), which Agreement
relates to the drilling and operating of ________________ (______) natural gas
wells on the ________________ (______) Initial Well Locations in Mercer County,
Pennsylvania, identified on the maps attached as Exhibits A-l through A-______
to said Agreement, and provides for the development upon the terms and
conditions therein set forth of such Additional Well Locations as the parties
may from time to time designate; and
WHEREAS, pursuant to Section l(c) of said Agreement, Operator and Developer
presently desire to designate ________________ Additional Well Locations
hereinafter described to be developed in accordance with the terms and
conditions of said Agreement.
NOW, THEREFORE, in consideration of the mutual covenants herein contained and
intending to be legally bound hereby, the parties hereto agree as follows:
1. Pursuant to Section l(c) of the aforesaid Agreement, the Developer hereby
authorizes Operator to drill, complete (or plug) and operate, upon the terms and
conditions set forth in said Agreement and this Addendum No.__________,
________________ additional natural gas wells on the ________________ Additional
Well Locations described on Exhibit A hereto and on the maps attached hereto as
Exhibits A-______ through A-______.
2. Operator, as Developer's independent contractor, agrees to drill, complete
(or plug) and operate said additional natural gas wells on said Additional Well
Locations in accordance with the terms and conditions of said Agreement and
further agrees to use its best efforts to commence drilling the first such
additional well within thirty (30) days after the date hereof and to commence
drilling all said ________________ additional wells on or before March 30, 2000.
3. Developer hereby acknowledges that Operator has furnished Developer with the
title opinions identified on Exhibit A hereto, and such other documents and
information which Developer or its counsel has requested in order to determine
the adequacy of the title to the aforesaid Additional Well Locations. The
Developer hereby accepts the title to the aforesaid Additional Well Locations
and leased premises in accordance with the provisions of Section 5 of the
Agreement.
4. The drilling and operation of said ________________ additional natural gas
wells on the aforesaid ________________ Additional Well Locations shall be in
accordance with and subject to the terms and conditions set forth in the
aforesaid Agreement as supplemented by this Addendum No. __________ and except
as previously supplemented, all terms and conditions of the aforesaid Agreement
shall remain in full force and effect as originally written.
5. This Addendum No. __________ shall be legally binding upon, and shall inure
to the benefit of, the parties hereto and their respective heirs, personal
representatives, successors and assigns.
Exhibit C
(Page 1)
<PAGE>
WITNESS the due execution hereof on the day and year first above written.
Attest: ATLAS RESOURCES, INC.
___________________________ By___________________________
Secretary
[Corporate Seal]
ATLAS ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
By its Managing General Partner:
ATLAS RESOURCES, INC.
Attest:
___________________________ By___________________________
Secretary
[Corporate Seal]
Exhibit C
(Page 2)
<PAGE>
EXHIBIT (B)
SPECIAL SUITABILITY REQUIREMENTS
AND DISCLOSURES TO INVESTORS
<PAGE>
SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS
If you are a resident of one of the following states, then you must meet that
state's qualification and suitability standards as follows:
SUBSCRIBERS TO LIMITED PARTNER UNITS.
If you are a resident of Michigan or North Carolina and you purchase limited
partner units, then you must:
- have a net worth of not less than $225,000, exclusive of home,
furnishings and automobiles; or
- have 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, if you are a resident of Michigan, Ohio or Pennsylvania, then you
must not make an investment in the partnership in excess of 10% of your net
worth, exclusive of home, furnishings and automobiles.
If you are a resident of California and you purchase limited partners units,
then you must::
- 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 year of $65,000 or more; or
- have a net worth of not less than $500,000, exclusive of home,
furnishings and automobiles; or
- have a net worth of not less than $1,000,000, or
- expect to have gross income in the current tax year of not
less than $200,000.
PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than
$1,800,000 you are cautioned to carefully evaluate the partnership's ability to
fully accomplish its stated objectives and inquire as to the current dollar
volume of partnership subscriptions.
SUBSCRIBERS TO INVESTOR GENERAL PARTNER UNITS.
If you are a resident of California and you purchase investor general partner
units, then you must:
- have a net worth of not less than $250,000, exclusive of home,
furnishings and automobiles, and expect to have annual gross
income in the current year of $120,000 or more; or
- have a net worth of not less than $500,000, exclusive of home,
furnishings and automobiles; or
- have a net worth of not less than $1,000,000; or
- expect to have gross income in the current year of not less
than $200,000.
If you are a resident of Alabama, Maine, Massachusetts, Minnesota, North
Carolina, Ohio, Pennsylvania, Tennessee, or Texas and you purchase investor
general partner units, then you must:
- have an individual or joint net worth with your spouse of
$225,000 or more, without regard to the investment in the
partnership, exclusive of home, home furnishings and
automobiles, and a combined gross income of $100,000 or more
for the current year and for the two previous years; or
- have an individual or joint net worth with your spouse in
excess of $1,000,000, inclusive of home, home furnishings and
automobiles; or
- have an individual or joint net worth with your spouse in
excess of $500,000, exclusive of home, home furnishings and
automobiles; or
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<PAGE>
- have 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 you are a resident of Arizona, Indiana, Iowa, Kansas, Kentucky, Michigan,
Mississippi, Missouri, New Hampshire, New Mexico, Oklahoma, Oregon, South
Dakota, Vermont, or Washington and you purchase investor general partner units,
then you must:
- have an individual or joint net worth with your spouse of
$225,000 or more, without regard to the investment in the
partnership, exclusive of home, home furnishings and
automobiles, and a combined "taxable income" of $60,000 or
more for the previous year and expect to have a combined
"taxable income" of $60,000 or more for the current year and
for the succeeding year; or
- have an individual or joint net worth with your spouse in
excess of $1,000,000, inclusive of home, home furnishings and
automobiles; or
- have an individual or joint net worth with your spouse in
excess of $500,000, exclusive of home, home furnishings and
automobiles; or
- have 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, if you are a resident of Michigan, Ohio or Pennsylvania, then you
must not make an investment in the partnership in excess of 10% of your net
worth, exclusive of home, furnishings and automobiles.
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:
(i) to the issuer;
(ii) pursuant to the order or process of any court;
(iii) to any person described in Subdivision (i) of Section
25102 of the Code or Section 260.105.14 of these
rules;
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<PAGE>
(iv) to the transferor's ancestors, descendants or spouse,
or any custodian or trustee for the account of the
transferor's ancestors, descendants or spouse, or to
a transferee by a trustee or custodian for the
account of the transferee or the transferee's
ancestors, descendants or spouse;
(v) to holders of securities of the same class of the
same issuer;
(vi) by way of gift or donation inter vivos or on death;
(vii) by or through a broker-dealer licensed under the Code
(either acting as such or as a finder) to a resident
of a foreign state, territory or country who is
neither domiciled in this state to the knowledge of
the broker-dealer, nor actually present in this state
if the sale of such securities is not in violation of
any securities law of the foreign state, territory or
country concerned;
(viii) to a broker-dealer licensed under the Code in a
principal transaction, or as an underwriter or member
of an underwriting syndicate or selling group;
(ix) if the interest sold or transferred is a pledge or
other lien given by the purchaser to the seller upon
a sale of the security for which the Commissioner's
written consent is obtained or under this rule not
required;
(x) by way of a sale qualified under Sections 25111,
25112, 25113 or 25121 of the Code, of the securities
to be transferred, provided that no order under
Section 25140 or Subdivision (a) of Section 25143 is
in effect with respect to such qualification;
(xi) by a corporation or wholly-owned subsidiary of such
corporation, or by a wholly-owned subsidiary of a
corporation to such corporation;
(xii) by way of an exchange qualified under Sections 25111,
25112 or 25113 of the Code, provided that no order
under Section 25140 or Subdivision (a) of Section
25143 is in effect with respect to such
qualification;
(xiii) between residents of foreign states, territories or
countries who are neither domiciled nor actually
present in this state;
(xiv) to the State Controller pursuant to the Unclaimed
Property Law or to the administrator of the unclaimed
property law of another state;
(xv) by the State Controller pursuant to the Unclaimed
Property Law or by the administrator of the unclaimed
property law of another state if, in either such
case, such person (i) discloses to potential
purchasers at the sale that transfer of the
securities is restricted under this rule, (ii)
delivers to each purchaser a copy of this rule, and
(iii) advises the Commissioner of the name of each
purchaser;
(xvi) by a trustee to a successor trustee when such
transfer does not involve a change in the beneficial
ownership of the securities;
(xvii) by way of an offer and sale of outstanding securities
in an issuer transaction that is subject to the
qualification requirement of Section 25110 of the
Code but exempt from that qualification requirement
by subdivision (f) of Section 25102;
provided that any such transfer is on the condition that any
certificate evidencing the security issued to such transferee
shall contain the legend required by this section.
(c) The certificates representing all such securities subject to
such a restriction on transfer, whether upon initial issuance
or upon any transfer thereof, shall bear on their face a
legend, prominently stamped or printed thereon in capital
letters of not less than 10-point size, reading as follows:
"IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS
SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY
CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF
THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA,
EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES."
3
<PAGE>
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.
PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than
$1,800,000 you are cautioned to carefully evaluate the partnership's ability to
fully accomplish its stated objectives and inquire as to the current dollar
volume of partnership subscriptions.
4
<PAGE>
TABLE OF CONTENTS
================================================================================
<TABLE>
<CAPTION>
PAGE
<S> <C>
Summary of the Offering.......................................................1
Risk Factors..................................................................2
Additional Information........................................................7
Forward Looking Statements and Associated
Risks......................................................................7
Investment Objectives.........................................................8
Actions to be Taken by Managing General
Partner to Reduce Risks of Additional
Payments by Investor General Partners......................................9
Capitalization and Source of Funds and Use of
Proceeds..................................................................10
Compensation.................................................................12
Terms of the Offering........................................................15
Prior Activities.............................................................19
Management...................................................................26
Proposed Activities..........................................................30
Competition, Markets and Regulation..........................................67
Participation in Costs and Revenues..........................................70
Conflicts of Interest........................................................73
Fiduciary Responsibility of the Managing
General Partner...........................................................80
Tax Aspects..................................................................81
Summary of Partnership Agreement.............................................91
Summary of Drilling and Operating Agreement..................................93
Reports to Investors.........................................................94
Presentment Feature..........................................................95
Transferability of Units.....................................................97
Plan of Distribution.........................................................98
Sales Material...............................................................99
Legal Opinions...............................................................99
Experts......................................................................99
Litigation..................................................................100
Financial Information Concerning the Managing
General Partner and the Partnership......................................100
</TABLE>
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
No one has been authorized to give any information or make any
representations other than those contained in this prospectus in connection
with this offering. If given or made, you should not rely on such information
or representations as having been authorized by the managing general partner.
The delivery of this prospectus does not imply that its information is
correct as of any time after its date. This prospectus is not an offer to
sell these securities in any state to any person where the offer and sale is
not permitted.
ATLAS-ENERGY FOR
THE NINETIES -
PUBLIC #8 LTD.
--------------
PROSPECTUS
--------------
______________, 1999
Until December 31, 1999, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealers' obligation to
deliver a prospectus when acting as underwriters and with respect to their
unsold allotments or subscriptions.
================================================================================
<PAGE>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 24. 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 the course of conduct was not the result of their negligence
or misconduct.
Paragraph 11 of the Dealer-Manager Agreement provides for the indemnification
of the Managing General Partner, the Partnership and control persons under
specified conditions by the Dealer-Manager and/or Selling Agent.
ITEM 25. 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:
<TABLE>
<S> <C>
Accounting $ 15,000.00*
Legal Fees (including Blue Sky) 75,000.00*
Printing 155,000.00*
SEC Registration Fee 5,310.00
Blue Sky Filing Fees (excluding legal fees) 26,000.00*
NASD Filing Fee 2,300.00
Miscellaneous 531,390.00*
-----------
Total $810,000.00*
===========
</TABLE>
- ------------------------------
*Estimated
ITEM 26. 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 27. EXHIBITS.
<TABLE>
<S> <C>
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 #8 Ltd.
4(b) Amended and Restated Certificate and Agreement of Limited
Partnership for Atlas-Energy for the Nineties-Public #8 Ltd.
(See Exhibit (A) to Prospectus)
<PAGE>
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) 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 Grant Thornton, L.L.P.
24(b) Consent of United Energy Development Consultants, Inc.
24(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)
24(d) Consent of Wright & Company, Inc.
25 Power of Attorney
</TABLE>
ITEM 28. 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.
<PAGE>
[Letterhead]
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. 2 to the Registration Statement to be signed on
its behalf by the undersigned, thereto duly authorized, in Moon Township,
Pennsylvania, on the 24th day of September, 1999.
<TABLE>
<S> <C>
ATLAS-ENERGY FOR THE NINETIES-
PUBLIC #8 LTD.
(Registrant)
By: Atlas Resources, Inc.,
Managing General Partner
James R. O'Mara and Tony C. Banks, By: /s/ James R. O'Mara
pursuant to the Registration Statement, ------------------------------------------------
have been granted Power of Attorney and are James R. O'Mara, President, Chief Executive
signing on behalf of the names shown below, Officer and Director
in the capacities indicated.
By: /s/ Tony C. Banks
------------------------------------------------
Tony C. Banks, Senior Vice President of Finance,
Principal Financial Officer and Director
</TABLE>
In accordance with the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
- --------- ----- ----
<S> <C> <C>
Charles T. Koval Chairman of the Board and a Director September 24, 1999
James R. O'Mara President, Chief Executive Officer and a Director September 24, 1999
Tony C. Banks Senior Vice President of Finance, Principal Financial Officer, and a Director September 24, 1999
Frank P. Carolas Vice President of Land and Geology September 24, 1999
Jeffrey C. Simmons Vice President - Operations September 24, 1999
William R. Seiler Vice President and Controller September 24, 1999
</TABLE>
<PAGE>
As filed with the Securities and Exchange Commission on October 1, 1999
Registration No. 333-82389
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------------------------
EXHIBITS
TO
PRE-EFFECTIVE AMENDMENT NO. 2
TO
FORM SB-2
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933
----------------------------------
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 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
OKLAHOMA CITY, OKLAHOMA 73112 MOON TOWNSHIP, PENNSYLVANIA 15108
================================================================================
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit No. Description Page
----------- ----------- ----
<S> <C> <C>
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 #8 Ltd.*
4(b) Amended and Restated Certificate and Agreement of Limited
Partnership for Atlas-Energy for the Nineties-Public #8 Ltd.
(See Exhibit (A) to Prospectus)
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 Grant Thornton, L.L.P.
24(b) Consent of United Energy Development Consultants, Inc.
24(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)
24(d) Consent of Wright & Company, Inc.
25 Power of Attorney
</TABLE>
- ---------------
*Previously submitted
<PAGE>
OPINION OF KUNZMAN & BOLLINGER, INC.
AS TO THE LEGALITY OF THE
UNITS REGISTERED HEREBY
<PAGE>
KUNZMAN & BOLLINGER, INC.
ATTORNEYS-AT-LAW
5100 N. BROOKLINE, SUITE 600
OKLAHOMA CITY, OKLAHOMA 73112
Telephone (405) 942-3501
Fax (405) 942-3527
Exhibit 5
September 29, 1999
Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
RE: ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
Gentlemen:
You have requested our opinion on certain issues pertaining to
Atlas-Energy for the Nineties-Public #8 Ltd. (the "Partnership") formed under
the Limited Partnership Laws of Pennsylvania. Atlas Resources, Inc., a
Pennsylvania corporation, is the Managing General Partner of the Partnership.
BASIS OF OPINION
Our opinion is based on our review of a certain Registration Statement
on Form SB-2 and any amendments thereto, including any post-effective
amendments, for the Partnership (the "Registration Statement") as filed with the
Securities and Exchange Commission (the "Commission"), including the Certificate
of Limited Partnership for the Partnership, the Prospectus and the Amended and
Restated Certificate and Agreement of Limited Partnership for the Partnership
(the "Partnership Agreement"), the Subscription Agreement and the Drilling and
Operating Agreement contained therein, and on our review of such other documents
and records as we have deemed necessary to review for purposes of rendering our
opinion. As to various questions of fact material to our opinion which we have
not independently verified, we have relied on certain representations made to us
by officers and directors of the Managing General Partner.
In rendering the opinion herein provided, we have assumed the due
authorization, execution and delivery of all relevant documents by all parties
thereto.
OPINION
Based upon the foregoing, we are of the opinion that:
The Units, when sold in accordance with the Registration
Statement as amended at the time it becomes effective with the
Commission, will be legally issued pursuant to Pennsylvania
partnership law, fully paid and nonassessable except as described
in the Registration Statement with respect to the Investor
General Partner Units.
We hereby consent to the use of this opinion as an Exhibit to the
Registration Statement and to the reference to this firm in the Prospectus
included in the Registration Statement.
Yours very truly,
/s/ KUNZMAN & BOLLINGER, INC.
KUNZMAN & BOLLINGER, INC.
<PAGE>
OPINION OF KUNZMAN & BOLLINGER, INC.
AS TO TAX MATTERS
<PAGE>
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 29, 1999
Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
RE: ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
Gentlemen:
You have requested our opinions on the material federal income tax
issues pertaining to Atlas-Energy for the Nineties-Public #8 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. 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 Amended and Restated Certificate and
Agreement of Limited Partnership for the Partnership (the "Partnership
Agreement").
BASIS OF OPINION
Our opinions are based upon our review of: (1) a certain Registration
Statement on Form SB-2 for Atlas-Energy for the Nineties-Public #8 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 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 will be executed by the Managing
General Partner and the Participants and recorded in all
places required under the Revised Uniform Limited
Partnership Act of Pennsylvania and any other applicable
limited partnership act. Also, the Partnership will be
operated in accordance with the terms of the Partnership
Agreement, the Prospectus, and the Revised Uniform Limited
Partnership Act of Pennsylvania and any other applicable
limited partnership act.
(2) No election will be made by 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 legal title to the Working Interest
in all of its Prospects.
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 2
(4) The respective amounts that will be paid to the Managing General
Partner 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 between the Managing General Partner
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 the Managing General Partner's experience and the
intended operations of the Partnership, the Managing General
Partner reasonably believes that the aggregate deductions,
including depletion deductions, and 350% of the aggregate
credits, if any, which will be claimed by the Managing
General Partner and the Participants, will not during the
first five tax years following the funding of the
Partnership exceed twice the amounts invested by the
Managing General Partner 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
Section 465 of the Code, to a Person (other than the Participant) having such
interest and the 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 31 CFR, Part 10, Section 10.33
(Treasury Department Circular No. 230) on tax law opinions and 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 statutes, rulings or regulations, as interpreted by judicial or
administrative bodies.
Our opinions are only predictions of the outcome of the particular tax
issues being addressed. The results are not certain and depend on the
Partnership's operations in the future. Also, as required by Circular 230
our opinions state whether it is "more likely than not" that the predicted
outcome will occur.
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 3
Accordingly, in our opinion it is more likely than not that the following
tax treatment will be upheld if challenged by the IRS and litigated:
(1) PARTNERSHIP CLASSIFICATION. The Partnership will be classified as a
partnership for federal income tax purposes, and not as a corporation. The
Partnership, as such, will not pay any federal income taxes, and all items of
income, gain, loss and deduction of the Partnership will be reportable by the
Partners in the Partnership. (See "- Partnership Classification.")
(2) PASSIVE ACTIVITY CLASSIFICATION. The Partnership's oil and gas
production income, together with gain, if any, from the disposition of its
oil and gas properties, which is 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 Section 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. Also, the passive
activity limitations on losses under Section 469, more likely than not, 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.")
(3) 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. Section 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.")
(4) 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 "-1999 Expenditures," "- Availability of Certain
Deductions" and "- Partnership Organization and Syndication Fees.")
(5) 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.")
(6) PREPAYMENTS OF INTANGIBLE DRILLING AND DEVELOPMENT COSTS.
Depending primarily on when the Partnership Subscription is received, the
Managing General Partner anticipates that the Partnership will prepay in 1999
most, if not all, of the intangible drilling and development costs related to
Partnership Wells the drilling of which will begin in 2000. 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 1999 taxable year
even though all Working Interest owners in the well may not be required to
prepay such amounts, 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 "- Drilling
Contracts," below.)
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 4
The foregoing opinion is based in part on the assumptions that: (1)
such costs will be required to be prepaid in 1999 for specified wells
pursuant to the Drilling and Operating Agreement; (2) pursuant to the
Drilling and Operating Agreement the drilling of the wells is required to be,
and actually is, begun on or before March 30, 2000, and the wells are
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.
(7) DEPLETION ALLOWANCE. The greater of cost depletion or percentage
depletion will be available to qualified Participants as a current deduction
against the Partnership's oil and gas production income, subject to certain
restrictions summarized below. (See "- Depletion Allowance.")
(8) MACRS. The Partnership's reasonable equipment costs for depreciable
property placed in the wells which cannot be deducted immediately ("Tangible
Costs") will be eligible for cost recovery deductions under the Modified
Accelerated Cost Recovery System ("MACRS"), generally over a seven year "cost
recovery period," 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 - Modified Accelerated
Cost Recovery System ("MACRS").")
(9) 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.")
(10) 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.")
(11) ALLOCATIONS. Assuming the effect of the allocations of income,
gain, loss and deduction (or items thereof) set forth in the Partnership
Agreement, including the allocations of basis and amount realized with
respect to 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.")
(12) AGREED SUBSCRIPTION. No gain or loss will be recognized by the
Participants on payment of their Agreed Subscriptions.
(13) PROFIT MOTIVE AND NO TAX SHELTER REGISTRATION. 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 under Section 183 of the
Code and is not required to register with the IRS as a tax shelter. (See
"- Disallowance of Deductions Under Section 183 of the Code" and "- Lack of
Registration as a Tax Shelter.")
(14) 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. Section 1.701-2.
(See "-Penalties and Interest - IRS Anti-Abuse Rule.")
(15) OVERALL EVALUATION OF TAX BENEFITS. 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. 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.)
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 5
* * * * * * * * * * * * *
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.
IN GENERAL
The following is a summary of all of the material federal income tax
consequences of the purchase, ownership and disposition of Investor General
Partners Units and Limited Partner Units which will apply to 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 each Participant's particular income tax position in the year in
which items of income, gain, loss, deduction or credit are properly taken
into account in computing his federal income tax liability. In addition,
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. Also,
the treatment of the tax attributes of the Partnership may vary among
Participants. ACCORDINGLY, EACH PARTICIPANT IS URGED TO SEEK QUALIFIED,
PROFESSIONAL ASSISTANCE IN THE PREPARATION OF HIS FEDERAL, STATE AND LOCAL
TAX RETURNS WITH SPECIFIC REFERENCE TO HIS OWN TAX SITUATION.
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.
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.
Under the regulations, a business entity with two or more members is
classified for federal tax purposes as either a corporation or a partnership.
Treas. Reg. Section 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. Section 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
will automatically be classified as a partnership unless it 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. "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. Losses generated by
"passive activities" can offset only passive income and cannot be applied
against active income or portfolio income.
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 6
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 any trade or business in which the taxpayer
does not materially participate on a regular, continuous, and substantial
basis. Under the Partnership Agreement, Limited Partners will not have
material participation in the Partnership and generally will be subject to
the passive activity rules.
Investor General Partners also do not materially participate in the
Partnership. However, because Investor General Partners do not have limited
liability under the Revised Uniform Limited Partnership Act of Pennsylvania
until they are converted to Limited Partners, their deductions generally will
not be treated as passive deductions prior to the conversion. (See "
- -Conversion from Investor General Partner to Limited Partner", below.)
However, if an Investor General Partner invests in the Partnership through an
entity which limits his liability (e.g., a limited partnership or S
corporation), he will be treated the same as a Limited Partner and generally
will be subject to the passive activity limitations. Contractual limitations
on the liability of Investor General Partners under the Partnership Agreement
(e.g., insurance, limited indemnification, etc.) will not cause Investor
General Partners to be subject to the passive activity limitations.
Deductions disallowed by the at-risk limitation on losses under Section
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 under Section 465 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. 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.
PUBLICLY TRADED PARTNERSHIP RULES. 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.C. Sections 469(k)(2) and
7704. However, in the opinion of Special Counsel 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. Section 1.7704-1(e)).
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 the Managing General Partner anticipates will be in the late summer of
2000. Thereafter, each Investor General Partner will
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 7
have limited liability as a limited partner under the Revised Uniform Limited
Partnership Act of Pennsylvania with respect to his interest in the
Partnership.
Concurrently, the Investor General Partner will become subject to the
passive activity limitations. However, because an Investor General Partner
will have a non-passive loss in 1999 as a result of the Partnership's
deduction for Intangible Drilling Costs, his net income from Partnership
Wells following the conversion will continue to be characterized as
non-passive income which cannot be offset with passive losses. An Investor
General Partner's conversion of his Partnership interest into a Limited
Partner interest should not have any other 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. Section 1.1254-2. A reduction in a partner's share of liabilities
is treated as a constructive distribution of cash to the partner, which
reduces the basis of the partner's interest in the partnership and is taxable
to the extent it exceeds such basis.
TAXABLE YEAR
The Partnership intends to adopt a calendar year taxable year. I.R.C.
Section 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%.
1999 EXPENDITURES
The Managing General Partner anticipates that all of the Partnership's
subscription proceeds will be expended in 1999 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,
the Managing General Partner anticipates that the Partnership will prepay in
1999 most, if not all, of its intangible drilling and development costs for
wells the drilling of which will begin in 2000. The deductibility in 1999 of
such advance payments cannot be guaranteed. (See "- Drilling Contracts,"
below.)
AVAILABILITY OF CERTAIN DEDUCTIONS
Ordinary and necessary business expenses, including reasonable
compensation for personal services actually rendered, are deductible in the
year incurred. Treasury Regulation Section 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 Special Counsel that the amounts payable
to the Managing General Partner and its Affiliates, including the amounts
paid to the Managing General Partner 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.
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 8
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 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. Section
1.612-4(a). (See "Participation in Costs and Revenues" in the Prospectus and
"- Limitations on Passive Activities," above.) These deductions are subject
to recapture as ordinary income rather than capital gain upon the disposition
of the property or a Participant's interest in the Partnership. (See
"- Sale of the Properties" and "- Disposition of Partnership Interests,"
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 preparing the Partnership's informational tax returns, the Managing
General Partner will allocate Partnership costs among Intangible Drilling
Costs, Tangible Costs, Direct Costs, Administrative Costs, Organization and
Offering Costs and Operating Costs based upon guidance from advisors to the
Managing General Partner. The Managing General Partner has allocated
approximately 76.12% 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 the Managing General Partner 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.
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 Section
263(c) of the Code is reduced by 30%. I.R.C. Section 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. 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.
DRILLING CONTRACTS
The Partnership will enter into the Drilling and Operating Agreement
with the Managing General Partner or its Affiliates, as a third-party general
drilling contractor, to drill and complete the Partnership's Development
Wells on a footage basis of $37.81 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, the Managing General Partner 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 5,950
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.
The Managing General Partner believes the Drilling and Operating
Agreement is at competitive rates in the proposed areas of operation.
Nevertheless, the amount of the profit realized by the Managing General
Partner 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,
the Managing General Partner anticipates that the Partnership will prepay in
1999 most, if not all, of the intangible drilling and development costs for
drilling activities that will begin in 2000. In KELLER V. COMMISSIONER, 79
T.C. 7 (1982), aff'd 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a
two-part test for the current deductibility of prepaid intangible drilling
and development
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 9
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 KELLER 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.
In LEONARD T. RUTH, 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 the 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 KELLER, 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
KELLER with respect to prepaid intangible drilling and development costs. The
Drilling and Operating Agreement will require the Partnership to prepay in
1999 intangible drilling and development costs for specified wells the
drilling of which will begin in 2000. 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, the Managing General Partner anticipates
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
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 10
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 KELLER, 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. However, in the view of
Special Counsel, a legitimate business purpose for the required prepayments
may exist under the guidelines set forth in KELLER, 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
begins before the close of the 90th day after the close of the taxable year.
The Managing General Partner will attempt to cause the drilling of all
prepaid Partnership Wells to begin on or before March 30, 2000. However, the
drilling 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 the
drilling of all prepaid Partnership Wells required by the Drilling and
Operating Agreement to begin on or before March 30, 2000, will actually begin
by that date. In that event, deductions claimed in 1999 for prepaid
intangible drilling and development costs would be disallowed and deferred to
the 2000 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.
DEPLETION ALLOWANCE
Proceeds from the sale of the Partnership's 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.
These deductions are subject to recapture as ordinary income rather than
capital gain upon the disposition of the property or a Participant's interest
in the Partnership. (See "- Sale of the Properties" and "- Disposition of
Partnership Interests," below.)
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 is based on the Participant's share of the
Partnership's gross income from its oil and gas properties. 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
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KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 11
rate of percentage depletion for marginal production in 1999 is 24%. (See the
model decline curve included in the United Energy Development Consultants,
Inc. Geologic Evaluation in "Proposed Activities - Information Regarding
Currently Proposed Wells" in the Prospectus.)
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 percentage
depletion, net operating loss carry-backs and capital loss carry-backs. With
respect to marginal properties, however, the 100% of net income property
limitation is suspended for 1999.
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.
DEPRECIATION - MODIFIED ACCELERATED COST RECOVERY SYSTEM ("MACRS")
Tangible Costs and the related depreciation deductions are allocated and
charged under the Partnership Agreement 43.75% to the Managing General
Partner and 56.25% to the Participants. These deductions are subject to
recapture as ordinary income rather than capital gain upon the disposition of
the property or a Participant's interest in the Partnership. (See "- Sale
of the Properties" and "- Disposition of Partnership Interests," below.)
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. I.R.C. Section 168(c). 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 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 MACRS 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.
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 the Managing General Partner, which
will contribute the Leases to the Partnership as a part of its Capital
Contribution.
TAX BASIS OF PARTICIPANTS' INTERESTS
A Participant's distributive share of Partnership loss is allowable only
to the extent of the adjusted basis of the Participant's interest in the
Partnership at the end of the Partnership's taxable year. 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; (ii) his share,
if any, of Partnership debt; and (iii) his share of Partnership income. (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 Partnership liabilities, if
any, is considered a cash distribution. 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 - If You Choose to Invest as a General Partner for
the Tax Benefits, Then You Have a Greater Risk Than a Limited Partner" in the
Prospectus.)
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KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 12
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.)
"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 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 the loss only to the extent of the amount he has "at risk" in such
activities at the end of a taxable year. 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 the pledged property. I.R.C. Section 465(b)(1) and (2). However, amounts
borrowed will not be considered "at risk" if the amounts are borrowed from
any person who has an interest (other than as a creditor) in the 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 the year from the activity. 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 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. Previously allowed
losses must be recaptured, I.E., included in gross income, if the "at risk"
amount is reduced below zero. 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."
DISTRIBUTIONS FROM A PARTNERSHIP
Generally, a cash distribution from a partnership to a partner in excess
of the adjusted basis of the 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. Section 731(a)(1). No loss is recognized by the partners on these
types of distributions. I.R.C. Section 731(a)(2). No gain or loss is
recognized by the Partnership on these types of distributions. I.R.C. Section
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, Section 5.04(d).] I.R.C. Sections 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.)
SALE OF THE PROPERTIES
Generally, net long-term capital gains of a noncorporate taxpayer on the
sale of assets held more than a year are taxed at a maximum rate of 20% or
10% if they would be subject to tax at a rate of 15% if they were not
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September 29, 1999
Page 13
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, which is
reduced to $1,500 for married persons filing separate returns, or the excess
of capital losses over capital gains.
Gains and losses from sales of oil and gas properties held for more than
twelve months generally will be treated as a long-term capital gain, while a
net loss will be an ordinary deduction, except to the extent of depreciation
recapture on equipment and recapture of any intangible drilling and
development costs, depletion deductions and certain losses on previous sales,
if any, of the Partnership's assets as discussed below. 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. Section 1254(a).
(See "- Intangible Drilling and Development Costs," above.)
In addition, the deductions for depletion which reduced the adjusted
basis of the property are subject to recapture as ordinary income, and all
income to the extent of MACRS deductions claimed by the Partnership. (See
"- Depletion Allowance" and "- Depreciation - Modified Accelerated Cost
Recovery System ("MACRS")," above.)
DISPOSITION OF PARTNERSHIP INTERESTS
The sale or exchange, including a repurchase by the Managing General
Partner, 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
long-term capital gain or loss. However, previous deductions for
depreciation, depletion and intangible drilling and development costs may be
recaptured as ordinary income rather than capital gain. (See "- Sale of the
Properties," above.) In the event the interest is held for twelve months or
less, such gain or loss will generally be short-term gain or loss. Also, a
Participant's pro rata share of the Partnership's liabilities, if any, as of
the date of the sale or exchange must be included in the amount realized.
Therefore, the gain recognized may result in a tax liability greater than the
cash proceeds, if any, from such disposition. In addition to gain from a
passive activity, a portion of any gain recognized by a Limited Partner on the
sale or other disposition of his interest in the Partnership will be
characterized as portfolio income under Section 469 to the extent the gain is
itself attributable to portfolio income, e.g. interest on investment of
working capital. Treas. Reg. Section 1.469-2T(e)(3). (See "- Limitations on
Passive Activities," above.)
A gift of an interest in the Partnership may result in federal and/or
state income tax and gift tax liability of the Participant, and interests in
different partnerships do not qualify for tax-free like-kind exchanges. I.R.C.
Section 1031(a)(2)(D). Other dispositions of a Participant's interest,
including a repurchase of the interest by the Managing General Partner, 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. Rev. Rul. 84-52, 1984-1 C.B. 157.
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Atlas Resources, Inc.
September 29, 1999
Page 14
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. Section 6050K.
After receiving the 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.
If a partner sells or exchanges his entire interest in a partnership,
the taxable year of the partnership will close with respect to that 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. Section 706(d).
NO DISPOSITION OF AN INTEREST IN THE PARTNERSHIP (INCLUDING REPURCHASE
OF THE INTEREST BY THE MANAGING GENERAL PARTNER) SHOULD BE MADE BY ANY
PARTICIPANT PRIOR TO CONSULTATION WITH HIS TAX ADVISOR.
MINIMUM TAX - TAX PREFERENCES
With limited exceptions, all taxpayers are subject to the alternative
minimum tax. If the alternative minimum tax exceeds the regular tax, the
excess is payable in addition to the regular tax. The alternative minimum
tax is intended to insure that no one with substantial income can avoid tax
liability by using deductions and credits. The alternative minimum tax
accomplishes this objective by not treating favorably certain items that are
treated favorably for purposes of the regular tax, 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 Section 56(e) of the Code and investment
interest expense not exceeding net investment income), and certain estate
taxes. The net operating loss for 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 Section 172(d) allowable
in computing alternative minimum taxable income. Code sections suspending
losses, such as Sections 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.
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
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September 29, 1999
Page 15
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. 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 item for costs of nonproductive wells.
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.
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. I.R.C. Section 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 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 income from a trade or
business in which the taxpayer does not materially participate if the
activity is not a "passive activity." In the case of Investor General
Partners, this includes the Partnership prior to the conversion of Investor
General Partner Units to Limited Partner interests. 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 Section 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.
ALLOCATIONS
The Partnership Agreement allocates to each Partner his share of the
Partnership's income, gains, credits and deductions, including the deductions
for intangible drilling and development costs and depreciation. 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 these
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,
Section 5.03(b).]
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Atlas Resources, Inc.
September 29, 1999
Page 16
Allocations made in a manner that is disproportionate to the respective
interests of the partners in a partnership of any item of partnership income,
gain, loss, deduction or credit will not be given effect unless the
allocation has "substantial economic effect." I.R.C. Section 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 to 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. 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. Section
1.704-l(b)(2)(ii)(d). (See Section 5.03(h) of the Partnership Agreement.)
Special provisions apply to deductions related to nonrecourse debt. If
the Managing General Partner or an Affiliate makes a nonrecourse loan to the
Partnership ("partner nonrecourse liability"), Partnership losses,
deductions, or Section 705(a)(2)(B) expenditures attributable to the loan
must be allocated to the Managing General Partner, and if there is a net
decrease in partner nonrecourse liability minimum gain with respect to the
loan, the Managing General Partner must be allocated income and gain equal to
the net decrease. (See Section 5.03(i) 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 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, for example, 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 tax liability on 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 the Managing General Partner's
policy that Partnership distributions will not be less than the Managing
General Partner's estimate of the Participants' income tax liability with
respect to Partnership income.
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
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KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 17
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. 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.
PARTNERSHIP BORROWINGS
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 borrowings could create income
tax liability for the Participants in excess of cash distributions to them,
since repayments of principal are not deductible for federal income tax
purposes. In addition, interest on the loans will not be deductible unless
the loans are bona fide loans that will not be treated as Capital
Contributions. In Revenue Ruling 72-135, 1972-1 C.B. 200, the IRS ruled that
a nonrecourse loan from a general partner 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.
PARTNERSHIP ORGANIZATION AND SYNDICATION FEES
Expenses connected with the issuance and sale of interests in a
partnership, such as promotional expense, selling expense, commissions,
professional fees and printing costs, are not deductible. However, expenses
incident to the creation of a partnership may be amortized over a period of
not less than 60 months. Such amortizable organization expenses will be paid
by the Managing General Partner as part of the Partnership's Organization and
Offering Costs and any related deductions, which the Managing General Partner
does not anticipate will be material in amount, will be allocated to the
Managing General Partner. I.R.C. Section 709; Treas. Reg. Sections 1.709-1
and 2.
TAX ELECTIONS
The Partnership may elect to adjust the basis of Partnership property on
the transfer of an interest in the 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 Section 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 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 Section 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
Section 162 of the Code, the Partnership's deductions would be reduced.
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KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 18
DISALLOWANCE OF DEDUCTIONS UNDER SECTION 183 OF THE CODE
Under Section 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 the
activity exceeds the deductions attributable to the 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 and the possibility that the
IRS could successfully challenge the Partnership 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 Section 183. (See Treas. Reg. Section 1.183-2(c),
Example (5).) 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
possess the requisite profit motive.
TERMINATION OF A PARTNERSHIP
Pursuant to Section 708(b) of the Code, the 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, for example, in
the case of Partners using fiscal years other than the calendar year. Under
Section 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, however, will
not result in a termination of the Partnership. Rev. Rul. 84-52, 1984-1 C.B.
157.
LACK OF REGISTRATION AS A TAX SHELTER
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 the 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 determined without reduction for
gross income to be derived from the investment.
The Managing General Partner 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, the Managing General Partner does not believe that the Partnership
will be a "potentially abusive tax shelter." Accordingly, the Managing
General Partner does not intend to cause the Partnership to register with the
IRS as a tax shelter.
If it is subsequently determined by the IRS or the courts that the
Partnership was required to be registered with the IRS as a tax shelter, the
Managing General Partner 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
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KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 19
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
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, the Managing General Partner does not believe the
Partnership is subject to the requirements of Section 6112. If this
determination is wrong, Section 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 Section 6112, 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 the
partnership items on the partnership return. I.R.C. Sections 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. Section 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 the
Managing General Partner, 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 any proceedings undertaken by the Tax 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.
TAX RETURNS. A Participant's 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.
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September 29, 1999
Page 20
PENALTIES AND INTEREST
IN GENERAL. Interest 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 those 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. Section 1.6662-3.
VALUATION MISSTATEMENT PENALTY. 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. Section 6662(e) and (h).
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
($10,000 in the case of corporations other than S corporations or personal
holding companies). I.R.C. Section 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.
IRS ANTI-ABUSE RULE. Under Treas. Reg. Section 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 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. Section
1.701-2.
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 21
STATE AND LOCAL TAXES
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.
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.
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 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.
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. I.R.C. Section 1402(a). For 1999 the ceiling for social security
tax of 12.4% is $72,600 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,
which will be adjusted for inflation. 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 $650,000 (which increases in stages to
<PAGE>
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
September 29, 1999
Page 22
$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.
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,
/s/ KUNZMAN & BOLLINGER, INC.
KUNZMAN & BOLLINGER, INC.
<PAGE>
ESCROW AGREEMENT
<PAGE>
EXHIBIT 10(a)
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
ESCROW AGREEMENT
THIS AGREEMENT, made to be effective as of the 22nd day of September
1999, by and between Atlas Resources, Inc., a Pennsylvania corporation (the
"Managing General Partner"), Anthem Securities, Inc., a Pennsylvania corporation
("Anthem"), Bryan Funding, Inc., a Pennsylvania corporation ("Bryan Funding"),
collectively Anthem and Bryan Funding are referred to as the "Dealer-Manager",
Atlas-Energy for the Nineties-Public #8 Ltd., a Pennsylvania limited partnership
(the "Partnership") and National City Bank of Pennsylvania, Pittsburgh,
Pennsylvania, as escrow agent (the "Escrow Agent").
WITNESSETH:
WHEREAS, the Partnership intends to offer publicly for sale to qualified
investors (the "Investors") up to 1,800 limited partnership interests in the
Partnership (the "Units"); and
WHEREAS, each Investor will be required to pay his subscription in full
upon subscribing ($10,000 per Unit, however, the Managing General Partner, in
its discretion, may accept one-half Unit [$5,000] subscriptions, with larger
subscriptions permitted in $1,000 increments), by check, draft or money order
except that the broker-dealers and the Managing General Partner, its officers
and directors and Affiliates, may purchase Units net of the Dealer-Manager fee,
the commissions and reimbursement of marketing expenses and bona fide
accountable due diligence expenses set forth below, and registered investment
advisors and their clients may purchase Units subject to the Dealer-Manager fee
but net of the commissions and reimbursement of marketing expenses and bona fide
accountable due diligence expenses set forth below (the "Subscription
Proceeds"); and
WHEREAS, the Managing General Partner and Anthem have executed an
agreement ("Anthem Dealer-Manager Agreement") pursuant to which Anthem will
solicit subscriptions for Units in all states other than Minnesota and New
Hampshire on a "best efforts" "all or none" basis for $1,000,000 and on a "best
efforts" basis for the remaining Units on behalf of the Managing General Partner
and the Partnership and pursuant to which Anthem has been authorized to select
certain members in good standing of the National Association of Securities
Dealers, Inc. ("NASD") to participate in the offering of the Units ("Selling
Agents"); and
WHEREAS, the Managing General Partner and Bryan Funding have executed an
agreement ("Bryan Funding Dealer-Manager Agreement") pursuant to which Bryan
Funding will solicit subscriptions for Units in the states of Minnesota and New
Hampshire on a "best efforts" "all or none" basis for $1,000,000 and on a "best
efforts" basis for the remaining Units on behalf of the Managing General Partner
and the Partnership and pursuant to which Bryan Funding has been authorized to
select certain members in good standing of the NASD to participate in the
offering of the Units ("Selling Agents"); and
WHEREAS, the Anthem Dealer-Manager Agreement and the Bryan Funding
Dealer-Manager Agreement, collectively referred to as the "Dealer-Manager
Agreement", provide for compensation to the Dealer-Manager which includes, but
is not limited to: (i) a 2.5% Dealer-Manager fee; (ii) a 7.0% sales commission;
(iii) a .5% reimbursement of marketing expenses; and (iv) reimbursement of the
Selling Agents' bona fide accountable due diligence expenses of .5% per Unit to
participate in the offering of the Units, all or a portion of which compensation
will be reallowed to the Selling Agents and wholesalers; and
1
<PAGE>
WHEREAS, under the terms of the Dealer-Manager Agreement the Subscription
Proceeds are required to be held in escrow subject to the receipt and acceptance
by the Managing General Partner of the minimum Subscription Proceeds of
$1,000,000, excluding any optional subscription by the Managing General Partner,
its officers, directors and Affiliates; and
WHEREAS, no subscriptions to the Partnership will be accepted after
receipt of the maximum Subscription Proceeds of $18,000,000 or December 31,
1999, whichever event occurs first (the "Offering Termination Date"); and
WHEREAS, to facilitate compliance with the terms of the Dealer-Manager
Agreement, the Managing General Partner and the Dealer-Manager desire to have
the Subscription Proceeds deposited with the Escrow Agent and the Escrow Agent
desires to hold the Subscription Proceeds pursuant to the terms and conditions
set forth herein;
NOW, THEREFORE, in consideration of the mutual covenants and conditions
herein contained, the parties hereto, intending to be legally bound, hereby
agree as follows:
1. APPOINTMENT OF ESCROW AGENT. The Managing General Partner, the
Partnership and the Dealer-Manager hereby appoint Escrow Agent as the
escrow agent to receive and to hold the Subscription Proceeds deposited
with Escrow Agent by the Dealer-Manager and the Selling Agents pursuant
hereto and Escrow Agent hereby agrees to serve in such capacity during
the term and based upon the provisions hereof.
2. DEPOSIT OF SUBSCRIPTION PROCEEDS. Pending receipt of the minimum
Subscription Proceeds of $1,000,000, the Dealer-Manager shall deposit the
Subscription Proceeds of each Investor with the Escrow Agent and shall
deliver to the Escrow Agent a copy of the Subscription Agreement of such
Investor. Payment for each subscription for Units shall be in the form of
a check made payable to "Atlas Public #8 Ltd., Escrow Agent, National
City Bank of PA". The Escrow Agent shall deliver a receipt to Anthem and
the Managing General Partner for each deposit of Subscription Proceeds
made pursuant hereto by Anthem, and to Bryan Funding and the Managing
General Partner for each deposit of subscription proceeds made pursuant
hereto by Bryan Funding.
3. INVESTMENT OF SUBSCRIPTION PROCEEDS. The Subscription Proceeds shall be
deposited in an interest bearing account maintained by the Escrow Agent
entitled "Armada Government Fund." Subscription Proceeds may be
temporarily invested by the Escrow Agent only in income producing
short-term, highly liquid investments secured by the United States
government where there is appropriate safety of principal, such as U.S.
Treasury Bills. The interest earned shall be added to the Subscription
Proceeds and disbursed in accordance with the provisions of paragraph 4
or 5, as the case may be.
4. DISTRIBUTION OF SUBSCRIPTION PROCEEDS. If the Escrow Agent:
(a) receives written notice from an authorized officer of the
Managing General Partner that at least the minimum aggregate
subscriptions of $1,000,000 have been received and accepted by
the Managing General Partner; and
(b) determines that Subscription Proceeds for at least $1,000,000 as
determined by the Managing General Partner have cleared the
banking system and are good;
2
<PAGE>
the Escrow Agent shall promptly release and distribute to the Managing
General Partner such escrowed Subscription Proceeds which have cleared
the banking system and are good plus any interest paid and investment
income earned on such Subscription Proceeds while held by the Escrow
Agent in an escrow account.
Any remaining Subscription Proceeds, plus any interest paid and
investment income earned on such Subscription Proceeds while held by the
Escrow Agent in an escrow account shall be promptly released and
distributed to the Managing General Partner by the Escrow Agent as such
Subscription Proceeds clear the banking system and become good.
5. SEPARATE PARTNERSHIP ACCOUNT. During the continuation of the offering
after the Partnership is funded with cleared Subscription Proceeds of at
least $1,000,000 and the Escrow Agent receives the notice described in
Paragraph 4 of this Agreement, and prior to the Offering Termination
Date, any additional Subscription Proceeds may be deposited by the
Dealer-Manager directly in a separate Partnership account which shall not
be subject to the terms of this Agreement.
6. DISTRIBUTIONS TO SUBSCRIBERS.
(a) In the event that the Partnership will not be funded as
contemplated because less than the minimum aggregate
subscriptions of $1,000,000 have been received and accepted by
the Managing General Partner by twelve p.m. (noon), local time,
on December 31, 1999, or for any other reason, the Managing
General Partner shall so notify the Escrow Agent, whereupon the
Escrow Agent promptly shall distribute to each Investor a refund
check made payable to such Investor in an amount equal to the
Subscription Proceeds of such Investor, plus any interest paid or
investment income earned thereon while held by the Escrow Agent
in an escrow account as calculated by the Managing General
Partner.
(b) In the event that a subscription for Units submitted by an
Investor is rejected by the Managing General Partner for any
reason after the Subscription Proceeds relating to such
subscription have been deposited with the Escrow Agent, then the
Managing General Partner promptly shall notify the Escrow Agent
of such rejection, and the Escrow Agent shall promptly distribute
to such Investor a refund check made payable to such Investor in
an amount equal to the Subscription Proceeds of such Investor,
plus any interest paid or investment income earned thereon while
held by the Escrow Agent in an escrow account as calculated by
the Managing General Partner.
7. COMPENSATION AND EXPENSES OF ESCROW AGENT. The Managing General Partner
shall be solely responsible for and shall pay the compensation of the
Escrow Agent for its services hereunder, as provided in Appendix 1 to
this Agreement and made a part hereof, and the charges, expenses
(including any reasonable attorneys' fees), and other out-of-pocket
expenses incurred by the Escrow Agent in connection with the
administration of the provisions of this Agreement. The Escrow Agent
shall have no lien on the Subscription Proceeds deposited in an escrow
account unless and until the Partnership is funded with cleared
Subscription Proceeds of at least $1,000,000 and the Escrow Agent
receives the notice described in Paragraph 4 of this Agreement, at which
time the Escrow Agent shall have, and is hereby granted, a prior lien
upon any property, cash, or assets held hereunder, with respect to its
unpaid compensation and nonreimbursed expenses, superior to the interests
of any other persons or entities.
8. DUTIES OF ESCROW AGENT. The Escrow Agent shall not be obligated to accept
any notice, make any delivery, or take any other action under this Escrow
Agreement unless the notice or request or demand for delivery or other
action is in writing and given or made by the party given the right or
charged with the obligation under this Escrow Agreement to give the
notice or to make the request or demand. In no event shall the Escrow
Agent be obligated to accept any notice, request, or demand from anyone
other than the Managing General Partner or the Dealer-
3
<PAGE>
Manager.
9. LIABILITY OF ESCROW AGENT. The Escrow Agent shall not be liable for any
damages, or have any obligations other than the duties prescribed herein
in carrying out or executing the purposes and intent of this Escrow
Agreement; provided, however, that nothing herein contained shall relieve
the Escrow Agent from liability arising out of its own willful misconduct
or gross negligence. Escrow Agent's duties and obligations under this
Agreement shall be entirely administrative and not discretionary. Escrow
Agent shall not be liable to any party hereto or to any third party as a
result of any action or omission taken or made by Escrow Agent in good
faith. The parties to this Agreement will indemnify Escrow Agent, hold
Escrow Agent harmless, and reimburse Escrow Agent from, against and for,
any and all liabilities, costs, fees and expenses (including reasonable
attorney's fees) Escrow Agent may suffer or incur by reason of its
execution and performance of this Agreement. In the event any legal
questions arise concerning Escrow Agent's duties and obligations
hereunder, Escrow Agent may consult with its counsel and rely without
liability upon written opinions given to it by such counsel.
The Escrow Agent shall be protected in acting upon any written notice,
request, waiver, consent, authorization, or other paper or document which
the Escrow Agent, in good faith, believes to be genuine and what it
purports to be.
In the event that there shall be any disagreement between any of the
parties to this Agreement, or between them or any of them and any other
person, resulting in adverse claims or demands being made in connection
with this Agreement, or in the event that Escrow Agent, in good faith,
shall be in doubt as to what action it should take hereunder, Escrow
Agent may, at its option, refuse to comply with any claims or demands on
it or refuse to take any other action hereunder, so long as such
disagreement continues or such doubt exists. In any such event, Escrow
Agent shall not be or become liable in any way or to any person for its
failure or refusal to act and Escrow Agent shall be entitled to continue
to so refrain from acting until the dispute is resolved by the parties
involved.
National City Bank of Pennsylvania is acting solely as Escrow Agent and
is not a party to, nor has it reviewed or approved any agreement or
matter of background related to this Agreement, other than this Agreement
itself, and has assumed, without investigation, the authority of the
individuals executing this Agreement to be so authorized on behalf of the
party or parties involved.
10. RESIGNATION OR REMOVAL OF ESCROW AGENT. The Escrow Agent may resign as
such following the giving of thirty days' prior written notice to the
other parties hereto. Similarly, the Escrow Agent may be removed and
replaced following the giving of thirty days' prior written notice to the
Escrow Agent by the other parties hereto.
In either event, the duties of the Escrow Agent shall terminate thirty
days after the date of such notice (or as of such earlier date as may be
mutually agreeable); and the Escrow Agent shall then deliver the balance
of the Subscription Proceeds (and any interest paid or investment income
earned thereon while held by the Escrow Agent in an escrow account) in
its possession to a successor escrow agent as shall be appointed by the
other parties hereto as evidenced by a written notice filed with the
Escrow Agent. If the other parties hereto are unable to agree upon a
successor or shall have failed to appoint a successor prior to the
expiration of thirty days following the date of the notice of resignation
or removal, the then acting Escrow Agent may petition any court of
competent jurisdiction for the appointment of a successor escrow agent or
other appropriate relief; and any such resulting appointment shall be
binding upon all of the parties hereto.
Upon acknowledgment by any successor escrow agent of the receipt of the
then remaining balance of the Subscription Proceeds (and any interest
paid or investment income earned thereon while held by the Escrow Agent
in an escrow account), the then acting Escrow Agent shall be fully
released and relieved of all duties, responsibilities, and obligations
under this Agreement.
4
<PAGE>
11. TERMINATION. This Agreement shall terminate and the Escrow Agent shall
have no further obligation with respect hereto upon the occurrence of the
distribution of all Subscription Proceeds (and any interest paid or
investment income earned thereon while held by the Escrow Agent in an
escrow account) as contemplated hereby or upon the written consent of all
the parties hereto.
12. NOTICE. Any notices or instructions, or both, to be given hereunder shall
be validly given if set forth in writing and mailed by certified mail,
return receipt requested, as follows:
IF TO THE ESCROW AGENT:
National City Bank of Pennsylvania
Attention: Mr. Robert Mialki, Vice President
Corporate Trust Department
300 Fourth Avenue
Pittsburgh, Pennsylvania 15278-2331
Phone: (412) 644-8401
Facsimile: (412) 644-7971
IF TO THE MANAGING GENERAL PARTNER:
Atlas Resources, Inc.
311 Rouser Road
P.O. Box 611
Moon Township, Pennsylvania 15108
Attention: Tony C. Banks
Phone: (412) 262-2830
Facsimile: (412) 262-2820
IF TO ANTHEM:
Anthem Securities, Inc.
311 Rouser Road
P.O. Box 926
Coraopolis, Pennsylvania 15108
Attention: Eric D. Koval
Phone: (412) 262-1680
Facsimile: (412) 262-7430
IF TO BRYAN FUNDING:
Bryan Funding, Inc.
393 Vanadium Road
Pittsburgh, Pennsylvania 15243
Attention: Richard G. Bryan, Jr.
Phone: (412) 276-9393
Facsimile: (412) 276-9396
Any party may designate any other address to which notices and
instructions shall be sent by notice duly given in accordance herewith.
5
<PAGE>
13. MISCELLANEOUS.
(a) This Agreement shall be governed by and construed in accordance
with the laws of the Commonwealth of Pennsylvania.
(b) This Agreement is binding upon and shall inure to the benefit of
the undersigned and their respective heirs, successors and
assigns.
(c) This Agreement may be executed in multiple copies, each executed
copy to serve as an original.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement to be
effective as of the day and year first above written.
NATIONAL CITY BANK OF PENNSYLVANIA
ATTEST: As Escrow Agent
By: Brian Morris By: John Hoffman
--------------------------- ---------------------------
(Authorized Officer) (Authorized Officer)
ATLAS RESOURCES, INC.
ATTEST: A Pennsylvania corporation
By: Barbara J. Krasnicki By: Tony C. Banks
--------------------------- ---------------------------
Secretary Tony C. Banks, Senior Vice President and
Chief Financial Officer
ANTHEM SECURITIES, INC.
ATTEST: A Pennsylvania corporation
By: Eric D. Koval By: Eric D. Koval
--------------------------- ---------------------------
Secretary Eric D. Koval, President
BRYAN FUNDING, INC.
ATTEST: A Pennsylvania corporation
By: Richard G. Bryan, Jr. By: Richard G. Bryan, Jr.
--------------------------- ---------------------------
Secretary Richard G. Bryan, Jr., President
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
By: ATLAS RESOURCES, INC.
ATTEST: Managing General Partner
By: Barbara J. Krasnicki By: Tony C. Banks
--------------------------- ---------------------------
Secretary Tony C. Banks, Senior Vice President
Chief Financial Officer
6
<PAGE>
APPENDIX I TO ESCROW AGREEMENT
COMPENSATION FOR SERVICES OF ESCROW AGENT
Escrow Agent annual fee per year or any part thereof $3,000.00
7
<PAGE>
CONSENT OF GRANT THORNTON, L.L.P.
<PAGE>
CONSENT OF GRANT THORNTON LLP
We have issued our report dated June 30, 1999 on the balance sheet of
Atlas-Energy for the Nineties - Public #8 Ltd. as of June 11, 1999 and our
report dated March 22, 1999 on the consolidated balance sheet of Atlas
Resources, Inc. as of September 30, 1998 contained in the Registration Statement
and Prospectus for Atlas-Energy for the Nineties Public #8 Ltd. We consent to
use of the aforementioned reports in the Registration Statement and Prospectus,
and to the use of our name as it appears under the caption "Experts".
/s/ GRANT THORNTON LLP
Cleveland, Ohio
September 29, 1999
<PAGE>
CONSENT OF UNITED ENERGY DEVELOPMENT CONSULTANTS, INC.
<PAGE>
Exhibit 24(b)
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 its Geologic Evaluation, dated September 27,
1999, in the Registration Statement and any supplements thereto, including
pre-effective and post-effective amendments, for the Atlas-Energy for the
Nineties-Public #8, Ltd., and to all references to UEDC as having prepared
such report and as an expert concerning such report.
UEDC, Inc.
/s/ Isaias Ortiz 9/27/99
- --------------------------------------
Isaias Ortiz September 27, 1999
President Pittsburgh, PA
<PAGE>
CONSENT OF WRIGHT & COMPANY, INC.
<PAGE>
Exhibit 24(d)
CONSENT OF INDEPENDENT PETROLEUM CONSULTANTS
Wright & Company, Inc. hereby consents to the use of our analysis
relating to the 1998 oil and gas reserves at October 1, 1998 of Atlas
America, Inc. for use in the Pre-Effective Amendment No. 2 to Form SB-2
Registration Statement of ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
(Registration No. 333-82398), and to all references to Wright & Company, Inc.
as having prepared such analysis and as an expert concerning such analysis.
Wright & Company, Inc.
/s/ Wright & Company, Inc.
--------------------------
Wright & Company, Inc.
Brentwood, TN
September 24, 1999
<PAGE>
POWER OF ATTORNEY
<PAGE>
[Logo]
Exhibit 25
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and/or
directors of Atlas Resources, Inc., a Pennsylvania corporation which has
filed with the Securities and Exchange Commission, under the provisions of
the Securities Act of 1933, as amended, a Registration Statement on Form SB-2
relating to certain securities of Atlas-Energy for the Nineties-Public #8
Ltd., constitutes and appoints James R. O'Mara and Tony C. Banks, his/her
true and lawful attorney-in-fact, with full power of substitution and
resubstitution and with full power to act without another, for him/her and in
his/her name, place and stead, in any and all capacities, to sign such
Registration Statement, and any and all amendments, including pre-effective
amendments and post-effective amendments thereto, and to file the same, with
all exhibits thereto, and other documents in connection therewith, with the
Securities and Exchange Commission and all states and other jurisdictions
wherein such Registration Statement and amendments thereto may be filed for
securities compliance measures, granting unto said attorneys-in-fact and
agents, and each of them full power and authority to do and perform each and
every act and thing requisite and necessary to be done in and about the
premises, as fully to all intents and purposes as he/she might or could do in
person, hereby ratifying and confirming all that said attorneys-in-fact and
agents, or his/her substitute or substitutes, may lawfully do or cause to be
done by virtue hereof.
<TABLE>
<S> <C>
Dated: September 24, 1999 /s/ Charles T. Koval
--------------------------------------------------------------------
Charles T. Koval, Chairman of the Board and a Director
Dated: September 24, 1999 /s/ James R. O'Mara
--------------------------------------------------------------------
James R. O'Mara, President, Chief Executive Officer and a Director
Dated: September 24, 1999 /s/ Tony C. Banks
--------------------------------------------------------------------
Tony C. Banks, Senior Vice President of Finance, Principal Financial
Officer, and a Director
Dated: September 24, 1999 /s/ Frank P. Carolas
--------------------------------------------------------------------
Frank P. Carolas, Vice President of Land and Geology
Dated: September __, 1999
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Jeffrey C. Simmons, Vice President of Production
Dated: September 24, 1999 /s/ William R. Seiler
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William R. Seiler, Vice President and Controller
</TABLE>
<PAGE>
Exhibit 25
ATLAS-ENERGY FOR THE NINETIES-PUBLIC #8 LTD.
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and/or
directors of Atlas Resources, Inc., a Pennsylvania corporation which has
filed with the Securities and Exchange Commission, under the provisions of
the Securities Act of 1933, as amended, a Registration Statement on Form SB-2
relating to certain securities of Atlas-Energy for the Nineties-Public #8
Ltd., constitutes and appoints James R. O'Mara and Tony C. Banks, his/her
true and lawful attorney-in-fact, with full power of substitution and
resubstitution and with full power to act without another, for him/her and in
his/her name, place and stead, in any and all capacities, to sign such
Registration Statement, and any and all amendments, including pre-effective
amendments and post-effective amendments thereto, and to file the same, with
all exhibits thereto, and other documents in connection therewith, with the
Securities and Exchange Commission and all states and other jurisdictions
wherein such Registration Statement and amendments thereto may be filed for
securities compliance measures, granting unto said attorneys-in-fact and
agents, and each of them full power and authority to do and perform each and
every act and thing requisite and necessary to be done in and about the
premises, as fully to all intents and purposes as he/she might or could do in
person, hereby ratifying and confirming all that said attorneys-in-fact and
agents, or his/her substitute or substitutes, may lawfully do or cause to be
done by virtue hereof.
<TABLE>
<S> <C>
Dated: September __, 1999
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Charles T. Koval, Chairman of the Board and a Director
Dated: September __, 1999
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James R. O'Mara, President, Chief Executive Officer and a Director
Dated: September __, 1999
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Tony C. Banks, Senior Vice President of Finance, Principal Financial
Officer, and a Director
Dated: September __, 1999
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Frank P. Carolas, Vice President of Land and Geology
Dated: September 22, 1999 /s/ Jeffrey C. Simmons
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Jeffrey C. Simmons, Vice President of Production
Dated: September __, 1999
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William R. Seiler, Vice President and Controller
</TABLE>
