<PAGE>
As filed with the Securities and Exchange Commission on September 8, 2000
Registration No. 333-44130
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------------------
PRE-EFFECTIVE AMENDMENT NO. 1
TO
FORM SB-2
REGISTRATION STATEMENT
Under
The Securities Act of 1933
------------------------------------
ATLAS AMERICA PUBLIC #9 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/
------------------------------------
<TABLE>
<CAPTION>
CALCULATION OF REGISTRATION FEE
----------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------
Proposed Proposed
Title of Each Dollar Maximum Maximum Amount of
Class of Securities Amount Offering Aggregate Registration
to be Registered to be Registered Price per Unit Offering Price Fee
----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Units (1) $15,000,000 $10,000 $15,000,000 $3,960
----------------------------------------------------------------------------------------------
</TABLE>
(1) "Units" means the Limited Partner interests and the Investor General
Partner interests offered to Participants in the Partnership.
THE REGISTRANT HEREBY AMENDS THE REGISTRATION STATEMENT ON SUCH DATES AS MAY BE
NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER
AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL
THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES
ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH
DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.
<PAGE>
ATLAS AMERICA PUBLIC #9 LTD.
CROSS REFERENCE SHEET
PURSUANT TO RULE 404
<TABLE>
<CAPTION>
Item of Form SB-2 Caption in Prospectus
----------------- ---------------------
<S> <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.
<PAGE>
Preliminary Prospectus Dated September __, 2000
ATLAS AMERICA PUBLIC #9 LTD.
- General and Limited Partner Interests at $10,000 per Unit
- $1,000,000 (100 Units) Minimum Aggregate Capital Contributions
- $15,000,000 (1,500 Units) Maximum Aggregate Capital Contributions
<TABLE>
<S><C>
- Atlas America Public #9 Ltd., a - The Offering:
limited partnership, is managed by
Atlas Resources, Inc. of Total Total
Pittsburgh, Pennsylvania, and will Per Unit Minimum Maximum
be funded to drill primarily -------- ------- -------
natural gas development wells. Public Price $10,000 $1,000,000 $15,000,000
- The units will be offered on a Dealer-manager fee, $1,000 $ 100,000 $ 1,500,000
"best efforts" "minimum-maximum" sales commissions, and
basis. This means the reimbursement for
broker-dealers must sell at least accountable due
100 units in order for this diligence expenses
offering to close, and they are
required to use only their best Proceeds to partnership $9,000 $ 900,000 $13,500,000
efforts to sell the remaining 1,400
units. Thus, this offering may
close even though all of the 1,500 ------------
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, 2000, and
will not be extended. If
subscriptions for $1 million are
not received by the offering
termination date, then your
subscription will be promptly
returned to you from the escrow
account with interest and without
deduction for any fees.
</TABLE>
---------------------------------------
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 America Public #9 Ltd...................................................................................1
Description of Units..........................................................................................1
Investor General Partner Units..........................................................................1
Limited Partner Units...................................................................................2
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 Oil and 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................................................................................................3
Risk of Reduced Partnership Distributions
Because of Decrease in the Price of Oil and Gas.........................................................3
Risks Regarding the Partnership's Gas Market
Which Could Reduce Partnership Distributions............................................................3
If You Choose to Invest as a General Partner
for the Tax Benefits, Then You Have
Greater Risk Than a Limited Partner.....................................................................4
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...........................................................................5
Risks of a Long-Term Investment Because
the Units Are Illiquid and Not Readily
Transferable............................................................................................5
The Number of Partnership Wells Drilled
Depends Upon the Amount of Subscription
Proceeds................................................................................................5
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
Risk of Bias Regarding Geological Report
Prepared by Managing General Partner....................................................................6
Managing General Partner's Subordination
is not a Guarantee of the Return of Any
of Your Investment......................................................................................6
Risk That Borrowings by the Managing
General Partner Could Reduce Funds
Available for Its Subordination Obligation..............................................................6
Compensation and Fees to the Managing General
Partner Regardless of Success of the
Partnership's Activities................................................................................6
Risk of Circumstances Causing Distributions
to Investors to be Reduced or Delayed...................................................................6
Risks Arising From Conflicts of Interest Between
Managing General Partner and the Investors..............................................................6
Risks That Presentment Obligation May Not
Be Funded and Repurchase Price May Not
Reflect Full Value......................................................................................6
Risk Regarding Participation with Third Parties
in Drilling Wells.......................................................................................7
Risk of Prepaying Subscription Proceeds to
Managing General Partner................................................................................7
Risks Associated with Managing General Partner's
Benefit from Development of Partnership
Prospects...............................................................................................7
Tax Risks.....................................................................................................7
You May Owe Taxes in Excess of Your Cash
Distributions from the Partnership......................................................................7
Your Deduction for Intangible Drilling Costs
May Be Limited for Purposes of the
Alternative Minimum Tax.................................................................................8
Investment Interest Deductions of Investor
General Partners May Be Limited.........................................................................8
Lack of Tax Shelter Registration...........................................................................8
ADDITIONAL INFORMATION............................................................................................8
FORWARD LOOKING STATEMENTS AND
ASSOCIATED RISKS..................................................................................................8
INVESTMENT OBJECTIVES.............................................................................................9
ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS............................................................................10
CAPITALIZATION AND SOURCE OF FUNDS
AND USE OF PROCEEDS..............................................................................................11
Source of Funds..............................................................................................11
Use of Proceeds..............................................................................................11
Subsequent Source of Funds and Borrowings....................................................................13
COMPENSATION.....................................................................................................14
Oil and Gas Revenues.........................................................................................14
Lease Costs..................................................................................................14
Drilling Contracts...........................................................................................15
Per Well Charges.............................................................................................15
Gathering Fees...............................................................................................16
Dealer-Manager Fees..........................................................................................17
Other Compensation...........................................................................................17
Estimate of Administrative Costs and Direct Costs
to be Borne by the Partnership...........................................................................17
TERMS OF THE OFFERING............................................................................................18
Subscription to the Partnership..............................................................................18
Partnership Closings and Escrow..............................................................................18
Acceptance of Subscriptions..................................................................................19
Drilling Period..............................................................................................19
Suitability Standards........................................................................................20
In General.............................................................................................20
Purchasers of Limited Partner Units....................................................................20
Purchasers of Investor General Partner Units...........................................................20
Fiduciary Accounts and Confirmations...................................................................21
PRIOR ACTIVITIES.................................................................................................22
MANAGEMENT.......................................................................................................29
Managing General Partner and Operator........................................................................29
Organizational Diagram.......................................................................................30
Officers, Directors and Key Personnel........................................................................30
Remuneration.................................................................................................32
Security Ownership of Certain Beneficial Owners..............................................................32
Transactions with Management and Affiliates..................................................................32
PROPOSED ACTIVITIES..............................................................................................33
Overview of Drilling Activities..............................................................................33
Primary Areas of Operations..................................................................................34
The Clinton/Medina Geological Formation
In Northwestern Pennsylvania.......................................................................34
Mississippian/Upper Devonian Sandstone
Reservoirs, Fayette County, Pennsylvania...........................................................35
Secondary Areas of Operations................................................................................35
Clinton/Medina Geological Formation
In Ohio............................................................................................35
Clinton/Medina Geological Formation
In New York........................................................................................36
Mississippian Berea Sandstone in Ohio..................................................................36
Devonian Oriskany Sandstone in Ohio....................................................................36
Kentucky and Virginia..................................................................................37
Acquisition of Leases........................................................................................37
Deep Drilling Rights Retained by
Managing General Partner...............................................................................38
Interests of Parties.........................................................................................38
Primary Areas ...............................................................................................39
Clinton/Medina Geological Formation
In Northwestern Pennsylvania and
Mississippian/Upper Devonian Sandstone
Reservoirs in Fayette County, Pennsylvania.....................................................39
Secondary Areas..............................................................................................40
Title to Properties..........................................................................................40
Drilling and Completion Activities; Operation
of Producing Wells........................................................................................40
Sale of Oil and Gas Production...............................................................................42
ii
<PAGE>
Policy of Treating All Wells Equally in a
Geographic Area................................................................................42
Gathering of the Gas...................................................................................42
Gas Contracts..........................................................................................43
Marketing of Gas Production from Wells in
Other Areas of the United States...............................................................45
Crude Oil..............................................................................................45
Insurance....................................................................................................45
Use of Consultants and Subcontractors........................................................................46
Information Regarding Currently Proposed Wells...............................................................47
COMPETITION, MARKETS AND REGULATION..............................................................................96
Competition and Markets......................................................................................96
Crude Oil Regulation.........................................................................................97
Federal Gas Regulation.......................................................................................97
State Regulations............................................................................................98
Environmental Regulation.....................................................................................98
Proposed Regulation..........................................................................................99
PARTICIPATION IN COSTS AND REVENUES..............................................................................99
In General...................................................................................................99
Costs........................................................................................................99
Revenues....................................................................................................100
Subordination of Portion of Managing General
Partner's Net Revenue Share..............................................................................101
Table of Participation in Costs and Revenues................................................................101
Allocation and Adjustment Among Investors...................................................................102
Distributions...............................................................................................103
Liquidation.................................................................................................103
CONFLICTS OF INTEREST...........................................................................................103
In General..................................................................................................103
Conflicts Regarding Transactions with the Managing
General Partner and its Affiliates....................................................................104
Conflict Regarding the Drilling and Operating
Agreement................................................................................................104
Conflicts Regarding Sharing of Costs and Revenues...........................................................104
Conflicts Regarding Tax Matters Partner.....................................................................105
Conflicts Regarding Other Activities of the
Managing General Partner, the Operator and
Their Affiliates.........................................................................................105
Conflicts Involving the Acquisition of Leases...............................................................105
Conflicts Between Investors and the Managing
General Partner as an Investor........................................................................108
Lack of Independent Underwriter and Due
Diligence Investigation..................................................................................108
Conflicts Concerning Legal Counsel..........................................................................108
Conflicts Regarding Preparation of
Geological Report.....................................................................................108
Conflicts Regarding Presentment Feature.....................................................................108
Conflicts Regarding Managing General Partner
Withdrawing an Interest...............................................................................109
Conflicts Regarding Order of Pipeline Construction
and Gathering Fees....................................................................................109
Procedures to Reduce Conflicts of Interest..................................................................109
Policy Regarding Roll-Ups...................................................................................110
Certain Transactions........................................................................................111
FIDUCIARY RESPONSIBILITY OF THE
MANAGING GENERAL PARTNER........................................................................................112
In General..................................................................................................112
Limitations on Managing General Partner Liability
as Fiduciary.............................................................................................112
TAX ASPECTS.....................................................................................................113
Summary of Tax Opinion......................................................................................113
Partnership Classification..................................................................................114
Limitations on Passive Activities...........................................................................115
Publicly Traded Partnership Rules.....................................................................115
Conversion from Investor General Partner to
Limited Partner...............................................................................115
Taxable Year................................................................................................115
2000 Expenditures...........................................................................................115
Availability of Certain Deductions..........................................................................116
Intangible Drilling Costs...................................................................................116
Drilling Contracts..........................................................................................116
Depletion Allowance.........................................................................................117
Depreciation - Modified Accelerated Cost
Recovery System ("MACRS").............................................................................118
Leasehold Costs and Abandonment.............................................................................118
Tax Basis of Investors' Interests...........................................................................118
"At Risk" Limitation for Losses.............................................................................118
Distributions from a Partnership............................................................................119
Sale of the Properties......................................................................................119
Disposition of Partnership Interests........................................................................119
Minimum Tax - Tax Preferences...............................................................................119
Limitations on Deduction of Investment Interest.............................................................120
Allocations.................................................................................................120
Partnership Borrowings......................................................................................121
Partnership Organization and Syndication Fees...............................................................121
Tax Elections...............................................................................................121
Disallowance of Deductions under Section 183
of the Internal Revenue Code.............................................................................121
Termination of a Partnership................................................................................121
Lack of Registration as a Tax Shelter.......................................................................121
Investor Lists........................................................................................122
Tax Returns and Audits......................................................................................122
In General............................................................................................122
Tax Returns...........................................................................................122
Penalties and Interest......................................................................................122
In General............................................................................................122
Penalty for Negligence or Disregard of
Rules or Regulations..........................................................................122
Valuation Misstatement Penalty........................................................................122
Substantial Understatement Penalty....................................................................123
IRS Anti-Abuse Rule...................................................................................123
State and Local Taxes.......................................................................................123
Severance and Ad Valorem (Real Estate) Taxes................................................................123
Social Security Benefits and Self-Employment Tax............................................................123
Foreign Partners............................................................................................123
Estate and Gift Taxation....................................................................................124
SUMMARY OF PARTNERSHIP AGREEMENT................................................................................124
Liability of Limited Partners...............................................................................124
Amendments..................................................................................................124
Notice......................................................................................................124
Voting Rights...............................................................................................125
Access to Records...........................................................................................125
Withdrawal of Managing General Partner......................................................................126
SUMMARY OF DRILLING AND OPERATING
AGREEMENT ......................................................................................................126
REPORTS TO INVESTORS............................................................................................127
PRESENTMENT FEATURE.............................................................................................128
TRANSFERABILITY OF UNITS........................................................................................129
Restrictions on Transfer Imposed by the Securities
and Tax Law ..........................................................................................129
PLAN OF DISTRIBUTION............................................................................................130
Commissions...........................................................................................130
Indemnification.......................................................................................131
SALES MATERIAL..................................................................................................131
LEGAL OPINIONS..................................................................................................132
EXPERTS ......................................................................................................132
LITIGATION......................................................................................................132
FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND
THE PARTNERSHIP.............................................................................................133
</TABLE>
iii
<PAGE>
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
iv
<PAGE>
SUMMARY OF THE OFFERING
Throughout this prospectus when there is a reference to you it is a reference to
you as a potential investor or participant in the partnership.
ATLAS AMERICA PUBLIC #9 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,
completing and operating of the wells to be drilled as operator.
The partnership will drill development wells 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 the majority of the wells will be
classified as gas wells although some of the wells may be classified as oil
wells.
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 2000 deduction for
intangible drilling costs will not be subject to the
passive activity limitations. This means that generally
you may deduct approximately 90% of your subscription,
$9,000 per unit, in 2000.
- 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
- the partnership assets
1
<PAGE>
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.
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 2000 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 OIL AND GAS WELLS. Oil and 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 oil and gas recoverable from the well; or
- the time it will take to recover the oil and 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 oil and gas reserves from productive
wells. Oil and 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 oil
and gas in commercial quantities it will not produce enough oil and gas to pay
for the costs of drilling and completing the well, even if tax benefits are
considered. The managing general partner has formed 34 partnerships since 1985,
29 of which were formed in 1990 or subsequent years. All the partnerships are
continuing to make cash distributions, however, 32 of the 34 partnerships have
not yet returned to the investor 100% of his capital contributions without
taking tax savings into account.
2
<PAGE>
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
OIL AND GAS. There is no assurance of the price at which the partnership's oil
and gas will be sold. If oil and gas prices decrease, then your partnership
distributions 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 oil and gas prices have been volatile and there is a risk that
oil and gas prices could decrease in the future.
There is a further risk that the price of oil and 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.
RISKS REGARDING THE PARTNERSHIP'S GAS MARKET WHICH COULD REDUCE PARTNERSHIP
DISTRIBUTIONS. In addition to the risk of decreased oil and gas prices described
above, there are risks associated with the marketing of the gas which could
result in reduced distributions from the partnership to you and the other
investors. These risks are set forth below.
- There is a risk that competition from other gas marketers
will make it more difficult to market the partnership's gas.
- The managing general partner anticipates that a portion of
the partnership's gas production will be sold directly to
industrial end-users situated in the areas where the wells
will be drilled. Selling gas to industrial end-users creates
a risk 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 Northwestern Pennsylvania until it
filed a second Chapter 11 bankruptcy in 1992 owing monies to
the managing general partner and its partnerships.
- There can be no assurance that the terms of a gas supply
agreement will be favorable over the life of the wells. A
substantial portion of the partnership's gas will be sold
under a 10-year agreement which provides that the gas price
may be adjusted upward or downward in accordance with the
spot market price and market conditions. The managing general
partner anticipates that the remainder of the partnership's
gas will be sold under similar contracts. 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 decrease because of market conditions.
Furthermore, even if the gas supply contract did not provide
for price and other adjustments, 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 and the amount of gas to be purchased.
- Partnership revenues may be less the farther the gas is
transported because of increased transportation costs.
- There is a risk that gas production from the wells may be
reduced due to seasonal marketing demands since the demand
for gas is usually greater in the winter months because of
residential heating requirements than the summer months.
There is also a risk that from time to time the managing
general partner will reduce production awaiting a better
gas price. This would reduce or delay distributions from
the partnership to you and the other investors.
- Production from wells drilled in certain areas may be delayed
for up to several months until construction of the necessary
pipelines and production facilities is completed.
3
<PAGE>
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 million during drilling operations and $11 million 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 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; and
- liability for drilling hazards which result in property
damage or personal injury or death to third parties in
excess of the amounts insured under the policies. The
drilling hazards include, but are not limited to:
- well blowouts;
- fires; and
- explosions.
If the insurance proceeds, partnership assets, and the managing general
partner's indemnification of you and the other investor 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:
- the payment of equipment costs and organization costs;
- 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.
4
<PAGE>
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,
then 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 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 5.5 wells
will be drilled if the minimum required subscriptions of $1 million are
received, and approximately 80 wells will be drilled if subscriptions for $15
million are received. Also, there is a risk of cost overruns in drilling and
completing the wells because the wells will not be drilled and completed on a
turnkey basis for a fixed price which would shift the risk of loss to the
managing general partner as drilling contractor. If there are cost overruns on a
well or wells, then the managing general partner anticipates that it would use
subscription proceeds, if available, to pay the cost overrun, or advance the
necessary funds to the partnership. However, using subscription proceeds to pay
cost overruns will result in the partnership drilling fewer wells and having
less diversification.
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.
RISK REGARDING LACK OF INFORMATION REGARDING A PORTION OF THE WELLS. The
wells currently proposed to be drilled represent approximately 63% 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 are 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 show:
- all the wells drilled in the area; or
- the correct volume of gas produced from the wells.
5
<PAGE>
Also, the production information for some of the wells is incomplete because:
- the information is unavailable to the managing general
partner since there is a third-party operator; or
- if the managing general partner is the operator the wells
have been producing for only a short period of time, or
are not yet completed or on-line.
RISK OF BIAS REGARDING GEOLOGICAL REPORT PREPARED BY MANAGING GENERAL PARTNER.
The geological report for the currently proposed wells in Fayette County,
Pennsylvania was prepared by the managing general partner which is not
independent. This lack of independence in the preparation of the report may
affect its reliability since the managing general partner has an incentive to
prepare a more positive report than an independent geologist.
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 oil and gas volume, and/or oil and gas prices decrease, then even with
subordination your cash flow may be very small and you may not receive a return
of your 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. There is a risk that 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
will 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 any of the following:
- repayment of borrowings:
- costs related to completing some of the wells in additional
zones;
- 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 2005 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 cannot arrange financing for this
purpose on reasonable terms. In either event the managing general partner is
able to suspend the
6
<PAGE>
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 distributions 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. The managing
general partner anticipates that the partnership will own 25% to 100% of the
interest in its wells subject to royalties and any other burdens on the leases.
Thus, third parties may 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.
If the managing general partner were not the actual operator of the well, then
there is a risk that the managing general partner cannot supervise the
third-party operator closely enough. Decisions concerning expenditures related
to the well and how the well is operated will be made by a third-party operator
and may not be in the best interests of the partnership. There is also a risk
that a third-party operator will have financial difficulties and fail to pay for
materials or services on the wells it drills or operates and, in that event, the
partnership could incur extra costs in discharging materialmen's and workmen's
liens. The managing general partner may not be the operator of the well if the
partnership owns less than a 50% interest in the well or if the well location is
originated by a third-party and as a part of the terms of acquisition it
requires that it be named operator.
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.
RISKS ASSOCIATED WITH MANAGING GENERAL PARTNER'S BENEFIT FROM DEVELOPMENT OF
PARTNERSHIP PROSPECTS. A risk is created by the right of the managing general
partner's parent company, Atlas America, and its affiliate Atlas Pipeline
Partners, L.P., to determine the order of priority for constructing gathering
lines which may be required to connect certain of the partnership's wells into
the gathering system of Atlas Pipeline Partners. Also, the managing general
partner may choose well locations along the gathering system which would benefit
its parent company and Atlas Pipeline Partners, even if there are well locations
available in the area or other areas which offer the partnership a greater
potential return.
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.
7
<PAGE>
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.
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 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, then 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 this 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.
8
<PAGE>
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:
- 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;
- the risk that the wells are 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
effective September, 1999 which was prepared by Wright &
Company, Inc., petroleum consultants, and reviewed by the
managing general partner, evaluated the past history and
estimated future production of 1,016 wells drilled to the
Clinton/Medina geological formation which is the objective
formation in the partnership's primary drilling area in
Northwestern Pennsylvania, as well as its secondary areas in
New York and certain areas in Ohio. Based on data in that
report, approximately 907 of those wells are expected by the
managing general partner to produce more than 20 years.
- Obtain tax deductions in 2000 from intangible drilling 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 2000 tax deduction of approximately
$9,000, 90%:
- 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 approximately $3,564 or $3,240
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 2000 and is estimated to be 26% on net
revenue. The managing general partner estimates that in 2000
this feature would reduce your effective tax rate from 39.6%
to 29.3%, which is 74% of 39.6%, on partnership net revenues.
The percentage depletion rate fluctuates from year to year
depending on the price of oil, but will not be less than the
statutory rate of 15% nor more than 25%.
9
<PAGE>
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 OIL AND GAS WHICH IS
VOLATILE AND MAY DECREASE. THERE CAN BE NO GUARANTEE THAT THE FOREGOING
OBJECTIVES WILL BE ATTAINED.
ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS
You may choose to invest as an investor general partner so that you can receive
an immediate tax deduction against any type of income. To help reduce the risk
that you and other investor general partners could be required to make
additional payments to the partnership, the managing general partner will take
the actions set forth below.
- INSURANCE. The partnership will have $50 million dollars of
liability coverage during drilling operations and $11 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 by the managing general partner to
limited partner interests after substantially all of the
partnership wells have been drilled and completed. The
managing general partner anticipates conversion in late
summer of 2001.
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.
10
<PAGE>
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.
CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS
SOURCE OF FUNDS
Upon completion of the offering the partnership's source of funds will be as
follows:
- the capital contributions of you and the other investors will
range from $1 million if 100 units are sold to $15 million if
1,500 units are sold; and
- the capital contributions of the managing general partner
will range from approximately $345,000 if 100 units are
sold, to approximately $4,950,000 if 1,500 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
approximately $1,345,000 if 100 units are sold to approximately $19,950,000 if
1,500 units are sold.
USE OF PROCEEDS
The subscription proceeds received from you and the other investors will be used
to pay:
- all of the intangible drilling costs of drilling and
completing the partnership's wells; and
- all of the dealer-manager fee, sales commissions, and
reimbursement of bona fide accountable due diligence
expenses.
The managing general partner will:
- pay all of the equipment costs, organization costs, and the
reimbursement of marketing expenses to the dealer-manager;
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 you and the other 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:
11
<PAGE>
INVESTOR CAPITAL
<TABLE>
<CAPTION>
ENTITY RECEIVING 100 UNITS 1,500 UNITS
PAYMENT NATURE OF PAYMENT SOLD % (1) SOLD % (1)
------- ----------------- ---- ----- ---- -----
<S> <C> <C> <C> <C> <C>
TOTAL INVESTOR CAPITAL $1,000,000 100% $15,000,000 100%
LESS: ORGANIZATION AND OFFERING EXPENSES
Broker-Dealers Dealer-manager fee, sales $100,000 10% $1,500,000 10%
commissions, 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 $900,000 90% $13,500,000 90%
Managing General Partner Equipment costs -0- -0- -0- -0-
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.
MANAGING GENERAL PARTNER CAPITAL
<TABLE>
<CAPTION>
ENTITY RECEIVING 100 UNITS 1,500 UNITS
PAYMENT NATURE OF PAYMENT SOLD % (1) SOLD % (1)
------- ----------------- ---- ----- ---- -----
<S> <C> <C> <C> <C> <C>
TOTAL MANAGING GENERAL PARTNER CAPITAL $345,000 100% $4,950,000 100%
LESS: ORGANIZATION AND OFFERING EXPENSES
Broker-Dealers Dealer-manager fee, sales -0- -0- -0- -0-
commissions, and reimbursement
for bona fide accountable due
diligence expenses
Broker-Dealers Reimbursement of marketing $5,000 1.5% $75,000 1.4%
expenses
Various Organization costs $45,000 13.0% $675,000 12.7%
AMOUNT AVAILABLE FOR INVESTMENT:
Managing General Partner Intangible drilling costs -0- -0- -0- -0-
Managing General Partner Equipment costs $295,000 85.5% $4,200,000(2) 85.9%
Managing General Partner Leases (3) (3) (3) (3)
</TABLE>
-----------------------------------
(1) The percentage is based upon the managing general partner's capital
contribution and excludes the investors' subscriptions.
(2) On average over all of the wells drilled and completed by the partnership
the managing general partner anticipates that the average equipment cost
per well will be $52,500.
(3) Instead of contributing cash for the leases, the managing general partner
will assign the leases to the partnership. On average over all of the
wells to be drilled by the partnership, the managing general partner
anticipates that the average lease cost per prospect will be $3,232.
12
<PAGE>
SUBSEQUENT SOURCE OF FUNDS AND BORROWINGS
The managing general partner anticipates that substantially all the
partnership's initial capital will be committed or expended after the
offering. If the partnership requires additional funds for cost overruns,
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:
- subscription proceeds, if available;
- borrowings from the managing general partner or its affiliates;
or
- retaining partnership revenues.
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, which it is
not required to do, 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, together with affiliates Resource
Energy, Inc. and Viking Resources Corporation, participate in a $40 million
revolving credit facility with a group of banks with PNC Bank as the agent
bank. A portion of the credit facility, $6.3 million, supports an irrevocable
letter of credit in favor of Atlas Pipeline Partners, L.P., in connection
with a distribution support agreement between Atlas Pipeline Partners and its
general partner. The letter of credit will reduce each quarter as the
distribution support obligation reduces. Borrowings under the facility are
collateralized by substantially all the oil and gas properties of the
borrowers. The current revolving credit facility has a term ending in June
2003.
The revolving credit facility contains certain financial covenants of the
borrowers, including maintaining the following:
- a current ratio, as defined, that exceeds .85 to 1;
- a ratio of earnings to fixed charges of 1.5 to 1, increasing
to 2.5 to 1 in 2002;
- a leverage ratio, essentially a ratio of debt to earnings
before interest, taxes and depreciation, of not more than 3 to
1; and
- a covenant to preserve the borrowers' tangible net worth, as
defined.
The credit facility also imposes the following limits on the borrowers:
- the borrowers' exploration expense can be no more than 20% of
their capital expenditures plus exploration expense, without
PNC Bank's consent;
13
<PAGE>
- sales, leases or transfers of unsecured property by the
borrowers are limited to $1 million without PNC Bank's
consent; and
- the borrowers cannot incur debt in excess of $2 million to
lenders other than the lender under the facility without PNC
Bank's consent.
As of June 30, 2000, there was $33.0 million of outstanding borrowings 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
Until you receive cash distributions and tax benefits equal to 100% of your
subscription, you and the other investors and the managing general partner
will share in partnership revenues in the same percentages as your respective
capital contributions bear to the total partnership capital contributions.
After net of tax savings payout the managing general partner will receive an
additional 6.5% of partnership revenues, and after partnership payout the
managing general partner will receive an additional 8.5% of partnership
revenues for a total additional amount of 15% of partnership revenues.
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 the fair market
value of the leases.
The cost of the leases will include a portion of the managing general
partner's reasonable, necessary and actual expenses for the following:
- 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 Northwestern Pennsylvania and Fayette County, Pennsylvania, which is the
partnership's primary area of interest, the managing general partner's lease
cost is approximately $3,232 per prospect. Assuming all the leases are
situated in this area and the partnership acquires 100% of the interest, the
managing general partner estimates that its credit for lease costs will be:
- $17,776 if $1,000,000 is received, which is 5.5 wells at
$3,232 per prospect; and
- $258,560 if $15,000,000 is received, which is 80 wells at
$3,232 per prospect.
14
<PAGE>
The development of wells on the acreage may also 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 cost
plus 15%. If this rate exceeds competitive rates available from other
non-affiliated persons in the area engaged in the business of rendering or
providing comparable services or equipment, then the rate will be adjusted to
the competitive rate. 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.
Cost when used with respect to services, generally means the reasonable,
necessary and actual expense incurred in providing the services, determined
in accordance with generally accepted accounting principles. The cost of the
well includes all ordinary costs of drilling, testing and completing the well
such as:
- 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;
- the cost of installing gathering lines of up to 2,500 feet;
and
- other necessary facilities for the production of natural gas.
The amount of compensation which the managing general partner could earn as a
result of these arrangements depends on many factors, including the number of
wells drilled. The managing general partner anticipates that on average over
all of the wells drilled and completed by the partnership that the average
well cost, excluding lease costs, will be $219,390. 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. On a per
well basis the managing general partner will have reimbursement of general
and administrative overhead of approximately $12,900 per well and a profit of
15% (approximately $21,850) per well with respect to the intangible drilling
costs paid by you and the other investors. Assuming the partnership acquires
100% of the interest in the wells, the managing general partner estimates
that its general and administrative overhead reimbursement and profit will be:
- $191,125 if $1 million is received, which is 5.5 wells at
$34,750 profit and overhead per well; and
- $2,780,000 if $15 million is received, which is 80 wells at
$34,750 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 receive the
following:
- reimbursement at actual cost for all direct expenses incurred
on behalf of the partnership; and
- well supervision fees for operating and maintaining the wells
during producing operations at a competitive rate.
Currently the competitive rates for the areas range from $275 per well per
month to $400 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, and may be
adjusted for inflation annually beginning January 1, 2002. 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
15
<PAGE>
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 oil and gas, such as:
- well tending, routine maintenance and adjustment;
- reading meters, recording production, pumping, maintaining
appropriate books and records; and
- preparing reports to the partnership and to government
agencies.
The well supervision fees do not include costs and expenses related to:
- the 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 partnership's primary
area of interest and the partnership acquires 100% of the interest in the
wells, the managing general partner estimates that it will receive well
supervision fees for the partnership's first 12 months of operation of:
- $18,150 if $1 million is received, which is 5.5 wells at
$275 per well per month; and
- $264,000 if $15 million is received, which is 80 wells at
$275 per well per month.
GATHERING FEES
Atlas Pipeline Partners, L.P. is a master limited partnership which has
acquired the gathering system owned by the managing general partner's parent
company, Atlas America, and its affiliates. The managing general partner
anticipates that this entity, of which approximately 53% is owned by Atlas
America and its affiliates, will gather and deliver the majority of the
natural gas produced by the partnership to either industrial end-users in the
area, local distribution companies, or interstate pipeline systems. The
partnership will pay a gathering charge at a competitive rate. Currently the
managing general partner anticipates that the partnership will pay the
following gathering fees to Atlas Pipeline Partners in its primary and
secondary areas:
<TABLE>
<CAPTION>
AREA GATHERING FEE
---- -------------
<S> <C>
Clinton/Medina Geological Formation in Pennsylvania,
Ohio and New York..........................................................$.29 per mcf (1)
Mississippian/Upper Devonian Sandstone Reservoirs in
Fayette County, Pennsylvania...............................................$.35 per mcf (1)
Mississippian Berea Sandstone Geological Formation in
Columbiana County, Ohio....................................................$.35 per mcf (1)
Devonian Oriskany Sandstone Geological Formation in
Tuscarawas County, Ohio....................................................$.35 per mcf (1)
Big Lime, Weir, and Devonian Shale Geological Formation
in Kentucky and Virginia................................................................(2)
----------------------------
</TABLE>
16
<PAGE>
(1) The managing general partner and its affiliates will pay the
difference between the amounts set forth above and the greater of
$.35 per mcf or 16% of the gross sales price for gas produced to
Atlas Pipeline Partners.
This arrangement is described in "Proposed Activities - Sale
of Oil and Gas Production - Gathering of the Gas."
(2) The partnership will use a third-party gathering system.
The actual amount to be paid to Atlas Pipeline Partners cannot be quantified
because the amount of gas that will be produced from the wells and
transported by Atlas Pipeline Partners cannot be predicted.
DEALER-MANAGER FEES
Anthem Securities, the dealer-manager and an affiliate of the managing
general partner, 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 million is received; and
- $1,575,000 if $15 million 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 generally will be reallowed to the wholesalers who are
associated with Anthem Securities for subscriptions obtained through the
wholesalers' effort.
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:
- $4,950 if $1 million is received, which is 5.5 wells at
$75 per well per month; and
- $72,000 if $15 million is received, which is 80 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;
17
<PAGE>
- inflation; and
- various other factors involving the administration of the
partnership.
<TABLE>
<CAPTION>
Minimum Maximum
Subscriptions Subscriptions
($1,000,000) ($15,000,000)
------------ -------------
<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, which is $1 million, and a
maximum of 1,500 units, which is $15 million. 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.
PARTNERSHIP CLOSINGS AND ESCROW
The offering period will begin on the date of this prospectus, and will end
on or before December 31, 2000, as determined by the managing general
partner, in its sole discretion. The offering period will not be extended
beyond December 31, 2000, and subject to the receipt of the minimum
subscriptions of $1 million, the managing general partner may close the
offering period before this date. 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 million are not received by the offering termination
date, 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, then 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, although the managing general partner does
not anticipate that there will be any 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.
18
<PAGE>
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, before 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 give 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 and it may reject your subscription for any
reason without incurring any liability to you for this decision. If your
subscription is rejected, then all funds will be promptly returned to you.
You will be admitted to the partnership as follows:
- 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; and
- 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.
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; and
- 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 the managing general partner anticipates that the partnership will
spend the entire subscription proceeds soon after the offering closes, the
partnership will have 12 months 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.
19
<PAGE>
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. Because the
partnership's income would be unrelated business taxable income,
subscriptions will not be accepted from IRAs, Keogh plans and qualified
retirement plans.
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 partnership's term 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
- 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
20
<PAGE>
- 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.
FIDUCIARY ACCOUNTS AND CONFIRMATIONS. In the case of a sale to a fiduciary
account, all the suitability standards set forth above must be met by:
- the beneficiary;
- the fiduciary account; or
- the donor or grantor who directly or indirectly supplies the
funds to purchase the units if the donor or grantor is the
fiduciary.
21
<PAGE>
Generally, you are required to execute your own subscription agreement and
the managing general partner will not accept any subscription agreement that
has been executed by someone other than you. The only exception is if you
have given someone else the legal power of attorney to sign on your behalf
and you meet all of the conditions in this prospectus. Also, the managing
general partner may not complete a sale of units to you until at least five
business days after the date you receive a final prospectus and will send you
a confirmation of purchase.
PRIOR ACTIVITIES
The following tables, other than Table 5, reflect certain historical data
with respect to 26 private drilling partnerships which raised a total of
$96,075,134 and 8 public drilling partnerships which raised a total of
$60,074,570, which the managing general partner has sponsored.
IT SHOULD NOT BE ASSUMED THAT YOU AND THE OTHER INVESTORS WILL EXPERIENCE
RETURNS, IF ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS IN THE PRIOR
DRILLING PARTNERSHIPS FOR SEVERAL REASONS, INCLUDING, BUT NOT LIMITED TO:
- DIFFERENCES IN PARTNERSHIP TERMS,
- PROPERTY LOCATIONS,
- PARTNERSHIP SIZE, AND
- ECONOMIC CONSIDERATIONS,
THE RESULTS OF THE PRIOR DRILLING PARTNERSHIPS SHOULD BE VIEWED ONLY AS A
MEASURE OF THE LEVEL OF ACTIVITY AND EXPERIENCE OF THE MANAGING GENERAL
PARTNER WITH RESPECT TO DRILLING PARTNERSHIPS.
22
<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 July 15, 2000
<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 14.55 -0-
A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 13.55 -0-
A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 12.55 -0-
A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 11.55 -0-
A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 10.55 -0-
A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 9.55 -0-
A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 9.33 -0-
A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 8.50 -0-
A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 8.33 -0-
A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 8.25 -0-
A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 7.58 -0-
A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 7.08 -0-
A.E. Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 6.83 -0-
A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 6.50 -0-
A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 6.25 -0-
A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 6.00 -0-
A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 5.50 -0-
A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 5.25 -0-
A.E. Nineties-Public #3 391 5,799,750 928,546 6,728,296 12/31/94 06/05/95 5.25 -0-
A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96 4.42 -0-
A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96 4.00 -0-
A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96 4.25 -0-
A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 3.58 -0-
A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97 3.25 -0-
A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 3.25 -0-
A.E. Nineties-17 217 8,813,488 2,113,947 10,927,435 08/29/97 12/12/97 2.67 -0-
A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98 2.25 -0-
A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98 2.08 -0-
A.E. Nineties-18 225 11,391,673 3,448,751 14,840,424 07/31/98 01/07/99 1.58 -0-
A.E. Nineties-Public #7 366 11,988,350 3,812,150 15,800,500 12/31/98 07/10/99 1.25 -0-
A.E. Partners 1998 26 1,740,000 756,360 2,496,360 12/31/98 07/02/99 1.25 -0-
A.E. Nineties-19 288 15,720,450 4,776,598 20,497,048 09/30/99 01/14/00 0.75 -0-
A.E. Nineties-Public #8 380 11,088,975 3,148,181 14,237,156 12/31/99 06/09/00 0.25 -0-
A.E. Partners 1999 8 450,000 196,500 646,500 12/31/99 - - -0-
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
23
<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 July 15, 2000
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
GROSS WELLS(1) 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 42.00 1.50
A.E. Nineties-Public #6 0 55 0 0 44.45 0.00
A.E. Partners 1997 0 6 0 0 2.81 0.00
A.E. Nineties-18 0 63 0 0 58.00 0.00
A.E. Nineties-Public #7 0 64 0 0 57.50 0.00
A.E. Partners 1998 0 19 0 0 9.50 0.00
A.E. Nineties-19 (4) 0 86 4 0 79.75 4.00
A.E. Nineties-Public #8 0 58 0 0 54.66 0.00
A.E. Partners 1999 0 5 0 0 2.50 0.00
------ ----- ------ ------- ------ -----
TOTALS 0 930 10 0 751.17 8.75
====== ===== ====== ======= ====== =====
--------------------------------------------------------------------------------------------------------------------------
</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. For example, a 50% leasehold interest in a well is
one gross well, but a .50 net well.
(3) For purposes of this Table only, a "Dry Hole" means a well which is plugged
and abandoned without a completion attempt because the operator has
determined that it will not be productive of gas and/or oil in commercial
quantities.
(4) - Atlas L.P. #1-1985 had 1 gross well (.25 net well) which was completed
but non-commercial;
- A.E. Nineties-1993 Ltd. had 1 gross well (1 net well) which was completed
but non-commercial;
- A.E. Nineties-14 had 2 gross wells (2 net wells) which were completed but
non-commercial;
- A.E. Partners-1994 had 1 gross well (.25 net well) which was completed
but non-commercial;
- A.E. Nineties-15 had 1 gross well (1 net well) which was completed but
non-commercial;
- A.E. Nineties-16 had 5 gross wells (4.5 net wells) which were completed
but non-commercial;
- A.E. Nineties-17 had 3 gross wells (2.5 net wells) which were completed
but non-commercial; and
- A.E. Nineties-19 had 4 gross wells (4 net wells) which were completed but
non-commercial.
24
<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 July 15, 2000
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Cash
Total Costs -on- Average Latest Quarterly
------------------------------- Cash Cash Yearly Cash Distribution
Partnership Capitalization(1) Operating Admin. Direct Distributions(2) Return Return As of Date of Table
----------- ----------------- --------- ------ ------ ---------------- ------ ------ -------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 $600,000 $158,536 $35,700 $8,335 $1,336,573 223% 15% $7,013
A.E. Partners 1986 631,250 123,163 52,738 7,102 639,925 101% 7% 4,776
A.E. Partners 1987 721,000 120,111 47,247 7,177 515,981 72% 6% 2,536
A.E. Partners 1988 617,050 97,132 43,758 6,691 472,008 76% 7% 2,641
A.E. Partners 1989 550,000 93,099 46,821 5,650 626,356 114% 11% 4,546
A.E. Partners 1990 887,500 133,696 64,166 6,687 809,303 91% 10% 9,235
A.E. Nineties-10 2,200,000 294,008 63,271 22,640 1,430,010 65% 7% 18,599
A.E. Nineties-11 750,000 109,573 68,968 37,777 870,403 116% 14% 12,292
A.E. Partners 1991 868,750 112,168 83,039 14,698 872,413 100% 12% 15,558
A.E. Nineties-12 2,212,500 307,277 66,731 109,481 1,633,629 74% 9% 19,390
A.E. Nineties - JV 92 4,004,813 464,438 102,585 198,344 3,252,883(3) 81% 11% 81,167
A.E. Partners 1992 600,000 65,188 40,275 4,775 607,294 101% 13% 8,989
A.E. Nineties-Public #1 2,988,960 271,789 64,468 82,719 1,784,586 60% 9% 27,095
A.E. Nineties-1993 Ltd. 3,753,937 347,933 70,702 36,279 1,885,912 50% 8% 18,967
A.E. Partners 1993 700,000 76,533 29,738 4,115 685,426 98% 16% 16,410
A.E. Nineties-Public #2 3,323,920 270,178 53,629 37,699 1,577,057 47% 8% 35,652
A.E. Nineties-14 9,940,045 814,378 164,101 41,266 4,404,539 44% 8% 115,150
A.E. Partners 1994 892,500 57,468 32,061 3,438 646,819 72% 14% 21,328
A.E. Nineties-Public #3 5,799,750 380,884 79,637 41,743 2,683,908 46% 9% 76,071
A.E. Nineties-15 10,954,715 692,603 147,045 24,380 4,686,866 43% 10% 174,394
A.E. Partners 1995 600,000 38,827 10,646 2,838 254,307 42% 11% 5,393
A.E. Nineties-Public #4 6,991,350 427,509 84,573 35,912 2,083,878 30% 7% 67,199
A.E. Nineties-16 10,955,465 534,305 96,354 39,601 2,920,939 27% 7% 119,070
A.E. Partners 1996 800,000 44,460 11,833 39,878 232,572 29% 9% 13,219
A.E. Nineties-Public #5 7,992,240 351,079 68,139 22,119 2,125,563 27% 8% 113,595
A.E. Nineties-17 8,813,488 308,559 61,198 97,339 2,189,229 25% 9% 159,172
A.E. Nineties-Public #6 9,901,025 343,140 61,293 14,335 2,230,079 23% 10% 210,591
A.E. Partners 1997 506,250 17,307 4,502 25,965 113,831 22% 11% 10,992
A.E. Nineties-18 11,391,673 307,984 52,576 260,131 1,974,075 17% 11% 248,020
A.E. Nineties-Public #7 11,988,350 248,460 36,669 12,683 1,334,901 11% 9% 218,369
A.E. Partners 1998 1,740,000 45,978 10,044 40,743 332,371 19% 15% 58,008
A.E. Nineties-19 15,720,450 152,887 21,385 4,605 1,083,145 7% 9% 446,670
A.E. Nineties-Public #8 11,088,975 10,671 1,960 0 100,032 1% 4% 100,032
A.E. Partners 1999 450,000 0 0 0 0 0% N/A N/A
------------------------------------------------------------------------------------------------------------------------------------
</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:
- A.E. Nineties-10 - $330,000;
- A.E. Nineties-11 - $112,500; and
- 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.
25
<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 July 15, 2000
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Cash
Total Costs -on- Latest Quarterly
------------------------------- Cash Cash Cash Distribution
Partnership Capitalization Operating Admin. Direct Distributions(1) Return As of Date of Table
----------- ----------------- --------- ------ ------ ---------------- ------ -------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Atlas L.P. #1-1985 $114,800 $30,197 $6,800 $1,588 $253,135 221% $1,336
A.E. Partners 1986 120,400 23,460 10,045 1,353 122,219 102% 910
A.E. Partners 1987 158,269 34,631 13,623 2,069 131,035 83% 731
A.E. Partners 1988 135,450 31,282 14,092 2,155 117,751 87% 851
A.E. Partners 1989 120,731 20,436 10,278 1,240 143,124 119% 998
A.E. Partners 1990 244,622 44,565 0 0 312,497 128% 3,828
A.E. Nineties-10 484,380 98,003 0 0 505,307 104% 7,300
A.E. Nineties-11 268,003 46,960 29,558 11,132 366,305 137% 5,268
A.E. Partners 1991 318,063 37,389 0 0 377,231 119% 6,244
A.E. Nineties-12 791,833 131,690 28,599 21,413 700,126 88% 8,310
A.E. Nineties-JV 92 1,414,917 228,753 50,527 16,152 846,212 60% 11,337
A.E. Partners 1992 176,100 21,729 0 0 286,202 163% 3,680
A.E. Nineties-Public #1 528,934 85,828 20,358 14,315 495,734 94% 8,556
A.E. Nineties-1993 Ltd. 1,264,183 149,114 30,301 11,966 335,242 27% 8,129
A.E. Partners 1993 219,600 25,511 0 0 252,225 115% 5,987
A.E. Nineties-Public #2 587,340 85,319 16,936 11,905 332,987 57% 11,258
A.E. Nineties-14 3,584,027 401,111 80,826 13,146 1,124,317 31% 1,684
A.E. Partners 1994 231,500 19,156 0 0 228,085 99% 7,786
A.E. Nineties-Public #3 928,546 126,961 26,546 13,914 833,449 90% 25,357
A.E. Nineties-15 3,435,936 296,830 63,019 10,448 1,751,385 51% 2,656
A.E. Partners 1995 244,725 12,942 0 0 75,144 31% 2,223
A.E. Nineties-Public #4 1,287,752 142,503 28,191 11,971 564,423 44% 11,859
A.E. Nineties-16 1,643,320 146,338 26,390 6,040 530,524 32% 16,622
A.E. Partners 1996 367,416 14,820 0 0 94,761 26% 4,919
A.E. Nineties-Public #5 1,654,740 117,026 22,713 7,373 509,021 31% 20,046
A.E. Nineties-17 2,113,947 111,249 22,065 5,750 766,935 36% 27,540
A.E. Nineties-Public #6 1,950,345 114,380 20,431 4,778 731,870 38% 58,707
A.E. Partners 1997 231,050 5,769 0 0 48,099 21% 4,044
A.E. Nineties-18 3,448,751 141,628 24,177 6,751 924,719 27% 114,053
A.E. Nineties-Public #7 3,812,150 111,627 16,474 5,698 305,027 8% 49,898
A.E. Partners 1998 756,360 15,326 0 0 127,719 17% 20,265
A.E. Nineties-19 4,776,598 70,306 9,834 2,118 498,089 10% 205,403
A.E. Nineties-Public #8 3,148,181 4,358 801 0 21,072 1% 21,072
A.E. Partners 1999 196,500 0 0 0 N/A N/A N/A
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) All cash distributions were from the sale of gas and not sales of
properties.
26
<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 July 15, 2000
<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% 50.0% $298,337 $116,655 N/A $55,915
A.E. Partners-1986 631,250 99% 50.0% 312,889 64,217 N/A 13,507
A.E. Partners-1987 721,000 99% 38.5% 356,895 46,538 N/A N/A
A.E. Partners-1988 617,050 99% 33.0% 244,351 42,558 N/A N/A
A.E. Partners-1989 550,000 99% 33.0% 179,685 59,497 N/A N/A
A.E. Partners-1990 887,500 99% 33.0% 275,125 79,438 N/A 234,190
A.E. Nineties-10 2,200,000 100% 33.0% 726,000 142,961 N/A 417,423
A.E. Nineties-11 750,000 100% 31.0% 232,500 83,739 N/A 267,473
A.E. Partners-1991 868,750 100% 31.0% 269,313 93,011 N/A 251,487
A.E. Nineties-12 2,212,500 100% 31.0% 685,875 170,425 N/A 497,871
A.E. Nineties-JV 92 4,004,813 92.5% 31.0% 1,322,905 284,782 N/A 756,727
A.E. Partners-1992 600,000 100% 31.0% 186,000 69,034 N/A 182,143
A.E. Nineties-Public #1 2,988,960 80.5% 36.0% 877,511 181,735 $246,143 N/A
A.E. Nineties-1993 Ltd. 3,753,937 92.5% 39.6% 1,378,377 177,120 N/A N/A
A.E. Partners-1993 700,000 100% 39.6% 273,216 70,068 N/A N/A
A.E. Nineties-Public #2 3,323,920 78.7% 39.6% 1,036,343 146,214 254,264 N/A
A.E. Nineties-14 9,940,045 95% 39.6% 3,739,445 381,587 N/A N/A
A.E. Partners-1994 892,500 100% 39.6% 353,430 58,854 N/A N/A
A.E. Nineties-Public #3 5,799,750 76.2% 39.6% 1,752,761 248,650 429,089 N/A
A.E. Nineties-15 10,954,715 90.0% 39.6% 3,904,261 430,494 N/A N/A
A.E. Partners-1995 600,000 100% 39.6% 237,600 18,890 N/A N/A
A.E. Nineties-Public #4 6,991,350 80.0% 39.6% 2,214,860 208,126 412,316 N/A
A.E. Nineties-16 10,955,465 86.8% 39.6% 3,361,289 250,005 663,202 N/A
A.E. Partners-1996 800,000 100% 39.6% 316,800 25,944 N/A N/A
A.E. Nineties-Public #5 7,992,240 84.9% 39.6% 2,530,954 186,594 399,437 N/A
A.E. Nineties-17 8,813,488 85.2% 39.6% 2,966,366 202,055 317,274 N/A
A.E. Nineties-Public #6 9,901,025 80.0% 39.6% 3,166,406 225,803 382,863 N/A
A.E. Partners-1997 506,250 100% 39.6% 200,475 14,843 N/A N/A
A.E. Nineties-18 11,391,673 90.0% 39.6% 4,030,884 209,989 171,156 N/A
A.E. Nineties-Public #7 11,988,350 85.0% 39.6% 4,043,670 135,432 153,542 N/A
A.E. Partners-1998 1,740,000 100.0% 39.6% 689,040 42,252 N/A N/A
A.E. Nineties-19 15,720,450 90.0% 39.6% 5,602,767 93,632 38,434 N/A
A.E. Nineties-Public #8 11,088,975 85.0% 39.6% 3,734,654 0 0 N/A
A.E. Partners-1999 450,000 100.0% 39.6% 178,200 0 N/A N/A
<CAPTION>
Cumulative
Cash Percent of
Distribution Total Cash Cash Dist.
As of Dist. and and Tax
Date of Tax Savings to
Partnership Total Table (5) Savings Date
----------- ----- --------- ------- ----
<S> <C> <C> <C> <C>
Atlas L.P. #1 - 1985 $470,907 $1,336,573 $1,807,479 301%
A.E. Partners-1986 390,613 639,925 1,030,538 163%
A.E. Partners-1987 403,433 515,981 919,414 128%
A.E. Partners-1988 286,909 472,008 758,917 123%
A.E. Partners-1989 239,182 626,356 865,538 157%
A.E. Partners-1990 588,753 809,303 1,398,056 158%
A.E. Nineties-10 1,286,384 1,430,010 2,716,395 123%
A.E. Nineties-11 583,712 870,403 1,454,115 194%
A.E. Partners-1991 613,811 872,413 1,486,224 171%
A.E. Nineties-12 1,354,171 1,633,629 2,987,799 135%
A.E. Nineties-JV 92 2,364,414 3,252,883 5,617,297 140%
A.E. Partners-1992 437,177 607,294 1,044,471 174%
A.E. Nineties-Public #1 1,305,389 1,784,586 3,089,975 103%
A.E. Nineties-1993 Ltd. 1,555,497 1,885,912 3,441,409 92%
A.E. Partners-1993 343,284 685,426 1,028,710 147%
A.E. Nineties-Public #2 1,436,821 1,577,057 3,013,878 91%
A.E. Nineties-14 4,121,032 4,404,539 8,525,571 86%
A.E. Partners-1994 412,284 646,819 1,059,103 119%
A.E. Nineties-Public #3 2,430,500 2,683,908 5,114,408 88%
A.E. Nineties-15 4,334,755 4,686,866 9,021,621 82%
A.E. Partners-1995 256,490 254,307 510,797 85%
A.E. Nineties-Public #4 2,835,302 2,083,878 4,919,181 70%
A.E. Nineties-16 4,274,496 2,920,939 7,195,435 66%
A.E. Partners-1996 342,744 232,572 575,316 72%
A.E. Nineties-Public #5 3,116,985 2,125,563 5,242,547 66%
A.E. Nineties-17 3,485,695 2,189,229 5,674,924 64%
A.E. Nineties-Public #6 3,775,072 2,230,079 6,005,151 61%
A.E. Partners-1997 215,318 113,831 329,149 65%
A.E. Nineties-18 4,412,029 1,974,075 6,386,105 56%
A.E. Nineties-Public #7 4,332,644 1,334,901 5,667,545 47%
A.E. Partners-1998 731,292 332,371 1,063,663 61%
A.E. Nineties-19 5,734,833 1,083,145 6,817,978 43%
A.E. Nineties-Public #8 3,734,654 100,032 3,834,686 35%
A.E. Partners-1999 178,200 0 178,200 40%
---------------------------------------------------------------------------------
</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) The managing general partner anticipates that approximately 90% of an
investor general partner's subscription to the partnership will be
deductible in 2000.
(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.
27
<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 3,600 wells over the 28-year period from 1972
to 2000.
TABLE 5
ATLAS RESOURCES, INC. AND ITS AFFILIATES' HISTORICAL PRODUCTION RECORD
As of July 15, 2000 (4)
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
Last 3 Mo.
Year Wells Total Total Amount Distribution
Were Placed Total Mcf's Invested In Total Amount Cum % Return Ending As of
Into Production Wells(1) Produced Wells(2) Returned(2) Cash-on-Cash (3) Date of Table
--------------- ------- -------- ---------- -------------- ---------------- -------------
<S> <C> <C> <C> <C> <C> <C>
1973 6 2,569,859 $576,000 $4,112,000 714% $14,476
1974 18 3,032,534 2,387,200 4,011,528 168% 12,124
1975 21 4,345,693 2,814,200 6,799,756 242% 23,032
1976 14 2,943,208 1,819,200 4,444,897 244% 11,102
1977 26 9,495,805 3,912,600 16,681,418 426% 61,541
1978 78 8,134,937 12,399,900 19,493,721 157% 69,004
1979 46 9,526,283 7,404,000 20,142,326 272% 60,343
1980 41 5,975,284 6,561,100 13,945,603 213% 46,712
1981 77 6,562,297 15,382,850 17,389,084 113% 34,280
1982 63 2,551,761 12,438,500 5,899,303 47% 14,392
1983 22 1,358,278 6,725,480 3,153,537 47% 16,474
1984 47 4,917,584 10,663,250 10,647,518 100% 47,888
1985 39 5,132,600 8,971,200 10,601,817 118% 47,398
1986 45 5,936,415 9,649,100 11,180,160 116% 82,520
1987 12 1,629,940 2,425,800 2,799,885 115% 15,152
1988 37 4,107,722 7,688,386 7,243,032 94% 63,526
1989 48 4,270,278 9,967,768 7,386,077 74% 63,662
1990 46 5,329,729 9,038,238 9,501,916 105% 70,262
1991 79 9,274,372 16,034,382 16,916,465 106% 196,849
1992 64 8,628,630 14,250,032 15,417,107 108% 196,874
1993 107 10,807,424 21,958,681 17,861,194 81% 128,912
1994 94 7,425,666 20,418,366 11,962,899 59% 276,468
1995 105 7,732,269 22,350,889 12,991,414 58% 352,443
1996 114 6,141,324 25,396,708 10,271,141 40% 356,411
1997 103 4,575,186 20,908,334 7,906,961 38% 451,721
1998 128 4,302,182 26,317,000 7,572,060 29% 634,075
1999 117 2,245,551 29,930,581 4,170,750 14% 2,288,913
2000 33 145,709 10,009,388 293,431 3% 286,118
------- -------------- --------------- --------------- ---------- ------------
TOTAL 1,630 149,098,520 $338,399,133 $280,796,999 83% $5,922,671
======= ============== =============== =============== ========== ============
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) The above numbers do not include information for:
- 87 wells drilled for General Motors from 1971 to 1973 which were
subsequently purchased by General Motors;
- 25 wells successfully drilled in 1981 and 1982 for an industrial
customer which requested that the wells be capped and not placed into
production;
- 127 wells drilled from 1980 to 1985 which were sold in 1993 and are no
longer operated by the managing general partner; and
- wells which were drilled recently but are not yet in production.
(2) - 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.
- 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.
28
<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. The managing general partner and its affiliates
have acted as the operator and the general drilling contractor on
approximately 3,650 gas wells, approximately 3,450 of which were capable of
production in commercial quantities. As of December 31, 1999, the managing
general partner and its affiliates operated approximately 3,400 oil or
natural gas wells located in Ohio, Pennsylvania and New York.
Since 1985 the managing general partner has sponsored 8 public and 26 private
partnerships to conduct natural gas drilling and development activities in
Pennsylvania and Ohio. In these partnerships the managing general partner and
its affiliates acted as the operator and the general drilling contractor and
were responsible for drilling, completing and operating the wells.
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 energy, energy finance and real estate
finance. Viking Resources was acquired in August 1999.
Atlas America is continuing the existing business of Atlas Group and is
headquartered at 311 Rouser Road, Moon Township, Pennsylvania 15108, near the
Pittsburgh International Airport which is also the managing general partner's
primary office. 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 61 Chairman of the Board
James R. O'Mara 57 Director
Tony C. Banks 46 Director
Michael L. Staines 51 Director
Jonathan Z. Cohen 30 Director
John S. White 60 Director
JoAnn Bagnell 71 Director
Charles T. Koval 66 Director
James C. Eigel 66 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. Biographical information on the
other directors will be provided by the managing general partner upon request.
The managing general partner and its affiliates under Atlas America employ a
total of approximately 154 persons, consisting of five geologists, eight
landmen, six engineers, 33 operations staff, 14 accounting, one gas
marketing, and 18 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 28 years, providing drilling, operating and supervisory
services for more than $380 million of independent investment now under Atlas
America's management.
29
<PAGE>
ORGANIZATIONAL DIAGRAM (1)(2)
This organizational diagram does not include all of the subsidiaries of Resource
America.
<TABLE>
<S><C>
----------------------------------------
Resource America, Inc.
----------------------------------------
----------------------------------------
Atlas America, Inc.
----------------------------------------
----------------------------------------
AIC, Inc.
----------------------------------------
-------------------- --------------- ------- ------- ---- ---------- ----- ----------
----------------- --------------- -------------- ------------- --------------- ----------------
Atlas Atlas Energy Transatco, Atlas Anthem Atlas Energy
Resources, Corporation, Inc., which Information Securities Group, Inc.,
Inc., managing managing owns 50% of Management, Inc., driller and
general general Topico, L.L.C., registered operator in
partner, partner of operates markets broker-dealer Ohio
driller and exploratory pipeline in information and
operator in drilling Ohio and dealer-manager
Pennsylvania partnerships technology
and driller services
and operator
----------------- --------------- -------------- ------------- --------------- ----------------
---------------- --------------
ARD AED
Investments, Investments,
Inc. Inc.
---------------- --------------
</TABLE>
------------------------------------------
(1) Resource Energy and Viking Resources, which are subsidiaries of Resource
America, are also engaged in the oil and gas business. In the near term
both Resource Energy and Viking Resources will retain their separate
corporate existence, however, Atlas America will manage the assets and
employees of both including sharing common employees. Also, many of the
officers and directors of the managing general partner serve as officers
and directors of those entities.
(2) Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating Partnership)
is a master limited partnership formed by a subsidiary of Atlas America
as managing general partner which has acquired the natural gas gathering
system and related facilities from Atlas America, Resource Energy, and
Viking Resources. The gathering system consists of approximately 888
miles of intrastate pipelines located in Pennsylvania, Ohio, and New
York. It is anticipated that this master limited partnership will gather
and deliver the majority of the natural gas produced by the partnership
to either industrial end-users in the area, local distribution companies,
or interstate pipeline systems.
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>
James R. O'Mara 57 President, Chief Executive Officer and a Director
Tony C. Banks 46 Senior Vice President, Chief Financial Officer and a Director
Michael L. Staines 51 Senior Vice President and Chief Operating Officer
Frank P. Carolas 40 Vice President of Land and Geology
Jeffrey C. Simmons 41 Vice President of Operations
William R. Seiler 45 Assistant Secretary
Barbara J. Krasnicki 54 Secretary
</TABLE>
JAMES R. O'MARA. President, Chief Executive Officer and a Director. Mr. O'Mara
also serves as Vice Chairman and a Director of Atlas America. Mr. O'Mara served
with the United States Army Security Agency (ASA) and is a Vietnam veteran. Mr.
O'Mara is a Certified Public Accountant and had been associated with Coopers and
Lybrand, a national accounting firm, and Teledyne, Inc., a large conglomerate,
before joining Atlas Energy in 1975. He is a member of the Pennsylvania
Institute of Certified Public Accountants, and received a Bachelor of Science
Degree in Accounting from Gannon University in 1968.
30
<PAGE>
TONY C. BANKS. Senior Vice President, Chief Financial Officer, and a
Director. Mr. Banks also serves as President, Chief Executive Officer and a
Director of Atlas America. 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.
MICHAEL L. STAINES. Senior Vice President and Chief Operating Officer. Mr.
Staines is also Secretary and Managing Director, Business Development of
Atlas America and Atlas Pipeline Partners, and a Director of Atlas America
since 1998, Senior Vice President and a Director of Resource America since
1998 and 1989, respectively, Secretary of Resource America from 1989 to 1998,
and President, Chief Executive Officer and a Director of Resource Energy, the
energy subsidiary of Resource America, since 1997. Mr. Staines is a member of
the Ohio Oil and Gas Association and the Independent Oil and Gas Association
of New York. Mr. Staines received a Bachelor of Science Degree from Cornell
University in 1971 and a Master of Business Degree from Drexel University in
1977.
FRANK P. CAROLAS. Vice President of Land and Geology. Mr. Carolas also serves
as Vice President of Land and Geology of Atlas America and Viking Resources.
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 Operations. Mr. Simmons also serves as
Vice President of Operations of Atlas America and Viking Resources. 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. He is a Board Member of the Ohio Oil and Gas Association,
the Independent Oil and Gas Association of New York and the Ohio Section of
the Society of Petroleum Engineers.
WILLIAM R. SEILER. Assistant Secretary. Mr. Seiler also serves as Vice
President and Controller of Atlas America. Mr. Seiler had 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 included the
corporate strategic financial planning department, manager of strategic
financial planning, corporate-wide financial and accounting planning
committee, and chair of 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.
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.
31
<PAGE>
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, 1999, to the
five most highly compensated persons who were 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 NUMBER CAPACITIES IN WHICH SERVED CASH COMPENSATION AGGREGATE OF
OF PERSONS IN GROUP (3) COMPENSATION (1) PURSUANT TO CONTINGENT FORMS OF
PLANS (2) REMUNERATION
------------------------------- ---------------------------- ----------------------- ---------------------- -----------------------
<S> <C> <C> <C> <C>
James R. O'Mara President, Chief Executive $317,000 $5,000 --
Officer and a Director
Charles T. Koval Chairman and a Director $240,614 $5,000 --
Tony C. Banks Senior Vice President, $200,968 $5,000 --
Chief Financial Officer,
and a Director
Frank P. Carolas Vice President of Land and $98,412 $5,000 --
Geology
Jeffrey C. Simmons Vice President of $115,865 $8,646 --
Operations
Executive Officers as a Group $1,034,985 $49,649 --
(7 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) The managing general partner participates in a 401(k) plan which allowed
employees to contribute the lesser of 15% of their compensation or
$10,000 for the 1998 and 1999 calendar years. The managing general
partner's parent company generally contributed an amount equal to 50% of
each employee's contribution. However, this plan merged into the Resource
America, Inc. Investment Savings Plan on September 1, 1999, which
provided that for contributions up to 10% of the employee's compensation
the employer would contribute in cash an amount equal to 50% of each
employee's contribution or, at the employee's option, an amount of
Resource America stock in an amount equal to 100% of the employee's
contribution. Contributions in excess of 10% of an employee's
compensation were not matched by the employer.
(3) No director's fees were paid for the year to the directors of the
managing general partner.
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.
32
<PAGE>
Atlas Group shareholders received certain "piggy-back" registration rights,
effective during the period from September 30, 1999 through September 29,
2000, for 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 Joseph Sadowski and Charles T. Koval, co-founders of
Atlas Energy, 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. 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, 13,106 stock options in
Resource America were issued at an option price of $0.1069 per share to Mr.
Banks.
The managing general partner and its officers, directors and affiliates have
in the past invested, and may in the future invest, in partnerships sponsored
by the managing general partner on the same terms as unrelated investors.
They may also subscribe for units in the partnership as described in "Plan of
Distribution."
PROPOSED ACTIVITIES
OVERVIEW OF DRILLING ACTIVITIES
The managing general partner anticipates that all the partnership's wells will
be development wells, which 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. Also, the majority of the wells will be classified as gas wells
which may produce a small amount of oil, although some of the wells may be
classified as oil wells. Assuming the partnership acquires 100% of the interest
in the wells, the managing general partner anticipates that the partnership will
drill approximately :
- 5.5 wells if the minimum subscriptions of $1 million are
received; and
- 80 wells if the maximum subscriptions of $15 million are
received.
The actual number of wells drilled by the partnership, however, may vary from
these estimates and will depend on the following:
- the amount of subscriptions proceeds received;
- the partnership's percentage of the interest in the wells; and
- where the wells are drilled.
The managing general partner anticipates that the partnership generally will own
25% to 100% of the interest in its wells.
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, but not limited to:
33
<PAGE>
- logs;
- completion reports; and
- plugging reports.
PRIMARY AREAS OF OPERATIONS
As discussed below, the two primary areas for the partnership's drilling
activities are the Clinton/Medina Geological Formation in Northwestern
Pennsylvania and the Mississippian/Upper Devonian Sandstone reservoirs in
Fayette County, Pennsylvania. The wells drilled to the Clinton/Medina geological
formation and the Mississippian/Upper Devonian Sandstone reservoirs have the
following similarities:
- geological features such as structure and faulting are not
generally factors used in finding commercial production from a
well drilled to this formation or these reservoirs and the
governing factors appear to be sand quality in terms of net
pay zone thickness, porosity, and the effectiveness of
fracture stimulation;
- a well drilled to this formation or these reservoirs usually
requires hydraulic fracturing of the formation to stimulate
productive capacity;
- generally, gas from a well drilled to this formation or these
reservoirs is produced at rates which decline rapidly during
the first few years of operations, and although the well can
produce for many years, a proportionately larger amount of
production can be expected within the first several years; and
- it has been the managing general partner's experience that gas
production from wells drilled to this formation or these
reservoirs is reasonably consistent within close proximity,
although from time to time great differences in well
performance can occur in wells located close together.
THE CLINTON/MEDINA GEOLOGICAL FORMATION IN NORTHWESTERN PENNSYLVANIA. The
managing general partner anticipates that if $1,000,000 is raised
approximately 50% of the subscription proceeds will be used to drill
approximately 3 wells, and if $15,000,000 is raised approximately 35% of the
subscription proceeds will be used to drill approximately 31 wells, in
Northwestern Pennsylvania in the Clinton/Medina geological formation. 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, and permeability is the property of porous rock
that allows fluids or gas to flow through it. Based on the managing general
partner's experience, it anticipates that all the partnership's wells will be
completed and fraced in two different zones of the Clinton/Medina geological
feature. See the geologic evaluation and the model decline curve prepared by
United Energy Development Consultants, Inc., an independent geological and
engineering firm for a discussion of the development of the Clinton/Medina
Geological Formation in Northwestern Pennsylvania.
The wells in the Clinton/Medina geological formation:
- will be primarily situated in Mercer, Lawrence, Warren,
Venango, and Crawford Counties;
- will be situated on approximately 50 acres, subject to
adjustment to take into account lease boundaries;
- 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;
- will be drilled from 5,100 to 6,300 feet in depth;
34
<PAGE>
- will cost approximately $223,300 per well to drill and
complete unless directional drilling tools are used which
will increase the cost of the well by approximately $45,000;
- will be classified as gas wells which may produce a small
amount of oil; and
- will be connected to the gathering system owned by Atlas
Pipeline Partners and have their gas production marketed to
First Energy Corporation as described below, although a
portion of the gas production may be gathered by and sold to
third parties if there were a third-party operator.
Also, see "Secondary Areas" below, for a discussion of the Clinton/Medina
geological formation in Ohio and New York.
MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS, FAYETTE COUNTY,
PENNSYLVANIA. The managing general partner anticipates that if $1,000,000 is
raised approximately 40% of the subscription proceeds will be used to drill
approximately 2.5 wells, and if $15,000,000 is raised approximately 23% of
the subscription proceeds will be used to drill approximately 20 wells, in
Fayette County, Pennsylvania in the Mississippian/Upper Devonian Sandstone
reservoirs. The Mississippian/Upper Devonian Sandstone reservoirs are
discontinuous lens-shaped accumulations found throughout most of the
Appalachian Basin. The Mississippian/Upper Devonian Sandstone reservoirs have
porosities ranging from 5% to 20% with attendant permeabilities. See the
managing general partner's geologic evaluation for a discussion of the
development of the Mississippian/Upper Devonian Sandstone reservoirs in
Fayette County, Pennsylvania.
The wells in the Mississippian/Upper Devonian Sandstone reservoirs:
- will be situated on approximately 20 acres, subject to
adjustment to take into account lease boundaries;
- will not be drilled closer than 1,000 feet to each other;
- will be drilled from 1,900 to 4,500 feet in depth;
- will cost approximately $223,900 per well to drill and
complete;
- will be classified as gas wells which may produce a small
amount of oil; and
- will be connected to the gathering system owned by Atlas
Pipeline Partners and have their gas production marketed to
First Energy Corporation as described below.
SECONDARY AREAS OF OPERATIONS.
The managing general partner also has reserved the right to use a portion of the
subscription proceeds to drill development wells in other areas of the United
States primarily in the Appalachian Basin. The secondary areas anticipated by
the managing general partner are discussed below.
CLINTON/MEDINA GEOLOGICAL FORMATION IN OHIO. Wells located in Ohio and drilled
to the Clinton/Medina geological formation:
- will be primarily situated in Mahoning, Portage, Trumbull,
Noble, and Washington Counties.
- will be situated on approximately 40 acres, subject to
adjustment to take into account lease boundaries;
- will not be drilled closer than approximately 1,000 feet to
each other;
- will be drilled from 4,900 to 6,300 feet in depth;
35
<PAGE>
- will cost approximately $223,000 to drill and
complete a gas well and approximately $230,000 to drill and
complete an oil well unless directional drilling tools are
used which will increase the cost of the well by approximately
$45,000;
- will have a 84.375% to 87.5% net revenue interest;
- may be classified as either gas wells or oil wells; and
- if classified as a gas well will be connected to the gathering
system owned by Atlas Pipeline Partners and have its gas
production marketed to First Energy Corporation as described
below, although a portion of the gas production may be
gathered by and sold to third parties if there were a
third-party operator.
CLINTON/MEDINA GEOLOGICAL FORMATION IN NEW YORK. Wells located in New York and
drilled to the Clinton/Medina geological formation:
- will be primarily situated in Chautauqua County;
- will be situated on approximately 40 acres, subject to
adjustment to take into account lease boundaries;
- will be drilled from 3,800 to 4,000 feet in depth;
- will cost approximately $223,300 per well to drill and
complete;
- will have a 84.375% to 87.5% net revenue interest;
- will be classified as gas wells which may produce a small
amount of oil; and
- will be connected to the gathering system owned by Atlas
Pipeline Partners and have their gas production marketed to
First Energy Corporation as described below.
MISSISSIPPIAN BEREA SANDSTONE IN OHIO. Wells located in Ohio and drilled to the
Mississippian Berea Sandstone:
- will be primarily situated in Columbiana County;
- will be situated on approximately 5 acres, subject to
adjustment to take into account lease boundaries;
- will be drilled from 850 to 950 feet in depth;
- will cost approximately $72,200 per well to drill and
complete;
- will have a 84.375% to 87.5% net revenue interest;
- will be classified as gas wells which may produce a small
amount of oil; and
- will be connected to the gathering system owned by Atlas
Pipeline Partners and have their gas production marketed to
First Energy Corporation as described below.
DEVONIAN ORISKANY SANDSTONE IN OHIO. Wells located in Ohio and drilled to the
Devonian Oriskany Sandstone:
- will be primarily situated in Tuscarawas County;
36
<PAGE>
- will be situated on approximately 40 acres, subject to
adjustment to take into account lease boundaries;
- will be drilled from 3,800 to 4,200 feet in depth;
- will cost approximately $230,225 per well to drill and
complete;
- will have a 84.375% to 87.5% net revenue interest;
- will be classified as gas wells which may produce a small
amount of oil; and
- will be connected to the gathering system owned by Atlas
Pipeline Partners and have their gas production marketed to
First Energy Corporation as described below.
KENTUCKY AND VIRGINIA. Wells in Kentucky and Virginia will be drilled to the
following formations in descending order: Big Lime Limestone; Weir Sandstone;
and the Cleveland, Upper Huron and Lower Huron members of the Devonian Shale.
These wells:
- will be primarily situated in Harlan County, Kentucky and Lee
County, Virginia;
- will be situated on approximately 70 acres, subject to
adjustment to take into account lease boundaries;
- will be drilled from 5,000 to 6,600 feet in depth;
- will cost approximately $338,200 per well to drill and
complete;
- will have a 81.25% net revenue interest;
- will be classified as gas wells which may produce a small
amount of oil; and
- will not be connected to the gathering system owned by Atlas
Pipeline Partners, which is not situated in the area, and will
have their gas production marketed to Duke Energy Marketing.
ACQUISITION OF LEASES
The managing general partner will have the right, in its sole discretion, to
select the prospects which the partnership will drill. Currently, the managing
general partner has proposed approximately 63% of the prospects to be drilled if
all the units are sold. The leases covering the prospect 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. Neither the managing general partner nor its affiliates will
receive any royalty or overriding royalty interest on any well.
The managing general partner may substitute the prospects depending upon various
considerations. The managing general partner anticipates that it will select any
additional and/or substituted prospects from the following:
- leases in its and its affiliates' existing leasehold
inventory;
- leases which are subsequently acquired by it or its
affiliates; or
- leases owned by independent third parties.
Most of the additional and/or substituted prospects will be 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
37
<PAGE>
wells. The managing general partner believes that its and its affiliates'
leasehold inventory and leases acquired from third parties will be sufficient
to provide all the well locations to be drilled by the partnership.
The managing general partner and its affiliates are continually engaged in
acquiring additional leasehold acreage in Pennsylvania and other areas of the
United States. As of the date of this prospectus, the managing general partner
and its affiliates owned approximately:
- 93,674 net acres of undeveloped lease acreage in Pennsylvania;
- 50,437 net acres of undeveloped lease acreage in Ohio;
- 8,652 net acres of undeveloped lease acreage in West Virginia;
- 2,370 net acres of undeveloped lease acreage in Kentucky; and
- 13,643 net acres of undeveloped lease acreage in New York.
Because the managing general partner will assign to the partnership only the
number of prospects which it believes are necessary for the drilling
operations of the partnership, the partnership will not farmout any acreage.
Generally, a farmout is an agreement where the owner of the leasehold
interest agrees to assign his interest in certain specific acreage to an
assignee subject to the assignee drilling one or more specific wells as a
condition of the assignment. The owner would retain some interest such as an
overriding royalty interest which could revert to a working or operating
interest at a designated time such as payout.
DEEP DRILLING RIGHTS RETAINED BY MANAGING GENERAL PARTNER. In the areas where
the Clinton/Medina is the primary geological formation, the lease assignments to
the partnership will be limited to a depth of from the surface to the top of the
Queenston geological formation. In the areas where the Mississippian/Upper
Devonian Sandstone reservoirs are the primary targets, the lease assignments to
the partnership will be limited to a depth of from the surface through the
completion total depth of the well, and the managing general partner will retain
the drilling rights below the completion total depth of the well. The managing
general partner will retain the deeper drilling rights, because the
partnership's objective is to conduct development drilling which would not be
the case with the deeper formations. The managing general partner, however,
believes that the partnership's development drilling in these areas will not
provide any geological information that would assist it in evaluating drilling
to deeper formations. 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 or
other exploratory activity is undertaken by the managing general partner on the
deeper formations which provides a basis for the managing general partner
drilling an exploratory well, then the partnership would not share in the
profits from these activities.
INTERESTS OF PARTIES
Generally, production and revenues from a well drilled by the partnership will
be net of the applicable landowner's royalty interest which is typically 1/8th
(12.5%) of gross production, any overriding royalty interests, and any interest
in favor of third parties. Landowner's royalty interest generally means an
interest which is created in favor of the landowner when an oil and gas lease is
obtained, and overriding royalty interest generally means an interest which is
created in favor of someone other than the landowner. In either case, the owner
of the interest receives a specific percentage of the oil and gas production
free and clear of all costs of development, operation, or maintenance of the
well.
The managing general partner anticipates that the partnership generally will
have a net revenue interest in its leases in its primary drilling areas as set
forth in the charts below. Net revenue interest generally means the percentage
of revenues the owner of an interest in a well is entitled to receive under the
lease. The following charts express the percentage of production revenues that
the managing general partner, the landowner, other third-parties, and you and
the other investors will share in from the wells in
38
<PAGE>
the primary proposed areas. If the partnership acquires a lesser percentage
ownership interest in a well, then the partnership's net revenue interest
will decrease proportionately.
PRIMARY AREAS.
CLINTON/MEDINA GEOLOGICAL FORMATION IN NORTHWESTERN PENNSYLVANIA AND
MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS IN FAYETTE COUNTY,
PENNSYLVANIA:
- Before Net of Tax Savings Payout and Partnership Payout.
<TABLE>
<CAPTION>
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP
ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST(1)
------ -------------- -------------------- -----------------------
<S> <C> <C> <C>
Managing General Partner.................25% partnership interest (2) 21.875%
Investors................................75% partnership interest (2) 65.625%
Third Party.......................................................... 12.500% Landowner Royalty 12.500%
Interest ---------
100.000%
=========
</TABLE>
---------------------------------
(1) It is possible that substituted or additional wells could have a net
revenue interest to the partnership as low as 84.375% which would reduce
the investors' interest to 63.281% (2).
(2) These percentages are for illustration purposes only and are based on the
managing general partner's minimum required capital contribution to the
partnership compared to the corresponding capital contributions of you and
the other investors. The actual percentages are likely to be different
because they will be based on the actual capital contributions of the
managing general partner and you and the other investors.
- After Net of Tax Savings Payout, but before Partnership Payout.
<TABLE>
<CAPTION>
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP
ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST(1)
------ -------------- -------------------- -----------------------
<S> <C> <C> <C>
Managing General Partner.................31.5% partnership interest (2) 27.5625%
Investors................................68.5% partnership interest (2) 59.9375%
Third Party.......................................................... 12.500% Landowner Royalty 12.5000%
Interest ---------
100.0000%
=========
</TABLE>
---------------------------------
(1) It is possible that substituted or additional wells could have a net
revenue interest to the partnership as low as 84.375% which would reduce
the investors' interest to 57.7969% (2).
(2) These percentages are for illustration purposes only and are based on the
managing general partner's minimum required capital contribution to the
partnership compared to the corresponding capital contributions of you and
the other investors. The actual percentages are likely to be different
because they will be based on the actual capital contributions of the
managing general partner and you and the other investors.
- After Partnership Payout.
<TABLE>
<CAPTION>
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP
ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST(1)
------ -------------- -------------------- -----------------------
<S> <C> <C> <C>
Managing General Partner ................40% partnership interest (2) 35.000%
Investors................................60% partnership interest (2) 52.500%
Third Party.......................................................... 12.500% Landowner Royalty 12.500%
Interest ---------
100.000%
=========
</TABLE>
---------------------------------
39
<PAGE>
(1) It is possible that substituted or additional wells could have a net
revenue interest to the partnership as low as 84.375% which would reduce
the investors' interest to 50.625% (2).
(2) These percentages are for illustration purposes only and are based on the
managing general partner's minimum required capital contribution to the
partnership compared to the corresponding capital contributions of you and
the other investors.
The actual percentages are likely to be different because they will be
based on the actual capital contributions of the managing general
partner and you and the other investors.
SECONDARY AREAS. Although the managing general partner anticipates the
partnership will have a net revenue interest ranging from 81% to 87.5% in the
secondary areas described above, there is no minimum net revenue interest
which the partnership is required to own before drilling a well in other
areas of the Appalachian Basin or the United States. The leases in these
other areas may be subject to interests in favor of third parties which are
not currently known such as:
- overriding royalty interests;
- net profits interests;
- carried interests;
- production payments;
- reversionary interests pursuant to farmouts or non-consent
elections under joint operating agreements; or
- other retained or carried interests.
TITLE TO PROPERTIES
Title to all leases acquired by the partnership will be held in the name of
the partnership. However, to facilitate the acquisition of the leases title
to the leases may initially be held in the name of:
- the managing general partner;
- its affiliates; or
- any nominee designated by the managing general partner.
Title to the leases will be transferred to the partnership from time to time
after the minimum subscriptions are received and released from escrow. After
drilling, the title to the leases will be filed for record.
The managing general partner will take the steps it deems necessary to assure
that the partnership has acceptable title for its purposes. However, it is
not the practice in the oil and gas industry to warrant title or obtain title
insurance on leases and the managing general partner will provide neither for
its lease interests assigned to the partnership. The managing general partner
will obtain a favorable formal title opinion for the lease interest before
each well is drilled, but the managing general partner may use its own
judgment in waiving title requirements and will not be liable for any failure
of title of leases transferred to the partnership. Also, there is no
assurance that the partnership will not experience losses from title defects
excluded from or not disclosed by the formal title opinion.
DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS
Under the drilling and operating agreement the responsibility for drilling
and completing, or plugging, partnership wells will be on the managing
general partner or an affiliate as the operator and the general drilling
contractor for cost plus 15% as described in
40
<PAGE>
"Compensation." During drilling operations the managing general partner's
duties as operator and general drilling contractor will include:
- making necessary arrangements for drilling and completing
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 drilling, testing and equipping the wells; and
- making technical decisions required in drilling and
completing the wells.
Under the drilling and operating agreement all partnership wells will be
drilled to a sufficient depth to test thoroughly the objective geological
formation, and the partnership will prepay the investors' share of the
drilling and completion costs.
If there is a co-owner of the well which serves as the actual operator and
the general drilling contractor, then the managing general partner will still
enter into the drilling and operating agreement with the partnership to drill
and complete the wells on the terms described in "Compensation." This may
include a few of the wells drilled in the Clinton/Medina geological formation
in Northwestern Pennsylvania and Ohio and the Devonian Shale geological
formation in Kentucky and Virginia. The managing general partner would review
the performance of the third-party operator and general drilling contractor
which would include the following:
- monitoring all field operations in connection with
drilling, testing and equipping the wells;
- monitoring technical decisions required in drilling and
completing the wells;
- monitoring the costs and expenses charged by the third
party operator; and
- monitoring the accounting and production records for the
partnership.
If the partnership is the largest interest owner in the well, then it is
likely that even in these circumstances the managing general partner would
control the operations through its ownership interest in the well.
Under the drilling and operating agreement the managing general partner, as
operator, will complete each well if there is a reasonable probability of
obtaining commercial quantities of oil or gas. However, based upon its past
experience, the managing general partner anticipates that most of the
partnership's wells drilled to the Clinton/Medina geological formation and
the Mississippian/Upper Devonian Sandstone reservoirs will be required to be
completed before it can determine the well's productivity. If the managing
general partner, as operator, determines that a well should not be completed,
then the well will be plugged and abandoned.
During producing operations the managing general partner's duties as operator
will include:
- managing and conducting all field operations in connection
with operating and producing the wells;
- making technical decisions required in operating the wells;
and
- maintaining the wells, equipment and facilities in good
working order during their useful life.
The managing general partner will be reimbursed for its direct expenses and
will receive well supervision fees at competitive rates for operating and
maintaining the wells during producing operations. The drilling and operating
agreement contains a number of other material provisions which you and the
other prospective investors should carefully review.
41
<PAGE>
If the managing general partner or an affiliate is not the actual operator of
the well during producing operations as described above, then the managing
general partner will enter into the drilling and operating agreement and
receive well supervision fees for reviewing the performance of the third
party operator. This includes the following:
- 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. In these cases these
fees will be paid by the managing general partner from the well supervision
fees it receives under the drilling and operating agreement entered into
between the managing general partner and the partnership.
As described above, certain wells may be drilled with third parties owning a
portion of the interest in the wells. 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.
SALE OF OIL AND GAS PRODUCTION
POLICY OF TREATING ALL WELLS EQUALLY IN A GEOGRAPHIC AREA. The managing
general partner is responsible for selling the partnership's gas and oil
production, and its policy is to treat all wells in a given geographic area
equally. This reduces certain potential conflicts of interest among the
owners of the various wells, including the partnership, concerning to whom
and at what price the gas and oil will be sold. For example, the managing
general partner calculates a weighted average selling price for all of the
gas sold in the geographic area by dividing the money received from the sale
of all of the gas sold to customers in the area by the volume of all gas sold
from the wells in the area. For gas sold in Northwestern Pennsylvania the
managing general partner received an average selling price after deducting
all expenses, including transportation expenses, of approximately:
- $2.39 per mcf in 1997;
- $2.22 per mcf in 1998;
- $2.35 per mcf in 1999; and
- $2.80 per mcf for the first six months of 2000.
Although 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 has not voluntarily restricted its
gas production in the past five years because of a lack of a profitable
market price.
If the managing general partner should decide that curtailment of production
would 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 able to feed into the pipeline,
regardless of which partnerships own the wells.
GATHERING OF THE GAS. With respect to the majority of the partnership's
natural gas production, including gas in the primary areas of Northwestern
Pennsylvania and Fayette County, Pennsylvania, Atlas Pipeline Partners, L.P.,
a limited partnership in which a subsidiary of Atlas America serves as
managing general partner, will gather, compress and transport the gas to
industrial
42
<PAGE>
end-users, local distribution companies, or interstate pipeline systems as
discussed below. If the partnership's gas is not transported through the
Atlas Pipeline Partners gathering system, then it is because there is a
third-party operator or the gathering system has not been extended to the
wells. In these cases the gas will be transported through a third-party
gathering system and the partnership will pay a competitive fee.
As a part of the sale of the gathering system to Atlas Pipeline Partners,
Atlas America and its affiliates, Resource Energy and Viking Resources, made
the commitments set forth below which to varying degrees may affect the
partnership. The commitments were intended to maximize the use and expansion
of the gathering system. These are continuing obligations of Atlas America,
Resource Energy, and Viking Resources unless the managing general partner of
Atlas Pipeline Partners is removed without cause in which case the
obligations cease.
- They are required to pay a gathering fee equal to the greater
of $0.35 per mcf or 16% of the gross sales price for each mcf
transported for all partnerships in which their subsidiaries
serve as managing general partner, which includes the
partnership. Gross sales price generally means the price
received by the seller, for natural gas sold by it, without
deduction for brokerage fees, commissions, or offsets. Thus,
if the partnership pays a lesser amount as is currently
anticipated by the managing general partner as described in
"Compensation - Gathering Fees," then Atlas America or one of
the other parties must pay the difference to Atlas Pipeline
Partners.
- They committed to adding 225 wells to the gathering system
over a period from January 1, 1999, until December 31, 2002,
which includes any well drilled in a partnership sponsored by
them. To satisfy the commitment the wells must be drilled
within 2,500 feet of the gathering system and the well owner
must construct up to 2,500 feet of small diameter sales or
flow lines from the wellhead to the gathering system. This
commitment has been satisfied.
- With respect to wells drilled more than 3,500 feet from the
gathering system, Atlas Pipeline Partners may, at its cost,
extend its gathering systems to within 2,500 feet. If it does
not, then the well may be connected to a third party pipeline,
a local distribution company or an end user. If the wells are
to be connected to a third party gathering system, however,
Atlas Pipeline Partners has the right to pay the cost of
constructing the line from the well to the third party
gathering system. If it does so, it will own the line and will
be paid an amount equal to the greater of $0.35 per mcf or 16%
of the gross sales price for each mcf transported, less the
gathering fee charged by the other gathering system.
- They have agreed to assist Atlas Pipeline Partners in
identifying existing gathering systems for possible
acquisition and provide consulting services in evaluating and
bidding for these systems.
- They have agreed that their subsidiaries which currently serve
as managing general partners of their drilling programs will
continue to serve as managing partners of new drilling
programs, and a managing general partner's interests in a
drilling program may not be transferred to a person unless it
transfers its ownership in each of its other drilling programs
to the same person.
- Atlas America has agreed to provide construction management
and financing services to Atlas Pipeline Partners in the
construction of additions or extensions to the gathering
system. For a period of five years from January 28, 2000 to
January 28, 2005 Atlas America has a standby commitment for a
maximum of $1.5 million in any contract year. The funds will
be provided through the purchase by Atlas America of Atlas
Pipeline Partners' common units in the amount of the
construction costs.
GAS CONTRACTS. The managing general partner, Resource Energy, Inc. and Atlas
Energy Group, Inc. have a gas supply agreement with First Energy Corporation
through its affiliate, Northeast Ohio Gas Marketing, for a 10-year term which
began on April 1, 1999. Subject to certain exceptions, First Energy
Corporation must buy all of the gas produced and delivered by the managing
general partner and its affiliates, which includes the partnership, at
certain delivery points with the facilities of: East Ohio Gas
43
<PAGE>
Company, National Fuel Gas Distribution, and Peoples Natural Gas Company,
which are local distribution companies, and National Fuel Gas Supply,
Columbia Gas Transmission Corporation, and Tennessee Gas Pipeline Company,
which are interstate pipelines. First Energy Corporation is an electric
utility listed on the New York Stock Exchange which also provides natural gas
to industry and retail consumers.
Generally, all of the managing general partner's and its affiliates' gas is
subject to the agreement with First Energy Corporation, with the following
exceptions:
- gas being sold to Wheatland Tube Company, CSC Industries and
Warren Consolidated, which are industrial end-users and direct
delivery customers of the managing general partner and its
affiliates;
- gas which at the time of the agreement was already dedicated
for the life of the well to another buyer;
- gas which is produced by a company which was not an affiliate
of the managing general partner at the time of the agreement;
- gas which is produced in areas where there is not a delivery
point into any of the interstate pipelines or local
distribution companies described above; or
- gas which is produced from a well which is being operated by a
third-party and as a part of the acquisition it was agreed
that the third-party operator would market the gas.
The contract with Wheatland Tube currently provides for more favorable
pricing than under the agreement with First Energy Corporation. The contracts
with CSC and Warren Consolidated will be unrelated to the partnership.
The agreement establishes a price formula for each of the delivery points for
either the first one or two years of the agreement which is tied to the spot
market price. If, at the end of the applicable period, the parties cannot
agree to a new price for any delivery point, then the managing general
partner and its affiliates may arrange a sale of their gas for that delivery
point to a third-party for 12 months. If First Energy Corporation does not
match this price, then the gas will be sold to the third-party. This process
will be repeated each year. The contracts with National Fuel Resources, Inc.
and NUI Energy Brokers, Inc. discussed below were entered into pursuant to
this process.
The agreement may be suspended for force majeure which means generally such
things as an act of God, fire, storm, flood, and explosion, but also includes
the permanent closing of the factories of Carbide Graphite or Duferco Farrell
Corporation during the term of First Energy Corporation's agreements to sell
gas to them. If these factories were closed, however, the managing general
partner believes that First Energy Corporation would be able to find
alternative purchasers and would not invoke the force majeure.
The managing general partner anticipates that the gas produced by the
partnership from wells drilled to the Clinton/Medina geological formation in
Northwestern Pennsylvania will be sold to the following customers.
- Approximately 10% to 15% to Wheatland Tube pursuant to an
agreement that contains minimum and maximum prices that are
fixed over each annual period.
- Approximately 40% to National Fuel Resources, Inc., a
marketing subsidiary of National Fuel Gas Company, which is a
publicly traded company that distributes natural gas to
approximately 744,000 customers in Southwest New York and
Northwest Pennsylvania through its regulated utility
divisions, pursuant to an agreement for successive one year
terms beginning April 1, 2000.
- Approximately 17% to NUI Energy Brokers, Inc., a marketing
subsidiary of NUI Corporation, a publicly traded company that
distributes natural gas to approximately 372,000 customers in
six states through its regulated utility divisions, pursuant
to an agreement for successive one year terms beginning April
1, 2000.
- The remainder of the partnership's gas will be sold to First
Energy Corporation as discussed above.
44
<PAGE>
All of these agreements include monthly pricing formulas for the gas for each
of the delivery points set forth in the respective agreements. Also, since
the agreements with National Fuel Resources and NUI Energy Brokers, the
managing general partner and First Energy Corporation have been able to agree
to new pricing arrangements for other delivery points pursuant to their
agreement. At the end of the one year term, which is April 1, 2001, First
Energy Corporation will have the opportunity to again buy the gas at the
delivery points which are currently under the agreements with National Fuel
Resources and NUI Energy Brokers.
The managing general partner anticipates that all of the gas produced by the
partnership from wells drilled to the Mississippian/Upper Devonian Sandstone
reservoirs in Fayette County, Pennsylvania will be sold to First Energy
Corporation.
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 used 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 using 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.
The managing general partner expects that gas produced from wells drilled in
areas of the United States other than described above will be primarily tied
to the spot market price and supplied to:
- gas marketers;
- local distribution companies;
- industrial end-users; and/or
- electric companies.
CRUDE OIL. Crude oil produced from the wells will flow directly into storage
tanks where it will be picked up by the oil company, a common carrier or
pipeline companies acting for the oil company which is purchasing the crude
oil. Thus, crude oil does not present any transportation problem. The
managing general partner anticipates selling any oil produced by the wells to
purchasers in spot sales. The managing general partner was receiving an
average selling price for oil of approximately:
- $15.20 per barrel in December, 1997;
- $13.00 per barrel in December, 1998;
- $16.20 per barrel in 1999; and
- $25.00 per barrel for the first six months of 2000.
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, including its
partnerships, have been involved in the drilling of more than 3,600 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
45
<PAGE>
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 million 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 where the wells will be drilled;
- liability insurance, including automobile, which has a $1
million 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 million during drilling
operations and $10 million thereafter, per occurrence or
accident and in the aggregate.
- This includes $1,000,000 of seepage, pollution and
contamination insurance which protects the insured
against bodily injury or property damage 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 effective no later than the date
subscription proceeds are first released from escrow, and 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
million 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 its current coverage, but may be unsuccessful
if the coverage becomes unavailable or too expensive.
If you are an investor general partner and there is going to be an adverse
material change in the partnership's insurance coverage, which is not
anticipated, then the managing general partner must notify you at least 30
days before the effective date. If the insurance coverage is materially
reduced, 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 who 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
under the drilling and operating agreement. These charges will be in addition
to the unaccountable, fixed payment reimbursement paid to the managing
general partner for administrative costs, and well supervision fees paid to
the managing general partner as operator.
46
<PAGE>
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 $9.5
million 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 any of the following occur:
- a greater amount is raised;
- the partnership takes a lesser interest in the wells;
- the wells are substituted; or
- the managing general partner decides to drill wells in
other areas of the United States.
The managing general partner has not authorized any person to make any
representations to you 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;
- 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 and will generally
be located in areas where the managing general partner or its affiliates have
previously conducted drilling operations. You, however, will not have the
opportunity to evaluate for yourself the relevant 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
help you in evaluating the proposed wells, including production information
for wells in the general area which the managing general partner believes 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 these areas can change in a short distance.
You are cautioned 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. In your analysis you should weigh the factors set forth
below.
47
<PAGE>
- The length of time which the well has been on line and the
period 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 from a well declines at various rates throughout
the life of the 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 for 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 close to a
proposed well tends to be more relevant than production
information for wells farther from a proposed well,
although from time to time great differences in well
performance can occur in wells located close together.
- Consistency in production among wells tends to confirm the
reliability and predictability of the production.
To help you in becoming familiar with the proposed wells the information set
forth below is included.
- Northwestern Pennsylvania (Clinton/Medina Geological
Formation).
- 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.
- Fayette County, Pennsylvania (Mississippian/Upper Devonian
Sandstone Reservoirs).
- A map of western Pennsylvania showing Fayette County.
- Lease information.
- A Location and Production Map showing the proposed
wells and the wells in the area.
- Production data.
- The managing general partner's geologic evaluation.
48
<PAGE>
MAP OF WESTERN PENNSYLVANIA
AND
EASTERN OHIO
49
<PAGE>
[MAP]
50
<PAGE>
LEASE INFORMATION
51
<PAGE>
<TABLE>
<CAPTION>
OVERRIDING ROYALTY
INTEREST TO THE
EFFECTIVE EXPIRATION LANDOWNER ROYALTY MANAGING GENERAL
PROSPECT NAME COUNTY DATE* DATE* PARTNER
----------------------------- ----------------- --------------- ---------------- ------------------ --------------------
<S> <C> <C> <C> <C> <C>
1. Elder #2 Lawrence 03/08/02 03/08/02 12.5% 0%
2. Griffith #1 Lawrence 09/21/99 09/21/02 12.5% 0%
3. Griffith #2 Lawrence 09/21/99 09/21/02 12.5% 0%
4. Kauffman #2 Lawrence 04/27/98 04/27/01 12.5% 0%
5. Lahr #1 Lawrence 06/25/99 06/25/02 12.5% 0%
6. Mast #9 Lawrence 07/24/98 07/24/01 12.5% 0%
7. McConnell #2 Lawrence 08/13/98 08/13/01 12.5% 0%
8. Miller #15 Lawrence 10/28/99 10/28/02 12.5% 0%
9. Patterson #2 Lawrence 10/19/99 10/19/02 12.5% 0%
10. Porada #1 Lawrence 06/04/99 06/04/02 12.5% 0%
11. R. & K. Partners #1 Lawrence 11/16/99 11/16/02 12.5% 0%
12. Reiber #1 Lawrence 01/26/99 01/26/02 12.5% 0%
13. Rose #1 Lawrence 12/21/99 12/21/02 12.5% 0%
14. Wengerd #6 Lawrence 01/26/99 01/26/02 12.5% 0%
15. White #6 Lawrence 10/02/98 10/02/01 12.5% 0%
16. Wilson #7 Lawrence 03/12/99 03/12/02 12.5% 0%
17. Burgoon #1 Mercer 05/25/00 05/25/03 12.5% 0%
18. Byler #83 Mercer 06/21/00 06/21/03 12.5% 0%
19. Byler #84 Mercer 10/14/99 10/14/02 12.5% 0%
20. Garrett #8 Mercer 09/09/98 09/09/03 12.5% 0%
21. Jovenall #2 Mercer 06/18/98 HBP 12.5% 0%
22. King #6 Mercer 06/28/99 06/28/02 12.5% 0%
23. Lutz #3 Mercer 06/25/00 06/25/03 12.5% 0%
24. McFarland #19 Mercer 10/08/97 10/08/00 12.5% 0%
25. Minner #7 Mercer 05/07/98 HBP 12.5% 0%
26. Revale #1 Mercer 10/08/99 10/08/02 12.5% 0%
27. Schwartz #2 Mercer 07/16/98 07/16/01 12.5% 0%
28. Shetler #3 Mercer 03/23/72 HBP 12.5% 0%
29. Webster #1 Mercer 06/19/99 06/19/02 12.5% 0%
30. Weimer #1 Mercer 01/04/00 01/04/03 12.5% 0%
<CAPTION>
OVERRIDING
ROYALTY ACRES TO BE
INTEREST TO NET REVENUE NET ACRES ASSIGNED TO
PROSPECT NAME 3RD PARTIES INTEREST PARTNERSHIP
----------------------------- -------------------- ---------------- ---------- ---------------
<S> <C> <C> <C> <C>
1. Elder #2 0% 87.5% 148.00 50.00
2. Griffith #1 0% 87.5% 51.17 50.00
3. Griffith #2 0% 87.5% 93.59 50.00
4. Kauffman #2 0% 87.5% 92.00 50.00
5. Lahr #1 0% 87.5% 39.00 50.00
6. Mast #9 0% 87.5% 80.00 50.00
7. McConnell #2 0% 87.5% 75.00 50.00
8. Miller #15 0% 87.5% 59.00 50.00
9. Patterson #2 0% 87.5% 98.60 50.00
10. Porada #1 0% 87.5% 63.00 50.00
11. R. & K. Partners #1 0% 87.5% 82.00 50.00
12. Reiber #1 0% 87.5% 126.00 50.00
13. Rose #1 0% 87.5% 81.00 50.00
14. Wengerd #6 0% 87.5% 54.00 50.00
15. White #6 0% 87.5% 107.00 50.00
16. Wilson #7 0% 87.5% 104.00 50.00
17. Burgoon #1 0% 87.5% 58.00 50.00
18. Byler #83 0% 87.5% 100.00 50.00
19. Byler #84 0% 87.5% 102.00 50.00
20. Garrett #8 0% 87.5% 50.00 50.00
21. Jovenall #2 0% 87.5% 132.00 50.00
22. King #6 0% 87.5% 35.00 50.00
23. Lutz #3 0% 87.5% 160.00 50.00
24. McFarland #19 0% 87.5% 133.00 50.00
25. Minner #7 0% 87.5% 205.00 50.00
26. Revale #1 0% 87.5% 65.00 50.00
27. Schwartz #2 0% 87.5% 110.00 50.00
28. Shetler #3 0% 87.5% 60.00 50.00
29. Webster #1 0% 87.5% 140.00 50.00
30. Weimer #1 0% 87.5% 60.00 50.00
</TABLE>
--------------------------------
*HBP - Held by Production
52
<PAGE>
LOCATION AND PRODUCTION MAP
53
<PAGE>
[MAP]
54
<PAGE>
[MAP]
55
<PAGE>
[MAP]
56
<PAGE>
[MAP]
57
<PAGE>
[MAP]
58
<PAGE>
[MAP]
59
<PAGE>
PRODUCTION DATA
60
<PAGE>
<TABLE>
<CAPTION>
The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results, although
it is an important indicator in evaluating the economic potential of any well to
be drilled by the partnership.
ID 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>
20187 Atlas Resources, Inc. Wengerd Unit #2A 03/22/98 24 26361 6075 756
20195 Atlas Resources, Inc. Byler #33 01/11/99 16 28675 6098 1200
20203 Atlas Resources, Inc. Teh #1 09/18/98 20 24243 5999 734
20216 Atlas Resources, Inc. Kempf #3 02/03/99 16 16097 6087 630
20245 Atlas Resources, Inc. Buchowski #2 07/14/99 10 59931 6111 8707
20246 Atlas Resources, Inc. Contray #1 09/25/99 8 17825 6087 1994
20247 Atlas Resources, Inc. Johnston Unit #5 08/20/99 9 12311 6085 921
20272 Atlas Resources, Inc. Best #3 11/01/99 2 4554 6292 2608
20273 Atlas Resources, Inc. Grata #1 01/26/00 2 3346 6000 2468
20274 Atlas Resources, Inc. Mitcheltree #1 01/09/00 2 5668 6279 3417
20275 Atlas Resources, Inc. Shaffer Unit #6 01/04/00 2 6813 6337 3774
20276 Atlas Resources, Inc. Wengerd #7 02/01/00 N/A N/A 6132 N/A
20277 Atlas Resources, Inc. Stickle #1 01/23/00 3 2390 6297 944
20279 Atlas Resources, Inc. Byler #73 01/08/00 3 3389 6272 1594
20280 Atlas Resources, Inc. Byler #72 01/12/00 3 562 6283 307
20281 Atlas Resources, Inc. Braatz #1 01/14/00 2 5573 6332 3285
20283 Atlas Resources, Inc. Telesz #1 01/17/00 2 3955 6311 2276
20285 Atlas Resources, Inc. Kendall #2 02/01/00 N/A N/A 6315 N/A
20286 Atlas Resources, Inc. Clark #7 02/14/00 1 1239 6326 N/A
20291 Atlas Resources, Inc. Kauffman #1 02/13/00 N/A N/A 6156 N/A
20292 Atlas Resources, Inc. Telesz #2 03/13/00 2 3585 6317 2298
20293 Atlas Resources, Inc. Wilson #6 02/07/00 N/A N/A 6197 N/A
20392 Atlas Resources, Inc. Hillmar Unit #9 02/22/82 170 49014 6234 576
20604 Atlas Resources, Inc. Nych Unit #1 05/05/84 149 32650 5652 159
20740 Atlas Resources, Inc. Five Brothers #1 11/03/85 173 38452 5513 N/A
20867 Atlas Resources, Inc. Valentine #1 03/07/88 147 40954 5545 127
20873 Cabot Oil & Gas Nader #2 11/23/80 N/A N/A 5121 N/A
21121 Capital Oil & Gas Hostetler, M. & D. #1 11/11/90 N/A N/A 6140 N/A
21126 Atlas Resources, Inc. Stambaugh #2 02/06/91 110 90115 5528 596
21231 Capital Oil & Gas Cox, Joan #1 12/23/91 N/A N/A 6100 N/A
21368 Atlas Resources, Inc. Moose #3 08/29/92 89 59946 5906 169
21497 Capital Oil & Gas Byler, S. & M. #2 12/02/92 N/A N/A 6210 N/A
61
<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.
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
CLINTON/MEDINA DEPTH PROD.
-----------------------------------------------------------------------------------------------------------------------------
21498 Capital Oil & Gas Hostetler, M. & D. #3 10/29/92 N/A N/A 6154 N/A
21508 Capital Oil & Gas Cox, J. #2 12/17/92 N/A N/A 6035 N/A
21569 Tipka Oil & Gas Byler, J. & K. #1 09/19/92 N/A N/A 6036 N/A
21577 Atlas Resources, Inc. Symons #1 09/19/92 89 41310 5950 114
21582 Tipka Oil & Gas Janosky Unit #1 10/02/92 N/A N/A 5882 N/A
21590 Tipka Oil & Gas McFarland Unit #1 10/20/92 N/A N/A 5864 N/A
21591 Atlas Resources, Inc. Hover #1 10/07/92 89 55269 6001 247
21614 Atlas Resources, Inc. Byler #3 12/15/92 88 117438 6037 509
21617 Atlas Resources, Inc. Williams Unit #2 12/19/92 88 134340 5901 674
21642 Atlas Resources, Inc. Hover Unit #2 01/10/93 88 76626 5999 536
21663 Atlas Resources, Inc. Ammer #6 03/01/93 86 78790 6196 466
21664 Atlas Resources, Inc. Byler #4 06/28/93 83 144579 6022 1055
21666 Atlas Resources, Inc. Moose #8A 12/05/93 78 76575 6121 539
21669 Atlas Resources, Inc. Byler #7A 07/07/93 83 60371 6182 481
21672 Atlas Resources, Inc. Moose Unit #6 12/12/93 76 64776 5975 567
21677 Atlas Resources, Inc. Moose #5 02/17/93 86 81195 6052 365
21678 Atlas Resources, Inc. Byler Unit #6 11/03/93 79 66691 6135 440
21679 Atlas Resources, Inc. Swartzentruber #2 11/09/93 Plugged & Abandoned 6177 N/A
21680 Atlas Resources, Inc. Edeburn Unit #1 11/14/93 78 46764 6060 370
21715 Atlas Resources, Inc. McCutcheon #1 02/23/93 86 78026 5978 303
21745 North Coast Energy Ray, F. & E. #1 10/15/93 N/A N/A 5900 N/A
21806 Atlas Resources, Inc. Kirk #1 02/12/94 74 63352 6212 325
21845 Atlas Resources, Inc. Swartzentruber #1 01/07/94 76 42101 6123 329
21922 Atlas Resources, Inc. Kirk #3 07/30/94 68 108442 6160 819
21935 Atlas Resources, Inc. Kirk #2 08/03/94 68 67468 6163 493
22033 Atlas Resources, Inc. Byler #10 01/23/95 64 73357 6209 652
22269 Atlas Resources, Inc. Ealy #3 09/01/96 44 56220 5451 604
22347 Atlas Resources, Inc. Ealy Unit #5 03/03/97 38 61731 5379 1026
22465 Atlas Resources, Inc. Byler #29 03/03/98 24 47896 6071 1113
22466 Atlas Resources, Inc. Byler #31 03/12/98 25 58571 6034 2743
22472 Atlas Resources, Inc. Ellis #1 09/04/98 20 37172 6415 1243
22487 Atlas Resources, Inc. Kurtz #7 07/14/98 20 57874 6020 2248
62
<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.
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
CLINTON/MEDINA DEPTH PROD.
-----------------------------------------------------------------------------------------------------------------------------
22492 Atlas Resources, Inc. Byler #25 03/25/98 24 31186 5848 922
22493 Atlas Resources, Inc. Western Reserve Sports #1 03/22/98 26 11801 5756 409
22496 Atlas Resources, Inc. Byers #2 03/19/98 24 21839 5893 545
22530 Atlas Resources, Inc. Hughes #2 08/23/98 20 8830 5894 228
22538 Atlas Resources, Inc. Book #1 03/31/99 13 10078 5905 520
22539 Atlas Resources, Inc. Wengerd #3 01/12/99 16 32079 6048 1521
22554 Atlas Resources, Inc. Byler #32 08/23/98 20 42415 5941 1238
22559 Atlas Resources, Inc. Borowicz #1 09/22/98 20 26209 5955 663
22560 Atlas Resources, Inc. Thompson #9 10/22/98 18 16660 5781 790
22566 Atlas Resources, Inc. Santelli #1 10/20/99 7 12341 5882 1276
22568 Atlas Resources, Inc. Byers #3 10/19/99 7 15297 5829 1774
22570 Atlas Resources, Inc. Donner #1 10/05/98 19 37408 5902 1397
22590 Atlas Resources, Inc. Thompson #8 10/26/99 7 19663 5805 3475
22595 Atlas Resources, Inc. Thompson #7 02/19/99 15 23169 5750 1232
22610 Atlas Resources, Inc. Jovenall #1 03/02/99 14 13723 5889 639
22617 Atlas Resources, Inc. Cameron #2 03/10/99 14 13413 5843 666
22629 Atlas Resources, Inc. Dixon #4 03/16/99 14 7589 5964 546
22638 Atlas Resources, Inc. Cypher Unit #1 03/17/99 13 22438 5272 1119
22651 Atlas Resources, Inc. Byler #62 07/02/99 10 19954 5931 1627
22653 Atlas Resources, Inc. Buckwalter Unit #1 07/31/99 9 28612 5834 3454
22675 Atlas Resources, Inc. Ligo Unit #1 08/28/99 8 14419 6005 1304
22676 Atlas Resources, Inc. Byler #66 08/27/99 9 15771 5921 1202
22677 Atlas Resources, Inc. Byler #69 09/15/99 8 22775 5883 2837
22678 Atlas Resources, Inc. Hayman #1 10/11/99 7 16354 5924 1865
22680 Atlas Resources, Inc. Turner #2 09/09/99 7 14636 5271 2065
22685 Atlas Resources, Inc. Byler Unit #67 10/08/99 7 14539 5951 1325
22687 Atlas Resources, Inc. Ammann #1 09/19/99 N/A N/A 5513 N/A
22690 Atlas Resources, Inc. Living Word #1A 10/08/99 7 16953 5919 1887
22696 Atlas Resources, Inc. King #4 10/01/99 N/A N/A 5466 N/A
22703 Atlas Resources, Inc. Wallace #1 11/03/99 6 5655 5302 947
22704 Atlas Resources, Inc. Minner #5 11/07/99 6 24523 5715 3359
22705 Atlas Resources, Inc. Minner #9 11/13/99 6 10751 5784 1714
63
<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.
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
CLINTON/MEDINA DEPTH PROD.
-----------------------------------------------------------------------------------------------------------------------------
22706 Atlas Resources, Inc. McFarland #15 12/17/99 5 9689 5967 1777
22707 Atlas Resources, Inc. Hostetler Unit #14 12/07/99 4 8332 5952 1606
22708 Atlas Resources, Inc. Hostetler #15 12/12/99 5 14133 5930 2989
22710 Atlas Resources, Inc. Swaney #6 11/20/99 6 16013 5775 2658
22711 Atlas Resources, Inc. Swaney Unit #5 11/14/99 6 10492 5808 1507
22713 Atlas Resources, Inc. Buckwalter Unit #2 11/17/99 5 7234 5791 1197
22714 Atlas Resources, Inc. Combine #1 12/19/99 4 23334 5811 8540
22716 Atlas Resources, Inc. Yoder #8 12/14/99 5 9064 5979 1729
22717 Atlas Resources, Inc. Lehto #1 12/29/99 4 3636 5893 791
22720 Atlas Resources, Inc. Bobish #1 12/16/99 1 794 5785 N/A
22721 Atlas Resources, Inc. Czubek #2 12/29/99 4 7746 5711 2199
22731 Atlas Resources, Inc. Shaffer Unit #8 01/19/00 4 14821 5864 4534
22732 Atlas Resources, Inc. Gilliland #1 12/03/99 N/A N/A 5893 N/A
22733 Atlas Resources, Inc. Jovenall #3 12/09/99 N/A N/A 5883 N/A
22735 Atlas Resources, Inc. Horodnic #2 12/10/99 4 11462 5890 2780
22739 Atlas Resources, Inc. Leali #6 12/29/99 4 4761 5770 1393
22740 Atlas Resources, Inc. Yasnowsky #3 12/21/99 4 5387 5699 1314
22741 Atlas Resources, Inc. Minner #4 01/04/00 4 5971 5728 1537
22742 Atlas Resources, Inc. Hardisky #1 01/07/00 4 3562 5897 893
22743 Atlas Resources, Inc. Whalen #1 12/21/99 4 9116 5890 2552
22744 Atlas Resources, Inc. Picirilli #1 01/06/00 3 6423 5827 2767
22745 Atlas Resources, Inc. Minner #6 01/09/00 4 5938 5728 1440
22749 Atlas Resources, Inc. Shardy #1 01/12/00 N/A N/A 5535 N/A
22750 Atlas Resources, Inc. Leali #7 01/06/00 4 3233 5812 962
22761 Atlas Resources, Inc. Yoder #9 01/14/00 N/A N/A 5128 N/A
22763 Atlas Resources, Inc. Racketa Unit #2 01/18/00 N/A N/A 5551 N/A
22772 Atlas Resources, Inc. Herriott #1 01/24/00 3 4816 5886 2365
22774 Atlas Resources, Inc. Lehto #2 01/30/00 3 6647 5855 2615
22775 Atlas Resources, Inc. Minner #10 02/05/00 3 8145 5741 2253
22782 Atlas Resources, Inc. Garrett #2 02/21/00 1 2210 5923 N/A
22783 Atlas Resources, Inc. Yasnowsky #2 02/11/00 3 4179 5713 1294
22786 Atlas Resources, Inc. Aiken #3 02/20/00 1 1287 5629 N/A
64
<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.
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
CLINTON/MEDINA DEPTH PROD.
-----------------------------------------------------------------------------------------------------------------------------
22787 Atlas Resources, Inc. Garrett Unit #5 02/25/00 1 N/A 5758 N/A
22789 Atlas Resources, Inc. Byler #76 02/27/00 1 1783 5865 N/A
22790 Atlas Resources, Inc. Gearhart #1 02/21/00 1 1599 5807 N/A
22792 Atlas Resources, Inc. Minner #11 03/02/00 1 1293 5825 N/A
22793 Atlas Resources, Inc. McFarland Unit #16 02/26/00 1 1720 5861 N/A
Note: Accurate through ------- Period Ending 5/2000
</TABLE>
65
<PAGE>
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
NORTHWESTERN PENNSYLVANIA
66
<PAGE>
GEOLOGIC EVALUATION
OF
ATLAS AMERICA PUBLIC #9 LTD
DRILLING PROGRAM
SOUTHWESTERN MERCER & SOUTHWESTERN WARREN PROSPECT AREA
PENNSYLVANIA
PROGRAM PROPOSED BY:
ATLAS RESOURCES, INC.
311 ROUSER ROAD
P.O. BOX 611
MOON TOWNSHIP, PA 15108
REPORT SUBMITTED BY:
UEDC
UNITED ENERGY DEVELOPMENT CONSULTANTS, INC.
1715 CRAFTON BLVD.
PITTSBURGH, PA 15205
67
<PAGE>
[MAP]
<TABLE>
<CAPTION>
TABLE OF CONTENTS
<S> <C>
INVESTIGATION SUMMARY..........................................................3
OBJECTIVE...............................................................3
AREA OF INVESTIGATION...................................................3
METHODOLOGY.............................................................3
PROSPECT AREA HISTORY..........................................................4
DRILLING ACTIVITY.......................................................4
GEOLOGY.................................................................4
STRATIGRAPHY, LITHOLOGY & DEPOSITION...............................4
RESERVOIR CHARACTERISTICS..........................................6
PRODUCTION CURVE........................................................8
POTENTIAL MARKETS AND PIPELINES.........................................8
STATEMENTS.....................................................................8
CONCLUSION..............................................................9
DISCLAIMER..............................................................9
NON-INTEREST............................................................9
</TABLE>
68
<PAGE>
INVESTIGATION SUMMARY
OBJECTIVE
The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Southwestern Mercer & Southwestern
Warren Prospect Areas (consisting of Lawrence, Mercer, Warren and Venango
Counties in Pennsylvania) as proposed by Atlas Resources, Inc.
AREA OF INVESTIGATION
A portion of this prospect area, herein identified as the Atlas America
Public #9 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> <C> <C>
Lackawannock Shenango Wilmington Wilmington
East Lackawannock Sandy Creek Delaware Hickory
</TABLE>
Thirty (30) drilling prospects designated for this program will be targeted
to produce natural gas from Clinton-Medina Group reservoirs, found at an
average depth range of approximately 5,100 to 6,300 feet beneath the earth's
surface. These are the only prospects evaluated for the purposes of this
report. Additional wells may be drilled to similar reservoirs in the
following Pennsylvania counties in the townships listed below:
<TABLE>
<CAPTION>
Crawford County Lawrence County Mercer County Warren County Venango County
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Greenfield Plain Grove Jefferson Southwest Oil Creek
Oil Creek Pulaski Deer Creek Triumph Cherrytree
Neshannock Eldred Cornplanter
Beaver Freehold
</TABLE>
METHODOLOGY
The data incorporated into this report was provided by Atlas Resources,
Inc. and the inhouse archives of UEDC, Inc. Geological mapping and the
interpretations by Atlas geologists were also examined. Available "electric"
log, completion, and production data on wells ofsetting prospect locations
and other "key" wells within and adjacent to the defined prospect area were
utilized to determine productive and depositional trends.
69
<PAGE>
PROSPECT AREA HISTORY
DRILLING ACTIVITY
The proposed drilling area lies within a region of northwestern
Pennsylvania which has been very active for the past decade in terms of
exploration for, and exploitation of natural gas reserves. Development within
and adjacent to the Southeastern Mercer Prospect Area has escalated since
1986, with Atlas Resources, Inc. and it's affiliates drilling over one
thousand fifty (1050) wells during this period. Atlas Resources, Inc. has
encountered favorable drilling and production results while solidifying a
strong acreage position, and continues to identify and extend productive
trends. Drilling is ongoing as of the date of this report with recent wells
displaying favorable initial drilling and completion results. Competitive
activity has begun 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:
70
<PAGE>
STRATIGRAPHIC NAMES-NW PENNSYLVANIA
[GRAPHIC]
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
encoutered 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.
71
<PAGE>
The GRIMSBY is the thickest sandstone member of the Clinton-Medina
Group. Sand development ranges from ten (10) to forty-five (45) feet within
an interval comprised of fine to very fine, light gray to red sandstones and
siltstones broken up by thin dark gray silty shale layers. Average porosity
values for the Grimsby are approximately six (6) to (10) percent over the pay
interval regionally. Permeability may be enhanced locally by the presence of
naturally occurring micro-fractures. Future development focuses on
established production trends.
The THOROLD sandstone is the uppermost producing interval of the
Clinton-Medina sequence. This interbedded ferric sand, silt and shale
interval averages forty (40) to seventy (70) feet, from west to east in the
prospect area. Where pay sand development occurs, porosities are in the
typical Clinton-Medina group range of six (6) to (10) percent. Permeability
may be enhanced locally by the presence of naturally occurring
micro-fractures.
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable
barrier trapping natural gas of commercial quantities in a more permeable
medium. In the Clinton-Medina, this occurs either stratigraphically when a
permeable sand containing hydrocarbons encounters an impermeable shale or
when a permeable sand changes gradually into a non-permeable sand by a
cementation process known as "diagenesis". Thus, this type of trap represents
cemented-in hydrocarbon accumulations.
Electric well logs can be used in conjunction with production to
interpret reservoir parameters. When sandstones in the Thorold, Grimsby,
Cabot Head or Whirlpool develop porosity in excess of 6%, or a bulk density
of 2.55 or less, the permeability of the reservoir (which ranges from less
than 0.1 to greater than 0.2 mD) can become great enough to allow commercial
production of natural gas. Small, naturally occurring cracks in the
formation, referred to as micro-fractures, can also enhance permeability. A
gamma, bulk density, density porosity and neutron log suite showing sand
development in the Grimsby, Cabot Head and Whirlpool is illustrated on the
following page.
72
<PAGE>
[GRAPH]
Two other phenomena detected by well logs can occur which are indicators of
enhanced permeability. These indicators used to detect productive intervals
are:
- MUDCAKE BUILDUP ACROSS THE ZONE OF INTEREST - after loading the wellbore
with brine fluid and circulating, an interval with enhanced permeability
will accept fluid, filtering out the solids and leaving behind a buildup (or
mudcake) on the formation wall. This is detectable with a caliper log.
- INVASION PROFILE - during circulation, a brine that has a high
conductivity (or low resistivity) that is accepted into the formation (as
described above) will change the electrical conductivity of the reservoir
rock near and around the wellbore. The resistivity will be low nearest to the
wellbore and will increase away from the wellbore. A dual laterolog can be
used to detect this profile created by a permeable zone - it records
resistivity near the wellbore as well as deeper into the formation. A zone
with enhanced permeability will show a separation between the shallow and
deep laterologs, while a zone with little or no permeability would cause the
two resistivity measurements to read exactly the same. An example follows:
73
<PAGE>
[GRAPH] [GRAPH]
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 percentage of gas recovery per year is illustrated
by the diagram below:
[GRAPH]
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.
74
<PAGE>
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasability study of the ATLAS AMERICA
PUBLIC #9 LTD. DRILLING PROGRAM, which will consist of developmental drilling
of the Clinton-Medina Group sands in Mercer, Lawrence, Warren and Venango
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 oficers
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/ Isaias Ortiz
UEDC, Inc.
75
<PAGE>
MAP OF WESTERN PENNSYLVANIA
AND
FAYETTE COUNTY
76
<PAGE>
[MAP OF WESTERN PENNSYLVANIA AND FAYETTE COUNTY]
77
<PAGE>
LEASE INFORMATION
78
<PAGE>
<TABLE>
<CAPTION>
EFFECTIVE EXPIRATION LANDOWNER ROYALTY
PROSPECT NAME COUNTY DATE* DATE*
------------------------------- --------------- --------------- ---------------- ------------------
<S> <C> <C> <C> <C> <C>
1. Grant #5 Fayette HBP 12.50%
2. Stiner #1 Fayette 01/21/2000 01/21/2003 12.50%
3. Keslar #4 Fayette HBP 12.50%
4. Check Unit #1 Fayette 04/15/2000 04/15/2005 12.50%
5. Bukovitz Tr. 5 #2 Fayette 08/30/1999 08/30/2002 12.50%
6. Lacava/USX #1 Fayette 03/15/1999 03/15/2001 12.50%
7. Stoken #1 Fayette HBP 12.50%
8. Bukovitz Tr. 4 #1 Fayette HBP 12.50%
9. Soberdash #1 Fayette 12/06/1999 12/12/2001 12.50%
10. Tiberi #1 Fayette 01/20/2000 01/20/2004 12.50%
11. Croushore #3 Fayette HBP 12.50%
12. Deaton #1 Fayette 02/25/2000 10/25/2001 12.50%
13. CFR/USX #3 Fayette 01/04/1999 01/04/2001 12.50%
14. S. Skovran #1 Fayette 05/18/1999 05/17/2004 12.50%
15. Bukovitz Tr. 1 #1 Fayette 08/30/1999 08/30/2002 12.50%
16. J. Riffle #1 Fayette HBP 12.50%
17. Fairbank Rod & Gun Fayette 01/31/2000 01/31/2005 12.50%
Club #1
18. Trosiek #1 Fayette 01/24/2000 01/24/2002 12.50%
19. Friend Unit #1 Fayette 04/15/2000 04/15/2005 12.50%
20. Dick #1 Fayette HBP 12.50%
<CAPTION>
OVERRIDING ROYALTY OVERRIDING
INTEREST TO THE ROYALTY ACRES TO BE
MANAGING GENERAL INTEREST TO NET REVENUE NET ACRES ASSIGNED TO
PROSPECT NAME PARTNER 3RD PARTIES INTEREST PARTNERSHIP
------------------------------- -------------------- ---------------- ---------------- ---------- ---------------
<S> <C> <C> <C> <C> <C> <C>
1. Grant #5 0% 0% 87.50% 156.00 20
2. Stiner #1 0% 0% 87.50% 27.30 20
3. Keslar #4 0% 0% 87.50% 223.00 20
4. Check Unit #1 0% 0% 87.50% 10.00 10
5. Bukovitz Tr. 5 #2 0% 0% 87.50% 62.60 20
6. Lacava/USX #1 0% 0% 87.50% 146.96 20
7. Stoken #1 0% 0% 87.50% 247.50 20
8. Bukovitz Tr. 4 #1 0% 0% 87.50% 106.72 20
9. Soberdash #1 0% 0% 87.50% 108.05 20
10. Tiberi #1 0% 0% 87.50% 9.00 9
11. Croushore #3 0% 0% 87.50% 163.86 20
12. Deaton #1 0% 0% 87.50% 32.60 20
13. CFR/USX #3 0% 0% 87.50% 245.00 20
14. S. Skovran #1 0% 0% 87.50% 105.00 20
15. Bukovitz Tr. 1 #1 0% 0% 87.50% 90.34 20
16. J. Riffle #1 0% 0% 87.50% 37.50 20
17. Fairbank Rod & Gun 0% 0% 87.50% 240.26 20
Club #1
18. Trosiek #1 0% 0% 87.50% 12.77 12.77
19. Friend Unit #1 0% 0% 87.50% 25.50 20
20. Dick #1 0% 0% 87.50% 20.00 20
</TABLE>
-----------------------
*HBP - Held by Production
79
<PAGE>
LOCATION AND PRODUCTION MAP
80
<PAGE>
[MAP OF FAYETTE COUNTY AREA]
81
<PAGE>
PRODUCTION DATA
82
<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
* DEPTH PROD.
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
10 Manufacturers Light & Heat Co Hogsett #9 10/21/47 N/A N/A N/A N/A
29 Carnegie Natural Gas Co H.C.Frick (Buffington) #1 09/07/44 N/A 101,000/1959 3700 N/A
30 Manufacturers Light & Heat Co Sangston #1 N/A N/A N/A 2391 N/A
41 Greensboro Gas Co Hogsett #2 01/01/22 N/A N/A 1968 N/A
50 Keystone Gas Co Mercer #1 11/07/58 N/A N/A 2180 N/A
56 Manufacturers Light & Heat Co Brown #1 05/21/45 N/A N/A 2608 N/A
57 Carnegie Natural Gas Co H.C.Frick Coke(Ralph)#2 02/05/45 N/A 105,000/1963 2595 N/A
58 Carnegie Natural Gas Co H.C.Frick Coke(Ralph)#1 07/22/44 228 86,000/1963 N/A N/A
62 Manufacturers Light & Heat Co Puritan Coke Co 08/15/45 N/A N/A 1615 N/A
63 Manufacturers Light & Heat Co Hogsett #6 02/17/45 N/A N/A 2793 N/A
66 Manufacturers Light & Heat Co Hogsett #8 05/26/47 N/A N/A 2475 N/A
71 Peoples Natural Gas Co DiCarlo #1 N/A N/A N/A 1975 N/A
73 Manufacturers Light & Heat Co S.Fayette C.&C.Co N/A N/A N/A 2655 N/A
78 Orville Eberly Herrington #1 05/12/45 N/A N/A 3494 N/A
79 Orville Eberly Old Home Fuel #1 10/29/47 N/A N/A 3451 N/A
84 Greensboro Gas Co Hogsett #5 08/30/44 N/A N/A 2128 N/A
85 Peoples Natural Gas Co Vail #2 06/20/46 N/A 171,000/1974 2790 N/A
87 Wahler & Powers Tomasek #1 03/05/48 N/A N/A 2295 N/A
88 Manufacturers Light & Heat Co Coffman #1 N/A N/A N/A 1390 N/A
107 Orville Eberly Puritan Coke Co 10/21/46 N/A N/A 2545 N/A
118 Peoples Natural Gas Co Kovach #1 12/07/43 N/A 263,000/1992 3162 N/A
119 W.Burkland Natale #1 06/19/44 N/A 267,000/1992 3101 N/A
122 Equitable Gas Co H.C. Frick (Buffington) #2 02/02/45 N/A 337,000/1995 3041 N/A
123 Carnegie Natural Gas Co H.C.Frick Coke(Footedale)#1 10/01/45 N/A 192,000/1995 3265 N/A
146 Castle Gas Co Springer #1 09/24/40 N/A 142,000/1990 2570 N/A
149 Castle Gas Co Coffman #2 10/01/24 N/A 573,000/1990 2490 N/A
165 N/A N/A N/A N/A 324,000/1990 2700 N/A
167 N/A N/A N/A N/A N/A 2382 N/A
168 Castle Gas Co T.Rider #1 01/01/42 N/A 477,000/1990 2579 N/A
184 Castle Gas Co Jacobs #5 10/01/43 N/A 93,000/1990 3024 N/A
197 W.Burkland F. Horak #1 05/29/46 N/A N/A 2394 N/A
200 W.Burkland Leslie #1 06/10/41 N/A N/A 1367 N/A
</TABLE>
83
<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
* DEPTH PROD.
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
201 N/A N/A N/A N/A N/A 4353 N/A
202 N/A N/A N/A N/A N/A N/A N/A
205 W.Burkland Tomasek #1 01/07/39 N/A N/A 1361 N/A
220 W.Burkland Hibbs #1 07/01/40 N/A N/A 1299 N/A
224 W.Burkland Weirton Coal Co #1 07/25/45 N/A N/A 1906 N/A
225 W.Burkland Heller Coal Co #1 09/26/58 N/A N/A 1892 N/A
232 W.Burkland Gray #1 02/10/40 N/A N/A 2405 N/A
20059 M.C.Brumage DiCarlo #2 12/29/67 N/A N/A 3093 N/A
20102 Peoples Natural Gas Co Parshall #2 06/18/46 N/A 92,000/1969 2793 N/A
20103 Peoples Natural Gas Co J.A. Coffman #1 02/12/47 N/A 160,000/1970 N/A N/A
20114 Orville Eberly Sharpnack #1 04/10/45 N/A N/A 3300 N/A
20130 Keystone Gas Co Hecla #2 04/12/73 N/A N/A 3156 N/A
20134 Orville Eberly Puritan Coke Co #1 06/28/44 N/A N/A 2540 N/A
20136 Peoples Natural Gas Co Sisler #1(now Mcgill) 09/24/73 N/A N/A 3504 N/A
20138 Peoples Natural Gas Co Gray #1 (now Keslar) 09/10/73 N/A N/A 4513 N/A
20145 Orville Eberly Kalonsky #1 06/14/41 N/A N/A 2395 N/A
20181 W.Burkland Parshall #1 05/14/45 N/A 139,000/1980 2784 N/A
20185 W.Burkland Kalonsky #1 11/04/77 N/A N/A 4086 N/A
20192 W.Burkland Sharpnack #1 04/24/78 N/A N/A 4290 N/A
20226 Orville Eberly Puritan Coke Co #2 08/01/46 N/A N/A 2533 N/A
20249 W.Burkland Hanigosky #1 08/18/41 N/A N/A 2611 N/A
20263 Greensboro Gas Co Hicks #1 03/27/40 N/A N/A 2645 N/A
20272 Peoples Natural Gas Co Kovach #3 12/17/80 N/A N/A 3347 N/A
20290 Orville Eberly S. Wycinsky #1 11/20/81 N/A 199,000/1986 3250 N/A
20330 W.Burkland Valerio #1 03/22/41 N/A N/A 2502 N/A
20347 Peoples Natural Gas Co J. Magerko #1 07/13/44 N/A 149,000/1977 3709 N/A
20371 W.Burkland Ludi #2 08/27/83 N/A N/A 5789 N/A
20372 W.Burkland LaCava #1 09/07/83 N/A N/A 5665 N/A
20377 W.Burkland Lyons #2 01/01/83 N/A N/A 5300 N/A
20434 W.Burkland Staso #1 06/19/47 N/A 139,000/1994 2794 N/A
20723 Kriebel Gas Inc Kovach #1 03/23/94 N/A N/A 4450 N/A
20742 Kriebel Gas Inc Fairbank Rod & Gun #1 11/05/96 N/A N/A 3895 N/A
</TABLE>
84
<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
* DEPTH PROD.
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
20888 Atlas Leichliter/Savage #1A 01/10/97 28 46,400 4112 1,168
20890 Atlas New Salem Vol Fire Co #1 01/17/97 28 35,671 3980 754
20892 Atlas Zalac #1 11/05/97 26 24,534 4229 368
20900 Atlas McGill #2 02/16/97 28 35,145 5576 823
20903 Atlas McGill #3A 10/28/97 26 43,165 4265 894
20950 Atlas Leichliter #2 10/07/98 14 51,487 3856 3,264
20951 Atlas Zalac #3 11/23/97 26 16,438 4448 341
20954 Atlas Leichliter 1A 10/17/98 14 13,963 3184 487
20955 Atlas Zalac #2 12/06/97 26 26,647 4412 532
20958 Atlas Lambert/USX #1 12/16/97 25 28,479 4492 671
20961 Atlas Prah #1 12/30/97 24 17,715 4590 448
20962 Atlas Lavery #1 01/13/98 25 22,006 4476 231
20963 Atlas Wycinsky #1 01/21/98 25 12,291 4270 383
20971 Atlas Swetz/Densmore #1 01/28/98 23 3,611 6010 118
20979 W.Burkland Kalonsky #2 N/A N/A N/A N/A N/A
20991 Atlas DiCarlo #1 03/12/98 21 9,219 4439 241
20992 Atlas Fette/Davis/Sunyak #1 03/30/98 21 34,824 6015 1,116
20999 Atlas Skiles #1A 03/18/99 10 10,846 4164 745
21000 Atlas Edenborn/USX #1 01/13/99 11 12,555 3071 450
21001 Atlas K.Kovach #1 01/02/99 11 28,742 3951 2,013
21004 Atlas Winter #1 01/29/99 13 1,365 4110 141
21010 Atlas Tippet #1 01/20/99 11 30,155 3805 2,982
21021 Atlas Croushore #1 02/10/99 9 13,627 4009 1,175
21029 Atlas Christopher #1 10/25/98 14 3,821 4228 193
21030 Atlas Pollick #1 11/19/98 13 9,228 3450 471
21037 Atlas Lindsey #1 11/04/98 13 15,242 4227 487
21040 Atlas Howe #1 02/08/99 12 23,563 3643 2,658
21061 Atlas Jarina Unit #1 02/25/99 11 1,365 3650 129
21066 W.Burkland Parshall #1 N/A N/A N/A N/A N/A
21068 Atlas Skovran #1 02/15/99 11 44,119 4098 4,882
21069 Atlas Pike #1 02/19/99 10 961 3623 63
21073 W.Burkland Miles #1 N/A N/A N/A N/A N/A
85
<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.
<CAPTION>
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
* DEPTH PROD.
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
21074 Atlas E.Riffle #1 03/02/99 11 8,680 4060 442
21076 Atlas East Huntingdon #1 03/27/99 10 3,864 3866 243
21077 W.Burkland D'Amico #1 N/A N/A N/A 2500 N/A
21079 Atlas Craig #1 03/26/99 11 5,418 4015 656
21080 Atlas Bowers/Hogsett #2 02/24/99 10 8,238 3528 804
21083 Atlas K.Kovach #3 04/21/99 9 18,063 3979 1,656
21084 Atlas Leichliter #3 04/08/99 10 7,522 3839 512
21085 Atlas Filbert/USX #1 03/19/99 8 11,994 3927 1,215
21099 W.Burkland D'Amico #2 11/10/99 N/A N/A 2480 N/A
21104 Atlas Check #1 01/21/00 3 10,703 3888 4381
21105 Atlas K.Kovach #2A 02/03/00 3 9,387 4068 3648
21107 Atlas McGill #1 12/08/99 3 4,816 4052 1,478
21109 Atlas Pollick #2 02/11/00 2.75 3,211 3788 1,723
21110 Atlas Lee/Fette-Gipson #1 02/02/00 3 2,293 3933 706
21111 Atlas Skovran #3 12/18/99 3 41,043 4168 17,234
21112 Atlas Skovran #4 01/07/00 3 2,025 4187 635
21113 Atlas Visnich #1 01/19/00 3 15,090 3968 6011
21116 Atlas Johnston/Densmore #1 03/25/00 2.25 4,615 4270 2606
21118 Atlas Grant #1 01/14/00 3 35,438 3870 13990
21122 Atlas Bukovitz Tr-3 #1 01/28/00 3 8,393 3658 3031
21123 W.Burkland W.S. Burkland #1 N/A N/A N/A N/A N/A
21126 Atlas Edenborn/USX #2 02/09/00 2.75 290 3849 135
21127 Atlas Fette/Davis/Sunyak #2 01/27/00 2.5 2,349 3980 1014
21128 Atlas Bukovitz Tr-2 #1 02/18/00 2.5 1,788 3753 730
21130 Atlas Koenig #1 02/28/00 3 2,510 2070 128
21131 Atlas Winter #2 02/25/00 3 3,256 4082 1120
21133 Atlas P.Antram #1 02/18/00 3 2,187 4203 556
21135 Atlas Skovran #2 03/02/00 2.75 294 4062 102
21138 Atlas Keslar #1 03/08/00 3 18,750 4085 7699
21140 Atlas Skovran #5 03/13/00 2.75 1,950 4067 778
21143 Atlas Craig #2 03/19/00 N/A N/A 4090 N/A
21147 Atlas Krepps #1 04/01/00 2.25 2,518 4210 1,415
86
<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.
<CAPTION>
ID DATE MOS TOTAL TOTAL LATEST
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY
* DEPTH PROD.
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
90012 Manufacturers Light & Heat Co Hartley #1 12/31/46 N/A N/A 3237 N/A
90020 Duquesne Natural Gas Co J. Race #1 08/14/42 N/A N/A 3419 N/A
90035 Greensboro Gas Co Hanigosky #1 04/10/41 N/A N/A 2623 N/A
90036 Greensboro Gas Co Jefferis #1 06/21/43 N/A N/A 2599 N/A
90059 Greensboro Gas Co Hogsett #4 10/23/23 N/A N/A 3045 N/A
90066 Greensboro Gas Co Hogsett #1 01/01/11 N/A N/A 3117 N/A
90068 Greensboro Gas Co Christopher #1 01/15/15 N/A N/A 3100 N/A
90069 Greensboro Gas Co Christopher #2 02/13/17 N/A N/A 3065 N/A
90078 Greensboro Gas Co Jacobs #2 08/03/16 N/A N/A 1766 N/A
90100 Greensboro Gas Co Jacobs #4 05/23/17 N/A N/A 2751 N/A
90101 Greensboro Gas Co Christopher #3 02/03/23 N/A N/A 3206 N/A
90102 Greensboro Gas Co Hartley #1 02/07/24 N/A N/A 3210 N/A
90103 Greensboro Gas Co Riffle #1 01/18/24 N/A N/A 3035 N/A
90107 Greensboro Gas Co E.Christopher #1 01/01/16 N/A N/A 2864 N/A
90108 Greensboro Gas Co Brown #1 N/A N/A N/A 3273 N/A
F22290 N/A Riffle #1 N/A N/A N/A N/A N/A
F30027 N/A Riffle #1 N/A N/A N/A N/A N/A
G675 Greensboro Gas Co M. Fleming #1 N/A N/A N/A 2410 N/A
GRE1397 Castle Gas Co J. Kerr #1 10/22/18 N/A 337,000/1990 2400 N/A
GRE22490 R.Burkland Luzerne #4 03/26/93 N/A N/A 2439 N/A
L2373 Manufacturers Light & Heat Co H.G. Moore(Skovran) #1 06/18/19 N/A N/A 2005 N/A
P17181 N/A N/A N/A N/A N/A N/A N/A
P21257 C.D.White & Co Pollick #1 04/07/39 N/A N/A 2530 N/A
P21283 Wahler & Powers Hicks #1 N/A N/A N/A N/A N/A
P21286 Wahler & Powers Reynolds #1 N/A N/A N/A 3345 N/A
P21341 Adrian et al Whitlock #1 N/A N/A N/A 1353 N/A
P21706 Wahler & Powers Risko #1 N/A N/A N/A 2412 N/A
P21747 N/A Lilley #1 N/A N/A N/A N/A N/A
P21971 Bortz et al Hicks #1 N/A N/A N/A 2267 N/A
P22120 Wahler & Powers Gray #2 N/A N/A N/A N/A N/A
P22152 Geo Reynolds Reynolds #2 N/A N/A N/A 1370 N/A
P22271 Jack Cornell Kosky #1 10/05/40 N/A N/A 2560 N/A
</TABLE>
87
<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
* DEPTH PROD.
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
P22272 Wahler & Powers Reynolds #3 N/A N/A N/A 2443 N/A
P22359 Fayette County Gas Co Puritan Coke Co #2 N/A N/A N/A N/A N/A
P22772 Bortz et al Pollick #2 N/A N/A N/A 2548 N/A
P22938 Fayette County Gas Co A. Coffman #1 05/01/24 N/A N/A 2544 N/A
P22969 Wahler & Powers Hibbs #2 N/A N/A N/A 2302 N/A
P23664 Fayette County Gas Co Marciniak #1 N/A N/A N/A 2410 N/A
P23900 Greensboro Gas Co Van Breman #1 N/A N/A N/A 2567 N/A
P23901 Greensboro Gas Co Montgomery #1 N/A N/A N/A 2462 N/A
P24149 Bortz et al Jefferies #1 N/A N/A N/A 2652 N/A
P24150 Bachman & Rudert Vail #1 05/11/29 N/A N/A 2740 N/A
P24154 Puritan Coal & Coke Wolf #1 N/A N/A N/A N/A N/A
P24155 Fayette County Gas Co J. Hoover #1 N/A N/A N/A N/A N/A
P24172 M.C.Brumage Riffle #1 N/A N/A N/A 2400 N/A
P24173 M.C.Brumage Hartley #1 N/A N/A N/A N/A N/A
P24174 M.C.Brumage Cameron #1 N/A N/A N/A N/A N/A
P24175 N/A Thompson #1 N/A N/A N/A 2907 N/A
P24464 M.C.Brumage Hartley #1 N/A N/A N/A N/A N/A
P24828 Kirk Brumage LaCava #1 N/A N/A N/A 1900 N/A
P25709 Bortz C.Snell #1 05/22/43 N/A N/A 2370 N/A
P26065 Moore Palko #1 12/17/43 N/A N/A 2363 N/A
P26092 H.K.Porter Hartley #1 01/06/44 N/A N/A N/A N/A
P26456 H.K.Porter Hartley #1 04/12/44 N/A N/A 2055 N/A
P26505 Orville Eberly Ross #1 05/02/44 N/A 56,000/1972 3240 N/A
P26862 H.K.Porter Hecla #1 01/22/94 N/A N/A 3076 N/A
P26874 J.D.Boyle Hoover #1 01/09/45 N/A N/A 1525 N/A
P27813 R. Murray et al Hibbs #2 09/04/46 N/A N/A N/A N/A
P27631 T.Blayho Hoover #1 04/26/46 N/A N/A 2400 N/A
P27648 R.Murray et al Hibbs #1 05/19/46 N/A N/A 1913 N/A
P27764 Petroleum Drilling Co Baird #1 10/11/46 N/A N/A 3195 N/A
P27978 T.Blayho Noble #1 01/27/47 N/A N/A 2420 N/A
P28257 Flack & Bungard Palko #1 06/12/47 N/A N/A 2408 N/A
P28302 Brown Higbee E. Wendella #1 06/24/47 N/A N/A 2415 N/A
</TABLE>
88
<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
* DEPTH PROD.
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
P28303 Wahler & Powers Hicks #2 06/16/47 N/A N/A 2600 N/A
P28368 Henry Johns M. Kobilack #1 09/02/47 N/A N/A 2402 N/A
P28401 L.V. Simmer G.Kaufman #1 09/04/47 N/A N/A 2600 N/A
P28757 Wahler & Powers Tomasek #2 03/08/48 N/A N/A 2350 N/A
P28780 Wahler & Powers Tomasek #3 05/19/48 N/A N/A 2390 N/A
P29132 Cunarro C. Mitchell #1 N/A N/A N/A N/A N/A
P29233 Manufacturers Light & Heat Co Gray #1 07/23/23 N/A N/A 2605 N/A
P29479 N/A C. Jones #1 N/A N/A N/A N/A N/A
PNG3359 Peoples Natural Gas Co D.H. Sangston #1 10/26/42 N/A 53,000/1952 3814 N/A
PNG3394 Peoples Natural Gas Co Parshall #1 05/05/43 N/A N/A 3551 N/A
PNG3473 Peoples Natural Gas Co Byers #1 01/01/44 N/A N/A N/A N/A
PNG3490 Peoples Natural Gas Co Stoken #1 01/01/44 N/A N/A N/A N/A
PNG3664 Peoples Natural Gas Co McCann #1 10/28/46 N/A N/A N/A N/A
PNG3491 Peoples Natural Gas Co Kovach #1 04/23/45 N/A N/A 3750 N/A
PNG3671 Peoples Natural Gas Co Podolinski #1 09/27/46 N/A N/A N/A N/A
PNG3672 Peoples Natural Gas Co H.Hogsett #3 12/10/46 N/A N/A 3212 N/A
PNG3683 Peoples Natural Gas Co Parshall #3 02/12/47 N/A N/A 2546 N/A
PNG3705 Peoples Natural Gas Co Jefferies #1 07/21/47 N/A N/A 2831 N/A
PNG3724 Peoples Natural Gas Co H.Hogsett #4 08/14/47 N/A N/A 3327 N/A
PNG3774 Peoples Natural Gas Co Springer #1 04/20/48 N/A N/A N/A N/A
</TABLE>
* Cumulative production through 6/2000 unless noted; ie 1952 for PNG3359)
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MANAGING GENERAL PARTNER'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
FAYETTE COUNTY, PENNSYLVANIA
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OBJECTIVE
The purpose of the following investigation is to evaluate the
geologic feasibility and further development of the Fayette Prospect Area as
proposed by Atlas Resources, Inc.
AREA OF INVESTIGATION
A portion of this prospect area contains acreage in German, Luzerne,
Redstone and Menallen Townships in Fayette County. Fayette County is located
in Pennsylvania. Twenty (20) drilling prospects have currently been
designated for this program and will be targeted to produce natural gas from
Mississippian and Upper Devonian reservoirs, found at depths from 1900 feet
to 4500 feet beneath the earth's surface.
METHODOLOGY
The data incorporated into this report were provided by Atlas
Resources, Inc. Geological mapping and the interpretations by Atlas
geologists were also examined. Available "electric" log, completion and
production data on wells offsetting prospect locations and other "key" wells
within and adjacent to the defined prospect area were utilized to determine
productive and depositional trends.
FAYETTE PROSPECT AREA
DRILLING ACTIVITY
The proposed drilling area lies within a region of southwestern
Pennsylvania, which has been active for the past four years in terms of
exploration for, and exploitation of natural gas reserves. Development within
and adjacent to the Fayette Prospect Area has continued steadily since 1996.
Over sixty (60) wells have been drilled in the area during this period. Atlas
Resources, Inc. has encountered favorable drilling and production results
while solidifying a strong acreage position of over 13,000 acres, as Atlas
Resources, Inc. continues to identify and extend productive trends. Drilling
is ongoing as of the date of this report with recent wells displaying
favorable initial drilling and completion results.
The area of proposed drilling is situated in a portion of Fayette
County that has had established production from shallower, historic pay
zones. Atlas Resources, Inc. will target deeper pay zones when locating a
drill site within the "old shallow field area". Otherwise, Atlas Resources,
Inc. will maintain a minimum of 1000 feet from any existing producing well in
the area.
GEOLOGY
STRATIGRAPHY, LITHOLOGY & DEPOSITION
The Mississippian reservoirs currently producing in the Fayette
Prospect Area are the Burgoon Sandstone (lower Big Injun) and the 2nd Gas
Sand. The Burgoon Sandstone is part of the massive Big Injun fluvial-deltaic
sand system, which extends from eastern Kentucky through West Virginia into
southwestern Pennsylvania. This reservoir is an historic prolific producing
zone in this region, with some wells still producing long beyond fifty years.
There is not much history of production from the 2nd Gas Sand in this area.
The Upper Devonian reservoirs consist of three groups of sands,
Upper Venango, Lower Venango and Bradford. Each of these "Groups" has
multiple reservoirs making up their total rock section. The Upper Venango
Group consists of the Gantz Sand and the Fiftyfoot Sand. The Lower Venango
Group
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consists of the Fifth Sand and the Bayard Sand. Depositional environments of
these Upper and lower Venango Group sands are of near shore to offshore
marine settings related to the last major advance of the Catskill Delta. The
Bradford Group consists of the Lower Warren Sand, Upper Speechley Sand, Lower
Speechley Sand, Upper Balltown Sand and the First Bradford Sand. Depositional
environments of these sands are offshore marine, pro-delta and basin floor
settings related to the intermediate advance of the Catskill Delta.
Stratigraphically, in descending order, the potentially productive
units of the Mississippian and Upper Devonian Groups are: 1) Burgoon, 2) 2nd
Gas Sand, 3) Gantz, 4) Fiftyfoot, 5) Fifth, 6) Bayard, 7) L.Warren, 8)
U.Speechley, 9) L.Speechley, 10) U.Balltown and 11) First Bradford Sand.
These stratigraphic relationships are illustrated in the following diagram.
STRATIGRAPHIC NAMES-FAYETTE COUNTY AREA
[CHART]
The BURGOON SANDSTONE is a fine to medium grained, medium to
massively bedded, light-gray sandstone ranging in thickness from 200-250
feet. Average porosity values for this sand range from 6% to 12% regionally.
It is not uncommon to encounter porosities as high as 20% and attendant large
natural open flows from this sand. Tracking these high flow trends is
targeted for further development. Also, this zone does produce water in
certain locales within the Fayette Prospect Area. This reservoir is
considered a secondary target in the high flow trend areas.
The 2ND GAS SAND of this region has limited areal extent and
therefore is not discussed in the literature regarding lithology, thickness
etc. It can be inferred from underlying and overlying sands that it is
probably a fine to very fine grained, light gray sand. Subsurface mapping
indicates that the sand can achieve a thickness of twenty (20) feet. Average
porosity values for this sand range from 10% to 13%
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<PAGE>
when this zone is present in the area. Peak porosities of 17% have been
encountered within the prospect area. This reservoir is considered to be a
secondary target when encountered.
The GANTZ SAND is a white to light-gray, medium to coarse grained
sandstone ranging in thickness from a few feet to over thirty (30) feet.
Average porosity values for this sand range from 5% to 10% regionally. Within
the area of investigation, porosities in excess of 13% occur within localized
trends characterized by large natural open flows. These trends are targeted
for future development. This reservoir is considered a primary target in the
high flow trend areas.
The FIFTYFOOT SAND is a white to light gray, thinly bedded, fine
grained sandstone ranging in thickness from ten (10) to thirty (30) feet.
Average porosity values for this sand range from 5% to 8% regionally. Within
the prospect area, porosities in excess of 12% occur within localized trends
targeted for future development. This sand reservoir is considered a secondary
target.
The FIFTH SAND is a white to light gray, very fine to fine grained
sandstone ranging in thickness from a few feet to twenty (20) feet. Within
the main Fifth fairway, porosity values average from 9% to 15%. This sand is
considered a primary target and will be exploited in future development.
The BAYARD SAND in the prospect area ranges in thickness from a few
feet to more than sixty (60) feet. Average porosity values range from 5% to
12% for this fine to coarse grained sandstone. Discreet reservoirs within the
sand have been identified and mapped. Gas shows in the member sandstones
delineate trends within the prospect area and will be targeted for future
development. This sand is considered a primary target.
The LOWER WARREN SAND is a primary target in the prospect area.
Average thickness for this sand ranges from zero (0) feet to over forty (40)
feet. Porosities average between 8% and 12% in the area. Gas shows are
commonly found in this sand, which is probably a fine-grained, well-sorted
sand. This reservoir is targeted for future development.
The UPPER SPEECHLEY SAND is considered a secondary target with
average thickness ranging from two (2) feet to ten (10) feet over much of the
prospect area. Gas shows from this sand are common throughout the area and
the zone is combined with other zones when treated.
The LOWER SPEECHLEY SAND is a primary target in the area with
reservoir thickness ranging from zero (0) to over forty (40) feet. Average
porosity values range from 5% to 12% where the sand is present. Significant
natural and after treatment flows from this sand have been encountered. This
sand is being targeted throughout the prospect area.
The UPPER BALLTOWN SAND is currently being produced in a few wells
in the prospect area. The zone is a siltstone with fracture-enhanced
porosity, based on log interpretation, and has associated gas shows. This
sand is considered a secondary target and is usually combined with other
zones when treated.
The FIRST BRADFORD SAND, like the Balltown above, is currently being
produced in a few wells in the prospect area. This silty-sand does have
porosity up to 10% in the area and is considered to be a secondary target
when encountered.
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable
barrier trapping natural gas of commercial quantities in a more permeable
medium. In the Mississippian and Upper Devonian reservoirs, this occurs
either stratigraphically when a permeable sand containing hydrocarbons
encounters impermeable shale or when permeable sand changes gradually into
non-permeable sand by a cementation
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<PAGE>
process known as "diagenesis". Thus, this type of trap represents cemented-in
hydrocarbon accumulations.
Electric well logs can be used in conjunction with production to
interpret reservoir parameters. When sandstones in the Mississippian and
Upper Devonian reservoirs develop porosity in excess of 8%, or a bulk density
of 2.50 or less, the permeability of the reservoir can become great enough to
allow commercial production of natural gas. Small, naturally occurring cracks
in the formation, referred to as micro-fractures, can also enhance
permeability. A gamma, bulk density, neutron, induction and temperature log
suite showing sand development in both the Mississippian and Upper Devonian
reservoirs is illustrated below.
[GRAPH]
temp log arching to the left = gas (natural production)
The temperature log shown in the illustration identifies where gas
is entering the wellbore. Evidence of a temperature "kick" or cooling is also
an indication of enhanced permeability and the willingness of the reservoir
to produce gas.
PRODUCTION EXPECTATIONS
The prospect area produces from a number of reservoirs of different
age and type. Each well has a unique combination of these reservoirs yielding
different production declines. While we anticipate production from each
reservoir to be comparable to like reservoirs historically produced
throughout the Appalachian Basin, a model decline curve for this prospect
area is not included due to the multiple sets of commingled reservoirs
exclusively found in this area. We expect producing life of the proposed
wells to range from twenty to forty years, which is similar to Atlas'
existing wells in the area. This average projected producing life is taken
directly from the 1999 audited report of Wright & Company, Inc.
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<PAGE>
POTENTIAL MARKETS AND PIPELINES
In the area of the drilling program, Atlas Resources, Inc. will be
transporting all the gas through Texas Eastern Transmission Co. and marketing
all the gas through Northeast Ohio Gas Marketing Co.
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<PAGE>
COMPETITION, MARKETS AND REGULATION
COMPETITION AND MARKETS
There are many companies engaged in oil and 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 oil and 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.
Oil and gas produced by the partnership's wells must be marketed in order for
you to realize revenues. In recent years oil and gas prices have been
volatile. Reduced oil and gas demand and/or excess oil and gas supplies will
result in lower prices. The marketing of oil and gas production 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 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, and
the North American Free Trade Agreement ("NAFTA") eliminated 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 decreasing, 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 oil and gas sold from the partnership's wells.
The accelerating deregulation of electricity transmission has caused, and
will continue to cause, a coming together of the natural gas and electric
industries. Because of increased competition in the electric industry, and
the enforcement of stringent environmental regulations, the electric industry
increased its reliance on natural gas and this demand is expected to increase
through the next decade.
FERC also 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.
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
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<PAGE>
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.
From time to time a portion of the partnership's gas may be sold to local
distribution companies. While in the past these purchases were generally made
on the spot market, FERC Order No. 636 has made long-term market-based gas
supply arrangements more important for local distribution companies than they
were previously. Although the spot market is still used, it is less important
as a market-based supply source and many local distribution companies are
directly buying their own gas reserves in an attempt to minimize their risks
and 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 completion of natural gas sales. 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 the following:
- supply;
- demand;
- 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
Governmental agencies regulate the production and transportation of natural
gas. Generally, the state regulatory agency where a producing natural gas
well is located supervises production activities and the transportation of
natural gas sold into intrastate markets and FERC regulates the interstate
transportation of natural gas.
Gas prices are not regulated. The price of gas is subject to the following:
- supply;
- demand;
- BTU content;
- pressure;
- location of the wells; and
- other factors.
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<PAGE>
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;
- certain well site restoration, groundwater protection and
safety measures;
- landowner notification requirements;
- certain bonding or other security measures;
- various reporting requirements; and
- well plugging standards and procedures.
These state regulatory agencies also have broad regulatory and enforcement
powers including those associated with pollution and environmental control
laws which may create additional financial and operational burdens on oil and
gas operations like those of the partnership.
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
- hazardous substance contamination under the Comprehensive
Environmental Response, Compensation and Liability Act of
1980, the Superfund.
There is unlimited liability for willful negligence or misconduct and
environmental cleanup costs or damages. 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
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<PAGE>
governmental or citizen prosecution. Compliance with these statutes and
regulations may cause delays or increase the cost of producing the oil and
gas. 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 gas industry. The proposals
involve, among other things:
- limiting the disposal of waste water from wells which could
make the partnership's wells uneconomical to produce; and
- changes in the tax laws.
However, it is impossible to accurately predict what proposals, if any, will
be enacted and their subsequent effect on the partnership's activities.
PARTICIPATION IN COSTS AND REVENUES
IN GENERAL
The partnership agreement provides for the sharing of costs and revenues
among the managing general partner and you and the other investors. A tabular
summary of the following discussion appears below.
COSTS
1. ORGANIZATION COSTS. Organization costs will be charged 100% to the
managing general partner. However, the managing general partner will not
receive any credit towards its required capital contribution for any
organization costs that it pays in excess of 4.5% of investors'
subscriptions.
- Organization costs generally means all costs of organizing
the offering, but excludes sales commissions and other
compensation to the dealer-manager and the broker-dealers.
2. DEALER-MANAGER FEE, SALES COMMISSIONS, REIMBURSEMENT OF MARKETING
EXPENSES, AND REIMBURSEMENT FOR BONA FIDE ACCOUNTABLE DUE DILIGENCE
EXPENSES. The dealer-manager fee, sales commissions, and reimbursement for
bona fide accountable due diligence expenses will be charged 100% to you
and the other investors. The reimbursement of marketing expenses will be
charged 100% to the managing general partner.
3. 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; or
- fair market value if the managing general partner has reason
to believe that cost is materially more than fair market
value.
4. INTANGIBLE DRILLING COSTS. Intangible drilling costs will be allocated and
charged 100% to you and the other investors.
- 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 equipment costs which must be
recovered through depreciation deductions.
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<PAGE>
Although subscription proceeds may be used to pay the costs of drilling
different wells depending on when the subscriptions are received, you and the
other investors will pay the same amount of the costs regardless of when you
subscribe. Also, the IRS could challenge the characterization of a portion of
these costs as deductible intangible drilling costs and recharacterize the
costs as some other item which may be non-deductible however, this would have
no effect on the allocation and payment of the costs under the partnership
agreement.
5. EQUIPMENT COSTS. Equipment costs will be allocated and charged 100% to the
managing general partner.
- Equipment costs generally means the costs of drilling and
completing a well that are not currently deductible and are
not lease costs.
6. 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.
7. 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 25% 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, 2001.
REVENUES
The revenues from all partnership wells will be commingled. Thus, 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.
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 to the subscription 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.
3. EQUIPMENT PROCEEDS. Proceeds from the sale or other disposition of
equipment will be credited to the parties charged with the costs of the
equipment in the ratio in which the costs were charged.
4. PRODUCTION REVENUES. Subject to the managing general partner's
subordination obligation as described below, all other revenues of the
partnership, including production revenues, will be credited as follows:
- before net of tax savings payout and partnership payout you
and the other investors and the managing general partner will
share in partnership revenues in the same percentage as your
respective capital contribution bears to the total partnership
capital contributions. For example, if the managing general
partner contributes 25% of the total partnership capital
contributions and you and the other investors contribute
75% of the total
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<PAGE>
partnership capital contributions, then the managing general
partner will receive 25% of the partnership revenues and you
and the other investors will receive 75% of the partnership
revenues.
- After net of tax savings payout the managing general partner
will receive an additional 6.5% of the partnership revenues,
and after partnership payout the managing general partner
will receive an additional 8.5% of partnership revenues for
a total additional amount of 15% of partnership revenues. In
the above example, after net of tax savings payout but before
partnership payout the managing general partner would receive
31.5% of the partnership revenues and you and the other
investors would receive 68.5% of the partnership revenues.
After partnership payout the managing general partner would
then receive 40% of the partnership revenues and you and the
other investors would receive 60% of the partnership revenues.
- Net of tax savings payout generally means the time
when the cumulative credit equivalent of the
partnership's deductions for intangible drilling
costs and percentage depletion on your share of the
partnership's income, plus the cumulative cash
distributed to you and the other participants, equals
100% of the participants' aggregate capital
contributions.
- Partnership payout generally means the time when the
partnership's cumulative cash distributions to you
and the other investors equals 100% of the investors'
aggregate capital contributions.
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 50% of its share of 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 generally means the
partnership's gross revenues after deducting the related
operating costs, direct costs, administrative costs and all
other 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 oil and 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 oil and gas volumes or
oil and gas prices decrease, then even with subordination your cash flow may
be very small and you may not receive a return of your investment. As of
March 1, 2000, the managing general partner was subordinating a portion or
all of its net revenues in 11 of its previous 15 limited partnerships which
currently have the subordination feature in effect, and from time to time it
has subordinated its partnership revenues in all of these partnerships.
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.
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<TABLE>
<CAPTION>
MANAGING
GENERAL
PARTNER INVESTORS
------- ---------
<S> <C> <C>
PARTNERSHIP COSTS
Organization costs..................................................................100% 0%
Dealer-manager fee, sales commissions, and reimbursement for
bona fide accountable due diligence expenses.....................................0% 100%
Reimbursement of marketing expenses.................................................100% 0%
Lease costs.........................................................................100% 0%
Intangible drilling costs.............................................................0% 100%
Equipment costs.....................................................................100% 0%
Operating costs, administrative costs, direct costs and all
other costs.....................................................................(1) (1)
PARTNERSHIP REVENUES
Interest income......................................................................(2) (2)
Equipment proceeds..................................................................100% 0%
All other revenues including production revenues
Before net of tax savings payout and partnership payout (3).....................(4) (4)
After net of tax savings payout, but before partnership payout (3)..............(4) (4)
After partnership payout........................................................(4) (4)
PARTICIPATION IN DEDUCTIONS
Intangible drilling costs.............................................................0% 100%
Depreciation........................................................................100% 0%
Percentage depletion allowance (3)...................................................(5) (5)
</TABLE>
------------------------
(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.
(4) Subject to the managing general partner's subordination obligation, all
other revenues of the partnership, including production revenues, will be
credited as follows: before net of tax savings payout and partnership
payout you and the other investors and the managing general partner will
share in partnership revenues in the same percentage as your respective
capital contributions bears to the total partnership capital
contributions. After net of tax savings payout the managing general
partner will receive an additional 6.5% of the partnership revenues, and
after partnership payout the managing general partner will receive an
additional 8.5% of partnership revenues for a total additional amount of
15% of partnership revenues.
(5) The percentage depletion allowances will be in the same percentages as the
production revenues.
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 units. These charges
and credits will take into account any investor general partner's status as a
defaulting investor general partner.
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DISTRIBUTIONS
The managing general partner will review your account at least quarterly to
determine whether cash distributions are appropriate and the amount to be
distributed, if any. The partnership will distribute funds to you and the
other investors 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 distributions to you and the
other investors 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 by a final terminating event as described below or an
event which causes the dissolution of a limited partnership under state law.
However, if the partnership terminates upon an event which causes a
dissolution under state law and it is not a final terminating event, then a
successor limited partnership will automatically be formed under those
circumstances. Thus, only upon a final terminating event will the partnership
be liquidated. A final terminating event is any of the following:
- an election to terminate the partnership by the managing
general partner or the affirmative vote of investors whose
subscriptions equal a majority of the total subscriptions;
- the termination of the partnership under Section 708(b)(1)(A)
of the Internal Revenue Code; or
- the partnership ceases to be going concern.
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 until the capital accounts of all of the
partners have been reduced to zero. Thereafter, 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 you affirmatively consent to receive an in-kind
property distribution after being told of the risks associated with the
direct ownership or there are alternative arrangements in place which assure
that you will not be responsible for the operation or disposition of the
partnership properties. If the managing general partner has not received your
written consent to the in-kind distribution within 30 days after it is
mailed, then it will be presumed that you have not consented. The managing
general partner may then sell the asset at the best price reasonably
obtainable from an independent third party. 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 with respect to some of the conflicts of
interest, but not all, certain limitations which are designed to reduce, but
which will not eliminate, the conflicts. Other than these limitations the
managing general partner has not established procedures to resolve a conflict
of interest and under the terms of the partnership agreement the managing
general partner may resolve the conflict of interest in its sole discretion
and best interest.
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The following discussion is 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
The managing general partner anticipates that all of 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.
CONFLICTS REGARDING SHARING OF COSTS AND REVENUES
After net of tax savings payout 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 all 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 equipment costs
to complete the well 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 most of the partnership wells drilled to the
Clinton/Medina geological
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formation and the Mississippian/Upper Devonian Sandstone reservoirs, which
will be a majority portion of the partnership's drilling activities, will be
required to be completed before it can determine 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. For example,
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
depreciation deductions, or the 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 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 from participating in other businesses or activities, even if
these other businesses or activities compete 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
- it is not appropriate for the partnership under the existing
circumstances.
CONFLICTS INVOLVING THE ACQUISITION OF LEASES
The managing general partner will select, in its sole discretion, the wells
to be drilled by 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 or its affiliate's other partnerships or
third-party programs in which they serve as driller/operator. It may be in
the managing general partner's or its affiliates' advantage to have 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.
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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 and 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, Pennsylvania and New York on which a well will be
drilled to test the Clinton/Medina geologic formation or to the
Mississippian/Upper Devonian Sandstone reservoirs, 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. 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 the majority of the wells drilled by the
partnership will develop either the Clinton/Medina geologic formation or
the Mississippian/Upper Devonian Sandstone reservoirs. The drilling of
these wells may provide the managing general partner with offset sites by
allowing it to determine at the partnership's expense the value of
adjacent acreage in which the partnership would not have any interest.
The managing general partner owns acreage 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:
- in the Clinton/Medina geologic formation within 1,650 feet of
an existing partnership well in Pennsylvania or within 1,000
feet of an existing partnership well in Ohio; or
- in the Mississippian/Upper Devonian Sandstone reservoirs
within 1,000 feet of an existing partnership well.
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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 prospect is not
limited to the drilling or spacing unit and the area constituting the
partnership's prospect is subsequently enlarged based on geological
information which is later acquired then there is the following special
provision:
- if the prospect is enlarged to cover any area where the
managing general partner owns a separate property interest and
the partnership activities were material in establishing the
existence of proved undeveloped reserves which are
attributable to the separate property interest, then the
separate property interest or a portion thereof must be sold
to the partnership in accordance with (1), (2) and (4).
(4) TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS AFFILIATES'
ENTIRE INTEREST. If the managing general partner sells or transfers to
the partnership less than all of its ownership in any prospect then it
must comply with the following conditions:
- the retained interest 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 revenue interest 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 is also
prohibited from buying the additional interest.
(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:
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- 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 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.
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 PREPARATION OF GEOLOGICAL REPORT
The geological report for Fayette County, Pennsylvania which covers a portion
of the currently proposed wells was prepared by the managing general partner
which is not independent. This lack of independence in the preparation of the
report may affect its reliability since the managing general partner has an
incentive to prepare a more positive report than an independent geologist.
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 2005. 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.
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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 to be used as collateral for a loan.
CONFLICTS REGARDING ORDER OF PIPELINE CONSTRUCTION AND GATHERING FEES
A conflict of interest is created by the right of the managing general
partner's parent company, Atlas America, and its affiliate, Atlas Pipeline
Partners, L.P., to determine the order of priority for constructing gathering
lines which may be required to connect certain of the partnership's wells
into the gathering system of Atlas Pipeline Partners. Also, the managing
general partner may choose well locations along the gathering system which
would benefit its parent company and Atlas Pipeline Partners, even if there
are well locations available in the area or other areas which offer the
partnership a greater potential return.
The managing general partner and its affiliates will pay the difference
between the gathering fees to be paid by the partnership to Atlas Pipeline
Partners, which are set forth in "Compensation - Gathering Fees," and the
greater of $.35 per mcf or 16% of the gross sales price for the gas. This
provides an incentive to the managing general partner to increase the amount
of the gathering fees paid by the partnership in the future.
PROCEDURES TO REDUCE CONFLICTS OF INTEREST
In addition to the procedures set forth in " - Conflicts Involving the
Acquisition of Leases," the managing general partner and its affiliates will
comply with the following procedures in the partnership agreement to reduce
some of the conflicts of interest with you and the other investors. The
managing general partner does not have any other conflict of interest
resolution procedures. Thus, conflicts of interest between the managing
general partner and you and the other investors may not necessarily be
resolved in your best interests. However, the managing general partner
believes that its significant capital contribution to 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.
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(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:
- 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
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- 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.
CERTAIN TRANSACTIONS
As of April 15, 2000, 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 $186,698 $42,146
A.E. Partners 1986 631,250 0 631,250 143,731 61,239
A.E. Partners 1987 721,000 0 721,000 152,876 60,028
A.E. Partners 1988 617,050 0 617,050 125,772 56,721
A.E. Partners 1989 550,000 0 550,000 109,413 55,952
A.E. Partners 1990 887,500 0 887,500 173,636 62,666
A.E. Nineties-10 2,200,000 0 2,200,000 381,327 61,771
A.E. Nineties-11 750,000 0 761,802 (2) 151,703 95,814
A.E. Partners 1991 868,750 0 867,500 144,733 80,564
A.E. Nineties-12 2,212,500 0 2,272,017 (2) 426,414 92,690
A.E. Nineties-JV 92 4,004,813 0 4,157,700 (2) 669,077 147,880
A.E. Partners 1992 600,000 0 600,000 83,879 38,925
A.E. Nineties-Public #1 2,988,960 0 3,026,348 (2) 343,493 81,997
A.E. Nineties-1993 Ltd. 3,753,937 0 3,480,656 (2) 480,719 97,494
A.E. Partners 1993 700,000 0 689,940 98,013 28,838
A.E. Nineties-Public #2 3,323,920 0 3,324,668 (2) 342,081 67,949
A.E. Nineties-14 9,940,045 0 9,512,015 (2) 1,163,337 234,054
A.E. Partners 1994 892,500 0 892,500 72,752 30,655
A.E. Nineties-Public #3 5,799,750 0 5,799,750 485,030 100,898
A.E. Nineties-15 10,954,715 0 9,859,244 (2) 937,691 198,432
A.E. Partners 1995 600,000 0 600,000 48,761 9,971
A.E. Nineties-Public #4 6,991,350 0 6,991,350 538,325 106,123
A.E. Nineties-16 10,955,465 0 10,955,465 635,890 114,198
A.E. Partners 1996 800,000 0 800,000 54,704 10,894
A.E. Nineties-Public #5 7,992,240 0 7,992,240 432,882 83,681
A.E. Nineties-17 8,813,488 0 8,813,488 378,062 75,122
A.E. Partners 1997 506,250 0 506,250 20,368 3,962
A.E. Nineties-Public #6 9,901,025 0 9,901,025 405,333 71,798
A.E. Nineties-18 11,391,673 0 11,391,673 378,742 64,229
A.E. Partners-1998 1,740,000 0 1,740,000 49,128 7,906
A.E. Nineties-Public #7 11,988,350 0 11,988,350 283,067 41,603
A.E. Nineties-19 15,720,450 0 15,720,450 100,143 17,588
A.E. Partners 1999 450,000 0 450,000 0 0
A.E. Nineties-Public #8 11,088,975 0 11,088,975 0 0
</TABLE>
----------------------------
(1) Excluding the managing general partner's capital contributions.
(2) Includes additional drilling costs paid with production revenues.
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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.
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, judgments, 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 following:
- the tangible net assets of the partnership;
- revenues from operations; and
- 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.
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.
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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.
- 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.
- Generally, the passive activity limitations on losses
under Section 469 of the Internal Revenue Code, more
likely than not, will not be applicable to investor
general partners before the conversion of investor
general partner units to limited partner interests.
- 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 (other than converted investor
general 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.
- 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
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subject to certain restrictions summarized below, including
basis and "at risk" limitations and the passive activity loss
limitation with respect to the limited partners.
- PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Depending primarily
on when the partnership subscriptions are received, the
managing general partner anticipates that the partnership will
prepay in 2000 most, if not all, of the intangible drilling
costs related to partnership wells the drilling of which will
begin in 2001. Assuming that the amounts are fair and
reasonable, and based in part on the factual assumptions set
forth below, in special counsel's opinion the prepayments of
intangible drilling costs will be deductible for the 2000
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 2000 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 31, 2001, 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.
- 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
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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
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 Pennsylvania Revised Uniform Limited Partnership Act until they are
converted to limited partners, their deductions generally will not be treated as
passive deductions before the conversion. However, if an investor general
partner invests in the partnership through an entity which limits his liability,
for example, a limited partnership, limited liability company, 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 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 2001. Thereafter, each
investor general partner will have limited liability as a limited partner under
the Pennsylvania Revised Uniform Limited Partnership Act 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.
2000 EXPENDITURES
The managing general partner anticipates that all of the partnership's
subscription proceeds will be expended in 2000 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 2000 most, if not all, of its intangible drilling
costs for wells the drilling of which will begin in 2001. The deductibility in
2000 of such advance payments cannot be guaranteed.
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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; or
- they are properly characterized as organization or syndication
fees, other capital costs such as the acquisition cost of the
leases, or are not "ordinary and necessary" business expenses.
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. Intangible drilling 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.
Under the partnership agreement 90% of the subscription proceeds received by the
partnership from you and the other investors will be used to pay intangible
drilling costs which are charged 100% to you and the other investors. The IRS
could challenge the characterization of a portion of these costs as deductible
intangible drilling costs and recharacterize the costs as some other item which
may be non-deductible; however, this would have no effect on the allocation and
payment of the 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
million; 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
cost plus 15% basis. For its services as general drilling contractor, the
managing general partner anticipates that on average over all of the wells
drilled and completed by the partnership it will have reimbursement of
general and administrative overhead of approximately $12,900 per well and a
profit of 15% (approximately $21,850) per well with respect to the intangible
drilling costs paid by you and the other investors as described in
"Compensation - Drilling Contracts". However, the actual cost of drilling and
completing the wells may be more or less than the estimated amount, due
primarily to the uncertain nature of drilling operations, and the managing
general partner's reimbursement of overhead and profit also could be more or
less than the amount estimated by the managing general partner.
The managing general partner believes the drilling and operating agreement is at
a competitive rate in the proposed areas of operation. Nevertheless, the amount
of the profit realized by the managing general partner under the drilling and
operating agreement could be challenged by the IRS as 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 2000
most, if not all, of the intangible drilling costs for drilling activities that
will begin in 2001. 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.
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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 2000 intangible drilling
costs for specified wells the drilling of which will begin in 2001. 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 drilling and completing
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 and completing 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 31, 2001. 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, for example, the unavailability
of drilling rigs, decisions of third-party operators to delay drilling the
wells, 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 31,
2001, will actually begin by that date. In that event, deductions claimed in
2000 for prepaid intangible drilling costs would be disallowed and deferred to
the 2001 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 the 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 2000 is 24%. This rate fluctuates from year to year
depending on the price of oil, but will not be less than the statutory rate of
15% nor more than 25%.
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Also, percentage depletion:
- 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 2000 and 2001.
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 to drill and complete the partnership's wells, and the related
depreciation deductions, are allocated and charged under the partnership
agreement 100% to the managing general partner.
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 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;
- share of partnership income; and
- share, if any, of partnership debt.
The adjusted basis of your interest in the partnership will be reduced by your:
- share of partnership losses;
- depletion deduction, but not below zero; and
- cash distributions from the partnership. 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. Your initial amount "at risk" is
the amount of money you have contributed to the partnership. However, 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.
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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 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 12
months will generally result in a recognition of long-term capital gain or loss.
However, the recapturable portions of depletion and intangible drilling costs
will constitute ordinary income. If the interest is held for 12 months or less,
then 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 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 BEFORE
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, then 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 deduction for intangible drilling costs.
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
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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 deduction for intangible drilling
costs. 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 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.
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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, including the
dealer-manager fee, sales commissions, and reimbursement for bona fide
accountable due diligence expenses which are charged 100% to you and the other
investors under the partnership agreement, 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 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 the activity exceeds the deductions
attributable to the 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 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.
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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 if the partnership has more
than 100 partners. In addition, a partnership with at least 100 partners may
elect to be governed under simplified tax reporting and audit rules as an
"electing large partnership." These rules also facilitate the matching of
partnership items with individual partner 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 that 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.
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
- the price for any property or services, or for the use of
property, claimed on a return is 200% or more, or 50% or less,
of the correct price.
If there is a gross valuation misstatement, which is 400% or more of the correct
value or adjusted basis or the undervaluation is 25% or less of the correct
amount, then the penalty is 40%.
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SUBSTANTIAL UNDERSTATEMENT PENALTY. There is also an addition to tax of 20%
of any underpayment if the difference between the tax required to be shown on
the return over the tax actually shown on the return, exceeds the greater of:
- 10% of the tax required to be shown on the return; or
- $5,000.
The amount of any understatement generally will be reduced to the extent it is
attributable to the tax treatment of an item:
- supported by substantial authority; or
- adequately disclosed on the taxpayer's return and there is a
reasonable basis for the tax treatment of the 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 2000 the
ceiling for social security tax of 12.4% is $76,200 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.
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ESTATE AND GIFT TAXATION
There is no federal tax on lifetime or testamentary transfers of property
between spouses. The gift tax annual exclusion is $10,000 per donee, which will
be adjusted for inflation. Estates of $675,000, 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 THE MATERIAL PROVISIONS IN THE PARTNERSHIP AGREEMENT
WHICH ARE NOT COVERED ELSEWHERE IN THIS PROSPECTUS.
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 partners 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
The following provisions apply regarding notices:
- when the managing general partner gives you and other
investors notice it begins to run from the date of mailing the
notice and is binding even if not received;
- the notice periods are frequently quite short, a minimum of 22
calendar days, and apply to matters which may seriously affect
your rights; and
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- if you fail to respond in the specified time to the managing
general partner's second request for approval of or
concurrence in a proposed action, then you will conclusively
be deemed to have approved the action unless the partnership
agreement expressly requires your affirmative approval.
VOTING RIGHTS
Generally, you will not be entitled to vote with respect to any partnership
matters at any meeting which is called by the managing general partner other
than as set forth below. However, at any time upon the request of investors
whose subscriptions equal 10% or more of the total subscriptions, you and the
other investors may call a meeting to vote or vote without a meeting on the
matters set forth below without the concurrence of the managing general partner.
For each unit you own you are entitled to one vote on the matters being voted
upon. However, 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. Investors
whose subscriptions equal a majority of the total subscriptions may vote to:
- 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;
- cancel any contract for services with the managing general
partner, the operator or their affiliates without penalty upon
60 days notice; and
- 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
contribution of you or the managing general partner
without the approval of you or the managing general
partner; or
- affect the classification of partnership income and
loss for federal income tax purposes without the
unanimous approval of all investors.
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 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, as a participant 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.
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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. The operator
may be replaced at any time upon 60 days 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.
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- 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 you will be provided the reports and information
set forth below which the partnership will pay as a direct cost.
- Beginning with the 2000 calendar year, the partnership will
provide you an annual report within 120 days after the close
of the calendar year, and beginning with the 2001 calendar
year, a report within 75 days after the end of the first six
months of its calendar year, containing at least the following
information.
- Audited financial statements of the partnership
prepared in accordance with generally accepted
accounting principles. Semiannual reports will not be
audited.
- 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 you and the other
investors.
- By March 15 of each year, the partnership will send you the
information needed for you to file your federal and state
income tax returns.
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- Beginning January 1, 2002, 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 2005. 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
- it 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, then it will be transferred to the party who pays for it and you
will be required to deliver an executed assignment of your interest along with
any other documents that the managing general partner requests.
You may present your units in writing to the managing general partner beginning
in 2005 subject to the following conditions:
- the presentment must be within 120 days of the partnership
reserve report discussed below;
- in accordance with Treas. Reg. Section 1.7704-1(f), the
repurchase may not be made until at least 60 calendar days
after you notify the partnership in writing of your
presentment; and
- 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 2002 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. It will include the sum of the following
partnership items:
- an amount based on 70% of the present worth of future net
revenues from the proved reserves, determined as described
above;
- cash on hand;
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- prepaid expenses and accounts receivable, less a reasonable
amount for doubtful accounts; and
- the estimated market value of all assets not separately
specified above, determined in accordance with standard
industry valuation procedures.
There will be deducted from the foregoing sum the following items:
- an amount equal to all 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 following:
- 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
- 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
- changes in income, ad valorem and other tax laws such
as material variations in the provisions for
depletion and similar matters.
As of March 31, 2000, fewer than 25 units have been presented to the managing
general partner for repurchase in its previous 34 limited partnerships.
TRANSFERABILITY OF UNITS
RESTRICTIONS ON TRANSFER IMPOSED BY THE SECURITIES AND TAX LAW
Your transferability of the units is restricted by the securities laws, the tax
laws, and the partnership agreement as described below.
First, 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 1933 Act 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.
The managing general partner and the partnership are not obligated to, and do
not intend to, register the units for resale.
Second, under the tax laws, you will not be able to sell, assign, exchange or
transfer your unit if it would, in the opinion of counsel for the partnership
result in the following:
- the termination of the partnership for tax purposes; or
129
<PAGE>
- the partnership being treated as a "publicly-traded"
partnership for tax purposes.
Finally, under the partnership agreement you may not transfer your unit unless
the managing general partner consents. 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
- at the managing general partner's election 7:00 A.M. of the
following day.
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.
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
seven 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.
130
<PAGE>
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 four wholesalers,
Mr. Eric Koval, Mr. Bruce Bundy, Mr. Robert Gourlay and Ms. Vicki Burbridge
who are employed by it or its affiliates and associated with Anthem
Securities. The 2.5% dealer-manager fee generally 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.
You and the other investors will share costs, revenues and distributions in
the partnership pro rata in accordance with your respective subscription.
Also, the managing general partner, its officers, directors and affiliates
and the selling agents may subscribe for units on the same basis as you and
other investors but without paying the dealer-manager fee, sales commissions,
reimbursement of marketing expenses, and due diligence reimbursements; and
registered investment advisors and their clients may subscribe to units
without paying sales commissions, reimbursement of marketing expenses, and
due diligence reimbursements. These investors will share in the partnership's
costs, revenues and distributions on the same basis as the other investors,
even though they pay a reduced price for their units.
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
1933 Act 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 1933 Act.
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 America Public #9 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 and the sales
material is not complete. The 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:
131
<PAGE>
- 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.
Also, no cash, merchandise or other items of value may be offered as an
inducement to you or any prospective investor to attend the meeting. All written
or prepared audiovisual presentations including scripts prepared in advance for
oral presentations to be made at the meetings must be submitted to the state
administrators within a prescribed review period. These provisions, however,
will not apply to meetings consisting only of 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 in this prospectus 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 dates 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 September 1999 oil and gas reserves of Resource America, Inc.
are made in reliance on Wright & Company, Inc.'s authority as an expert in
petroleum consulting.
LITIGATION
The managing general partner knows of no litigation pending or threatened to
which the managing general partner or the 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.
132
<PAGE>
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.
133
<PAGE>
FINANCIAL STATEMENT AND REPORT OF
INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
ATLAS AMERICA - PUBLIC #9 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP
July 31, 2000
134
<PAGE>
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Partners
ATLAS AMERICA - PUBLIC #9 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP
We have audited the accompanying balance sheet of Atlas America - Public #9
Ltd., a Pennsylvania Limited Partnership, as of July 31, 2000. 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 auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the financial statement referred to above presents fairly, in
all material respects, the financial position of Atlas America - Public #9
Ltd. as of July 31, 2000, in conformity with accounting principles generally
accepted in the United States.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
August 15, 2000
135
<PAGE>
Atlas America - Public #9 Ltd.
(A Pennsylvania Limited Partnership)
BALANCE SHEET
July 31, 2000
<TABLE>
<CAPTION>
ASSETS
<S> <C>
Cash $ 100
====================
PARTNERS' CAPITAL
Partners' capital: $ 100
====================
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THIS FINANCIAL STATEMENT.
136
<PAGE>
Atlas America - Public #9 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENT
July 31, 2000
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
Atlas America - Public #9 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., which is a wholly-owned subsidiary of Resource America, Inc., a
publicly traded company) will be Managing General Partner and Operator,
and subscribers to Units will be either Limited Partners or Investor
General Partners depending upon their election.
The Partnership will be funded to drill development wells which are
proposed to be located primarily in the Clinton/Medina geological
formation in Northwestern Pennsylvania and the Mississippian/Upper
Devonian Sandstone reservoir in Fayette County, Pennsylvania, although
the Managing General Partner has reserved the right to drill wells in
other areas of the United States, primarily in the Appalachian Basin.
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 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
$15,000,000) by December 31, 2000.
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.
137
<PAGE>
Atlas America - Public #9 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENT - CONTINUED
July 31, 2000
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 costs 100% 0%
Dealer-manager fee, sales commissions, and
reimbursement for bona fide accountable
due diligence expenses 0% 100%
Reimbursement of marketing expenses 100% 0%
Lease costs 100% 0%
Revenues (1) (1)
Operating costs, administrative costs,
direct costs and all other costs (2) (2)
Intangible drilling costs 0% 100%
Tangible costs 100% 0%
Tax deductions:
Intangible drilling and development costs 0% 100%
Depreciation 100% 0%
Depletion allowances (3) (3)
</TABLE>
(1) Subject to the Managing General Partner's subordination
obligation, substantially all revenues will be credited as
follows: before net of tax savings payout and partnership
payout, partnership revenues will be shared in the same
percentage as capital contributions are to the total
partnership capital contributions. After net of tax savings
payout, the Managing General Partner will receive an
additional 6.5% of the partnership revenues, and after
partnership payout, the Managing General Partner will receive
an additional 8.5% of partnership revenues.
(2) These costs will be charged to the partners in the same ratio
as the related production revenues are credited.
(3) The percentage depletion allowance will be in the same
percentages as the production revenues.
138
<PAGE>
Atlas America - Public #9 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENT - CONTINUED
July 31, 2000
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
cost plus 15%.
Administrative costs at $75 per well per month.
Well supervision fees for operating and maintaining the wells
during producing operations at a competitive rate (currently
in the range of $275 to $400 per well per month.
Reimbursement of gas transportation at competitive rates
(currently in the range of $.29 to $.35 per MCF).
6. PURCHASE COMMITMENT
Subject to certain conditions, investor partners may present their
interests beginning in 2005 for purchase by Atlas. Atlas is not
obligated to purchase more than 5% of the units in any calendar year.
In the event that Atlas is unable to obtain the necessary funds, Atlas
may suspend its repurchase obligation.
7. SUBORDINATION OF MANAGING GENERAL PARTNER'S
REVENUE SHARE
Atlas will subordinate up to 50% of its share 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.
139
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
AND REPORT OF
INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
ATLAS RESOURCES, INC.
September 30, 1999 and 1998
140
<PAGE>
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Board of Directors
ATLAS AMERICA, INC.
We have audited the accompanying consolidated balance sheets of Atlas
Resources, Inc. (a Pennsylvania corporation) and Subsidiary as of September
30, 1999 and 1998, and the related consolidated statements of earnings and
retained earnings, and cash flows for the year ended September 30, 1999.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position
of Atlas Resources, Inc. and Subsidiary as of September 30, 1999 and 1998,
and the consolidated results of their operations and their consolidated cash
flows for the year ended September 30, 1999, in conformity with generally
accepted accounting principles.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
November 17, 1999
141
<PAGE>
Atlas Resources, Inc. and Subsidiary
CONSOLIDATED BALANCE SHEETS
September 30
ASSETS
<TABLE>
<CAPTION>
1999 1998
------------------- -------------------
<S> <C> <C>
Current Assets
Cash and cash equivalents $ 9,417,386 $ 83,890
Accounts and other receivables 3,686,386 2,918,819
Inventories 331,019 160,890
Prepaid expenses and other current assets 63,599 25,987
------------------- -------------------
Total current assets 13,498,390 3,189,586
Property, Plant and Equipment - at cost
Oil and gas properties and equipment (successful efforts) 21,968,332 13,290,245
Land 361,000 361,000
Buildings 2,469,000 2,469,000
Equipment 378,029 209,964
------------------- -------------------
25,176,361 16,330,209
Less accumulated depreciation and amortization (1,705,672) -
------------------- -------------------
Net property, plant and equipment 23,470,689 16,330,209
Contract rights and other intangibles (less accumulated 11,481,913 12,095,708
amortization of $613,795 in 1999)
Goodwill (less accumulated amortization of $536,263 in 1999) 15,551,595 16,087,858
------------------- -------------------
$ 64,002,587 $47,703,361
=================== ===================
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 3,830,648 $ 801,488
Working interests and royalties payable 4,397,894 4,723,751
Billings in excess of costs on uncompleted contracts 4,815,172 5,290,633
Current maturities of long-term debt 185,714 185,714
------------------- -------------------
Total current liabilities 13,229,428 11,001,586
Deferred Taxes 1,688,480 919,000
Advances from Parent and affiliates 5,965,392 1,166,755
Long-Term Debt, net of current maturities 5,315,477 526,191
Stockholder's Equity
Capital stock - stated value $10 per share; authorized -
500 shares, issued and outstanding - 200 shares 2,000 2,000
Additional paid-in capital 34,087,829 34,087,829
Retained earnings 3,713,981 -
------------------- -------------------
37,803,810 34,089,829
------------------- -------------------
$ 64,002,587 $47,703,361
=================== ===================
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
142
<PAGE>
Atlas Resources, Inc. and Subsidiary
CONSOLIDATED STATEMENT OF EARNINGS
AND RETAINED EARNINGS
For the year ended September 30, 1999
<TABLE>
<S> <C>
REVENUES
Well drilling $29,183,206
Oil and gas production 3,966,063
Well services 3,537,652
Other income 178,776
--------------------
36,865,697
COSTS AND EXPENSES
Well drilling 24,082,593
Oil and gas production 1,820,000
Well services 224,491
Exploration 175,806
General and administrative 854,411
Depreciation, depletion and amortization 2,855,730
Interest 490,930
Other 154,800
--------------------
30,658,761
--------------------
Earnings from operations 6,206,936
Provision for income taxes 2,492,955
--------------------
NET EARNINGS 3,713,981
Retained earnings - beginning of year -
--------------------
Retained earnings - end of year $ 3,713,981
====================
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THIS STATEMENT.
143
<PAGE>
Atlas Resources, Inc. and Subsidiary
CONSOLIDATED STATEMENT OF CASH FLOWS
For the year ended September 30, 1999
<TABLE>
<S> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings $ 3,713,981
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depreciation, depletion and amortization 2,855,730
Deferred income taxes 769,480
Changes in operating assets and liabilities:
Increase in accounts receivable (767,567)
Increase in inventory (170,129)
Increase in prepaid expenses and other current assets (37,612)
Increase in accounts payable and accrued liabilities 3,029,160
Decrease in working interests and royalties payable (325,857)
Decrease in billings in excess of costs on
uncompleted contracts (475,461)
--------------------
Cash provided by operating activities 8,591,725
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (8,846,152)
--------------------
Cash used in investing activities (8,846,152)
CASH FLOWS FROM FINANCING ACTIVITIES
Advances from Parent 4,798,637
Payment on mortgage payable (185,714)
Borrowings on revolving credit loan 4,975,000
--------------------
Cash provided by financing activities 9,587,923
--------------------
INCREASE IN CASH AND
CASH EQUIVALENTS 9,333,496
Cash and cash equivalents at beginning of period 83,890
--------------------
Cash and cash equivalents at end of period $ 9,417,386
====================
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THIS STATEMENT.
144
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 1999 and 1998
NOTE A - NATURE OF OPERATIONS
Atlas Resources, Inc. (the "Company") and its subsidiary, ARD Investments,
are engaged in the exploration for development and production of natural
gas and oil primarily in the Appalachian Basin Area. In addition, the
Company performs contract drilling and well operation services.
Atlas Resources, Inc. 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 a publicly traded company (trading under the symbol
REXI on the NASDAQ System) operating in the real estate finance, leasing
and energy business sectors. 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.
On September 29, 1998, Atlas America, Inc. acquired all the common stock of
The Atlas Group, 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 $ 71,951,000
Liabilities assumed (43,284,000)
Amounts due seller (9,191,000)
Common stock issued (29,534,000)
------------------
NET CASH ACQUIRED $ (10,058,000)
==================
</TABLE>
NOTE B - SUMMARY OF ACCOUNTING POLICIES
A summary of significant accounting policies consistently applied in the
preparation of the accompanying consolidated financial statements follows.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary. The Company 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, the Company includes its
pro rata share of the assets, liabilities, income and expenses of such
partnerships in the consolidated financial statements. All significant
intercompany transactions and balances have been eliminated.
Certain reclassifications have been made to the 1998 financial statements
to conform to the 1999 presentation.
145
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 1998
NOTE B - SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
USE OF ESTIMATES
Preparation of financial statements in conformity with generally accepted
accounting principles requires management 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.
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.
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting.
Accordingly, property acquisition costs, costs of successful exploratory
wells, all development costs, and the cost of support equipment and
facilities are capitalized. Costs of unsuccessful exploratory wells are
expensed when such wells are determined to be nonproductive. The costs
associated with drilling and equipping wells not yet completed are
capitalized as uncompleted wells, equipment and facilities. Geological and
geophysical costs and the costs of carrying and retaining undeveloped
properties, including delay rentals, are expensed.
Production costs, overhead, and all exploration costs other than costs of
exploratory drilling are charged to expense as incurred.
Proved developed oil and gas properties, which include intangible drilling
and development costs, tangible well equipment and leasehold costs, are
amortized on the unit-of-production method using the ratio of current
production to the estimated aggregate proved developed oil and gas
reserves.
Unproved properties are assessed periodically to determine whether there
has been a decline in value and, if such decline is indicated, a loss will
be recognized. The Company compares the carrying value of its oil and gas
producing properties to the estimated future cash flow, net of applicable
income taxes, from such properties in order to determine whether their
carrying values should be reduced. No adjustment was necessary at September
30, 1999.
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,
1999 and 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.
146
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 1998
NOTE B - SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
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 while subsequent
additions are recorded at cost. Depreciation is provided using the
straight-line method over the following estimated useful lives once the
asset is put into productive use.
Equipment 5 - 7 years
Building 39 years
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.
BILLINGS IN EXCESS OF COSTS ON UNCOMPLETED CONTRACTS
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.
REVENUE RECOGNITION
The Company sells interests in oil and gas wells and retains there from a
working interest and/or overriding royalty in the producing wells. The
income from the working interests is recorded when the natural gas and oil
are produced.
The Company also contracts to drill oil and gas wells. The income from
these contracts is recorded upon substantial completion of the well.
147
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 1998
NOTE B - SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
IMPAIRMENT OF LONG-LIVED ASSETS
The Company reviews its long-lived assets for impairment whenever events or
circumstances indicate that the carrying amount of an asset may not be
recoverable. If it is determined that an asset's estimated future cash
flows will not be sufficient to recover its carrying amount, an impairment
charge will be recorded to reduce the carrying amount for that asset to its
estimated fair value.
FEDERAL INCOME TAXES
The Company is included in the consolidated federal income tax return of
Resource America, Inc. Income taxes are calculated as if the Company had
filed a return on a separate company basis utilizing a statutory rate of
35%. Deferred taxes represent deferred tax assets or liabilities which are
recognized based on the temporary differences between the tax basis of the
Company's assets and liabilities and the amounts reported in the financial
statements. Separate company state tax returns are filed in those states in
which the Company is registered to do business.
FAIR VALUE OF FINANCIAL INSTRUMENTS
For cash and cash equivalents, receivable and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments. For long-term debt, the fair value approximates historically
recorded cost, since interest rates approximate market. Management believes
the fair value of any financial commitments are not material.
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the year for:
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30, 1999
-------------------------------
<S> <C>
Interest $ 50,707
-------------------------------
Income taxes $145,106
===============================
</TABLE>
148
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 1998
NOTE B - SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
NEW ACCOUNTING STANDARDS
Effective October 1, 1998, the Company became subject to the provisions of
Statements of Financial Accounting Standards No. 130 (SFAS 130), REPORTING
COMPREHENSIVE INCOME requires disclosure of comprehensive income and its
components. Comprehensive income includes net income and all other changes
in equity of a business during a period from transactions and other events
and circumstances from non-owner sources. These changes, other than net
income, are referred to as "other comprehensive income". The Company has no
material elements of comprehensive income, other than net income to report.
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133 (SFAS 133), ACCOUNTING
FOR DERIVATIVE INSTRUMENTS AND HEDGING. SFAS 133 will require the Company
to recognize all derivatives as either assets or liabilities in its
consolidated balance sheet and to measure those instruments at fair value.
The Company is required to adopt SFAS 133 effective October 1, 2000. The
effect of adopting SFAS 133 on the Company's consolidated financial
position, results of operations and cash flows will be dependent on the
extent of future hedging activities and fluctuations in interest rates.
NOTE C - RELATED PARTY TRANSACTIONS
The Company conducts certain energy activities through, and a substantial
portion of its revenues are attributable to limited partnerships
("Partnerships"). The Company serves as general partner of the Partnerships
and assumes customary rights and obligations for the Partnerships. As the
general partner, the Company is liable for Partnership liabilities and can
be liable to limited partners if it breaches its responsibilities with
respect to the operations of the Partnerships. The Company is entitled to
receive management fees, reimbursement for administrative costs incurred,
and to share in the Partnerships' revenue and costs and expenses according
to the respective Partnership agreements.
NOTE D - INCOME TAXES
The Company is included in the consolidated 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 and settled through increases or decreases to the Advances from
Parent and affiliates balance.
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,
1999 was primarily related to differences between book and tax bases of oil
and gas properties.
149
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 1998
NOTE E - LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30,
-----------------------------------
1999 1998
--------------- -------------------
<S> <C> <C>
Note payable to bank, secured by a building and certain
equipment, monthly installments of $15,476 plus interest
at or below the LIBOR rate plus 2-1/4% (7.5625% at
September 30, 1999); due August 2002 $526,191 $711,905
Revolving credit facility, secured by oil and gas
properties and pipelines; interest ranging from
7.0625% to 9% due November 2002 4,975,000 -
--------------- -------------------
5,501,191 711,905
Less current portion 185,714 185,714
--------------- -------------------
$5,315,477 $526,191
=============== ===================
</TABLE>
Atlas America, Inc. (Atlas), along with other energy affiliates owned by
Resource America, Inc., maintain a $45.0 million credit facility (with
$22.0 million of permitted draws available to Atlas) at PNC Bank ("PNC").
The facility is cross collateralized by the assets of all of the energy
affiliates, and a breach of the loan agreement by any of the energy
affiliates would constitute a default by Atlas. The revolving credit
facility has a term ending in November 2002 and bears interest at one of
two rates (elected at the borrower's option) which increase as the amount
outstanding under the facility increases: (i) PNC prime rate plus between 0
to 75 basis points, or (ii) the Eurodollar rate plus between 150 to 225
basis points. The credit facility contains certain financial covenants 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) limitations on indebtedness, sales, leases or transfers of
property by Atlas without PNC's consent; and (c) the maintenance of certain
financial ratios. Borrowings under the credit facility are collateralized
by substantially all the oil and gas properties and pipelines of Atlas.
Maturities of all long-term debt for the years following September 30, 1999
are as follows: 2000 - $185,714; 2001 - $185,714; 2002 - $154,763; and 2003
- $4,975,000.
150
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 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 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 may be required to subordinate a part of its net partnership
revenues to the receipt by investor partners of cash distributions from the
Partnership equal to at least 10% of their agreed subscriptions determined
on a cumulative basis, in accordance with the terms of the partnership
agreement.
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, 1999.
NOTE H - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Results of operations for oil and gas producing activities:
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30, 1999
-------------------------
<S> <C>
Revenues $ 3,966,063
Production Costs (1,820,000)
Exploration Expenses (175,806)
Depreciation, Depletion and Amortization (1,594,894)
Income Taxes -
-------------------------
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES $ 375,363
=========================
</TABLE>
151
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 1998
NOTE H - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
(CONTINUED)
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, 1999 and 1998. All reserves
are located in the Appalachian Basin Area. 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.
The components of capitalized costs related to the Company's oil and gas
producing activities are as follows:
<TABLE>
<CAPTION>
SEPTEMBER 30
---------------------------------------
1999 1998
-------------------- ------------------
<S> <C> <C>
Proved properties $21,946,148 $13,279,245
Unproved properties 22,184 11,000
-------------------- ------------------
Total 21,968,332 13,290,245
Accumulated depreciation, depletion
and amortization (1,594,894) -
-------------------- ------------------
NET CAPITALIZED COSTS $20,373,438 $13,290,245
==================== ==================
</TABLE>
The costs incurred by the Company in its oil and gas activities during the
fiscal year are as follows:
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30, 1999
--------------------------
<S> <C>
Property acquisition costs:
Unproved properties $ 11,184
Proved properties 15,519
Exploration costs 175,806
Development costs $ 8,651,384
</TABLE>
There are numerous uncertainties inherent in estimating quantities of
proven reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates
only and should not be construed as being exact. In addition, the
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.
152
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 1998
NOTE H - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
(CONTINUED)
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
each fiscal year, 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, 1999 and 1998 and such conditions
continually change. Accordingly, such information should not serve as a
basis in making any judgment on the potential value of recoverable reserves
or in estimating future results of operations.
<TABLE>
<CAPTION>
GAS OIL
(MCF) (BBLS)
------------------- ------------------
<S> <C> <C>
Proved developed and undeveloped reserves at
September 30, 1998: 65,376,210 4,574
Current additions 29,705,025 -
Revision of previous estimates (4,939,305) (2,437)
Transfer to limited partnerships (18,221,632) -
Production (2,432,098) (354)
------------------- ------------------
Proved developed and undeveloped reserves at
September 30, 1999 69,488,200 1,783
=================== ==================
Proved developed reserves at:
September 30, 1999 27,531,938 1,783
=================== ==================
September 30, 1998 25,360,750 4,574
=================== ==================
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED RESERVES
<TABLE>
<CAPTION>
SEPTEMBER 30
------------------------------------------
1999 1998
---------------------- -------------------
<S> <C> <C>
Future cash inflows $202,362,311 $152,909,040
Future production and development costs 99,691,650 73,423,000
---------------------- -------------------
Future net cash flows before income taxes 102,670,661 79,486,040
Future income taxes 13,861,715 3,853,561
---------------------- -------------------
Future net cash flows 88,808,946 75,632,479
Annual discount for estimated timing of cash flows 62,275,451 56,231,521
---------------------- -------------------
Standardized measure of discounted
future net cash flows $26,533,495 $ 19,400,968
====================== ===================
</TABLE>
153
<PAGE>
Atlas Resources, Inc. and Subsidiary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
September 30, 1999 and 1998
NOTE H - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
(CONTINUED)
The following table summarizes the changes in the standardized measure of
discounted future net cash flows from estimated production of proved
developed and undeveloped oil and gas reserves after income taxes.
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30, 1999
--------------------------
<S> <C>
Balance, beginning of year $19,400,968
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas net of related costs (2,146,063)
Net changes in prices and production costs 1,033,939
Revisions of previous quantity estimates (3,744,734)
Extensions, discoveries, and improved recovery, less related costs -
Purchases of reserves-in-place 10,412,270
Accretion of discount 2,043,105
Net change in future income taxes (1,306,947)
Other 840,957
-------------------------
BALANCE, END OF YEAR $26,533,495
=========================
</TABLE>
154
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
ATLAS RESOURCES, INC.
JUNE 30, 2000
155
<PAGE>
ATLAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
<TABLE>
<CAPTION>
6/30/2000 9/30/99
(Unaudited)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 5,490,541 $ 9,417,386
Trade accounts receivable 6,203,668 3,686,386
Inventories 470,857 331,019
Other current assets 72,016 63,599
------------ ------------
TOTAL CURRENT ASSETS 12,237,082 13,498,390
------------ ------------
OIL AND GAS PROPERTIES
Oil and gas wells and leases 27,493,472 21,968,332
Less accumulated depreciation, depletion and amortization 2,953,902 1,594,894
------------ ------------
NET OIL & GAS PROPERTIES 24,539,570 20,373,438
------------ ------------
OTHER PROPERTY, PLANT AND EQUIPMENT
Land 361,000 361,000
Buildings 2,469,000 2,469,000
Equipment 349,168 378,029
------------ ------------
Sub-total 3,179,168 3,208,029
Less accumulated depreciation 187,421 110,778
------------ ------------
NET OTHER PROPERTY, PLANT & EQUIPMENT 2,991,747 3,097,251
------------ ------------
Contract rights and other intangibles(Net of accumulated amortization of $1,074,145 and $613,795) 11,021,563 11,481,913
Goodwill(Net of accumulated amortization of $938,458 and $536,263) 15,149,400 15,551,595
------------ ------------
TOTAL ASSETS $ 65,939,362 $ 64,002,587
============ ============
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 425,734 $ 3,830,648
Working interests and royalties payable 5,212,668 4,397,894
Billings in excess of costs on uncompleted contracts 3,330,990 4,815,172
Current maturities on long-term debt 185,714 185,714
------------ ------------
TOTAL CURRENT LIABILITIES 9,155,106 13,229,428
------------ ------------
LONG-TERM DEBT, net of current maturities 216,667 5,315,477
------------ ------------
ADVANCES FROM PARENT & AFFILIATES 14,092,269 5,965,392
------------ ------------
DEFERRED INCOME TAXES 2,143,337 1,688,480
------------ ------------
STOCKHOLDER'S EQUITY
Capital stock, stated value $10.00 per share: Authorized - 500 shs; Issued - 200
shs. 2,000 2,000
Additional Paid in Capital 34,087,829 34,087,829
Retained earnings 6,242,154 3,713,981
------------ ------------
TOTAL STOCKHOLDER'S EQUITY 40,331,983 37,803,810
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 65,939,362 $ 64,002,587
============ ============
</TABLE>
156
<PAGE>
ATLAS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED JUNE 30
-------------------------
2000 1999
---- ----
<S> <C> <C>
REVENUES
Well drilling $ 21,789,141 $ 24,669,120
Oil and gas production 4,322,881 3,413,813
Well services 2,326,924 1,980,255
Interest 54,577 27,580
Other 199,528 314,422
------------ ------------
TOTAL REVENUES 28,693,051 30,405,190
------------ ------------
COSTS AND EXPENSES
Well drilling 18,054,058 20,133,912
Oil and gas production 1,098,420 737,791
Depreciation, depletion and amortization 2,300,546 2,030,003
Exploration 202,852 129,304
General and administrative 2,205,728 1,240,567
Interest 327,228 261,176
Other 248,036 126,944
------------ ------------
TOTAL COSTS AND EXPENSES 24,436,868 24,659,697
------------ ------------
INCOME BEFORE INCOME TAXES 4,256,183 5,745,493
INCOME TAXES 1,728,010 2,334,221
------------ ------------
NET INCOME $ 2,528,173 $ 3,411,272
============ ============
</TABLE>
ATLAS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED JUNE 30
-------------------------
2000 1999
------------ ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 2,528,173 $ 3,411,272
Adjustments to reconcile net income to net cash provided
by (used in) operating activities:
Depreciation, depletion and amortization 2,300,546 2,030,003
Deferred Income Taxes 454,857 --
(Increase) in Current Assets (2,665,537) (2,400,443)
Increase (Decrease) in Current Liabilities (4,074,322) 8,093,913
------------ ------------
Net cash provided by (used in) operating activities (1,456,283) 11,134,745
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in oil and gas wells and leases (5,525,140) (6,323,735)
Investment in other property, plant & equipment (23,177) (7,738)
Sale of other property, plant & equipment 49,457 --
------------ ------------
Net cash used in investing activities (5,498,859) (6,331,473)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings/(Repayments) under revolving credit (4,975,000) 5,425,000
Advances from parent & affiliates 8,127,108 --
Repayment of bank notes (123,810) (139,286)
------------ ------------
Net cash provided by (used in) financing activities 3,028,298 5,285,714
------------ ------------
Net increase (decrease) in cash and cash equivalents (3,926,845) 10,088,986
Cash and cash equivalents at beginning of year 9,417,386 62,724
------------ ------------
Cash and cash equivalents at end of period $ 5,490,541 $ 10,151,710
============ ============
</TABLE>
157
<PAGE>
ATLAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
June 30, 2000
1. INTERIM FINANCIAL STATEMENTS
The consolidated financial statements as of June 30, 2000 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 the 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, 1999 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,
2000 1999
<S> <C> <C>
Cash paid during the period for:
Interest $341,140 $218,950
Income taxes 268,000 266,000
</TABLE>
3. LONG-TERM DEBT
Long-term debt consists of a note payable to a bank in the amount of
$402,381 which is payable in monthly installments of $15,476 plus interest
at Libor plus 2 1/4% (8.94% at June 30, 2000) or the prime rate plus 1/2%
at the borrower's option 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, 2000 are as follows:
158
<PAGE>
Period Ending June 30,
2001 185,714
2002 185,714
Final Maturity August, 2002 30,953
--------
402,381
Less current maturities 185,714
--------
$216,667
========
Atlas America, Inc., the parent company of Atlas Resources, Inc. together
with other energy affiliates of Atlas America, maintain a $40.0 million
credit facility (with $33.7 million of permitted draws) with a bank group
with PNC Bank as the agent bank. As of June 30, 2000, Atlas Resources, Inc.
had no balance outstanding under the revolving credit facility.
159
<PAGE>
EXHIBIT (A)
AMENDED AND RESTATED CERTIFICATE
AND
AGREEMENT OF LIMITED PARTNERSHIP
ATLAS AMERICA PUBLIC #9 LTD.
<PAGE>
TABLE OF CONTENTS
SECTION NO. DESCRIPTION PAGE
I. FORMATION
1.01 Formation..................................1
1.02 Certificate of Limited Partnership.........1
1.03 Name, Principal Office and Residence.......1
1.04 Purpose....................................1
II. DEFINITION OF TERMS
2.01 Definitions................................2
III. SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
3.01 Designation of Managing General Partner
and Participants......................10
3.02 Participants..............................10
3.03 Subscriptions to the Partnership..........11
3.04 Capital Contributions.....................13
3.05 Payment of Subscriptions..................14
3.06 Partnership Funds.........................14
IV. CONDUCT OF OPERATIONS
4.01 Acquisition of Leases.....................15
4.02 Conduct of Operations.....................16
4.03 General Rights and Obligations of the
Participants and Restricted and
Prohibited Transactions...............20
4.04 Designation, Compensation and
Removal of Managing General
Partner and Removal of Operator.......29
4.05 Indemnification and Exoneration...........31
4.06 Other Activities..........................33
V. PARTICIPATION IN COSTS AND REVENUES, CAPITAL
ACCOUNTS, ELECTIONS AND DISTRIBUTIONS
5.01 Participation in Costs and Revenues.......34
5.02 Capital Accounts and Allocations
Thereto...............................37
5.03 Allocation of Income, Deductions and
Credits...............................38
5.04 Elections.................................40
5.05 Distributions.............................40
VI. TRANSFER OF INTERESTS
6.01 Transferability...........................41
6.02 Special Restrictions on Transfers.........42
6.03 Right of Managing General
Partner to Hypothecate and/or
Withdraw Its Interests....................43
6.04 Presentment...............................44
VII. DURATION, DISSOLUTION, AND
WINDING UP
7.01 Duration....................................46
7.02 Dissolution and Winding Up..................46
VIII. MISCELLANEOUS PROVISIONS
8.01 Notices.....................................47
8.02 Time........................................47
8.03 Applicable Law..............................47
8.04 Agreement in Counterparts...................47
8.05 Amendment...................................48
8.06 Additional Partners.........................48
8.07 Legal Effect................................48
EXHIBITS
EXHIBIT (I-A) - Managing General Partner Signature Page
EXHIBIT (I-B) - Subscription Agreement
EXHIBIT (II) - Drilling and Operating Agreement
i
<PAGE>
AMENDED AND RESTATED CERTIFICATE AND
AGREEMENT OF LIMITED PARTNERSHIP
ATLAS AMERICA PUBLIC #9 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 _____________________, 2000, 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 America Public #9 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, do the following:
(i) change the investment and business purpose of the Partnership; or
(ii) cause the Partnership to engage in activities outside the stated
business purposes of the Partnership through joint ventures with
other entities.
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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. Administrative Costs shall be
limited as follows:
(i) no Administrative Costs charged shall be duplicated under
any other category of expense or cost; and
(ii) no portion of the salaries, benefits, compensation or
remuneration of controlling persons of the Managing General
Partner shall be reimbursed by the Partnership as
Administrative Costs. Controlling persons include
directors, executive officers and those holding 5% or more
equity interest in the Managing General Partner or a person
having power to direct or cause the direction of the
Managing General Partner, whether through the ownership of
voting securities, by contract, or otherwise.
2. "Administrator" 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 10% or more of the outstanding
voting securities of the specified person;
(ii) any person 10% or more of whose outstanding voting
securities are directly or indirectly owned, controlled, or
held with power to vote, by the specified person;
(iii) any person directly or indirectly controlling, controlled
by, or under common control with the specified person;
(iv) any officer, director, trustee or partner of the specified
person; and
(v) if the specified person is an officer, director, trustee or
partner, any person for which the person acts in any such
capacity.
4. "Agreed Subscription" shall mean:
(i) that amount so designated on the Subscription Agreement
executed by the Participant; or
(ii) 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.
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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.
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 the property, including bonuses;
(ii) title insurance or examination costs, brokers' commissions,
filing fees, recording costs, transfer taxes, if any, and
like charges in connection with the acquisition of the
property;
(iii) a pro rata portion of the seller's actual necessary and
reasonable expenses for seismic and geophysical services;
and
(iv) rentals and ad valorem taxes paid by the seller with
respect to the property to the date of its transfer to the
buyer, interest and points actually incurred on funds used
to acquire or maintain the property, and the portion of the
seller's reasonable, necessary and actual expenses for
geological, engineering, drafting, accounting, legal and
other like services allocated to the property cost in
conformity with generally accepted accounting principles
and industry standards, except for expenses in connection
with the past drilling of wells which are not producers of
sufficient quantities of oil or gas to make commercially
reasonable their continued operations, and provided that
the expenses enumerated in this subsection (iv) shall have
been incurred not more than 36 months before the 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 the 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:
(i) Anthem Securities, Inc., an Affiliate of the Managing
General Partner, the broker/dealer which will manage the
offering and sale of the Units in all states other than
Minnesota and New Hampshire; and
(ii) Bryan Funding, Inc., the broker/dealer which will manage
the offering and sale of Units in Minnesota and New
Hampshire.
15. "Development Well" 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 be limited as follows:
(i) Direct Costs shall not include any cost otherwise
classified as Organization Costs, Administrative Costs,
Intangible Drilling Costs, Tangible Costs, Operating Costs
or costs related to the Leases; and
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(ii) 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, the 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; including the Managing
General Partner's increased interests after Net of Tax Savings
Payout and Partnership Payout.
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).
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 after the minimum
Partnership Subscription has been received when subscription
proceeds are first withdrawn from the escrow account.
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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. This includes all expenditures
made with respect to any well before the establishment of
production in commercial quantities for wages, fuel, repairs,
hauling, supplies and other costs and expenses incident to and
necessary for the drilling of the well and the preparation of the
well for the production of oil or gas, that are currently
deductible pursuant to Section 263(c) of the Code and Treasury
Reg. Section 1.612-4, which are generally termed "intangible
drilling and development costs," including the expense of plugging
and abandoning any well before a completion attempt.
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.
27. "Investor General Partners" shall mean:
(i) the persons signing the Subscription Agreement as Investor
General Partners; and
(ii) 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:
(i) the persons signing the Subscription Agreement as Limited
Partners;
(ii) the Managing General Partner to the extent of any optional
subscription under Section 3.03(b)(2);
(iii) the Investor General Partners upon the conversion of their
Investor General Partner Units to Limited Partner interests
pursuant to Section 6.01(b); and
(iv) any other persons who are admitted to the Partnership as
additional or substituted Limited Partners.
Except as provided in Section 3.05(b), with respect to the
required additional Capital Contributions of Investor General
Partners, all Limited Partners shall be of the same class and have
the same rights.
31. "Managing General Partner" shall mean:
(i) Atlas Resources, Inc.; or
(ii) 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.
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33. "Net of Tax Savings Payout" shall mean the time when:
(i) the cumulative credit equivalent of the Partnership's
deductions for Intangible Drilling Costs and percentage
depletion on the Participants' share of the Partnership's
income as estimated by the Managing General Partner; plus
(ii) the cumulative cash distributed to the Participants;
equals 100% of the Participants' aggregate Capital Contributions.
Once Net of Tax Savings Payout is reached it will not be affected
by future Capital Contributions.
34. "Offering Termination Date" shall mean the date after the minimum
Partnership Subscription has been received on which the Managing
General Partner determines, in its sole discretion, the
Partnership's subscription period is closed and the acceptance of
subscriptions ceases, which shall not be later than December 31,
2000.
35. "Operating Costs" shall mean expenditures made and costs incurred
in producing and marketing oil or gas from completed wells. These
costs include, but are not limited to:
(i) labor, fuel, repairs, hauling, materials, supplies, utility
charges and other costs incident to or related to producing
and marketing oil and gas;
(ii) ad valorem and severance taxes;
(iii) insurance and casualty loss expense; and
(iv) compensation to well operators or others for services
rendered in conducting such operations.
Operating Costs also include reworking, workover, subsequent
equipping and similar expenses relating to any well.
36. "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.
37. "Organization and Offering Costs" shall mean all costs of
organizing and selling the offering including, but not limited to:
(i) total underwriting and brokerage discounts and commissions
(including fees of the underwriters' attorneys);
(ii) expenses for printing, engraving, mailing, salaries of
employees while engaged in sales activities, charges of
transfer agents, registrars, trustees, escrow holders,
depositaries, engineers and other experts;
(iii) expenses of qualification of the sale of the securities
under federal and state law, including taxes and fees,
accountants' and attorneys' fees; and
(iv) other front-end fees.
38. "Organization Costs" shall mean all costs of organizing the
offering including, but not limited to:
(i) expenses for printing, engraving, mailing, salaries of
employees while engaged in sales activities, charges of
transfer agents, registrars, trustees, escrow holders,
depositaries, engineers and other experts;
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(ii) expenses of qualification of the sale of the securities
under federal and state law, including taxes and fees,
accountants' and attorneys' fees; and
(iii) other front-end fees.
39. "Overriding Royalty Interest" 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.
40. "Participants" shall mean:
(i) the Managing General Partner to the extent of its optional
subscription under Section 3.03(b)(2);
(ii) the Limited Partners; and
(iii) the Investor General Partners.
41. "Partners" shall mean:
(i) the Managing General Partner;
(ii) the Investor General Partners; and
(iii) the Limited Partners.
42. "Partnership" shall mean Atlas America Public #9 Ltd., the
Pennsylvania limited partnership formed pursuant to this
Agreement.
43. "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.
44. "Partnership Payout" shall mean the time when the Partnership's
cumulative cash distributions to the Participants equal 100% of
the Participants' aggregate Capital Contributions. Once
Partnership Payout is reached it will not be affected by future
Capital Contributions. Although the Participants receive tax
benefits, the Managing General Partner will not include these in
the Participant return for determining Partnership Payout. I.E.,
the Managing General Partner's increased revenue share after
Partnership Payout will not begin until the Participant receives
all of his investment back in cash excluding tax benefits.
45. "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).
46. "Partnership Well" shall mean a well, some portion of the revenues
from which is received by the Partnership.
47. "Person" shall mean a natural person, partnership, corporation,
association, trust or other legal entity.
48. "Program" shall mean one or more limited or general partnerships
or other investment vehicles formed, or to be formed, for the
primary purpose of:
(i) exploring for oil, gas and other hydrocarbon substances; or
(ii) investing in or holding any property interests which permit
the exploration for or production of hydrocarbons or the
receipt of such production or the proceeds thereof.
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49. "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:
(i) designated by the Managing General Partner in writing
before the conduct of Partnership operations; and
(ii) enlarged or contracted from time to time on the basis of
subsequently acquired information to define the anticipated
limits of the associated hydrocarbon reserves and to
include all acreage encompassed therein.
If the well to be drilled by the Partnership is to a Horizon
containing Proved Reserves, then a "Prospect" 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. Subject to the foregoing
sentence, with respect to the Clinton/Medina geological formation
and the Mississippian/Upper Devonian Sandstone reservoirs in Ohio,
Pennsylvania and New York, "Prospect" shall be deemed the drilling
or spacing unit.
50. "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.
51. "Proved Reserves" shall mean the estimated quantities of crude
oil, natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, I.E., prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility
is supported by either actual production or conclusive
formation test. The area of a reservoir considered proved
includes:
(a) that portion delineated by drilling and defined by
gas-oil and/or oil-water contacts, if any; and
(b) the immediately adjoining portions not yet drilled,
but which can be reasonably judged as economically
productive on the basis of available geological and
engineering data.
In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when
successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for
the engineering analysis on which the project or program
was based.
(iii) Estimates of proved reserves do not include the following:
(a) oil that may become available from known reservoirs
but is classified separately as "indicated
additional reserves";
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(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.
52. "Proved Undeveloped Reserves" shall mean reserves that are
expected to be recovered from either:
(i) new wells on undrilled acreage; or
(ii) from existing wells where a relatively major expenditure is
required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of
production when drilled. Proved reserves for other undrilled units
can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing
productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for
which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same reservoir.
53. "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. The term does not include:
(i) a transaction involving securities of the Partnership that
have been listed for at least 12 months on a national
exchange or traded through the National Association of
Securities Dealers Automated Quotation National Market
System; or
(ii) a transaction involving the conversion to corporate, trust
or association form of only the Partnership if, as a
consequence of the transaction, there will be no
significant adverse change in any of the following:
(a) voting rights;
(b) the term of existence of the Partnership;
(c) the Managing General Partner's compensation; and
(d) the Partnership's investment objectives.
54. "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.
55. "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.
56. "Selling Agents" shall mean those broker/dealers selected by the
Dealer-Manager which will participate in the offer and sale of the
Units.
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57. "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. The definition includes:
(i) the managing and controlling general partner(s) and any
other person who actually controls or selects the person
who controls 25% or more of the exploratory, development or
producing activities of the program, or any segment
thereof, even if that person has not entered into a
contract at the time of formation of the program; and
(ii) whenever the context so requires, the term "sponsor" shall
be deemed to include its affiliates.
"Sponsor" does not include wholly independent third parties such
as attorneys, accountants, and underwriters whose only
compensation is for professional services rendered in connection
with the offering of units.
58. "Subscription Agreement" shall mean an execution and subscription
instrument in the form attached as Exhibit (I-B) to this
Agreement, which is incorporated herein by reference.
59. "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. This includes all
costs of equipment, parts and items of hardware used in drilling
and completing a well, and those items necessary to deliver
acceptable oil and gas production to purchasers to the extent
installed downstream from the wellhead of any well and which are
required to be capitalized pursuant to applicable provisions of
the Code and regulations promulgated thereunder.
60. "Tax Matters Partner" shall mean the Managing General Partner.
61. "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.
62. "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.
3.02. PARTICIPANTS.
3.02(a). LIMITED PARTNER AT FORMATION. Atlas America, Inc., as Original Limited
Partner, has acquired one Unit and has made a Capital Contribution of $100.
Upon the admission of one or more Limited Partners, the Partnership shall return
to the Original Limited Partner its Capital Contribution and shall reacquire its
Unit. The Original Limited Partner shall then cease to be a Limited Partner in
the Partnership with respect to the Unit.
3.02(b). OFFERING OF INTERESTS. The Partnership is authorized to admit to the
Partnership at the Initial Closing Date, any Interim Closing Date(s), and the
Offering Termination Date additional Participants whose Agreed Subscriptions for
Units are
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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.
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, 2000; or
(ii) at the time the 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 in this Agreement. 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 as set forth in this Agreement.
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.
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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 Agents' 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.
In both cases their Agreed Subscriptions shall be treated by the Partnership as
though they had paid $10,000 per Unit for purposes of:
(i) their voting rights under this Agreement;
(ii) the Roll-Up provisions under Section 4.03(d)(16) and its
subsections;
(iii) their allocations under Section 5.01(c)(1); and
(iv) their presentment rights under Section 6.04 and its subsections.
3.03(b)(3). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing General Partner
has executed a Managing General Partner Signature Page which:
(i) evidences the Managing General Partner's required subscription
under Section 3.03(b)(1); and
(ii) may be amended to reflect the amount of any optional subscription
under Section 3.03(b)(2).
Execution of the Managing General Partner Signature Page serves as an agreement
by the Managing General Partner to be bound by each and every term of this
Agreement.
3.03(c). MAXIMUM AND MINIMUM 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 $15,000,000 (1,500 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.
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 of
the subscription 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 an Agreed Subscription is rejected, then all funds
shall be returned to the subscriber immediately.
3.03(d)(3) ADMISSION TO THE PARTNERSHIP. The Participants shall be admitted to
the Partnership as follows:
(i) not later than 15 days after the release from escrow of
Participants' funds to the Partnership; and
(ii) after the close of the escrow account not later than the last day
of the calendar month in which their Agreed Subscriptions were
accepted by the Partnership.
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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.
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 no later than
December 31, 2001.
3.04(b)(2). MINIMUM AMOUNT OF MANAGING GENERAL PARTNER'S REQUIRED CONTRIBUTION.
The Managing General Partner is required to:
(i) make aggregate Capital Contributions to the Partnership (including
Leases contributed pursuant to Section 3.03(b)(1)) of not less
than 25% of all Capital Contributions to the Partnership; and
(ii) 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. The Managing General Partner shall
contribute to the Partnership any deficit balance in its Capital Account upon
the occurrence of either of the following events:
(i) the liquidation of the Partnership; or
(ii) the liquidation of the Managing General Partner's interest in the
Partnership.
This shall be determined after taking into account all adjustments for the
Partnership's taxable year during which the liquidation occurs (other than
adjustments made pursuant to this requirement), by the end of the taxable year
in which its interest in the Partnership is liquidated or, if later, within 90
days after the date of 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).
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3.05. PAYMENT OF SUBSCRIPTIONS.
3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing General Partner
shall:
(i) contribute to the Partnership the Leases pursuant to Section
3.03(b)(1);
(ii) pay the costs charged to it when incurred by the Partnership,
subject to Section 3.04(b)(1); and
(iii) pay any optional subscription under Section 3.03(b)(2) in the same
manner as provided for the payment of Participant subscriptions.
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.
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);
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(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:
(i) any limitations as to the Horizons to be assigned to the
Partnership; and
(ii) subject to any burdens, as the Managing General Partner deems
necessary in its sole discretion.
4.01(a)(4). COST OF LEASES. All Leases shall be:
(i) acquired from the Managing General Partner or its Affiliates; and
(ii) credited towards the Managing General Partner's required Capital
Contribution set forth in Section 3.03(b)(1) at the Cost of the
Lease, unless the Managing General Partner 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:
(i) supported by an appraisal from an Independent Expert; and
(ii) maintained in the Partnership's records for six years along with
associated supporting information.
4.01(a)(5). THE MANAGING GENERAL PARTNER, OPERATOR OR THEIR AFFILIATES' RIGHTS
IN THE REMAINDER INTERESTS. To the extent the Partnership does not acquire a
full interest in a Lease from the Managing General Partner or its Affiliates,
the remainder of the interest in the Lease may be held by the Managing General
Partner or its Affiliates. They may either:
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(i) retain and exploit the remaining interest for their own account;
or
(ii) sell or otherwise dispose of all or a part of the remaining
interest.
Profits from the exploitation and/or disposition of their retained interests in
the Leases shall be for the benefit of the Managing General Partner or its
Affiliates to the exclusion of the Partnership.
4.01(a)(6). NO BREACH OF DUTY. Subject to the provisions of 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:
(i) the Managing General Partner;
(ii) the Operator;
(iii) their Affiliates; or
(iv) in the name of any nominee designated by the Managing General
Partner to facilitate the acquisition of the properties.
4.01(c)(2). MANAGING GENERAL PARTNER'S DISCRETION. The Managing General Partner
shall take the steps which are necessary in its best judgment to render title to
the Leases to be acquired by the Partnership acceptable for the purposes of the
Partnership. The Managing General Partner shall be free, however, to use its own
best judgment in waiving title requirements.
The Managing General Partner shall not be liable to the Partnership or to the
other parties for any mistakes of judgment; nor shall the Managing General
Partner be deemed to be making any warranties or representations, express or
implied, as to the validity or merchantability of the title to the Leases
assigned to the Partnership or the extent of the interest covered thereby except
as otherwise provided in the Drilling and Operating Agreement.
4.01(c)(3). COMMENCEMENT OF OPERATIONS. The Partnership shall not begin
operations on the Leases acquired by the Partnership unless the Managing General
Partner is satisfied that necessary title requirements have been satisfied.
4.02. CONDUCT OF OPERATIONS.
4.02(a). IN GENERAL. The Managing General Partner shall establish a program of
operations for the Partnership. Subject to the limitations contained in Article
III of this Agreement concerning the maximum Capital Contribution which can be
required of a Limited Partner, the Managing General Partner, the Limited
Partners, and the Investor General Partners agree to participate in the program
so established by the Managing General Partner.
4.02(b). MANAGEMENT. Subject to any restrictions contained in this Agreement,
the Managing General Partner shall exercise full control over all operations of
the Partnership.
4.02(c). GENERAL POWERS OF THE MANAGING GENERAL PARTNER.
4.02(c)(1). IN GENERAL. Subject to the provisions of Section 4.03 and its
subsections, and to any authority which may be granted the Operator under
Section 4.02(c)(3)(b), the Managing General Partner shall have full authority to
do all things deemed necessary or desirable by it in the conduct of the business
of the Partnership. Without limiting the generality of the foregoing, the
Managing General Partner is expressly authorized to engage in:
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(i) the making of all determinations of which Leases, wells and
operations will be participated in by the Partnership, which
includes:
(a) which Leases are developed;
(b) which Leases are abandoned; or
(c) which leases are sold or assigned to other parties,
including other investor ventures organized by the Managing
General Partner, the Operator, or any of their Affiliates;
(ii) the negotiation and execution on any terms deemed desirable in its
sole discretion of any contracts, conveyances, or other
instruments, considered useful to the conduct of the operations or
the implementation of the powers granted it under this Agreement,
including, without limitation:
(a) the making of agreements for the conduct of operations;
(b) the furnishing of equipment, facilities, supplies and
material, services, and personnel; and
(c) 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
$1,000,000 of seepage, pollution and contamination
insurance which protects and defends the insured against
property damage or bodily injury claims from third parties
(other than a co-owner of the Working Interest) alleging
seepage, pollution or contamination damage resulting from
an accident. The excess liability insurance shall be in
place and effective no later than the date drilling
operations begin and shall continue until the Investor
General Partners are converted to Limited Partners, at
which time the Partnership shall 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
Programs;
(vii) the use of the funds and revenues of the Partnership, and the
borrowing on behalf of, and the loan of money to, the Partnership,
on any terms it sees fit, for any purpose, including without
limitation:
(a) the conduct or financing, in whole or in part, of the
drilling and other activities of the Partnership;
(b) the conduct of additional operations; and
(c) the repayment of any such borrowings or loans used
initially to finance such operations or activities;
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(viii) the disposition, hypothecation, sale, exchange, release,
surrender, reassignment or abandonment of any or all assets of
the Partnership (including, without limitation, the Leases, wells,
equipment and production therefrom) provided that the sale of all
or substantially all of the assets of the Partnership shall only
be made as provided in 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:
(a) the employment of attorneys to advise and otherwise
represent the Partnership;
(b) the conduct of litigation and other incurring of
legal expense; and
(c) the settlement of claims and litigation;
(xi) the operation of producing wells drilled on the Leases 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 under this Agreement to any entity chosen
by it, including an entity related to it. The party shall have the same powers
in the conduct of the duties as would the Managing General Partner. The
delegation, however, shall not relieve the Managing General Partner of its
responsibilities under this Agreement.
4.02(c)(3)(b). DELEGATION TO OPERATOR. The Managing General Partner is
specifically authorized to delegate any or all of its duties to the Operator by
executing the Drilling and Operating Agreement. This delegation shall not
relieve the Managing General Partner of its responsibilities under this
Agreement.
In no event shall any consideration received for operator services be in excess
of 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. All Partnership Wells will be drilled
pursuant to the Drilling and Operating Agreement on a Cost plus 15% basis.
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The Managing General Partner or its Affiliates, as drilling contractor, is
subject to the following prohibitions:
(i) it may not receive a rate that is not competitive with the rates
charged by unaffiliated contractors in the same geographic region;
(ii) it may not enter into a turnkey drilling contract with the
Partnership;
(iii) it may not profit by drilling in contravention of its fiduciary
obligations to the Partnership; and
(iv) it 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 to this Agreement 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 to this Agreement authorizes the
attorney-in-fact to take any further action which the attorney-in-fact
considers necessary or advisable in connection with any of the foregoing.
Each party acknowledges that the power of attorney granted under this section:
(i) is a special power of attorney coupled with an interest and is
irrevocable; and
(ii) 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 the party's entire interest in the Partnership and the
purchaser, transferee or assignee of the interest, 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 the
attorney-in-fact to execute, acknowledge and file any agreement,
certificate, instrument or document necessary to effect the
substitution.
4.02(d)(2)(c). POWER OF ATTORNEY TO OPERATOR. The Managing General Partner
is hereby authorized to grant a Power of Attorney to the Operator on behalf
of the Partnership.
4.02(e). BORROWINGS AND USE OF PARTNERSHIP REVENUES.
4.02(e)(1). POWER TO BORROW OR USE PARTNERSHIP REVENUES.
4.02(e)(1)(a). IN GENERAL. If additional funds over the Participants'
Capital Contributions are needed for Partnership operations, then the
Managing General Partner may:
(i) use Partnership revenues for such purposes; or
(ii) the Managing General Partner and its Affiliates may advance to the
Partnership the funds necessary pursuant to Section 4.03(d)(8)(b),
although they are not obligated to advance the funds to the
Partnership.
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4.02(e)(1)(b). LIMITATION ON BORROWING. The borrowings (other than credit
transactions on open account customary in the industry to obtain goods and
services) shall be subject to the following limitations:
(i) the borrowings must be without recourse to the Investor General
Partners and the Limited Partners except as otherwise provided in
this Agreement; and
(ii) the amount that may be borrowed at any one time may not exceed an
amount equal to 5% of the Partnership Subscription.
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 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 other than as provided under the
Pennsylvania Revised Uniform Limited Partnership Act. Limited Partners shall
not be personally liable for any debts of the Partnership or any of the
obligations or losses of the Partnership beyond the amount of their agreed
Capital Contributions unless:
(i) they also subscribe to the Partnership as Investor General
Partners; or
(ii) 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. Beginning with the
2000 calendar year, the Partnership shall provide each Participant an annual
report within 120 days after the close of the calendar year, and beginning
with the 2001
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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 are not required to be audited.
(ii) A summary itemization, by type and/or classification of the total
fees and compensation including any unaccountable, fixed payment
reimbursements for Administrative Costs and Operating Costs, paid
by the Partnership, or indirectly on behalf of the Partnership, to
the Managing General Partner, the Operator and their Affiliates.
In addition, Participants shall be provided the percentage that
the annual unaccountable, fixed fee reimbursement for
Administrative Costs bears to annual Partnership revenues.
(iii) A description of each Prospect in which the Partnership owns an
interest, including:
(a) the cost, location, and number of acres under Lease; and
(b) the Working Interest owned in the Prospect by the
Partnership. Succeeding reports, however, must only
contain material changes, if any, regarding the Prospects.
(iv) A list of the wells drilled or abandoned by the Partnership during
the period of the report (indicating whether each of the wells has
or has not been completed), and a statement of the cost of each
well completed or abandoned. Justification must be included for
wells abandoned after production has begun.
(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 the following:
(i) his federal income tax return;
(ii) any required state income tax return; and
(iii) any other reporting or filing requirements imposed by any
governmental agency or authority.
4.03(b)(3). RESERVE REPORT. Annually, beginning January 1, 2002 the
Partnership shall provide to each Participant the following:
(i) a computation of the total oil and gas Proved Reserves of the
Partnership;
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(ii) a computation of 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;
(iii) a statement of each Participant's interest in the reserves; and
(iv) an estimate of the time required for the extraction of the
reserves with a statement that because of the time period required
to extract the reserves the present value of revenues to be
obtained in the future is less than if immediately receivable.
The reserve computations shall be based on engineering reports prepared by the
Managing General Partner and reviewed by an Independent Expert.
Also, if there is an event which leads to the 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, then a computation and
estimate must be sent to each Participant within 90 days.
4.03(b)(4). COST OF REPORTS. The cost of all reports described 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 which
includes:
(i) a record that a Participant meets the suitability standards
established in connection with an investment in the Partnership;
and
(ii) of fair market value as set forth in Section 4.01(a)(4).
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 his
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 the refusal or neglect. It shall be a
defense
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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 the 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:
(i) the California Commissioner of Corporations; and
(ii) the securities commissions of other states which request the
report.
4.03(c). MEETINGS OF PARTICIPANTS.
4.03(c)(1). PROCEDURE FOR A PARTICIPANT MEETING.
4.03(c)(1)(a). MEETINGS MAY BE CALLED BY MANAGING GENERAL PARTNER OR
PARTICIPANTS. Meetings of the Participants may be called as follows:
(i) by the Managing General Partner; or
(ii) by Participants whose 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.
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) dissolve the Partnership;
(ii) remove the Managing General Partner and elect a new Managing
General Partner;
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(iii) elect a new Managing General Partner if the Managing General
Partner elects to withdraw from the Partnership;
(iv) remove the Operator and elect a new Operator;
(v) approve or disapprove the sale of all or substantially all of the
assets of the Partnership;
(vi) cancel any contract for services with the Managing General
Partner, the Operator, or their Affiliates without penalty upon 60
days notice; and
(vii) amend this Agreement; provided however:
(a) any amendment may not increase the duties or liabilities of
any Participant or the Managing General Partner or increase
or decrease the profit or loss sharing or required Capital
Contribution of any Participant or the Managing General
Partner without the approval of the Participant or the
Managing General Partner; and
(b) any amendment may not affect the classification of
Partnership income and loss for federal income tax purposes
without the unanimous approval of all Participants.
4.03(c)(3). RESTRICTIONS ON MANAGING GENERAL PARTNER'S VOTING RIGHTS. With
respect to Units owned by the Managing General Partner or its Affiliates, the
Managing General Partner and its Affiliates may vote or consent on all matters
other than the following:
(i) the matters set forth in Section 4.03(c)(2)(ii) and (iv) above; or
(ii) 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.
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
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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 if the following conditions are met:
(i) the geological feature to which the well will be drilled
contains Proved Reserves; and
(ii) the drilling or spacing unit protects against drainage.
With respect to an oil and gas Prospect located in Ohio, Pennsylvania and New
York on which a well will be drilled by the Partnership to test the
Clinton/Medina geological formation or the Mississippian/Upper Devonian
Sandstone reservoirs, a Prospect shall be deemed to consist of the drilling
and spacing unit if it meets the test in the preceding sentence. Within five
years of the drilling of the Partnership Well neither the Managing General
Partner nor its Affiliates may drill any well in the Clinton/Medina
geological formation within 1,650 feet of an existing Partnership Well in
Pennsylvania or within 1,000 feet of an existing Partnership Well in Ohio or
in the Mississippian/Upper Devonian Sandstone reservoirs within 1,000 feet of
an existing 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 or the Mississippian/Upper Devonian Sandstone reservoirs shall not
be enlarged or contracted if the Prospect was limited to the drilling or
spacing unit because the well was being drilled to Proved Reserves in the
geological formation and the drilling or spacing unit protected against
drainage.
4.03(d)(2). TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS
AFFILIATES' ENTIRE INTEREST. A sale, transfer or a conveyance to the
Partnership of less than all of the ownership of the Managing General Partner
or an Affiliate (excluding another Program in which the interest of the
Managing General Partner or its Affiliates is substantially similar to or
less than their interest in the Partnership) in any Prospect shall not be
made unless:
(i) the interest retained by the Managing General Partner or the
Affiliate is a proportionate Working Interest;
(ii) the respective obligations of the Managing General Partner or its
Affiliates and the Partnership are substantially the same after
the sale of the interest by the Managing General Partner or its
Affiliates; and
(iii) the Managing General Partner's interest in revenues does not
exceed the amount proportionate to its retained Working Interest.
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.
4.03(d)(4). LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND
ITS AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. During a period of five
years after the Offering Termination Date of the Partnership, if the Managing
General Partner or any of its Affiliates (excluding another Program in which
the interest of the Managing General Partner or its Affiliates is
substantially similar to or less than their interest in the Partnership)
proposes to acquire an interest from an unaffiliated person in a Prospect in
which the Partnership possesses an interest or in a Prospect in which the
Partnership's interest has been terminated without compensation within one
year preceding the proposed acquisition, the following conditions shall apply:
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(i) if the Managing General Partner or the Affiliate (excluding
another Program in which the interest of the Managing General
Partner or its Affiliates is substantially similar to or less than
their interest in the Partnership) does not currently own property
in the Prospect separately from the Partnership, then neither the
Managing General Partner nor the Affiliate shall be permitted to
purchase an interest in the Prospect; and
(ii) if the Managing General Partner or the Affiliate (excluding
another Program in which the interest of the Managing General
Partner or its Affiliates is substantially similar to or less than
their interest in the Partnership) currently owns a proportionate
interest in the Prospect separately from the Partnership, then the
interest to be acquired shall be divided between the Partnership
and the Managing General Partner or the Affiliate in the same
proportion as is the other property in the Prospect. Provided,
however, if cash or financing is not available to the Partnership
to enable it to complete a purchase of the additional interest to
which it is entitled, then neither the Managing General Partner
nor the Affiliate shall be permitted to purchase any additional
interest in the Prospect.
4.03(d)(5). TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The
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 therefore is competitive with
the compensation, price or rental of other persons in the area
engaged in the business of rendering comparable services or
selling or leasing comparable equipment and supplies which could
reasonably be made available to the Partnership.
If the person is not engaged in such a business, then the compensation, price or
rental shall be the Cost of the services, equipment or supplies to the person or
the competitive rate which could be obtained in the area, whichever is less.
4.03(d)(7)(b). IF NOT DISCLOSED IN THE PROSPECTUS OR THIS AGREEMENT THEN
SERVICES BY THE MANAGING GENERAL PARTNER MUST BE DESCRIBED IN A SEPARATE
CONTRACT AND CANCELABLE. Any services for which the Managing General Partner
or an Affiliate is to receive compensation other than those described in this
Agreement or the Prospectus shall be set forth in a written contract which
precisely describes the services to be rendered and all compensation to be
paid. These contracts are cancelable without penalty upon 60 days written
notice by Participants whose Agreed Subscriptions equal a majority of the
Partnership Subscription.
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4.03(d)(8). LOANS.
4.03(d)(8)(a). NO LOANS FROM THE PARTNERSHIP. No loans or advances shall be
made by the Partnership to the Managing General Partner or any Affiliate.
4.03(d)(8)(b). LOANS TO THE PARTNERSHIP. Neither the Managing General Partner
nor any Affiliate shall loan money to the Partnership if the interest to be
charged exceeds either:
(i) the Managing General Partner's or the Affiliate's interest cost;
or
(ii) that which would be charged to the Partnership (without reference
to the Managing General Partner's or the Affiliate's financial
abilities or guarantees) by unrelated lenders, on comparable loans
for the same purpose.
Neither the Managing General Partner nor any Affiliate shall receive points or
other financing charges or fees, regardless of the amount, although the actual
amount of the charges incurred from third-party lenders may be reimbursed to the
Managing General Partner or the Affiliate.
4.03(d)(9). 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. Subject to Section 4.06(c), all benefits
from marketing arrangements or other relationships affecting the property of the
Managing General Partner or its Affiliates and the Partnership shall be fairly
and equitably apportioned according to the respective interests of each in the
property. The Managing General Partner shall treat all wells in a geographic
area equally concerning to whom and at what price the Partnership's 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.
4.03(d)(13). ADVANCE PAYMENTS. Advance payments by the Partnership to the
Managing General Partner and its Affiliates are prohibited except when advance
payments are required to secure the tax benefits of prepaid Intangible Drilling
Costs and for a business purpose.
4.03(d)(14). NO REBATES. No rebates or give-ups may be received by the
Managing General Partner or any Affiliate nor may the Managing General Partner
or any Affiliate participate in any reciprocal business arrangements which would
circumvent these guidelines.
4.03(d)(15). PARTICIPATION IN OTHER PARTNERSHIPS. If the Partnership
participates in other partnerships or joint ventures (multi-tier arrangements),
then the terms of any of these arrangements shall not result in the
circumvention of any of the requirements or prohibitions contained in this
Agreement, including the following:
(i) there shall be no duplication or increase in organization and
offering 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.
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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. Thus, an issuer
using the appraisal shall be subject to liability for violation of Section 11 of
the Securities Act of 1933 and comparable provisions under state law for any
material misrepresentations or material omissions in the appraisal.
Partnership assets shall be appraised on a consistent basis. The appraisal shall
be based on all relevant information, including current reserve estimates
prepared by an independent petroleum consultant, and shall indicate the value of
the Partnership's assets as of a date immediately before the announcement of the
proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation
of the Partnership's assets over a 12-month period.
The terms of the engagement of the Independent Expert shall clearly state that
the engagement is for the benefit of the Partnership and the Participants. A
summary of the independent appraisal, indicating all material assumptions
underlying the appraisal, shall be included in a report to the Participants in
connection with a proposed Roll-Up.
4.03(d)(16)(b). RIGHTS OF PARTICIPANTS WHO VOTE AGAINST PROPOSAL. In
connection with a proposed Roll-Up, Participants who vote "no" on the proposal
shall be offered the choice of:
(i) accepting the securities of the Roll-Up Entity offered in the
proposed Roll-Up;
(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.
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.
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4.03(d)(18). TRANSACTIONS MUST BE FAIR AND REASONABLE. Neither the Managing
General Partner nor any Affiliate shall sell, transfer, or convey any property
to or purchase any property from the Partnership, directly or indirectly,
except:
(i) pursuant to transactions that are fair and reasonable; nor
(ii) take any action with respect to the assets or property of the
Partnership which does not primarily benefit the Partnership.
4.04. DESIGNATION, COMPENSATION AND REMOVAL OF MANAGING GENERAL PARTNER AND
REMOVAL OF OPERATOR.
4.04(a). MANAGING GENERAL PARTNER.
4.04(a)(1). TERM OF SERVICE. Atlas shall serve as the Managing General Partner
of the Partnership until either:
(i) it is removed pursuant to Section 4.04(a)(3); or
(ii) it withdraws pursuant to Section 4.04(a)(3)(f).
4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. In addition to the
compensation set forth in Sections 4.01(a)(4) and 4.02(d)(1), the Managing
General Partner shall receive the compensation set forth in Sections
4.04(a)(2)(b) through 4.04(a)(2)(g).
4.04(a)(2)(a). CHARGES MUST BE NECESSARY AND REASONABLE. Charges by the
Managing General Partner for goods and services must be fully supportable as to
(i) the necessity of the goods and services; and
(ii) the reasonableness of the amount charged.
All actual and necessary expenses incurred by the Partnership may be paid out of
the Partnership 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. The unaccountable, fixed payment reimbursement
of $75 per well per month shall be subject to the following:
(i) it shall not be increased in amount during the term of the
Partnership;
(ii) it shall be proportionately reduced to the extent the Partnership
acquires less than 100% of the Working Interest in the well;
(iii) it shall be the entire payment to reimburse the Managing General
Partner for the Partnership's Administrative Costs; and
(iv) it shall not be received for plugged or abandoned wells.
4.04(a)(2)(d). GAS GATHERING. A limited partnership in which a subsidiary of
Atlas America, Inc. serves as general partner, Atlas Pipeline Partners, L.P.,
shall receive a gathering fee for gathering, compressing and transporting the
Partnership's gas at a competitive rate.
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;
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(iii) a .5% reimbursement of marketing expenses; and
(iv) a .5% reimbursement of the Selling Agents' bona fide accountable
due diligence expenses.
4.04(a)(2)(f). DRILLING AND OPERATING AGREEMENT. The Managing General Partner
and its Affiliates shall receive compensation as set forth in the Drilling and
Operating Agreement.
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.
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Notwithstanding any other provision in this Agreement, the Partnership or the
successor Managing General Partner shall not:
(i) be a party to any gas supply agreement that the Managing General
Partner or its Affiliates enters into with a third-party; or
(ii) have any rights pursuant to such gas supply agreement.
Further, the Partnership or the successor Managing General 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. If the Managing General Partner withdraws an interest, then the Managing
General Partner shall:
(i) pay the expenses of withdrawing; and
(ii) fully indemnify the Partnership against any additional expenses
which may result from a partial withdrawal of its interests
including insuring that Participants do not have a greater amount
of Direct Costs or Administrative Costs allocated to them.
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 by them 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.
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4.05(a)(2). STANDARDS FOR MANAGING GENERAL PARTNER INDEMNIFICATION. The
Managing General Partner, the Operator, and their Affiliates shall be
indemnified by the Partnership against any losses, judgments, liabilities,
expenses and amounts paid in settlement of any claims sustained by them in
connection with the Partnership, provided that:
(i) the Managing General Partner, the Operator, and their Affiliates
determined in good faith that the course of conduct which caused
the loss or liability was in the best interest of the Partnership;
(ii) the Managing General Partner, the Operator, and their Affiliates
were acting on behalf of, or performing services for, the
Partnership; and
(iii) the course of conduct was not the result of negligence or
misconduct of the Managing General Partner, the Operator, or their
Affiliates.
Provided, however, payments arising from such indemnification or agreement to
hold harmless are recoverable only out of the following:
(i) the tangible net assets of the Partnership;
(ii) revenues from operations; and
(iii) 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
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(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.
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:
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(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 in this
Agreement; 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 in this Agreement, 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 the opportunity
either:
(i) cannot be pursued by the Partnership because of insufficient
funds; or
(ii) it is not appropriate for the Partnership under the existing
circumstances.
4.06(b). MANAGING GENERAL PARTNER MAY MANAGE MULTIPLE PARTNERSHIPS. The
Managing General Partner or its Affiliates may manage multiple Programs
simultaneously.
4.06(c). PARTNERSHIP HAS NO INTEREST IN GAS CONTRACTS OR PIPELINES AND
GATHERING SYSTEMS. Notwithstanding any other provision in this Agreement, the
Partnership shall not:
(i) be a party to any gas supply agreement that the Managing General
Partner, the Operator, or their Affiliates enter into with a
third-party; or
(ii) 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 COSTS. Organization 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 Costs paid by the Managing General Partner up to and including
4.5% of the Partnership Subscription. Any Organization Costs in excess of
4.5% 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.
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5.01(a)(2). DEALER-MANAGER FEE, SALES COMMISSIONS, REIMBURSEMENT OF
MARKETING EXPENSES, AND REIMBURSEMENT FOR BONA FIDE ACCOUNTABLE DUE DILIGENCE
EXPENSES. The Dealer-Manager fee, Sales Commissions, and reimbursement for
bona fide accountable due diligence expenses payable to the Dealer-Manager
shall be charged 100% to the Participants. The reimbursement of marketing
expenses payable to the Dealer-Manager shall be charged 100% to the Managing
General Partner.
5.01(a)(3). INTANGIBLE DRILLING COSTS. Intangible Drilling Costs shall be
charged 100% to the Participants.
5.01(a)(4). TANGIBLE COSTS. Tangible Costs shall be charged 100% to the
Managing General Partner.
5.01(a)(5). 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)(6). ALLOCATION OF INTANGIBLE DRILLING COSTS AT PARTNERSHIP CLOSINGS.
Intangible Drilling 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)(7). LEASE COSTS. The Leases shall be contributed to the Partnership
by the Managing General Partner as set forth in Section 4.01(a)(4).
5.01(b). REVENUES. Revenues 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.
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
the 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 the equipment in the ratio in which the costs were charged.
5.01(b)(4). OTHER REVENUES. Subject to Section 5.01(b)(4)(a), all other
revenues of the Partnership shall be credited as follows: before Net of Tax
Savings Payout and Partnership Payout the Participants and the Managing
General Partner shall share in
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Partnership revenues in the same percentage as their respective Capital
Contribution bears to the total Partnership Capital Contributions. For
example, if the Managing General Partner contributes 25% of the total
Partnership Capital Contributions and the Participants contribute 75% of the
total Partnership Capital Contributions, then the Managing General Partner
will receive 25% of the Partnership revenues and the Participants will
receive 75% of the Partnership revenues.
After Net of Tax Savings Payout the Managing General Partner shall receive an
additional 6.5% of the Partnership revenues, and after Partnership Payout the
Managing General Partner shall receive an additional 8.5% of the Partnership
revenues for a total additional amount of 15% of Partnership revenues. In the
above example, after Net of Tax Savings Payout but before Partnership Payout
the Managing General Partner would receive 31.5% of the Partnership revenues
and the Participants would receive 68.5% of the Partnership revenues. After
Partnership Payout the Managing General Partner would then receive 40% of the
Partnership revenues and the Participants would receive 60% of the
Partnership revenues.
5.01(b)(4)(a). SUBORDINATION. The Managing General Partner shall
subordinate up to 50% of its share of Partnership Net Production Revenues to
the receipt by Participants of cash distributions from the Partnership equal
to 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 50% of its share of Partnership Net Production
Revenues (I.E., net of the related costs as provided in Section 5.01(a)(5))
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.
The Managing General Partner's subordination obligation shall be further subject
to the following conditions:
(i) the 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);
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(ii) the Managing General Partner shall not be required to return
Partnership distributions previously received by it, even though a
subordination obligation arises after the distributions;
(iii) 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; and
(iv) subject to the foregoing provisions of this section, only
Partnership revenues in the current distribution period shall be
debited or credited to the Managing General Partner as may be
necessary to provide, to the extent possible, 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 under
this Agreement, the Managing General Partner may adopt any method of allocation
which it, in its reasonable discretion, selects, if, in its sole discretion
based on advice from its legal counsel or accountants, a revision to the
allocations is required for the allocations to be recognized for federal income
tax purposes either because of the promulgation of Treasury Regulations or other
developments in the tax law. Any new allocation provisions shall be provided by
an amendment to this Agreement and shall be made in a manner that would result
in the most favorable aggregate consequences to the Participants as nearly as
possible consistent with the original allocations described in this Agreement.
5.02. CAPITAL ACCOUNTS AND ALLOCATIONS THERETO.
5.02(a). CAPITAL ACCOUNTS FOR EACH PARTY TO THE AGREEMENT. A single, separate
Capital Account shall be established for each party 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;
(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
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(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 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.
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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 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,
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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 the
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 the debt at the beginning of the year shall be allocated
items of Partnership income and gain in accordance with Treas. Reg. Section
1.704-2(i).
5.03(j). PARTNERS' ALLOCABLE SHARES. Except as otherwise provided in this
Agreement, each 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, the allocable share shall be based on
actual income, gain, loss, deductions and credits economically accrued each
day during the taxable year in proportion to each 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 partnership provisions of Subchapter K of the
Code.
5.04(c). CONTINGENT INCOME. If it is determined that any taxable income
results to any party by reason of its entitlement to a share of profits or
revenues of the Partnership before the profit or revenue has been realized by
the Partnership, the resulting deduction as well as any resulting gain, shall
not enter into Partnership net income or loss but shall be separately
allocated to the party.
5.04(d). 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.
5.05(a)(3). NO BORROWINGS. In no event, however, shall funds 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. The determination of revenues and costs shall be made in accordance
with generally accepted accounting principles, consistently applied.
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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 of these funds shall be deposited in a separate interest
bearing account for the benefit of the Partnership, and the total amount so
retained and deposited shall not exceed the Managing General Partner's
reasonable estimate of 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 to
this Agreement 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 under this
Agreement, other than the right to receive all or part of the share of the
profits, losses, income, gain, credits and cash distributions or returns of
capital to which his assignor would otherwise be entitled.
6.01(b). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER
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.
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
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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. Transfers are subject to the following general
conditions:
(i) 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;
(ii) the costs and expenses associated with the assignment must be paid
by the assignor Participant;
(iii) the assignment must be in a form satisfactory to the Managing
General Partner; and
(iv) the terms of the assignment must not contravene those of this
Agreement.
Transfers of 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
unless there is either:
(i) an effective registration of the Units under the Securities Act of
1933, as amended, and qualification under applicable state
securities laws; or
(ii) an opinion of counsel acceptable to the Managing General Partner
that 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;
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(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.
6.02(a)(3)(b). RIGHTS OF SUBSTITUTE PARTICIPANT. A substitute Participant
is entitled to all of the rights attributable to full ownership of the
assigned Units including the right to vote.
6.02(b). EFFECT OF TRANSFER.
6.02(b)(1). AMENDMENT OF RECORDS. The Partnership shall amend its records
at least once each calendar quarter to effect the substitution of substituted
Participants.
Any transfer permitted under this Agreement when the assignee does not become
a substituted Participant shall be effective:
(i) as of midnight of the last day of the calendar month in which it
is made; or
(ii) at the Managing General Partner's election, 7:00 A.M. of the
following day.
6.02(b)(2). TRANSFER DOES NOT RELIEVE TRANSFEROR OF CERTAIN COSTS. No
transfer (including a transfer of less than all of a party's rights under
this Agreement or the transfer of rights under this Agreement to more than
one party) shall relieve the transferor of its responsibility for its
proportionate part of any expenses, obligations and liabilities under this
Agreement related to the 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 under this Agreement, including the exercise of
any elections, as between the transferring parties and the remaining parties
to this Agreement to more than one party unanimously designated by the
transferees and, if he should have retained an interest under this Agreement,
the transferor.
6.02(b)(4). NOTICE. Until the Managing General Partner receives a proper
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 under this Agreement, to hypothecate, pledge,
or otherwise encumber, on any terms it chooses for its own general purposes
either:
(i) its Partnership interest; or
(ii) an undivided interest in the assets of the Partnership equal to or
less than its respective interest in the revenues of the
Partnership.
All repayments of such borrowings and costs and interest or other charges
related to the borrowings shall be borne and paid separately by the Managing
General Partner. In no event shall the repayments, costs, interest, or other
charges related to the borrowing be charged to the account of the
Participants.
In addition, subject to a required participation of not less than 1% 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:
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(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.
A Participant may present his Units in writing to the Managing General
Partner every year beginning in 2005 subject to the following conditions:
(i) the presentment must be made within 120 days of the reserve report
set forth in Section 4.03(b)(3);
(ii) in accordance with Treas. Reg. Section 1.7704-1(f), the repurchase
may not be made until at least 60 calendar days after the
Participant notifies the Partnership in writing of the
Participant's intention to exercise the repurchase right; and
(iii) the repurchase shall not be considered effective until the payment
has been made to the Participant in cash.
6.04(b). REQUIREMENT FOR INDEPENDENT PETROLEUM CONSULTANT. The amount
attributable to Partnership reserves shall be determined based upon the last
reserve report of the Partnership prepared by the Managing General Partner
and reviewed by an Independent Expert. The Managing General Partner shall
estimate the present worth of future net revenues attributable to the
Partnership's interest in the Proved Reserves. In making this estimate, the
Managing General Partner shall use the following terms:
(i) a discount rate equal to 10%;
(ii) a constant price for the oil; and
(iii) base the price of 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
Partnership items:
(i) an amount based on 70% of the present worth of future net revenues
from the Proved Reserves determined as described in Section
6.04(b);
(ii) cash on hand;
(iii) prepaid expenses and accounts receivable less a reasonable amount
for doubtful accounts; and
(iv) the estimated market value of all assets, not separately specified
above, determined in accordance with standard industry valuation
procedures.
There shall be deducted from the foregoing sum the following items:
(i) an amount equal to all debts, obligations, and other liabilities,
including accrued expenses; and
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(ii) any distributions made to the Participants between the date of the
request and the actual payment. However, if any cash distributed
was derived from the sale, after the presentment request, of 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 the report to the date of payment of the presentment
price to the Participants because of the following:
(i) the production or sales of, or additions to, reserves and lease
and well equipment, sale or abandonment of Leases, and similar
matters occurring before the request for repurchase; and
(ii) any of the following occurring before payment of the presentment
price to the selling Participants:
(a) changes in well performance;
(b) increases or decreases in the market price of oil, gas, or
other minerals;
(c) revision of regulations relating to the importing of
hydrocarbons;
(d) changes in income, ad valorem and other tax laws such as
material variations in the provisions for depletion; and
(e) similar matters.
6.04(e). SELECTION BY LOT. If less than all interests presented at any time
are to be purchased, then the Participants whose interests are to be
purchased will be selected by lot.
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 this purpose on terms it deems
reasonable.
In addition, the presentment feature may be conditioned, in the Managing
General Partner's sole discretion, on the Managing General Partner's receipt
of an opinion of counsel that the transfers will not cause the Partnership to
be treated as a "publicly traded partnership" under the Code.
The Managing General Partner shall hold the repurchased Units for its own
account and not for resale.
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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. The successor
limited partnership shall succeed to all of the assets of the Partnership. As
used throughout this Agreement, the term "Partnership" shall include the
successor limited partnerships and the parties to the successor limited
partnerships.
7.02. DISSOLUTION AND WINDING UP.
7.02(a). FINAL TERMINATING EVENT. 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:
(i) the end of the taxable year in which liquidation occurs
(determined without regard to Section 706(c)(2)(A) of the Code);
or
(ii) if later, within 90 days after the date of the liquidation.
Notwithstanding, the following amounts are not required to be distributed
within the foregoing time periods so long as the withheld amounts are
distributed as soon as practical:
(i) amounts withheld for reserves reasonably required for liabilities
of the Partnership; and
(ii) installment obligations owed to the Partnership.
7.02(c). IN-KIND DISTRIBUTIONS. 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 his 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
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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 under this Agreement shall be:
(i) in writing; and
(ii) given by mail or wire addressed to the party to receive the notice
at the address designated in Section 1.03.
If there is a transfer of rights under this Agreement, no notice to the
transferee shall be required, nor shall the transferee have any rights under
this Agreement, until notice shall have been given to the Managing General
Partner.
Any transfer of rights under this Agreement shall not increase the duty to
give notice. If there is a transfer of rights under this Agreement to more
than one party, then notice to any owner of any interest in the rights shall
be notice to all owners of the interest.
8.01(b). CHANGE IN ADDRESS. The address of any party to this Agreement may
be changed by:
(i) written notice to the Participants if there is a change of address
by the Managing General Partner; or
(ii) to the Managing General Partner if there is a change of address by
a Participant.
8.01(c). TIME NOTICE DEEMED GIVEN. If the notice is given by the Managing
General Partner, then the notice shall be considered given, and any
applicable time shall run, from the date the notice is placed in the mail or
delivered to the telegraph company.
If the notice is given by any Participant, then the notice shall be
considered given and any applicable time shall run from the date the notice
is received.
8.01(d). EFFECTIVENESS OF NOTICE. Any notice to a party other than the
Managing General Partner, including a notice requiring concurrence or
nonconcurrence, shall be effective, and any failure to respond binding,
irrespective of the following:
(i) whether or not the notice is actually received; or
(ii) any disability or death on the part of the noticee, even if the
disability or death is known to the party giving the notice.
8.01(e). FAILURE TO RESPOND. Except when this Agreement expressly requires
affirmative approval of a Participant, any Participant who fails to respond
in writing within the time specified to a request by the Managing General
Partner as set forth below for approval of or concurrence in a proposed
action shall be conclusively deemed to have approved the action. The
Managing General Partner shall send the first request and the time period
shall be not less than 15 business days from the date of mailing of the
request. If the Participant does not respond to the first request then the
Managing General Partner shall send a second request. If the Participant
does not respond within seven calendar days from the date of the mailing of
the second request then the Participant shall be conclusively deemed to have
approved the action.
8.02. TIME. Time is of the essence of each part of this Agreement.
8.03. APPLICABLE LAW. The terms and provisions of this Agreement shall be
construed under the laws of the 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.
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.
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<PAGE>
8.05. AMENDMENT.
8.05(a). PROCEDURE FOR AMENDMENT. No changes in this Agreement shall be
binding unless:
(i) proposed in writing by the Managing General Partner, and adopted
with the consent of Participants whose 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 to this
Agreement. The terms "Partnership," "Limited Partner," "Investor General
Partner," "Participant," "Partner," "Managing General Partner," "Operator,"
or "parties" shall equally apply to any successor limited partnership, and
any heir, devisee, personal representative, successor or assign of a party.
IN WITNESS WHEREOF, the parties hereto set their hands and seal as of the day
and year hereinabove shown.
ATLAS: ATLAS RESOURCES, INC.
Managing General Partner
By:
---------------------------------
Attest:
---------------------------------
(SEAL) Secretary
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<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 AMERICA PUBLIC #9 LTD.
The undersigned agrees:
1. to serve as the Managing General Partner of ATLAS AMERICA PUBLIC #9
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
Section 3.03(b)(1) of the Partnership Agreement; and
3. to subscribe to the Partnership as follows:
(a) $___________________ [________] Unit(s)] under Section 3.03(b)(2)
of the Partnership Agreement as a Limited Partner; or
(b) $___________________ [________] Unit(s)] under Section 3.03(b)(2)
of the Partnership Agreement as an Investor General Partner.
MANAGING GENERAL PARTNER:
Atlas Resources, Inc. Address:
By:________________________________ 311 Rouser Road
Moon Township, Pennsylvania 15108
ACCEPTED this ____ day of _________ , 2000.
ATLAS RESOURCES, INC.
MANAGING GENERAL PARTNER
By:_______________________________
Attest
_______________________________
(SEAL) Secretary
<PAGE>
EXHIBIT (I-B)
SUBSCRIPTION AGREEMENT
<PAGE>
ATLAS AMERICA PUBLLC #9 LTD.
_______________________________________________________________________________
SUBSCRIPTION AGREEMENT
_______________________________________________________________________________
I, the undersigned, hereby offer to purchase Units of Atlas America Public #9
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
America Public #9 Ltd. (as supplemented or amended from time to time). I
acknowledge and agree that my execution of this Subscription Agreement also
constitutes my execution of the 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 I agree to be bound by
all of the terms and conditions of the Partnership Agreement if my Agreed
Subscription is accepted by the Managing General Partner. I understand and
agree that I may not assign this offer, nor may it be withdrawn after it has
been accepted by the Managing General Partner. I hereby irrevocably
constitute and appoint Atlas Resources, Inc. (and its duly authorized agents)
my agent and attorney-in-fact, in my name, place and stead, to make, execute,
acknowledge, swear to, file, record and deliver the 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,
I hereby represent, warrant, covenant and agree as follows:
INVESTOR'S INITIALS
_____ I have received the Prospectus.
_____ I (other than if I am a Minnesota resident) recognize and understand
that:
- before this offering there has been no public market for the Units
and it is unlikely that after the offering there will be any such
market;
- the transferability of the Units is restricted; and
- in case of emergency or other change in circumstances I cannot
expect to be able to readily liquidate my investment in the Units.
_____ I am purchasing the Units for the following:
- my own account;
- for investment purposes and not for the account of others; and
- with no present intention of reselling them.
_____ If an individual, I am:
- a citizen of the United States of America; and
- at least twenty-one years of age.
_____ If a partnership, corporation or trust, then the members, stockholders
or beneficiaries thereof are citizens of the United States and each is
at least twenty-one years of age. I am empowered and duly authorized
under a governing document, trust instrument, charter, certificate of
incorporation, by-law provision or the like to enter into this
Subscription Agreement and to perform the transactions contemplated by
the Prospectus, including the exhibits thereto.
_____ (a) I have:
- 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
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- had during the last tax year, or estimate that I will have
during the current tax year, "taxable income" as defined in
Section 63 of the Code of at least $60,000, without regard to
an investment in the Partnership.
(b) IN ADDITION, IF I AM 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 I REPRESENT THAT I AM
AWARE OF AND MEET THAT STATE'S QUALIFICATIONS AND SUITABILITY
STANDARDS SET FORTH IN EXHIBIT (B) TO THE PROSPECTUS.
(c) If I am a fiduciary, then I am purchasing for a person or entity
having the appropriate income and/or net worth specified in (a) or
(b) above.
_____ I understand that if I am an Investor General Partner, then I will have
unlimited joint and several liability for Partnership obligations and
liabilities including amounts in excess of my Agreed Subscription to the
extent the obligations and liabilities exceed the following:
- 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.
_____ I understand that if I am a Limited Partner, then I may only use my
partnership losses to the extent of my net passive income from passive
activities in the year, with any excess losses being deferred.
_____ I understand that no state or federal governmental authority has made
any finding or determination relating to the fairness for public
investment of the Units and no state or federal governmental authority
has recommended or endorsed or will recommend or endorse the Units.
_____ I understand that the Selling Agent or registered representative is
required to inform me and the other potential investors of all pertinent
facts relating to the Units, including the following:
- the risks involved in the offering, including the speculative
nature of the investment and the speculative nature of drilling for
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.
THE ABOVE REPRESENTATIONS DO NOT CONSTITUTE A WAIVER OF ANY RIGHTS THAT I MAY
HAVE UNDER THE ACTS ADMINISTERED BY THE SEC OR BY ANY STATE REGULATORY AGENCY
ADMINISTERING STATUTES BEARING ON THE SALE OF SECURITIES.
INSTRUCTIONS TO INVESTOR
You are required to execute your own Subscription Agreement and the Managing
General Partner will not accept any Subscription Agreement that has been
executed by someone other than you unless the person has been given your
legal power of attorney to sign on your behalf and you meet all of the
conditions 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.
2
<PAGE>
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 I acknowledge the receipt of California Rule
260.141.11 set forth in Exhibit (B) to the Prospectus.
3
<PAGE>
_______________________________________________________________________________
SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
_______________________________________________________________________________
I, the undersigned, agree to purchase ________ Units of Participation at
$10,000 per Unit in ATLAS AMERICA PUBLIC #9 LTD. (the "Partnership") as
(check one):
/ / INVESTOR GENERAL PARTNER AGREED SUBSCRIPTION
/ / LIMITED PARTNER $ ___________________________
(______________________# Units)
INSTRUCTIONS
_______________________________________________________________________________
Make check payable to: "Atlas America Public #9 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. Additional Subscriptions in $1,000 increments. If
you are an individual investor you must personally sign this signature page
and provide the information requested below.
_______________________________________________________________________________
<TABLE>
<S> <C>
Subscriber (All individual investors must My Home Address (Do not use P.O. Box)
personally sign this Signature Page.)
_________________________________________________ ___________________________________________________
Print Name
_________________________________________________ ___________________________________________________
Signature
_________________________________________________ ___________________________________________________
Print Name
_________________________________________________
Signature
_________________________________________________
Name of Entity if a Trust, Corporation or
Partnership is Subscribing
Date: _______________ My Address for Distributions if Different from Above
___________________________________________________
___________________________________________________
My Telephone No.: Business _________________________ Home __________________ Email Address__________
My Tax I.D. No. (Social Security No.): _____________________________________________________________
(CHECK ONE): I am a: Calendar Year Taxpayer / / Fiscal Year Taxpayer / /
(CHECK ONE): OWNERSHIP OF THE UNITS- Tenants-in-Common / / Partnership / /
Joint Tenancy / / C Corporation / /
Individual / / S Corporation / /
Trust / / Community Property / /
Other / /
</TABLE>
1
<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>
<S> <C>
_________________________________________ _______________________________________________
Registered Representative Name and Number Name of Broker-Dealer
Registered Representative Office Address: _______________________________________________
CRD Number
_____________________________________________ _______________________________________________
Company Name (if other than Broker-Dealer Name)
_____________________________________________
_____________________________________________
Phone Number; Facsimile Number, Email Address
NOTICE TO BROKER-DEALER:
Send complete and signed DOCUMENTS
and THE CHECK to:
Mr. John S. Coffey
Anthem Securities, Inc.
P.O. Box 926
Coraopolis, Pennsylvania 15108-0911
(412) 262-1680
FACSIMILE: (412) 262-7430
EMAIL: [email protected]
________________________________________________________________________________
TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
________________________________________________________________________________
ACCEPTED THIS ______ day ATLAS RESOURCES, INC.,
of _________________ , 2000 MANAGING GENERAL PARTNER
Attest By:_______________________________________
_________________________________________
(SEAL) Secretary
</TABLE>
2
<PAGE>
EXHIBIT (II)
DRILLING AND OPERATING AGREEMENT
ATLAS AMERICA PUBLIC #9 LTD.
(THIS DRILLING AND OPERATING AGREEMENT WILL BE APPROPRIATELY
MODIFIED FOR OTHER AREAS OF THE UNITED STATES. THE AMOUNT OF THE WELL
SUPERVISION FEES WILL BE AS DESCRIBED IN
"COMPENSATION" IN THE PROSPECTUS.)
<PAGE>
INDEX
<TABLE>
<CAPTION>
SECTION PAGE
<S> <C>
1. Assignment of Well Locations; Representations; Designation of Additional Well Locations;
Outside Activities........................................................................................1
2. Drilling of Wells; Timing; Depth; Interest of Developer; Right of Substitution.............................2
3. Operator - Responsibilities in General; Covenants; Term.....................................................3
4. Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination;
Excess Funds if Dry Hole..................................................................................4
5. Title Examination of Well Locations; Liability for Title Defects............................................5
6. Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs;
Pipelines; Price Determinations; Plugging and Abandonment.................................................6
7. Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Records
and Reports; Additional Information.......................................................................7
8. Operator's Lien; Right to Collect From Gas Purchaser........................................................9
9. Successors and Assigns; Transfers; Appointment of Agent.....................................................9
10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability......................................10
11. Internal Revenue Code Election, Relationship of Parties; Right to Take Production in Kind..................11
12. Force Majeure..............................................................................................11
13. Term.......................................................................................................12
14. Governing Law and Invalidity...............................................................................12
15. Integration................................................................................................12
16. Waiver of Default or Breach................................................................................12
17. Notices....................................................................................................12
18. Interpretation.............................................................................................13
19. Counterparts...............................................................................................13
Signature Page.............................................................................................13
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 _______________, 2000, by and
between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter
referred to as "Atlas" or "Operator"),
and
ATLAS AMERICA PUBLIC #9 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) ASSIGNMENT OF WELL LOCATIONS. The Operator shall execute an
assignment of an undivided percentage of Working Interest in the Well Location
acreage for each well to the Developer as shown on Exhibit A attached hereto,
which assignment shall be limited to a depth from the surface to the 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) REPRESENTATIONS. As of the date hereof, the Operator represents and
warrants to the Developer that:
(i) 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;
(ii) the Operator has good right and authority to sell and
convey the same;
(iii) said rights, interest and property are free and clear
from all liens and encumbrances; and
(iv) 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
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<PAGE>
that, except as specifically set forth above, the Operator makes no warranty
or representation, express or implied, as to its title or the title of the
lessors in and to the lands or oil and gas interests covered by said Leases.
(c) DESIGNATION OF ADDITIONAL WELL LOCATIONS. 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:
(i) the undivided percentage of Working Interest and the
Oil and Gas Leases to be included as Leases hereunder;
(ii) the amount and configuration of acreage included in
each such Additional Well Location on maps attached as
exhibits to such addendum; and
(iii) their agreement that such Additional Well Locations
shall be developed in accordance with the terms and
conditions of this Agreement.
(d) OUTSIDE ACTIVITIES. 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; TIMING; DEPTH; INTEREST OF DEVELOPER; RIGHT OF
SUBSTITUTION.
(a) DRILLING OF WELLS. 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) TIMING. Operator will use its best efforts to commence drilling the
first well within thirty (30) days after the date of this Agreement and to
commence the drilling of each of said ______________ (_____) initial wells for
which payment is made pursuant to Section 4(b) of this Agreement, on or before
March 31, 2001. Subject to the foregoing time limits, Operator shall determine
the timing of and the order of the drilling of said ____________ (______)
Initial Well Locations.
(c) DEPTH. 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) INTEREST OF DEVELOPER. 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 2,500 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) RIGHT OF SUBSTITUTION. Notwithstanding the provisions of
sub-section (a) above, if the Operator or Developer determines in good faith,
with respect to any Well Location, before operations commence hereunder with
respect to such Well Location, based upon:
(i) the production (or failure of production) of any other
wells which may have been recently drilled in the
immediate area of such Well Location;
(ii) upon newly discovered title defects; or
2
<PAGE>
(iii) 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 therefore 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 United
States 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, then Operator shall promptly propose another substitute well location
pursuant to the provisions hereof.
Once the Developer accepts a substitute well location or does not
reject it within said seven (7) day period, this Agreement shall terminate as to
the original Well Location and the substitute well location shall become subject
to the terms and conditions hereof.
3. OPERATOR - RESPONSIBILITIES IN GENERAL; COVENANTS; TERM.
(a) OPERATOR - RESPONSIBILITIES IN GENERAL. Atlas shall be the Operator
of the wells and Well Locations subject to this Agreement and, as the
Developer's independent contractor, shall, in addition to its other obligations
hereunder do the following:
(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) COVENANTS. 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;
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<PAGE>
(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) TERM. Atlas shall serve as Operator hereunder until the earliest
of:
(i) the termination of this Agreement pursuant to Section
13 hereof;
(ii) the termination of Atlas as Operator by the Developer
which may be effected by the Developer at any time in
its discretion, with or without cause; upon sixty (60)
days advance written notice to the Operator; or
(iii) the resignation of Atlas as Operator hereunder which
may occur upon ninety (90) days' written notice to the
Developer at any time after five (5) years from the
date hereof, it being expressly understood and agreed
that Atlas shall have no right to resign as Operator
hereunder prior to the expiration of the aforesaid
five-year period.
Any successor Operator hereunder shall be selected by the Developer.
Nothing contained in this sub-section (c) shall relieve or release Atlas or the
Developer from any liability or obligation hereunder which accrued or occurred
prior to Atlas' removal or resignation as Operator hereunder. Upon any change in
Operator pursuant to this provision, the then present Operator shall deliver to
the successor Operator possession of all records, equipment, materials and
appurtenances used or obtained for use in connection with operations hereunder
and owned by the Developer.
4. OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS; PAYMENT;
COMPLETION DETERMINATION; EXCESS FUNDS IF DRY HOLE.
(a) OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS. All natural
gas wells which are drilled and completed hereunder shall be drilled and
completed on a Cost plus 15% basis. "Cost," when used with respect to services,
shall mean the reasonable, necessary and actual expenses incurred by Operator on
behalf of Developer in providing the services under this Agreement, determined
in accordance with generally accepted accounting principles. As used elsewhere,
"Cost" shall mean the price paid by Operator in an arm's-length transaction. The
estimated price for each of 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 2,500
feet of gathering line per well, geological and engineering services and
completing two (2) zones. Such estimated 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 estimated 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 Cost plus
15% basis.
(b) PAYMENT. The Developer shall pay to Operator, in proportion to the
share of the Working Interest owned by the Developer in the wells, one hundred
percent (100%) of the estimated Intangible Drilling Costs as hereinafter defined
for drilling and completing all initial wells upon execution of this Agreement,
which payment shall be nonrefundable in all events, in order to enable Operator
to do the following:
(i) commence site preparation for ________________ (______)
initial wells;
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(ii) obtain suitable subcontractors for the drilling and
completion of such wells at currently prevailing
prices; and
(iii) insure the availability of equipment and materials.
Atlas' payments for the Tangible Costs as hereinafter defined of drilling and
completing all initial wells as the Managing General Partner of the Developer
shall be paid within five (5) business days of notice from Operator that such
costs have been incurred.
For purposes of this Agreement, "Intangible Drilling Costs" shall mean
those expenditures associated with property acquisition and the drilling and
completion of oil and gas wells that under present law are generally accepted as
fully deductible currently for federal income tax purposes. This includes all
expenditures made with respect to any well before the establishment of
production in commercial quantities for wages, fuel, repairs, hauling, supplies
and other costs and expenses incident to and necessary for the drilling of the
well and the preparation of the well for the production of oil or gas, that are
currently deductible pursuant to Section 263(c) of the Internal Revenue Code of
1986, as amended, (the "Code"), and Treasury Reg. Section 1.612-4, which are
generally termed "intangible drilling and development costs," including the
expense of plugging and abandoning any well before a completion attempt.
"Tangible Costs" shall mean those costs associated with the drilling and
completion of oil and gas wells which are generally accepted as capital
expenditures pursuant to the provisions of the Code. This includes all costs of
equipment, parts and items of hardware used in drilling and completing a well,
and those items necessary to deliver acceptable oil and gas production to
purchasers to the extent installed downstream from the wellhead of any well and
which are required to be capitalized pursuant to applicable provisions of the
Code and regulations promulgated thereunder.
With respect to each additional well drilled on the Additional Well
Locations, if any, Developer shall pay Operator, in proportion to the share of
the Working Interest owned by the Developer in the wells, one hundred percent
(100%) of the estimated Intangible Drilling Costs for such well upon execution
of the applicable addendum pursuant to Section l(c) above, which payment shall
be nonrefundable in all events, in order to enable Operator to do the following:
(i) commence site preparation;
(ii) obtain suitable subcontractors for the drilling and
completion of such wells at currently prevailing
prices; and
(iii) insure the availability of equipment and materials.
Atlas' payments for the Tangible Costs of drilling and completing all additional
wells as the Managing General Partner of the Developer shall be paid within five
(5) business days of notice from Operator that such costs have been incurred.
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 therefore.
(c) COMPLETION DETERMINATION. Operator shall determine whether or not
to run the production casing for an attempted completion or to plug and abandon
any well drilled 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) EXCESS FUNDS IF DRY HOLE. 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. Any Intangible Drilling Costs paid by Developer with respect to such dry
hole which exceed Operator's price specified in sub-section (a) above for such
dry hole shall be retained by Operator and shall be applied to the Intangible
Drilling Costs for an additional well or wells to be drilled on the Additional
Well Locations or to cost overruns over the estimated price for Intangible
Drilling Costs, if any, on one or more of the other initial or additional
wells, to be drilled by Operator on Developer's behalf.
5. TITLE EXAMINATION OF WELL LOCATIONS; LIABILITY FOR TITLE DEFECTS.
(a) TITLE EXAMINATION OF WELL LOCATIONS. 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
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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) LIABILITY FOR TITLE DEFECTS. 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; FEE ADJUSTMENTS;
EXTRAORDINARY COSTS; PIPELINES; PRICE DETERMINATIONS; PLUGGING AND ABANDONMENT.
(a) OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS. 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:
(i) well tending, routine maintenance and adjustment;
(ii) reading meters, recording production, pumping,
maintaining appropriate books and records;
(iii) preparing reports to the Developer and government
agencies; and
(iv) collecting and disbursing revenues.
The operating fees shall not cover costs and expenses related to the
following:
(i) the production and sale of oil;
(ii) the collection and disposal of salt water or other
liquids produced by the wells;
(iii) the rebuilding of access roads; and
(iv) the purchase of equipment, materials or third party
services, which, subject to the provisions of
sub-section (c) of this Section 6, shall be paid by the
Developer in proportion to the share of the Working
Interest owned by the Developer in the wells.
Any well which is temporarily abandoned or shut-in continuously for the
entire month shall not be considered a producing well for purposes of
determining the number of wells in such month subject to the aforesaid operating
fee.
(b) FEE ADJUSTMENTS. The monthly operating fee set forth in
sub-section (a) above may in the following manner be adjusted annually as of
the first day of January (the "Adjustment Date") each year beginning January
l, 2002. 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,
2000, in the case of the first adjustment, and since the previous Adjustment
Date, in the case of each subsequent adjustment.
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(c) EXTRAORDINARY COSTS. Without the prior written consent of the
Developer, pursuant to a written estimate submitted by Operator, Operator shall
not undertake any single project or incur any extraordinary cost with respect to
any well being produced hereunder reasonably estimated to result in an
expenditure of more than $5,000, unless such project or extraordinary cost is
necessary for the following:
(i) to safeguard persons or property; or
(ii) to protect the well or related facilities in the event
of a sudden emergency.
In no event, however, shall the Developer be required to pay for any
project or extraordinary cost arising from the negligence or misconduct of
Operator, its agents, servants, employees, contractors, licensees or invitees.
All extraordinary costs incurred and the cost of projects undertaken
with respect to a well being produced 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) PIPELINES. 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) PRICE DETERMINATIONS. 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) PLUGGING AND ABANDONMENT. 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.
7. BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS;
DISBURSEMENTS; RECORDS AND REPORTS; ADDITIONAL INFORMATION.
(a) BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF
WELLS. Operator shall promptly and timely pay and discharge on behalf of the
Developer, in proportion to the share of the Working Interest owned by the
Developer in the wells, 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.
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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) DISBURSEMENTS. Operator shall disburse to the Developer, on a
monthly basis, the Developer's share of the proceeds received from the sale
of oil and/or gas sold from the wells operated 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) RECORDS AND REPORTS. In addition to the statements required under
sub-section (b) above, Operator, within seventy-five (75) days after the
completion of each well drilled 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) ADDITIONAL INFORMATION. Upon request, Operator shall promptly
furnish the Developer with such additional information as it may reasonably
request, including without limitation geological, technical and financial
information, in such form as may reasonably be requested, pertaining to any
phase of the operations and activities governed by this Agreement. The Developer
and its authorized employees, agents and consultants, including independent
accountants shall, at Developer's sole cost and expense:
(i) upon at least ten (10) days' written notice have access
during normal business hours to all of Operator's
records pertaining to operations hereunder, including
without limitation, the right to audit the books of
account of Operator relating to all receipts, costs,
charges and expenses under this Agreement; and
(ii) have access, at its sole risk, to any wells drilled by
Operator hereunder at all times to inspect and observe
any machinery, equipment and operations.
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8. OPERATOR'S LIEN; RIGHT TO COLLECT FROM GAS PURCHASER.
(a) OPERATOR'S LIEN. 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) RIGHT TO COLLECT FROM GAS PURCHASER. 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) SUCCESSORS AND ASSIGNS. 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) TRANSFERS. Subject to the provisions of sub-section (a) above, any
sale, encumbrance, transfer or other disposition made by the Developer of its
interests in the wells, production, equipment, and/or leasehold interests
covered hereby shall be made:
(i) expressly subject to this Agreement;
(ii) without prejudice to the rights of the other party; and
(iii) in accordance with and subject to the provisions of the
Lease.
(c) APPOINTMENT OF AGENT. If at any time the interest of the Developer
is divided among or owned by co-owners, Operator may, at its discretion, require
such co-owners to appoint a single trustee or agent with full authority to do
the following:
(i) receive notices, reports and distributions of the
proceeds from production;
(ii) approve expenditures;
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(iii) receive billings for and approve and pay all costs,
expenses and liabilities incurred hereunder;
(iv) exercise any rights granted to such co-owners under
this Agreement;
(v) grant any approvals or authorizations required or
contemplated by this Agreement;
(vi) sign, execute, certify, acknowledge, file and/or record
any agreements, contracts, instruments, reports, or
documents whatsoever in connection with this Agreement
or the activities contemplated hereby; and
(vii) deal generally with, and with power to bind, such
co-owners with respect to all activities and operations
contemplated by this Agreement.
However, 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. OPERATOR'S INSURANCE; SUBCONTRACTORS' INSURANCE; OPERATOR'S LIABILITY.
(a) OPERATOR'S INSURANCE. Operator shall obtain and maintain at its own
expense so long as it is Operator 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.
However, the Developer shall reimburse Operator for the additional cost, if any,
of including it as an additional insured party under the Operator's insurance.
Current copies of all policies or certificates 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) SUBCONTRACTORS' INSURANCE. Operator shall require all of its
subcontractors to carry all required Workmen's Compensation Insurance and to
maintain such other insurance, if any, as Operator in its discretion may
require.
(c) OPERATOR'S LIABILITY. Operator's liability to the Developer as
Operator 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.
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11. INTERNAL REVENUE CODE ELECTION; RELATIONSHIP OF PARTIES; RIGHT TO
TAKE PRODUCTION IN KIND.
(a) INTERNAL REVENUE CODE ELECTION. With respect to this Agreement,
each of the parties hereto elects, under the authority of Section 761(a) of
the Internal Revenue Code of 1986, as amended, to be excluded from the
application of all of the provisions of Subchapter K of Chapter 1 of Sub
Title A of the Internal Revenue Code of 1986, as amended. If the income tax
laws of the state or states in which the property covered hereby is located
contain, or may hereafter contain, provisions similar to those contained in
the Subchapter of the Internal Revenue Code of 1986, as amended, referred to
under which a similar election is permitted, each of the parties agrees that
such election shall be exercised. Beginning with the first taxable year of
operations hereunder, each party agrees that the deemed election provided by
Section 1.761-2(b)(2)(ii) of the Regulations under the Internal Revenue Code
of 1986, as amended, will apply; and no party will file an application under
Section 1.761-2 (b)(3)(i) and (ii) of said Regulations to revoke such
election. Each party hereby agrees to execute such documents and make such
filings with the appropriate governmental authorities as may be necessary to
effect such election.
(b) RELATIONSHIP OF PARTIES. 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) RIGHT TO TAKE PRODUCTION IN KIND. 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:
(i) production which may be used in development and
producing operations;
(ii) production unavoidably lost; and
(iii) production used to fulfill any free gas obligations
under the terms of the applicable Lease or Leases.
Operator shall not have any right to sell or otherwise dispose of 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
supply agreements of Operator, except the right to receive Developer's share of
the proceeds received from the sale of any gas or oil from wells developed
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.
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.
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,
11
<PAGE>
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.
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.
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 America Public #9 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.
12
<PAGE>
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.
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 AMERICA PUBLIC #9 LTD.
Attest By its Managing General Partner:
ATLAS RESOURCES, INC.
---------------------------------------
Secretary
[Corporate Seal] By:
------------------------------------
13
<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 ____________,
200___.
(d) The Developer's interest in the leasehold estate constituting this
Well Location is an undivided % Working Interest to those oil and gas
rights from the surface to the bottom of the __________________
Formation, subject to the landowner's royalty interest and Overriding
Royalty Interests.
Exhibit A
(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 ___________________________________________________
(hereafter 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
_______________________________________________________________________________
(hereafter 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 ___________________ , 2000
THIS ADDENDUM NO. __________ made and entered into this ______ day of
________________, 2000, by and between ATLAS RESOURCES, INC., a Pennsylvania
corporation (hereinafter referred to as "Operator"),
and
ATLAS AMERICA PUBLIC #9 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 ___________________, 2000, (the "Agreement"), which Agreement
relates to the drilling and operating of ________________ (______) natural gas
wells on the ________________ (______) Initial Well Locations in
_________________, ___________, 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 31, 2001.
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 AMERICA PUBLIC #9 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.
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.
1
<PAGE>
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
- 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;
2
<PAGE>
- 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.
3
<PAGE>
CALIFORNIA ADMINISTRATIVE CODE, TITLE 10, CH. 3, RULE 260.141.11. RESTRICTION
ON TRANSFER.
(a) The issuer of any security upon which a restriction on transfer
has been imposed pursuant to Sections 260.102.6, 260.141.10 and
260.534 shall cause a copy of this section to be delivered to
each issuee or transferee of such security at the time the
certificate evidencing the security is delivered to the issuee
or transferee.
(b) It is unlawful for the holder of any such security to consummate
a sale or transfer of such security, or any interest therein,
without the prior written consent of the Commissioner (until
this condition is removed pursuant to Section 260.141.12 of
these rules), except:
(i) to the issuer;
(ii) pursuant to the order or process of any court;
(iii) to any person described in Subdivision (i) of Section
25102 of the Code or Section 260.105.14 of these rules;
(iv) to the transferor's ancestors, descendants or spouse,
or any custodian or trustee for the account of the
transferor's ancestors, descendants or spouse, or to a
transferee by a trustee or custodian for the account of
the transferee or the transferee's ancestors,
descendants or spouse;
(v) to holders of securities of the same class of the same
issuer;
(vi) by way of gift or donation inter vivos or on death;
(vii) by or through a broker-dealer licensed under the Code
(either acting as such or as a finder) to a resident of
a foreign state, territory or country who is neither
domiciled in this state to the knowledge of the
broker-dealer, nor actually present in this state if
the sale of such securities is not in violation of any
securities law of the foreign state, territory or
country concerned;
(viii) to a broker-dealer licensed under the Code in a
principal transaction, or as an underwriter or member
of an underwriting syndicate or selling group;
(ix) if the interest sold or transferred is a pledge or
other lien given by the purchaser to the seller upon a
sale of the security for which the Commissioner's
written consent is obtained or under this rule not
required;
(x) by way of a sale qualified under Sections 25111, 25112,
25113 or 25121 of the Code, of the securities to be
transferred, provided that no order under Section 25140
or Subdivision (a) of Section 25143 is in effect with
respect to such qualification;
(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
4
<PAGE>
subdivision (f) of Section 25102;
provided that any such transfer is on the condition that any
certificate evidencing the security issued to such transferee
shall contain the legend required by this section.
(c) The certificates representing all such securities subject to
such a restriction on transfer, whether upon initial issuance or
upon any transfer thereof, shall bear on their face a legend,
prominently stamped or printed thereon in capital letters of not
less than 10-point size, reading as follows:
"IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS
SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY
CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE
COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT
AS PERMITTED IN THE COMMISSIONER'S RULES."
If a resident of North Carolina, I am aware that:
IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR
OWN EXAMINATION OF THE PERSON OR ENTITY CREATING THE
SECURITIES AND THE TERMS OF THE OFFERING, INCLUDING THE MERITS
AND RISKS INVOLVED. THESE SECURITIES HAVE NOT BEEN RECOMMENDED
BY ANY FEDERAL OR STATE SECURITIES COMMISSION OR REGULATORY
AUTHORITY. FURTHERMORE, THE FOREGOING AUTHORITIES HAVE NOT
CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS
DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
OFFENSE.
PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than
$1,500,000 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.
5
<PAGE>
TABLE OF CONTENTS
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Page
<S> <C>
Summary of the Offering..............................1
Risk Factors.........................................2
Additional Information...............................8
Forward Looking Statements and Associated
Risks.............................................8
Investment Objectives................................9
Actions to be Taken by Managing General
Partner to Reduce Risks of Additional
Payments by Investor General Partners............10
Capitalization and Source of Funds and Use of
Proceeds.........................................11
Compensation........................................14
Terms of the Offering...............................18
Prior Activities....................................22
Management..........................................29
Proposed Activities.................................33
Competition, Markets and Regulation.................96
Participation in Costs and Revenues.................99
Conflicts of Interest..............................103
Fiduciary Responsibility of the Managing
General Partner.................................112
Tax Aspects........................................113
Summary of Partnership Agreement...................124
Summary of Drilling and Operating Agreement........126
Reports to Investors...............................127
Presentment Feature................................128
Transferability of Units...........................129
Plan of Distribution...............................130
Sales Material.....................................131
Legal Opinions.....................................132
Experts............................................132
Litigation.........................................132
Financial Information Concerning the Managing
General Partner and the Partnership.............133
</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 AMERICA
PUBLIC #9 LTD.
---------------
PROSPECTUS
---------------
_____________, 2000
Until December 31, 2000, 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........................................................................ 3,960.00
Blue Sky Filing Fees (excluding legal fees)................................................. 26,000.00*
NASD Filing Fee............................................................................. 2,000.00
Miscellaneous............................................................................... 398,040.00*
------------
Total................................................. $675,000.00*
============
</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.
1
<PAGE>
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 America Public #9
Ltd.
4(b) Amended and Restated Certificate and Agreement of Limited
Partnership for Atlas America Public #9 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>
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.
2
<PAGE>
(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.
3
<PAGE>
SIGNATURES
In accordance with the requirements of the Securities Act of 1933, the
Registrant certifies that it has reasonable grounds to believe that it meets
all of the requirements for filing on Form SB-2 and has authorized this
Pre-Effective Amendment No. 1 to the Registration Statement to be signed on
its behalf by the undersigned, thereto duly authorized, in Moon Township,
Pennsylvania, on the 5th day of September, 2000.
ATLAS AMERICA PUBLIC #9 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,
signing on behalf of the names shown below, Chief Executive Officer
in the capacities indicated. and Director
By: /s/ Tony C. Banks
-------------------------------
Tony C. Banks, Senior Vice
President, Chief Financial
Officer and Director
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>
James R. O'Mara President, Chief Executive Officer and a Director September 5, 2000
Tony C. Banks Senior Vice President, Chief Financial Officer and a Director September 5, 2000
Michael L. Staines Senior Vice President and Chief Operating Officer September 5, 2000
Frank P. Carolas Vice President of Land and Geology September 5, 2000
Barbara J. Krasnicki Secretary September 5, 2000
</TABLE>
<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 America Public #9 Ltd.* ________
4(b) Amended and Restated Certificate and Agreement of Limited
Partnership for Atlas America Public #9 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.
