As filed with the Securities and Exchange Commission on June 3, 2003
Registration Number
- --------------------------------------------------------------------------------
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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ATLAS AMERICA PUBLIC #12-2003 PROGRAM
(Exact name of Registrant as Specified in its Charter)
Delaware
(State or other jurisdiction of incorporation or organization)
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1311
(Primary Standard Industrial Classification Code Number)
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Not Applicable
(IRS Employer Identification Number)
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311 Rouser Road
Moon Township, Pennsylvania 15108
(412) 262-2830
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
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Jack L. Hollander, Senior Vice President - Direct Participation Programs
Atlas Resources, Inc.
311 Rouser Road, Moon Township, Pennsylvania 15108
(412) 262-2830
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
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With a Copy to:
Wallace W. Kunzman, Jr., Esq.
Kunzman & Bollinger, Inc.
5100 N. Brookline
Suite 600
Oklahoma City, Oklahoma 73112
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As soon as practicable after this Registration Statement becomes effective.
(Approximate Date of Commencement of Proposed Sale to the Public)
If any of the securities being registered on this form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box: |X|
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. |_|
If this Form is a post-effective amendment filed pursuant to rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. |_|
If this Form is a post-effective amendment filed pursuant to rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. |_|
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box: |_|
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CALCULATION OF REGISTRATION FEE
Proposed Proposed
Unit Maximum Maximum
Title of Each Amounts Dollar Offering Aggregate Amount of
Class of Securities to be Amounts to be Price per Offering Registration
to be Registered Registered Registered Unit Price Fee
------------------------------ ------------- ------------- ------------- ------------- -------------
Investor General Partner Units (1) ......... 7,125 $71,250,000 $10,000 $71,250,000 $6,555
Converted Limited Partner Units (2) ........ 7,125 -0- -0- -0- -0-
Limited Partner Units (2) .................. 375 $3,750,000 $10,000 $3,750,000 $345
------------- ------------- ------------- ------------- -------------
TOTAL ...................................... 7,500 $75,000,000 $75,000,000 $6,900
============= ============= ============= =============
(1) "Investor General Partner Units" means the investor general partner
interests offered to participants in the program.
(2) "Limited Partner Units" means up to 375 initial limited partner interests
offered to participants in the program and up to 7,125 limited partner units
into which the investor general partners automatically will be converted by
the managing general partner with no additional price paid by the investor.
The Registrant hereby amends this Registration Statement on such dates as may be
necessary to delay its effective date until the Registrant shall file a further
amendment which specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a) of the Securities
Act of 1933 or until this Registration Statement shall become effective on such
date as the Commission, acting pursuant to said Section 8(a), may determine.
ATLAS AMERICA PUBLIC #12-2003 PROGRAM
CROSS REFERENCE SHEET
Item of Form S-1 Caption in Prospectus
---------------- ---------------------
Item 1. Forepart of the Registration Statement and Outside Front Front Page of Registration Statement and Outside Front
Cover Page of Prospectus .................................... Cover Page of Prospectus
Item 2. Inside Front and Outside Back Cover Pages of Prospectus ..... Inside Front and Outside Back Cover Pages of Prospectus
Item 3. Summary Information, Risk Factors and Ratio Of Earnings to
Fixed Changes ............................................... Summary of the Offering; Risk Factors
Item 4. Use of Proceeds ............................................. Capitalization and Source of Funds and Use of Proceeds
Item 5. Determination of Offering Price ............................. Terms of the Offering
Item 6. Dilution .................................................... The partnerships composing the program have not
conducted any activities and the managing general
partner's officers, directors, promoters and
affiliated persons have not acquired any units during
the past five years. Also, no units will be issued in
this offering to the managing general partner except
units subscribed for by the managing general partner,
which it does not anticipate. Discounted units, if
any, are described in "Plan of Distribution."
Item 7. Selling Security Holders .................................... The partnerships composing the program do not have
any selling security holders
Item 8. Plan of Distribution ........................................ Plan of Distribution
Item 9. Description of Securities to be Registered .................. Summary of the Offering; Terms of the Offering; Summary
of Partnership Agreement
Item 10. Interests of Named Experts and Counsel ...................... Legal Opinions; Experts
Item 11. Information with respect to the Registrant
(a) Description of Business ................................. Proposed Activities; Management
(b) Description of Property ................................. Proposed Activities
(c) Legal Proceedings ....................................... Litigation
(d) Market Price of and Dividends on the Registrant's The partnerships composing the program have no markets
Common Equity and Related Stockholder Matters ........... in which their units are being traded, no holders of
units, and they have not conducted activities or paid
any dividends.
(e) Financial Statements ................................... Financial Information Concerning the Managing General
Partner
(f) Selected Financial Data ................................ The partnerships composing the program have not been
formed. Thus, they have not conducted any activities
and they do not have this information.
(g) Supplementary Financial Information ..................... The partnerships composing the program have not been
formed. Thus, they have not conducted any activities
and they do not have this information.
(h) Management's Discussion and Analysis of Financial Management's Discussion and Analysis of Financial
Condition and Results of Operations .................... Condition, Results of Operations, Liquidity and Capital
Resources
Item of Form S-1 Caption in Prospectus
---------------- ---------------------
(i) Changes in and Disagreements with Accountants on There have been no changes in and disagreements with
Accounting and Financial Disclosure .................... accountants on accounting and financial disclosure.
(j) Quantitative and Qualitative Disclosures about Market The partnerships composing the program have no market
Risk .................................................... for their units and none will be created.
(k) Directors and Executive Officers ....................... Management
(l) Executive Compensation ................................. Management
(m) Security Ownership of Certain Beneficial Owners and
Management ............................................. Management
(n) Certain Relationships and Related Transactions ......... Compensation; Management; Conflicts of Interest
Item 12. Disclosure of Commission Position on Indemnification for Fiduciary Responsibilities of the Managing General
Securities Act Liabilities .................................. Partner
The information in this prospectus is not complete and may be changed. We may
not sell these securities until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell these securities and it is not soliciting an offer to buy these
securities in any state where the offer or sale is not permitted.
PRELIMINARY PROSPECTUS DATED _______ ___, 2003
ATLAS AMERICA PUBLIC #12-2003 PROGRAM
o Up to 7,125 Investor General Partner Units and 7,125 converted Limited Partner
Units and up to 375 Limited Partner Units, which are collectively
referred to as the "Units," at $10,000 per Unit
o $1 Million (100 Units) Minimum Aggregate Subscriptions
o $75 Million (7,500 Units) Maximum Aggregate Subscriptions
o Units of preformation investor general partner interest and preformation
limited partner interest will become units of investor general partner
interest and limited partner interest, respectively, in the particular
partnership. There is no restriction on the composition of the type of
partnership interests in any partnership other than no more than 5% of the
units in all the partnerships composing Atlas America Public #12-2003
Program (the "Program") may be limited partner units.
o Atlas America Public #12-2003 Program is a series of up to three limited
partnerships, which will be formed to drill primarily natural gas
development wells. They will be managed by Atlas Resources, Inc. of
Pittsburgh, Pennsylvania,
o If you invest in a partnership, then you will not have any interest in any
of the other partnerships unless you also make a separate investment in the
other partnerships.
o The units will be offered on a "best efforts" "minimum-maximum" basis. This
means the broker-dealers must sell at least 100 units and receive
subscription proceeds of at least $1 million in order for a partnership to
close, and they must use only their best efforts to sell the remaining
units in the partnership.
o Subscription proceeds for each partnership will be held in an interest
bearing escrow account until $1 million has been received. The offering
of the partnership designated Atlas America Public #12-2003 Limited
Partnership will not extend beyond December 31, 2003, and the offering of
any partnership designated Atlas America #12-2004(___) Limited
Partnership will not extend beyond December 31, 2004. If subscription
proceeds of $1 million are not received by a partnership's offering
termination date, then your subscription will be promptly returned to you
from the escrow account with interest and without deduction for any fees.
o The Offering: In addition to the information in the table below for not
less than 95% (7,125) of the units, up to 5% (375) of the units, in the
aggregate, may be sold at $8,950 per unit to the managing general
partner, its officers, directors and affiliates, and investors who buy
units through the officers and directors of the managing general partner;
or at $9,300 per unit to registered investment advisors and their
clients, and selling agents and their registered representatives and
principals. These discounted prices reflect certain fees, sales
commissions and reimbursements which will not be paid for these sales.
(See "Plan of Distribution.") To the extent that units are sold at
discounted prices, a partnership's subscription proceeds will be reduced.
(See "Risk Factors - Risks Related to an Investment in a Partnership -
Spreading the Risks of Drilling Among a Number of Wells Will be Reduced
if Less than the Maximum Subscription Proceeds are Received and Fewer
Wells are Drilled.")
Per Unit Total Minimum Total Maximum
------------- ------------- -------------
Public Price .................................................................. $ 10,000 $1,000,000 $75,000,000
Dealer-manager fee, sales commissions,
accountable marketing expense fees, and accountable
due diligence reimbursements (1)............................................. $ 1,050 $ 105,000 $ 7,875,000
Proceeds to partnership ....................................................... $ 10,000 $1,000,000 $75,000,000
(1) These fees, sales commissions and reimbursements will be paid by the
managing general partner as a part of its capital contribution and not from
subscription proceeds.
o A partnership's drilling operations involves the possibility of a
substantial or partial loss of your investment because of wells which
are productive, but do not produce enough revenue to return the
investment made.
o A partnership's revenues are directly related to the ability to market
the natural gas and the price of natural gas, which is unstable and
cannot be predicted. If the price of gas decreases then your investment
return will decrease.
o Unlimited joint and several liability for partnership obligations if you
choose to invest as an investor general partner until you convert to a
limited partner.
o Lack of liquidity or a market for the units.
o Lack of conflict of interest resolution procedures.
o Total reliance on the managing general partner and its affiliates.
o Authorization of substantial fees to the managing general partner and
its affiliates.
o You and the managing general partner will share in costs
disproportionately to your sharing of revenues.
o Possible allocation of taxable income to you in excess of your cash
distributions from your partnership.
o No guaranty of cash distributions every quarter.
These securities are speculative and are subject to certain risks. You should
purchase these securities only if you can afford a complete loss of your
investment. (See "Risk Factors," Page 8.)
Neither the SEC nor any state securities commission has approved or disapproved
of these securities or determined if this prospectus is truthful or complete.
Any representation to the contrary is a criminal offense.
Anthem Securities, Inc. - Dealer-Manager
TABLE OF CONTENTS
SUMMARY OF THE OFFERING................................................... 1
Business of the Partnerships and the Managing General Partner ........... 1
Risk Factors ............................................................ 1
Description of Units .................................................... 3
Investor General Partner Units......................................... 3
Limited Partner Units.................................................. 4
Terms of the Offering ................................................... 4
Use of Proceeds ......................................................... 5
Subordination, Participation in Costs and Revenues,
and Distributions ..................................................... 5
Compensation ............................................................ 7
RISK FACTORS.............................................................. 8
Risks Related To The Partnerships' Oil and Gas Operations ............... 8
No Guarantee of Return of Investment or Rate of Return on Investment
Because of Speculative Nature of Drilling Natural Gas and Oil Wells.. 8
Because Some Wells May Not Return Their Drilling and Completion Costs,
It May Take Many Years to Return Your Investment in Cash, If Ever.... 8
Nonproductive Wells May be Drilled Even Though the Partnerships'
Operations are Limited to Development Drilling....................... 8
Partnership Distributions May be Reduced if There is a Decrease in the
Price of Natural Gas and Oil......................................... 8
Adverse Events in Marketing a Partnership's Natural Gas Could Reduce
Partnership Distributions............................................ 8
Possible Leasehold Defects............................................. 9
Transfer of the Leases Will Not Be Made Until Well is Completed........ 9
Participation with Third-Parties in Drilling Wells May Require the
Partnerships to Pay Additional Costs................................. 9
Risks Related to an Investment In a Partnership ......................... 10
If You Choose to Invest as a General Partner, Then You Have Greater
Risk Than a Limited Partner......................................... 10
The Managing General Partner May Not Meet Its Indemnification and
Purchase Obligations If Its Liquid Net Worth Is Not Sufficient....... 10
An Investment in a Partnership Must be for the Long-Term Because the
Units Are Illiquid and Not Readily Transferable...................... 11
Spreading the Risks of Drilling Among a Number of Wells Will be Reduced
if Less than the Maximum Subscription Proceeds are Received and Fewer
Wells are Drilled.................................................... 11
The Partnerships Do Not Own Any Prospects, the Managing General Partner
Has Complete Discretion to Select Which Prospects Are Acquired By a
Partnership, and the Lack of Information for a Portion or Majority of
the Prospects Decreases Your Ability to Evaluate the Feasibility of a
Partnership.......................................................... 11
Lack of Production Information Increases Your Risk and Decreases Your
Ability to Evaluate the Feasibility of a Partnership's Drilling
Program.............................................................. 12
The Partnerships Within the Program and Other Partnerships Sponsored by
the Managing General Partner May Compete With Each Other for
Prospects, Equipment, Contractors, and Personnel..................... 12
Managing General Partner's Subordination is not a Guarantee of the
Return of Any of Your Investment..................................... 12
Borrowings by the Managing General Partner Could Reduce Funds Available
for Its Subordination Obligation..................................... 12
Compensation and Fees to the Managing General Partner Regardless of
Success of a Partnership's Activities
Will Reduce Cash Distributions....................................... 13
The Intended Quarterly Distributions to Investors May be Reduced or
Delayed.............................................................. 13
There Are Conflicts of Interest Between the Managing General Partner
and the Investors.................................................... 13
The Presentment Obligation May Not Be Funded and the Presentment Price
May Not Reflect Full Value........................................... 14
The Managing General Partner May Not Devote the Necessary Time to the
Partnerships Because Its Management Obligations Are Not Exclusive.... 14
Prepaying Subscription Proceeds to Managing General Partner May Expose
the Subscription Proceeds to Claims of the Managing General Partner's
Creditors............................................................ 14
Lack of Independent Underwriter May Reduce Due Diligence Investigation
of the Partnerships and the Managing General Partner................. 15
A Lengthy Offering Period May Result in Delays in the Investment of
Your Subscription and Any Cash Distributions From the Partnership
to You............................................................... 15
Tax Risks ............................................................... 15
Changes in the Law May Reduce to Some Degree Your Tax Benefits From an
Investment in a Partnership.......................................... 15
You May Owe Taxes in Excess of Your Cash Distributions from a
Partnership.......................................................... 15
Your Deduction for Intangible Drilling Costs May Be Limited for
Purposes of the Alternative Minimum Tax.............................. 16
Investment Interest Deductions of Investor General Partners May Be
Limited.............................................................. 16
Lack of Tax Shelter Registration Could Result in
Penalties to You..................................................... 16
ADDITIONAL INFORMATION.................................................... 16
FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS........................... 16
INVESTMENT OBJECTIVES..................................................... 17
ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF
ADDITIONAL PAYMENTS BY INVESTOR
GENERAL PARTNERS.......................................................... 18
ii
TABLE OF CONTENTS
CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS.................... 20
Source of Funds ......................................................... 20
Use of Proceeds ......................................................... 21
COMPENSATION.............................................................. 24
Natural Gas and Oil Revenues ............................................ 24
Lease Costs ............................................................. 24
Drilling Contracts ...................................................... 25
Per Well Charges ........................................................ 26
Gathering Fees .......................................................... 27
Dealer-Manager Fees ..................................................... 28
Interest and Other Compensation ......................................... 29
Estimate of Administrative Costs and Direct Costs to be Borne by the
Partnerships .......................................................... 29
TERMS OF THE OFFERING..................................................... 30
Subscription to a Partnership ........................................... 30
Partnership Closings and Escrow ......................................... 31
Acceptance of Subscriptions ............................................. 32
Activation of the Partnerships .......................................... 33
Suitability Standards ................................................... 33
In General............................................................. 33
Purchasers of Limited Partner Units in California, Michigan, New
Hampshire, North Carolina, Ohio and Pennsylvania..................... 34
Purchasers of Investor General Partner Units in either: (i) Alabama,
Maine, Massachusetts, Minnesota, North Carolina, Ohio, Oklahoma,
Pennsylvania, Tennessee, Texas, or Washington; or (ii) Arizona,
Indiana, Iowa, Kansas, Kentucky, Michigan, Mississippi, Missouri, New
Mexico, Oregon, South Dakota, or Vermont............................. 34
Purchasers of Investor General Partner Units in either California or
New Hampshire........................................................ 36
Fiduciary Accounts and Confirmations................................... 36
PRIOR ACTIVITIES.......................................................... 37
MANAGEMENT................................................................ 44
Managing General Partner and Operator ................................... 44
Officers, Directors and Other Key Personnel ............................. 44
Atlas America, Inc., a Delaware Holding Company ......................... 48
Organizational Diagram .................................................. 49
Remuneration ............................................................ 49
Security Ownership of Certain Beneficial Owners ......................... 49
Transactions with Management and Affiliates ............................. 49
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS OF
OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES............................... 50
PROPOSED ACTIVITIES....................................................... 52
Overview of Drilling Activities ......................................... 52
Primary Areas of Operations ............................................. 53
Clinton/Medina Geological Formation In Western Pennsylvania............ 54
Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County,
Pennsylvania......................................................... 54
Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania.... 55
Secondary Areas of Operations ........................................... 55
Clinton/Medina Geological Formation in Western New York................ 55
Mississippian Berea Sandstone in Eastern Ohio.......................... 56
Devonian Oriskany Sandstone in Eastern Ohio............................ 56
Upper Devonian Sandstone in McKean County, Pennsylvania................ 56
Clinton/Medina Geological Formation in Southern Ohio................... 57
Acquisition of Leases ................................................... 57
Deep Drilling Rights Retained by Managing General Partner.............. 58
Interests of Parties .................................................... 59
Primary Areas ........................................................... 60
Clinton/Medina Geological Formation in Western Pennsylvania and
Mississippian/Upper Devonian Sandstone Reservoirs in Fayette and
Greene Counties, Pennsylvania........................................ 60
Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania ... 60
Secondary Areas ......................................................... 60
Title to Properties ..................................................... 60
Drilling and Completion Activities; Operation of Producing Wells ........ 61
Sale of Natural Gas and Oil Production .................................. 62
Policy of Treating All Wells Equally in a Geographic Area.............. 62
Gathering of Natural Gas............................................... 63
Natural Gas Contracts.................................................. 63
Marketing of Natural Gas Production from Wells in Other Areas of the
United States ......................................................... 65
Crude Oil ............................................................... 65
Insurance ............................................................... 66
Use of Consultants and Subcontractors ................................... 66
COMPETITION, MARKETS AND REGULATION....................................... 66
Natural Gas Regulation .................................................. 66
Crude Oil Regulation .................................................... 66
Competition and Markets ................................................. 66
State Regulations ....................................................... 68
Environmental Regulation ................................................ 69
Proposed Regulation ..................................................... 69
PARTICIPATION IN COSTS AND REVENUES....................................... 69
In General .............................................................. 69
Costs ................................................................... 70
Revenues ................................................................ 71
Subordination of Portion of Managing General
Partner's Net Revenue Share ............................................. 72
Table of Participation in Costs and Revenues ............................ 73
Allocation and Adjustment Among Investors ............................... 74
Distributions ........................................................... 74
Liquidation ............................................................. 75
CONFLICTS OF INTEREST..................................................... 75
In General .............................................................. 75
Conflicts Regarding Transactions with the Managing General Partner and
its Affiliates......................................................... 76
Conflict Regarding the Drilling and Operating
Agreement ............................................................. 76
Conflicts Regarding Sharing of Costs and Revenues ....................... 76
Conflicts Regarding Tax Matters Partner ................................. 77
Conflicts Regarding Other Activities of the Managing General Partner,
the Operator and Their Affiliates ..................................... 77
Conflicts Involving the Acquisition of Leases .......................... 78
iii
TABLE OF CONTENTS
Conflicts Between Investors and the Managing General Partner as an
Investor ............................................................. 82
Lack of Independent Underwriter and Due Diligence Investigation ........ 83
Conflicts Concerning Legal Counsel ..................................... 83
Conflicts Regarding Presentment Feature ................................ 83
Conflicts Regarding Managing General Partner Withdrawing an Interest ... 83
Conflicts Regarding Order of Pipeline Construction and Gathering Fees .. 83
Procedures to Reduce Conflicts of Interest ............................. 84
Policy Regarding Roll-Ups .............................................. 85
FIDUCIARY RESPONSIBILITY OF THE
MANAGING GENERAL PARTNER ............................................... 86
In General ............................................................. 86
Limitations on Managing General Partner Liability as Fiduciary ......... 87
TAX ASPECTS.............................................................. 88
Summary of Tax Opinion ................................................. 88
In General ............................................................. 90
Partnership Classification ............................................. 90
Limitations on Passive Activities ...................................... 90
Publicly Traded Partnership Rules..................................... 91
Conversion from Investor General Partner to Limited Partner........... 91
Taxable Year and Method of Accounting .................................. 91
2003 and 2004 Expenditures ............................................. 91
Availability of Certain Deductions ..................................... 92
Intangible Drilling Costs .............................................. 92
Drilling Contracts ..................................................... 92
Depletion Allowance .................................................... 94
Depreciation - Modified Accelerated Cost Recovery System ("MACRS") ..... 95
Lease Acquisition Costs and Abandonment ................................ 95
Tax Basis of Units ..................................................... 95
"At Risk" Limitation for Losses ........................................ 96
Distributions from a Partnership ....................................... 96
Sale of the Properties ................................................. 96
Disposition of Units ................................................... 96
Minimum Tax - Tax Preferences .......................................... 97
Limitations on Deduction of Investment Interest ........................ 98
Allocations ............................................................ 98
Partnership Borrowings ................................................. 99
Partnership Organization and Syndication Fees .......................... 99
Tax Elections .......................................................... 99
Disallowance of Deductions under Section 183 of the Internal Revenue
Code ................................................................. 99
Termination of a Partnership ........................................... 99
Lack of Registration as a Tax Shelter .................................. 99
Investor Lists........................................................ 100
Tax Returns and Audits ................................................. 100
In General............................................................ 100
Tax Returns........................................................... 100
Penalties and Interest ................................................. 100
In General............................................................ 100
Penalty for Negligence or Disregard of Rules or Regulations........... 100
Valuation Misstatement Penalty........................................ 100
Substantial Understatement Penalty.................................... 101
IRS Anti-Abuse Rule................................................... 101
Judicial Doctrines.................................................... 101
State and Local Taxes .................................................. 101
Severance and Ad Valorem (Real Estate) Taxes ........................... 102
Social Security Benefits and Self-Employment Tax ....................... 102
Farmouts ............................................................... 102
Foreign Partners ....................................................... 102
Estate and Gift Taxation ............................................... 102
Changes in the Law ..................................................... 102
SUMMARY OF PARTNERSHIP AGREEMENT......................................... 103
Liability of Limited Partners .......................................... 103
Amendments ............................................................. 103
Notice ................................................................. 103
Voting Rights .......................................................... 104
Access to Records ...................................................... 105
Withdrawal of Managing General Partner ................................. 105
Return of Subscription Proceeds if Funds Are Not Invested in Twelve
Months................................................................... 105
SUMMARY OF DRILLING AND OPERATING AGREEMENT.............................. 105
REPORTS TO INVESTORS..................................................... 106
PRESENTMENT FEATURE...................................................... 107
TRANSFERABILITY OF UNITS................................................. 109
Restrictions on Transfer Imposed by the Tax Laws and the Partnership
Agreement ............................................................ 109
Conditions to Becoming a Substitute Partner ............................ 109
PLAN OF DISTRIBUTION..................................................... 110
Commissions ............................................................ 110
Indemnification ........................................................ 111
SALES MATERIAL........................................................... 112
LEGAL OPINIONS........................................................... 113
EXPERTS.................................................................. 113
LITIGATION............................................................... 113
FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER............ 113
Exhibits
Appendix A Information Regarding Currently Proposed Prospects
Exhibit (A) Form of Limited Partnership Agreement of Atlas
America Public # 12-2003 Limited Partnership
[Atlas America Public # 12-2004(_) Limited
Partnership]
Exhibit (I-A) Form of Managing General Partner Signature Page
Exhibit (I-B) Form of Subscription Agreement
Exhibit (II) Form of Drilling and Operating Agreement for
Atlas America Public # 12-2003 Limited
Partnership [Atlas America Public 12-2004(_)
Limited Partnership]
Exhibit (B) Special Suitability Requirements and Disclosures
to Investors
iv
SUMMARY OF THE OFFERING
This is a summary and does not include all of the information which may be
important to you. You should read the entire prospectus and the attached
exhibits and appendix before you decide to invest. Throughout this prospectus
when there is a reference to you it is a reference to you as a potential
investor or participant in a partnership.
Business of the Partnerships and the Managing General Partner
Atlas America Public #12-2003 Program is sometimes referred to in this
prospectus as "program," consists of up to three Delaware limited partnerships
which will be formed. These limited partnerships are sometimes referred to in
this prospectus in the singular as a "partnership" or in the plural as the
"partnerships." We will offer and sell units of the various partnerships during
a portion of 2003 and 2004. See "Terms of the Offering" for a discussion of the
terms and conditions involved in making an investment in the program.
Each partnership in the program when formed will be a separate business entity
from the other partnerships. A limited partnership agreement will govern the
rights and obligations of the partners of each partnership. A form of the
limited partnership agreement is attached to the prospectus as Exhibit A. For a
summary of the material provisions of the limited partnership agreement which
are not covered elsewhere in this Prospectus see "Summary of Partnership
Agreement." You will be a partner only in the partnership in which you invest.
You will have no interest in the business, assets or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the partnership in which you invest.
Each partnership will drill, own and operate natural gas wells in the
Appalachian Basin located in western Pennsylvania, eastern and southern Ohio and
western New York as described in "Proposed Activities." Currently, the
partnerships do not hold any interests in any properties or prospects on which
the wells will be drilled.
All offering proceeds will be used to drill development wells. A development
well means a well drilled within the proved area of a natural gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.
The managing general partner of each partnership is Atlas Resources, Inc., a
Pennsylvania corporation, which was incorporated in 1979, and is sometimes
referred to in this prospectus as "Atlas Resources." As set forth in "Prior
Activities," the managing general partner has sponsored and serves as managing
general partner of 31 private drilling partnerships which raised a total of
$160,393,999, and 11 public drilling partnerships which raised a total of
$127,440,590. Atlas Resources also will serve as each partnership's general
drilling contractor and operator and supervise the drilling, completing and
operating of the wells to be drilled. As of January 1, 2003, the managing
general partner and its affiliates operated approximately 4,416 natural gas and
oil wells located in Ohio, Pennsylvania and New York.
The address and telephone number of the partnerships and the managing general
partner are 311 Rouser Road, Moon Township, Pennsylvania 15108, (412) 262- 2830.
Risk Factors
This offering involves numerous risks, including the risks related to each
partnership's oil and gas operations, the risks related to a partnership
investment, and tax risks. You should carefully consider a number of significant
risk factors inherent in and affecting the business of a partnership and this
offering, including the following.
o Each partnership's drilling operations involve the possibility of a
substantial or partial loss of your investment because of wells which
are productive, but do not produce enough revenue to return the
investment made and/or from time to time dry holes.
1
o Each partnership's revenues are directly related to the ability to
market the natural gas and the price of natural gas, which cannot be
predicted, and if the price of gas decreases then your investment
return will decrease.
o Unlimited joint and several liability for partnership obligations if
you choose to invest as an investor general partner until you convert
to a limited partner.
o Lack of liquidity or a market for the units, necessitating a long-term
commitment.
o Total reliance on managing general partner and its affiliates.
o Authorization of substantial fees to the managing general partner and
its affiliates.
o Possible allocation of taxable income to investors in excess of their
cash distributions from a partnership.
o Each partnership must receive minimum subscriptions of $1 million to
close, and the subscription proceeds of all partnerships, in the
aggregate, may not exceed $75 million. There are no other requirements
regarding the size of a partnership, and the subscription proceeds of
one partnership may be substantially more or less than the
subscription proceeds of the other partnerships. If only the minimum
subscriptions were received in a partnership, then only five wells
will be drilled in that partnership which decreases the partnership's
ability to spread the risks of drilling.
o Certain conflicts of interest between the managing general partner and
you and the other investors and lack of procedures to resolve the
conflicts.
o You and the other investors and the managing general partner will
share in costs disproportionately to the sharing of revenues.
o Currently, the partnerships do not hold any interests in any
properties or prospects on which the wells will be drilled. Although
the managing general partner has absolute discretion in determining
which properties or prospects will be drilled by a partnership, the
managing general partner intends that Atlas America Public #12-2003
Limited Partnership, which must close on or before December 31, 2003,
will drill the prospects described in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public
#12-2003 Limited Partnership." These prospects represent a portion of
the non-binding targeted subscription proceeds described in "Terms of
the Offering - Subscription to a Partnership." If there are adverse
events with respect to any of the currently proposed prospects, the
managing general partner will substitute the partnership's prospects.
The managing general partner also anticipates that it will designate a
portion of each partnership's prospects in the partnerships designated
Atlas America Public #12-2004(_) Limited Partnership by supplement or
an amendment to the registration statement.
o In each partnership the managing general partner may subordinate a
portion of its share of that partnership's net production revenues.
This subordination is not a guaranty by the managing general partner,
and if the wells in that partnership produce small volumes of gas
and/or the price of gas decreases, then even with subordination your
cash flow from the partnership may not return your entire investment.
o In each partnership quarterly cash distributions to investors may be
deferred if revenues are used on partnership operations or reserves.
2
Description of Units
In the partnership being offered at the time you subscribe you may buy either:
o preformation investor general partner units; or
o preformation limited partner units.
Units of preformation investor general partner interest and preformation limited
partner interest will become units of investor general partner interest and
limited partner interest, respectively, in the particular partnership.
The type of unit you buy will not affect the allocation of costs, revenues, and
cash distributions among you and the other investors. There are, however,
material differences in the federal income tax effects and liability associated
with each type of unit.
Investor General Partner Units.
o Tax Effect. If you invest in a partnership as an investor general
partner, then your share of the partnership's deduction for intangible
drilling costs will not be subject to the passive activity limitations
because your investor general partner units will not be converted to
limited partner units until after all the wells have been drilled and
completed. For example, if you pay $10,000 for a unit, then generally
you may deduct approximately 90% of your subscription, $9,000, in the
year in which you invest, which includes your deduction for intangible
drilling costs for all of the wells to be drilled by the partnership.
(See "Tax Aspects - Limitations on Passive Activities.")
o Intangible drilling costs generally means those costs of drilling
and completing a well that are currently deductible, as compared
to lease costs which must be recovered through the depletion
allowance and costs for equipment in the well which must be
recovered through depreciation deductions.
o Liability. If you invest in a partnership as an investor general
partner, then you will have unlimited liability regarding the
partnership activities. This means if:
o the insurance proceeds;
o the managing general partner's indemnification; and
o the partnership assets
were not sufficient to satisfy a partnership liability for which you
and the other investor general partners were also liable, then the
managing general partner would require you and the other investor
general partners to make additional capital contributions to the
partnership to satisfy the liability. In addition, you and the other
investor general partners have joint and several liability, which
means generally that a person with a claim against the partnership may
sue all or any one or more of the partnership's general partners,
including you, for the entire amount of the liability. (See "Actions
To Be Taken By Managing General Partner To Reduce Risks of Additional
Payments by Investor General Partners" and "Proposed Activities -
Insurance.")
Although past performance is no guarantee of future results, the investor
general partners in the managing general partner's prior partnerships have not
had to make additional capital contributions to their partnerships because of
their status as investor general partners.
3
Your investor general partner units in a partnership will be automatically
converted by the managing general partner to limited partner units after all of
the partnership wells have been drilled and completed. The conversion will not
create any tax liability to you or the other investors.
Once your units are converted you will have the lesser liability of a limited
partner under Delaware law for obligations and liabilities arising after the
conversion. However, you will continue to have the responsibilities of a general
partner for partnership liabilities and obligations incurred before the
effective date of the conversion. For example, you might become liable for
partnership liabilities in excess of your subscription 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.
Limited Partner Units.
o Tax Effect. If you invest in a partnership as a limited partner, then
the use of your share of the partnership's deduction for intangible
drilling costs will be limited to net passive income from "passive"
trade or business activities. Passive trade or business activities
generally include 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 the year in which
you invest unless you have passive income from investments other than
the partnership.
o Liability. If you invest in a partnership as a limited partner, then
you will have limited liability. This means you will not be liable for
amounts beyond your initial investment and share of undistributed net
profits, subject to certain exceptions set forth in "Summary of
Partnership Agreement - Liability of Limited Partners."
Terms of the Offering
The offering period will begin on the date of this prospectus. Each partnership
will offer a minimum of 100 units, which is $1 million, and all partnerships, in
the aggregate, will offer a maximum of 10,000 units which is $75 million.
The maximum subscriptions for each partnership will be lesser of:
o the registered amount of $75 million; or
o the number of units unsold from the $75 million aggregate
registration.
The targeted maximum subscription and closing date for each partnership are set
forth in a table in "Terms of the Offering - Subscription to a Partnership."
However, the targeted maximum subscription is not binding on the managing
general partner.
Units are offered at a subscription price of $10,000 per unit, provided that up
to 5% of the units sold, in the aggregate, may be sold to certain investors at
discounts as described in "Plan of Distribution." All subscriptions must be paid
100% in cash at the time of subscribing. Your minimum subscription in a
partnership is one unit; however, the managing general partner, in its
discretion, may accept one-half unit subscriptions from you at any time. Larger
fractional subscriptions will be accepted in $1,000 increments, beginning, for
example, with either $11,000, $12,000, etc. if you pay $10,000 for a full unit,
or $6,000, $7,000, etc. if you pay $5,000 for a one-half unit. You will have the
election to purchase units as either an investor general partner or a limited
partner as described above in "- Description of Units." The managing general
partner will have exclusive management authority for the partnerships.
Subscription proceeds for a partnership will be held in a separate interest
bearing escrow account at National City Bank of Pennsylvania until receipt of
the minimum subscriptions. A partnership may not break escrow as described in
"Terms of the Offering-Partnership Closings and Escrow," unless the partnership
is in receipt of subscription proceeds of $1 million after the discounts
described in "Plan of Distribution." However, on receipt of the minimum
subscriptions and written
4
instructions to the escrow agent from the managing general partner and the
dealer-manager, the managing general partner on behalf of a partnership may:
o break escrow;
o form the partnership under the Delaware Revised Uniform Limited
Partnership Act;
o transfer the escrowed funds to a partnership account;
o enter into the drilling and operating agreement with itself or an
affiliate as operator; and
o begin drilling to the extent the prospects have been identified.
After breaking escrow additional subscription payments to a partnership may be
paid directly to the partnership account for that partnership and will continue
to earn interest until the offering closes. (See "Terms of the Offering.")
Use of Proceeds
Each partnership must receive minimum subscriptions of $1 million to close, and
the subscription proceeds of all partnerships, in the aggregate, may not exceed
$75 million. There are no other requirements regarding the size of a partnership
other than the targeted amounts described in "Terms of the Offering -
Subscription to a Partnership" which are not binding on the managing general
partner. The subscription proceeds of one partnership may be substantially more
or less than the subscription proceeds of the other partnerships. The
subscription proceeds of each partnership received from you and the other
investors, regardless of whether the minimum or maximum number of units are
sold, will be used to pay:
o 100% of the intangible drilling costs, which is defined above in
"- Description of Units"; and
o 34% of the equipment costs of drilling and completing the
partnership's wells, but not to exceed 10% of the partnership's
subscription proceeds.
The managing general partner will contribute all of the leases to each
partnership covering the acreage on which each partnership's wells will be
drilled and pay:
o 100% of the organization and offering costs;
o 66% of the equipment costs of drilling and completing the
partnership's wells; and
o any equipment costs that exceed 10% of the partnership's subscription
proceeds that would otherwise be charged to you and the other
investors. (See "Capitalization and Source of Funds and Use of
Proceeds" and "Tax Aspects - Intangible Drilling Costs.")
Subordination, Participation in Costs and Revenues, and Distributions
Each partnership will be a separate business entity from the other partnerships,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest. Each partnership is
structured to provide you and the other investors with cash distributions equal
to a minimum of 10% per unit, based on $10,000 per unit regardless of the actual
subscription price for your units, in each of the first five 12-month periods
beginning with the partnership's first cash distributions from operations. To
help achieve this investment feature the managing general partner will
subordinate up to 50% of its share of partnership net production revenues during
this subordination period.
5
Each partnership's 60-month subordination period will begin with the
partnership's first cash distribution from operations to you and the other
investors. However, no subordination distributions to you and the other
investors will be required until the partnership's first cash distribution after
substantially all of the partnership wells are drilled, completed, and begin
producing into a sales line. Subordination distributions will be determined by
debiting or crediting current period partnership revenues to the managing
general partner as may be necessary to provide the distributions to you and the
other investors. At any time during the subordination period, but not after, the
managing general partner is entitled to an additional share of partnership
revenues to recoup previous subordination distributions to the extent your cash
distributions from the partnership exceed the 10% return described above. The
specific formula is set forth in Section 5.01(b)(4)(a) of the partnership
agreement.
The following table sets forth the participation in partnership costs and
revenues between the managing general partner and you and the other investors
for each partnership after deducting from the partnership's gross revenues the
landowner royalties and any other lease burdens.
Managing
General
Partner Investors
------------- -------------
Partnership Costs
Organization and offering costs.............. 100% 0%
Lease costs.................................. 100% 0%
Intangible drilling costs.................... 0% 100%
Equipment costs(1)........................... 66% 34%
Operating costs, administrative costs,
direct costs, and all other costs.......... (2) (2)
Partnership Revenues
Interest income.............................. (3) (3)
Equipment proceeds(1)........................ 66% 34%
All other revenues including production
revenues................................... (4)(5) (4)(5)
- ---------------
(1) These percentages may vary. If the total equipment costs for all of the
partnership's wells that would be charged to you and the other investors
exceeds an amount equal to 10% of the subscription proceeds of you and the
other investors in the partnership, then the excess will be charged to the
managing general partner.
(2) These costs will be charged to the parties in the same ratio as the related
production revenues are being credited.
(3) Interest earned on your subscription proceeds before the final closing of
the partnership to which you subscribed will be credited to your account and
paid not later than the partnership's first cash distributions from
operations. After each closing of a partnership and until the subscription
proceeds from the closing are invested in the partnership's natural gas and
oil operations any interest income from temporary investments will be
allocated pro rata to the investors providing the subscription proceeds. All
other interest income, including interest earned on the deposit of operating
revenues, will be credited as natural gas and oil production revenues are
credited.
(4) The managing general partner and the investors in the partnership will share
in all of the partnership's other revenues in the same percentage as their
respective capital contributions bears to the total partnership capital
contributions except that the managing general partner will receive an
additional 7% of the partnership revenues. However, the managing general
partner's total revenue share may not exceed 35% of partnership revenues.
(5) The actual allocation of partnership revenues between the managing general
partner and the investors will vary from the allocation described in (4)
above if a portion of the managing general partner's partnership net
production revenues is subordinated as described above.
6
The managing general partner will review a partnership's accounts 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 that the managing general partner does not believe are necessary
for the partnership to retain. (See "Participation in Costs and Revenues.")
Compensation
The items of compensation paid to the managing general partner and its
affiliates from each partnership are as follows:
o The managing general partner will receive a share of each
partnership's revenues. The managing general partner's revenue share
will be in the same percentage as its capital contribution bears to
that partnership's total capital contributions plus an additional 7%
of partnership revenues, but not to exceed a total of 35% of
partnership revenues, regardless of the amount of the managing general
partner's capital contribution, subject to the managing general
partner's subordination obligation.
o The managing general partner will receive a credit to its capital
account equal to the cost of the leases or the fair market value of
the leases if the managing general partner has reason to believe that
cost is materially more than the fair market value.
o Each partnership will enter into the drilling and operating agreement
with the managing general partner to drill and complete the
partnership wells at cost plus 15%. The cost of the well includes
reimbursement to the managing general partner of its general and
administrative overhead of $14,142 per well.
o When the wells for a partnership begin producing the managing general
partner, as operator of the wells, will receive:
o reimbursement at actual cost for all direct expenses incurred on
behalf of the partnership; and
o well supervision fees for operating and maintaining the wells
during producing operations at a competitive rate.
o The managing general partner will receive gathering fees at
competitive rates.
o Subject to certain exceptions described in "Plan of Distribution,"
Anthem Securities, Inc., the dealer-manager and an affiliate of the
managing general partner, which is sometimes referred to in this
prospectus as "Anthem Securities," will receive on each unit sold to
an investor a 2.5% dealer-manager fee, a 7% sales commission, a .5%
accountable marketing expense fee, and a .5% reimbursement of the
selling agents' bona fide accountable due diligence expenses.
o The managing general partner or an affiliate will have the right to
charge a competitive rate of interest on any loan it may make to or on
behalf of a partnership. If the managing general partner provides
equipment, supplies, and other services to a partnership, then it may
do so at competitive industry rates.
o The managing general partner and its affiliates will receive an
unaccountable, fixed payment reimbursement for their administrative
costs, which has been determined by the managing general partner to be
$75 per well per month. The managing general partner may not increase
this fee during the term of the partnership.
(See "Compensation.")
7
RISK FACTORS
An investment in a partnership involves a high degree of risk and is suitable
only if you have substantial financial means and no need of liquidity in your
investment.
Risks Related To The Partnerships' Oil and Gas Operations
No Guarantee of Return of Investment or Rate of Return on Investment Because of
Speculative Nature of Drilling Natural Gas and Oil Wells. Natural gas and oil
exploration is an inherently speculative activity. Before the drilling of a well
the managing general partner cannot predict with absolute certainty:
o the volume of natural gas and oil recoverable from the well; or
o the time it will take to recover the natural gas and oil.
You may not recover all of your investment in a partnership, or if you do
recover your investment in a partnership you may not receive a rate of return on
your investment which is competitive with other types of investment. You will be
able to recover your investment only through the partnership's distributions of
the sales proceeds from the production of natural gas and oil from productive
wells. The quantity of natural gas and oil in a well, which is referred to as
its reserves, decreases over time as the natural gas and oil is produced until
the well is no longer economical to operate. All of these distributions to you
will be considered a return of capital until you have received 100% of your
investment. This means that you are not receiving a return on your investment in
a partnership, excluding tax benefits, until your total cash distributions from
the partnership exceed 100% of your investment. (See "Prior Activities.")
Because Some Wells May Not Return Their Drilling and Completion Costs, It May
Take Many Years to Return Your Investment in Cash, If Ever. Even if a well is
completed in a partnership and produces natural gas and oil in commercial
quantities, it may not produce enough natural gas and oil to pay for the costs
of drilling and completing the well, even if tax benefits are considered. For
example, the managing general partner has formed 42 partnerships since 1985. All
the partnerships are continuing to make cash distributions, however, 32 of the
42 partnerships have not yet returned to the investor 100% of his capital
contributions without taking tax savings into account. Thus, it may take many
years to return your investment in cash, if ever. (See "Prior Activities.")
Nonproductive Wells May be Drilled Even Though the Partnerships' Operations are
Limited to Development Drilling. Each partnership may 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. (See "Prior Activities.")
Partnership Distributions May be Reduced if There is a Decrease in the Price of
Natural Gas and Oil. The price at which a partnership's natural gas and oil will
be sold cannot be predicted. The price of natural gas and oil will depend on
supply and demand factors largely beyond the control of the partnership. For
example, the demand for natural gas is usually greater in the winter months
because of residential heating requirements than the summer months, and
generally results in lower natural gas prices in the summer months than in the
winter months. Natural gas and oil prices are volatile, and natural gas and oil
prices could decrease in the future. If natural gas and oil prices decrease,
then your partnership distributions will decrease accordingly.
Also, the price of natural gas and oil may decrease during the first years of
production when the wells achieve their greatest level of production. This would
have a greater adverse effect on your partnership distributions than price
decreases in later years when the wells have a lower level of production. (See
"Proposed Activities - Sale of Natural Gas and Oil Production.")
Adverse Events in Marketing a Partnership's Natural Gas Could Reduce Partnership
Distributions. In addition to the risk of decreased natural gas and oil prices
described above, there are risks associated with marketing natural gas which
could reduce a partnership's distributions to you and the other investors. These
risks are set forth below.
8
o Competition from other natural gas producers and marketers in the
Appalachian Basin may make it more difficult to market each
partnership's natural gas.
o Each partnership may not be paid or may experience delays in receiving
payment for natural gas that has already been delivered.
o A substantial portion of each partnership's natural gas will be sold
under a 10-year agreement which began on April 11, 1999, and provides
that the 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 each partnership's natural
gas will be sold under similar contracts. Thus, each partnership is
not guaranteed a specific natural gas price, other than through
hedging, and the price for each partnership's natural gas may decrease
because of market conditions.
o Partnership revenues may be less the farther the natural gas is
transported because of increased transportation costs.
o Production from wells drilled in certain areas, such as the wells in
Crawford County, Pennsylvania and to a lesser extent, Fayette County,
Pennsylvania, may be delayed until construction of the necessary
gathering lines and production facilities is completed. (See "Proposed
Activities - Sale of Natural Gas and Oil Production.")
Possible Leasehold Defects. There may be defects in a partnership's title to its
leases. Although the managing general partner will obtain a favorable formal
title opinion for the leases before each well is drilled, it will not obtain a
division order title opinion after the well is completed. A partnership may
experience losses from title defects which arose during drilling that would have
been disclosed by a division order title opinion, such as liens that may arise
during drilling or transfers made after drilling begins. Also, the managing
general partner may use its own judgment in waiving title requirements and will
not be liable for any failure of title of leases transferred to the partnership.
(See "Proposed Activities - Title to Properties."
Transfer of the Leases Will Not Be Made Until Well is Completed. Because the
leases will not be transferred from the managing general partner to a
partnership until the wells are drilled and completed, the transfer could be set
aside by a creditor of the managing general partner, or the trustee in the event
of the voluntary or involuntary bankruptcy of the managing general partner, if
it were determined that the managing general partner received less than a
reasonably equivalent value for the leases. In this event, the leases and the
wells would revert to the creditors or trustee, and the partnership would either
recover nothing or the amount paid for the leases and the cost of drilling the
wells. Assigning the leases to a partnership after the wells are drilled and
completed, however, will not affect the availability of the tax deductions since
the partnership will have an economic interest in the wells under the drilling
and operating agreement before the wells are drilled. (See "Proposed Activities
- - Title to Properties.")
Participation with Third-Parties in Drilling Wells May Require the Partnerships
to Pay Additional Costs. Third-parties will participate with each partnership in
drilling some of the wells. Financial risks exist when the cost of drilling,
equipping, completing, and operating wells is shared by more than one person. If
a partnership pays its share of the costs, but another interest owner does not
pay its share of the costs, then the partnership would have to pay the costs of
the defaulting party. In this event, the partnership would receive the
defaulting party's revenues from the well, if any, under penalty arrangements
set forth in the operating agreement.
If the managing general partner is not the actual operator of the well, then
there is a risk that the managing general partner cannot supervise the third-
party operator closely enough. Also, decisions concerning how the well is
operated and expenditures related to the well would be made by the third-party
operator, and these decisions may not be in the best interests of the
partnerships and you and the other investors. Further, the third-party operator
may have financial difficulties and fail to pay for materials or services on the
wells it drills or operates, which would cause the partnership to incur extra
costs in discharging materialmen's and workmen's liens. The managing general
partner may not be the operator of the well
9
if the partnership owns less than a 50% interest in the well, or if the managing
general partner acquired the interest in the well from a third-party which
required that the third-party be named operator as one of the terms of the
acquisition.
Risks Related to an Investment In a Partnership
If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a
Limited Partner. If you invest as an investor general partner for the tax
benefits instead of as a limited partner, then under Delaware law you will have
unlimited liability for your partnership's activities until converted to limited
partner status subject to certain exceptions as described in "Actions To Be
Taken by Managing General Partner To Reduce Risks of Additional Payments By
Investor General Partners - Conversion of Investor General Partner Units to
Limited Partner Units." This could result in you being required to make
payments, in addition to your original investment, in amounts that are
impossible to predict because of their uncertain nature. Under the terms of the
partnership agreement, if you are an investor general partner you agree to pay
only your proportionate share of your partnership's obligations and liabilities.
This agreement, however, does not eliminate your liability to third-parties if
another investor general partner does not pay his proportionate share of your
partnership's obligations and liabilities.
Also, each partnership will own less than 100% of the interest in some of the
wells. If a court holds you and the other third-party owners of the well 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.
As an investor general partner you may become subject to the following:
o contract liability, which is not covered by insurance;
o liability for pollution, abuses of the environment, and other
environmental damages against which the managing general partner
cannot insure because coverage is not available or against which it
may elect not to insure because of high premium costs or other
reasons; and
o liability for drilling hazards which result in property damage,
personal injury, or death to third-parties in amounts greater than the
insurance coverage. The drilling hazards include, but are not limited
to well blowouts, fires, and explosions.
If your partnership's insurance proceeds and assets, the managing general
partner's indemnification of you and the other investor general partners, and
the liability coverage provided by major subcontractors were not sufficient to
satisfy the liability, then the managing general partner would call for
additional funds from you and the other investor general partners to satisfy the
liability. (See "Actions To Be Taken By Managing General Partner To Reduce Risks
of Additional Payments by Investor General Partners.")
The Managing General Partner May Not Meet Its Indemnification and Purchase
Obligations If Its Liquid Net Worth Is Not Sufficient. The managing general
partner has made commitments to you and the other investors in each partnership
regarding the following:
o the payment of the majority of equipment costs and organization and
offering costs;
o indemnification of the investor general partners for liabilities in
excess of their pro rata share of partnership assets; and
o purchasing units presented by an investor, although this may be
suspended if the managing general partner determines, in its sole
discretion, that it does not have the necessary cash flow or cannot
arrange financing or other consideration for this purpose on
reasonable terms.
A significant financial reversal for the managing general partner could
adversely affect its ability to honor these obligations.
10
The managing general partner's net worth is based primarily on the estimated
value of its producing natural gas properties and is not available in cash
without borrowings or a sale of the properties. Also, if natural gas prices
decrease, then the estimated value of the properties and the managing general
partner's net worth will be reduced. The managing general partner's net worth
may not be sufficient, either currently or in the future, to meet its financial
commitments under the partnership agreement. These risks are increased because
the managing general partner has made similar financial commitments in 38 other
partnerships and will make this same commitment in future partnerships. (See
"Financial Information Concerning the Managing General Partner.")
An Investment in a Partnership Must be for the Long-Term Because the Units Are
Illiquid and Not Readily Transferable. If you invest in a partnership, then you
must assume the risks of an illiquid investment. The transferability of the
units is limited by the federal securities laws, tax laws, and the partnership
agreement. The units cannot be readily liquidated since there is not a readily
available market for the sale of the units. Further, the partnerships do not
intend to list the units on any exchange. Also, a sale of your units could
create adverse tax and economic consequences for you. (See "Tax
Aspects-Disposition of Units" and "Presentment Feature.")
Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less
than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled.
Each partnership must receive minimum subscriptions of $1 million to close, and
the subscription proceeds of all partnerships, in the aggregate, may not exceed
$75 million. There are no other requirements regarding the size of a partnership
other than the nonbinding targeted amounts described in "Terms of the Offering -
Subscription to a Partnership," and the subscription proceeds of one partnership
may be substantially more or less than the subscription proceeds of another
partnership. A partnership subscribed at the minimum will drill fewer wells
which decreases the partnership's ability to spread the risks of drilling. For
example, the managing general partner anticipates that a partnership will drill
approximately 5 wells in which it has a 100% working interest if the minimum
subscriptions of $1 million are received. This is compared with 75 wells in
which it has a 100% working interest if subscription proceeds of $15 million are
received by a partnership.
On the other hand, to the extent more than the minimum subscriptions are
received by a partnership and the number of wells drilled increases, the
partnership's overall investment return may decrease if the managing general
partner is unable to find enough suitable wells to be drilled. Also, in a large
partnership greater demands will be placed on the managing general partner's
management capabilities.
Also, there may be cost overruns in drilling and completing the wells because
the wells will not be drilled and completed on a turnkey basis for a fixed
price, which would shift the risk of loss to the managing general partner as
drilling contractor. The majority of the equipment costs of a partnership's
wells, including any equipment costs in excess of 10% of the partnership's
subscription proceeds, will be paid by the managing general partner. However,
all of the intangible drilling costs will be charged to you and the other
investors. If there is a cost overrun for the intangible drilling costs of a
well or wells, then the managing general partner anticipates that it would use
the subscription proceeds, if available, to pay the cost overrun or advance the
necessary funds to the partnership. Using subscription proceeds to pay cost
overruns will result in a partnership drilling fewer wells.
The Partnerships Do Not Own Any Prospects, the Managing General Partner Has
Complete Discretion to Select Which Prospects Are Acquired By a Partnership, and
The Lack of Information for a Portion or Majority of the Prospects Decreases
Your Ability to Evaluate the Feasibility of a Partnership. The partnerships do
not currently hold any interests in any prospects on which the wells will be
drilled, and the managing general partner has absolute discretion in determining
which prospects will be acquired to be drilled.
The managing general partner has identified in "Proposed Activities" the general
areas where each partnership will drill wells and the managing general partner
intends that Atlas America Public #12-2003 Limited Partnership, which must close
on or before December 31, 2003, will drill the prospects described in "Appendix
A - Information Regarding Currently Proposed Prospects." These prospects
represent approximately $15 million of subscription proceeds which is a portion
of the non-binding targeted subscription proceeds described in "Terms of the
Offering - Subscription to a Partnership." If there are
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adverse events with respect to any of the currently proposed prospects, the
managing general partner will substitute the partnership's prospects. The
managing general partner also anticipates that it will designate a portion of
each partnership's prospects in the partnerships designated Atlas America Public
#12-2004(_) Limited Partnership by supplement or an amendment to the
registration statement. Thus, you do not have any geological or production
information to evaluate any additional and/or substituted prospects and wells.
Instead, you must rely entirely on the managing general partner to select those
prospects and wells.
The partnerships do not have the right of first refusal in the selection of
prospects from the inventory of the managing general partner and its affiliates,
and they may sell their prospects to other partnerships, companies, joint
ventures, or other persons at any time.
Lack of Production Information Increases Your Risk and Decreases Your Ability to
Evaluate the Feasibility of a Partnership's Drilling Program. Production
information from surrounding wells in the area is an important indicator in
evaluating the economic potential of a proposed well to be drilled. However, the
data set forth in "Appendix A - Information Concerning Currently Proposed Wells
for Atlas America Public #12-2003 Limited Partnership" for the proposed wells in
Pennsylvania may not show all the wells drilled and/or production from those
wells because there was a third-party operator and the Pennsylvania Department
of Environmental Resources keeps production data confidential for the first five
years from the time a well starts producing. If the managing general partner is
the operator and no production data is shown it is because the wells are not yet
completed, on-line to sell production, or have been producing for only a short
period of time. This lack of production information from surrounding wells
results in greater uncertainty.
The Partnerships Within the Program and Other Partnerships Sponsored by the
Managing General Partner May Compete With Each Other for Prospects, Equipment,
Contractors, and Personnel. A number of partnerships in the program or other
partnerships sponsored by the managing general partner may have unexpended
capital funds at the same time. Thus, these partnerships may compete for
suitable prospects and the availability of equipment, contractors, and the
managing general partner's personnel. For example, a partnership previously
organized by the managing general partner may still be purchasing prospects when
partnerships within the program are attempting to purchase prospects. This may
make it more difficult to complete the prospect acquisition activities for the
partnerships within the program and may make each partnership less profitable.
Managing General Partner's Subordination is not a Guarantee of the Return of Any
of Your Investment. If cash distributions from the partnership in which you
invest are less than a 10% return for each of the first five 12-month periods
beginning with the partnership's first cash distributions from operations, then
the managing general partner has agreed to subordinate a portion of its share of
the partnership's net production revenues. However, if the wells produce only
small natural gas and oil volumes, and/or natural gas and oil prices decrease,
then even with subordination you may not receive the 10% return for each of the
first five years as described above, or a return of your investment. Also, at
any time during the subordination period the managing general partner is
entitled to an additional share of partnership revenues to recoup previous
subordination distributions to the extent your cash distributions from the
partnership exceed the 10% return described above. (See "Participation in Costs
and Revenues - Subordination of Portion of the Managing General Partner's Net
Revenue Share.")
Borrowings by the Managing General Partner Could Reduce Funds Available for Its
Subordination Obligation. The managing general partner will pledge with respect
to each partnership either its partnership interest and/or an undivided interest
in the partnership assets equal to or less than its revenue interest, which will
range from 32% to 35% depending on the amount of its capital contribution, to
secure borrowings for its own corporate purposes. Under agreements previously
entered into, the managing general partner's lenders have required a first lien
in the property and will have priority over the managing general partner's
subordination obligation under each partnership agreement. Thus, if there was a
default to the lender under this pledge arrangement, then this would reduce the
amount of each partnership's net production revenues available to the managing
general partner for its subordination obligation to you and the other investors.
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Compensation and Fees to the Managing General Partner Regardless of Success of a
Partnership's Activities Will Reduce Cash Distributions. The managing general
partner and its affiliates will profit from their services in drilling,
completing, and operating each partnership's wells, and will receive the other
fees and reimbursement of direct costs described in "Compensation" regardless of
the success of the partnership's wells. These fees and direct costs will reduce
the amount of cash distributions to you and the other investors. The amount of
the fees is subject to the complete discretion of the managing general partner
other than the fees must not exceed competitive fees charged by unaffiliated
third-parties in the same geographic area engaged in similar businesses and any
other restrictions set forth in "Compensation." With respect to direct costs,
the managing general partner has sole discretion on behalf of each partnership
to select the provider of the services or goods and the provider's compensation
as discussed in "Compensation."
The Intended Quarterly Distributions to Investors May be Reduced or Delayed.
Cash distributions to you and the other investors may not be paid each quarter.
Distributions may be reduced or deferred, in the discretion of the managing
general partner, to the extent a partnership's revenues are used for any of the
following:
o repayment of borrowings;
o cost overruns;
o remedial work to improve a well's producing capability;
o direct costs and general and administrative expenses of the
partnership;
o reserves, including a reserve for the estimated costs of eventually
plugging and abandoning the wells; or
o indemnification of the managing general partner and its affiliates by
the partnership for losses or liabilities incurred in connection with
the partnership's activities. (See "Participation in Costs and
Revenues - Distributions.")
There Are Conflicts of Interest Between the Managing General Partner and the
Investors. There are conflicts of interest between you and the managing general
partner and its affiliates. These conflicts of interest, which are not otherwise
discussed in this "Risk Factors" section, include the following:
o the managing general partner has determined the compensation and
reimbursement that it and its affiliates will receive in connection
with the partnerships without any unaffiliated third-party dealing at
arms' length on behalf of the investors;
o the managing general partner must monitor and enforce, on behalf of
the partnerships, its own compliance with the drilling and operating
agreement;
o because the managing general partner will receive a percentage of
revenues greater than the percentage of costs that it pays, there may
be a conflict of interest concerning which wells will be drilled based
on the wells' risk and profit potential;
o the allocation of all intangible drilling costs to you and the other
investors and the majority of the equipment costs to the managing
general partner may create a conflict of interest concerning whether
to complete a well;
o if the managing general partner, as tax matters partner, represents a
partnership before the IRS potential conflicts include whether or not
to expend partnership funds to contest a proposed adjustment by the
IRS, if any, to the amount of your deduction for intangible drilling
costs, or the credit to the managing general partner's capital account
for contributing the leases to the partnership;
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o which wells will be drilled by the managing general partner's and its
affiliates' other affiliated partnerships or third-party programs in
which they serve as driller/operator and which wells will be drilled
by the partnerships, and the terms on which the partnerships' leases
will be acquired;
o the terms on which the managing general partner or affiliated limited
partnerships may purchase producing wells from each partnership;
o the possible purchase of units by the managing general partner, its
officers, directors, and affiliates for a reduced price which would
dilute the voting rights of you and the other investors on certain
matters;
o the representation of the managing general partner and each
partnership by the same legal counsel;
o the right of Atlas Pipeline Partners to determine the order of
priority for constructing gathering lines;
o the benefits to Atlas Pipeline Partners of the managing general
partner drilling wells that will connect to the gathering system owned
by Atlas Pipeline Partners; and
o the managing general partner's affiliates' obligation, which does not
include the partnerships, to pay the difference between the gathering
fees to be paid by each partnership and the greater of $.35 per mcf or
16% of the gross sales price for the gas as described in "Proposed
Activities - Sale of Natural Gas and Oil Production - Gathering of
Natural Gas."
Other than certain guidelines set forth in "Conflicts of Interest," the managing
general partner has no established procedures to resolve a conflict of interest.
The Presentment Obligation May Not Be Funded and the Presentment Price May Not
Reflect Full Value. Subject to certain conditions, beginning with the fifth
calendar year after your partnership closes you may present your units to the
managing general partner for purchase. However, the managing general partner may
determine, in its sole discretion, that it does not have the necessary cash flow
or cannot borrow funds for this purpose on reasonable terms. In either event the
managing general partner may suspend the presentment feature. This risk is
increased because the managing general partner has and will incur similar
presentment obligations in other partnerships.
Further, the presentment price may not reflect the full value of a partnership's
property or your units because of the difficulty in accurately estimating
natural gas and oil reserves. The estimates are merely appraisals of value and
may not correspond to realizable value. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact way, and the accuracy of the reserve estimate is
a function of the quality of the available data and of engineering and
geological interpretation and judgment. The presentment price paid for your
units and any revenues received by you before the presentment may not be equal
to the purchase price of the units. Conversely, because the presentment price is
a contractual price it is not reduced by discounts such as minority interests
and lack of marketability that generally are used to value partnership interests
for tax and other purposes. (See "Presentment Feature.")
The Managing General Partner May Not Devote the Necessary Time to the
Partnerships Because Its Management Obligations Are Not Exclusive. The managing
general partner may not devote the necessary time to the partnerships. The
managing general partner and its affiliates will be engaged in other oil and gas
activities, including other partnerships and unrelated business ventures for
their own account or for the account of others, during the term of the
partnerships. (See "Management.")
Prepaying Subscription Proceeds to Managing General Partner May Expose the
Subscription Proceeds to Claims of the Managing General Partner's Creditors.
Under the drilling and operating agreement each partnership will be required to
immediately pay the managing general partner the investors' share of the entire
estimated price for drilling and completing the partnership's wells. Thus, these
funds could be subject to claims of the managing general partner's creditors.
(See "Financial Information Concerning the Managing General Partner.")
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Lack of Independent Underwriter May Reduce Due Diligence Investigation of the
Partnerships and the Managing General Partner. There has not been an extensive
in-depth "due diligence" investigation of the existing and proposed business
activities of the partnerships and the managing general partner that would be
provided by independent underwriters. Anthem Securities, which is affiliated
with the managing general partner, serves as dealer-manager and will receive
reimbursement of accountable due diligence expenses for certain due diligence
investigations conducted by the selling agents that will be reallowed to the
selling agents. However, its due diligence examination concerning the
partnerships cannot be considered to be independent or as comprehensive as an
investigation that would be conducted by an independent broker/dealer. (See
"Conflicts of Interest.")
A Lengthy Offering Period May Result in Delays in the Investment of Your
Subscription and Any Cash Distributions From the Partnership to You. Because the
offering period for a particular partnership can extend for many months, it is
likely that there will be a delay in the investment of your subscription. This
may create a delay in the partnership's cash distributions to you which will be
paid only after payment of the managing general partner's fees and expenses and
only if there is sufficient cash available. See "Terms of the Offering" for a
discussion of the procedures involved in the offering and in the formation of a
partnership.
Tax Risks
Changes in the Law May Reduce to Some Degree Your Tax Benefits From an
Investment in a Partnership. Your investment in a partnership may be affected by
changes in the tax laws. For example, under the Economic Growth and Tax Relief
Reconciliation Act of 2001 the federal income tax rates are being reduced
between 2001 and 2006, including reducing the top rate in stages from:
o 39.1% for 2001 to 38.6% for 2002 and 2003;
o 37.6% for 2004 and 2005; and
o 35% for 2006 through 2010.
This will reduce to some degree the amount of taxes you save by virtue of your
share of your partnership's deductions for intangible drilling costs, depletion,
and depreciation. Also, the federal income tax rates described above may be
changed in the future.
You May Owe Taxes in Excess of Your Cash Distributions from a Partnership. You
may become subject to income tax liability for partnership income in excess of
the cash you actually receive from a partnership. For example:
o if the partnership borrows money your share of partnership revenues
used to pay principal on the loan will be included in your taxable
income from the partnership and will not be deductible;
o income from sales of natural gas and oil may be accrued by a
partnership in one tax year, although payment is not actually received
by the partnership until the next tax year;
o 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;
o partnership revenues may be expended by the managing general partner
for non-deductible costs or retained to establish a reserve for future
estimated costs, including a reserve for the estimated costs of
eventually plugging and abandoning the wells; and
o the taxable disposition of partnership property or your units may
result in income tax liability in excess of cash distributions.
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Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the
Alternative Minimum Tax. You will be allocated a share of your partnership's
deduction for intangible drilling costs. However, under current tax law your
alternative minimum taxable income cannot be reduced by more than 40% by the
deduction for intangible drilling costs. Also, if you invest as a limited
partner you may not have enough passive income to use your share of a
partnership's deduction for intangible drilling costs.
Investment Interest Deductions of Investor General Partners May Be Limited. An
investor general partner's share of a 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 Could Result in Penalties to You. The managing
general partner believes that the partnerships are not tax shelters required to
register with the IRS. If it is subsequently determined by the IRS or the courts
that the partnerships were required to be registered with the IRS as tax
shelters, then you would be liable for a $250 penalty for failure to include a
tax registration number for your partnership on your tax return, unless this
failure was due to reasonable cause.
ADDITIONAL INFORMATION
The program and the partnerships composing the program currently are not
required to file reports with the SEC. However, a registration statement on Form
S-1 has been filed on behalf of the program with the SEC. Certain portions of
the registration statement have been deleted from this prospectus under SEC
rules and regulations. You are urged to refer to the registration statement and
exhibits for further information concerning the provisions of certain documents
referred to in this prospectus.
You may read and copy any materials filed as a part of the registration
statement, including the tax opinion included as Exhibit 8, at the SEC's Public
Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The SEC
maintains an internet world wide web site that contains registration statements,
reports, proxy statements, and other information about issuers who file
electronically with the SEC, including the program. The address of that site is
http://www.sec.gov. Also, you may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, a copy
of the tax opinion may be obtained by you or your advisors from the managing
general partner at no cost. The delivery of this prospectus does not imply that
its information is correct as of any time after its date.
FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS
Statements, other than statements of historical facts, included in this
prospectus and its exhibits address activities, events or developments that the
managing general partner and the partnerships anticipate will or may occur in
the future. These forward-looking statements include such things as:
o investment objectives;
o business strategy;
o estimated future capital expenditures;
o competitive strengths and goals;
o references to future success; and
o other similar matters.
These statements are based on certain assumptions and analyses made by the
partnerships and the managing general partner in light of their experience and
their perception of historical trends, current conditions, and expected future
developments.
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However, whether actual results will conform with these expectations is subject
to a number of risks and uncertainties, many of which are beyond the control of
the partnerships, including, but not limited to:
o general economic, market, or business conditions;
o changes in laws or regulations;
o the risk that the wells are productive, but do not produce enough
revenue to return the investment made;
o the risk that the wells are dry holes; and
o uncertainties concerning the price of natural gas and oil.
Thus, all of the forward-looking statements made in this prospectus and its
exhibits are qualified by these cautionary statements. There can be no assurance
that actual results will conform with the managing general partner's and the
partnerships' expectations.
INVESTMENT OBJECTIVES
Each partnership's principal investment objectives are to invest its
subscription proceeds in natural gas development wells which will:
o Provide quarterly cash distributions to you from the partnership in
which you invest until the wells are depleted, historically 20+
years, with a minimum annual cash flow of 10% during the first five
years beginning with your partnership's first revenue distribution
based on $10,000 per unit for all units sold. These distributions of
10% during the first five years are not guaranteed, but are subject
to the managing general partner's subordination obligation. The
managing general partner anticipates that investors in a partnership
will begin to receive quarterly cash distributions approximately
seven months after the offering period for a partnership ends. (See
"Participation in Costs and Revenues - Subordination of Portion of
Managing General Partner's Net Revenue Share.") The partnerships do
not currently hold any interests in any prospects on which the wells
will be drilled.
The basis for this forward looking statement is a reserve and economic
report effective September 30, 2002 which was prepared by Wright &
Company, Inc., petroleum consultants, and reviewed by the managing
general partner, which evaluated the past history and estimated future
production of 1,212 wells drilled to the Clinton/ Medina geological
formation in western Pennsylvania which is one of the primary drilling
areas of each partnership. These wells are owned by the managing
general partner and its affiliates and not by the partnerships. Based
on data in that report, approximately 1,149 of those wells are
expected by the managing general partner to produce more than 20
years. The Clinton/Medina geological formation is also the objective
formation in southern Ohio and western New York, which are secondary
drilling areas.
o Obtain tax deductions from the partnership in which you invest in the
year that you invest from intangible drilling costs to offset a
portion of your taxable income, subject to the passive activity rules
if you invest as a limited partner. For example, if you pay $10,000
for a unit your investment will produce a tax deduction of
approximately $9,000 per unit, 90% against:
o ordinary income or, in some situations, capital gain if you
invest as an investor general partner in a partnership; and
o passive income if you invest as a limited partner in a
partnership.
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If you are in either the 38.6% or 35% tax bracket for 2003 or the
37.6% or 34% tax bracket for 2004, then one unit will save you up to
approximately $3,475 or $3,150 per unit in Atlas America Public #12-
2003 Limited Partnership and $3,385 or $3,060 for units in a
partnership designated Atlas America Public #12-2004(___) Limited
Partnership in federal taxes in the year that you invest. Most states
also allow this type of a deduction against the state income tax.
If all or a portion of the wells in the partnership in which you
invest begin producing in the year in which you invest, then you may
be allocated taxable income which will be offset by the intangible
drilling cost deduction.
o Offset a portion of any taxable income generated by your partnership
with tax deductions from percentage depletion, which is 15% in 2003.
The percentage depletion rate fluctuates from year to year depending
on the price of oil, but under current tax law will not be less than
the statutory rate of 15% nor more than 25%.
o Obtain tax deductions of the remaining 10% of the initial investment
of you and the other investors in your partnership over a seven-year
cost recovery period. For example, if you pay $10,000 for a unit,
you will receive an additional tax deduction of approximately $1,000
per unit for depreciation of your partnership's equipment costs for
the wells. Also, under the Job Creation and Worker Assistance Act of
2002, your partnership will be entitled to accelerate the
depreciation allowance based on 30% of its equipment costs of the
wells for equipment acquired before September 11, 2004, in the year
the equipment is placed in service. Your share of this additional
accelerated depreciation deduction will not increase your
alternative minimum tax.
Attainment of these investment objectives by a partnership will depend on many
factors, including the ability of the managing general partner to select
suitable wells that will be productive and produce enough revenue to return the
investment made. The success of each partnership depends largely on future
economic conditions, especially the future price of natural gas which is
volatile and may decrease. Also, the extent to which each partnership attains
the foregoing investment objectives will be different, because each partnership
is a separate business entity which:
o generally will drill different wells;
o may drill wells situated in different areas; and
o will drill a different number of wells depending primarily on the
amount of their respective subscription proceeds.
There can be no guarantee that the foregoing objectives will be attained.
ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS
You may choose to invest in a partnership as an investor general partner so that
you can receive an immediate tax deduction against any type of income. To help
reduce the risk that you and other investor general partners could be required
to make additional payments to the partnership, the managing general partner
will take the actions set forth below.
o Insurance. The managing general partner will obtain and maintain
insurance coverage in amounts and for purposes which would be
carried by a reasonable, prudent general contractor and operator in
accordance with industry standards. Each partnership will be
included as an insured under these general, umbrella, and excess
liability policies. In addition, the managing general partner
requires all of its subcontractors to certify that they have
acceptable insurance coverage for worker's compensation and general,
auto, and
18
excess liability coverage. Major subcontractors are required to carry
general and auto liability insurance with a minimum of $1 million
combined single limit for bodily injury and property damage in any one
occurrence or accident. In the event of a loss, the insurance policies
of the particular subcontractor at risk would be drawn on before the
insurance of the managing general partner or that of the partnership.
The managing general partner's current insurance coverage satisfies the
following specifications:
o worker's compensation insurance in full compliance with the laws of
the Commonwealth of Pennsylvania and any other applicable state laws
where the wells will be drilled;
o commercial general liability: bodily injury and property damage third
party liability, including products/completed operations, blow out,
cratering, and explosion with limits of $1 million per occurrence/$2
million general aggregate; $1 million products/completed operations
aggregate;
o underground resources and equipment property damages liability to
others with a limit of $1 million;
o automobile liability with a $1 million combined single limit;
o employer's liability with a $500,000 policy limit;
o pollution liability resulting from a "pollution incident" with a limit
of $1 million for bodily injury and property damage and a limit of
$100,000 for clean-up for third-parties. Coverage, however, does not
apply to pollution damage to the well site itself or the property of
the insured. A "pollution incident" is defined as the discharge,
dispersal, seepage, migration, release or escape of one or more
pollutants directly from a well site;
o commercial umbrella liability;
o commercial primary umbrella limit of $25 million over general
liability, automobile liability, and employer's liability and a
$10 million sublimit for pollution liability; and
o commercial excess liability providing excess limits of $24
million over the $25 million provided in the commercial umbrella,
but excluding pollution liability.
Because the managing general partner is driller and operator of other
partnerships, the insurance available to each partnership could be
substantially less if insurance claims are made in the other partnerships.
This insurance has deductibles, which would first have to be paid by a
partnership, of:
o $2,500 per occurrence for bodily injury and property damage; and
o $10,000 per pollution incident for pollution damage.
The insurance has terms, including exclusions, which are standard for the
natural gas and oil industry. On request the managing general partner will
provide you or your representative a copy of its insurance policies. The
managing general partner will use its best efforts to maintain insurance
coverage that meets its current coverage, but 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 a partnership's insurance coverage, which the managing
general partner does not anticipate, then the managing general partner must
notify you at least 30 days before the effective date of the change. You
will have the right to
19
convert your units into limited partner units before the change by
giving written notice to the managing general partner.
o Conversion of Investor General Partner Units to Limited Partner
Units. Your investor general partner units will be automatically
converted by the managing general partner to limited partner units
beginning in the calendar year after all of the wells in your
partnership have been drilled and completed. In each partnership,
the managing general partner anticipates that the wells will be
placed in service approximately seven months after a partnership
closes.
Once your units are converted, which is a nontaxable event, you will
have the lesser liability of a limited partner in your partnership
under Delaware law for obligations and liabilities arising after the
conversion. However, you will continue to have the responsibilities of
a general partner for partnership liabilities and obligations incurred
before the effective date of the conversion. For example, you might
become liable for partnership liabilities in excess of your
subscription during the time the partnership is engaged in drilling
activities and for environmental claims that arose during drilling
activities, but were not discovered until after conversion.
o Nonrecourse Debt. The partnerships do not anticipate that they will
borrow funds. However, if borrowings are required, then the
partnerships will be permitted to borrow funds only from the
managing general partner or its affiliates without recourse against
non-partnership assets. Thus, if there is a default under this loan
arrangement you cannot be required to contribute funds to the
partnership. Any borrowings for a partnership will be repaid from
that partnership's revenues.
The amount that may be borrowed at any one time by a partnership may
not exceed an amount equal to 5% of the investors' subscriptions in
the partnership. However, because you do not bear the risk of repaying
these borrowings with non-partnership assets, the borrowings will not
increase the extent to which you are allowed to deduct your individual
share of partnership losses.
o Indemnification. The managing general partner will indemnify you from
any liability incurred in connection with your partnership that is in
excess of your interest in the partnership's:
o undistributed net assets; and
o insurance proceeds, if any, from all potential sources.
The managing general partner's indemnification obligation, however,
will not eliminate your potential liability if the managing general
partner's assets are insufficient to satisfy its indemnification
obligation. There can be no assurance that the managing general
partner's assets, including its liquid assets, will be sufficient to
satisfy its indemnification obligation.
CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS
Source of Funds
Each partnership must receive minimum subscriptions of $1 million to close, and
the subscription proceeds of all partnerships, in the aggregate, may not exceed
$75 million. There are no other requirements regarding the size of a
partnership, and the subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other
partnerships. However, see "Terms of the Offering - Subscription to a
Partnership" regarding the targeted range of maximum subscriptions for each
partnership.
On completion of an offering for a partnership, a partnership's source of funds
will be as follows assuming each unit is sold for $10,000:
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o the subscription proceeds of you and the other investors, which will
be:
o $1 million if 100 units are sold;
o $75 million if 7,500 units are sold; and
o the managing general partner's capital contribution, which includes
its credit for contributing the leases, must be at least 25% of all
capital contributions, which it estimates will be:
o approximately $345,390 if 100 units are sold; and
o approximately $25,904,250 if 7,500 units are sold.
Thus, the total amount available to a partnership will be approximately
$1,345,390 for the sale of 100 units ranging to approximately $100,904,250 for
the sale of 7,500 units.
The managing general partner has made the largest single capital contribution in
each of its prior partnerships and no individual investor has contributed more,
although the total investor contributions in each partnership have exceeded the
managing general partner's contribution. The managing general partner expects to
make the largest single capital contribution in the partnerships as well.
Use of Proceeds
The subscription proceeds received from you and the other investors for each
partnership will be used to pay:
o 100% of the intangible drilling costs of drilling and completing that
partnership's wells; and
o 34% of the equipment costs of drilling and completing that
partnership's wells, but not to exceed 10% of that partnership's
subscription proceeds.
The managing general partner will contribute all of the leases to each
partnership covering the acreage on which the wells will be drilled, and pay:
o 100% of the organization and offering costs;
o 66% of the equipment costs of drilling and completing that
partnership's wells; and
o any equipment costs that exceed 10% of that partnership's subscription
proceeds that would otherwise be charged to you and the other
investors.
The following tables present information concerning the partnerships' use of the
proceeds provided by both you and the other investors and the managing general
partner. The tables are based on the managing general partner's required capital
contribution of 25% of all capital contributions for the partnerships', which
includes its credit for contributing the leases. The entity receiving the
dealer-manager fee, sales commissions, the .5% accountable marketing expense
fee, and .5% reimbursement for bona fide accountable due diligence expenses will
be the dealer-manager, a portion of which will be reallowed to the
broker/dealers as discussed in "Plan of Distribution." The organizational costs
will be paid to various entities and the intangible drilling costs and tangible
costs will be paid to the managing general partner. The managing general partner
will receive a credit for its contribution of leases to a partnership.
The tables are presented based on:
o the sale of 100 units which is the minimum number of units for each
partnership;
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o the sale of 4,000 units which is the targeted number of units for
Atlas America Public #12-2003 Limited Partnership which is to be
closed by December 31, 2003; and
o the sale of 7,500 units which is the maximum number of units for all
partnerships in the program.
Substantially all of the proceeds available to each partnership will be expended
for the following purposes and in the following manner:
INVESTOR CAPITAL
100 UNITS 4,000 UNITS 7,500 UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1) SOLD % (1)
- ------------------- ------------- ------------- ------------- ------------- ------------- -------------
Organization and Offering
Expenses
Dealer-manager fee, sales
commissions, .5% accountable
marketing expense fee,
and .5% reimbursement for
bona fide accountable due
diligence expenses - 0 - - 0 - - 0 - - 0 - - 0 - - 0 -
Organization costs - 0 - - 0 - - 0 - - 0 - - 0 - - 0 -
Amount Available for
Investment:
Intangible drilling costs
(2) $900,000 90% $36,000,000 90% $67,500,000 90%
Equipment costs (2) $100,000 10% $4,000,000 10% $7,500,000 10%
Leases - 0 - - 0 - - 0 - - 0 - - 0 - - 0 -
------------- ------------- ------------- ------------- ------------- -------------
Total Investor Capital $1,000,000 100% $40,000,000 100% $75,000,000 100%
============= ============= ============= ============= ============= =============
- ---------------
(1) The percentage is based on total investor subscriptions and excludes the
managing general partner's capital contribution.
(2) The equipment costs will vary depending on the actual cost of drilling and
completing the wells, but not less than 90% of the subscription proceeds
provided by you and the other investors will be used to pay intangible
drilling costs. Equipment costs will be charged 34% to the investors and 66%
to the managing general partner, however the investors' share of these costs
may not exceed 10% of investor subscriptions as discussed in "Participation
in Costs and Revenues." Thus, this table and the following tables assume the
maximum amount of investor subscriptions, which is 10%, is used to pay
equipment costs.
MANAGING GENERAL PARTNER CAPITAL
100 UNITS 4,000 UNITS 7,500 UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1) SOLD % (1)
- ------------------- ------------- ------------- ------------- ------------- ------------- -------------
Organization and Offering
Expenses
Dealer-manager fee, sales
commissions, .5% accountable
marketing expense fee,
and .5% reimbursement for
bona fide accountable due
diligence expenses (2) $105,000 30.4% $4,200,000 30.4% 7,875,000 30.4%
Organization costs (2) $45,000 13.0% $1,800,000 13.0% $3,375,000 13.0%
Amount Available for
Investment:
Intangible drilling costs - 0 - - 0 - - 0 - - 0 - - 0 - 0%
Equipment costs (3) $168,220 48.7% $6,728,800 48.7% $12,616,500 48.7%
Leases (4) $27,170 7.9% $1,086,800 7.9% $2,037,750 7.9%
------------- ------------- ------------- ------------- ------------- -------------
Total Managing General
Partner Capital $ 345,390 100% $13,815,600 100% $25,904,250 100%
============= ============= ============= ============= ============= =============
- ---------------
22
(1) The percentage is based on the managing general partner's capital
contribution and excludes the investors' subscriptions.
(2) If these fees, sales commissions, reimbursements and organization costs
exceed 15% of the investors' subscription proceeds in a partnership, then
the excess will be paid by the managing general partner, but will not be
included as part of its capital contribution.
(3) Generally, as described in "Compensation - Drilling Contracts" the managing
general partner's share of equipment costs is approximately $33,644 per well
and for purposes of this table has been quantified based on the managing
general partner's estimate of the number of wells that will be drilled as
set forth above which is approximately five wells in which it has a 100%
working interest per $1 million of subscriptions. Notwithstanding, these
costs will vary depending on the actual costs of drilling and completing the
wells. Also, see footnote (2) to the " - Investor Capital" table.
(4) Instead of contributing cash for the leases, the managing general partner
will assign to each partnership the leases covering the acreage on which the
partnership's wells will be drilled. Generally, as described in
"Compensation - Lease Costs," the managing general partner's lease cost is
approximately $5,434 per prospect and for purposes of this table has been
quantified based on the managing general partner's estimate of the number of
wells that will be drilled as set forth above which is approximately five
wells in which it has a 100% working interest per $1 million of
subscriptions. Notwithstanding, the managing general partner's lease costs
on a prospect may be significantly higher than $5,434, but the managing
general partner's credit for the leases contributed must not exceed its
cost, unless the managing general partner has a reason to believe that cost
is materially more than fair market value of the property, in which case the
managing general partner's credit for its lease contribution must not exceed
fair market value.
TOTAL PARTNERSHIP CAPITAL
100 UNITS 4,000 UNITS 7,500 UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1) SOLD % (1)
- ------------------------ ------------- ------------- ------------- ------------- ------------- -------------
Organization and Offering
Expenses
Dealer-manager fee, sales
commissions, .5%
nonaccountable marketing
expense fee, and .5%
reimbursement for bona
fide accountable due
diligence expenses (2) $105,000 7.8% $4,200,000 7.8% $7,875,000 7.8%
Organization costs (2) $45,000 3.3% $1,800,000 3.3% $3,375,000 3.3%
Amount Available for
Investment:
Intangible drilling costs
(3) $900,000 67.0% $36,000,000 67.0% $67,500,000 67.0%
Equipment costs (3) $ 268,220 19.9% $10,728,800 19.9% $20,116,500 19.9%
Leases (4) $ 27,170 2.0% $1,086,800 2.0% $2,037,750 2.0%
------------- ------------- ------------- ------------- ------------- -------------
Total Partnership Capital $ 1,345,390 100% $53,815,600 100% $100,904,250 100%
============= ============= ============= ============= ============= =============
- ---------------
(1) The percentage is based on total investor subscriptions and the managing
general partner's estimate of its capital contributions.
(2) If these fees, sales commissions, reimbursements and organization costs
exceed 15% of the investors' subscription proceeds in a partnership, then
the excess will be paid by the managing general partner, but will not be
included as part of its capital contribution.
(3) Generally, as described in "Compensation - Drilling Contracts" the managing
general partner's share of equipment costs is approximately $33,644 per well
and for purposes of this table has been quantified based on the managing
general partner's estimate of the number of wells that will be drilled as
set forth above which is approximately five wells in which it has a 100%
working interest per $1 million of subscriptions. Notwithstanding, these
costs will vary depending on the actual cost of drilling and completing the
wells, but not less than 90% of the subscription proceeds provided by you
and the other investors will be used to pay intangible drilling costs. Also,
see footnote (2) to the " - Investor Capital" table.
(4) Instead of contributing cash for the leases, the managing general partner
will assign to each partnership the leases covering the acreage on which the
partnership's wells will be drilled. Generally, as described in
"Compensation - Lease Costs," the managing general partner's lease cost is
approximately $5,434 per prospect and for purposes of the table has been
quantified based on the managing general partner's estimate of the number of
wells that will be drilled as set forth above which is approximately five
wells in which it has a 100% working interest per $1 million of
subscriptions. Notwithstanding, the managing general partner's lease costs
on a prospect may be significantly higher than $5,434, but the managing
general partner's credit for the leases contributed must not exceed its
cost, unless the managing general
23
partner has a reason to believe that cost is materially more than fair market
value of the property, in which case the managing general partner's credit for
its lease contribution must not exceed fair market value.
COMPENSATION
The items of compensation paid to the managing general partner and its
affiliates from each partnership are set forth below.
Natural Gas and Oil Revenues
Subject to the managing general partner's subordination obligation, the
investors and the managing general partner will share in each partnership's
revenues in the same percentages as their respective capital contributions bear
to the total partnership capital contributions for that partnership except that
the managing general partner will receive an additional 7% of that partnership's
revenues. However, the managing general partner's total revenue share may not
exceed 35% of that partnership's revenues regardless of the amount of its
capital contribution.
For example, if the managing general partner contributes the minimum of 25% of
the total partnership capital contributions and the investors contribute 75% of
the total partnership capital contributions, then the managing general partner
will receive 32% of the partnership revenues and the investors will receive 68%
of the partnership revenues. On the other hand, if the managing general partner
contributes 30% of the total partnership capital contributions and the investors
contribute 70% of the total partnership capital contributions, then the managing
general partner will receive 35% of the partnership revenues, not 37%, because
its revenue share cannot exceed 35% of partnership revenues, and the investors
will receive 65% of partnership revenues.
Furthermore, the managing general partner's revenue share from each partnership
is subject to its subordination obligation as described in "Partnership Costs
and Revenues - Subordination of Portion of the Managing General Partner's
Revenue Share" and the accompanying tables. For example, if the managing general
partner's revenue share is 35% of the partnership revenues, then up to 17.5% of
the managing general partner's partnership revenues could be used for its
subordination obligation.
Lease Costs
Under the partnership agreement the managing general partner will contribute to
each partnership all the undeveloped leases necessary to cover each of the
partnership's prospects. The managing general partner will receive a credit to
its capital account equal to:
o the cost of the leases; or
o the fair market value of the leases if the managing general partner
has reason to believe that cost is materially more than the fair
market value.
The cost of the leases will include a portion of the managing general partner's
reasonable, necessary, and actual expenses for services allocated to a
partnership's leases by it using industry guidelines.
In the primary areas of interest, the managing general partner's lease cost is
approximately $5,434 per prospect assuming a partnership acquires 100% of the
interest in the prospect. The managing general partner's credit for lease costs
will be proportionally reduced to the extent a partnership acquires less than
100% of the interest in the prospect. In this regard, a gross well is a well in
which a partnership owns an interest, and a net well is a well in which a
partnership's actual interest in the well, which may be less than 100%, is
divided by one hundred. Assuming all the leases are situated in these areas, the
managing general partner estimates that its credit for lease costs will be:
o $27,170 if $1 million is received, which is 5 wells in which it has a
100% working interest times $5,434 per prospect; and
24
o $2,037,750 if $75 million is received, which is 375 wells in which it
has a 100% working interest times $5,434 per prospect.
Notwithstanding, the managing general partner's lease costs on a prospect may be
significantly higher than $5,434, but the managing general partner's credit for
the leases contributed must not exceed its cost, unless the managing general
partner has a reason to believe that cost is materially more than fair market
value of the property, in which case the managing general partner's credit for
its lease contribution must not exceed fair market value.
Drilling a partnership's wells may also provide the managing general partner
with offset prospects to be drilled by allowing it to determine at the
partnership's expense the value of adjacent acreage in which the partnership
would not have any interest.
Drilling Contracts
Each partnership will enter into the drilling and operating agreement with the
managing general partner to drill and complete the partnership wells at cost
plus 15%. The managing general partner has determined that this is a competitive
rate based on:
o information it has concerning drilling rates of third-party drilling
companies in the Appalachian Basin;
o the estimated costs of non-affiliated persons to drill and equip wells
in the Appalachian Basin as reported for 2001 by an independent
industry association which surveyed other non-affiliated operators in
the area; and
o information it has concerning increases in drilling costs in the area
since 2001.
If this rate subsequently exceeds competitive rates available from other non-
affiliated persons in the area engaged in the business of rendering or providing
comparable services or equipment, then the rate will be adjusted to the
competitive rate. However, the 15% premium may not be increased by the managing
general partner during the term of the partnership.
The managing general partner expects to subcontract some of the actual drilling
and completion of each partnership's wells to third-parties selected by it.
However, the managing general partner may not benefit by interpositioning itself
between the partnership and the actual provider of drilling contractor services,
and may not profit by drilling in contravention of its fiduciary obligations to
the partnership.
Cost, when used with respect to services, generally means the reasonable,
necessary, and actual expense incurred in providing the services, determined in
accordance with generally accepted accounting principles. The cost of the well
includes reimbursement to the managing general partner of the investors' share
of its general and administrative overhead equal to $14,142 per well assuming a
100% working interest in the well. The cost of the well also includes all
ordinary costs of drilling, testing and completing the well, which includes the
cost of the following for a natural gas well, which will be the classification
of the majority of the wells:
o 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;
o installing gathering lines for the natural gas of up to 2,500 feet;
and
o the necessary facilities for the production of natural gas.
The amount of compensation that the managing general partner could earn as a
result of these arrangements depends on many factors, including the number of
wells drilled. Assuming a 100% working interest in the well, the managing
general partner anticipates that the average cost of drilling and completing a
partnership's wells, excluding lease costs, will be approximately $233,609 per
well, which includes the costs paid by you and the other investors in the
approximate amount of $199,965 and the managing general partner in the
approximate amount of $33,644. This estimate was based on the average
25
well cost, including "natural" completions, paid to the managing general partner
for all wells that it drilled in the Appalachian Basin for its partnerships for
the calendar year 2002, all of which included a 15% profit per well. Also, in
order to provide a more accurate estimate, the average general and
administrative overhead reimbursement of $14,380 per well from the investors in
2002 was reduced to $14,142 per well which is the same amount that the investors
in the partnerships will pay. These 2002 wells were drilled by the managing
general partner's partnerships in different areas with different drilling and
completion costs in each area. Based on this average cost for a 100% working
interest in each partnership well, as adjusted for a decrease in the investors'
reimbursement of the managing general partner's general and administrative
overhead from the 2002 average of $14,380 to $14,142 per gross well, the
managing general partner expects that the profit of 15% which it will receive
will be approximately $26,083 per well with respect to the intangible drilling
costs and the portion of equipment costs paid by you and the other investors.
The actual compensation received by the managing general partner as a result of
each partnership's drilling operations will vary from these assumptions, but the
managing general partner's profit will not in any event exceed 15% of the costs
of drilling and completing the wells. Also, to the extent that a partnership
acquires less than a 100% working interest in a well, its drilling and
completion costs of that well will be proportionately decreased.
Subject to the foregoing and based on the investors' share of the average well
cost in 2002, the managing general partner estimates that its general and
administrative overhead reimbursement of $14,142 and profit of 15%
(approximately $26,083), which totals $40,225 per well in which a partnership
has a 100% working interest, will be:
o $201,125 if $1 million is received, which is 5 wells in which a
partnership has a 100% working interest times $40,225; and
o $15,084,375 if $75 million is received, which is 375 wells in which a
partnership has a 100% working interest times $40,225.
The average cost of $233,609 per well in which it has a 100% working interest
anticipated by the general partner as discussed above consists of:
o intangible drilling costs of approximately $182,633 (78.18%); and
o equipment costs of approximately $50,976 (21.82%).
In this regard, the managing general partner further anticipates that a
partnership's cost of drilling and completing any given well in which it has a
100% working interest in the partnership's primary areas, excluding lease costs,
may range from as low as approximately $142,785 to as high as $268,000 or more,
depending on the area.
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
from each partnership:
o reimbursement at actual cost for all direct expenses incurred on
behalf of the partnership; and
o well supervision fees for operating and maintaining the wells during
producing operations at a competitive rate.
Currently the competitive rate is $275 per well per month. The well supervision
fees will be proportionately reduced to the extent the partnership acquires less
than 100% of the working interest in the well, and may be adjusted for inflation
annually beginning with the second calendar year after a partnership closes. If
the foregoing rates exceed competitive rates available from other non-affiliated
persons in the area engaged in the business of providing comparable services or
equipment, then the rates will be adjusted to the competitive rate. The managing
general partner may not benefit by interpositioning itself between the
partnership and the actual provider of operator services. In no event will any
consideration received for operator services be duplicative of any consideration
or reimbursement received under the partnership agreement.
26
The well supervision fee covers all normal and regularly recurring operating
expenses for the production, delivery, and sale of natural gas and oil, such as:
o well tending, routine maintenance, and adjustment;
o reading meters, recording production, pumping, maintaining appropriate
books and records; and
o preparing reports to the partnership and to government agencies.
The well supervision fees do not include costs and expenses related to:
o the purchase of equipment, materials, or third-party services;
o brine disposal; and
o rebuilding of access roads.
These costs will be charged at the invoice cost of the materials purchased or
the third-party services performed.
The managing general partner estimates that it will receive well supervision
fees for a partnership's first 12 months of operation after all of the wells
have been placed in production of:
o $16,500 if $1 million is received, which is 5 wells in which it has a
100% working interest at $275 per well per month; and
o $1,237,500 if $75 million is received, which is 375 wells in which it
has a 100% working interest at $275 per well per month.
Gathering Fees
Under the partnership agreement the managing general partner will be responsible
for gathering and transporting the natural gas produced by the partnerships to
interstate pipeline systems, local distribution companies, and end-users in the
area. The managing general partner anticipates that it will use the gathering
system owned by Atlas Pipeline Partners for the majority of the natural gas as
described in "Proposed Activities - Sale of Natural Gas and Oil Production -
Gathering of Natural Gas." The managing general partner's affiliate, Atlas
America, Inc., which is sometimes referred to in this prospectus as "Atlas
America," or another affiliate controls and manages the pipeline for Atlas
Pipeline Partners. Also, Atlas America and the managing general partner's
affiliates, Resource Energy, Inc., sometimes referred to in this prospectus as
"Resource Energy," and Viking Resources Corporation, sometimes referred to in
this prospectus as "Viking Resources," (the "Resource Entities"), which do not
include the partnerships, have an agreement with Atlas Pipeline Partners which
provides that generally all of the gas produced by their affiliated
partnerships, which includes each partnership composing the program, will be
gathered and transported through Atlas Pipeline Partners and that the Resource
Entities must pay the greater of $.35 per mcf or 16% of the gross sales price
for each mcf transported by these affiliated partnerships. Each partnership will
pay a gathering fee directly to the managing general partner at the competitive
rates described below. If the gathering system owned by Atlas Pipeline Partners
is used by the partnership the managing general partner will apply the gathering
fee it receives towards the Resource Entities' agreement with Atlas Pipeline
Partners, and if a third- party gathering system is used the managing general
partner will pay a portion or all of its gathering fee to the third-party
gathering the natural gas.
The current rates for gathering fees, which have been determined by the managing
general partner for each partnership's primary and secondary drilling areas, are
set forth in the chart below. Although the gathering fee paid by each
partnership to the managing general partner may be increased by the managing
general partner, in its sole discretion, from those set forth in the chart
below, the managing general partner may not increase the gathering fees beyond
those charged by unaffiliated third-parties in the same geographic area engaged
in similar businesses. The gathering fees have not been increased by the
managing general partner in several years.
27
Current Amount of
Gathering Fees to be
Paid by each
Partnership to
Each Partnership's Primary and Secondary Drilling Managing General
Areas Partner (1)
- ------------------------------------------------------ ---------------------
Clinton/Medina Geological Formation in Western
Pennsylvania in Crawford, Mercer, Lawrence, Warren,
and Venango Counties, and Eastern Ohio primarily in
Stark, Mahoning, Trumbull and Portage Counties....... $.29 per mcf
Mississippian/Upper Devonian Sandstone Reservoirs in
Fayette and Greene Counties, Pennsylvania............ $.35 per mcf
Upper Devonian Sandstone Reservoirs in
Armstrong County, Pennsylvania....................... (2)
Clinton/Medina Geological Formation in New York........ $.35 per mcf
Mississippian Berea Sandstone Geological Formation in
Columbiana County, Ohio.............................. $.35 per mcf
Devonian Oriskany Sandstone Geological Formation in
Tuscarawas County, Ohio.............................. $.35 per mcf
Clinton/Medina Geological Formation in Southern Ohio... $.35 per mcf
Upper Devonian Sandstone Reservoirs in
McKean County, Pennsylvania.......................... $.70 per mcf (3)
- ---------------
(1) The gathering fee paid by each partnership must not exceed a competitive
rate as determined by the managing general partner, and the managing general
partner may increase or decrease the gathering fee to a competitive rate
from time to time if conditions in the industry change.
(2) Each partnership will use a gathering system provided by a third-party joint
venture partner which will not charge the partnership a gathering fee if it
markets the gas. If the managing general partner markets the gas for the
partnership, then the partnership will pay a gathering fee to the managing
general partner equal to that charged by the third-party, which the managing
general partner anticipates will be $.20 per mcf.
(3) In this area, a partnership will deliver gas into a gathering system a
segment of which will be provided by Atlas Pipeline Partners and a segment
of which will be provided by a third-party. The third-party will receive
fees of $.25 per mcf for transportation and $.10 per mcf for compression.
From the fees charged the partnership by the managing general partner, the
managing general partner will pay $.35 to the third-party and $.35 to Atlas
Pipeline Partners.
The actual amount to be paid by a partnership to the managing general partner
cannot be quantified because the volume of natural gas that will be produced and
transported from the partnership's wells cannot be predicted.
Dealer-Manager Fees
Subject to certain exceptions described in "Plan of Distribution," Anthem
Securities, the dealer-manager and an affiliate of the managing general partner,
will receive on each unit sold to an investor:
o a 2.5% dealer-manager fee;
o a 7% sales commission;
o a .5% accountable marketing expense fee; and
o a .5% reimbursement of the selling agents' bona fide accountable due
diligence expenses.
The dealer-manager will receive:
o $105,000 if $1 million is received by a partnership; and
28
o $7,875,000 if $75 million is received by the partnerships.
All of the sales commissions and reimbursement of the selling agents' bona fide
accountable due diligence expenses will be reallowed to the selling agents, but
only a portion of the accountable marketing expense fee may be allowed to the
selling agents. Of the 2.5% dealer-manager fee, a portion will be reallowed to
the wholesalers who are associated with the managing general partner and
registered through Anthem Securities for subscriptions obtained through their
efforts. The dealer-manager will retain the remainder of the dealer-manager fee
and the accountable marketing expense fee not allowed to the selling agents.
Anthem Securities is a wholly owned subsidiary of AIC, Inc., which owns 100% of
the common stock of the managing general partner.
Interest and Other Compensation
The managing general partner or an affiliate will have the right to charge a
competitive rate of interest on any loan it may make to or on behalf of a
partnership. If the managing general partner provides equipment, supplies, and
other services to a partnership, then it may do so at competitive industry
rates. The managing general partner will determine a competitive rate of
interest and competitive industry rates for equipment, supplies and other
services by conducting a survey of the interest and/or fees charged by
unaffiliated third-parties in the same geographic area engaged in similar
businesses. If possible, the managing general partner will contact at least two
unaffiliated third-parties, however, the managing general partner will have sole
discretion in determining the amount to be charged a partnership.
Estimate of Administrative Costs and Direct Costs to be Borne by the
Partnerships
The managing general partner and its affiliates will receive from each
partnership an unaccountable, fixed payment reimbursement for their
administrative costs, which has been determined by the managing general partner
to be $75 per well per month. It is subject to the following:
o it will not be increased in amount during the term of the partnership;
o it will be proportionately reduced to the extent the partnership
acquires less than 100% of the working interest in the well;
o it will be the entire payment to reimburse the managing general
partner for the partnership's administrative costs; and
o it will not be received for plugged or abandoned wells.
The managing general partner estimates that the unaccountable, fixed payment
reimbursement for administrative costs allocable to a partnership's first 12
months of operation after all of its wells have been placed into production will
not exceed approximately:
o $4,500 if $1 million is received, which is 5 wells in which it has a
100% working interest at $75 per well per month; and
o $337,500 if $75 million is received, which is 375 wells in which it
has a 100% working interest at $75 per well per month.
Direct costs will be determined by the managing general partner, in its sole
discretion, including the provider of the services or goods and the amount of
the provider's compensation. Direct costs will be billed directly to and paid by
each partnership to the extent practicable. The anticipated direct costs set
forth below for a partnership's first 12 months of operation after all of its
wells have been placed into production may vary from the estimates shown for
numerous reasons which cannot accurately be predicted. These reasons include:
o the number of investors;
29
o the number of wells drilled;
o the partnership's degree of success in its activities;
o the extent of any production problems;
o inflation; and
o various other factors involving the administration of the partnership.
Maximum
Minimum Subscriptions
Subscriptions of $75 million
of $1 million (1)
----------------- -----------------
Direct Costs
External Legal ...................... $ 6,000 $18,000
Accounting Fees for Audit and Tax
Preparation......................... 20,500 94,500
Independent Engineering Reports ..... 1,500 30,000
----------------- -----------------
TOTAL ............................... $28,000 $142,500
================= =================
- ---------------
(1) This assumes three partnerships as described below in "Terms of the
Offering - Subscription to a Partnership" regarding the targeted maximum
subscriptions of each partnership.
TERMS OF THE OFFERING
Subscription to a Partnership
Atlas America Public #12-2003 Program will offer for sale an aggregate of $75
million of preformation interests in a series of up to three limited
partnerships to be formed under the laws of Delaware. Units of preformation
investor general partner interest and preformation limited partner interest will
become investor general partner units and limited partner units, respectively,
in the particular partnership. You may purchase units only if you meet the
suitability standards set forth below. The units will be offered for sale over a
period which may extend up to December 31, 2004, but may end earlier.
The minimum required aggregate subscription proceeds for the offering of units
in each partnership will be $1 million after the discounts described in "Plan of
Distribution." If this minimum amount of aggregate subscriptions is not received
in the offering of units of any partnership, then the partnership will not be
funded, and the escrow agent will promptly return all subscription proceeds for
that partnership to the respective subscribers in full with any interest earned
on the escrowed funds and without any deduction from the escrowed funds.
Set forth below is the targeted maximum subscriptions for each partnership,
although these targeted amounts are not mandatory and the managing general
partner may determine the maximum subscription for each partnership in its sole
discretion. The maximum subscription of any partnership must be the lesser of:
o the registered amount of $75 million; or
o the number of units unsold from the $75 million aggregate
registration.
The various partnerships and the subscription period for each will be as set
forth below, unless earlier terminated or withdrawn by the managing general
partner. The managing general partner may close the period of any partnership at
any time once the partnership is in receipt of subscription proceeds of $1
million. The offering of any particular partnership may extend beyond its
anticipated termination date by not more than 122 days or be terminated earlier.
However, the offering of
30
"Atlas America Public #12-2003 Limited Partnership" may not extend beyond
December 31, 2003, and the partnerships designated "Atlas America Public #12-
2004(___) Limited Partnership" may not extend beyond December 31, 2004.
Required Targeted Targeted
Minimum Maximum Ending
Partnership Name Subscription Subscription Date (1)
- ------------------------------------------- ------------- ------------- -----------------------
Atlas America Public #12-2003 $1 million $40 million December 31, 2003
The units in the above partnership will be sold only during 2003.
Atlas America Public #12-2004(A) $1 million $17.5 million March 30, 2004
Atlas America Public #12-2004(B) $1 million $17.5 million August 31, 2004
The units in the above partnerships will be sold only during 2004.
- ---------------
(1) The offering of units in subsequent partnerships will not begin until the
subscription of units in prior partnerships has reached the minimum
subscription or that prior offering has ended.
Units are offered at a subscription price of $10,000 per unit, subject to
certain exceptions which are described in "Plan of Distribution," and must be
paid 100% in cash at the time of subscribing. The subscription price of the
units has been arbitrarily determined by the managing general partner because
the partnerships have not been formed and do not have any prior operations,
assets, earnings, liabilities or present value. Your minimum subscription is one
unit; however, the managing general partner, in its discretion, may accept
one-half unit ($5,000) subscriptions from you at any time in each partnership.
Larger fractional subscriptions will be accepted in $1,000 increments, beginning
with either $11,000, $12,000, etc. if you pay $10,000 for a full unit or $6,000,
$7,000, etc. if you pay $5,000 for a one-half unit.
The managing general partner will have exclusive management authority for each
partnership. You will have the election to purchase units in a partnership as
either an investor general partner or a limited partner. Each partnership will
be a separate business entity from the other partnerships. Thus, as an investor,
you will be a partner only in the partnership in which you invest. You will have
no interest in the business, assets or tax benefits of the other partnerships
unless you also invest in the other partnerships. Your investment return will
depend solely on the operations and success or lack of success of the particular
partnership in which you invest.
Partnership Closings and Escrow
Subscription proceeds for a partnership will be held in a separate interest
bearing escrow account at National City Bank of Pennsylvania until receipt of
the minimum subscriptions. A partnership may not break escrow unless the
partnership is in receipt of subscription proceeds of $1 million after the
discounts described in "Plan of Distribution." However, on receipt of the
minimum subscriptions and written instructions to the escrow agent from the
managing general partner and the dealer-manager, the managing general partner on
behalf of a partnership may:
o form the partnership under the Delaware Revised Uniform Limited
Partnership Act;
o break escrow;
o transfer the escrowed funds to a partnership account;
o enter into the drilling and operating agreement with itself or an
affiliate as operator; and
o begin drilling to the extent the prospects have been identified.
31
After breaking escrow additional subscription payments may be paid directly to a
partnership account and will continue to earn interest until the offering
closes. At or about the time of closing of a particular partnership, the
managing general partner anticipates it will supplement this prospectus to
reflect the results of the offering of that partnership.
If subscriptions for $1 million are not received by the offering termination
date of a partnership, which is no later than the 122nd day after the targeted
ending date set forth above in "- Subscription to a Partnership," 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.
Also, if the offering of units in Atlas America Public #12-2003 Limited
Partnership has not closed on or before December 31, 2003, or any partnership
designated Atlas America Public #12-2004(___) Limited Partnership, has not
closed on or before December 31, 2004, then the escrow agent will promptly
return the escrowed funds of that particular partnership to the subscribers.
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 a partnership to break escrow and begin operations.
You will receive interest on your subscription proceeds from the time they are
deposited in the escrow account, or the partnership account if you subscribe
after the minimum subscriptions have been received and escrow has been broken,
until the final closing of the partnership to which you subscribed. The interest
will be paid to you not later than that partnership's first cash distribution
from operations.
During each partnership's escrow period its subscription proceeds will be
invested only in institutional investments comprised of or secured by securities
of the United States government. After the funds are transferred to the
partnership account and before their use in partnership operations, they may be
temporarily invested in income producing short-term, highly liquid investments,
in which there is appropriate safety of principal, such as U.S. Treasury Bills.
If the managing general partner determines that a partnership may be deemed an
investment company under the Investment Company Act of 1940, then the investment
activity will cease. Subscription proceeds will not be commingled with the funds
of the managing general partner or its affiliates, nor will subscription
proceeds be subject to their creditors' claims before they are paid to the
managing general partner under the drilling and operating agreement.
Acceptance of Subscriptions
You and the other investors should make your checks for units payable to
National City Bank as Escrow Agent for "Atlas America Public #12-2003 Limited
Partnership," or "Atlas America Public #12-2004(___) Limited Partnership" as
appropriate and give your check to your broker/dealer for submission to the
dealer manager and escrow agent. The managing general partner will place all
subscription proceeds of each partnership in an escrow account, or the
partnership account if you subscribe after the minimum subscriptions have been
received and escrow has been broken, until the final closing of the partnership
to which you subscribed.
Your execution of the subscription agreement constitutes your offer to buy units
in the partnership then being offered and to hold the offer open until either:
o your subscription is accepted or rejected by the managing general
partner; or
o you withdraw your offer.
To withdraw your offer, you must give written notice to the managing general
partner before your offer is accepted by the managing general partner. Your
subscription will be accepted or rejected by the partnership within 30 days of
its receipt. The managing general partner's acceptance of your subscription is
discretionary, and the managing general partner may reject your subscription for
any reason without incurring any liability to you for this decision. If your
subscription is rejected, then all of your funds will be promptly returned to
you together with any interest earned on your subscription proceeds.
When you will be admitted to a partnership depends on whether your subscription
is accepted before or after breaking escrow. If your subscription is accepted:
32
o before breaking escrow you will be admitted to the partnership to
which you subscribed not later than 15 days after the release from
escrow of the investors' funds to that partnership; and
o after breaking escrow you will be admitted to the partnership not
later than the last day of the calendar month in which your
subscription was accepted by that partnership.
Your execution of the subscription agreement and the managing general partner's
acceptance also constitutes your:
o execution of the partnership agreement and agreement to be bound by
its terms as a partner; and
o grant of a special power of attorney to the managing general partner
to file amended certificates of limited partnership, governmental
reports, and other matters.
Activation of the Partnerships
The managing general partner will organize each partnership under the Delaware
Revised Uniform Limited Partnership Act. On receipt of the minimum subscriptions
and written instructions to the escrow agent from the managing general partner
and the dealer-manager, the managing general partner on behalf of a partnership
may:
o form the partnership under the Delaware Revised Uniform Limited
Partnership Act;
o break escrow;
o transfer the escrowed funds to a partnership account;
o enter into the drilling and operating agreement with itself or an
affiliate as operator; and
o begin drilling to the extent the prospects have been identified.
After breaking escrow additional subscription payments may be paid directly to a
partnership account and will continue to earn interest until the offering
closes.
Each partnership will be a separate and distinct business and economic entity
from each other partnership. Thus, you will be a partner only of that
partnership in which you specifically invest and will have no interest in any of
the other partnerships (unless you also invest in other partnerships). Thus, you
should consider and rely solely on the operations and success or lack of success
of your own partnership in accessing the quality of your investment.
Suitability Standards
In General. It is the obligation of persons selling the units to make every
reasonable effort to assure that the units are suitable for you based on your
investment objectives and financial situation, regardless of your income or net
worth. However, you should invest in a partnership only if you are willing to
assume the risk of a speculative, illiquid, and long-term investment. Also,
subscriptions to a partnership will not be accepted from IRAs, Keogh plans and
qualified retirement plans because the partnership's income would be
characterized as unrelated business taxable income, which is subject to tax.
The decision to accept or reject your subscription will be made by the managing
general partner, in its sole discretion, and is final. The managing general
partner will not accept your subscription until it has reviewed your apparent
qualifications, and the suitability determination must be maintained by the
managing general partner during the partnership's term and for at least six
years thereafter.
Units will be sold to you only if you have:
o a minimum net worth of $225,000, exclusive of home, home furnishings,
and automobiles; or
33
o a minimum net worth of $60,000, exclusive of home, home furnishings,
and automobiles, and had during the last tax year or estimate that you
will have during the current tax year "taxable income" as defined in
Section 63 of the Internal Revenue Code of at least $60,000 without
regard to an investment in the partnership.
However, if you are a resident of the states set forth below, then additional
suitability requirements apply to you.
Purchasers of Limited Partner Units in California, Michigan, New Hampshire,
North Carolina, Ohio and Pennsylvania.
o If you are a resident of California and you purchase limited partner
units, then you must:
o have a net worth of not less than $250,000, exclusive of home,
home furnishings, and automobiles, and expect to have gross
income in the current tax year of $65,000 or more; or
o have a net worth of not less than $500,000, exclusive of home,
home furnishings, and automobiles; or
o have a net worth of not less than $1 million; or
o expect to have gross income in the current tax year of not less
than $200,000.
o If you are a resident of Michigan or North Carolina and you purchase
limited partner units, then you must:
o have a net worth of not less than $225,000, exclusive of home,
home furnishings, and automobiles; or
o have a net worth of not less than $60,000, exclusive of home,
home furnishings, and automobiles, and estimated current tax year
taxable income as defined in Section 63 of the Internal Revenue
Code of $60,000 or more without regard to an investment in the
partnership.
o If you are a resident of New Hampshire and you purchase limited
partner units, then you must:
o have a net worth of not less than $250,000, exclusive of home,
home furnishings, and automobiles; or
o have a net worth of not less than $125,000, exclusive of home,
home furnishings, and automobiles and $50,000 of taxable income.
o In addition, if you are a resident of Michigan, Ohio, or
Pennsylvania, then you must not make an investment in the
partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings and automobiles.
Purchasers of Investor General Partner Units in either: (i) Alabama, Maine,
Massachusetts, Minnesota, North Carolina, Ohio, Oklahoma, Pennsylvania,
Tennessee, Texas, or Washington; or (ii) Arizona, Indiana, Iowa, Kansas,
Kentucky, Michigan, Mississippi, Missouri, New Mexico, Oregon, South Dakota, or
Vermont.
o If you are a resident of:
34
o Alabama, o Nothe Carolina, o Tennessee,
o Maine, o Ohio, o Texas, or
o Massachusetts, o Oklahoma, o Washington
o Minnesota, o Pennsyivania,
and you purchase investor general partner units, then you must:
o 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
o have an individual or joint net worth with your spouse in excess
of $1 million, inclusive of home, home furnishings, and
automobiles; or
o have an individual or joint net worth with your spouse in excess
of $500,000, exclusive of home, home furnishings, and
automobiles; or
o 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.
o In addition, if you are a resident of Ohio or Pennsylvania, then you
must not make an investment in the partnership which is in excess of
10% of your net worth, exclusive of home, home furnishings, and
automobiles.
o If you are a resident of:
o Arizona, o Kentucky, o New Mexico,
o Indiana, o Michigan, o Oregon,
o Iowa, o Mississipi, o South Dakota, or
o Kansas, o Missouri, o Vermount
and you purchase investor general partner units, then you must:
o 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
o have an individual or joint net worth with your spouse in excess
of $1 million, inclusive of home, home furnishings, and
automobiles; or
o have an individual or joint net worth with your spouse in excess
of $500,000, exclusive of home, home furnishings, and
automobiles; or
o 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.
35
o In addition, if you are a resident of Iowa or Michigan, then you must
not make an investment in the partnership which is in excess of 10% of
your net worth, exclusive of home, home furnishings, and automobiles.
Purchasers of Investor General Partner Units in either California or New
Hampshire.
o If you are a resident of California and you purchase investor general
partner units, then you must:
o have a net worth of not less than $250,000, exclusive of home,
home furnishings, and automobiles, and expect to have gross
income in the current tax year of $120,000 or more; or
o have a net worth of not less than $500,000, exclusive of home,
home furnishings, and automobiles; or
o have a net worth of not less than $1 million; or
o expect to have gross income in the current tax year of not less
than $200,000.
o If you are a resident of New Hampshire and you purchase investor
general partner units, then you must:
o have a net worth, exclusive of home, home furnishings, and
automobiles, of $250,000; or
o have a net worth, exclusive of home, home furnishings, and
automobiles, of $125,000 and $50,000 of taxable income.
Fiduciary Accounts and Confirmations. If there is a sale of a unit to a
fiduciary account, then all the suitability standards set forth above must be
met by:
o the beneficiary;
o the fiduciary account; or
o the donor or grantor who directly or indirectly supplies the funds to
purchase the units if the donor or grantor is the fiduciary.
Generally, you are required to execute your own subscription agreement, and the
managing general partner will not accept any subscription agreement that has
been executed by someone other than you. The only exception is if you have given
someone else the legal power of attorney to sign on your behalf and you meet all
of the conditions in this prospectus. Also, the managing general partner will:
o not complete a sale of units to you until at least five business days
after the date you receive a final prospectus; and
o send you a confirmation of purchase.
PRIOR ACTIVITIES
The following tables reflect certain historical data with respect to 31 private
drilling partnerships which raised a total of $160,393,999, and 11 public
drilling partnerships which raised a total of $127,440,590, that the managing
general partner has sponsored. The tables also reflect certain historical data
with respect to 1999 Viking Resources LP, a private drilling
36
program which raised $4,555,210, and is the only drilling program sponsored by
Viking Resources after it was acquired by Resource America in August 1999.
Information concerning other programs sponsored by Viking Resources before it
was acquired by Resource America will be provided to you on written request to
the managing general partner. The tables also do not include information
concerning wells acquired by Atlas Resources through merger or other form of
acquisition.
Although past performance is no guarantee of future results, the investor
general partners in the managing general partner's prior partnerships have not
had to make additional capital contributions to their partnerships because of
their status as investor general partners.
It should not be assumed that you and the other investors will experience
returns, if any, comparable to those experienced by investors in the prior
drilling partnerships for several reasons, including, but not limited to,
differences in:
o partnership terms;
o property locations;
o partnership size; and
o economic considerations.
The results of the prior drilling partnerships should be viewed only as a
measure of the level of activity and experience of the managing general partner
with respect to drilling partnerships
37
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 APRIL 15, 2003
Managing Years
Number General Date Date of Wells Previous
of Investor Partner Total Operations First In Assess-
Partnership Investors Capital Capital Capital Began Distributions Production ments
------------------------ --------- ---------- ---------- -------- ---------- ------------- ---------- --------
1. Atlas L.P. #1-1985 19 $600,000 $114,800 $714,800 12/31/85 07/02/86 17.30 -0-
2. A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 16.30 -0-
3. A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 15.30 -0-
4. A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 14.30 -0-
5. A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 13.30 -0-
6. A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 12.30 -0-
7. A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 12.08 -0-
8. A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 11.25 -0-
9. A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 11.08 -0-
10. A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 11.00 -0-
11. A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 10.33 -0-
12. A.E.Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 9.83 -0-
13. A.E.Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 9.58 -0-
14. A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 9.25 -0-
15. A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 9.00 -0-
16. A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 8.75 -0-
17. A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 8.25 -0-
18. A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 8.00 -0-
19. A.E. Nineties-Public #3 391 5,800,990 928,546 6,729,536 12/31/94 06/05/95 8.00 -0-
20. A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96 7.17 -0-
21. A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96 6.75 -0-
22. A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96 7.00 -0-
23. A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 6.33 -0-
24. A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97 6.00 -0-
25. A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 6.00 -0-
26. A.E. Nineties-17 217 8,813,488 2,113,947 10,927,435 08/29/97 12/12/97 5.42 -0-
27. A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98 5.00 -0-
28. A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98 4.83 -0-
29. A.E. Nineties-18 225 11,391,673 3,448,751 14,840,424 07/31/98 01/07/99 4.08 -0-
30. A.E. Nineties-Public #7 366 11,988,350 3,812,150 15,800,500 12/31/98 07/10/99 3.75 -0-
31. A.E. Partners 1998 26 1,740,000 756,360 2,496,360 12/31/98 07/02/99 3.75 -0-
32. A.E. Nineties-19 288 15,720,450 4,776,598 20,497,048 09/30/99 01/14/00 3.25 -0-
33. A.E. Nineties-Public #8 380 11,088,975 3,148,181 14,237,156 12/31/99 06/09/00 2.75 -0-
34. A.E. Partners 1999 8 450,000 196,500 646,500 12/31/99 10/02/00 2.75 -0-
35. 1999 Viking Resources LP 131 4,555,210 1,678,038 6,233,248 12/31/99 06/01/00 2.75 -0-
36. Atlas America-Series 20 361 18,809,150 6,297,945 25,107,095 09/30/00 01/30/01 2.50 -0-
37. Atlas America-Public #9 530 14,905,465 5,563,527 20,468,992 12/31/00 07/13/01 2.10 -0-
38. Atlas America-Series 21- A 282 12,510,713 4,535,799 17,046,512 05/15/01 11/16/01 1.85 -0-
39. Atlas America-Series 21- B 360 17,411,825 6,442,761 23,854,586 09/19/01 03/02/02 1.25 -0-
40. Atlas America-Public #10 818 21,281,170 7,227,432 28,508,602 12/31/01 06/20/02 1.00 -0-
41. Atlas America-Series 22 258 10,156,375 3,481,591 13,637,966 05/31/02 11/12/02 .50 -0-
42. Atlas America-Series 23 246 9,644,550 3,214,850 12,859,400 09/30/02 02/18/03 .25 -0-
43. Atlas America-Public #11(1) 1017 31,178,145 10,534,476 41,712,621 12/31/02 (1) (1) -0-
- ---------------
(1) This program closed December 31, 2002, and its first distribution is
expected early summer 2003.
38
Table 2 reflects the drilling activity of previous development drilling
partnerships sponsored by the managing general partner and its affiliates. All
the wells were development wells. You should not assume that the past
performance of prior partnerships is indicative of the future results of the
partnerships.
TABLE 2
WELL STATISTICS - DEVELOPMENT WELLS
AS OF APRIL 15, 2003
GROSS WELLS (1) NET WELLS (2)
------------------------------------------- ----------------------------
Partnership Oil Gas Dry (3) Oil Gas Dry (3)
--------------------------- ------------ ------------ ------------ ------------ ------------ ------------
Investors Investors Investors Investors Investors Investors
1. Atlas L.P.#1-1985 0 7 1 0 3.15 0.25
2. A.E. Partners 1986 0 8 0 0 3.50 0.00
3. A.E. Partners 1987 0 9 0 0 4.10 0.00
4. A.E. Partners 1988 0 9 0 0 3.80 0.00
5. A.E. Partners 1989 0 10 0 0 3.30 0.00
6. A.E. Partners 1990 0 12 0 0 5.00 0.00
7. A.E. Nineties-10 0 12 0 0 11.50 0.00
8. A.E. Nineties-11 0 14 0 0 4.30 0.00
9. A.E. Partners 1991 0 12 0 0 4.95 0.00
10. A.E. Nineties-12 0 14 0 0 12.50 0.00
11. A.E. Nineties-JV 92 0 52 0 0 24.44 0.00
12. A.E. Partners 1992 0 7 0 0 3.50 0.00
13. A.E. Nineties-Public #1 0 14 0 0 14.00 0.00
14. A.E. Nineties-1993 Ltd. 0 20 1 0 19.40 1.00
15. A.E. Partners 1993 0 8 0 0 4.00 0.00
16. A.E. Nineties-Public #2 0 16 0 0 15.31 0.00
17. A.E. Nineties-14 0 55 2 0 55.00 2.00
18. A.E. Partners 1994 0 12 0 0 5.00 0.00
19. A.E. Nineties-Public #3 0 27 1 0 26.00 1.00
20. A.E. Nineties-15 0 61 1 0 55.50 1.00
21. A.E. Partners 1995 0 6 0 0 3.00 0.00
22. A.E. Nineties-Public #4 0 31 0 0 30.50 0.00
23. A.E. Nineties-16 0 57 6 0 47.50 4.50
24. A.E. Partners 1996 0 13 0 0 4.84 0.00
25. A.E. Nineties-Public #5 0 36 0 0 35.91 0.00
26. A.E. Nineties-17 0 52 5 0 42.00 4.00
27. A.E. Nineties-Public #6 0 55 0 0 44.45 0.00
28. A.E. Partners 1997 0 6 0 0 2.81 0.00
29. A.E. Nineties-18 0 63 0 0 58.00 0.00
30. A.E. Nineties-Public #7 0 64 0 0 57.50 0.00
31. A.E. Partners 1998 0 19 0 0 9.50 0.00
32. A.E. Nineties-19 0 86 4 0 79.75 4.00
33. A.E. Nineties-Public #8 0 58 0 0 54.66 0.00
34. A.E. Partners 1999 0 5 0 0 2.50 0.00
35. 1999 Viking Resources LP 0 25 2 0 23.00 2.00
36. Atlas America-Series 20 0 106 1 0 100.25 1.00
37. Atlas America-Public #9 0 83 2 0 78.75 2.00
38. Atlas America-Series 21-A 0 67 0 0 61.50 0.00
39. Atlas America-Series 21-B 0 88 1 0 81.50 1.00
40. Atlas America-Public #10 0 104 3 0 100.15 3.00
41. Atlas America-Series 22 0 51 1 0 49.55 1.00
42. Atlas America-Series 23 0 47 1 0 47.00 1.00
43. Atlas America-Public #11 0 167 0 0 160.50 0.00
------------ ------------ ------------ ------------ ------------ -------------
0 1668 32 0 1453.37 28.75
============ ============ ============ ============ ============ =============
- ---------------
(1) A "gross well" is one in which a partnership owns a leasehold interest.
(2) A "net well" equals the actual leasehold interest owned in one gross well
divided by one hundred. For example, a 50% leasehold interest in a well is
one gross well, but a .50 net well.
(3) For purposes of this Table only, a "Dry Hole" means a well which is plugged
and abandoned with or without a completion attempt because the operator has
determined that it will not be productive of gas and/or oil in commercial
quantities.
39
Table 3 provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates. You should not assume that the past performance of prior
partnerships is indicative of the future results of the partnerships.
TABLE 3
INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
AS OF APRIL 15, 2003
Latest Quaterly
Cash
TOTAL COSTS Cash Cash on Distribution
Investor -------------------------------------- Distributions Cash Return As of Date
Partnership Capital(1) Operating Admit Direct (2)(4) (4) of Table
--------------------- -------------- --------- ---------- ---------- ------------- ------------ ------------
1. Atlas L.P.#1-1985 $600,000 $202,703 $41,808 $10,470 $1,445,198 241% $12,554
2. A.E. Partners 1986 631,250 161,046 65,306 9,237 706,586 112% 5,564
3. A.E. Partners 1987 721,000 158,995 56,644 9,149 589,030 82% 6,667
4. A.E. Partners 1988 617,050 131,239 53,409 8,613 532,352 86% 4,873
5. A.E. Partners 1989 550,000 126,049 57,335 7,734 721,349 131% 7,483
6. A.E. Partners 1990 887,500 188,888 81,050 9,229 990,438 112% 13,512
7. A.E. Nineties-10 2,200,000 398,639 79,234 26,641 1,760,615 80% 22,070
8. A.E. Nineties-11 750,000 153,604 90,092 60,455 1,026,598 137% 9,426
9. A.E. Partners 1991 868,750 168,711 105,088 17,291 1,080,842 124% 14,551
10. A.E. Nineties-12 2,212,500 408,298 83,636 124,568 1,945,808 88% 20,080
11. A.E. Nineties-JV 92 4,004,813 663,890 139,307 214,692 4,137,339(3) 103% 52,124
12. A.E. Partners 1992 600,000 95,618 52,388 7,368 736,484 123% 8,843
13. A.E. Nineties-Public #1 2,988,960 414,289 87,154 101,508 2,232,478 75% 27,275
14. A.E. Nineties-1993 Ltd. 3,753,937 488,097 96,301 49,350 2,145,224 57% 14,498
15. A.E. Partners 1993 700,000 122,118 38,475 6,941 881,964 126% 12,773
16. A.E. Nineties-Public #2 3,323,920 407,208 75,627 61,658 2,039,167 61% 33,603
17. A.E. Nineties-14 9,940,045 1,232,619 239,169 56,450 5,600,871 56% 71,899
18. A.E. Partners 1994 892,500 112,326 45,018 5,929 944,155 106% 16,505
19. A.E. Nineties-Public #3 5,800,990 632,281 123,810 63,825 3,576,238 62% 51,390
20. A.E. Nineties-15 10,954,715 1,190,500 233,486 40,463 6,907,246 63% 116,765
21. A.E. Partners 1995 600,000 68,959 16,608 5,029 358,845 60% 4,429
22. A.E. Nineties-Public #4 6,991,350 738,000 135,387 54,494 2,963,111 42% 57,083
23. A.E. Nineties-16 10,955,465 1,006,906 170,773 58,120 4,686,870 43% 120,717
24. A.E. Partners 1996 800,000 92,280 21,018 40,257 458,796 57% 13,266
25. A.E. Nineties-Public #5 7,992,240 694,762 126,857 46,084 3,385,367 42% 74,786
26. A.E. Nineties-17 8,813,488 728,906 124,637 104,522 4,190,352 48% 117,257
27. A.E. Nineties-Public #6 9,901,025 830,043 137,897 47,546 4,618,106 47% 165,541
28. A.E. Partners 1997 506,250 48,684 11,081 27,150 304,362 60% 11,915
29. A.E. Nineties-18 11,391,673 897,573 142,560 263,282 4,663,297 41% 178,690
30. A.E. Nineties-Public #7 11,988,350 809,302 115,831 53,366 3,615,674 30% 125,948
31. A.E. Partners 1998 1,740,000 152,323 20,281 41,990 914,617 53% 31,980
32. A.E. Nineties-19 15,720,450 1,003,211 138,037 11,979 4,839,027 31% 217,134
33. A.E. Nineties-Public #8 11,088,975 735,110 86,899 52,859 3,677,364 33% 144,144
34. A.E. Partners 1999 450,000 28,564 2,709 2,893 284,492 63% 11,972
35. 1999 Viking Resources LP 4,555,210 720,901 0 137,948 5,241,222 115% 227,079
36. Atlas America-Series 20 18,809,150 1,259,831 125,996 42,501 9,255,520 49% 533,024
37. Atlas America-Public #9 14,905,465 983,753 81,020 34,735 4,643,396 31% 396,886
38. Atlas America-Series 21- A 12,510,713 502,294 50,744 6,381 2,301,598 18% 390,262
39. Atlas America-Series 21- B 17,411,825 562,536 55,107 6,207 2,246,265 13% 544,683
40. Atlas America-Publi #10(5) 21,281,170 528,097 48,799 20,201 2,448,340 12% 938,870
41. Atlas America-Series 22 (5) 10,156,375 134,532 14,214 1,044 647,308 6% 426,321
42. Atlas America-Series 23 (5) 9,644,550 71,646 7,242 973 281,396 0% 281,396
43. Atlas America-Public #11 (5) 31,178,145 0 0 0 0 0% 0
===================================================================================================================================
(1) There have been no partnership borrowings other than from the managing
general partner. The approximate principal amounts of such borrowings
are as follows:
o Atlas America - Public #11-2002;
o A.E. Nineties-11 - $125,000; and
o A.E. Nineties-12 - $365,500.
A portion of each partnership's cash distributions was used to repay that
partnership's loan.
(2) All cash distributions were from the sale of gas, and not sales of
properties.
(3) A portion of the cash distributions was used to drill three reinvestment
wells at a cost of $307,434 in accordance with the terms of the
offering.
(4) This column reflects total cash distributions beginning with the first
production from the program as a percentage of the total amount invested
in the program and includes the return of the investors' capital.
(5) As of the date of this table there is not twelve months of production
and/or not all wells are drilled or on-line to sell production.
40
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 APRIL 15, 2003
Latest
Quarterly
Cash
Managing Distribution
General Total Costs Cash Cash On As of
Partner ------------------------------- Distributions Cash Date of
Partnership Capital Operating Admin. Direct (1) Return Table
------------------ ----------- --------- -------- -------- ------------- --------- ------------
1. Atlas L.P. #1-1985 ....... $114,800 $38,610 $7,963 $1,994 $275,539 240% $2,391
2. A.E. Partners 1986 ........ 120,400 30,675 12,439 1,759 134,917 112% 1,060
3. A.E. Partners 1987 ........ 158,269 45,843 16,332 2,638 152,097 96% 1,922
4. A.E. Partners 1988 ........ 135,450 42,266 17,201 2,774 137,188 101% 1,570
5. A.E. Partners 1989 ........ 120,731 27,669 12,586 1,698 163,976 136% 1,643
6. A.E. Partners 1990 ........ 244,622 62,963 0 0 378,957 155% 5,196
7. A.E. Nineties-10 ........ 484,380 132,880 0 0 622,350 128% 8,123
8. A.E. Nineties-11 ........ 268,003 65,830 38,611 20,851 433,480 162% 4,040
9. A.E. Partners 1991 ........ 318,063 56,237 0 0 454,646 143% 5,711
10. A.E. Nineties-12 ........ 791,833 174,985 35,844 27,879 836,854 106% 8,606
11. A.E. Nineties-JV 92 ..... 1,414,917 326,991 68,614 24,204 1,034,584 73% 7,080
12. A.E. Partners 1992 ........ 176,100 31,873 0 0 333,929 190% 3,414
13. A.E. Nineties-Public #1 . 528,934 130,828 27,522 20,248 617,605 117% 8,613
14. A.E. Nineties-1993 Ltd. . 1,264,183 209,184 41,272 17,568 447,897 35% 6,214
15. A.E. Partners 1993 ........ 219,600 40,706 0 0 347,676 158% 4,649
16. A.E. Nineties-Public #2 . 587,340 128,592 23,882 19,471 329,992 56% 10,611
17. A.E. Nineties-14 ........ 3,584,027 607,111 117,800 20,625 1,540,333 43% 35,413
18. A.E. Partners 1994 ........ 231,500 37,442 0 0 358,798 155% 6,043
19. A.E. Nineties-Public #3 . 928,546 210,760 41,270 21,275 1,085,002 117% 17,130
20. A.E. Nineties-15 ........ 3,435,936 510,214 100,065 17,341 2,035,393 59% 50,042
21. A.E. Partners 1995 ........ 244,725 22,986 0 0 127,719 52% 1,787
22. A.E. Nineties-Public #4 . 1,287,752 246,000 45,129 18,165 653,868 51% 19,028
23. A.E. Nineties-16 ........ 1,643,320 275,777 46,772 11,113 1,208,736 74% 33,063
24. A.E. Partners 1996 ........ 367,416 30,760 0 0 165,496 45% 4,834
25. A.E. Nineties-Public #5 . 1,654,740 231,587 42,286 15,361 480,636 29% 24,929
26. A.E. Nineties-17 ........ 2,113,947 262,803 44,937 8,340 1,386,267 66% 42,276
27. A.E. Nineties-Public #6 ... 1,950,345 276,681 45,966 15,849 1,322,655 68% 29,213
28. A.E. Partners 1997 .......... 231,050 16,228 0 0 105,973 46% 4,299
29. A.E. Nineties-18 .......... 3,448,751 412,753 65,557 8,200 2,045,670 59% 45,795
30. A.E. Nineties-Public #7 ... 3,812,150 363,599 52,040 23,976 835,218 22% 28,779
31. A.E. Partners 1998 .......... 756,360 50,774 0 0 312,390 41% 11,102
32. A.E. Nineties-19 .......... 4,776,598 461,331 63,477 5,509 2,127,129 45% 55,648
33. A.E. Nineties-Public #8 ... 3,148,181 300,256 35,494 21,590 1,470,647 47% 58,876
34. A.E. Partners 1999 .......... 196,500 9,522 0 0 96,651 49% 4,171
35. 1999 Viking Resources LP .... 1,678,038 240,300 0 45,983 1,747,074 104% 75,693
36. Atlas America-Series 20 ... 6,297,945 465,965 46,601 15,719 3,423,275 54% 197,146
37. Atlas America-Public #9 ... 5,563,527 401,815 33,093 14,188 1,734,490 34% 162,108
38. Atlas America-Series 21-A.. 4,588,337 256,844 25,947 3,263 1,176,902 26% 199,557
39. Atlas America-Series 21-B.. 6,449,743 289,791 28,388 3,198 1,157,167 18% 280,594
40. Atlas America-Public #10(2) 7,354,491 248,517 22,964 9,507 1,221,331 17% 441,823
41. Atlas America-Series 22(2) 3,481,591 64,863 6,689 503 312,118 9% 205,547
42. Atlas America-Series 23(2) 3,214,850 33,716 3,408 458 132,424 0% 132,424
43. Atlas America-Public #11(2) 10,534,476 0 0 0 0 0% 0
- ---------------
(1) All cash distributions were from the sale of gas and not sales of
properties.
(2) As of the date of this table there is not twelve months of production and/
or not all wells are drilled or on-line to sell production.
41
Table 4 sets forth the managing general partner's estimate of the federal tax
savings to investors in the managing general partner's prior development
drilling partnerships, based on the maximum marginal tax rate in each year, the
share of tax deductions as a percentage of their subscriptions, and the
aggregate cash distributions. You are urged to consult with your own tax
advisors concerning your specific tax situation and should not assume that the
past performance of prior partnerships is indicative of the future results of
the partnerships.
TABLE 4
SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
AS OF APRIL 15, 2003
Estimated Federal Tax Savings From (1)
------------------------------------------------------------
1st Year Eff 1st Year
Investor Tax Tax I.D.C. Depletion Section 29
Partnership Capital Deduct (2) Rate Deduct (3) Allowance(3) Depreciation(3) Tax Credit (4)
- ---------------------- ---------- ---------- ------ ---------- ------------ --------------- --------------
1. Atlas L.P. #1-1985 $600,000 99% 50.0% $298,337 $122,842 N/A $55,915
2. A.E. Partners 1986 631,250 99% 50.0% 312,889 68,709 N/A 13,507
3. A.E. Partners 1987 721,000 99% 38.5% 356,895 51,951 N/A N/A
4. A.E. Partners 1988 617,050 99% 33.0% 244,351 46,994 N/A N/A
5. A.E. Partners 1989 550,000 99% 33.0% 179,685 65,548 N/A N/A
6. A.E. Partners 1990 887,500 99% 33.0% 275,125 90,589 N/A 281,660
7. A.E. Nineties-10 2,200,000 100% 33.0% 726,000 154,628 N/A 521,602
8. A.E. Nineties-11 750,000 100% 31.0% 232,500 95,969 N/A 329,800
9. A.E. Partners 1991 868,750 100% 31.0% 269,313 104,866 N/A 315,893
10. A.E. Nineties-12 2,212,500 100% 31.0% 685,875 194,065 N/A 617,285
11. A.E. Nineties-JV 92 4,004,813 92.5% 31.0% 1,322,905 334,936 N/A 1,002,109
12. A.E. Partners 1992 600,000 100% 31.0% 186,000 76,004 N/A 224,631
13. A.E. Nineties-Public #1 2,988,960 80.5% 36.0% 877,511 209,580 254,729 N/A
14. A.E. Nineties-1993 Ltd. 3,753,937 92.5% 39.6% 1,378,377 201,792 N/A N/A
15. A.E. Partners 1993 700,000 100% 39.6% 273,216 80,972 N/A N/A
16. A.E. Nineties-Public #2 3,323,920 78.7% 39.6% 1,036,343 181,693 279,039 N/A
17. A.E. Nineties-14 9,940,045 95% 39.6% 3,739,445 480,589 N/A N/A
18. A.E. Partners 1994 892,500 100% 39.6% 353,430 75,503 N/A N/A
19. A.E. Nineties-Public #3 5,800,990 76.2% 39.6% 1,752,761 315,531 521,115 N/A
20. A.E. Nineties-15 10,954,715 90.0% 39.6% 3,904,261 561,327 N/A N/A
21. A.E. Partners 1995 600,000 100% 39.6% 237,600 23,910 N/A N/A
22. A.E. Nineties-Public #4 6,991,350 80.0% 39.6% 2,214,860 270,380 516,164 N/A
23. A.E. Nineties-16 10,955,465 86.8% 39.6% 3,361,289 372,289 830,506 N/A
24. A.E. Partners 1996 800,000 100% 39.6% 316,800 36,320 N/A N/A
25. A.E. Nineties-Public #5 7,992,240 84.9% 39.6% 2,530,954 274,732 530,055 N/A
26. A.E. Nineties-17 8,813,488 85.2% 39.6% 2,966,366 342,189 366,073 N/A
27. A.E. Nineties-Public #6 9,901,025 80.0% 39.6% 3,166,406 384,804 580,064 N/A
28. A.E. Partners 1997 506,250 100% 39.6% 200,475 23,946 N/A N/A
29. A.E. Nineties-18 11,391,673 90.0% 39.6% 4,030,884 241,772 344,797 N/A
30. A.E. Nineties-Public #7 11,988,350 85.0% 39.6% 4,043,670 256,717 463,771 N/A
31. A.E. Partners 1998 1,740,000 100.0% 39.6% 689,040 70,662 N/A N/A
32. A.E. Nineties-19 15,720,450 90.0% 39.6% 5,602,767 362,823 361,868 N/A
33. A.E. Nineties-Public #8 11,088,975 85.0% 39.6% 3,734,654 279,398 365,056 N/A
34. A.E. Partners 1999 450,000 100.0% 39.6% 178,200 17,719 N/A N/A
35. 1999 Viking Resources LP 4,555,210 92.0% 39.6% 1,678,038 374,844 N/A N/A
36. Atlas America-Series 20 18,809,150 90.0% 39.6% 6,712,802 578,697 291,307 N/A
37. Atlas America-Public #9 14,905,465 90.0% 39.6% 5,349,744 323,830 N/A N/A
38. Atlas America-Series 21-A 12,510,713 91.0% 39.1% 4,468,617 146,759 136,793 N/A
39. Atlas America-Series 21-B 17,411,825 91.0% 39.1% 6,197,907 140,052 161,888 N/A
40. Atlas America-Public #10 (8) 21,281,170 91.0% 39.1% 7,550,729 196,385 302,134 N/A
41. Atlas America-Series 22 (8) 10,156,375 91.0% 38.6% 3,564,312 25,367 133,518 N/A
42. Atlas America-Series 23 (8) 9,644,550 91.0% 38.6% 3,404,803 7,487 111,298 N/A
43. Atlas America-Public #11 (8) 31,178,145 91.0% 38.6% 11,003,503 0 0 N/A
Total Cumulative
Cash Distribution Cash Dist Percent of Cash
As of And Tax Dist And Tax
Partnership Total Date of Table(5)(7) Savings (7) Savings to Date (7)
- ---------------------- ---------- ------------------- ----------- -------------------
1. Atlas L.P. #1-1985 $477,094 $1,445,198 $1,922,292 320%
2. A.E. Partners 1986 395,104 706,586 1,101,691 175%
3. A.E. Partners 1987 408,846 589,030 997,876 138%
4. A.E. Partners 1988 291,345 532,352 823,696 133%
5. A.E. Partners 1989 245,233 721,349 966,582 176%
6. A.E. Partners 1990 647,374 990,438 1,637,812 185%
7. A.E. Nineties-10 1,402,230 1,760,615 3,162,845 144%
8. A.E. Nineties-11 658,269 1,026,598 1,684,866 225%
9. A.E. Partners 1991 690,072 1,080,842 1,770,914 204%
10. A.E. Nineties-12 1,497,225 1,945,808 3,443,033 156%
11. A.E. Nineties-JV 92 2,659,950 4,137,339 6,797,289 170%
12. A.E. Partners 1992 486,635 736,484 1,223,120 204%
13. A.E. Nineties-Public #1 1,341,820 2,232,478 3,574,299 120%
14. A.E. Nineties-1993 Ltd. 1,580,169 2,145,224 3,725,393 99%
15. A.E. Partners 1993 354,188 881,964 1,236,152 177%
16. A.E. Nineties-Public #2 1,497,075 2,039,167 3,536,242 106%
17. A.E. Nineties-14 4,220,034 5,600,871 9,820,906 99%
18. A.E. Partners 1994 428,933 944,155 1,373,088 154%
19. A.E. Nineties-Public #3 2,589,407 3,576,238 6,165,645 106%
20. A.E. Nineties-15 4,465,588 6,907,246 11,372,834 104%
21. A.E. Partners 1995 261,510 358,845 620,355 103%
22. A.E. Nineties-Public #4 3,001,404 2,963,111 5,964,514 85%
23. A.E. Nineties-16 4,564,085 4,686,870 9,250,954 84%
24. A.E. Partners 1996 353,120 458,796 811,916 101%
25. A.E. Nineties-Public #5 3,335,740 3,385,367 6,721,108 84%
26. A.E. Nineties-17 3,674,628 4,190,352 7,864,980 89%
27. A.E. Nineties-Public #6 4,131,274 4,618,106 8,749,380 88%
28. A.E. Partners 1997 224,421 304,362 528,783 104%
29. A.E. Nineties-18 4,617,452 4,663,297 9,280,749 81%
30. A.E. Nineties-Public #7 4,764,158 3,615,674 8,379,832 70%
31. A.E. Partners 1998 759,702 914,617 1,674,319 96%
32. A.E. Nineties-19 6,327,458 4,839,027 11,166,486 71%
33. A.E. Nineties-Public #8 4,379,107 3,677,364 8,056,471 73%
34. A.E. Partners 1999 195,919 284,492 480,411 107%
35. 1999 Viking Resources LP 2,052,882 5,241,222 7,294,104 160%
36. Atlas America-Series 20 7,582,806 9,255,520 16,838,326 90%
37. Atlas America-Public #9 5,673,574 4,643,396 10,316,971 69%
38. Atlas America-Series 21-A 4,752,169 2,301,598 7,053,767 56%
39. Atlas America-Series 21-B 6,499,846 2,246,265 8,746,111 50%
40. Atlas America-Public #10 (8) 8,049,248 2,448,340 10,497,587 49%
41. Atlas America-Series 22 (8) 3,723,197 647,308 4,370,505 43%
42. Atlas America-Series 23 (8) 3,523,587 281,396 3,804,983 39%
43. Atlas America-Public #11 (8) 11,003,503 0 11,003,503 35%
- ---------------
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. Atlas anticipates that approximately 90% of an investor general partner's
subscription to the partnership will be deductible in 2003.
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.
6. These amounts had not been determined as of the date of this table.
7. This column reflects total cash distributions beginning with the first
production from the program and includes the return of investor's capital.
8. As of the date of this table there is not twelve months of production and/
or not all wells are drilled or on-line to sell production.
42
Table 5 sets forth payments made to the managing general partners and its
affiliates from its previous partnerships.
TABLE 5
SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES
FROM PRIOR PARTNERSHIPS
AS OF APRIL 15, 2003
Cumulative
Leasehold Reimbursement
Drilling and Cumulative of General and
Investor Non-recurring Completion Operator's Administrative
Partnership Capital Management Fee Costs (1) Charges Overhead
----------------------------- --------------- ---------------- --------------- --------------- ---------------
1. Atlas L.P. #1-1985 $600,000 -0- $600,000 $241,313 $49,772
2. A.E. Partners 1986 631,250 -0- 631,250 191,721 77,746
3. A.E. Partners 1987 721,000 -0- 721,000 204,838 72,976
4. A.E. Partners 1988 617,050 -0- 617,050 173,504 70,610
5. A.E. Partners 1989 550,000 -0- 550,000 153,718 69,920
6. A.E. Partners 1990 887,500 -0- 887,500 251,850 81,050
7. A.E. Nineties-10 2,200,000 -0- 2,200,000 531,519 79,234
8. A.E. Nineties-11 750,000 -0- 761,802(2) 219,434 128,703
9. A.E. Partners 1991 868,750 -0- 867,500 224,948 105,088
10. A.E. Nineties-12 2,212,500 -0- 2,272,017(2) 583,283 119,480
11. A.E. Nineties-JV 92 4,004,813 -0- 4,157,700 990,881 207,920
12. A.E. Partners 1992 600,000 -0- 600,000 127,491 52,388
13. A.E. Nineties-Public #1 2,988,960 -0- 3,026,348(2) 545,118 114,676
14. A.E. Nineties-1993 Ltd. 3,753,937 -0- 3,480,656(2) 697,281 137,573
15. A.E. Partners 1993 700,000 -0- 689,940(2) 162,824 38,475
16. A.E. Nineties-Public #2 3,323,920 -0- 3,324,668 535,800 99,509
17. A.E. Nineties-14 9,940,045 -0- 9,512,015(2) 1,839,730 356,969
18. A.E. Partners 1994 892,500 -0- 892,500 149,768 45,018
19. A.E. Nineties-Public #3 5,800,990 -0- 5,800,990 843,041 165,080
20. A.E. Nineties-15 10,954,715 -0- 9,859,244(2) 1,700,714 333,551
21. A.E. Partners 1995 600,000 -0- 600,000 91,946 16,608
22. A.E. Nineties-Public #4 6,991,350 -0- 6,991,350 984,000 180,516
23. A.E. Nineties-16 10,955,465 -0- 10,955,465 1,282,683 217,545
24. A.E. Partners 1996 800,000 -0- 800,000 123,040 21,018
25. A.E. Nineties-Public #5 7,992,240 -0- 7,992,240 926,349 169,142
26. A.E. Nineties-17 8,813,488 -0- 8,813,488 991,709 169,574
27. A.E. Nineties-Public #6 9,901,025 -0- 9,901,025 1,106,724 183,862
28. A.E. Partners 1997 506,250 -0- 506,250 64,912 11,081
29. A.E. Nineties-18 11,391,673 -0- 11,391,673 1,310,326 208,117
30. A.E. Nineties-Public #7 11,988,350 -0- 11,988,350 1,172,901 167,871
31. A.E. Partners 1998 1,740,000 -0- 1,740,000 203,098 20,281
32. A.E. Nineties-19 15,720,450 -0- 15,720,450 1,464,542 201,514
33. A.E. Nineties-Public #8 11,088,975 -0- 11,088,975 1,035,367 122,394
34. A.E. Partners 1999 450,000 -0- 450,000 38,086 2,709
35. 1999 Viking Resources LP 4,555,210 -0- 4,555,210 961,201 0
36. Atlas America-Series 20 18,809,150 -0- 16,937,149 1,725,795 172,597
37. Atlas America-Public #9 14,905,465 -0- 13,509,454 1,385,568 114,113
38. Atlas America-Series 21-A 12,510,713 -0- 11,428,689 759,138 76,691
39. Atlas America-Series 21-B 17,411,825 -0- 15,851,425 852,327 83,495
40. Atlas America-Public #10 21,281,170 -0- 19,311,328 776,614 71,764
41. Atlas America-Series 22 10,156,375 -0- 9,233,970 199,395 20,903
42. Atlas America-Series 23 9,644,550 -0- 8,820,734 105,362 10,650
43. Atlas America-Public #11 31,178,145 -0- 28,506,485 0 0
- ---------------
(1) Excluding the managing general partner's capital contributions.
(2) Includes additional drilling costs paid with production revenues.
43
MANAGEMENT
Managing General Partner and Operator
The partnerships will have no officers or directors. Instead, Atlas Resources,
Inc., a Pennsylvania corporation which was incorporated in 1979, will serve as
the managing general partner of each partnership. Atlas Resources' affiliate
Atlas Energy Group, Inc., an Ohio corporation which was the first of the Atlas
group of companies, was incorporated in 1973. Atlas Energy Group, Inc. will
serve as the partnership's general drilling contractor and operator in Ohio.
As of January 1, 2003, the managing general partner and its affiliates
operated approximately 4,416 natural gas and oil wells located in Ohio,
Pennsylvania and New York.
Since 1985 the managing general partner has sponsored 11 public and 31 private
partnerships to conduct natural gas drilling and development activities in
Pennsylvania, Ohio, and New York. In these partnerships the managing general
partner and its affiliates acted as the operator and the general drilling
contractor and were responsible for drilling, completing, and operating the
wells. Atlas Resources has a 97% completion rate for wells drilled by its
development partnerships.
In September 1998, Atlas Energy Group, Inc., the former parent company of the
managing general partner, merged into Atlas America, Inc., a Delaware holding
company. Atlas America is a wholly-owned subsidiary of Resource America, Inc.,
which is sometimes referred to in this prospectus as Resource America. Resource
America is a publicly-traded company with a total capitalization in excess of
$400 million, and is principally engaged in energy, energy finance, real estate
finance, and equipment leasing. Resource America, which includes the managing
general partner as a subsidiary, was listed among the top 100 leaders in natural
gas and oil production in the Oil and Gas Journal, October 16, 2000. The
managing general partner is dependant on its parent company, Atlas America, for
management and administrative functions and financing for capital expenditures
as described below in " - Transactions With Management and Affiliates."
Atlas America has and is continuing the existing business of Atlas Energy Group,
Inc. It is headquartered at 311 Rouser Road, Moon Township, Pennsylvania 15108,
near the Pittsburgh International Airport, which is also the managing general
partner's primary office.
Officers, Directors and Other Key Personnel
The officers and directors of the managing general partner will serve until
their successors are elected. The officers, directors, and key personnel of the
managing general partner are as follows:
NAME AGE POSITION OR OFFICE
- ------ --- ------------------
Freddie M. Kotek 47 Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas 43 Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons 44 Executive Vice President - Operations and a Director
Jack L. Hollander 47 Senior Vice President - Direct Participation Programs
Nancy J. McGurk 47 Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines 54 Senior Vice President, Secretary and a Director
Michael G. Hartzell 47 Vice President - Land Administration
Donald R. Laughlin 55 Vice President - Drilling and Production
Darshan V. Patel 32 Chief Legal Officer
Marci F. Bleichmar 33 Vice President of Marketing
Sherwood S. Lutz 52 Senior Geologist/Manager of Geology
Michael W. Brecko 45 Director of Energy Sales
Karen A. Black 42 Vice President - Partnership Administration
Justin T. Atkinson 30 Director of Due Diligence
Winifred C. Loncar 62 Director of Investor Services
44
With respect to the biographical information set forth below:
o the approximate amount of an individual's professional time devoted to
the business and affairs of the managing general partner and Atlas
America have been aggregated because there is no reasonable method for
them to distinguish their activities between the two companies; and
o for those individuals who also hold senior positions with other
affiliates of the managing general partner, if it is stated that
they devote approximately 100% of their professional time to the
managing general partner and Atlas America, it is because either the
other affiliates are not currently active in drilling new wells,
such as Viking Resources or Resource Energy, and the individuals are
not required to devote a material amount of their professional time
to the affiliates, or there is no reasonable method to distinguish
their activities between the managing general partner and Atlas
America as compared with the other affiliates of the managing
general partner, such as Viking Resources or Resource Energy.
Freddie M. Kotek. President and Chief Executive Officer since 2002 and Chairman
of the Board of Directors since 2001. Mr. Kotek is employed by Resource America
from 1993 to the present in various capacities and is currently Senior Vice
President of Resource America. Mr. Kotek received a Bachelor of Arts degree from
Rutgers College in 1977 with high honors in Economics. He also received a Master
in Business Administration degree from the Harvard Graduate School of Business
Administration in 1981. Mr. Kotek devotes approximately 80% of his professional
time to the business and affairs of the managing general partner and Atlas
America, and the remainder of his professional time to the business and affairs
of the managing general partner's affiliates.
Frank P. Carolas. Executive Vice President-Land and Geology and a Director
since January, 2001. Mr. Carolas also serves as Executive Vice President-Land
and Geology of Atlas America since January, 2001 and a Director since January,
2002. Mr. Carolas served as Vice President of Land and Geology for the
managing general partner from July 1999 until 2001 and for Atlas America from
1998 until 2001. Before that Mr. Carolas served as Vice President of Atlas
Energy Group, Inc. from 1997 until 1998, which was the former parent company
of the managing general partner. Mr. Carolas is a certified petroleum
geologist and has been with Atlas Resources and its affiliates since 1981. He
received a Bachelor of Science degree in Geology from Pennsylvania State
University in 1981 and is an active member of the American Association of
Petroleum Geologists. Mr. Carolas devotes approximately 100% of his
professional time to the business and affairs of the managing general partner
and Atlas America.
Jeffrey C. Simmons. Executive Vice President-Operations and a Director since
January, 2001. Mr. Simmons also serves as Executive Vice President-Operations
of Atlas America since January, 2001 and a Director since January, 2002. Mr.
Simmons served as Vice President of Operations for the managing general
partner from July 1999 until 2001 and for Atlas America from 1998 until 2001.
Mr. Simmons also serves as Vice President of Atlas Energy Corp., Atlas Energy
Group, Inc., PA Industrial Energy, Inc., Viking Resources, Corp., and Atlas
Pipeline Partners G.P., President of REI-NY, Inc. and Resource Well Services,
Inc., and Executive Vice President of Atlas Noble Corp. 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, Inc., 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, Inc., 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. Mr. Simmons devotes approximately 80% of
his professional time to the business and affairs of the managing general
partner and Atlas America, and the remainder of his professional time to the
business and affairs of the managing general partner's affiliates, primarily
Viking Resources and Resource Energy.
45
Jack L. Hollander. Senior Vice President - Direct Participation Programs since
January, 2002. Mr. Hollander also serves as Senior Vice President - Direct
Participation Programs of Atlas America since January, 2002. Mr. Hollander
served as Vice President - Direct Participation Programs for the managing
general partner and Atlas America from 2001 until January, 2002. Mr. Hollander
began his career serving as in-house tax counsel for Integrated Resources,
Inc., a large diversified financial services company from 1982 to 1990. He
then went on to practice law with Rattet, Hollander & Pasternak with a
concentration in tax matters, real estate transactions, and consulted with and
assisted technology companies in raising capital until joining the managing
general partner in January 2001. Mr. Hollander earned a Bachelor of Science
degree from the University of Rhode Island in 1978, his law degree from
Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New
York University School of Law Graduate Division in 1982. Mr. Hollander is a
member of the New York State bar, the Investment Program Association, and the
Financial Planning Association. Mr. Hollander devotes approximately 100% of
his professional time to the business and affairs of the managing general
partner and Atlas America.
Nancy J. McGurk. Senior Vice President, Chief Financial Officer and Chief
Accounting Officer since January, 2002. Ms. McGurk also serves as Senior Vice
President, Chief Financial Officer, and Chief Accounting Officer of Atlas
America since January, 2002. Ms. McGurk served as Vice President, Chief
Financial Officer and Chief Accounting Officer of the managing general partner
and Atlas America from January, 2001 to January, 2002. Ms. McGurk has been Vice
President of Resource America since 1992 and before that she had served as
Treasurer and Chief Accounting Officer of Resource America since 1989. Also,
since 1995 Ms. McGurk has served as Vice President - Finance of Resource Energy,
Inc. Ms. McGurk devotes approximately 20% of her professional time to the
business and affairs of the managing general partner and Atlas America, and the
remainder of her professional time to the business and affairs of the managing
general partner's affiliates.
Michael L. Staines. Senior Vice President, Secretary, and a Director since 1998.
Mr. Staines is also Executive Vice President, Secretary, and a Director of Atlas
America since 1998; Senior Vice President of Resource America since 1989;
Secretary of Resource America from 1989 to 1998; Director of Resource America
from 1989 to 2000; President, Secretary, and a Director of Resource Energy,
Inc., an energy subsidiary of Resource America, since 1993; President of Atlas
Pipeline Partners GP, LLC since 2001; and Chief Operating Officer, Secretary,
and Managing Board Member of Atlas Pipeline Partners GP, LLC since its formation
in 1999. Mr. Staines is a member of the Ohio Oil and Gas Association and the
Independent Oil and Gas Association of New York. Mr. Staines received a Bachelor
of Science degree from Cornell University in 1971 and a Master of Business
degree from Drexel University in 1977. Mr. Staines devotes approximately 10% of
his professional time to the business and affairs of the managing general
partner and Atlas America, and the remainder of his professional time to the
business and affairs of the managing general partner's affiliates.
Michael G. Hartzell. Vice President - Land Administration since 2001. Mr.
Hartzell has been with Atlas Energy Group, Inc. since 1980. He began his career
with Atlas Energy Group, Inc. as a Land Department Representative and was
promoted to Land Manager of the Indiana County, Pennsylvania operations in 1981.
He relocated to the Atlas Energy Group, Inc. office in Mercer, Pennsylvania in
1985 where he served as Land Manager until being promoted to General Manager in
1996. In 2000, Mr. Hartzell was promoted to Senior Land Coordinator for Atlas
America, Inc., and he manages all Land Department functions. Mr. Hartzell serves
on the Environmental Committee of the Independent Oil and Gas Association of
Pennsylvania and is a past Chairman of the Committee. Mr. Hartzell devotes
approximately 100% of his professional time to the business and affairs of the
managing general partner and Atlas America.
Donald R. Laughlin. Vice President-Drilling and Production since January 2002.
Mr. Laughlin joined Atlas America as Senior Drilling Engineer in May, 2001 and
has over thirty years of experience in the Appalachian Basin. Before joining
Atlas America, Mr. Laughlin was employed with Columbia Gas Transmission
Corporation from 1995 to May 2001 where he became Vice President Drilling and
Production. From 1989 to 1995 Mr. Laughlin was employed by Cabot Oil & Gas
Corporation as Manager of Drilling Operations and Manager of Technical
Services; from 1977 to 1989 he was employed by Doran & Associated, Inc. as
Vice President-Operations; and from 1970 to 1977 he was employed by Columbia
Gas Transmission Corporation as Drilling Engineer and Gas Storage Engineer.
Mr. Laughlin received his Petroleum Engineering degree from the University of
Pittsburgh in 1970. He is a member of the Society of Petroleum Engineers. Mr.
Laughlin
46
devotes approximately 100% of his professional time to the business and affairs
of the managing general partner and Atlas America.
Darshan V. Patel. Chief Legal Officer since January, 2002. Mr. Patel also serves
as Associate General Counsel for Resource America, Inc. since 2001, and Vice
President of Anthem Securities, Inc. since August, 2002. Mr. Patel received a
Bachelor of Arts degree from Boston University in 1992. He also received a Juris
Doctorate degree from American University's Washington College of Law in 1995.
From 1996 to 1998, Mr. Patel was associated with the law firm of Glynn &
Associates, in Flemington, N.J., practicing litigation and real estate. From
1998 to 2000, Mr. Patel was associated with the law firm of Berman, Paley,
Goldstein & Kannry, in New York, N.Y., practicing commercial litigation. Mr.
Patel devotes approximately 20% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates.
Marci F. Bleichmar. Vice President of Marketing for the managing general partner
since January 2003. Before that Ms. Bleichmar served as Director of Marketing
for the managing general partner and Atlas America since February 2001 when she
joined the managing general partner and Atlas America. Ms. Bleichmar also serves
as Director of Marketing for Resource America, Inc. since February 2001. From
March 2000 through February 2001, Ms. Bleichmar served as Director of Marketing
for Jacob Asset Management. From March 1998 through March 2000, she served as an
Account Executive at Bloomberg Financial Services LP. From November 1994 through
March 1998, Ms. Bleichmar was an Associate on the Derivatives Trading Desk of JP
Morgan. Ms. Bleichmar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.
Sherwood S. Lutz. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined
Viking Resources as senior geologist, which was purchased by Resource America in
1999. Since 1999 Mr. Lutz has been a senior geologist for the managing general
partner and Atlas America. Mr. Lutz received his Bachelor of Science degree in
Geological Sciences from the Pennsylvania State University in 1973. Mr. Lutz is
a certified petroleum geologist with the American Association of Petroleum
Geologists as well as a licensed professional geologist in Pennsylvania. Mr.
Lutz devotes approximately 100% of his professional time to the business and
affairs of the managing general partner and Atlas America.
Michael W. Brecko. Director of Energy Sales since November 2002. Mr. Brecko has
over 16 years of natural gas marketing experience in the oil and natural gas
industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University
with a Bachelor of Science degree in Civil Engineering. His career in natural
gas marketing began when he joined Equitable Gas Company, a local distribution
company as a marketing representative in the commercial/industrial marketing
division from May 1986 to August 1992. He subsequently joined O&R Energy, a
subsidiary of Orange and Rockland Utilities, as regional marketing manager from
August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr.
Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and
natural gas producer as an account executive and was promoted in August 1998 to
natural gas trader. In November 2001, he joined Sprague Energy Corporation, a
multi-energy sourced company as a regional account manager before joining Atlas
America Inc in 2002. Mr. Brecko devotes approximately 100% of his professional
time to the business and affairs of the managing general partner and Atlas
America.
Karen A. Black. Vice President - Partnership Administration since February 2003.
Ms. Black is also Vice President and Financial and Operations Principal of
Anthem Securities since October 2002. Ms. Black joined the managing general
partner and Atlas America in July 2000 and served as manager of production,
revenue and partnership accounting from July 2000 through October 2001, after
which she served as manager and financial analyst until her appointment as Vice
President - Partnership Administration. Before joining the managing general
partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as
controller from April 1997 through June 2000. Ms. Black was employed as a tax
accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997.
Ms. Black devotes approximately 50% of her professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
her professional time to the business and affairs of Anthem Securities.
47
Justin T. Atkinson. Director of Due Diligence since February 2003. Mr.
Atkinson also serves as Vice President and Chief Compliance Officer of Anthem
Securities since October 2002 and before that Mr. Atkinson served as assistant
compliance Officer of Anthem Securities from December 2001 until October 2002.
Before his employment with the managing general partner, Mr. Atkinson was a
manager of investor and broker dealer relations with Viking Resources
Corporation from 1996 until November 2001. Mr. Atkinson earned a Bachelor of
Arts in Business Management From Walsh University in North Canton, Ohio. Mr.
Atkinson devotes approximately 25% of his professional time to the business
and affairs of the managing general partner and Atlas America, and the
remainder of his professional time to the business and affairs of Anthem
Securities.
Winifred C. Loncar, Director of Investor Services since February, 2003. Mrs.
Loncar previously held the position of manager of investor services from the
inception of the investor service department in 1990 to February 2003. Before
that she was executive secretary to the managing general partner. Mrs. Loncar
received a degree in business from Point Park College in 1998. Ms. Loncar
devotes approximately 100% of her professional time to the business and
affairs of the managing general partner and Atlas America.
Other Key Personnel.
John S. Coffey. Mr. Coffey serves as President of Anthem Securities since May,
2000. He is also a national accounts representative for the managing general
partner since September 2002. Before joining Anthem Securities, Mr. Coffey was
previously associated with Financial Investment Analysts, Inc. from November
1984 to May 2000, where he served as a financial planner, a principal, a
branch office manager and a registered investment advisor. Mr. Coffey earned a
Bachelor of Science degree in Industrial Management from Gannon University in
1970 and is a member of the Institute of Industrial Engineers and The
Financial Planning Association. Mr. Coffey devotes approximately 75% of his
professional time to the business and affairs of the managing general partner
and Atlas America, and the remainder of his professional time to the business
and affairs of Anthem Securities.
Atlas America, Inc., a Delaware Holding Company
As of January 1, 2003, the Board of Directors for Atlas America includes the
following:
NAME AGE POSITION OR OFFICE
- ---- --- ------------------
Edward E. Cohen 64 Chairman of the Board
Jonathan Z. Cohen 32 Vice Chairman
Freddie M. Kotek 47 Director
Michael L. Staines 53 Director
John S. White 62 Director
JoAnn Bagnell 74 Director
Frank P. Carolas 43 Director
Jeffrey C. Simmons 44 Director
See " - Officers, Directors and Key Personnel," above, 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 on request.
The managing general partner and its affiliates under Atlas America employ a
total of approximately one hundred thirty-eight persons in its energy
operations, consisting of six drilling and completion personnel, eighty
production/measurement personnel, six pipeline personnel, thirteen well services
personnel, four purchasing personnel, one reservoir engineer, one health,
environment and safety person, one gas marketing person, four leasing personnel,
five geologists, three well site construction personnel, eleven land
administration personnel, and three office services personnel.
At September 30, 2002 Atlas America and its affiliates had more than $360
million of energy assets under management.
48
Organizational Diagram (1)
This organizational diagram does not include all of the subsidiaries of Resource
America.
GRAPHIC OMITTED
- ---------------
(1) Resource Energy, Viking Resources, and Atlas Noble Corporation are also
engaged in the oil and gas business. Resource Energy has been an energy
subsidiary of Resource America since 1993. Resource America acquired Viking
Resources in August 1999, and Atlas Noble Corporation was formed in October
2000 after Resource America acquired all of the assets of Kingston Oil
Corporation. Atlas America manages their assets and employees including
sharing common employees. Also, many of the officers and directors of the
managing general partner serve as officers and directors of those entities.
Remuneration
No officer or director of the managing general partner will receive any direct
remuneration or other compensation from the partnership. These persons will
receive compensation solely from affiliated companies 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. The officers and directors of AIC, Inc. are
Jonathan Z. Cohen, Michael L. Staines, Frank P. Carolas and Jeffrey C.
Simmons. The biographies of Messrs. Staines, Carolas and Simmons are set forth
above.
Transactions with Management and Affiliates
The managing general partner is dependant on its parent company, Atlas America,
for management and administrative functions and financing for capital
expenditures. The managing general partner pays a management fee to Atlas
America
49
for management and administrative services, which amounted to $10.5 million
and $6.4 million for the years ended September 30, 2002 and 2001,
respectively. (See "Financial Information Concerning the Managing General
Partner.")
Atlas Energy Group, Inc. shareholders are eligible to receive incentive
compensation should Atlas Energy Group, Inc.'s post-acquisition earnings exceed
a specified amount during the five years following the merger which was in
September 1998. The incentive compensation is equal to 10% of Atlas Energy
Group, Inc.'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.
The managing general partner and its officers, directors and affiliates have in
the past invested, and may in the future invest, in partnerships sponsored by
the managing general partner. They may also subscribe for units in each
partnership as described in "Plan of Distribution."
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION,
RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES
None of the partnerships composing the program have been formed. Each
partnership once funded as discussed in "Terms of the Offering - Activation of
the Partnerships" will be formed under the Delaware Revised Uniform Limited
Partnership Act. Thus, the partnerships to be formed:
o have no net worth;
o do not own any properties on which wells will be drilled;
o have no third-party investors;
o have not conducted any operations; and
o have not made any distributions.
Thus, they have not included any historical information in this prospectus. (See
"Capitalization and Source of Funds and Use of Proceeds," "Proposed Activities,"
"Competition, Markets and Regulation," and "Financial Information Concerning the
Managing General Partner.")
Each partnership will depend on the proceeds of this offering and the managing
general partner's capital contributions to carry out its proposed activities.
Each partnership intends to use the subscription proceeds to pay the intangible
drilling costs, the investors' share of equipment costs, and the investors'
share of any cost overruns of drilling and completing the partnership's wells.
To the extent that the subscription proceeds are less than the nonbinding
targeted amounts described in "Terms of the Offering - Subscription to a
Partnership," fewer wells will be drilled and each partnership's ability to
diversify its drilling activities will be reduced.
The managing general partner believes that each partnership's liquidity
requirements will be satisfied from the following:
o the subscription proceeds of this offering;
o the managing general partner's capital contributions;
50
o the cash flow from future operations; and
o partnership borrowings, if necessary,
The managing general partner also anticipates that no additional funds will be
required for operating costs before a partnership begins receiving production
revenues from its wells.
Substantially all the subscription proceeds of you and the other investors in a
partnership will be committed or expended after the offering of the partnership
closes. If a partnership requires additional funds for cost overruns or
additional development or remedial work after a well begins producing, then
these funds may be provided by:
o subscription proceeds, if available, drilling fewer wells, or
acquiring a lesser working interest in one or more wells;
o borrowings from the managing general partner or its affiliates; or
o retaining partnership revenues.
There will be no borrowings from third-parties. The amount that may be borrowed
by a partnership from the managing general partner and its affiliates may not at
any time exceed 5% of the partnership's subscription proceeds from you and the
other investors and must be without recourse to you and the other investors. The
partnership's repayment of any borrowings would be from partnership production
revenues and would reduce or delay your cash distributions.
If the managing general partner loans money to a partnership, which it is not
required to do, then:
o the interest charged to the partnership must not exceed the managing
general partner's interest cost or the interest that would be charged
to the partnership without reference to the managing general partner's
financial abilities or guarantees by unrelated lenders, on comparable
loans for the same purpose; and
o the managing general partner may not receive points or other financing
charges or fees, although the actual amount of the charges incurred
from third-party lenders may be reimbursed to the managing general
partner.
Currently, Atlas America, Inc. (the "borrower"), which is an affiliate of the
managing general partner, participates in a $75 million revolving credit
facility with a group of banks that includes Union Bank of California, N.A., as
syndication agent with Wachovia Bank, N.A. as the agent and issuing bank. The
managing general partner, Resource America, Inc. and various energy subsidiaries
of Resource America are guarantors of the credit agreement. This facility has an
initial borrowing base of $45 million, which may be increased to $75 million
subject to growth in the oil and gas reserves of the borrower and the
guarantors. Borrowings under the facility are collateralized by substantially
all the assets of Atlas America, the managing general partner and the other
guarantors. This includes the managing general partner's interests in its
partnerships, but does not include any investor's interest in a partnership. A
breach of the credit agreement by the borrower constitutes a default under the
loan. The credit facility has a term ending in July 2005. At March 31, 2003, the
borrower had an outstanding balance of approximately $39 million and also had a
$275,000 letter of credit issued under the facility.
The managing general partner is dependant on its parent company, Atlas America,
for management and administrative functions and financing for capital
expenditures. The managing general partner pays a management fee to Atlas
America for management and administrative services, which amounted to $10.5
million and $6.4 million for the years ended September 30, 2002 and 2001,
respectively. See footnotes 3 and 4 to the managing general partner's audited
financial statements and footnote 4 to the managing general partner's unaudited
financial statements for more details concerning the credit facility and
inter-company borrowings in "Financial Information Concerning the Managing
General Partner."
51
PROPOSED ACTIVITIES
Overview of Drilling Activities
The managing general partner anticipates that all the wells of each partnership
will be development wells, which means a well drilled within the proved area of
a natural gas or oil reservoir to the depth of a stratigraphic horizon known to
be productive. Stratigraphic means a layer of rock which has characteristics
that differentiate it from the rocks above and below it. Stratigraphic horizon
generally means that part of a formation or layer of rock with sufficient
porosity and permeability to form a petroleum reservoir. Also, the majority of
the wells will be classified as natural gas wells, which may produce a small
amount of oil, although some of the wells may be classified as oil wells.
Each partnership will be a separate business entity from the other partnership,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnership unless you also invest in the other partnership. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest.
The number of wells drilled by a partnership is determined by the amount of
funds raised for that partnership and the specific prospects drilled by that
partnership, and cannot be determined precisely in advance of funding of a
partnership. The managing general partner, however, anticipates that a
partnership will drill approximately:
o 5 wells in which it has a 100% working interest if the minimum
subscriptions of $1 million are received; and
o 50 wells in which it has a 100% working interest will be drilled for
every $10 million of subscriptions received.
The actual number of wells drilled by each partnership may vary from these
estimates and will depend on the following:
o where the wells are drilled;
o if there are any cost overruns on the investors' share of well
costs; and
o the partnership's percentage of interest owned in the wells, which
could range from 25% to 100%.
Each partnership generally will drill different wells, but they may own
interests and participate in drilling and completing one or more of the same
wells.
Before the managing general partner selects a prospect on which a well will be
drilled by a partnership, it will review all available geologic and production
data for wells located in the vicinity of the proposed well including, but not
limited to:
o various well logs;
o completion reports;
o plugging reports; and
o production reports.
For example, production information from surrounding wells in the area is an
important indicator in evaluating the economic potential of a proposed well to
be drilled. It has been the managing general partner's experience that natural
gas production from wells drilled to the formations or the reservoirs in the
primary areas is reasonably consistent with nearby wells, although from time to
time there can be great differences in the natural gas volumes and performance
of wells located close together.
52
However, production information is only one factor and the managing general
partner may propose a well to be drilled by a partnership because geologic
trends in the immediate area where production has already been established, such
as sand thickness, porosities and water saturations, lead the managing general
partner to believe that the proposed well locations will have similar
production.
Primary Areas of Operations
The managing general partner will not decide on the majority of the specific
wells to be drilled in any partnership until the offering of units in that
partnership has ended. However, the managing general partner intends that Atlas
America Public #12-2003 Limited Partnership, which must close on or before
December 31, 2003, will drill the prospects described in "Appendix A -
Information Regarding Currently Proposed Prospects for Atlas America Public
#12-2003 Limited Partnership." These prospects represent approximately $15
million of subscription proceeds which is a portion of the non-binding targeted
subscription proceeds described in "Terms of the Offering - Subscription to a
Partnership." If there are adverse events with respect to any of the currently
proposed prospects, the managing general partner will substitute the
partnership's prospects as discussed below in "- Interest of Parties." The
managing general partner also anticipates that it will designate a portion of
each partnership's prospects in the partnerships designated Atlas America Public
#12-2004(_) Limited Partnership by supplement or an amendment to the
registration statement.
This means that you will not be able to evaluate the majority of the specific
prospects that will be drilled by your partnership. However, by waiting as long
as possible before selecting all of the specific prospects to be drilled by a
partnership, the managing general partner may have information available which
helps it to select better prospects for the partnership, and it may be able to
include prospects which were not available when this prospectus was written or
even before the partnership was closed.
This section includes a general description of the areas where the managing
general partner anticipates partnership wells may be drilled. If additional
areas are added, then this information will be supplemented. As discussed below,
the three primary areas for the partnerships' drilling activities are:
o the Clinton/Medina Geological Formation in western Pennsylvania that
also covers an area in eastern Ohio primarily in Stark, Mahoning,
Trumbull and Portage Counties;
o the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and
Greene Counties, Pennsylvania; and
o the Upper Devonian Sandstone Reservoirs in Armstrong County,
Pennsylvania.
Both Fayette County and Armstrong County are in western Pennsylvania. The
Clinton/Medina geological formation in Pennsylvania and Ohio is the same
geological formation, although in Pennsylvania it is often referred to as the
Medina/Whirlpool geological formation. For purposes of this prospectus, the term
Clinton/Medina geological formation is used for both Ohio and Pennsylvania. The
wells drilled to the Clinton/Medina geological formation, regardless of whether
they are situated in western Pennsylvania, eastern Ohio, western New York, or
southern Ohio, and the Mississippian and/or Upper Devonian Sandstone reservoirs
have the following similarities:
o geological features such as structure and faulting are not generally
factors used in finding commercial production from a well drilled to
this formation or these reservoirs and the governing factors appear to
be sand quality in terms of net pay zone thickness, porosity, and the
effectiveness of fracture stimulation;
o a well drilled to this formation or these reservoirs usually requires
hydraulic fracturing of the formation to stimulate productive
capacity;
o generally, natural gas from a well drilled to this formation or these
reservoirs is produced at rates which decline rapidly during the first
few years of operations, and although the well can produce for many
years, a proportionately larger amount of production can be expected
within the first several years; and
53
o it has been the managing general partner's experience that natural gas
production from wells drilled to this formation or these reservoirs is
reasonably consistent with nearby wells, although from time to time
there can be great differences in the natural gas volumes and
performance of wells located close together.
The managing general partner anticipates that the majority of the subscription
proceeds of each partnership will be expended in the primary areas, although
some of the subscription proceeds of each partnership may be expended in the
secondary areas.
Clinton/Medina Geological Formation in Western Pennsylvania. The Clinton/ Medina
geological formation is a blanket sandstone found throughout most of the
northwestern edge of the Appalachian Basin. The Clinton/Medina is described in
petroleum industry terms as a "tight" sandstone with porosity ranging from 6% to
12% and with very low 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 natural gas 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, in "Appendix
A - Information Regarding Currently Proposed Prospects for Atlas America Public
#12-2003 Limited Partnership" for a discussion of the development of the
Clinton/Medina Geological Formation in western Pennsylvania, which also covers
an area in eastern Ohio primarily in Stark, Mahoning, Trumbull, and Portage
Counties.
The wells in the Clinton/Medina geological formation in western Pennsylvania and
eastern Ohio will be:
o primarily situated in Crawford, Mercer, Lawrence, Warren, and
Venango Counties, Pennsylvania, and Stark, Mahoning, Trumbull and
Portage Counties, Ohio;
o situated on approximately 50 acres, subject to adjustment to take
into account lease boundaries;
o drilled at least 1,650 feet from each other in Pennsylvania, which is
greater than the 660 feet minimum distance allowed by state law or
local practice to protect against drainage from adjacent wells, and
drilled at least 1,000 feet from each other in Ohio;
o drilled from approximately 5,100 to 6,300 feet in depth;
o classified as natural gas wells which may produce a small amount of
oil, although the wells in eastern Ohio may be classified as oil
wells; and
o primarily connected to the gathering system owned by Atlas Pipeline
Partners and have their natural gas production primarily marketed to
First Energy Solutions Corporation as described below in " - Sale of
Natural Gas and Oil Production".
Also, see "- Secondary Areas of Operations" below, for a discussion of the
Clinton/Medina geological formation in western New York and southern Ohio.
Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania.
The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous
lens-shaped accumulations found throughout most of the Appalachian Basin. The
Mississippian/Upper Devonian Sandstone reservoirs have porosities ranging from
5% to 20% with attendant permeabilities. See the geologic evaluation prepared by
United Energy Development Consultants, Inc. for a discussion of the development
of the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and Greene
Counties, Pennsylvania.
The wells in the Mississippian/Upper Devonian Sandstone reservoirs will be:
o situated on approximately 20 acres, subject to adjustment to take into
account lease boundaries;
54
o drilled at least 1,000 feet from each other, although existing wells
may be re-entered by parties other than the partnership even though
they are not 1,000 feet from each other;
o drilled from approximately 1,900 to 4,500 feet in depth;
o classified as natural gas wells which may produce a small amount of
oil; and
o primarily connected to the gathering system owned by Atlas Pipeline
Partners and have their natural gas production primarily marketed to
First Energy Solutions Corporation, although for the 12 month period
from March 31, 2003 to March 31, 2004 the natural gas production will
be marketed primarily to Colonial Energy, Inc. and UGI Energy Services
as described below in "- Sale of Natural Gas and Oil Production."
Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania. The Upper
Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found
throughout most of the Appalachian Basin. The Upper Devonian Sandstone
reservoirs have porosities ranging from greater than 5% to 20% with attendant
permeabilities. See the geologic evaluation prepared by United Energy
Development Consultants, Inc. for a discussion of the development of the Upper
Devonian Sandstone Reservoir in Armstrong County, Pennsylvania. The prospects in
Armstrong County, Pennsylvania were acquired from U.S. Energy Exploration
Corporation as described below in "-Interest of Parties," and U.S. Energy will
participate in the wells with the partnership.
The wells in the Upper Devonian Sandstone reservoirs will be:
o situated on approximately 20 acres, subject to adjustment to take into
account lease boundaries;
o drilled at least 1,000 feet from each other, although under
Pennsylvania law in certain circumstances a variance can be obtained,
and out of the wells the managing general partner has drilled to date
in this general area, some have been drilled less than 1,000 feet
apart, but even in those cases the wells were approximately 980 feet
or more from each other;
o drilled from approximately 1,800 to 4,400 feet in depth;
o classified as natural gas wells which may produce a small amount of
oil; and
o connected to a gathering system owned by U.S. Energy and have their
natural gas production marketed by U.S. Energy as described below in
"- Sale of Natural Gas and Oil Production."
Secondary Areas of Operations
The managing general partner also has reserved the right to use a portion of the
subscription proceeds of each partnership to drill development wells in other
areas of the Appalachian Basin. The secondary areas anticipated by the managing
general partner are discussed below.
Clinton/Medina Geological Formation in Western New York. Wells located in
western New York and drilled to the Clinton/Medina geological formation will be:
o primarily situated in Chautauqua County;
o situated on approximately 40 acres, subject to adjustment to take
into account lease boundaries;
o drilled from approximately 3,800 to 4,000 feet in depth;
o drilled on leases with a net revenue interest of approximately
84.375% to 87.5%;
55
o classified as natural gas wells which may produce a small amount of
oil; and
o connected to the gathering system owned by Atlas Pipeline Partners and
have their natural gas production primarily marketed to First Energy
Solutions Corporation, and/or commercial users in the area, although a
portion of the natural gas production may be gathered and marketed by
Great Lakes Energy Partners, L.L.C. as described below in " - Sale of
Natural Gas and Oil Production."
Mississippian Berea Sandstone in Eastern Ohio. Wells located in eastern Ohio
and drilled to the Mississippian Berea Sandstone will be:
o primarily situated in Columbiana County;
o situated on approximately 5 acres, subject to adjustment to take
into account lease boundaries;
o drilled from approximately 850 to 950 feet in depth;
o drilled on leases with a net revenue interest of approximately
84.375% to 87.5%;
o classified as natural gas wells which may produce a small amount of
oil; and
o connected to the gathering system owned by Atlas Pipeline Partners and
have their natural gas production primarily marketed to First Energy
Solutions Corporation, as described below in " - Sale of Natural Gas
and Oil Production."
Devonian Oriskany Sandstone in Eastern Ohio. Wells located in eastern Ohio and
drilled to the Devonian Oriskany Sandstone will be:
o primarily situated in Tuscarawas County;
o situated on approximately 40 acres, subject to adjustment to take
into account lease boundaries;
o drilled from approximately 3,800 to 4,200 feet in depth;
o drilled on leases with a net revenue interest of approximately
84.375% to 87.5%;
o classified as natural gas wells which may produce a small amount of
oil; and
o connected to the gathering system owned by Atlas Pipeline Partners and
have their natural gas production primarily marketed to First Energy
Solutions Corporation, although a portion of the natural gas
production may be marketed by Dominion Field Services as described
below in " - Sale of Natural Gas and Oil Production."
Upper Devonian Sandstone in McKean County, Pennsylvania. Wells located in McKean
County and drilled to the Upper Devonian Sandstones will be:
o primarily situated in McKean County;
o situated on approximately 6 acres subject to adjustments to take
into account lease boundaries;
o drilled from approximately 2,000 to 2,500 feet in depth;
o drilled on leases with a net revenue interest of approximately
84.375% to 87.5%;
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o classified as combination wells producing both natural gas and oil;
and
o connected to the gathering systems owned by Atlas Pipeline Partners
and M&M Royalty, LTD. and have their natural gas production
primarily marketed to M&M Royalty, LTD. as described below in " -
Sale of Natural Gas and Oil Production."
Clinton/Medina Geological Formation in Southern Ohio. Wells located in
southern Ohio and drilled to the Clinton/Medina geological formation will be:
o primarily situated in Noble, Washington, Guernsey, and Muskingum
Counties;
o situated on approximately 40 acres, subject to adjustment to take
into account lease boundaries;
o drilled at least 1,000 feet from each other;
o drilled from approximately 4,900 to 6,500 feet in depth;
o drilled on leases with a net revenue interest of approximately 82.5%
to 87.5%;
o classified as either natural gas wells or oil wells; and
o primarily connected to the gathering system owned by Atlas Pipeline
Partners if classified as natural gas wells and have their natural gas
production primarily marketed by First Energy Solutions Corporation,
although a portion of the natural gas production may be gathered and
marketed by Triad Energy Corporation of West Virginia, Inc. as
described below in " - Sale of Natural Gas and Oil Production."
Additionally, the managing general partner anticipates that the leases in
southern Ohio will have been originally acquired from a coal company and are
subject to a provision that the well must be abandoned if it hinders the
development of the coal. Thus, the managing general partner will not drill a
well on any lease subject to this provision unless it covers lands that were
previously mined. Although this does not totally eliminate the risk because the
leases may cover other coal deposits that might be mined during the life of a
well, the managing general partner believes that drilling wells on these
previously mined leases would be in the best interests of the partnership.
Acquisition of Leases
The managing general partner will have the right, in its sole discretion, to
select the prospects which each partnership will drill, and the managing general
partner intends that Atlas America Public #12-2003 Limited Partnership, which
must close on or before December 31, 2003, will drill the prospects described in
"Appendix A - Information Regarding Currently Proposed Prospects for Atlas
America Public #12-2003 Limited Partnership." The managing general partner also
anticipates that it will designate a portion of each partnership's prospects in
the partnerships designated Atlas America Public #12-2004(_) Limited Partnership
by supplement or an amendment to the registration statement.
The leases covering each prospect on which one well will be drilled will be
acquired by a partnership from the managing general partner or its affiliates
and credited to the managing general partner as a part of its required capital
contribution to the partnership. Neither the managing general partner nor its
affiliates will receive any royalty or overriding royalty interest on any well.
The managing general partner anticipates that it will select the prospects for
each partnership, including any additional and/or substituted prospects, from
the following:
o leases in its and its affiliates' existing leasehold inventory;
57
o leases that are subsequently acquired by it or its affiliates; or
o leases owned by independent third-parties that may participate with
the partnership in drilling wells.
Most of the prospects acquired by a partnership will be in areas where the
managing general partner or its affiliates have previously conducted drilling
operations. The managing general partner believes that its and its affiliates'
leasehold inventory and leases acquired from third-parties will be sufficient to
provide all the prospects to be drilled by each partnership.
The managing general partner and its affiliates are continually engaged in
acquiring additional leasehold acreage in Pennsylvania, Ohio, and other areas of
the United States. As of April 30, 2003, the managing general partner and its
affiliates owned approximately:
o 121,974 net acres of undeveloped lease acreage in Pennsylvania;
o 60,841 net acres of undeveloped lease acreage in Ohio;
o 5,301 net acres of undeveloped lease acreage in West Virginia;
o 6,251 net acres of undeveloped lease acreage in Kentucky; and
o 11,985 net acres of undeveloped lease acreage in New York.
Most, if not all, of the prospects to be selected for the partnerships are
expected to be single well proved undeveloped prospects. Thus, only one well
will be drilled on each prospect and the number of prospects the managing
general partner will assign to each partnership will be the same as the number
of wells which the partnership has the funds to drill. This also means that the
partnership, in all likelihood, will not farmout any acreage. However, the need
for a farmout might arise, for example, if during drilling or subsequently the
managing general partner determines there might be a productive horizon situated
above (i.e. uphole) the target horizon, but the partnership does not have the
funds to complete the well in the horizon or the completion of the horizon would
be inconsistent with the partnership objective. In this event, the managing
general partner might determine to farmout the activity for the partnership.
Generally, a farmout is an agreement in which the owner of the lease or existing
well agrees to assign his interest in certain acreage under the lease or the
existing well to an assignee subject to the assignee drilling one or more wells
or completing or recompleting the existing well in one or more horizons. The
owner would retain some interest in the assigned acreage or well. See "Conflicts
of Interest - Conflicts Involving the Acquisition of Leases" for the procedure
for a farmout.
Deep Drilling Rights Retained by Managing General Partner. In the areas where
the Clinton/Medina is the primary geological formation, the lease assignments to
each partnership will be limited to a depth of from the surface to the top of
the Queenston geological formation, and the managing general partner will retain
the deeper drilling rights beginning with the Queenston geological formation. In
all other areas the lease assignments to each 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 deeper drilling rights. Because each
partnership's objective is to conduct development drilling which would not be
the case with the deeper formations the managing general partner will retain the
deeper formations, which includes ownership of any coal bed methane production
that might be obtained from the deeper formations. Conversely, as between a
partnership and the managing general partner, the partnership will own any coal
bed methane production that might be obtained from the shallower formations that
are not included in the deeper drilling rights retained by the managing general
partner.
The managing general partner believes that a 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 leases does not include any value
allocable to the deeper drilling rights retained by it. If in the future the
managing general partner undertakes any activities with respect to the deeper
formations, including
58
drilling an exploratory well, then the partnerships would not share in the
profits from these activities, nor would they pay any of the associated costs.
Interests of Parties
Generally, production and revenues from a well drilled by a partnership will be
net of the applicable landowner's royalty interest, which is typically 1/8th
(12.5%) of gross production, and any interest in favor of third-parties such as
an overriding royalty interest. Landowner's royalty interest generally means an
interest that is created in favor of the landowner when an oil and gas lease is
obtained; and overriding royalty interest generally means an interest 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 natural gas and oil
production free and clear of all costs of development, operation, or maintenance
of the well. This is compared with a working interest, which generally means an
interest in the lease under which the owner of the interest must pay some
portion of the cost of development, operation, or maintenance of the well. Also,
the leases will be subject to terms that are customary in the industry such as
free gas to the landowner-lessor for home heating requirements, etc.
The managing general partner anticipates that each partnership generally will
have a net revenue interest in its leases in its primary drilling areas as set
forth in the chart below. Net revenue interest generally means the percentage of
revenues the owner of an interest in a well is entitled to receive under the
lease. The following chart expresses the percentage of production revenues that
the managing general partner, the landowner, other third-parties, and you and
the other investors in a partnership will share in from the wells in two of the
three primary proposed areas. The third primary proposed area is discussed
following the chart. The chart assumes that the partnership owns 100% of the
interest in the well. If a partnership acquires a lesser percentage ownership
interest in a well, which will be the case in Armstrong County, then the
partnership's net revenue interest in that well will decrease proportionately.
The actual number, identity and percentage of working interests or other
interests in prospects to be acquired by the partnerships will depend on, among
other things:
o the amount of subscription proceeds received in a partnership;
o the latest geological and production data;
o potential title or spacing problems;
o availability and price of drilling services, tubular goods and
services;
o approvals by federal and state departments or agencies;
o agreements with other working interest owners in the prospects;
o farm-ins; and
o continuing review of other prospects that may be available.
59
Primary Areas.
Clinton/Medina Geological Formation in Western Pennsylvania and Mississippian/
Upper Devonian Sandstone Reservoirs in Fayette and Greene Counties,
Pennsylvania.
Partnership Third Party 87.5% Partnership
Entity Interest Royalty Interest Net Revenue Interest(2)
----------------- ------------------------- ---------------------------- ---------------------
Managing General Partner ........ 32% partnership interest (1) 28.0%
Investors ....................... 68% partnership interest (1) 59.5%
Third Party ........................................................ 12.5% Landowner Royalty Interest 12.5%
---------------------
100.0%
=====================
- ---------------
(1) These percentages are for illustration purposes only and assume the managing
general partner's minimum required capital contribution to each partnership
of 25% and capital contributions of 75% from you and the other investors.
The actual percentages are likely to be different because they will be based
on the actual capital contributions of the managing general partner and you
and the other investors. However, the managing general partner's total
revenue share may not exceed 35% of partnership revenues regardless of the
amount of its capital contributions.
(2) It is possible that the wells could have a net revenue interest to a
partnership as low as 84.375% which would reduce the investors' interest to
57.375%.
Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania. The
managing general partner anticipates the leases in Armstrong County,
Pennsylvania will have a net revenue interest of 84.375% which would reduce the
investors' net revenue interest in the above chart to 57.375% assuming a 100%
working interest. U.S. Energy, the originator of the leases, however, will
retain a 25% working interest in the wells and participate with the partnership
in the costs of drilling, completing, and operating the wells to the extent of
its retained working interest. Thus, the net revenue interest to the investors
will be reduced to approximately 43% which is 75% of 57.375%.
Secondary Areas. Although the managing general partner anticipates each
partnership will have a net revenue interest ranging from 81% to 87.5% in the
secondary areas described above, there is no minimum net revenue interest that a
partnership is required to own before drilling a well in other areas of the
Appalachian Basin. The leases in these other areas may be subject to interests
in favor of third-parties that are not currently known such as:
o overriding royalty interests;
o net profits interests;
o carried interests;
o production payments;
o reversionary interests pursuant to farmouts or non-consent elections
under joint operating agreements; or
o other retained or carried interests.
Title to Properties
Title to all leases acquired by a partnership will be held in the name of the
partnership. However, to facilitate the acquisition of the leases title to the
leases may initially be held in the name of:
o the managing general partner;
o the operator;
60
o their affiliates; or
o any nominee designated by the managing general partner.
Title to each partnership's leases will be transferred to the partnership and
filed for record from time to time after the wells are drilled and completed.
The managing general partner will take the steps it deems necessary to assure
that each partnership has acceptable title for its purposes. However, it is not
the practice in the natural gas and oil industry to warrant title or obtain
title insurance on leases and the managing general partner will provide neither
for the leases it assigns to a partnership. The managing general partner will
obtain a favorable formal title opinion for the leases before each well is
drilled, but will not obtain a division order title opinion after the well is
completed. The managing general partner may use its own judgment in waiving
title requirements and will not be liable for any failure of title of leases
transferred to a partnership. Also, there is no assurance that the partnerships
will not experience losses from title defects excluded from or not disclosed by
the formal title opinion or that would have been disclosed by a division order
title opinion.
Drilling and Completion Activities; Operation of Producing Wells
The managing general partner intends that Atlas America Public #12-2003 Limited
Partnership, which must close on or before December 31, 2003, will drill the
prospects described in "Appendix A - Information Regarding Currently Proposed
Prospects for Atlas America Public #12-2003 Limited Partnership." These
prospects represent a portion of the non-binding targeted subscription proceeds
described in "Terms of the Offering - Subscription to a Partnership." The
managing general partner also anticipates that it will designate a portion of
each partnership's prospects in the partnerships designated Atlas America Public
#12-2004(_____) Limited Partnership by supplement or an amendment to the
registration statement. On receipt of the minimum subscriptions and written
instructions to the escrow agent from the managing general partner and the
dealer-manager, the managing general partner on behalf of a partnership may:
o form the partnership under the Delaware Revised Uniform Limited
Partnership Act;
o break escrow;
o transfer the escrowed funds to a partnership account;
o enter into the drilling and operating agreement, which is attached to
the partnership agreement as Exhibit II, with itself or an affiliate
as operator; and
o begin drilling to the extent the prospects have been identified to the
prospective investors.
Under the drilling and operating agreement, which is attached to the partnership
agreement as Exhibit II, the responsibility for drilling and either completing
or plugging partnership wells will be on the managing general partner or an
affiliate as the operator and the general drilling contractor. The managing
general partner as operator and general drilling contractor must begin drilling
the wells no later than March 31, 2004 for "Atlas America Public #12-2003
Limited Partnership," and March 31, 2005 for partnerships designated "Atlas
America Public #12-2004(___) Limited Partnership." The managing general partner
will pay the drilling and completion costs to itself as the operator as
incurred, except that the managing general partner is permitted to make advance
payments to itself as the operator when necessary to secure tax benefits of
prepaid drilling costs and when there is a substantial business purpose for the
advance payment. (See "Tax Aspects-Drilling Contracts.")
During drilling operations the managing general partner's duties as operator and
general drilling contractor will include:
o making the necessary arrangements for drilling and completing
partnership wells and related facilities for which it has
responsibility under the drilling and operating agreement;
61
o managing and conducting all field operations in connection with
drilling, testing, and equipping the wells; and
o making the technical decisions required in drilling and completing the
wells.
All partnership wells will be drilled to a sufficient depth to test thoroughly
the objective geological formation.
Under the drilling and operating agreement the managing general partner, as
operator and general drilling contractor, will complete each well if there is a
reasonable probability of obtaining commercial quantities of natural gas or oil.
However, based on its past experience, the managing general partner anticipates
that most of the wells drilled in the primary and secondary areas will have to
be completed before it can determine the well's productivity. If the managing
general partner, as operator and general drilling contractor, determines that a
well should not be completed, then the well will be plugged and abandoned.
During producing operations the managing general partner's duties, as operator,
will include:
o managing and conducting all field operations in connection with
operating and producing the wells;
o making the technical decisions required in operating the wells; and
o maintaining the wells, equipment, and facilities in good working order
during their useful life.
The managing general partner, as operator, will be reimbursed for its direct
expenses and will receive well supervision fees at competitive rates for
operating and maintaining the wells during producing operations. As discussed in
"Summary of Drilling and Operating Agreement," the drilling and operating
agreement contains a number of other material provisions which you are urged to
review.
Certain wells may be drilled with third-parties owning a portion of the working
interest in the wells. Any other working interest owner in a well may have a
separate agreement with the managing general partner for drilling and operating
the well with differing terms and conditions from those contained in a
partnership's drilling and operating agreement.
Sale of Natural Gas and Oil Production
Policy of Treating All Wells Equally in a Geographic Area. The managing general
partner is responsible for selling each partnership's natural gas and oil
production, and its policy is to treat all wells in a given geographic area
equally. This reduces certain potential conflicts of interest among the owners
of the various wells, including the partnerships, concerning to whom and at what
price the natural gas and oil will be sold. For example, the managing general
partner calculates a weighted average selling price for all of the natural gas
sold in the geographic area by dividing the money received from the sale of all
of the natural gas sold to customers in the area, which may be at different
prices, by the volume of all natural gas sold from the wells in the area. For
natural gas sold in western Pennsylvania the managing general partner received
an average selling price after deducting all expenses, including transportation
expenses, of approximately:
o $2.22 per mcf in 1998;
o $2.35 per mcf in 1999;
o $3.30 per mcf in 2000;
o $4.08 per mcf in 2001; and
o $3.34 per mcf in 2002.
Mcf means 1,000 cubic feet of gas.
62
If all the natural gas produced cannot be sold because of limited gathering or
pipeline capacity, or limited demand for the natural gas, which increases
pipeline pressure, then the production that is sold will be from those wells
which have the greatest well pressure and are able to feed into the pipeline,
regardless of which partnerships own the wells. The proceeds from these natural
gas sales will be credited only to the partnerships whose wells produced the
natural gas sold.
Gathering of Natural Gas. Under the partnership agreement the managing general
partner will be responsible for gathering and transporting the natural gas
produced by the partnerships to interstate pipeline systems, local distribution
companies, and end-users in the area. For the majority of each partnership's
natural gas production, including natural gas in the primary areas, as discussed
below, the managing general partner anticipates that it will use the gathering
system owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating
Partnership) which is a master limited partnership formed by a subsidiary of
Atlas America as managing general partner using Atlas America and Viking
Resources personnel who act as its officers and employees. Atlas Pipeline
Partners acquired the natural gas gathering system and related facilities of
Atlas America, Resource Energy, and Viking Resources in February 2000. The
gathering system consists of approximately 1,300 miles of intrastate pipelines
located in western Pennsylvania, eastern Ohio, and western New York. If a
partnership's natural gas is not transported through the Atlas Pipeline Partners
gathering system, it is because there is a third- party operator or the
gathering system has not been extended to the wells. In these cases as described
in "Compensation - Gathering Fees," the natural gas will be transported through
a third-party gathering system, and the partnership will pay the managing
general partner a competitive gathering fee all or a portion of which will be
paid to the third-party.
As a part of the sale of the gathering system to Atlas Pipeline Partners in
February 2000, Atlas America and its affiliates, Resource Energy and Viking
Resources, made the commitments set forth below which to varying degrees may
affect the partnerships. 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.
Atlas America, Resource Energy and Viking Resources are required to pay a
gathering fee to Atlas Pipeline Partners equal to the greater of $0.35 per Mcf
or 16% of the gross sales price for each Mcf transported through the gathering
system of Atlas Pipeline Partners. If a partnership pays a lesser amount, which
is anticipated by the managing general partner to range from $.29 per Mcf to
$.35 per Mcf except in the McKean County area as described in "Compensation -
Gathering Fees," then Atlas America, Resource Energy or Viking Resources must
pay the difference to Atlas Pipeline Partners. Also, Atlas America, Resource
Energy and Viking Resources committed to adding 225 wells to the gathering
system over a period from January 1, 1999, until December 31, 2002, which
included any well drilled in a partnership sponsored by them, which has been
satisfied. The wells had to be drilled within 2,500 feet of the gathering system
and the partnership as the well owner had to construct up to 2,500 feet of small
diameter sales or flow lines from the wellhead to the gathering system. They
have agreed to assist Atlas Pipeline Partners in identifying existing gathering
systems for possible acquisition and 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.
Natural Gas Contracts. The managing general partner, Resource Energy and Atlas
Energy Group, Inc. have a natural gas supply agreement with First Energy
Solutions Corporation for a 10-year term which began on April 1, 1999. Subject
to certain exceptions, First Energy Solutions Corporation has a last right of
refusal to buy all of the natural gas produced and delivered by the managing
general partner and its affiliates, which includes the partnerships, at certain
delivery points with the facilities of:
o East Ohio Gas Company, National Fuel Gas Distribution, Columbia of
Ohio, and Peoples Natural Gas Company, which are local distribution
companies; and
o National Fuel Gas Supply, Columbia Gas Transmission Corporation,
Tennessee Gas Pipeline Company, and Texas Eastern Transmission
Company, which are interstate pipelines.
63
First Energy Solutions Corporation is the marketing affiliate of First Energy
Corporation, which is a large regional electric utility listed on the New York
Stock Exchange. First Energy Corporation has provided a guaranty of the monetary
obligations of First Energy Solutions Corporation of an amount up to $10 million
for a period until December 31, 2003, which will continue on a monthly basis
thereafter unless terminated on 30 days notice.
The majority of the managing general partner's and its affiliates' natural gas
is subject to the agreement with First Energy Solutions Corporation, with the
following exceptions:
o natural gas being sold to Warren Consolidated, an industrial end-user,
and direct delivery customer of the managing general partner and its
affiliates;
o natural gas that at the time of the agreement was already dedicated
for the life of the well to another buyer;
o natural gas that is produced by a company which was not an affiliate
of the managing general partner at the time of the agreement;
o natural gas that is delivered to interstate pipelines or local
distribution companies other than those described above; or
o natural gas that is produced from well(s) operated by a third-party or
subject to an agreement under which a third-party was to arrange for
the gathering and sale of the natural gas.
The agreement established an indexed price formula for each of the delivery
points during an initial period of one or two years, and requires the parties to
negotiate a new pricing arrangement at each delivery point for subsequent
periods. If, at the end of any applicable period, the parties cannot agree to a
new price for any delivery point, then the managing general partner and its
affiliates may solicit offers from third-parties to buy the natural gas for that
delivery point. If First Energy Solutions Corporation does not match this price,
then the natural gas may be sold to the third-party. This process is repeated at
the end of each contract period which is usually one year. For example, during
the period April 1, 2000 through March 31, 2001, the managing general partner
and its affiliates sold natural gas delivered to National Fuel Gas Supply to
other entities under this process. The managing general partner anticipates that
the majority of the natural gas produced by each partnership from wells drilled
in the primary and secondary areas will be sold to First Energy Solutions
Corporation as described above in "-Primary Areas of Operations" and "-Secondary
Areas of Operations." For the period from April 1, 2003 through March 31, 2004,
the managing general partner and First Energy Solutions Corporation have been
able to agree to new pricing arrangements for approximately 75% of the delivery
points, which are described above, under their agreement. The remainder of the
natural gas, which is primarily located in the Fayette County area, will be
marketed primarily to Colonial Energy, Inc. and UGI Energy Services, and
possibly others, for the period ending March 31, 2004.
The pricing arrangement with First Energy Solutions Corporation and the other
third-parties are tied to the New York Mercantile Exchange Commission ("NYMEX")
monthly futures contract, which is reported daily in the Wall Street Journal.
The total price received for each partnership's gas is a combination of the
monthly NYMEX futures price plus a fixed basis. For example, the NYMEX futures
price is the base price and there is an additional premium paid because of the
location of the gas (the Appalachian Basin) in relation to the gas market which
is referred to as the basis. See " - Policy of Treating All Wells Equally in a
Geographic Area" for the average natural gas prices since 1998.
The agreement with First Energy Solutions Corporation 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
Solutions Corporation's agreements to sell natural gas to them. If these
factories were closed, however, the managing general partner believes that First
Energy Solutions Corporation would be able to find alternative purchasers and
would not invoke the force majeure.
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The marketing of natural gas production has been influenced by the availability
of financial instruments that may be used to hedge the price that will
ultimately be paid for future deliveries of natural gas. The managing general
partner purchases and sells natural gas futures and options contracts to limit
its and its partnerships' exposure to changes in natural gas prices. These
contracts may include regulated NYMEX futures and options contracts and
non-regulated over-the-counter futures contracts with qualified counterparties.
The futures contracts employed by the managing general partner are commitments
to purchase or sell natural gas at future dates and generally cover one-month
periods for up to 24 months in the future. To assure that the financial
instruments will be used solely for hedging price risks and not for speculative
purposes, the managing general partner has established a committee to assure
that all financial trading is done in compliance with the managing general
partner's hedging policies and procedures. The managing general partner does not
intend to contract for positions that it cannot offset with actual production.
Although hedging provides the partnerships some protection against falling
prices, these activities could also reduce the potential benefits of price
increases, depending on the instrument.
First Energy Solutions Corporation and the third-party marketers, such as
Colonial Energy, Inc. and UGI Energy Services, also use NYMEX based financial
instruments to hedge their pricing exposure and make price hedging opportunities
available to the managing general partner. These transactions are similar to
NYMEX based futures contracts, swaps and options, but also require firm delivery
of the hedged quantity. Thus, the managing general partner limits these
arrangements to much smaller quantities than those projected to be available at
any delivery point. The price paid by First Energy Solutions Corporation,
Colonial Energy, Inc., UGI Energy Services, and any other third-party marketers
for certain volumes of natural gas sold under these hedge agreements may be
significantly different from the underlying monthly spot market value.
The portion of natural gas that is hedged and the manner in which it is hedged
(e.g. fixed pricing, floor pricing, etc.) changes from time to time. As of
January 31, 2003, the managing general partner's overall price hedging position
the 12 months ending December 31, 2003 was approximately as follows:
o 37.9% was hedged with a fixed price;
o 2.2% was hedged with a floor price; and
o 59.9% was not hedged.
It is difficult to project what portion of these hedges will be allocated to
each partnership by the managing general partner because of uncertainty about
the quantity, timing, and delivery locations of natural gas that may be produced
by a partnership.
Marketing of Natural Gas Production from Wells in Other Areas of the United
States. The managing general partner expects that natural gas produced from
wells drilled in areas of the Appalachian Basin other than described above, will
be primarily tied to the spot market price and supplied to:
o gas marketers;
o local distribution companies;
o industrial or other end-users; and/or
o companies generating electricity.
Crude Oil. Crude oil produced from the wells will flow directly into storage
tanks where it will be picked up by the oil company, a common carrier, or
pipeline companies acting for the oil company which is purchasing the crude oil.
Unlike natural gas, crude oil does not present any transportation problem. The
managing general partner anticipates selling any oil produced by the wells to
regional oil refining companies at the prevailing spot market price for
Appalachian crude oil in spot sales. The managing general partner was receiving
an average selling price for oil of approximately:
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o $13.00 per barrel in 1998;
o $16.20 per barrel in 1999;
o $26.21 per barrel in 2000;
o $22.60 per barrel in 2001; and
o $18.92 per barrel in 2002.
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 partnerships.
Insurance
Since 1972 the managing general partner and its affiliates, including its
partnerships, have been involved in the drilling of approximately 4,975 wells in
Ohio, Pennsylvania, and other areas of the Appalachian Basin. They have not
incurred a blow-out or made any material insurance claims with any of these
wells. See "Actions to be Taken by Managing General Partner to Reduce Risks of
Additional Payments by Investor General Partners - Insurance" for a discussion
of the insurance coverage.
Use of Consultants and Subcontractors
The partnership agreement authorizes the managing general partner to use the
services of independent outside consultants and subcontractors on behalf of the
partnerships. The services will normally be paid on a per diem or other cash fee
basis and will be charged to the partnership on whose behalf the costs were
incurred as either a direct cost or as a direct expense under the drilling and
operating agreement. These charges will be in addition to the unaccountable,
fixed payment reimbursement paid to the managing general partner for
administrative costs and well supervision fees paid to the managing general
partner as operator.
COMPETITION, MARKETS AND REGULATION
Natural Gas Regulation
Governmental agencies regulate the production and transportation of natural gas.
Generally, the regulatory agency in the state where a producing natural gas well
is located supervises production activities and the transportation of natural
gas sold into intrastate markets, and the Federal Energy Regulatory Commission
("FERC") regulates the interstate transportation of natural gas.
Natural gas prices are not regulated, and the price of natural gas is subject to
the supply and demand for the natural gas along with factors such as the natural
gas' BTU content and where the wells are located. See "- Competition and
Markets" below for certain measures which FERC has taken to increase
competitiveness in the natural gas markets.
Crude Oil Regulation
Oil prices are not regulated, and the price is subject to the supply and demand
for oil, along with qualitative factors such as the gravity of the crude oil and
sulfur content differentials.
Competition and Markets
There are many companies engaged in natural gas and oil drilling operations in
the Appalachian Basin, where all of the wells in each partnership will be
located. According to the Energy Information Administration, the independent
statistical and analytical agency within the Department of Energy, the
Appalachian Basin accounted for 3.5% of the total domestic natural gas
production in the year 2000 in the United States, and as of December 31, 2000 it
holds economically recoverable reserves representing approximately 4.5% of total
domestic reserves.
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The oil and gas industry is highly competitive in all phases, including
acquiring suitable properties for drilling and marketing natural gas and oil.
Product availability and price are the principal means of competing in selling
natural gas and oil. Many of the partnerships' competitors will have financial
resources and staffs larger than those available to the partnerships. While it
is impossible to accurately determine the partnerships' industry position, the
managing general partner does not consider the partnerships' operations to be a
significant factor in the industry.
Current economic conditions indicate that the costs of exploration and
development are increasing gradually. However, the natural gas and oil industry
has from time to time experienced periods of rapid cost increases. Over the term
of a partnership there may be fluctuating or increasing costs in doing business
which directly affect the managing general partner's ability to operate the
partnership's wells at acceptable price levels. Also, the natural gas price
increases which occurred at the end of 2002 and the beginning of 2003 may
increase the demand for drilling rigs and other related equipment. This may
increase the cost to drill the wells or reduce the availability of drilling rigs
and related equipment, both of which could adversely affect the partnerships.
The natural gas and oil produced by your partnership's wells must be marketed
for you to receive revenues. As set forth above, natural gas and oil prices are
not regulated, but instead are subject to factors which are primarily beyond the
partnership's control such as the supply and demand for the natural gas and oil.
For example, reduced natural gas demand and/or excess natural gas supplies will
result in lower prices, and in recent years natural gas and oil prices have been
volatile. Other factors affecting the marketing of natural gas and oil
production, which are also beyond the control of the partnerships and cannot be
accurately predicted, are the following:
o the proximity, availability, and capacity of pipeline and other
transportation facilities;
o competition from other energy sources such as coal and nuclear energy;
o local, state, and federal regulations regarding production and
transportation;
o the general level of market demand on a regional, national and
worldwide basis;
o fluctuating seasonal supply and demand because of various factors such
as home heating requirements in the winter months;
o political instability and/or war in natural gas and oil producing
countries;
o the amount of domestic production; and
o the amount of foreign imports of natural gas and oil.
For example, increased imports into the United States of Canadian natural gas
have occurred and are expected to continue which will increase the supply of
natural gas in the United States. This increase in natural gas imports was
primarily the result of the North American Free Trade Agreement ("NAFTA"), which
eliminated trade and investment barriers in the United States, Canada, and
Mexico, and new pipeline projects that have been constructed and/or proposed to
the FERC. Without a corresponding increase in demand in the United States, the
imported natural gas would have an adverse effect on both the price and volume
of natural gas sales from the partnerships' wells. However, according to the
Energy Information Administration, the use of natural gas in the United States
is projected to increase approximately 51% to 69% between 1999 and 2020. Also,
members of the Organization of Petroleum Exporting Countries ("OPEC") establish
production quotas for petroleum products from time to time with the intent of
increasing, maintaining, or decreasing price levels. The managing general
partner, however, is unable to predict what effect these actions will have on
the price of the natural gas and oil sold from the partnerships' wells.
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FERC has sought to promote greater competition in natural gas markets in the
U.S. Traditionally, natural gas was sold by producers to interstate pipeline
companies that resold the natural gas to local distribution companies for resale
to end-users. FERC changed this market structure by requiring interstate
pipeline companies to transport natural gas for third-parties. Thereafter, FERC
Order 636 was issued which 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 natural
gas producers or suppliers. The premise behind FERC Order 636 was that the
interstate pipeline companies had an unfair advantage over other natural gas
producers or suppliers because they could bundle their sales and transportation
services together. FERC Order 636 is designed to ensure that no natural gas
seller has a competitive advantage over another natural gas seller because it
also provides transportation services.
In February, 2000, FERC Order 637 was issued to provide further competitive
initiatives by removing price ceilings on short-term capacity release
transactions. It also enacted other regulatory policies that are intended to
increase the flexibility of interstate natural gas transportation. Further, FERC
has required pipeline companies to develop electronic bulletin boards to provide
standardized access to information concerning capacity and prices.
There have been several developments which the managing general partner believes
have the effect of increasing the demand for natural gas. For example, the Clean
Air Act Amendments of 1990 contain incentives for the future development of
"clean alternative fuel," which includes natural gas and liquefied petroleum gas
for "clean-fuel vehicles." Also, the accelerating deregulation of electricity
transmission has caused a convergence between the natural gas and electricity
industries. The electricity industry has increased its reliance on natural gas
because of increased competition in the electricity industry and the enforcement
of stringent environmental regulations. For example, to reduce urban smog the
Environmental Protection Agency has sought to enforce environmental regulations
which increase the cost of operating coal-fired power plants, which in December
2000 produced more than half of the U.S.'s electricity. The Department of Energy
has also denied financial incentives to utilities to build more nuclear power
plants and large scale hydroelectric projects. Together, these policies tend to
make natural gas the fuel of choice for electricity producers which have started
moving away from dirtier-burning fuels, such as coal and oil. The electricity
industry has started plans to bring new natural gas-fired power plants into
service, some of which are not designed to allow for switching to other fuels.
Natural gas was used to generate approximately 16% of the United States'
electricity in December 2000, and this demand is expected to increase through
the decade.
State Regulations
Oil and gas operations are regulated in Pennsylvania by the Department of
Environmental Resources. Pennsylvania and the other states where each
partnership's wells may be situated impose a comprehensive statutory and
regulatory scheme for natural gas and oil operations, which creates additional
financial and operational burdens. Among other things, these regulations
involve:
o new well permit and well registration requirements, procedures, and
fees;
o minimum well spacing requirements;
o restrictions on well locations and underground gas storage;
o certain well site restoration, groundwater protection, and safety
measures;
o landowner notification requirements;
o certain bonding or other security measures;
o various reporting requirements; and
o well plugging standards and procedures.
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These state regulatory agencies also have broad regulatory and enforcement
powers including those associated with pollution and environmental control laws,
which are discussed below.
Environmental Regulation
Each partnership's drilling and producing operations are subject to various
federal, state, and local laws covering the discharge of materials into the
environment, or otherwise relating to the protection of the environment. The
Environmental Protection Agency and state and local agencies will require the
partnerships to obtain permits and take other measures with respect to:
o the discharge of pollutants into navigable waters;
o disposal of wastewater; and
o air pollutant emissions.
If these requirements or permits are violated there can be substantial civil and
criminal penalties which will increase if there was willful negligence or
misconduct. Also, the partnerships have unlimited liability for cleanup costs
under various federal laws such as the Federal Clean Water Act, the Resource
Conservation and Recovery Act, and the Comprehensive Environmental Response,
Compensation and Liability Act of 1980 for oil and/or hazardous substance
contamination.
A partnership's liability can also extend to pollution costs that occurred on
the leases before they were acquired by the partnership. Although the managing
general partner will not transfer any lease to a partnership if it has actual
knowledge that there is an existing potential environmental liability on the
lease, there will not be an independent environmental audit of the leases before
they are transferred to a partnership. Thus, there is a risk that the leases
will have potential environmental liability even before drilling begins.
A partnership's required compliance with these environmental laws and
regulations may cause delays or increase the cost of the partnership's drilling
and producing activities. Because these laws and regulations are 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. Also, the managing general partner is unable to obtain insurance to
protect against many environmental claims.
Proposed Regulation
From time to time there are a number of proposals considered in Congress and in
the legislatures and agencies of various states that if enacted would
significantly and adversely affect the natural gas and oil industry and the
partnerships. The proposals involve, among other things:
o limiting the disposal of waste water from wells that could
substantially increase a partnership's operating costs and make the
partnership's wells uneconomical to produce; and
o changes in the tax laws as discussed in "Tax Aspects-Changes in the
Law."
However, it is impossible to accurately predict what proposals, if any, will be
enacted and their subsequent effect on a partnership's activities.
PARTICIPATION IN COSTS AND REVENUES
In General
The partnership agreement provides for the sharing of costs and revenues among
the managing general partner and you and the other investors. A tabular summary
of the following discussion appears below. Each partnership will be a separate
business entity from the other partnerships, and you will be a partner only in
the partnership in which you invest. You
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will have no interest in the business, assets, or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest.
Costs
1. Organization and Offering Costs. Organization and offering costs will be
charged 100% to the managing general partner. However, the managing general
partner will not receive any credit towards its required capital
contribution or its revenue share for any organization and offering costs
that it pays in excess of 15% of a partnership's investors' subscription
proceeds.
o Organization and offering costs generally means all costs of
organizing and selling the offering and includes the dealer-manager
fee, sales commissions, the .5% reimbursement for bona fide
accountable due diligence expenses, and the .5% accountable marketing
expense fee.
2. Lease Costs. Each partnership's leases will be contributed by the managing
general partner. The managing general partner will be credited with a
capital contribution for each lease valued at:
o its cost; or
o fair market value if the managing general partner has reason to
believe that cost is materially more than fair market value.
3. Intangible Drilling Costs. Intangible drilling costs of your partnership
will be charged 100% to you and the other investors.
o Intangible drilling costs generally means those costs of drilling and
completing a well that are currently deductible, as compared with
lease costs, which must be recovered through the depletion allowance,
and equipment costs, which must be recovered through depreciation
deductions.
Although subscription proceeds of a partnership may be used to pay the costs of
drilling different wells depending on when the subscriptions are received, not
less than 90% of the subscription proceeds of you and the other investors will
be used to pay intangible drilling costs regardless of when you subscribe. Also,
even if the IRS successfully challenged the managing general partner's
characterization of a portion of these costs as deductible intangible drilling
costs, and instead recharacterized the costs as some other item that may be
non-deductible, such as equipment costs and/or lease costs, this
recharacterization by the IRS would have no effect on the allocation and payment
of the costs by you and the other investors under the partnership agreement.
4. Equipment Costs. Equipment costs of your partnership will be charged 66% to
the managing general partner and 34% to you and the other investors.
However, if the total equipment costs for your partnership's wells that
would be charged to you and the other investors exceeds an amount equal to
10% of the subscription proceeds of you and the other investors in the
partnership, then the excess will be charged to the managing general
partner.
o Equipment costs generally means the costs of drilling and completing a
well that are not currently deductible and are not lease costs.
5. Operating Costs, Direct Costs, Administrative Costs and All Other Costs.
Operating costs, direct costs, administrative costs, and all other
partnership costs of your partnership not specifically charged will be
charged to the parties in the same ratio as the related production revenues
are being credited.
o These costs generally include all costs of partnership administration
and producing and maintaining the partnership's wells.
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6. The Managing General Partner's Required Capital Contribution. The managing
general partner's aggregate capital contributions to each partnership must
not be less than 25% of all capital contributions to that partnership. This
includes such items as:
o its credit for the cost of the leases contributed;
o its administrative overhead reimbursement; and
o its profit on the equipment costs paid by it to itself under the
drilling and operating agreement.
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 the end
of the year in which the partnership had its final closing.
Revenues
Each partnership's production revenues from all of its wells will be commingled.
Thus, regardless of when you subscribe to a partnership you will share in the
production revenues from all wells in that partnership on the same basis as the
other investors in the partnership in proportion to your number of units.
1. Proceeds from the Sale of Leases. If a partnership well is sold, a portion
of the sales proceeds will be allocated to the partners in the same
proportion as their share of the adjusted tax basis of the property. In
addition, proceeds will be allocated to the managing general partner to the
extent of the pre-contribution appreciation in value of the property, if
any. Any excess will be credited as provided in 4, below.
2. Interest Proceeds. Interest income will be shared as follows:
o interest earned on your subscription proceeds before the close of your
offering will be credited to your account and paid not later than the
partnership's first cash distributions from operations;
o after closing of your partnership and until the subscription proceeds
from the closing are invested in your partnership's operations any
interest income from temporary investments will be allocated pro rata
to you and the other investors providing the subscription; and
o all other interest income, including interest earned on the deposit of
production revenues, will be credited as provided in 4, below.
3. Equipment Proceeds. Proceeds from the sale or other disposition of
equipment will be credited to the parties charged with the costs of the
equipment in the ratio in which the costs were charged.
4. Production Revenues. Subject to the managing general partner's
subordination obligation as described below, the managing general partner
and the investors in a partnership will share in all of that
partnership's other revenues, including production revenues, in the same
percentage as their respective capital contribution bears to the total
partnership capital contributions, except that the managing general
partner will receive an additional 7% of that partnership's revenues.
However, the managing general partner's total revenue share may not
exceed 35% of that partnership revenues regardless of the amount of its
capital contributions. For example, if the managing general partner
contributes the minimum of 25% of the total partnership capital
contributions and the investors contribute 75% of the total partnership
capital contributions, then the managing general partner will receive 32%
of the partnership revenues and the investors will receive 68% of the
partnership revenues. On the other hand, if the managing general partner
contributes 30% of the total partnership capital contributions and the
investors contribute 70% of the total partnership capital contributions,
then the managing general partner will receive 35% of the partnership
revenues, not 37%, because its revenue share cannot exceed 35% of
partnership revenues, and the investors will receive 65% of partnership
revenues.
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Subordination of Portion of Managing General Partner's Net Revenue Share
Each partnership is structured to provide you and the other investors with cash
distributions equal to a minimum of 10% per unit, based on $10,000 per unit
regardless of the actual subscription price for your units, in each of the first
five 12-month periods beginning with that partnership's first cash distributions
from operations. To help achieve this investment feature, the managing general
partner will subordinate up to 50% of its share of the managing general
partner's share of partnership net production revenues during this subordination
period.
o Partnership net production revenues means gross revenues after
deduction of the related operating costs, direct costs, administrative
costs, and all other costs not specifically allocated.
Each partnership's 60-month subordination period will begin with that
partnership's first cash distribution from operations to you and the other
investors. However, no subordination distributions to you and the other
investors will be required until that partnership's first cash distribution
after substantially all of the partnership wells are drilled, completed, and
begin producing into a sales line. Subordination distributions will be
determined by debiting or crediting current period partnership revenues to the
managing general partner as may be necessary to provide the distributions to you
and the other investors. At any time during the subordination period the
managing general partner is entitled to an additional share of partnership
revenues to recoup previous subordination distributions to the extent your cash
distributions from that partnership exceed the 10% return described above. 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 natural gas and oil received by the partnership and/or the
results of the partnership's drilling activities are unable to provide the
required return. However, if the wells produce small natural gas and oil volumes
or natural gas and oil prices decrease, then even with subordination your cash
flow may be very small and you may not receive the 10% return for each of the
first five years beginning with the partnership's first cash distribution from
operations.
As of May 15, 2003, the managing general partner was subordinating a portion or
all of its net revenues in 3 of its previous 12 limited partnerships that
currently have the subordination feature in effect. Since 1993 the managing
general partner has had a subordination feature in 22 of its partnerships and
from time to time it has subordinated its partnership net revenues in 16 of
these partnerships. The managing general partner is entitled to recoup these
subordination distributions during the subordination period to the extent cash
distributions to the investors in these previous partnerships would exceed the
specified return to the investors.
Example of Revenue Sharing During a Subordination Period.
Revenues to Managing
Maximum Amount of General Partner and
Managing General Investors if Maximum
Percentage of Percentage of Partner's Share of Amount of Managing
Partnership Partnership Partnership Revenues General Partner's Share
Capital Revenues Without Available for of Partnership Revenues
Entity Contributions (1) Subordination (1) Subordination (2) is Subordinated (1)(2)
- -------- ------------------ ------------------ --------------------- ------------------------
Managing General Partner ......... 25% 32% 16% 16%
Investors ........................ 75% 68% 84%
- ---------------
(1) These percentages are for illustration purposes only and assume the managing
general partner's minimum required capital contribution of 25% to each
partnership and capital contributions of 75% from you and the other
investors. The actual percentages are likely to be different because they
will be based on the actual capital contributions of the managing general
partner and you and the other investors. However, the managing general
partner's total revenue share may not exceed 35% of partnership revenues
regardless of the amount of its capital contribution.
(2) Each partnership is structured to provide you and the other investors with
cash distributions equal to a minimum of 10% per unit, based on $10,000 per
unit regardless of the actual subscription price for your units, in each of
the first five 12-month periods beginning with the partnership's first cash
distributions from operations. To help achieve this
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investment feature, the managing general partner will subordinate up to
50% of its share of partnership net production revenues during this
subordination period.
Example of Revenue Sharing After the End of a Subordination Period.
Revenues to Managing
Maximum Amount of General Partner and
Managing General Investors if Maximum
Percentage of Percentage of Partner's Share of Amount of Managing
Partnership Partnership Partnership Revenues General Partner's Share
Capital Revenues Without Available for of Partnership Revenues
Entity Contributions (1) Subordination (1) Subordination is Subordinated (1)
- -------- ------------------ ------------------ --------------------- ------------------------
Managing General Partner ......... 25% 32% 0% 32%
Investors ........................ 75% 68% 68%
- ---------------
(1) These percentages are for illustration purposes only and assume the managing
general partner's minimum required capital contribution of 25% to each
partnership and capital contributions of 75% from you and the other
investors. The actual percentages are likely to be different because they
will be based on the actual capital contributions of the managing general
partner and you and the other investors. However, the managing general
partner's total revenue share may not exceed 35% of partnership revenues
regardless of the amount of its capital contribution.
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 in
each partnership after deducting from the partnership's gross revenues the
landowner royalties and any other lease burdens.
Managing
General
Partner Investors
------------- -------------
Partnership Costs
Organization and offering costs.............. 100% 0%
Lease costs.................................. 100% 0%
Intangible drilling costs.................... 0% 100%
Equipment costs (1).......................... 66% 34%
Operating costs, administrative costs,
direct costs, and all other costs.......... (2) (2)
Partnership Revenues
Interest income.............................. (3) (3)
Equipment proceeds (1)....................... 66% 34%
All other revenues including production
revenues................................... (4)(5) (4)(5)
Participation in Deductions
Intangible drilling costs.................... 0% 100%
Depreciation (1)............................. 66% 34%
Percentage depletion allowance............... (4)(5)(6) (4)(5)(6)
- ---------------
(1) These percentages may vary. If the total equipment costs for all of the
partnership's wells that would be charged to you and the other investors
exceeds an amount equal to 10% of the subscription proceeds of you and the
other investors in the partnership, then the excess will be charged to the
managing general partner.
(2) These costs will be charged to the parties in the same ratio as the related
production revenues are being credited.
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(3) Interest earned on your subscription proceeds before the offering of a
partnership closes will be credited to your account and paid not later than
the partnership's first cash distributions from operations. After the
offering closes and until proceeds from the offering are invested in the
partnership's operations any interest income from temporary investments will
be allocated pro rata to the investors providing the subscription proceeds.
All other interest income in the partnership, including interest earned on
the deposit of operating revenues, will be credited as production revenues
are credited.
(4) In each partnership the managing general partner and the investors will
share in all of the partnership's other revenues in the same percentage as
their respective capital contributions bears to the total partnership
capital contributions except that the managing general partner will receive
an additional 7% of the partnership revenues. However, the managing general
partner's total revenue share in a partnership may not exceed 35% of
partnership revenues.
(5) If a portion of the managing general partner's partnership net production
revenues is subordinated, then the actual allocation of partnership revenues
between the managing general partner and the investors will vary from the
allocation described in (4) above.
(6) The percentage depletion allowances will be in the same percentages as the
production revenues.
Allocation and Adjustment Among Investors
The investors' share as a group of each partnership's revenues, gains, income,
costs, expenses, losses, and other charges and liabilities generally will be
charged and credited among you and the other investors in that partnership in
accordance with your respective number of units, based on $10,000 per unit
regardless of the actual subscription price for an investor's units. These
allocations will take into account any investor general partner's status as a
defaulting investor general partner. Certain investors, however, will pay a
reduced amount for their units as described in "Plan of Distribution." Thus, the
following costs will be charged among you and the other investors in each
partnership in accordance with your respective subscription price for your units
rather than the number of your units:
o intangible drilling costs; and
o the investors' share of the equipment costs of drilling and completing
the partnership's wells.
Distributions
The managing general partner will review each partnership's accounts at least
quarterly to determine whether cash distributions are appropriate and the amount
to be distributed, if any, taking into account its subordination obligation
discussed above in "-Subordination of Portion of Managing General Partner's Net
Revenue Share." Your partnership will distribute funds to you and the other
investors that the managing general partner, in its sole discretion, does not
believe are necessary for the partnership to retain. Distributions may be
reduced or deferred to the extent partnership revenues are used for any of the
following:
o repayment of borrowings;
o cost overruns;
o remedial work to improve a well's producing capability;
o direct costs and general and administrative expenses of the
partnership;
o reserves, including a reserve for the estimated costs of eventually
plugging and abandoning the wells; or
o indemnification of the managing general partner and its affiliates by
the partnership for losses or liabilities incurred in connection with
the partnership's activities.
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Also, funds will not be advanced or borrowed for distributions if the
distribution amount would exceed the partnership's accrued and received revenues
for the previous four quarters, less paid and accrued operating costs with
respect to the revenues. Any cash distributions from a partnership to the
managing general partner will only be made in conjunction with distributions to
you and the other investors in that partnership and only out of funds properly
allocated to the managing general partner's account.
Liquidation
Each partnership will continue for 50 years unless it is terminated earlier by a
final terminating event as described below, or an event which causes the
dissolution of a limited partnership under the Delaware Revised Uniform Limited
Partnership Act. However, if a partnership terminates on an event which causes a
dissolution under state law and it is not a final terminating event, then a
successor limited partnership will automatically be formed. Thus, only on a
final terminating event will a partnership be liquidated. A final terminating
event is any of the following:
o the election to terminate the partnership by the managing general
partner or the affirmative vote of investors whose units equal a
majority of the total units;
o the termination of the partnership under Section 708(b)(1)(A) of the
Internal Revenue Code because no part of its business is being carried
on; or
o the partnership ceases to be a going concern.
On the partnership's liquidation you will receive your interest in the
partnership to which you subscribed. Generally, your interest in the partnership
means an undivided interest in the partnership assets, after payments to the
partnership's creditors, in the ratio your capital account bears to all the
capital accounts until they have been reduced to zero. Thereafter, your interest
in the remaining partnership assets will equal your interest in the related
partnership revenues.
Any in-kind property distributions to you from a partnership must be made to a
liquidating trust or similar entity, unless you affirmatively consent to receive
an in-kind property distribution after being told of the risks associated with
the direct ownership or there are alternative arrangements in place which assure
that you will not be responsible for the operation or disposition of the
partnership properties. If the managing general partner has not received your
written consent to the in-kind distribution within 30 days after it is mailed,
then it will be presumed that you have not consented. The managing general
partner may then sell the asset at the best price reasonably obtainable from an
independent third-party, or to itself or its affiliates at fair market value as
determined by an independent expert selected by the managing general partner.
Also, if a partnership is liquidated, the managing general partner will be
repaid for any debts owed it by the partnership before there are any payments to
you and the other investors in that partnership.
CONFLICTS OF INTEREST
In General
Conflicts of interest are inherent in natural gas and oil partnerships involving
non-industry investors because the transactions are entered into without arms'
length negotiation. Your interests and those of the managing general partner and
its affiliates may be inconsistent in some respects or in certain instances, and
the managing general partner's actions may not be the most advantageous to you.
The following discussion describes certain possible conflicts of interest that
may arise for the managing general partner and its affiliates in the course of
each partnership. For some of the conflicts of interest, but not all, there are
certain limitations on the managing general partner that are designed to reduce,
but which will not eliminate, the conflicts. Other than these limitations the
managing general partner has no procedures to resolve a conflict of interest and
under the terms of the partnership agreement the managing general partner may
resolve the conflict of interest in its sole discretion and best interest.
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The following discussion is materially complete; however, other transactions or
dealings may arise in the future that could result in conflicts of interest for
the managing general partner and its affiliates.
Conflicts Regarding Transactions with the Managing General Partner and its
Affiliates
Although the managing general partner believes that the compensation and
reimbursement that it and its affiliates will receive in connection with each
partnership are reasonable, the compensation has been determined solely by the
managing general partner and did not result from negotiations with any
unaffiliated third-party dealing at arms' length. The managing general partner
and its affiliates will receive compensation and reimbursement from each
partnership for their services in drilling, completing, and operating the
partnership's wells under the drilling and operating agreement and will receive
the other fees described in "Compensation" regardless of the success of the
partnership's wells. The managing general partner and its affiliates providing
the services or equipment can be expected to profit from the transactions, and
it is usually in the managing general partner's best interest to enter into
contracts with itself and its affiliates rather than unaffiliated third-parties
even if the contract terms, skill, and experience, offered by the unaffiliated
third-parties is comparable.
The partnership agreement provides that when the managing general partner and
any affiliate provide services or equipment to a partnership their fees must be
competitive with the fees charged by unaffiliated third-parties in the same
geographic area engaged in similar businesses. Also, before the managing general
partner and any affiliate may receive competitive fees for providing services or
equipment to a partnership they must be engaged, independently of the
partnership and as an ordinary and ongoing business, in rendering the services
or selling or leasing the equipment and supplies to a substantial extent to
other persons in the natural gas and oil industry in addition to the
partnerships in which the managing general partner or an affiliate has an
interest. If the managing general partner and any affiliate is not engaged in
such a business, then the compensation must be the lesser of its cost or the
competitive rate that could be obtained in the area.
Any services not otherwise described in this prospectus or the partnership
agreement for which the managing general partner or an affiliate is to be
compensated by a partnership must be:
o set forth in a written contract that describes the services to be
rendered and the compensation to be paid; and
o cancelable without penalty on 60 days written notice by investors
whose units equal a majority of the total units.
The compensation, if any, will be reported to you in your partnership's annual
and semiannual reports, and a copy of the contract will be provided to you on
request.
There is also a conflict of interest concerning the purchase price if the
managing general partner or an affiliate purchases a property from a
partnership, which they may do in certain limited circumstances as described in
"- Conflicts Involving the Acquisition of Leases - (6) Limitations on Sale of
Undeveloped and Developed Leases to the Managing General Partner," below.
Conflict Regarding the Drilling and Operating Agreement
The managing general partner anticipates that all of the wells drilled by each
partnership will be drilled and operated under the drilling and operating
agreement. This creates a continuing conflict of interest because the managing
general partner must monitor and enforce, on behalf of each partnership, its own
compliance with the drilling and operating agreement.
Conflicts Regarding Sharing of Costs and Revenues
The managing general partner will receive a percentage of revenues greater than
the percentage of costs that it pays. This sharing arrangement may create a
conflict of interest between the managing general partner and you and the other
investors in a partnership concerning the determination of which wells will be
drilled by the partnership based on the risk and profit potential associated
with the wells.
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In addition, the allocation of all the intangible drilling costs to you and the
other investors and the majority of the equipment costs to the managing general
partner creates a conflict of interest between the managing general partner and
you and the other investors concerning whether to complete a well. For example,
the completion of a marginally productive well might prove beneficial to you and
the other investors, but not to the managing general partner. When a completion
decision is made you and the other investors will have already paid the majority
of your costs so you will want to pay your share of the additional costs to
complete the well only if there is a reasonable opportunity to recoup your
completion costs plus any portion of the costs paid by you before the completion
attempt. However, if it appears likely that you would not recoup all of the
additional costs to complete the well, you will want to plug the well. On the
other hand, the managing general partner will have paid only a portion of its
costs before this time, and it will want to pay its additional equipment costs
to complete the well only if it is reasonably certain of recouping its money and
making a profit. However, based on its past experience the managing general
partner anticipates that most of the wells in the primary areas will have to be
completed before it can determine the well's productivity, which would eliminate
this potential conflict of interest. In any event, the managing general partner
will not cause any well to be plugged and abandoned without a completion attempt
unless it makes the decision in accordance with generally accepted oil and gas
field practices in the geographic area of the well location.
Conflicts Regarding Tax Matters Partner
The managing general partner will serve as each partnership's tax matters
partner and represent the partnership before the IRS. The managing general
partner will have broad authority to act on behalf of you and the other
investors in the partnership in any administrative or judicial proceeding
involving the IRS, and this authority may involve conflicts of interest. For
example, potential conflicts include:
o whether or not to expend partnership funds to contest a proposed
adjustment by the IRS, if any, to:
o the amount of a partnership's deduction for intangible drilling
costs, which is allocated 100% to you and the other investors in
the partnership; or
o the amount of the managing general partner's depreciation
deductions, or the credit to its capital account for contributing
the leases to a partnership, which would decrease the managing
general partner's liquidation interest in the partnership; or
o the amount of the managing general partner's reimbursement from a
partnership for expenses incurred by it in its role as the tax matters
partner.
Conflicts Regarding Other Activities of the Managing General Partner, the
Operator and Their Affiliates
The managing general partner will be required to devote to each partnership the
time and attention that it considers necessary for the proper management of the
partnership's activities. However, the managing general partner has sponsored
and continues to manage other natural gas and oil drilling partnerships, which
may be concurrent, and will engage in unrelated business activities, either for
its own account or on behalf of other partnerships, joint ventures,
corporations, or other entities in which it has an interest. This creates a
continuing conflict of interest in allocating management time, services, and
other activities between the partnerships of the program and its other
activities. The managing general partner will determine the allocation of its
management time, services, and other functions on an as-needed basis consistent
with its fiduciary duties among the partnerships of the program and its other
activities.
Subject to its fiduciary duties, the managing general partner will not be
restricted from participating in other businesses or activities, even if these
other businesses or activities compete with a partnership's activities and
operate in the same areas as the partnership. However, the managing general
partner and its affiliates may pursue business opportunities that are consistent
with the partnership's investment objectives for their own account only after
they have determined that the opportunity either:
o cannot be pursued by the partnership because of insufficient funds; or
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o it is not appropriate for the partnership under the existing
circumstances.
Conflicts Involving the Acquisition of Leases
The managing general partner will select, in its sole discretion, the wells to
be drilled by each partnership. Conflicts of interest may arise concerning which
wells will be drilled by each partnership in the program and which wells will be
drilled by the managing general partner's and its affiliates' other affiliated
partnerships or third-party programs in which they serve as driller/operator. It
may be in the managing general partner's or its affiliates' advantage to have a
partnership bear the costs and risks of drilling a particular well rather than
another affiliate. These potential conflicts of interest will be increased if
the managing general partner organizes and allocates wells to more than one
partnership at a time. To lessen this conflict of interest the managing general
partner generally takes a similar interest in other partnerships when it serves
as managing general partner and/or driller/operator.
The managing general partner anticipates that generally only one partnership
will be actively engaged in drilling at any time. However, when the managing
general partner must provide prospects to two or more partnerships at the same
time it will attempt to treat each partnership fairly on a basis consistent
with:
o the funds available to the partnerships; and
o the time limitations on the investment of funds for the partnerships.
Generally, the managing general partner follows a policy of developing prospects
in the order of what it believes is the "best available prospect." However, the
managing general partner will constantly change its assessment based on the
acquisition of new leases and information derived from wells already drilled.
If more than one partnership in the program has funds available for drilling,
the partnerships will alternate drilling of wells based on the "best available
prospect" format. The determination of the "best available prospect" is based on
the managing general partner's assessment of the economic potential of a
prospect and its suitability to a particular partnership, and considers various
factors including:
o estimated reserves;
o the targeted geological formations;
o gas and oil markets;
o geological and gas and oil market diversification within the
partnership;
o the prospect's net revenue interest;
o estimated lease and drilling costs; and
o limitations imposed by the prospectus and/or partnership agreements.
The limited partnership agreement gives the managing general partner the
authority to cause each partnership to acquire undivided interests in natural
gas and oil properties, and to participate with other parties, including other
drilling programs previously or subsequently conducted by the managing general
partner or its affiliates, in the conduct of its drilling operations on those
properties. If conflicts between the interest of the partnership and other
drilling partnerships do arise, then the managing general partner may be unable
to resolve those conflicts to the maximum advantage of the partnership because
the managing general partner must deal fairly with the investors in all of its
drilling partnerships.
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In addition, subject to the restrictions set forth below, the managing general
partner decides which prospects and what interest to transfer to a partnership.
This will result in a subsequent partnership sponsored by the managing general
partner acquiring a prospect adjacent to a prior partnership's prospect. The
subsequent partnership could gain an advantage over the prior partnership
because of the knowledge gained through the prior partnership's experience in
the area.
No procedures, other than the guidelines set forth below and in " - Procedures
to Reduce Conflicts of Interest," have been established by the managing general
partner to resolve any conflicts that may arise. The partnership agreement
provides that the managing general partner and its affiliates will abide by the
guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and
(9) there is an exception in the partnership agreement for another program in
which the interest of the managing general partner is substantially similar to
or less than its interest in the partnerships.
(1) Transfers at Cost. All leases will be acquired from the managing general
partner and credited towards its required capital contribution at the cost
of the lease, unless the managing general partner has a reason to believe
that cost is materially more than the fair market value of the property. If
the managing general partner believes cost is materially more than fair
market value, then the managing general partner's credit for the
contribution must be at a price not in excess of the fair market value.
o A determination of fair market value must be supported by an
appraisal from an independent expert and 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 a 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.
o The term "prospect" generally means an area which is believed to
contain commercially productive quantities of natural gas or oil.
However, a prospect will be limited to the drilling or spacing unit on
which one well will be drilled if the following two conditions are met:
o the well is being drilled to a geological feature which contains
proved reserves as defined below; and
o the drilling or spacing unit protects against drainage.
The managing general partner believes that for a prospect located in Ohio,
Pennsylvania and New York on which a well will be drilled to test the
Clinton/Medina geologic formation or the Mississippian and/or Upper
Devonian Sandstone reservoirs, a prospect will consist of the drilling and
spacing unit because it will meet the test in the preceding sentence.
o Proved reserves, generally, are the estimated quantities of
natural gas and oil which have been demonstrated to be
recoverable in future years with reasonable certainty under
existing economic and operating conditions. Proved reserves
include proved undeveloped reserves which generally are reserves
expected to be recovered from existing wells where a relatively
major expenditure is required for recompletion or from new wells
on undrilled acreage. Reserves on undrilled acreage will be
limited to those drilling units offsetting productive units that
are reasonably certain of production when drilled. Proved
Reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation.
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The managing general partner anticipates that the majority of the wells
drilled by each partnership will develop the Clinton/Medina geologic
formation or the Mississippian and/or 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 throughout the primary
areas where each partnership's wells will be situated. To lessen this
conflict of interest, for five years the managing general partner may not
drill any well:
o in the Clinton/Medina geologic formation within 1,650 feet of an
existing partnership well in Pennsylvania or within 1,000 feet of
an existing partnership well in Ohio; or
o in the Mississippian/Upper Devonian Sandstone reservoirs in
Fayette and Green Counties, Pennsylvania within 1,000 feet of an
existing partnership well.
If a 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 a partnership's
prospect is subsequently enlarged based on geological information, which is
later acquired, then there is the following special provision:
o if the prospect is enlarged to cover any area where the managing
general partner owns a separate property interest and the
partnership activities were material in establishing the
existence of proved undeveloped reserves which are attributable
to the separate property interest, then the separate property
interest or a portion thereof must be sold to the partnership in
accordance with (1), (2) and (4).
(4) Transfer of Less than the Managing General Partner's and its Affiliates'
Entire Interest. If the managing general partner sells or transfers to a
partnership less than all of its ownership in any prospect, then it must
comply with the following conditions:
o the retained interest must be a proportionate working interest;
o the managing general partner's obligations and the partnership's
obligations must be substantially the same after the sale of the
interest by the managing general partner or its affiliates; and
o the managing general partner's revenue interest must not exceed
the amount proportionate to its retained working interest.
For example, if the managing general partner transfers 50% of its working
interest in a prospect to a partnership and retains a 50% working interest,
then the partnership will not pay any of the costs associated with the
managing general partner's retained working interest as a part of the
transfer. This limitation does not prevent the managing general partner and
its affiliates from subsequently dealing with their retained working
interest as they may choose with unaffiliated parties or affiliated
partnerships. For example, the managing general partner may sell its
retained working interest to a third-party for a profit.
(5) Limitations on Activities of the Managing General Partner and its
Affiliates on Leases Acquired by a Partnership. For a five year period
after the final closing of a partnership, if the managing general partner
proposes to acquire an interest from an unaffiliated person in a prospect
in which the partnership owns an interest or in a prospect in which the
partnership's interest has been terminated without compensation within one
year before the proposed acquisition, then the following conditions apply:
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o if the managing general partner does not currently own property
in the prospect separately from the partnership, then the
managing general partner may not buy an interest in the prospect;
and
o if the managing general partner currently owns a proportionate
interest in the prospect separately from the partnership, then
the interest to be acquired must be divided in the same
proportion between the managing general partner and the
partnership as the other property in the prospect. However, if
the partnership does not have the cash or financing to buy the
additional interest, then the managing general partner is also
prohibited from buying the additional interest.
(6) Limitations on Sale of Undeveloped and Developed Leases to the Managing
General Partner. The managing general partner and its affiliates, other
than an affiliated partnership, may not purchase undeveloped leases or
receive a farmout from a partnership other than at the higher of cost or
fair market value. Farmouts to the managing general partner and its
affiliates also must be made as set forth in (9) below.
The managing general partner and its affiliates, other than an affiliated
income program, may not purchase any producing natural gas or oil property
from a partnership unless:
o the sale is in connection with the liquidation of the
partnership; or
o the managing general partner's well supervision fees under the
drilling and operating agreement for the well have exceeded the
net revenues of the well, determined without regard to the
managing general partner's well supervision fees for the well,
for a period of at least three consecutive months.
In both cases, the sale must be at fair market value supported by an
appraisal of an independent expert selected by the managing general
partner. The appraisal of the property must be maintained in the
partnership's records for at least six years.
(7) Transfer of Leases Between Affiliated Limited Partnerships. The transfer of
an undeveloped lease from a partnership to an affiliated drilling limited
partnership must be made as follows:
o at fair market value if the undeveloped lease has been held for
more than two years; or
o at cost if the managing general partner deems it to be in the
best interest of the partnership.
An affiliated income program may purchase a producing natural gas and oil
property from a partnership at any time at:
o fair market value as supported by an appraisal from an
independent expert if the property has been held by the
partnership for more than six months or there have been
significant expenditures made in connection with the property; or
o cost as adjusted for intervening operations if the managing
general partner deems it to be in the best interest of the
partnership.
However, these prohibitions do not apply to joint ventures or farmouts
among affiliated partnerships, provided that:
o the respective obligations and revenue sharing of all parties to
the transaction are substantially the same; and
o the compensation arrangement or any other interest or right of
either the managing general partner or its affiliates is the same
in each affiliated partnership or if different, the aggregate
compensation
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of the managing general partner or the affiliate is reduced to
reflect the lower compensation arrangement.
(8) Leases Will Be Acquired Only for Stated Purpose of the Partnership. Each
partnership must acquire only leases that are reasonably expected to meet
the stated purposes of the partnership. Also, no leases may be acquired for
the purpose of a subsequent sale, farmout or other disposition unless the
acquisition is made after a well has been drilled to a depth sufficient to
indicate that the acquisition would be in the partnership's best interest.
(9) Farmout. The managing general partner will not enter into a farmout to
avoid its paying its share of the costs related to drilling an undeveloped
lease. However, the managing general partner's decision with respect to
making a farmout and the terms of a farmout from a partnership involve
conflicts of interest since the managing general partner may benefit from
cost savings and reduction of risk.
The partnership may farmout an undeveloped lease or well activity to the
managing general partner, its affiliates or an unaffiliated third-party
only if the managing general partner, exercising the standard of a prudent
operator, determines that:
o the partnership lacks the funds to complete the oil and gas
operations on the lease or well and cannot obtain suitable
financing;
o drilling on the lease or the intended well activity would
concentrate excessive funds in one location, creating undue risks
to the partnership;
o the leases or well activity have been downgraded by events
occurring after assignment to the partnership so that development
of the leases or well activity would not be desirable; or
o the best interests of the partnership would be served.
If the partnership farmouts a lease or well activity, the managing general
partner must retain on behalf of the partnership the economic interests and
concessions as a reasonably prudent oil and gas operator would or could
retain under the circumstances prevailing at the time, consistent with
industry practices. However, if the farmout is made to the managing general
partner or its affiliates there is a conflict of interest since the
managing general partner will represent both the partnership and itself or
an affiliate.
Conflicts Between Investors and the Managing General Partner as an Investor
The managing general partner, its officers, directors, and affiliates may
subscribe for units in each partnership and the price of their units will be
reduced by 10.5%, which is equal to the dealer-manager fee, the sales
commission, the accountable marketing expense fee and the reimbursement of
accountable due diligence expenses for certain due diligence investigations
conducted by the selling agents which will be reallowed to the selling agents.
Even though they pay a reduced price for their units these investors generally
will:
o share in the partnership's costs, revenues, and distributions on the
same basis as the other investors as described in "Participation in
Costs and Revenues"; and
o have the same voting rights, except as discussed below.
Any subscription 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 as described in "Summary of Partnership
Agreement - Voting Rights."
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Lack of Independent Underwriter and Due Diligence Investigation
The terms of this offering, the partnership agreement, and the drilling and
operating agreement were determined by the managing general partner without
arms' length negotiations. You and the other investors have not been separately
represented by legal counsel, who might have negotiated more favorable terms for
you and the other investors in 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 partnerships and the managing
general partner that would be provided by independent underwriters. Although
Anthem Securities, which is affiliated with the managing general partner, serves
as dealer-manager and will receive reimbursement of 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
The managing general partner anticipates that its legal counsel will also serve
as legal counsel to each partnership and that this dual representation will
continue in the future. If a future dispute arises between the managing general
partner and you and the other investors in a partnership, then the managing
general partner will cause you and the other investors to retain separate
counsel. Also, if counsel advises the managing general partner that counsel
reasonably believes its representation of a partnership will be adversely
affected by its responsibilities to the managing general partner, then the
managing general partner will cause you and the other investors in a partnership
to retain separate counsel.
Conflicts Regarding Presentment Feature
You and the other investors in a partnership have the right to present your
units in the partnership to the managing general partner for purchase beginning
with the fifth calendar year after the end of the calendar year in which your
partnership closes. This creates the following conflicts of interest between you
and the managing general partner.
o The managing general partner may suspend the presentment feature if it
does not have the necessary cash flow or it cannot borrow funds for
this purpose on terms which it deems reasonable. Both of these
determinations are subjective and will be made in the managing general
partner's sole discretion.
o The managing general partner will also determine the purchase price
based on a reserve report that it prepares and is reviewed by an
independent expert that it chooses. The formula for arriving at the
purchase price has many subjective determinations that are within the
discretion of the managing general partner.
Conflicts Regarding Managing General Partner Withdrawing an Interest
A conflict of interest is created with you and the other investors by the
managing general partner's right to mortgage its interest or withdraw an
interest in each partnership's wells equal to or less than its revenue interest
to be used as collateral for a loan to the managing general partner. If there
was a default under the loan, this could reduce the amount of the managing
general partner's partnership net production revenues available for its
subordination obligation to you and the other investors.
Conflicts Regarding Order of Pipeline Construction and Gathering Fees
The managing general partner may choose well locations along the Atlas Pipeline
Partners gathering system which would benefit its parent company by providing
more gathering fees to Atlas Pipeline Partners, even if there are other well
locations available in the area or other areas which offer the partnerships a
greater potential return. However, the managing general partner believes this
conflict of interest is substantially reduced because the managing general
partner expects to make the largest single capital contribution in each
partnership as explained in "Capitalization and Source of Funds and Use of
Proceeds." Thus, it is in the best interest of its parent company for the
managing general partner to choose prospects for a partnership to drill which
have the greatest potential reserves even if they are not connected to the Atlas
Pipeline Partners gathering system. In addition, Atlas America or an affiliate
will operate the gathering system for Atlas Pipeline Partners. Thus, the
expansion of the Atlas Pipeline Partners gathering system will be within the
control of the managing general
83
partner's affiliate, which will attempt to expand the Atlas Pipeline Partners
gathering system to those areas with the greatest number of wells with the
greatest potential reserves.
The managing general partner's affiliates are obligated through their agreement
with Atlas Pipeline Partners to pay the difference between the amount each
partnership pays for gathering fees to the managing general partner as set forth
in "Compensation - Gathering Fees," and the greater of $.35 per mcf or 16% of
the gross sales price for the natural gas. This provides an incentive to the
managing general partner to increase the amount of the gathering fees paid by
each partnership to it, which are not fixed and may change as described in
"Compensation-Gathering Fees." However, the gathering fees paid to the managing
general partner may not exceed competitive rates.
Procedures to Reduce Conflicts of Interest
In addition to the procedures set forth in " - Conflicts Involving the
Acquisition of Leases," the managing general partner and its affiliates will
comply with the following procedures in the partnership agreement to reduce some
of the conflicts of interest with you and the other investors. The managing
general partner does not have any other conflict of interest resolution
procedures. Thus, conflicts of interest between the managing general partner and
you and the other investors may not necessarily be resolved in your best
interests. However, the managing general partner believes that its significant
capital contribution to each partnership will reduce the conflicts of interest.
(1) Fair and Reasonable. The managing general partner may not sell, transfer,
or convey any property to, or purchase any property from, a partnership
except:
o under transactions that are fair and reasonable; nor
o take any action with respect to the assets or property of a
partnership which does not primarily benefit the partnership.
(2) No Compensating Balances. The managing general partner may not use a
partnership's funds as a compensating balance for its own benefit. Thus, a
partnership's funds may not be used to satisfy any deposit requirements
imposed by a bank or other financial institution on the managing general
partner for its own corporate purposes.
(3) Future Production. The managing general partner may not commit the future
production of a partnership well exclusively for its own benefit.
(4) Disclosure. Any agreement or arrangement that binds a partnership must be
fully disclosed in this prospectus.
(5) No Loans from the Partnership. A partnership may not loan money to the
managing general partner.
(6) No Rebates. The managing general partner may not participate in any
business arrangements which would circumvent these guidelines including
receiving rebates or give-ups.
(7) Sale of Assets. The sale of all or substantially all of the assets of a
partnership may only be made with the consent of investors whose units
equal a majority of the total units.
(8) Participation in Other Partnerships. If a partnership participates in other
partnerships or joint ventures, then the terms of the arrangements must not
circumvent any of the requirements contained in the partnership agreement,
including the following:
o there may be no duplication or increase in organization and
offering expenses, the managing general partner's compensation,
partnership expenses, or other fees and costs;
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o there may be no substantive change in the fiduciary and
contractual relationship between the managing general partner and
you and the other investors; and
o there may be no diminishment in your voting rights.
(9) Investments. A partnership's funds may not be invested in the securities of
another person except in the following instances:
o investments in working interests made in the ordinary course of
the partnership's business;
o temporary investments in income producing short-term highly
liquid investments, in which there is appropriate safety of
principal, such as U.S. Treasury Bills;
o multi-tier arrangements meeting the requirements of (8) above;
o investments involving less than 5% of the total subscription
proceeds of the partnership that are a necessary and incidental
part of a property acquisition transaction; and
o investments in entities established solely to limit the
partnership's liabilities associated with the ownership or
operation of property or equipment, provided that duplicative
fees and expenses are prohibited.
(10) Safekeeping of Funds. The managing general partner may not employ, or
permit another to employ, the funds or assets of a partnership in any
manner except for the exclusive benefit of the partnership. The managing
general partner has a fiduciary responsibility for the safekeeping and use
of all funds and assets of each partnership whether or not in its
possession or control.
(11) Advance Payments. Advance payments by each partnership to the managing
general partner and its affiliates are prohibited except when advance
payments are required to secure the tax benefits of prepaid intangible
drilling costs and for a business purpose.
Policy Regarding Roll-Ups
It is possible at some indeterminate time in the future that each partnership
may become involved in a roll-up. In general, a roll-up means a transaction
involving the acquisition, merger, conversion, or consolidation of a partnership
with or into another partnership, corporation or other entity, and the issuance
of securities by the roll-up entity to you and the other investors. A roll-up
will also include any change in the rights, preferences, and privileges of you
and the other investors in the partnership. These changes could include the
following:
o increasing the compensation of the managing general partner;
o amending your voting rights;
o listing the units on a national securities exchange or on NASDAQ;
o changing the partnership's fundamental investment objectives; or
o materially altering the partnership's duration.
If a roll-up should occur in the future the partnership agreement provides
various policies which include the following:
o an independent expert must appraise all partnership assets, and you
must receive a summary of the appraisal in connection with a proposed
roll-up;
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o if you vote "no" on the roll-up proposal, then you will be offered a
choice of:
o accepting the securities of the roll-up entity; or
o one of the following:
o remaining a partner in the partnership and preserving your
units in the partnership on the same terms and conditions as
existed previously; or
o receiving cash in an amount equal to your pro-rata share of
the appraised value of the partnership's net assets; and
o the partnership will not participate in a proposed roll-up:
o unless approved by investors whose units equal 66% of the total
units;
o which would result in the diminishment of your voting rights
under the roll-up entity's chartering agreement;
o which includes provisions which would operate to materially
impede or frustrate the accumulation of shares by you of the
securities of the roll-up entity;
o in which your right of access to the records of the roll-up
entity would be less than those provided by the partnership
agreement; or
o in which any of the transaction costs would be borne by the
partnership if the proposed roll-up is not approved by investors
whose units equal 66% of the total units.
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
In General
The managing general partner will manage each partnership and its assets. In
conducting your partnership's affairs the managing general partner is
accountable to you as a fiduciary. Under Delaware law this generally means that
the managing general partner must exercise due care and deal fairly with you and
the other investors. Neither the partnership agreement nor any other agreement
between the managing general partner and each partnership may contractually
limit any fiduciary duty owed to you and the other investors by the managing
general partner under applicable law except as set forth in Sections 4.01, 4.02,
4.04, 4.05, and 4.06 of the partnership agreement. For example, the partnership
agreement does permit:
o the managing general partner and its affiliates to have business
interests or activities that may conflict with the partnerships if the
managing general partner and its affiliates determine that the
opportunity either:
o cannot be pursued by the partnership because of insufficient
funds; or
o it is not appropriate for the partnership under the existing
circumstances;
o the managing general partner and its affiliates to be indemnified and
held harmless as described below in "- Limitations on Managing General
Partner Liability as Fiduciary";
o the managing general partner to devote only so much of its time as is
necessary to manage the affairs of the program;
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o the managing general partner and its affiliates to conduct business
with the partnership in a capacity other than as managing general
partner or sponsor as described in ss.ss.4.01, 4.02, 4.04, 4.05 and
4.06 of the partnership agreement; and
o the managing general partner to manage multiple programs
simultaneously.
Other than as set forth above, the partnership agreement does not excuse the
managing general partner from liability or provide it with any defense for
breach of its fiduciary duty. The fiduciary duty owed by the managing general
partner to the partnership is analogous to the fiduciary duty owed by directors
to a corporation and its stockholders and is subject to the same rule, commonly
referred to as the "business judgment rule," that directors are not liable for
mistakes in the good faith exercise of honest business judgment or for losses
incurred in the good faith performance of their duties when performed with such
care as an ordinarily prudent person would use. As a result of the business
judgment rule, the managing general partner may not be held liable for mistakes
made or losses incurred in the good faith exercise of reasonable business
judgment as described below in "- Limitations on Managing General Partner
Liability as Fiduciary."
If the managing general partner breaches its fiduciary responsibilities, then
you are entitled to an accounting and the recovery of any economic loss caused
by the breach. The Delaware Revised Uniform Limited Partnership Act provides
that a limited partner may institute legal action (a "derivative" action) on a
partnership's behalf to recover damages from a third party when the managing
general partner refuses to institute the action or where an effort to cause the
managing general partner to do so is not likely to succeed. In addition, the
statutory or case law may permit a limited partner to institute legal action on
behalf of himself and all other similarly situated limited partners (a "class
action") to recover damages from the managing general partner for violations of
its fiduciary duties to the limited partners. This is a rapidly expanding and
changing area of the law, and if you have questions concerning the managing
general partner's duties you are urged to consult your own counsel.
Limitations on Managing General Partner Liability as Fiduciary
Under the terms of the partnership agreement the managing general partner, the
operator, and their affiliates have limited their liability to each partnership
and to you and the other investors for any loss suffered by your partnership or
you and the other investors in the partnership which arises out of any action or
inaction on their part if:
o they determined in good faith that the course of conduct was in the
best interest of the partnership;
o they were acting on behalf of, or performing services for, the
partnership; and
o their course of conduct did not constitute negligence or misconduct.
In addition, the partnership agreement provides for indemnification of the
managing general partner, the operator, and their affiliates by each partnership
against any losses, judgments, liabilities, expenses, and amounts paid in
settlement of any claims sustained by them in connection with that partnership
provided that they meet the standards set forth above. However, there is a more
restrictive standard for indemnification for losses arising from or out of an
alleged violation of federal or state securities laws. Also, to the extent that
any indemnification provision in the partnership agreement purports to include
indemnification for liabilities arising under the Securities Act of 1933, as
amended, you should be aware that, in the SEC's opinion, this indemnification is
contrary to public policy and therefore unenforceable.
Payments arising from the indemnification or agreement to hold harmless are
recoverable only out of a partnership's:
o tangible net assets;
o revenues; and
o insurance proceeds.
87
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.
A partnership may not pay the cost of the portion of any insurance that insures
the managing general partner, the operator, or an affiliate against any
liability for which they cannot be indemnified. However, a partnership's funds
can be advanced to them for legal expenses and other costs incurred in any legal
action for which indemnification is being sought only if the partnership has
adequate funds available and certain conditions in the partnership agreement are
met.
The effect of the foregoing provisions and the business judgment rule may be to
limit your recourse to the managing general partner.
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 applies equally to the
partnerships composing the program and 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 investor general partner and limited partner
units. You are strongly urged to read the entire tax opinion. (See "Additional
Information.")
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. 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 a
partnership or you, or the taxable year in which the deductions are claimed, and
no guaranty can be given that the challenge would not be upheld if litigated.
Also, special counsel's opinions are based in part on certain factual
representations of the managing general partner and factual assumptions which
are set forth in the tax opinion. Because of the inherent uncertainty created by
the foregoing factors, special counsel's opinions set forth below state whether
it is "more likely than not" that the predicted tax treatment is the proper tax
treatment. No advance ruling on any tax consequence of an investment in a
partnership will be requested from the IRS.
Different tax considerations than those addressed in this discussion may apply
to foreign persons, corporations, partnerships, trusts and other prospective
investors which are not treated as typical investors in the partnerships for
federal income tax purposes. For purposes of the tax opinion, the managing
general partner has represented to special counsel that "typical investors" are
natural persons who purchase units in this offering and are U.S. citizens. Also,
the treatment of the tax attributes of a 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.
o Partnership Classification. Each partnership will be classified as a
partnership for federal income tax purposes, and not as a corporation.
Each 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 that partnership.
o Passive Activity Classification.
o Generally, the passive activity limitations on losses under 1469
of the Internal Revenue Code will apply to limited partners, but
will not apply to investor general partners before the conversion
of investor general partner units to limited partner units.
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o The partnership's income and gain from its natural gas and oil
properties which are allocated to limited partners, other than
converted investor general partners, generally will be
characterized as passive activity income which may be offset by
passive activity losses.
o Income or gain attributable to investments of working capital of
a partnership will be characterized as portfolio income, which
cannot be offset by passive activity losses.
o Not a Publicly Traded Partnership. Assuming that no more than 10% of
the units are transferred in any taxable year of a partnership, other
than in private transfers described in Treas. Reg. ss.1.7704-1(e), the
partnership will not be treated as a "publicly traded partnership"
under the Internal Revenue Code.
o 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.
o Intangible Drilling Costs. Each partnership will elect to deduct
currently all intangible drilling costs. However, each investor may
elect instead to capitalize and deduct all or part of his share of the
intangible drilling costs ratably over a 60 month period as discussed
in "Minimum Tax - Tax Preferences," below. Subject to the foregoing,
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 the amounts are fair and
reasonable consideration and subject to certain restrictions
summarized below, including basis and "at risk" limitations and the
passive activity loss limitation with respect to the limited partners.
o Depletion Allowance. The greater of cost depletion or percentage
depletion will be available to qualified investors as a current
deduction against that partnership's natural gas and oil production
income, subject to certain restrictions summarized below.
o MACRS. Each partnership's reasonable costs for equipment placed in the
wells which cannot be deducted immediately will be eligible for cost
recovery deductions under the Modified Accelerated Cost Recovery
System ("MACRS"), generally over a seven year "cost recovery period,"
subject to certain restrictions summarized below, including basis and
"at risk" limitations and the passive activity loss limitation in the
case of the limited partners.
o Tax Basis of Units. Each investor's adjusted tax basis in his units
will be increased by his total subscription proceeds.
o At Risk Limitation on Losses. Each investor initially will be "at
risk" to the full extent of his subscription proceeds.
o 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 natural gas and oil properties, is substantial in light of
an investor's tax attributes that are unrelated to the partnership,
the allocations will have "substantial economic effect" and will
govern each investor's distributive share of those items to the extent
the allocations do not cause or increase deficit balances in the
investors' capital accounts.
o Subscription. No gain or loss will be recognized by the investors on
payment of their subscriptions.
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o Profit Motive and No Tax Shelter Registration. Based on the results of
the previous partnerships sponsored by the managing general partner
set forth in "Prior Activities" and the managing general partner's
representations to special counsel set forth in the tax opinion,
including that the principal purpose of each partnership is to locate,
produce and market natural gas and oil on a profitable basis apart
from tax benefits (which is supported by the geological evaluations
for the proposed prospects included in Appendix A to the prospectus,
which will cover a portion of the prospects to be drilled in Atlas
America Public #12-2003), the partnerships will possess the requisite
profit motive under ss.183 of the Internal Revenue Code and are not
required to register with the IRS as a tax shelter.
o Anti-Abuse Rules and Judicial Doctrines. Based on the results of the
previous partnerships sponsored by the managing general partner set
forth in "Prior Activities" and the managing general partner's
representations to special counsel set forth in the tax opinion,
including that the principal purpose of each partnership is to locate,
produce and market natural gas and oil on a profitable basis apart
from tax benefits (which is supported by the geological evaluations
for the proposed prospects included in Appendix A to the prospectus,
which will cover a portion of the prospects to be drilled in Atlas
America Public #12-2003), potentially relevant statutory or regulatory
anti-abuse rules and judicial doctrines will not have a material
adverse effect on the tax consequences of an investment in the
partnership by a typical investor as described in special counsel's
opinions.
o Overall Evaluation of Tax Benefits. Based on special counsel's
conclusion that substantially more than half of the material tax
benefits of each partnership, in terms of their financial impact on a
typical investor, more likely than not will be realized if challenged
by the IRS, the tax benefits of each partnership, in the aggregate,
which are a significant feature of an investment in a partnership by a
typical original investor more likely than not will be realized as
contemplated by the prospectus.
*************
In General
The following is a summary of all of the material federal income tax
consequences of the purchase, ownership and disposition of investor general
partner units and limited partner units discussed in the tax opinion which will
apply to typical investors.
Partnership Classification
For federal income tax purposes a partnership is not a taxable entity. The
partners, rather than the partnership, receive any deductions, 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 partnerships were formed under the
Delaware Revised Uniform Limited Partnership Act which describes each
partnership as a "partnership," each partnership automatically will be
classified as a partnership unless it elects to be classified as a corporation.
In this regard, the managing general partner has represented to special counsel
that the partnerships will not elect to be classified as a corporation.
Limitations on Passive Activities
Under the passive activity rules all income of a taxpayer who is subject to the
rules is categorized as:
o income from passive activities such as limited partners' interests in
a business;
o active income such as salary, bonuses, etc.; or
o portfolio income such as gain, interest, dividends and royalties
unless earned in the ordinary course of a trade or business.
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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 a partnership and generally will be subject to the passive activity
limitations.
Investor general partners also do not materially participate in a partnership.
However, because each partnership will own only "working interests," as defined
in the Internal Revenue Code, in its wells and investor general partners will
not have limited liability under Delaware law until they are converted to
limited partners, their deductions generally will not be treated as passive
deductions before the conversion. However, if an investor general partner
invests in a partnership through an entity which limits his liability, for
example, a limited partnership, limited liability company or S corporation, then
he generally will be subject to the passive activity limitations the same as a
limited partner. 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 passive income from a publicly
traded partnership. However, in the opinion of special counsel it is more likely
than not that each 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 in the partnership are transferred in any taxable year of the partnership
other than in private transfers described in Treas. Reg. ss.1.7704-1(e).
Conversion from Investor General Partner to Limited Partner. If you invest as an
investor general partner in a partnership, then your share of the partnership's
deduction for intangible drilling costs in the year in which you invest will not
be subject to the passive activity limitations because your investor general
partner units will not be converted to limited partner units until after all the
wells have been drilled and completed, which the managing general partner
anticipates will be in the year following the close of the partnership. (See
"Actions to be Taken by Managing General Partner to Reduce Risks of Additional
Payments by Investor General Partners" and "- Drilling Contracts," below.)
Thereafter, each investor general partner will have limited liability as a
limited partner under the Delaware Revised Uniform Limited Partnership Act with
respect to his interest in the partnership.
Concurrently, the investor general partner will become subject to the passive
activity limitations. However, because he previously will have received a non-
passive deduction for intangible drilling costs, the Internal Revenue Code
requires that his net income from the partnership's wells following the
conversion must 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 the 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 and Method of Accounting
Each partnership intends to adopt a calendar year taxable year and will use the
accrual method of accounting for federal income tax purposes.
2003 and 2004 Expenditures
The managing general partner anticipates that all of each partnership's
subscription proceeds will be expended in the year in which you invest and that
your share of your partnership's income and deductions will be reflected on your
federal income tax return for that period.
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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:
o in excess of reasonable compensation;
o properly characterized as organization or syndication fees, other
capital costs such as the acquisition cost of the leases; or
o not "ordinary and necessary" business expenses.
In the event of an audit, payments to the managing general partner and its
affiliates by a partnership will be scrutinized by the IRS to a greater extent
than payments to an unrelated party.
Intangible Drilling Costs
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 you elect to deduct all
or part of these costs ratably over a 60-month period as discussed in "Minimum
Tax - Tax Preferences," below.
The managing general partner estimates that on average approximately 78.18% of
the total price to be paid by each partnership for all of its completed wells
will be intangible drilling costs which are charged 100% to you and the other
investors under the partnership agreement. Under the partnership agreement not
less than 90% of the subscription proceeds received by a partnership from you
and the other investors will be used to pay intangible drilling costs. 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 by you and the other investors under the partnership
agreement.
You are urged to consult with your personal tax advisor concerning the tax
benefits to you of a partnership's deduction for intangible drilling costs in
light of your own tax situation.
Drilling Contracts
Each 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 each partnership it will have reimbursement of general and
administrative overhead of $14,142 per well and a profit of 15% (approximately
$26,083) per well with respect to the intangible drilling costs and the portion
of equipment 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 profit per well also could be more or less than the amount
estimated by the managing general partner.
The managing general partner believes the prices under the drilling and
operating agreement are competitive in the proposed areas of operation.
Nevertheless, the amount of the profit realized by the managing general partner
under the drilling and operating agreement could be challenged by the IRS as
unreasonable and disallowed as a deductible intangible drilling cost.
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Depending primarily on when the partnership subscriptions are received, the
managing general partner anticipates that the partnership designated Atlas
America Public #12-2003 will prepay in 2003 most of the intangible drilling
costs for drilling activities that will begin in 2004. The same may be true for
the partnerships designated Atlas America Public #12-2004(_) one of which may
close on December 31, 2004. 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. The test is:
o the expenditure must be a payment rather than a refundable deposit;
and
o the deduction must not result in a material distortion of income
taking into substantial consideration the business purpose aspects of
the transaction.
Each partnership will attempt to comply with the guidelines set forth in Keller
with respect to prepaid intangible drilling costs. The drilling and operating
agreement will require the partnership to prepay in the year in which you invest
intangible drilling costs for specified wells the drilling of which will begin
in the following year. Prepayments should not result in a loss of current
deductibility where:
o there is a legitimate business purpose for the required prepayment;
o the contract is not merely a sham to control the timing of the
deduction; and
o there is an enforceable contract of economic substance.
The drilling and operating agreement will require the partnerships to prepay the
intangible drilling costs of drilling and completing the wells in order to
enable the operator to:
o begin site preparation for the wells;
o obtain suitable subcontractors at the then current prices; and
o insure the availability of equipment and materials.
Under the drilling and operating agreement excess prepaid 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,
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 if 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, 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, of the year after which you invest. 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:
o the unavailability of drilling rigs;
93
o decisions of third-party operators to delay drilling the wells;
o weather conditions;
o inability to obtain drilling permits or access right to the drilling
site; or
o 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, of the year after which you invest, will actually
begin by that date. In that event, deductions claimed in the year in which you
invest for prepaid intangible drilling costs would be disallowed and deferred to
the next 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 a partnership's drilling contracts, thereby decreasing the amount of
deductions allocable to the investors for the current taxable year, or that the
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 each partnership's natural gas and oil production will
constitute ordinary income. A certain portion of the income will not be taxable
under the depletion allowance which permits the deduction from gross income for
federal income tax purposes of either the percentage depletion allowance or the
cost depletion allowance, whichever is greater. 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 natural gas or oil expected to be recoverable
from the property and then multiplying the resultant quotient by the number of
units actually sold during the year. Cost depletion cannot exceed the adjusted
tax basis of the property to which it relates.
Percentage depletion generally is available to taxpayers other than integrated
oil companies. Percentage depletion is based on your share of your partnership's
gross production income from its natural gas and oil properties. The rate of
percentage depletion is 15%. However, percentage depletion for marginal
production increases 1%, up to a maximum increase of 10%, for each whole dollar
that the domestic wellhead price of crude oil for the immediately preceding year
is less than $20 per barrel without adjustment for inflation. The term "marginal
production" includes natural gas and oil produced from a domestic stripper well
property, which is defined as any property which produces a daily average of 15
or less equivalent barrels of oil, which is equivalent to 90 mcf of natural gas,
per producing well on the property in the calendar year. The rate of percentage
depletion for marginal production in 2003 is 15%. 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%.
Also, percentage depletion:
o may not exceed 100% of the net income from each natural gas and oil
property before the deduction for depletion; and
o 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, which will include most, if not
all, of each partnership's wells, the 100% of net income property limitation is
suspended for 2003.
Availability of percentage depletion must be computed separately by you, and not
by a 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.
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Depreciation - Modified Accelerated Cost Recovery System ("MACRS")
Equipment costs and the related depreciation deductions of each partnership
generally are charged and allocated under the partnership agreement 66% to the
managing general partner and 34% to you and the other investors in the
partnership. However, if the total equipment costs for all of the partnership's
wells that would be charged to you and the other investors exceeds an amount
equal to 10% of the subscription proceeds of you and the other investors, then
the excess, together with the related depreciation deductions, will be charged
and allocated to the managing general partner. These deductions are subject to
recapture as ordinary income rather than capital gain on the disposition of the
property or an investor's units. The cost of most equipment placed in service by
the partnership will be recovered through depreciation deductions over a seven
year cost recovery period, using the 200% declining balance method, with a
switch to straight-line to maximize the deduction. In the case of a short tax
year the MACRS deduction is prorated on a 12-month basis. No distinction is made
between new and used property and salvage value is disregarded. Except as
discussed below, smaller depreciation deductions are used for purposes of the
alternative minimum tax, and generally only a half-year of depreciation is
allowed for the year recovery property is placed in service or disposed of.
Notwithstanding the foregoing, under the Job Creation and Worker Assistance Act
of 2002 ("2002 Act"), for federal income tax purposes each partnership will be
entitled to accelerate in the year in which the equipment is placed in service
an additional depreciation allowance based on 30% of the adjusted basis of
qualified equipment acquired before September 11, 2004. The basis of this
property will be reduced by the additional 30% first-year depreciation allowance
for purposes of calculating the regular MACRS depreciation allowances beginning
in 2003. Although not specifically mentioned in the 2002 Act, the examples
provided in the Technical Explanation of the 2002 Act do not reduce the 30%
additional depreciation allowance by the half-year convention discussed above.
Nevertheless, because this situation is not clearly addressed by the 2002 Act,
it is possible the half-year convention or a mid-quarter convention, depending
on when a partnership's equipment is placed in service, ultimately may be
determined to apply. Also, there will not be any alternative minimum tax
adjustment with respect to a partnership's additional 30% first-year
depreciation allowance, nor any of the other depreciation deductions allowable
in 2003 or later years for the costs of qualified equipment it places in the
wells.
Lease Acquisition Costs and Abandonment
Lease acquisition costs, together with the related cost depletion deduction and
any abandonment loss for lease costs, are allocated under the partnership
agreement 100% to the managing general partner, which will contribute each
partnership's leases to the respective partnership as a part of its capital
contribution.
Tax Basis of Units
Your distributive share of partnership loss is allowable only to the extent of
the adjusted basis of your units at the end of your partnership's taxable year.
The adjusted basis of your units will be adjusted, but not below zero, for any
gain or loss to you from a disposition by the partnership of a natural gas or
oil property, and will be increased by your:
o cash subscription payment;
o share of partnership income; and
o share, if any, of partnership debt.
The adjusted basis of your units will be reduced by your:
o share of partnership losses;
o depletion deduction, but not below zero; and
o cash distributions from the partnership.
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The reduction in your share of partnership liabilities, if any, is considered a
cash distribution. Should cash distributions exceed the tax basis of your units
taxable gain would result to the extent of the excess.
"At Risk" Limitation for Losses
Subject to the limitations on "passive losses" generated by a partnership in the
case of limited partners and your basis in your units, you may use your share of
a 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 you paid for your units in the partnership. However, the amount you have
"at risk" may not include the amount of any loss that you are protected against
through:
o nonrecourse loans;
o guarantees;
o stop loss agreements; or
o other similar arrangements.
Distributions from a Partnership
Generally, a cash distribution from a partnership to you in excess of the
adjusted basis of your units immediately before the distribution is treated as
gain from the sale or exchange of your units to the extent of the excess. No
loss can be recognized by you on these distributions. Other distributions of
property and liquidating distributions may result in taxable gain or loss.
Sale of the Properties
Generally, adjusted 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 below 25% if they were not
eligible for long-term capital gains treatment. These rates are 18% and 8%,
respectively, for gain on qualifying assets held for more than five years. The
capital gain 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 natural gas and oil properties held for more than
12 months generally will be treated as a long-term capital gain, while a net
loss will be an ordinary deduction. However, on disposition of a natural gas or
oil property gain is treated as ordinary income to the extent of the lesser of:
o the amounts that were deducted as intangible drilling costs rather
than added to basis, plus depletion deductions that reduced the basis
of the property, depreciation deductions and certain losses, if any,
on previous sales of partnership assets; or
o 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 natural gas and oil properties will generally
result in ordinary gains or losses.
Disposition of Units
The sale or exchange, including a purchase by the managing general partner, of
all or part of your units 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 depreciation, depletion and intangible drilling costs
will constitute ordinary income. If the units are held for 12 months or less,
the gain or loss generally will be short-term gain or loss. Also, your pro rata
share of your partnership's liabilities, if any, as of the date of the sale or
exchange must be included in the amount realized. Therefore, the gain recognized
may result in a tax liability greater than the cash proceeds, if any, from the
disposition. In addition to gain from a
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passive activity, a portion of any gain recognized by a limited partner on the
sale or other disposition of his units may be characterized as portfolio income.
A gift of your units 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 units may or may not
result in recognition of taxable gain. However, no gain should be recognized by
an investor general partner on the conversion of his investor general partner
units to limited partner units so long as there is no change in his share of his
partnership's liabilities or certain partnership assets as a result of the
conversion. In addition, if you sell or exchange all or part of your units you
are required by the Internal Revenue Code to notify your partnership within 30
days or by January 15 of the following year, if earlier.
You are urged to consult with your tax advisor before you make any disposition
of your units, including purchase of the units by the managing general partner.
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 deductions for intangible drilling costs and
accelerated depreciation except as discussed above in "- Depreciation - Modified
Accelerated Cost Recovery System ("MACRS")." 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 tax rates on capital gains also apply for purposes of the
alternative minimum tax. Regular tax personal exemptions are not available for
purposes of the alternative minimum tax, however, alternative minimum taxable
income may be reduced by certain itemized deductions, exemption amounts and net
operating losses. For tax years through 2004, the exemption is $49,000 for
married couples filing jointly and surviving spouses; $35,750 for single filers,
and $24,500 for married persons filing separately. However, these exemption
amounts are reduced by 25% of the alternative minimum taxable income in excess
of:
o $150,000 for joint returns and surviving spouses;
o $75,000 for married persons filing separately; and
o $112,500 for single taxpayers.
Also, for these tax years only, married persons filing separately must increase
their alternative minimum taxable income by the lesser of 25% of alternative
minimum taxable income over $173,000 or $24,500.
Alternative minimum taxable income generally is taxable income, plus or minus
adjustments, plus preferences. For taxpayers other than integrated oil
companies, the 1992 National Energy Bill repealed the preference for:
o excess intangible drilling costs; and
o the excess percentage depletion preference for natural gas and oil.
The repeal of the excess intangible drilling costs preference, however, may not
result in more than a 40% reduction in the amount of the taxpayer's alternative
minimum taxable income computed as if the excess intangible drilling costs
preference had not been repealed. Under the prior rules, the amount of
intangible drilling costs which is not deductible for alternative minimum tax
purposes is the excess of the "excess intangible drilling costs" over 65% of net
income from natural gas and oil properties. Excess intangible drilling costs is
the regular intangible drilling costs deduction minus the amount that would
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have been deducted under 120-month straight-line amortization, or, at the
taxpayer's election, under the cost depletion method. There is no preference
item for costs of nonproductive wells.
Also, you may elect to capitalize all or part of your share of the partnership's
intangible drilling costs and deduct the costs ratably over a 60-month period
beginning with the month in which the costs were paid or incurred. This election
also applies for regular tax purposes and can be revoked only with the IRS'
consent. Making this election, therefore, generally will result in the following
consequences to you:
o your regular tax deduction in the year in which you invest for
intangible drilling costs will be reduced because you must spread the
deduction for the amount of intangible drilling costs which you elect
to capitalize over the 60-month amortization period; and
o the capitalized intangible drilling costs will not be treated as a
preference that is included in your alternative minimum taxable
income.
The likelihood of you incurring, or increasing, any minimum tax liability
because of an investment in a partnership must be determined on an individual
basis, and you are urged to consult with your personal tax advisor.
Limitations on Deduction of Investment Interest
Investment interest expense is deductible by a noncorporate taxpayer only to the
extent of net investment income each year, with an indefinite carryforward of
disallowed amounts. An investor general partner's share of any interest expense
incurred by a partnership before the investor general partner units are
converted to limited partner units in that partnership will be subject to the
investment interest limitation. In addition, an investor general partner's
income and losses, including intangible drilling costs, from a 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 your partnership's
income, gains, losses and deductions, including the deductions for intangible
drilling costs and depreciation. Your capital account will be adjusted to
reflect these allocations and your capital account, as adjusted, will be given
effect in distributions made to you on liquidation of the partnership or your
interest in the partnership. Generally, your capital account will be:
o increased by the amount of money you contribute to the partnership and
allocations to you of income and gain; and
o decreased by the value of property or cash distributed to you 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 a 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 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 allocated by the partnership agreement exceed deductions
which would be allowed under a reallocation by the IRS, 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 a 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 in which you invest,
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 units in each partnership, including the
dealer-manager fee and sales commissions paid to the dealer-manager which are
charged 100% to the managing general partner under the partnership agreement,
are not deductible. Although certain organization expenses of the respective
partnership may be amortized over a period of not less than 60 months, these
expenses are also paid by the managing general partner as part of each
partnership's organization and offering costs and any related deductions, which
the managing general partner does not expect will be material in amount, will be
allocated to the managing general partner.
Tax Elections
Each partnership may elect to adjust the basis of its partnership property on
the transfer of a unit in the partnership by sale or exchange or on the death of
an investor, and on the distribution of property by the partnership to a
partner. The general effect of this election is that transferees of the units
are treated, for purposes of depreciation and gain, as though they had acquired
a direct interest in the partnership assets and the partnership is treated for
these purposes, on 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 a partnership's expenses constituted start-up expenditures and not
deductible business expenses, the partnership's deductions for those expenses
would be deferred.
Disallowance of Deductions under Section 183 of the Internal Revenue Code
Your ability to deduct your share of your 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 results of the previous partnerships sponsored by the
managing general partner set forth in "Prior Activities" and the managing
general partner's representations to special counsel set forth in the tax
opinion, including that the principal purpose of each partnership is to locate,
produce and market natural gas and oil on a profitable basis apart from tax
benefits (which is supported by the geological evaluations for the proposed
prospects included in Appendix A to the prospectus, which will cover a portion
of the prospects to be drilled in Atlas America Public #12-2003), in the opinion
of special counsel it is more likely than not that the partnership will possess
the requisite profit motive.
Termination of a Partnership
A partnership will be considered as terminated for federal income tax purposes
if within a 12 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 to the extent that money regarded as distributed to you by
your partnership exceeds the adjusted basis of your units. The conversion of
investor general partner units to limited partner units, however, will not
terminate 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
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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.
The managing general partner does not believe that either partnership will have
a tax shelter ratio greater than 2 to 1. Accordingly, the managing general
partner does not intend to register either partnership with the IRS as a tax
shelter.
If it is subsequently determined by the IRS or the courts that the partnership
in which you invest 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 units. However, based
on the representations of the managing general partner, special counsel has
expressed the opinion that the partnerships, more likely than not, are 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. If requested by the IRS, a partnership must identify its
investors and give the IRS certain information concerning each investor's
partnership investment and tax benefits.
Tax Returns and Audits
In General. The tax treatment of all partnership items generally is determined
at the partnership, rather than the partner, level; and the partners generally
are 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 you and the other investors attributable to
a partnership item may be extended by agreement between the IRS and the managing
general partner, which will serve as each partnership's representative 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 on, any investor 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 partnerships 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 in
which you invest 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 you fail to treat partnership items on your tax return in a manner
that is consistent with the treatment of those items on your 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:
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o the value or adjusted basis of any property claimed on a return is
200% or more of the correct amount; or
o 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%.
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:
o 10% of the tax required to be shown on the return; or
o $5,000.
The amount of any understatement generally will be reduced to the extent it is
attributable to the tax treatment of an item:
o supported by substantial authority; or
o adequately disclosed on the taxpayer's return and there was a
reasonable basis for the tax treatment.
However, in the case of "tax shelters," which includes the partnerships for this
purpose, 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.
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 representations to special
counsel as described in the tax opinion, in the opinion of special counsel it is
more likely than not that this rule or any other potentially relevant statutory
and regulatory anti-abuse rules will not have a material adverse effect on the
tax consequences of an investment in a partnership by a typical investor as
described in special counsel's opinions.
Judicial Doctrines. Special counsel also has considered the possible application
to the partnerships and their intended activities of all potentially relevant
judicial doctrines including step transactions, business purpose, economic
substance, substance over form, and sham transaction doctrines. The gist of
these judicial doctrines is that tax deductions from a transaction will be
disallowed if the transaction has no economic substance apart from the tax
benefits.
Based on the results of the previous partnerships sponsored by the managing
general partner set forth in "Prior Activities" and the managing general
partner's representations to special counsel set forth in the tax opinion,
including that the principal purpose of each partnership is to locate, produce
and market natural gas and oil on a profitable basis apart from tax benefits
(which is supported by the geological evaluations for the proposed prospects
included in Appendix A to the prospectus, which will cover a portion of the
prospects to be drilled in Atlas America Public #12-2003), special counsel has
concluded that none of the judicial doctrines will have a material adverse
effect on the tax consequences of an investment in the partnerships by a typical
investor as described in special counsel's opinions.
State and Local Taxes
Under Pennsylvania law each partnership is required to withhold state income tax
at the rate of 2.8% on any Pennsylvania taxable income allocable from the
partnership to its investors who are not residents of Pennsylvania. Also, your
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.
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You are urged to 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
Each partnership may incur various ad valorem or severance taxes imposed by
state or local taxing authorities.
Social Security Benefits and Self-Employment Tax
A limited partner's share of income or loss from a partnership is excluded from
the definition of "net earnings from self-employment." No increased benefits
under the Social Security Act will be earned by limited partners, and if any
limited partners are currently receiving Social Security benefits their shares
of partnership taxable income will not be taken into account in determining any
reduction in benefits because of "excess earnings."
An investor general partner's share of income or loss from a partnership will
constitute "net earnings from self-employment" for these purposes. The ceiling
for social security tax of 12.4% in 2003 is $87,000 and the ceiling for 2004 is
not yet known. There is no ceiling for medicare tax of 2.9%. Self-employed
individuals can deduct one-half of their self-employment tax.
Farmouts
Under a farmout by a partnership, if a property interest, other than an interest
in the drilling unit assigned to the partnership well in question, is earned by
the farmee (anyone other than the partnership) from the farmor (the partnership)
as a result of the farmee drilling or completing the well, then the farmee must
recognize income equal to the fair market value of the outside interest earned,
and the farmor must recognize gain or loss on a deemed sale equal to the
difference between the fair market value of the outside interest and the
farmor's tax basis in the outside interest. Neither the farmor nor the farmee
would have received any cash to pay the tax. The managing general partner will
attempt to eliminate or reduce any gain to the partnership from a farmout, if
any. However, if the IRS claims that a farmout by the partnership results in
taxable income to the partnership and its position is ultimately sustained, you
and the other investors in the partnership would be required to include your
distributive share of the resulting taxable income on your personal income tax
returns, even though the partnership and you and the other investors received no
cash from the farmout.
Foreign Partners
Each 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 them.
In the event of overwithholding a foreign partner must file a United States tax
return to obtain a refund. Under the Internal Revenue Code, for withholding
purposes, a foreign partner means a partner who is a nonresident alien
individual or a foreign corporation, partnership trust or estate, if the partner
has not certified to the partnership the partner's nonforeign status.
Estate and Gift Taxation
There is no federal tax on lifetime or testamentary transfers of property
between spouses. The gift tax annual exclusion is $11,000 per donee in 2003
which will be adjusted in subsequent years for inflation. Under the Economic
Growth and Tax Relief Reconciliation Act of 2001 ("the 2001 Act") estates of $1
million in 2003 and $1.5 million in 2004, which further increase in stages to
$3.5 million by 2009, or less generally are not subject to federal estate tax.
Under the 2001 Act, the federal estate tax is scheduled to be repealed in 2010,
and then reinstated in 2011 under the rules in effect before the 2001 Act.
Changes in the Law
Your investment in a partnership may be affected by changes in the tax laws. For
example, the accelerated depreciation deduction created under the Job Creation
and Worker Assistance Act and discussed in " - Depreciation - Modified
Accelerated Cost Recovery System" ends for qualified equipment acquired after
September 10, 2004. Also, under the Economic Growth and Tax Relief
Reconciliation Act of 2001 the federal income tax rates are being reduced in
stages between 2001 and 2006, including reducing the top rate from:
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o 39.1% for 2001 to 38.6% for 2002 and 2003;
o 37.6% for 2004 and 2005; and
o 35% for 2006 through 2010.
This will reduce to some degree the amount of taxes you save by virtue of your
share of the partnership's deductions for intangible drilling costs, depletion
and depreciation. There is no assurance that the federal income tax rates
described above will not be changed in the future.
SUMMARY OF PARTNERSHIP AGREEMENT
The rights and obligations of the managing general partner and you and the other
investors are governed by the form of partnership agreement, a copy of which is
attached as Exhibit (A) to this prospectus. You are urged to not invest in a
partnership without first thoroughly reviewing the partnership agreement. The
following is a summary of the material provisions in the partnership agreement
that are not covered elsewhere in this prospectus. Thus, this prospectus
summarizes all of the material provisions of the partnership agreement.
Liability of Limited Partners
Each partnership will be governed by the Delaware Revised Uniform Limited
Partnership Act. If you invest as a limited partner, then generally you will not
be liable to third-parties for the obligations of your partnership unless you:
o also invest as an investor general partner;
o take part in the control of the partnership's business in addition to
the exercise of your rights and powers as a limited partner; or
o fail to make a required capital contribution to the extent of the
required capital contribution.
In addition, you may be required to return any distribution you receive if you
knew at the time the distribution was made that it was improper because it
rendered the partnership insolvent.
Amendments
Amendments to the partnership agreement of a partnership may be proposed in
writing by:
o the managing general partner and adopted with the consent of investors
whose units equal a majority of the total units in the partnership; or
o investors whose units equal 10% or more of the total units in the
partnership and adopted by an affirmative vote of investors whose
units equal a majority of the total units in the partnership.
The partnership agreement of each partnership may also be amended by the
managing general partner without the consent of the investors for certain
limited purposes. However, an amendment that materially and adversely affects
the investors can only be made with the consent of the affected investors.
Notice
The following provisions apply regarding notices:
o when the managing general partner gives you and other investors notice
it begins to run from the date of mailing the notice and is binding
even if it is not received;
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o the notice periods are frequently quite short, a minimum of 22
calendar days, and apply to matters that may seriously affect your
rights; and
o if you fail to respond in the specified time to the managing general
partner's second request for approval of or concurrence in a proposed
action, then you will conclusively be deemed to have approved the
action unless the partnership agreement expressly requires your
affirmative approval.
Voting Rights
Other than as set forth below, you generally will not be entitled to vote on any
partnership matters at any partnership meeting. However, at any time investors
whose units equal 10% or more of the total units in a partnership may call a
meeting to vote, or vote without a meeting, on the matters set forth below
without the concurrence of the managing general partner. On the matters being
voted on you are entitled to one vote per unit or if you own a fractional unit
that fraction of one vote equal to the fractional interest in the unit.
Investors whose units equal a majority of the total units in a partnership may
vote to:
o dissolve the partnership;
o remove the managing general partner and elect a new managing general
partner;
o elect a new managing general partner if the managing general partner
elects to withdraw from the partnership;
o remove the operator and elect a new operator;
o approve or disapprove the sale of all or substantially all of the
partnership assets;
o cancel any contract for services with the managing general partner,
the operator, or their affiliates without penalty on 60 days notice;
and
o amend the partnership agreement; provided however, any amendment may
not:
o without the approval of you or the managing general partner
increase the duties or liabilities of you or the managing general
partner or increase or decrease the profits or losses or required
capital contribution of you or the managing general partner; or
o without the unanimous approval of all investors in the
partnership affect the classification of partnership income and
loss for federal income tax purposes.
The managing general partner, its officers, directors, and affiliates may also
subscribe for units in each partnership on a discounted basis, and they may vote
on all matters other than:
o the issues set forth above concerning removing the managing general
partner and operator; and
o any transaction between the managing general partner or its affiliates
and the partnership.
Any units owned by the managing general partner and its affiliates will not be
included in determining the requisite number of units necessary to approve any
partnership matter on which the managing general partner and its affiliates may
not vote or consent.
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Access to Records
You will have access to all records of your partnership at any reasonable time
on adequate notice. However, logs, well reports, and other drilling and
operating data may be kept confidential for reasonable periods of time. Your
ability to obtain the list of investors is subject to additional requirements
set forth in the partnership agreement.
Withdrawal of Managing General Partner
After 10 years the managing general partner may voluntarily withdraw as managing
general partner of a partnership for any reason by giving 120 days' written
notice to you and the other investors in the partnership. Although the
withdrawing managing general partner is not required to provide a substitute
managing general partner, a new managing general partner may be substituted by
the affirmative vote of investors whose units equal a majority of the total
units in the partnership. If the investors, however, choose not to continue the
partnership and select a substitute managing general partner, then the
partnership would terminate and dissolve which could result in adverse tax and
other consequences to you.
Also, subject to a required participation of not less than 1% of each
partnership's revenues, the managing general partner may partially withdraw a
property interest in the partnership's wells equal to or less than its revenue
interest if the withdrawal is:
o to satisfy the bona fide request of its creditors; or
o approved by investors in the partnership whose units equal a majority
of the total units.
Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months
Although the managing general partner anticipates that each partnership will
spend all the subscription proceeds soon after the offering of the partnership
closes, each partnership will have 12 months in which to use or commit funds to
drilling activities. If within the 12-month period the partnership has not used
or committed for use all the subscription proceeds, then the managing general
partner will distribute the remaining subscription proceeds to you and the other
investors in the partnership in accordance with your subscription proceeds as a
return of capital.
SUMMARY OF DRILLING AND OPERATING AGREEMENT
The managing general partner will serve as the operator under the drilling and
operating agreement, Exhibit (II) to the partnership agreement. The operator may
be replaced at any time on 60 days' advance written notice by the managing
general partner acting on behalf of a partnership on the affirmative vote of
investors whose units equal a majority of the total units in the partnership.
You are urged not to invest in a partnership without first thoroughly reviewing
the drilling and operating agreement. The following is a summary of the material
provisions in the drilling and operating agreement that are not covered
elsewhere in this prospectus. Thus, this prospectus summarizes all of the
material provisions of the drilling and operating agreement.
The drilling and operating agreement includes a number of material provisions,
including, without limitation, those set forth below.
o The operator's right to resign after five years.
o The operator's right beginning one year after a partnership well
begins producing to retain $200 per month to cover future plugging and
abandonment costs of the well, although the managing general partner
historically has never done this after only one year.
o The grant of a first lien and security interest in the wells and
related production to secure payment of amounts due to the operator by
a partnership.
o The prescribed insurance coverage to be maintained by the operator.
105
o Limitations on the operator's authority to incur extraordinary costs
with respect to producing wells in excess of $5,000 per well.
o Restrictions on the partnership's ability to transfer its interest in
fewer than all wells unless the transfer is of an equal undivided
interest in all wells.
o The limitation of the operator's liability to a partnership except for
the operator's:
o violations of law;
o negligence or misconduct by it, its employees, agents or
subcontractors; or
o breach of the drilling and operating agreement.
o The excuse for nonperformance by the operator due to force majeure
which generally means acts of God, catastrophes and other causes which
preclude the operator's performance and are beyond its control.
REPORTS TO INVESTORS
Under the partnership agreement for each partnership you and certain state
securities commissions will be provided the reports and information set forth
below for your partnership, which your partnership will pay as a direct cost.
o Beginning with the calendar year in which your partnership closes, you
will be provided an annual report within 120 days after the close of
the calendar year, and beginning with the following calendar year, a
report within 75 days after the end of the first six months of its
calendar year, containing at least the following information.
o Audited financial statements of the partnership prepared on an
accrual basis in accordance with generally accepted accounting
principles with a reconciliation with respect to information
furnished for income tax purposes. Independent certified public
accountants will audit the financial statements to be included in
the annual report. Semiannual reports will not be audited.
o A summary of the total fees and compensation paid by the
partnership to the managing general partner, the operator, and
their affiliates, including the percentage that the annual
unaccountable, fixed payment reimbursement for administrative
costs bears to annual partnership revenues.
o A description of each prospect owned by the partnership,
including the cost, location, number of acres, and the interest.
o A list of the wells drilled or abandoned by the partnership
indicating:
o whether each of the wells has or has not been completed; and
o a statement of the cost of each well completed or abandoned.
o A description of all farmouts, farmins, and joint ventures.
o A schedule reflecting:
o the total partnership costs;
106
o the costs paid by the managing general partner and the costs
paid by the investors;
o the total partnership revenues; and
o the revenues received or credited to the managing general
partner and the revenues received or credited to you and the
other investors.
o On request the managing general partner will provide you the
information specified by Form 10-Q (if such report is required to be
filed with the SEC) within 45 days after the close of each quarterly
fiscal period. Also, this information is available at the SEC website
www.sec.gov.
o By March 15 of each year you will receive the information that is
required for you to file your federal and state income tax returns.
o Beginning with the second calendar year after your partnership closes,
and every year thereafter, you will receive a computation of the
partnership's total natural gas and oil proved reserves and its dollar
value. The reserve computations will be based on engineering reports
prepared by the managing general partner and reviewed by an
independent expert.
PRESENTMENT FEATURE
Beginning with the fifth calendar year after your partnership closes you and the
other investors in your partnership may present your units to the managing
general partner to purchase your units. However, you are not required to offer
your units to the managing general partner, and you may receive a greater return
if you retain your units. The managing general partner will not purchase less
than one unit unless the fractional unit represents your entire interest.
The managing general partner has no obligation and does not intend to establish
a reserve to satisfy the presentment obligation and may immediately suspend its
purchase obligation by notice to you if it determines, in its sole discretion,
that it:
o does not have the necessary cash flow; or
o cannot borrow funds for this purpose on terms it deems reasonable.
If fewer than all units presented at any time are to be purchased by the
managing general partner, then the units to be purchased will be selected by
lot.
The managing general partner's obligation to purchase the units presented may be
discharged for its benefit by a third-party or an affiliate. If you sell your
unit it will be transferred to the party who pays for it, and you will be
required to deliver an executed assignment of your unit along with any other
documents that the managing general partner requests. Your presentment is
subject to the following conditions:
o the managing general partner will not purchase more than 5% of the
units in a partnership in any calendar year;
o the presentment must be within 120 days of the partnership reserve
report discussed below;
o in accordance with Treas. Reg. ss.1.7704-1(f) the purchase may not be
made by the managing general partner until at least 60 calendar days
after you notify the partnership in writing of your intent to present
your unit; and
o the purchase will not be considered effective until the presentment
price has been paid to you in cash.
107
The amount attributable to a partnership's natural gas and oil reserves will be
determined based on the last reserve report. Beginning with the second calendar
year after your partnership closes and every year thereafter, the managing
general partner will estimate the present worth of future net revenues
attributable to your partnership's interest in proved reserves. In making this
estimate, the managing general partner will use:
o a 10% discount rate;
o a constant oil price; and
o base natural gas prices on the existing natural gas contracts at the
time of the presentment.
Your presentment price will be based on your share of your partnership's net
assets and liabilities as described below, based on the ratio that the number of
your units bears to the total number of units in your partnership. The
presentment price will include the sum of the following partnership items:
o an amount based on 70% of the present worth of future net revenues
from the proved reserves determined as described above;
o cash on hand;
o prepaid expenses and accounts receivable, less a reasonable amount for
doubtful accounts; and
o the estimated market value of all assets not separately specified
above, determined in accordance with standard industry valuation
procedures.
There will be deducted from the foregoing sum the following items:
o an amount equal to all debts, obligations, and other liabilities,
including accrued expenses; and
o any distributions made to you between the date of the request and the
actual payment. However, if any cash distributed was derived from the
sale, after the presentment request, of oil, natural gas, or a
producing property, for purposes of determining the reduction of the
presentment price the distributions will be discounted at the same
rate used to take into account the risk factors employed to determine
the present worth of the partnership's proved reserves.
The amount may be further adjusted by the managing general partner for estimated
changes from the date of the reserve report to the date of payment of the
presentment price to you because of the following:
o the production or sales of, or additions to, reserves and lease and
well equipment, sale or abandonment of leases, and similar matters
occurring before the presentment request; and
o any of the following occurring before payment of the presentment price
to you;
o changes in well performance;
o increases or decreases in the market price of oil, natural gas,
or other minerals;
o revision of regulations relating to the importing of
hydrocarbons; and
o changes in income, ad valorem, and other tax laws such as
material variations in the provisions for depletion; and
108
o similar matters.
As of January 1, 2003, fewer than 35 units have been presented to the managing
general partner for purchase in its previous 43 limited partnerships.
TRANSFERABILITY OF UNITS
Restrictions on Transfer Imposed by the Tax Laws and the Partnership Agreement
Your ability to sell or otherwise transfer your units in your partnership is
restricted by the securities laws, the tax laws, and the partnership agreement
as described below.
First, under the tax laws you will not be able to sell, assign, exchange, or
transfer your unit if it would, in the opinion of counsel for the partnership,
result in the following:
o the termination of your partnership for tax purposes; or
o your partnership being treated as a "publicly-traded" partnership for
tax purposes.
Second, under the partnership agreement transfers are subject to the following
limitations:
o the partnership will recognize the transfer of only one or more whole
units unless you own less than a whole unit, in which case your entire
fractional interest must be transferred;
o the costs and expenses associated with the transfer must be paid by
the person transferring the unit;
o the form of transfer must be in a form satisfactory to the managing
general partner; and
o the terms of the transfer must not contravene those of the partnership
agreement.
Your transfer of a unit will not relieve you of your responsibility for any
obligations related to the units under the partnership agreement. Also, the
transfer does not grant rights under the partnership agreement as among your
transferees to more than one party unanimously designated by the transferees to
the managing general partner. Finally, the transfer of a unit does not require
an accounting by the managing general partner. Any transfer when the assignee of
the unit does not become a substituted partner as described below in
"- Conditions to Becoming a Substitute Partner," will be effective as of:
o midnight of the last day of the calendar month in which it is made; or
o at the managing general partner's election 7:00 A.M. of the following
day.
Finally, you will not be able to sell, assign, pledge, hypothecate, or transfer
your unit if there is an opinion of counsel for the partnership that the sale,
assignment, pledge, hypothecation, or transfer would result in the violation of
any applicable federal or state securities laws.
Conditions to Becoming a Substitute Partner
Under the partnership agreement an assignee of a unit may become a substituted
partner only on meeting certain further conditions. The conditions to become a
substitute partner are as follows:
o the assignor gives the assignee the right;
o the assignee pays all costs and expenses incurred in connection with
the substitution; and
109
o the assignee executes and delivers the instruments necessary to
establish that a legal transfer has taken place and to confirm his
agreement to be bound by all terms and provisions of the partnership
agreement.
A substitute partner is entitled to all of the rights of full ownership of the
assigned units, including the right to vote. Each partnership will amend its
records at least once each calendar quarter to effect the substitution of
substituted partners.
PLAN OF DISTRIBUTION
Commissions
The units of preformation limited and general partnership interest in each
partnership will be offered on a "best efforts" basis by Anthem Securities,
which is an affiliate of the managing general partner, acting as dealer- manager
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. 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.
The dealer-manager will manage and oversee the offering of the units as
described above. Best efforts generally means that the dealer-manager and
selling agents will not guarantee that a certain number of units will be sold.
Units may also be sold by the officers and directors of the managing general
partner in those states where they are licensed or exempt from licensing.
Messrs. Kotek and Patel and Ms. Bleichmar, who are associated with Anthem
Securities, will not make any offers or sales under the SEC safe harbor from
broker/dealer registration provided by SEC Rule 3a4-1 promulgated under the
Securities Exchange Act of 1934 (the "Act"), although they may do so as
associated persons of Anthem Securities. Also, all offers and sales of units by
the managing general partner's remaining officers and directors will be made
under the SEC safe harbor from broker/dealer registration provided by Rule
3a4-1. In this regard, none of the remaining officers and directors of the
managing general partner:
o is subject to a statutory disqualification, as that term is defined in
Section 3(a)(39) of the Act, at the time of his participation;
o is compensated in connection with his participation by the payment of
commissions or other remuneration based either directly or indirectly
on transactions in securities; and
o is at the time of his participation an associated person of a broker
or dealer.
Also, each of the remaining officers and directors:
o performs, or is intended primarily to perform at the end of the
offering, substantial duties for or on behalf of the managing general
partner otherwise than in connection with transactions in securities;
o was not a broker or dealer, or an associated person of a broker or
dealer, within the preceding 12 months; and
o will not participate in selling an offering of securities for any
issuer more than once every 12 months, with the understanding that for
securities issued pursuant to Rule 415 under Securities Act of 1933,
the 12 month period begins with the last sale of any security included
within one Rule 415 registration.
Subject to the exceptions described below, the dealer-manager will receive on
each unit sold:
o a 2.5% dealer-manager fee;
110
o a 7% sales commission;
o a .5% accountable marketing expense fee; and
o a .5% reimbursement of the selling agent's bona fide accountable due
diligence expenses.
All of the 7% sales commissions and the .5% reimbursement of the selling agents'
bona fide accountable due diligence expenses will be reallowed to the selling
agents, but only a portion of the .5% accountable marketing expense fee may be
reallowed to the selling agents. The dealer-manager will retain any of the
accountable marketing expense fee not reallowed to the selling agents.
The managing general partner is also using the services of wholesalers who are
employed by it or its affiliates and are registered through Anthem Securities.
The wholesalers include four Regional Marketing Directors, Mr. Mark Levy, Mr.
Bruce Bundy, Mr. Robert Gourlay and Ms. Vicki Burbridge. Of the 2.5% dealer-
manager fee, most of it will be reallowed to the affiliated Regional Marketing
Directors for subscriptions obtained through their efforts. The dealer-manager
will retain the remainder of the dealer-manager fee not reallowed to the
wholesalers.
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
..5% reimbursement for bona fide accountable due diligence expenses on each
subscription. Also, the offering will be made in compliance with Rule
2810(b)(2)(C) of the NASD Conduct Rules and the broker/dealers and wholesalers
will not execute a transaction for the purchase of units in a discretionary
account without the prior written approval of the transaction by the customer.
Finally, although not anticipated, if the dealer-manager assists in the transfer
of units then it will comply with Rule 2810(b)(3)(D) of the NASD Conduct Rules.
Subject to the following, you and the other investors will pay $10,000 per unit
and generally will share costs, revenues, and distributions in the partnership
in which you subscribe in proportion with your respective number of units.
However, the subscription price for certain investors will be reduced as set
forth below:
o the subscription price for the managing general partner, its officers,
directors, and affiliates, and investors who buy units through the
officers and directors of the managing general partner, will be
reduced by an amount equal to the 2.5% dealer-manager fee, the 7%
sales commission, the .5% reimbursement for accountable due diligence
expenses and the .5% accountable marketing expense fee, regardless of
the partnership in which they subscribe, which will not be paid with
respect to these sales; and
o the subscription price for registered investment advisors and their
clients, and selling agents and their registered representatives and
principals, will be reduced by an amount equal to the 7% sales
commission, which will not be paid with respect to these sales.
No more than 5% of the total units in each partnership may be sold with the
discounts described above.
These investors who pay a reduced price for their unit generally will share in
the partnership's costs, revenues, and distributions of the partnership on the
same basis as the other investors even though they pay a reduced price for their
units. Although the managing general partner and its affiliates may buy up to
10% of the units, they do not currently anticipate buying any units. If they do
buy units, then those units will not be applied towards the minimum subscription
proceeds required for a partnership to begin operations.
After the minimum subscriptions are received in a partnership and the checks
have cleared the banking system, the dealer-manager fee, the sales commissions,
the .5% accountable marketing expense fee and the .5% reimbursement for
accountable due diligence expenses will be paid to the dealer-manager and
broker/dealers approximately every two weeks until the offering closes.
111
Indemnification
The dealer-manager is an underwriter as that term is defined in the 1933 Act and
the sales commissions and dealer-manager fees will be deemed underwriting
compensation. The managing general partner and the dealer-manager have agreed to
indemnify each other, and it is anticipated that the dealer-manager and each
selling agent will agree to indemnify each other against certain liabilities,
including liabilities under the 1933 Act.
SALES MATERIAL
In addition to the prospectus the managing general partner intends to use the
following sales material with the offering of the units:
o a flyer entitled "Atlas America Public #12-2003 Program";
o an article entitled "Tax Rewards with Oil and Gas Partnerships";
o a brochure of tax scenarios entitled "How an Investment in Atlas
America Public #12-2003 Program Can Help Achieve an Investor's Tax
Objectives";
o a brochure entitled "Investing in Atlas America Public #12-2003
Program";
o a booklet entitled "Outline of Tax Consequences of Oil and Gas
Drilling Programs"; and
o possibly other supplementary materials.
The managing general partner has not authorized the use of other sales material
and the offering of units is made only by means of this prospectus. The sales
material is subject to the following:
o it must be preceded or accompanied by this prospectus;
o it is not complete;
o it will not contain any material information which is not also set
forth in the prospectus; and
o it should not be considered a part of or incorporated into this
prospectus or the registration statement of which this prospectus is a
part.
In addition, supplementary materials, including prepared presentations for group
meetings, must be submitted to the state administrators before they are used and
their use must either be preceded by or accompanied by a prospectus. Also, all
advertisements of, and oral or written invitations to, "seminars" or other group
meetings at which the units are to be described, offered, or sold will clearly
indicate the following:
o that the purpose of the meeting is to offer the units for sale;
o the minimum purchase price of the units;
o the suitability standards to be employed; and
o the name of the person selling the units.
112
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 the registered representatives of
the selling agents.
You should rely only on the information contained in this prospectus in making
your investment decision. No one is authorized to provide you with information
that is different.
LEGAL OPINIONS
Kunzman & Bollinger, Inc., has issued its opinion to the managing general
partner regarding the validity and due issuance of the units including
assessibility and its opinion on material tax consequences to individual typical
investors in the partnerships. 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 have been audited by Grant Thornton LLP, as of the date indicated in its
report which appears elsewhere in this prospectus. The financial statements have
been included in reliance on its report given on its authority as an expert in
auditing and accounting.
The geologic evaluation for each of the areas where potential prospects have
been identified 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 on 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 reserve and
economic report effective September 30, 2002 relating to the 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 partnerships are subject or may be a
party, which it believes would have a material adverse effect on the
partnerships or their business, and no such proceedings are known to be
contemplated by governmental authorities or other parties.
FINANCIAL INFORMATION CONCERNING THE MANAGING
GENERAL PARTNER
Financial information concerning 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 in which you purchase units.
113
Consolidated audit report
Atlas Resources, Inc. and Subsidiary
September 30, 2002 and 2001
114
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Board of Directors
ATLAS RESOURCES, INC.
We have audited the accompanying consolidated balance sheets of ATLAS RESOURCES,
INC. (a Pennsylvania corporation) and subsidiary as of September 30, 2002 and
2001, and the related consolidated statements of income, comprehensive income,
changes in stockholder's equity and cash flows for the years then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with 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 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 financial position of ATLAS RESOURCES,
INC. and subsidiary as of September 30, 2002 and 2001, and the results of their
operations and their cash flows for the years then ended, in conformity with
accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, effective October 1, 2001,
the Company changed its method of accounting for goodwill for the adoption of
SFAS No. 142.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
November 22, 2002
115
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2002 AND 2001
2002 2001
-------- -------
(in thousands,
except share data)
ASSETS
Current assets:
Cash and cash equivalents ............................... $ 698 $ 5,358
Accounts receivable ..................................... 5,419 5,207
Other current assets .................................... 320 298
-------- -------
Total current assets................................... 6,437 10,863
Property and equipment:
Oil and gas properties and equipment (successful
efforts)................................................ 59,757 44,445
Buildings and land ...................................... 2,830 2,830
Other ................................................... 394 392
-------- -------
62,981 47,667
Less - accumulated depreciation, depletion and
amortization............................................ (10,995) (6,777)
-------- -------
Net property and equipment .............................. 51,986 40,890
Goodwill ................................................. 20,868 14,479
Intangible assets ........................................ 4,400 11,278
-------- -------
Total assets........................................... $ 83,691 $77,510
======== =======
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Accounts payable ........................................ $ 3,272 $ 2,901
Deferred revenue on drilling contracts .................. 4,948 17,928
Accrued liabilities ..................................... 108 83
Advances and note from Parent ........................... 51,054 32,895
-------- -------
Total current liabilities.............................. 59,382 53,807
Commitments and contingencies ............................ -- --
Stockholder's equity:
Common stock, stated value $10 per share;
500 authorized shares; 200 shares issued and
outstanding............................................. 2 2
Additional paid-in capital .............................. 16,505 16,505
Accumulated other comprehensive (loss) income ........... (212) 10
Retained earnings ....................................... 8,014 7,186
-------- -------
Total stockholder's equity............................. 24,309 23,703
-------- -------
$ 83,691 $77,510
======== =======
See accompanying notes to consolidated financial statements
116
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2002 AND 2001
2002 2001
---- ----
(in thousands)
REVENUES
Well drilling ............................................. $49,516 $32,617
Gas and oil production .................................... 10,056 10,622
Well services ............................................. 5,758 4,431
Other ..................................................... 154 61
------- -------
65,484 47,731
COSTS AND EXPENSES
Well drilling ............................................. 42,996 26,842
Gas and oil production and exploration .................... 2,178 1,716
Well services ............................................. 1,108 918
Non-direct ................................................ 11,122 10,850
Depreciation, depletion and amortization .................. 4,595 4,225
Interest .................................................. 2,522 1,997
------- -------
64,521 46,548
------- -------
Income before income taxes ................................ 963 1,183
Provision for income taxes ................................ 135 455
------- -------
Net income ................................................ $ 828 $ 728
======= =======
See accompanying notes to consolidated financial statements
117
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
YEARS ENDED SEPTEMBER 30, 2002 AND 2001
(in thousands, except share data)
Common Stock Additional Accumulated Total
--------------- Paid-In Comprehensive Retained Stockholder's
Shares Amount Capital Income (Loss) Earnings Equity
-------------------------------------------------------------------------
Balance, September 30, 2000 .......................... 200 $2 $16,505 $ -- $6,458 $22,965
Other comprehensive income ........................... 10 10
Net income ........................................... 728 728
------ ------ ---------- ------------- -------- -------------
Balance, September 30, 2001 .......................... 200 2 16,505 10 7,186 23,703
Other comprehensive loss ............................. (222) (222)
Net income ........................................... 828 828
------ ------ ---------- ------------- -------- -------------
Balance September 30, 2002 ........................... 200 $2 $16,505 $(212) $8,014 $24,309
====== ====== ========== ============= ======== =============
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2002 AND 2001
2002 2001
----- -----
(in thousands)
Net income .................................................... $ 828 $ 728
Cumulative effect of accounting change, net of taxes of $145 .. -- 241
Derivative losses reclassed into gas production net of taxes
of $145...................................................... -- (241)
Unrealized (loss) gain on natural gas futures and option
contracts, net of taxes of $105 and $(5)..................... (222) 10
----- -----
Comprehensive income .......................................... $ 606 $ 738
===== =====
See accompanying notes to consolidated financial statements
118
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2002 AND 2001
2002 2001
---- ----
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................... $ 828 $ 728
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization ................ 4,595 4,225
License fees and interest on intercompany note due to
Parent.................................................. 12,399 8,042
Change in operating assets and liabilities:
Increase in accounts receivable ......................... (212) (7,387)
(Increase) decrease in other current assets ............. (22) 77
Decrease in accounts payable and accrued liabilities .... (1,005) (309)
(Decrease) increase in deferred revenue on drilling
contracts............................................... (12,711) 9,981
-------- -------
Net cash provided by operating activities ................ 3,872 15,357
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ..................................... (14,757) (9,072)
Decease in other assets .................................. -- 20
-------- -------
Net cash used in investing activities .................... (14,757) (9,052)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings ......................... -- (341)
Net advances from (payments to) Parent ................... 6,225 (3,667)
-------- -------
Net cash provided by (used in) financing activities ...... 6,225 (4,008)
-------- -------
Increase (decrease) in cash and cash equivalents ......... (4,660) 2,297
Cash and cash equivalents at beginning of year ........... 5,358 3,061
-------- -------
Cash and cash equivalents at end of year ................. $ 698 $ 5,358
======== =======
See accompanying notes to consolidated financial statements
119
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF OPERATIONS
Atlas Resources, Inc. (the "Company"), a Pennsylvania corporation, and its
subsidiary, ARD Investments, are engaged in the exploration for development and
production of natural gas and oil primarily in the Appalachian Basin Area. In
addition, the Company performs contract drilling and well operation services.
The Company is a second-tier wholly-owned subsidiary of Atlas America, Inc.
(Atlas). Atlas is a second-tier wholly-owned subsidiary of Resource America,
Inc.(RAI), a publicly traded company (trading under the symbol REXI on the
NASDAQ System) operating in the energy, real estate and financial services
sectors. The Company's operations are dependent upon the resources and services
provided by Atlas. The Company is also the managing general partner of several
oil and gas partnerships.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Reclassifications
Certain reclassifications have been made to the fiscal 2001 consolidated
financial statements to conform with the fiscal 2002 presentation.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary. The Company also owns individual interests in
the assets and is separately liable for its share of liabilities of oil and gas
partnerships, whose activities include only exploration and production
activities. In accordance with established practice in the oil and gas industry,
the Company also includes its pro-rata share of income and expenses of the oil
and gas partnerships in which it has an interest. All material intercompany
transactions have been eliminated.
Use of Estimates
Preparation of the financial statements in conformity with accounting
principles generally accepted in the United States of America, requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and 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 these
estimates.
Concentration of Credit Risk
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of periodic temporary
investments of cash. The Company places its temporary cash investments in high
quality short-term money market instruments and deposits with high quality
financial institutions and brokerage firms. At September 30, 2002 and 2001, the
Company had $698,000 and $5.3 million in deposits at various banks,
respectively, of which $601,000 and $5.2 million is over the insurance limit of
the Federal Deposit Insurance Corporation. No losses have been experienced on
such investments.
120
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Oil and Gas Properties
The Company follows the successful efforts method of accounting.
Accordingly, property acquisition costs, costs of successful exploratory wells,
all development costs, and the cost of support equipment and facilities are
capitalized. Costs of unsuccessful exploratory wells are expensed when such
wells are determined to be nonproductive or within twelve months of completion
of drilling if this determination cannot be made. The costs associated with
drilling and equipping wells not yet completed are capitalized as uncompleted
wells, equipment, and facilities. Geological and geophysical costs and the costs
of carrying and retaining undeveloped properties, including delay rentals, are
expensed as incurred. Production costs, overhead and all exploration costs other
than the costs of exploratory drilling are charged to expense as incurred.
The Company assesses unproved and proved properties periodically to
determine whether there has been a decline in value and, if such decline is
indicated a loss is recognized. The assessment of significant unproved
properties for impairment is on a property-by-property basis. The Company
considers whether a dry hole has been drilled on a portion of the property or in
close proximity, the Company's intentions of further drilling, the remaining
lease term of the property, and its experience in similar fields in close
proximity. The Company assesses unproved properties whose costs are individually
insignificant in the aggregate, this assessment includes considering the
Company's experience of similar situations, the primary lease terms, the average
holding period of unproved properties and the relative proportion of such
properties on which proved reserves have been found in the past.
The Company compares the carrying value of its proved developed gas and oil
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 during any of the fiscal years in
the two year period ended September 30, 2002.
Upon the sale or retirement of a complete or partial unit of a proved
property, the cost and related accumulated depletion are eliminated from the
property accounts, and the resultant gain or loss is recognized in the statement
of operations. Upon the sale of an entire interest in an unproved property where
the property had been assessed for impairment individually, a gain or loss is
recognized in the statement of operations. If a partial interest in an unproved
property is sold, any funds received are accounted for as a reduction of the
cost in the interest retained.
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 estimates the salvage value of
equipment recoverable upon abandonment. At both September 30, 2002 and 2001, the
Company's estimate of equipment salvage values was greater than or equal to the
estimated costs of future dismantlement, restoration, reclamation, and
abandonment.
121
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Revenue Recognition
The Company conducts certain energy activities through, and a portion of
its revenues are attributable to, sponsored limited partnerships
("Partnerships"). These Partnerships raise money from investors to drill gas and
oil wells. 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 income from the Company's general partner interest is
recorded when the gas and oil are sold by a Partnership.
The Company also contracts to drill gas and oil wells owned by the
Partnerships. The income from a drilling contract relating to a well is recorded
upon substantial completion of the well for turnkey contracts and as services
are performed for cost-plus contracts. Turnkey contracts are accounted for under
the completed contract method. Contracts are considered substantially complete
when remaining costs and potential risks are insignificant in amount. The
Company determines this on a well-by-well basis to be when the surface equipment
has been installed on the well. For contracts forwhich revenue is recognized as
services are performed, the Company uses the value added method (contract value
of total work performed at any reporting date) for measuring progress toward the
completion of the drilling contract.
The Company recognizes transportation revenues at the time the natural gas
is delivered to the purchaser.
The Company recognizes field services revenues at the time the services are
performed.
The Company is entitled to receive management fees according to the
respective Partnership agreements. The Company recognizes such fees as income
when earned and includes them in energy revenues.
The Company sells interests in gas and oil wells and retains a working
interest and/or overriding royalty. The Company records the income from the
working interests and overriding royalties when the gas and oil are sold.
Depreciation, Depletion and Amortization
The Company amortizes proved gas and oil properties, which include
intangible drilling and development costs, tangible well equipment and leasehold
costs, on the unit-of-production method using the ratio of current production to
the estimated aggregate proved gas and oil reserves.
Environmental Matters
The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Company has
established procedures for the ongoing evaluation of its operations, to identify
potential environmental exposures and to comply with regulatory policies and
procedures.
The Company accounts for environmental contingencies in accordance with
SFAS No. 5 "Accounting for Contingencies." Environmental expenditures that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable, and the costs can be reasonably estimated. The Company maintains
insurance which may cover in whole or in part certain environmental
expenditures. For the years ended September 30, 2002 and 2001, the Company had
no environmental matters requiring specific disclosure or requiring recording of
a liability.
122
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Property and Equipment
Property and equipment, other than oil and gas properties, are stated at
cost. Depreciation is provided using the straight-line method over the following
estimated useful lives once the asset is put into productive use:
Buildings ........................................................ 39 years
Other equipment .................................................. 3 - 7 years
Intangible Assets and Goodwill - Change in Accounting Principle
On October 1, 2001, the Company adopted SFAS 142, "Goodwill and Other
Intangible Assets", which requires that goodwill no longer be amortized, but
instead tested for impairment at least annually. At that time the Company had
unamortized goodwill of $14.5 million. The Company has completed the
transitional impairment test required upon adoption of SFAS 142. The
transitional test, which involved the use of estimates related to the fair
market value of the business operations associated with the goodwill did not
indicate an impairment loss. The Company will continue to evaluate its goodwill,
at least annually, and will charge operations for the impairment of goodwill, if
any, in the period in which it is indicated.
Changes in the carrying amount of goodwill for the year ended September 30,
2002 are as follows:
Year Ended
-----------------
2002 2001
------- -------
(in thousands)
Goodwill at beginning of year
(less accumulated amortization of $1,609 and $1,073)..... $14,479 $15,015
Amortization of Goodwill .................................. -- (536)
Syndication network reclassified from other assets
in accordance with SFAS 142 (net of accumulated
amortization of $711).................................... 6,389 --
------- -------
Goodwill at end of year
(net of accumulated amortization of $2,320 and $1,609)... $20,868 $14,479
======= =======
For the year ended September 30, 2001 the Company's goodwill amortization
expense was approximately $536,000. Adjusted net income for the year ended
September 30, 2001 would have been $1.1 million assuming the Company had adopted
SFAS 142 effective October 1, 2001.
Intangible assets relate primarily to partnership management and operating
contracts acquired through acquisitions. The Company amortizes contracts
acquired on a straight line method over their respective estimated lives,
ranging from five to thirteen years. Amortization expense for the years ended
September 30, 2002 and 2001 were $489,000 and $478,000 respectively. The annual
amortization expense is approximately $478,000 for each of the succeeding five
years.
Years Ended
-----------------
September 30,
-----------------
2002 2001
------- -------
(in thousands)
Intangible assets
Operating and management contracts ....................... $ 6,353 $ 6,353
Syndication rights ....................................... -- 7,100
------- -------
6,353 13,453
Accumulated amortization ................................. (1,953) (2,175)
------- -------
$ 4,400 $11,278
======= =======
123
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT 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.
Comprehensive Income
Comprehensive income includes net income and all other changes in the
equity of a business during a period from transactions and other events and
circumstances from non-owner sources. These changes, other than net income, are
referred to as "other comprehensive income" and for the Company represents
unrealized hedging gains and losses.
Deferred Revenue on Drilling Contracts
Funds received that are in excess of costs incurred are classified as a
current liability under deferred revenue on drilling 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.
Income Taxes
The Company is included in the consolidated federal income tax return of
RAI. Income taxes are presented as if the Company had filed a return on a
separate company basis utilizing their calculated effective rate of 14% and 38%
for fiscal years 2002 and 2001 respectively. The Company's effective tax rate
for fiscal 2002 is lower than the federal statutory rate due to the benefit of
percentage depletion and fuel credits. The decrease in the Company's effective
tax rate is due to goodwill no longer being amortized and increases in statutory
depletion and fuel credits for income tax purposes. Deferred taxes, which are
included in Advances from Parent, reflect the tax effect of temporary
differences between the tax basis of the Company's assets and liabilities and
the amounts reported in the financial statements. Separate company state tax
returns are filed in those states in which the Company is registered to do
business.
Fair Value of Financial Instruments
The following methods and assumptions were used by the Company in estimating
the fair value of each class of financial instruments for which it is
practicable to estimate fair value.
For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments.
In fiscal 2001, the Company adopted FASB Statement No. 133, "Accounting for
Derivative Instruments and Hedging Activities". Accordingly, natural gas futures
and option contracts are recorded at fair value in the Company's consolidated
balance sheet.
124
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Supplemental Disclosure of Cash Flow Information
The Company considers temporary investments with maturity at the date of
acquisition of 90 days or less to be cash equivalents.
Years Ended
-------------
September 30,
-------------
2002 2001
------ -----
(in thousands)
Cash paid during the year for:
Interest ..................................................... $114 $ 96
Income taxes (net of refund) ................................... $ -- $209
Recently Issued Financial Accounting Standard
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143
establishes requirements for accounting for removal costs associated with asset
retirements. SFAS 143 is effective for fiscal years beginning after June 15,
2002, and will require the Company to record a liability for its retirement
obligations with the related transition adjustment reported as a cumulative
effect of a change in accounting principle. The Company is currently assessing
the impact of this standard on its consolidated financial statements.
NOTE 3 - RELATED PARTIES
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.
The advances from Parent represent amounts owed for advances and
transactions in the normal course of business and a note payable to the parent.
Other than the note, these advances have no repayment terms and are subordinated
to any third-party debt. The note, which is also subordinated to any third-party
debt, has a face amount of $15.0 million and accrues interest at an annual rate
of 9.50% on any unpaid balances. The principal and any unpaid interest are due
upon demand by the Parent. Interest expense related to the note, which is being
deferred, was $1.9 million and $1.6 million for the years ended September 30,
2002 and 2001 respectively. The advances have no repayment terms and the note is
due on demand. Therefore the Company has classified the amounts due the Parent
as a current liability on its Consolidated Balance Sheets. The Parent does not
intend to demand payment on the advances or note within the next year.
The Company is dependant on its' Parent for management and administrative
functions and financing for capital expenditures. The Company pays a management
fee to its Parent for management and administrative services, which amounted to
$10.5 million and $6.4 million for the years ended September 30, 2002 and 2001,
respectively.
125
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 4 - COMMITMENTS AND CONTINGENCIES
The Company is the managing general partner in several oil and gas limited
partnerships and has agreed to indemnify each investor 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 the
Company.
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 will determine the
purchase price in accordance with the respective partnership agreement. The
Company is not obligated to purchase more than 5% or 10% of the units in any
calendar year. Based on past experience, the Company believes that any liability
incurred would not be material.
The Company may be required to subordinate a part of its net partnership
revenues to the receipt by investor partners of cash distributions from the
Partnership equal to at least 10% of their agreed subscriptions determined on a
cumulative basis, in accordance with the terms of the partnership agreement.
The Company is also party to various routine legal proceedings arising out
of the ordinary course of its business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on the Company's financial condition or operations.
In July 2002, the Company's parent (Atlas), entered into a $75.0 million
credit facility led by Wachovia Bank. The revolving credit facility has an
initial borrowing base of $45.0 million which may be increased subject to growth
in Atlas' oil and gas reserves. The facility permits draws based on the
remaining proved developed non-producing and proved undeveloped natural gas and
oil reserves attributable to Atlas' wells and the projected fees and revenues
from operation of the wells and the administration of partnerships. Up to $10.0
million of the facility may be in the form of standby letters of credit. The
facility is secured by Atlas' assets, including those of the Company. The
revolving credit facility has a term ending in July 2005 and bears interest at
one of two rates (elected at the borrower's option) which increase as the amount
outstanding under the facility increases: (i) Wachovia prime rate plus between
25 to 75 basis points, or (ii) LIBOR plus between 175 and 225 basis points. The
credit facility contains financial covenants, including covenants requiring
Atlas and RAI to maintain specified financial ratios, and imposes the following
limits: (a) the amount of debt that can be incurred cannot exceed specified
levels without the banks' consent; and (b) the energy affiliates may not sell,
lease or transfer property without the banks' consent. This credit facility was
used to pay off the previous energy revolving credit facility at PNC Bank. At
September 30, 2002, $45.0 million was outstanding under this facility, including
$43.7 in outstanding borrowings at interest rates ranging from 3.54% to 5.0% and
$1.3 million under letters of credit. The Company owed no amounts due under this
facility.
126
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 5 - HEDGING ACTIVITIES
The Company enters into natural gas futures and option contracts to hedge
its exposure to changes in natural gas prices. At any point in time, such
contracts may include regulated New York Mercantile Exchange ("NYMEX") futures
and options contracts and non-regulated over-the-counter futures contracts with
qualified counterparties. NYMEX contracts are generally settled with offsetting
positions, but may be settled by the delivery of natural gas.
Effective October 1, 2000, the Company adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," (as amended by SFAS 138).
This statement establishes accounting and reporting standards for derivative
instruments and hedging activities. The statement requires that all derivative
financial statements are recognized in the financial statements as either assets
or liabilities measured at fair value. Changes in the fair value of derivative
financial instruments are recognized in income or other comprehensive income,
depending on their classification. Upon adoption of SFAS 133, the Company did
not incur any transition adjustments to earnings.
The Company formally documents all relationships between hedging
instruments and the items being hedged, including the Company's risk management
objective and strategy for undertaking the hedging transactions. This includes
matching the natural gas futures and options contracts to the forecasted
transactions. The Company assesses, both at the inception of the hedge and on an
ongoing basis, whether the derivatives are highly effective in offsetting
changes in fair value of hedged items. When it is determined that a derivative
is not highly effective as a hedge or it has ceased to be a highly effective
hedge, due to the loss of correlation between changes in gas reference prices
under a hedging instrument and actual gas prices the Company will discontinue
hedge accounting for the derivative and further changes in fair value for the
derivative will be recognized immediately into earnings. Any gains or losses
that were accumulated in other comprehensive income (loss) will be recognized in
earnings when the hedged transaction is recognized in earnings.
At September 30, 2002, the Company had 267 open natural gas futures
contracts related to natural gas sales covering 747,600 dekatherm ("Dth") (net
to the Company) maturing through September 2003 at a combined average settlement
price of $3.58 per Dth. The fair value of the open natural gas futures
contracts, $2,995,100 at September 30, 2002, is based on quoted market prices.
As these contracts qualify and have been designated as cash flow hedges, any
gains or losses resulting from market price changes are deferred and recognized
as a component of sales revenues in the month the gas is sold. Gains or losses
on futures contracts are determined as the difference between the contract price
and a reference price, generally prices on NYMEX. The Company's net unrealized
loss related to open NYMEX contracts was approximately $316,600 at September 30,
2002 and its net unrealized gain was approximately $15,000 at September 30,
2001. The unrealized loss of $218,400 net of taxes of $98,200, at September 30,
2002 has been recorded as a liability in the Company's 2002 Consolidated
Financial Statements and in Stockholders' Equity as a component of Other
Comprehensive Income (loss). The Company recognized a loss of $59,000 and
$599,000 on settled contracts covering natural gas production for the years
ended September 30, 2002 and 2001, respectively. As of September 30, 2002, all
of the deferred net losses on derivative instruments included in accumulated
other comprehensive income (loss) are expected to be reclassified to earnings
during the next twelve months. The Company recognized no gains or losses during
the fiscal year ended September 30, 2002 for hedge ineffectiveness or as a
result of the discontinuance of cash flow hedges.
Although hedging provides the Company some protection against falling
prices, these activities could also reduce the potential benefits of price
increases, depending upon the instrument.
NOTE 6 - MAJOR CUSTOMERS
During both fiscal 2002 and 2001 one purchaser, First Energy Solutions
Corporation, accounted for 17% of total revenues.
127
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 7 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Results of operations for oil and gas producing activities:
Years Ended September 30,
-------------------------
2002 2001
------ ------
(in thousands)
Revenues .............................................. $10,056 $10,622
Production costs ...................................... (1,543) (1,315)
Exploration expenses .................................. (635) (401)
Depreciation, depletion, and amortization ............. (3,949) (2,937)
------- -------
Results of operations producing activities ............ $ 3,929 $ 5,969
======= =======
Capitalized Costs Related to Oil and Gas Producing Activities. The
components of capitalized costs related to the Company's oil and gas producing
activities are as follows:
Years Ended September 30,
------------------------
2002 2001
------ ------
(in thousands)
Proved properties .................................... $ 59,735 $44,320
Unproved properties .................................. 22 125
-------- -------
59,757 44,445
Accumulated depreciation, depletion, amortization and
valuation allowances................................ (10,506) (6,456)
-------- -------
Net capitalized costs .............................. $ 49,251 $37,989
======== =======
Costs Incurred in Oil and Gas Producing Activities. The costs incurred by
the Company in its oil and gas activities during fiscal years 2002 and 2001 are
as follows:
Years Ended September 30,
-------------------------
2002 2001
------ ------
(in thousands)
Property acquisition costs:
Unproved properties .................................. $ 4 $ 68
Proved properties .................................... $ 1 $ --
Exploration costs ..................................... $ 635 $ 401
Development costs ..................................... $14,243 $12,165
The development costs above for the years ended September 30, 2002 and 2001
were substantially all incurred for the development of proved undeveloped
properties.
128
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 7 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)
Oil and Gas Reserve Information (Unaudited). The estimates of the Company's
proved and unproved gas reserves are based upon evaluations made by management
and verified by Wright & Company, Inc., an independent petroleum engineering
firm, as of September 30, 2002 and 2001. All reserves are located within the
United States. Reserves are estimated in accordance with guidelines established
by the Securities and Exchange Commission and the Financial Accounting Standards
Board which require that reserve estimates be prepared under existing economic
and operating conditions with no provision for price and cost escalation except
by contractual arrangements.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e. prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangement, but not on
escalations based upon future conditions.
o Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation tests. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contracts, if any; and (b)
the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
o Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the
,,proved,, classification when successful testing by a pilot project, or
the operation of an installed program in the reservoir, provides support
for the engineering analysis on which the project or program was based.
o Estimates of proved reserves do not include the following: (a) oil that may
become available from known reservoirs but is classified separately as
,,indicated additional reservoirs,,; (b) crude oil, natural gas, and
natural gas liquids, the recovery of which is subject to reasonable doubt
because of uncertainty as to geology, reservoir characteristics or economic
factors; (c) crude oil, natural gas and natural gas liquids, that may occur
in undrilled prospects; and (d) crude oil and natural gas, and natural gas
liquids, that may be recovered from oil shales, coal, gilsonite and other
such sources.
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operation
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
There are numerous uncertainties inherent in estimating quantities of
proven reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates only
and should not be construed as being exact. In addition, the standardized
measures of discounted future net cash flows may not represent the fair market
value of the Company's oil and gas reserves or the present value of future cash
flows of equivalent reserves, due to anticipated future changes in oil and gas
prices and in production and development costs and other factors for which
effects have not been proved.
129
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 7 - 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.
Gas Oil
----- ------
(mcf) (bbls)
----- ------
Balance September 30, 2000 ............................ 70,198,510 3,747
Current additions .................................... 17,808,029 65,692
Transfers to limited partnerships .................... (11,871,230) -
Revisions ............................................ (2,054,459) 15,978
Production ........................................... (2,137,286) (2,885)
----------- -------
Balance September 30, 2001 ............................ 71,943,564 82,532
=========== =======
Current additions .................................... 17,855,966 43,089
Transfers to limited partnerships and Parent's
affiliate............................................ (7,396,491) (65,692)
Revisions ............................................ (5,321,048) (1,876)
Production ........................................... (2,944,605) (3,505)
----------- -------
Balance September 30, 2002 ............................ 74,137,386 54,548
=========== =======
Proved developed reserves at
September 30, 2002 ................................... 36,250,709 23,162
September 30, 2001 ................................... 34,075,205 16,840
The following schedule presents the standardized measure of estimated
discounted future net cash flows relating to proved oil and gas reserves. The
estimated future production is priced at year-end prices, adjusted only for
fixed and determinable increases in natural gas prices provided by contractual
agreements. The resulting estimated future cash inflows are reduced by estimated
future costs to develop and produce the proved reserves based on year-end cost
levels. The future net cash flows are reduced to present value amounts by
applying a 10% discount factor. The standardized measure of future cashflows was
prepared using the prevailing economic conditions existing at September 30, 2002
and 2001 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.
130
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 7 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)
Years Ended September 30,
-------------------------
2002 2001
------ ------
(in thousands)
Future cash inflows ................................. $288,574 $288,802
Future production costs ............................. (63,697) (52,223)
Future development costs ............................ (54,060) (50,873)
Future income tax expenses .......................... (41,694) (45,260)
-------- --------
Future net cash flows ............................... 129,123 140,446
Less 10% annual discount for estimated timing of
cash flows......................................... (80,521) (87,206)
-------- --------
Standardized measure of discounted future net
cash flow $ 48,602 $ 53,240
======== ========
The future cash flows estimated to be spent to develop proved undeveloped
properties in the years ended September 30, 2003 and 2004 are $27.3 million and
$26.8 million, respectively.
The following table summarizes the changes in the standardized measure of
discounted future net cash flows from estimated production of proved oil and gas
reserves after income taxes.
Years Ended September 30,
-------------------------
2002 n 2001
------ ------
(in thousands)
Balance, beginning of year ............................ $53,240 $45,083
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related
costs (8,513) (9,307)
Net changes in prices and production costs .......... (6,038) (7,129)
Revisions of previous quantity estimates ............ (5,633) (3,007)
Development costs incurred .......................... 3,555 4,002
Changes in future development costs ................. (149) (853)
Transfers to limited partnerships and Parent's affiliat (4,047) (5,596)
Extensions, discoveries, and improved recovery less
related costs...................................... 11,049 16,982
Accretion of discount ............................... 6,653 6,788
Net changes in future income taxes .................. 1,107 9,503
Other ............................................... (2,622) (3,226)
------- -------
Balance, end of year .................................. $48,602 $53,240
======= =======
131
Consolidated Financial Statements
(unaudited)
Atlas Resources, Inc. and Subsidiary
March 31, 2003
132
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
MARCH 31, 2003 AND SEPTEMBER 30, 2002
(in thousands, except share data)
March 31, September 30,
2003 2002
----------- ---------
(Unaudited) (Audited)
ASSETS
Current assets:
Cash and cash equivalents .......................... $ 4,013 $ 698
Accounts and notes receivable ...................... 5,999 5,419
Other current assets ............................... 308 320
-------- --------
Total current assets.............................. 10,320 6,437
Property and equipment:
Oil and gas properties and equipment (successful
efforts)........................................... 72,648 59,757
Buildings and land ................................. 2,830 2,830
Other .............................................. 411 394
-------- --------
75,889 62,981
Less - accumulated depreciation, depletion and
amortization....................................... (13,883) (10,995)
-------- --------
Net property and equipment ......................... 62,006 51,986
Goodwill ............................................ 20,868 20,868
Operating and management contracts
(less accumulated amortization of $2,152 and
$1,953)............................................ 4,201 4,400
-------- --------
Total assets...................................... $ 97,395 $ 83,691
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt .................. $ 60 $ -
Accounts payable and accrued liabilities ........... 9,605 3,380
Deferred revenue on drilling contracts ............. 9,035 4,948
Advances and note from Parent ...................... 50,808 51,054
-------- --------
Total current liabilities......................... 69,508 59,382
Long-term debt ...................................... 162 -
Asset retirement obligation ......................... 3,399 -
Commitments and contingencies ....................... - -
Stockholder's equity:
Common stock - stated value $10 per share;
500 authorized shares; 200 shares issued and
outstanding....................................... 2 2
Additional paid-in capital ......................... 16,505 16,505
Accumulated other comprehensive loss ............... (671) (212)
Retained earnings .................................. 8,490 8,014
-------- --------
Total stockholder's equity........................ 24,326 24,309
-------- --------
$ 97,395 $ 83,691
======== ========
See accompanying notes to consolidated financial statements
133
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
SIX MONTHS ENDED MARCH 31, 2003 AND 2002
(Unaudited)
(in thousands)
2003 2002
------- -------
REVENUES
Well drilling ............................................. $29,949 $27,809
Gas and oil production .................................... 7,359 3,335
Well services ............................................. 2,783 3,496
Other ..................................................... 75 103
------- -------
40,166 34,743
COSTS AND EXPENSES
Well drilling ............................................. 26,043 24,697
Gas and oil production and exploration .................... 908 1,233
Well services ............................................. 576 656
Non-direct ................................................ 8,450 4,492
Depreciation, depletion and amortization .................. 2,356 1,910
Asset retirement obligation accretion ..................... 99 -
Interest .................................................. 1,179 1,114
------- -------
Total costs and expenses................................ 39,611 34,102
------- -------
Income before income taxes ................................ 555 641
Provision for income taxes ................................ 79 148
------- -------
Net income ................................................ $ 476 $ 493
======= =======
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY
SIX MONTHS ENDED MARCH 31, 2003
(Unaudited)
(in thousands, except share data)
Common stock Additional Accumulated Totals
--------------- Paid-In Comprehensive Retained Stockholder's
Shares Amount Capital Loss Earnings Equity
------ ------ ---------- ------------- -------- -------------
Balance, October 1, 2002 ............................. 200 $2 $16,505 $(212) $8,014 $24,309
Other comprehensive loss ............................. (459) (459)
Net income ........................................... 476 476
--- -- ------- ----- ------ -------
Balance, March 31, 2003 .............................. 200 $2 $16,505 $(671) $8,490 $24,326
=== == ======= ===== ====== =======
See accompanying notes to consolidated financial statements
134
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
SIX MONTHS ENDED MARCH 31, 2003 AND 2002
(Unaudited)
(in thousands)
2003 2002
----- -----
Net income ..................................................... $ 476 $ 493
Cash flow hedge losses reclassed into gas sales, net of taxes
of $76........................................................ 468 -
Change in fair value of cash flow hedges, net of taxes of $151
and $23....................................................... (927) (143)
----- -----
Comprehensive income ........................................... $ 17 $ 350
===== =====
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
SIX MONTHS ENDED MARCH 31, 2003 AND 2002
(Unaudited)
(in thousands)
2003 2002
------- -------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................ $ 476 $ 493
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization ................. 2,356 1,910
Asset retirement obligation accretion .................... 99 -
License fees and interest on intercompany note due to
parent................................................... 9,200 7,700
Change in operating assets and liabilities:
Increase in accounts receivable and other current assets . (502) (36)
Increase (decrease) in accounts payable and other current
liabilities.............................................. 2,817 (8,177)
------- -------
Net cash provided by operating activities ................. 14,446 1,890
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ...................................... (9,424) (8,106)
------- -------
Net cash used in investing activities ..................... (9,424) (8,106)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings - long-term debt ............................... 229 -
Payments - long-term debt ................................. (7) -
Advances from (to) Parent and Affiliates .................. (1,929) 974
------- -------
Net cash provided by (used in) financing activities ....... (1,707) 974
------- -------
Increase (decrease) in cash and cash equivalents .......... 3,315 (5,242)
Cash and cash equivalents at beginning of year ............ 698 5,358
------- -------
Cash and cash equivalents at end of year .................. $ 4,013 $ 116
======= =======
See accompanying notes to consolidated financial statements
135
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2003
(Unaudited)
NOTE 1 - INTERIM FINANCIAL STATEMENTS
These consolidated financial statements have been prepared in accordance
with accounting principles generally accepted in the United States of America
("US GAAP") for interim financial information and certain rules and regulations
of the Securities and Exchange Commission. Accordingly, they do not include all
of the information and footnotes required by US GAAP for complete financial
statements.
The preparation of financial statements in conformity with US GAAP requires
management to make estimates and assumptions that affect (i) the reported
amounts of assets and liabilities, (ii) disclosure of contingent assets and
liabilities as of the dates of the financial statements and (iii) the reported
amounts of revenues and expenses during the reporting periods. In the opinion of
management, all adjustments (consisting only of normal recurring adjustments and
certain cost allocations for expenses paid by either the Parent or its'
affiliates on behalf of the Company) considered necessary for a fair
presentation have been reflected in these consolidated financial statements.
Operating results for the six months ended March 31, 2003, are not
necessarily indicative of the results that may be expected for the year ending
September 30, 2003. Certain reclassifications have been made in the fiscal 2002
consolidated financial statements to conform to the fiscal 2003 presentation.
These financial statements should be read in conjunction with the Company's
audited September 30, 2002 consolidated financial statements.
NOTE 2 - CONSOLIDATED STATEMENTS OF CASH FLOWS
Supplemental disclosure of cash flow information:
Six Months Ended
----------------
March 31,
----------------
2003 2002
---- ----
(in
thousands)
Cash paid during the period for:
Interest ....................................................... $250 $264
Income taxes ................................................... - -
NOTE 3 - ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143")
establishes requirements for accounting for the removal costs associated with
asset retirements. The adoption of SFAS 143 on October 1, 2002 resulted in the
recording of an additional $3.3 million to oil and gas properties and equipment,
representing the Company's share of estimated future well plugging costs (as
discounted to the present value at the dates the wells began operations). In
addition, the Company recorded a corresponding retirement obligation liability
of $3.3 million (which includes accretion of that discounted value to September
30, 2002). Accumulated depreciation and depletion did not change as the
additional cost basis associated with the plugging liability was offset by the
estimated salvage value to be realized upon the disposal of the wells. The
Company considers that the cumulative effect of initially applying SFAS 143 is
not material to its Consolidated Statements of Income.
Except for the item above, the Company has determined that there are no
other material retirement obligations associated with tangible long-lived
assets.
136
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
MARCH 31, 2003
(Unaudited)
NOTE 4 - COMMITMENTS AND CONTINGENCIES
The Company is the managing general partner in several oil and gas limited
partnerships and has agreed to indemnify each investor 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 the
Company.
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 will determine the
purchase price in accordance with the respective partnership agreement. The
Company is not obligated to purchase more than 5% or 10% of the units in any
calendar year. Based on past experience, the Company believes that any liability
incurred would not be material.
The Company may be required to subordinate a part of its net partnership
revenues to the receipt by investor partners of cash distributions from the
Partnership equal to at least 10% of their agreed subscriptions determined on a
cumulative basis, in accordance with the terms of the partnership agreement.
The Company is also party to various routine legal proceedings arising out
of the ordinary course of its business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on the Company's financial condition or operations.
In July 2002, the Company's parent (Atlas), entered into a $75.0 million
credit facility led by Wachovia Bank. The revolving credit facility has a
borrowing base of $52.5 million at March 31, 2003 and may be increased subject
to growth in Atlas' oil and gas reserves. The facility permits draws based on
the remaining proved developed non-producing and proved undeveloped natural gas
and oil reserves attributable to Atlas' energy subsidiaries' wells and the
projected fees and revenues from operation of the wells and the administration
of partnerships. At March 31, 2003, $39.0 million was outstanding under this
facility; the Company owed no amounts due under this facility.
137
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
MARCH 31, 2003
(Unaudited)
NOTE 5 - HEDGING ACTIVITIES
The Company enters into natural gas futures and option contracts to hedge
its exposure to changes in natural gas prices. At any point in time, such
contracts may include regulated New York Mercantile Exchange ("NYMEX") futures
and options contracts and non-regulated over-the-counter futures contracts with
qualified counterparties. NYMEX contracts are generally settled with offsetting
positions, but may be settled by the delivery of natural gas.
The Company formally documents all relationships between hedging instruments
and the items being hedged, including the Company's risk management objective
and strategy for undertaking the hedging transactions. This includes matching
the natural gas futures and options contracts to the hedged asset. The Company
assesses, both at the inception of the hedge and on an ongoing basis, whether
the derivatives are highly effective in offsetting changes in fair value of
hedged items. When it is determined that a derivative is not highly effective as
a hedge or it has ceased to be a highly effective hedge, due to the loss of
correlation between changes in gas reference prices under a hedging instrument
and actual gas prices, the Company will discontinue hedge accounting for the
derivative and further changes in fair value for the derivative will be
recognized immediately into earnings. Gains or losses on these instruments are
accumulated in other comprehensive income (loss) to the extent that these hedges
are deemed to be highly effective as hedges, and are recognized in earnings in
the period in which the hedged item is recognized in earnings.
At March 31, 2003, the Company had 172 open natural gas futures contracts
related to natural gas sales covering 516,000 dekatherm ("Dth") (net to the
Company) maturing through September 2003 at a combined average settlement price
of $3.59 per Dth. Based on quoted market prices, the fair value of the Company's
open natural gas futures contracts at March 31, 2003, is $8.8 million. As these
contracts qualify and have been designated as cash flow hedges, any gains or
losses resulting from market price changes are deferred and recognized as a
component of sales revenues in the month the gas is sold, unless the hedges are
no longer "highly effective." Gains or losses on futures contracts are
determined as the difference between the contract price and a reference price,
generally prices on NYMEX. The Company's net unrealized loss related to open
NYMEX contracts was approximately $780,000 at March 31, 2003 and $316,600 at
September 30, 2002. The unrealized losses, net of applicable taxes, have been
recorded as a liability in the Company's Consolidated Balance Sheets and in
Stockholders' Equity as a component of Accumulated Other Comprehensive Income.
The Company recognized a loss of $544,000 on settled contracts for the six
months ended March 31, 2003. No contracts were settled during the six months
ended March 31, 2002. The Company recognized no gains or losses during the three
months and six months ended March 31, 2003 for hedge ineffectiveness or as a
result of the discontinuance of cash flow hedges. As of March 31, 2003, all of
the deferred net losses on derivative instruments included in accumulated other
comprehensive income (loss) are expected to be reclassified to earnings during
the next six months.
Although hedging provides the Company some protection against falling
prices, these activities could also reduce the potential benefits of price
increases, depending upon the instrument.
NOTE 6 - EFFECTIVE TAX RATE
The Company's effective tax rate is lower compared to the statutory rate due
to the benefit of percentage depletion and certain tax credits.
138
APPENDIX A
INFORMATION REGARDING
CURRENTLY PROPOSED PROSPECTS
FOR
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS
The partnerships do not currently hold any interests in any prospects on which
the wells will be drilled, and the managing general partner has absolute
discretion in determining which prospects will be acquired to be drilled.
However, set forth below is information relating to approximately 75 proposed
prospects and the wells which will be drilled on the prospects by Atlas America
Public #12-2003 Limited Partnership, which is the first partnership in the
program and must be closed by December 31, 2003. It is referred to in this
section as the "2003 Partnership." One well will be drilled on each prospect,
and for purposes of this section the well and prospect are referred to together
as the "well." Although the managing general partner does not anticipate that
the wells will be selected in the order in which they are set forth below, these
wells are currently proposed to be drilled by the 2003 Partnership when the
subscription proceeds are released from escrow and from time to time thereafter
subject to the managing general partner's right to:
o withdraw the wells and to substitute other wells;
o take a lesser working interest in the wells;
o add other wells; or
o any combination of the foregoing.
The specified wells represent the necessary wells if approximately $15 million
is raised and the 2003 Partnership takes the working interest in the wells which
is set forth below in the "Lease Information" for each well. The managing
general partner has not proposed any other wells if:
o a greater amount of subscription proceeds is raised;
o a lesser working interest in the wells is acquired; or
o the wells are substituted for any of the reasons set forth below.
The managing general partner has not authorized any person to make any
representations to you concerning the possible inclusion of any other wells
which will be drilled by the 2003 Partnership or any of the other partnerships,
and you should rely only on the information in this prospectus. The currently
proposed wells will be assigned unless there are circumstances which, in the
managing general partner's opinion, lessen the relative suitability of the
wells. These considerations include:
o the amount of the subscription proceeds received in the 2003 Partnership;
o the latest geological and production data available;
o potential title or spacing problems;
o availability and price of drilling services, tubular goods and services;
o approvals by federal and state departments or agencies;
o agreements with other working interest owners in the wells;
o farmins; and
o continuing review of other properties which may be available.
1
Any substituted and/or additional wells will meet the same general criteria 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 production and geological
information for the substituted and/or additional wells.
The purpose of the information regarding the currently proposed wells is to help
you evaluate the economic potential and risks of drilling the proposed wells.
This includes production information for wells in the general area of the
proposed well which the managing general partner believes is an important
indicator in evaluating the economic potential of any well to be drilled.
However, a well drilled by the 2003 Partnership may not experience production
comparable to the production experienced by wells in the surrounding area since
the geological conditions in these areas can change in a short distance. Also,
the managing general partner has not been able to obtain production information
for previously drilled wells in the immediate areas where a portion of the
currently proposed wells in Pennsylvania are situated because the information is
not available to the managing general partner as discussed in "Risk Factors -
Risks Related to an Investment In a Partnership - Lack of Production Information
Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a
Partnership's Drilling Program." These wells, for which no production data for
other wells in the immediate area are available to the managing general partner,
have been proposed by the managing general partner to be drilled based on
geologic trends in the immediate area where production has been established,
such as sand thickness, porosities and water saturations, lead the managing
general partner to believe that the proposed wells will have similar production.
When reviewing production information for each well offsetting or in the general
area of a proposed well to be drilled you should consider the factors set forth
below.
o The length of time that the well has been on-line, and the period for
which production information is shown. Generally, the shorter the period
for which production information is shown the less reliable the
production information.
o Production from a well declines throughout the life of the well, but the
rate of decline (the "decline curve") may be affected by the operation of
the well and the geological location of the well.
o The greatest volume of production from a well ("flush production")
usually occurs in the early period of well operations and may indicate a
greater reserve volume than the well actually will produce. This period
of flush production can vary depending on how the well is operated and
the location of the well.
o The production information for some wells is incomplete or very limited.
The designation "N/A" means:
o the production information was not available to the managing general
partner for the reasons discussed in "Risk Factors - Risks Related to
an Investment In a Partnership - Lack of Production Information
Increases Your Risk and Decreases Your Ability to Evaluate the
Feasibility of a Partnership's Drilling Program."; or
o if the managing general partner was the operator, then when the
information was prepared the well was either:
o not completed;
o not on-line to sell production; or
o producing for only a short period of time.
o Production information for wells located close to a proposed well tends
to be more relevant than production information for wells located farther
away, although even with wells located close together well performance
and the volume of production from the wells can be much different.
2
o Consistency in production among wells tends to confirm the reliability
and predictability of the production.
To help you become familiar with the proposed wells the information set forth
below is included.
o A map of western Pennsylvania and eastern Ohio showing their counties. ......................................... 4
o Western Pennsylvania (Clinton/Medina Geological Formation)
o Lease information for western Pennsylvania and eastern Ohio. ............................................. 6
o Location and Production Map for western Pennsylvania and eastern Ohio showing the proposed wells and
the wells in the area. ................................................................................. 9
o Production data for western Pennsylvania and eastern Ohio. ............................................... 11
o United Energy Development Consultants, Inc.'s geologic evaluation for western Pennsylvania and eastern
Ohio. .................................................................................................. 15
o Fayette County, Pennsylvania (Mississippian/Upper Devonian Sandstone Reservoirs)
o Lease information for Fayette and Greene Counties, Pennsylvania. ......................................... 21
o Location and Production Maps for Fayette and Greene Counties, Pennsylvania showing the proposed wells
and the wells in the area. ............................................................................. 23
o Production data for Fayette and Greene Counties, Pennsylvania. ........................................... 29
o United Energy Development Consultants, Inc.'s geologic evaluation for Fayette and Greene Counties,
Pennsylvania. .......................................................................................... 39
o Armstrong County, Pennsylvania (Upper Devonian Sandstone Reservoirs)
o Lease information for Armstrong and Indiana Counties, Pennsylvania. ...................................... 45
o Location and Production Map for Armstrong and Indiana Counties, Pennsylvania showing the proposed
wells and the wells in the area. ....................................................................... 47
o Production data for Armstrong and Indiana Counties, Pennsylvania ......................................... 49
o United Energy Development Consultants, Inc.'s geologic evaluation for Armstrong and Indiana Counties,
Pennsylvania. .......................................................................................... 54
3
MAP OF WESTERN PENNSYLVANIA
AND
EASTERN OHIO
4
[GRAPHIC OMITTED]
5
LEASE INFORMATION
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
6
Overriding
Royalty Interest to Overriding Net
Effective Expiration Landowner the Managing Royalty Interest Revenue
Prospect Name County Date* Date* Royalty General Partner to 3rd Parties Interest
----------------------------------------------------------------------------------------------------------------------------------
1. Horne #3 Crawford 11/14/01 HBP 12.5% 0% 0% 87.5%
2. Bazylak #3 Crawford 10/24/01 HBP 12.5% 0% 0% 87.5%
3. Biemer Unit #2 Crawford 02/05/02 HBP 12.5% 0% 0% 87.5%
4. Dygert #1 Crawford 03/27/02 03/27/05 12.5% 0% 0% 87.5%
5. Stritzinger #2 Crawford 12/16/02 12/16/04 12.5% 0% 0% 87.5%
6. Nelson #9 Crawford 04/10/02 04/10/05 12.5% 0% 0% 87.5%
7. Shuffstall #2 Crawford 02/28/02 02/28/05 12.5% 0% 0% 87.5%
8. Ballut #1 Crawford 06/21/02 06/21/05 12.5% 0% 0% 87.5%
9. Warren #3 Crawford 02/02/02 02/02/05 12.5% 0% 0% 87.5%
10. Warren #4 Unit Crawford 02/02/02 02/02/05 12.5% 0% 0% 87.5%
11. Warren #5 Crawford 02/28/02 02/28/05 12.5% 0% 0% 87.5%
12. Grudoski #1 Crawford 11/16/02 11/16/05 12.5% 0% 0% 87.5%
13. Byler #96 Crawford 08/19/02 08/19/05 12.5% 0% 0% 87.5%
14. Fisher #4 Crawford 05/02/02 05/02/05 12.5% 0% 0% 87.5%
15. Townsend #4 Crawford 08/19/02 08/19/05 12.5% 0% 0% 87.5%
16. Byler #103 Crawford 11/11/02 11/11/05 12.5% 0% 0% 87.5%
17. Detweiler #6 Crawford 04/22/02 04/22/05 12.5% 0% 0% 87.5%
18. Detweiler #7 Crawford 04/22/02 04/22/05 12.5% 0% 0% 87.5%
19. Shrock #2 Crawford 06/12/02 06/12/05 12.5% 0% 0% 87.5%
20. Mullenax #1 Crawford 02/24/03 02/24/06 12.5% 0% 0% 87.5%
21. Klein #3 Crawford 02/22/03 02/22/06 12.5% 0% 0% 87.5%
22. Byler #104 Crawford 03/14/02 03/14/05 12.5% 0% 0% 87.5%
23. Przepiora #1 Crawford 03/17/03 03/17/06 12.5% 0% 0% 87.5%
24. Seeley #1 Crawford 08/05/02 08/05/05 12.5% 0% 0% 87.5%
25. Riley #3 Crawford 07/01/02 07/01/05 12.5% 0% 0% 87.5%
26. Collins #2 Crawford 07/01/02 07/01/05 12.5% 0% 0% 87.5%
27. Adsit #1 Crawford 07/24/02 07/24/05 12.5% 0% 0% 87.5%
28. Adsit #2 Crawford 07/24/02 07/24/05 12.5% 0% 0% 87.5%
Acres to be
Working Net Assigned to the
Prospect Name Interest Acres Partnership
-----------------------------------------------------------------
1. Horne #3 100% 145 50
2. Bazylak #3 100% 200 50
3. Biemer Unit #2 100% 117 50
4. Dygert #1 100% 115 50
5. Stritzinger #2 100% 201 50
6. Nelson #9 100% 250 50
7. Shuffstall #2 100% 110 50
8. Ballut #1 100% 19 19
9. Warren #3 100% 100 50
10. Warren #4 Unit 100% 100 50
11. Warren #5 100% 98 50
12. Grudoski #1 100% 47 47
13. Byler #96 100% 52 50
14. Fisher #4 100% 92 50
15. Townsend #4 100% 125 50
16. Byler #103 100% 91 50
17. Detweiler #6 100% 120 50
18. Detweiler #7 100% 120 50
19. Shrock #2 100% 70 50
20. Mullenax #1 100% 73 50
21. Klein #3 100% 53 50
22. Byler #104 100% 20 20
23. Przepiora #1 100% 57 50
24. Seeley #1 100% 65 50
25. Riley #3 100% 67 50
26. Collins #2 100% 74 50
27. Adsit #1 100% 100 50
28. Adsit #2 100% 100 50
7
Overriding
Royalty Interest to Overriding Net
Effective Expiration Landowner the Managing Royalty Interest Revenue
Prospect Name County Date* Date* Royalty General Partner to 3rd Parties Interest
----------------------------------------------------------------------------------------------------------------------------------
29. Merlin Enterprises #1 Crawford 07/08/02 07/08/05 12.5% 0% 0% 87.5%
30. Merlin Enterprises #2 Crawford 07/08/02 07/08/05 12.5% 0% 0% 87.5%
31. Merlin Enterprises #3 Crawford 07/08/02 07/08/05 12.5% 0% 0% 87.5%
32. Feidler #1 Crawford 04/11/03 04/11/06 12.5% 0% 0% 87.5%
Acres to be
Working Net Assigned to the
Prospect Name Interest Acres Partnership
-----------------------------------------------------------------
29. Merlin Enterprises #1 100% 327 50
30. Merlin Enterprises #2 100% 327 50
31. Merlin Enterprises #3 100% 327 50
32. Feidler #1 100% 43 43
- ---------------
* HBP - Held by Production.
8
LOCATION AND PRODUCTION MAP
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
9
[GRAPHIC OMITTED]
10
PRODUCTION DATA
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
11
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.
TOTAL MCF
THROUGH TOTAL LATEST
ID DATE MOS 03/31/03 LOGGERS 30 DAY
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE EXCEPT DEPTH PROD.
WHERE NOTED
1. 00194 Darwin C. Williams Dot #1 N/A N/A N/A N/A N/A
2. 00195 Darwin C. Williams Dot #2 N/A N/A N/A N/A N/A
3. 20483 N-REN Corp. Kebert Developers #2 09/21/75 N/A N/A 4901 N/A
4. 20519 R. D. Werner & Company Lashinsky, E. #1 05/27/83 N/A N/A 4672 N/A
5. 20613 R. D. Werner & Company Horne, D. #1 05/31/84 N/A N/A 4659 N/A
6. 20616 Pominex, Inc. Williams #1 11/16/85 N/A N/A 4980 N/A
7. 20709 R. D. Werner & Company Weaver, M. #1 07/16/85 N/A N/A 4820 N/A
8. 20807 R. D. Werner & Company Johnson, A. #1 06/04/86 N/A N/A 4865 N/A
9. 20809 R. D. Werner & Company Walker, R. #1 06/11/86 N/A N/A 4925 N/A
10. 21209 Cabot Oil & Gas Dygert, Paul #1 07/28/81 N/A N/A 4794 N/A
11. 21212 Cabot Oil & Gas Troyer, Eli #1 08/05/81 N/A Plugged & 4641 N/A
Abandoned
12. 21765 Great Lakes Energy Allen, James R. #1 08/09/82 N/A N/A 4545 N/A
Partners
13. 22610 Northern Appalachian Foulk #2 11/14/85 N/A N/A 5050 N/A
14. 22611 Northern Appalachian Foulk #3 11/03/85 N/A N/A 5000 N/A
15. 22628 Northern Appalachian Jolley #1 11/25/85 N/A N/A 4930 N/A
16. 22635 Northern Appalachian Foulk #1 11/24/85 N/A N/A 5059 N/A
17. 23776 Atlas Resources, Inc. Seamon #4 08/09/01 16 22103 5129 1142
18. 23792 Atlas Resources, Inc. Williams #11 05/05/02 9 14920 5075 1938
19. 23794 Atlas Resources, Inc. Byler #88 12/08/01 14 26750 5146 1283
20. 23798 Atlas Resources, Inc. Williams #12 12/13/01 14 29394 5097 1241
21. 23816 Atlas Resources, Inc. Williams #14 01/11/02 11 22555 5149 2159
22. 23839 Atlas Resources, Inc. Wotherspoon #2 05/17/02 9 14680 5065 1252
23. 23842 Atlas Resources, Inc. Pallack #9 05/10/02 9 14922 5061 1262
24. 23845 Atlas Resources, Inc. Byler #91 05/08/02 6 6843 5028 2085
25. 23966 Atlas Resources, Inc. McArdle #5 05/27/02 5 6315 5025 2034
26. 23976 Atlas Resources, Inc. Ruhlman #1 06/21/02 5 5193 5069 1819
12
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.
TOTAL MCF
THROUGH TOTAL LATEST
ID DATE MOS 03/31/03 LOGGERS 30 DAY
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE EXCEPT DEPTH PROD.
WHERE NOTED
27. 23977 Atlas Resources, Inc. Jackson #1 07/11/02 1 N/A 4978 N/A
28. 23982 Atlas Resources, Inc. Bazylak #1 07/03/02 4 3966 5003 2028
29. 23984 Atlas Resources, Inc. Jackson #2 08/19/02 N/A N/A 4973 N/A
30. 23985 Atlas Resources, Inc. McArdle #6 09/02/02 1 N/A 5008 N/A
31. 23991 Atlas Resources, Inc. Jackson #3 08/13/02 N/A N/A 5003 N/A
32. 23998 Atlas Resources, Inc. Saylor #2 08/25/02 N/A N/A 5002 N/A
33. 23999 Atlas Resources, Inc. Bazylak #2 09/01/02 N/A N/A 5003 N/A
34. 24000 Atlas Resources, Inc. Coulter #5 09/13/02 1 N/A 5070 N/A
35. 24003 Atlas Resources, Inc. Hall #12 09/06/02 N/A N/A 4967 N/A
36. 24006 Atlas Resources, Inc. Horne #1 09/13/02 N/A N/A 5003 N/A
37. 24009 Atlas Resources, Inc. Horne #2 11/04/02 N/A N/A 5018 N/A
38. 24011 Atlas Resources, Inc. McArdle #7 02/18/03 N/A N/A 5014 N/A
39. 24015 Atlas Resources, Inc. Byler #92 10/07/02 N/A N/A 4972 N/A
40. 24021 Atlas Resources, Inc. Horne #5 02/04/03 N/A N/A 4982 N/A
41. 24023 Atlas Resources, Inc. Sperry Farms #1 12/17/02 N/A N/A 4951 N/A
42. 24026 Atlas Resources, Inc. Sperry Farms #3 12/23/02 1 N/A 4919 N/A
43. 24028 Atlas Resources, Inc. Horne #6 12/10/02 1 N/A 4984 N/A
44. 24029 Atlas Resources, Inc. Lee Unit #4 12/28/02 N/A N/A 5133 N/A
45. 24030 Atlas Resources, Inc. Byler #94 01/14/03 N/A N/A 4932 N/A
46. 24031 Atlas Resources, Inc. Courtney #8 02/12/03 N/A N/A 5012 N/A
47. 24033 Atlas Resources, Inc. Stoker #4 01/07/03 N/A N/A 4989 N/A
48. 24034 Atlas Resources, Inc. Yoder #12 01/05/03 N/A N/A 4890 N/A
49. 24035 Atlas Resources, Inc. Horne #7 01/22/03 N/A N/A 4952 N/A
50. 24036 Atlas Resources, Inc. Kiskadden #3 02/05/03 N/A N/A 4884 N/A
51. 24041 Atlas Resources, Inc. Yoder Unit #11 01/11/03 N/A N/A 4923 N/A
52. 24046 Atlas Resources, Inc. Yoder #14 02/02/03 N/A N/A 4952 N/A
13
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.
TOTAL MCF
THROUGH TOTAL LATEST
ID DATE MOS 03/31/03 LOGGERS 30 DAY
NUMBER OPERATOR WELL NAME COMPLT'D ON LINE EXCEPT DEPTH PROD.
WHERE NOTED
53. 24047 Atlas Resources, Inc. Horne #8 01/29/03 1 N/A 5952 N/A
54. 24049 Atlas Resources, Inc. Morian #1 03/07/03 N/A N/A 4917 N/A
55. 24055 Atlas Resources, Inc. Kisdadden #1 02/13/03 N/A N/A 4920 N/A
56. 24057 Atlas Resources, Inc. Miller #19 01/27/03 N/A N/A 5062 N/A
57. 24061 Atlas Resources, Inc. Jackson #4 02/24/03 N/A N/A 4982 N/A
58. 24066 Atlas Resources, Inc. Yoder #15 02/07/03 N/A N/A 4920 N/A
59. 24076 Atlas Resources, Inc. Sperry Farms #2 02/26/03 N/A N/A 4924 N/A
60. 24079 Atlas Resources, Inc. Jacobs #1 03/09/03 N/A N/A 5040 N/A
61. 24080 Atlas Resources, Inc. Sperry Farms #4 02/19/03 N/A N/A 4854 N/A
62. 24083 Atlas Resources, Inc. Miller #18 03/03/03 N/A N/A 5105 N/A
63. 24097 Atlas Resources, Inc. Biemer #1 03/15/03 N/A N/A 4913 N/A
64. 24101 Atlas Resources, Inc. Sperry Farms Unit #5 03/14/03 N/A N/A 4863 N/A
65. 24102 Atlas Resources, Inc. Herbert #1 03/20/03 N/A N/A 4889 N/A
66. 24105 Atlas Resources, Inc. Miller Unit #20 03/22/03 N/A N/A 4945 N/A
67. 24109 Atlas Resources, Inc. McEntire #1 03/22/03 N/A N/A 4856 N/A
68. 24110 Atlas Resources, Inc. Morrow #2 03/26/03 N/A N/A 4769 N/A
69. 24112 Atlas Resources, Inc. Orr #2 03/29/03 N/A N/A 4855 N/A
70. 24118 Atlas Resources, Inc. Palermo #1 04/02/03 N/A N/A 4887 N/A
71. 90006 Sylvania Corp. Calvin Ellen #2 12/05/43 N/A N/A 4644 N/A
72. 90025 Sylvania Corp. Calvin Ellen #1 05/07/48 N/A Plugged & 4896 N/A
Abandoned
14
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
WESTERN PENNSYLVANIA AND EASTERN OHIO
15
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
Crawford Prospect Area
Pennsylvania
Dated: May 6, 2003
Program proposed by: Report submitted by:
ATLAS RESOURCES, INC. UEDC
311 Rouser Road United Energy Development Consultants, Inc.
P.O. Box 611 1715 Crafton Blvd.
Moon Township, PA 15108 Pittsburgh, PA 15205
LOCATION MAP - AREA OF INTEREST
[GRAPHIC OMITTED]
TABLE OF CONTENTS
INVESTIGATION SUMMARY .................................................... 2
OBJECTIVE ............................................................... 2
AREA OF INVESTIGATION ................................................... 2
METHODOLOGY ............................................................. 2
PROSPECT AREA HISTORY .................................................... 2
DRILLING ACTIVITY ....................................................... 2
GEOLOGY ................................................................. 2
STRATIGRAPHY, LITHOLOGY & DEPOSITION ................................... 2
RESERVOIR CHARACTERISTICS .............................................. 3
PRODUCTION .............................................................. 4
CONCLUSION .............................................................. 5
DISCLAIMER .............................................................. 5
NON-INTEREST ............................................................ 5
16
INVESTIGATION SUMMARY
OBJECTIVE
The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Crawford Prospect Area as proposed
by Atlas Resources, Inc. ("Atlas").
AREA OF INVESTIGATION
A portion of this prospect area, herein identified for drilling in Atlas
America Public #12-2003 Limited Partnership, contains acreage in East
Fallowfield, Greenwood and Sadsbury Townships in Crawford County,
Pennsylvania. Thirty-two (32) drilling prospects will be designated for this
program and will be targeted to produce natural gas from Clinton-Medina Group
reservoirs, found at an average depth range of approximately 5,000 to 6,300
feet beneath the earth's surface over the prospect area. These will be the
only prospects evaluated for the purposes of this report.
METHODOLOGY
The data incorporated into this report was provided by Atlas and the in-
house archives of UEDC, Inc. Geological mapping and the interpretations by
Atlas geologists were also examined. Available "electric" log, completion, and
production data on "key" wells within and adjacent to the defined prospect
area were utilized to determine productive and depositional trends.
PROSPECT AREA HISTORY
DRILLING ACTIVITY
The proposed drilling area lies within a region of northwestern
Pennsylvania which has been very active for the past decade in terms of
exploration for, and exploitation of natural gas reserves. Development within
and adjacent to the Crawford Prospect Area has escalated since 1986, with
Atlas and it's affiliates drilling over thirteen hundred (1300) wells during
this period. Atlas has encountered favorable drilling and production results
while solidifying a strong acreage position, and continues to identify and
extend productive trends. Drilling is ongoing as of the date of this report
with recent wells displaying favorable initial drilling and completion
results. Competitive activity has begun east of the prospect area, confirming
the Clinton-Medina Group of Lower Silurian age as a viable target for the
further development of producible quantities of natural gas.
GEOLOGY
STRATIGRAPHY, LITHOLOGY & DEPOSITION
Regionally, the Clinton-Medina Group was deposited in tide-dominated
shoreline, deltaic, and shelf environments and is lithologically comprised of
alternating sandstones, siltstones and shales. Productive sandstones are
composed of siliceous to dolomitic subarkoses, sublitharenites, and quartz
arenites. Reservoir quality sands occur throughout the delta-complex from
eastern Ohio through northwestern Pennsylvania and western New York. The
Clinton-Medina Group, deposited during the Lower Silurian, overlies the Upper
Ordovician age Queenston shale and is capped by the Middle Silurian Reynales
Formation. This dolomitic limestone "cap" is known locally to drillers as the
"Packer Shell".
Stratigraphically, in descending order, the potentially productive units
of the Clinton-Medina Group consist of the:
1) Thorold, 2) Grimsby, 3) Cabot Head, 4) Whirlpool members. The diagram
illustrates these stratigraphic relationships.
[GRAPHIC OMITTED]
17
The Whirlpool is a light gray quartzose sandstone to siltstone ranging in
thickness from five (5) to twenty (20) feet. Average porosity values for this
sand member range from five (5) to ten (10) percent regionally. Within the
area of investigation, porosities in excess of twelve (12) percent occur
within localized trends targeted for further development.
The Cabot Head is a dark green to black shale, most likely of marine
origin. Within the investigated area the Cabot Head sandstone has been
encountered in numerous wells. This formation has been found to contribute
natural gas when reservoir characteristics, including evidence of enhanced
permeability, warrant completion. This sand member is considered a secondary
target.
The Grimsby is the thickest sandstone member of the Clinton-Medina Group.
Sand development ranges from ten (10) to forty-five (45) feet within an
interval comprised of fine to very fine, light gray to red sandstones and
siltstones broken up by thin dark gray silty shale layers. Average porosity
values for the Grimsby are approximately six (6) to (10) percent over the pay
interval regionally. Permeability may be enhanced locally by the presence of
naturally occurring micro-fractures. Future development focuses on established
production trends.
The Thorold sandstone is the uppermost producing interval of the Clinton-
Medina sequence. This interbedded ferric sand, silt and shale interval
averages forty (40) to seventy (70) feet, from west to east in the prospect
area. Where pay sand development occurs, porosities are in the typical
Clinton-Medina group range of six (6) to (10) percent. Permeability may be
enhanced locally by the presence of naturally occurring micro-fractures.
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping natural gas of commercial quantities in a more permeable medium. In
the Clinton-Medina, this occurs either stratigraphically when a permeable sand
containing hydrocarbons encounters an impermeable shale or when a permeable
sand changes gradually into a non-permeable sand by a cementation process
known as "diagenesis". Thus, this type of trap represents cemented-in
hydrocarbon accumulations.
Electric well logs can be used in conjunction with production to interpret
reservoir parameters. When sandstones in the Thorold, Grimsby, Cabot Head or
Whirlpool develop porosity in excess of 6%, or a bulk density of 2.55 or less,
the permeability of the reservoir (which ranges from <0.l to
>40.2 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.
Two other phenomena detected by well logs can occur which are indicators
of enhanced permeability. These indicators used to detect productive intervals
are:
o Mudcake buildup across the zone of interest - after loading the wellbore
with brine fluid and circulating, an interval with enhanced permeability will
accept fluid, filtering out the solids and leaving behind a buildup (or
mudcake) on the formation wall. This is detectable with a caliper log.
[GRAPHIC OMITTED]
o Invasion profile - during circulation, a brine that has a high
conductivity (or low resistivity) that is accepted into the formation (as
described above) will change the electrical conductivity of the reservoir rock
near and around the wellbore. The resistivity will be low nearest to the
wellbore and will increase away from the wellbore. 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:
18
GAMMA RAY LOG RESISTIVITY LOG
[GRAPHIC OMITTED]
PRODUCTION
A model decline curve has been created based on the production histories
from approximately 900 wells drilled by Atlas and its programs in the adjacent
Mercer Fields. This model decline curve is consistent with the average
estimated decline curves for over 200 undeveloped well locations in the Mercer
Field which were used by Wright & Company, Inc., independent petroleum
consultants, in preparing Atlas' year 2000 reserve report. The model decline
curve is illustrated in the diagram below:
[GRAPHIC OMITTED]
It is important to note that the model decline curve is intended only to
present how a well's production may decline from year to year, and does not
attempt to predict the average recoverable reserves per well. Also, the model
decline curve is a forward-looking statement based on certain assumptions and
analyses of historical trends, current conditions and expected future
developments. The model decline curve is subject to a number of risks and
uncertainties including the risk that the wells are productive but do not
produce enough revenue to return the investment made and uncertainties
concerning the price of natural gas and oil. Actual results in this drilling
program will vary from the model decline curve, although a rapid decline in
production within the first several years can be expected.
19
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the drilling area for
Atlas America Public #12-2003 Limited Partnership, which will consist of
developmental drilling of the Clinton-Medina Group sands primarily in Crawford
County, Pennsylvania. It is the professional opinion of UEDC that the drilling
of the thirty-two (32) wells by Atlas America Public #12-2003 Limited
Partnership is supported by sufficient geologic and engineering data.
DISCLAIMER
For the purpose of this evaluation, UEDC did not visit any leaseholds or
inspect any of the associated production equipment. Likewise, UEDC has no
knowledge as to the validity of title, liabilities, or corporate matters
affecting these properties. UEDC does not warrant individual well performance.
NON-INTEREST
We hereby confirm that UEDC is an independent consulting firm and that
neither this firm or any of it's employees, contract consultants, or officers
has, or is committed to acquire any interest, directly or indirectly, in Atlas
Resources, Inc.; nor is this firm, or any employee, contract consultant, or
officer thereof, otherwise affiliated with Atlas Resources, Inc. We also
confirm that neither the employment of, nor payment of compensation received
by UEDC in connection with this report, is on a contingent basis.
Respectfully submitted,
/s/ Robin Anthony
-----------------
UEDC, Inc.
20
LEASE INFORMATION
FOR
FAYETTE AND GREENE COUNTIES, PENNSYLVANIA
21
Overriding
Royalty Overriding
Interest to the Royalty
Effective Expiration Landowner Managing Interest to
Prospect Name County Date* Date* Royalty General Partner 3rd Parties
----------------- ------------- ------------- ------------- ------------- --------------- -------------
1. Allen #5 Fayette 12/16/2002 12/16/2003 12.5% 0% 0%
2. Allen/USX #8 Fayette 10/5/2000 HBP 12.5% 0% 0%
3. Allen/USX #9 Fayette 10/5/2000 HBP 12.5% 0% 0%
4. Blaney #2 Fayette 8/3/2001 8/3/2004 12.5% 0% 0%
5. Blaney #3 Fayette 8/3/2001 8/3/2004 12.5% 0% 0%
6. Blaney/USX #4 Fayette 10/5/2000 HBP 12.5% 0% 0%
7. Cardine #4 Fayette 12/30/1998 HBP 12.5% 0% 0%
8. Conrail #11 Fayette 1/25/1906 HBP 12.5% 0% 0%
9. Diamond #2 Fayette 9/7/2001 HBP 12.5% 0% 0%
10. E&N Land #1 Fayette 12/31/2002 12/31/2004 12.5% 0% 0%
11. E&N Land #2 Fayette 12/13/2002 12/31/2004 12.5% 0% 0%
12. Graham #6 Fayette 8/22/1911 HBP 12.5% 0% 0%
13. Hassibi #4 Fayette 3/30/2003 9/30/2003 12.5% 0% 0%
14. Hendricks #4 Fayette 1/6/1999 1/6/2004 12.5% 0% 0%
15. Jackson Farms #15 Fayette 10/14/1998 10/14/2003 12.5% 0% 0%
16. Jackson Farms #17 Fayette 10/14/1998 HBP 12.5% 0% 0%
17. Jackson Farms #22 Fayette 10/14/1998 HBP 12.5% 0% 0%
18. Jackson Farms #5 Fayette 10/14/1998 10/14/2003 12.5% 0% 0%
19. Jackson Farms #8 Fayette 10/14/1998 10/14/2003 12.5% 0% 0%
20. Krukowski #1 Fayette 5/19/2001 5/19/2006 12.5% 0% 0%
21. Langley #8 Fayette 6/16/2001 HBP 12.5% 0% 0%
22. Moore #8 Fayette 8/13/2002 HBP 12.5% 0% 0%
23. Moore #9 Fayette 8/13/2002 HBP 12.5% 0% 0%
24. Nichols #3 Fayette 8/2/1996 HBP 12.5% 0% 0%
25. Porter #10 Fayette 10/20/2002 10/20/2004 12.5% 0% 0%
26. Ronco/USX #2 Fayette 3/15/1999 HBP 12.5% 0% 0%
27. Rosa #5 Fayette 3/19/2001 HBP 12.5% 0% 0%
28. Stewart #11 Fayette 12/29/1998 HBP 12.5% 0% 0%
29. Stewart #9 Fayette 9/26/2002 HBP 12.5% 0% 0%
30. Veschio/USX #1 Fayette 10/5/2000 HBP 12.5% 0% 0%
31. Wolf #12 Fayette 12/3/2002 12/3/2004 12.5% 0% 0%
32. Yoder #24 Fayette 1/24/1906 HBP 12.5% 0% 0%
Acres to be
Assigned to
Net Revenue Working Net the
Prospect Name Interest Interest Acres Partnership
----------------- ------------- ------------- ----- -------------
1. Allen #5 87.5% 100% 88 20
2. Allen/USX #8 87.5% 100% 2634 20
3. Allen/USX #9 87.5% 100% 2634 20
4. Blaney #2 87.5% 100% 44 20
5. Blaney #3 87.5% 100% 44 20
6. Blaney/USX #4 87.5% 100% 2634 20
7. Cardine #4 87.5% 100% 119 20
8. Conrail #11 87.5% 100% 145 20
9. Diamond #2 87.5% 100% 45 20
10. E&N Land #1 87.5% 100% 71 20
11. E&N Land #2 87.5% 100% 73 20
12. Graham #6 87.5% 100% 133 20
13. Hassibi #4 87.5% 100% 103 20
14. Hendricks #4 87.5% 100% 85 20
15. Jackson Farms #15 87.5% 100% 15 15
16. Jackson Farms #17 87.5% 100% 190 20
17. Jackson Farms #22 87.5% 100% 82 20
18. Jackson Farms #5 87.5% 100% 66 20
19. Jackson Farms #8 87.5% 100% 80 20
20. Krukowski #1 87.5% 100% 109 20
21. Langley #8 87.5% 100% 215 20
22. Moore #8 87.5% 100% 125 20
23. Moore #9 87.5% 100% 125 20
24. Nichols #3 87.5% 100% 111 20
25. Porter #10 87.5% 100% 76 20
26. Ronco/USX #2 87.5% 100% 294 20
27. Rosa #5 87.5% 100% 125 20
28. Stewart #11 87.5% 100% 67 20
29. Stewart #9 87.5% 100% 129 20
30. Veschio/USX #1 87.5% 100% 2634 20
31. Wolf #12 87.5% 100% 193 20
32. Yoder #24 87.5% 100% 260 20
- ---------------
* HBP-Held by Production
22
LOCATION AND PRODUCTION MAPS FOR
FAYETTE AND GREENE COUNTIES
23
[GRAPHIC OMITTED]
24
[GRAPHIC OMITTED]
25
[GRAPHIC OMITTED]
26
[GRAPHIC OMITTED]
27
[GRAPHIC OMITTED]
28
PRODUCTION DATA
FOR
FAYETTE AND GREENE COUNTIES, PENNSYLVANIA
29
The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of
any well to be drilled by the partnership.
TOTAL MCF
THROUGH
MOS 3/31/03 TOTAL LATEST 30
ID DATE ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
1. 3 M.E. Davis Ben Lardin #1 4/8/1956 N/A N/A 3814 N/A
2. 10 Manufacturers Light & Heat Co Hogsett #9 10/21/1947 N/A N/A N/A N/A
3. 19 Greensboro Gas Co J.V.Thompson 10/17/1945 N/A N/A 3044 N/A
4. 41 Greensboro Gas Co Hogsett #2 1/1/1922 N/A N/A 1968 N/A
5. 42 Nollem Oil & Gas Corp. Lingle (Neff Heirs) #1 5/20/1944 N/A N/A 3473 N/A
6. 43 Nollem Oil & Gas Corp. Neff Heirs #1 8/23/1943 N/A N/A 4210 N/A
7. 57 Carnegie Natural Gas Co H.C.Frick Coke(Ralph) #2 2/5/1945 N/A 105,000/1963 2595 N/A
8. 58 Carnegie Natural Gas Co H.C.Frick Coke(Ralph) #1 7/22/1944 228 86,428/1963 2588 N/A
9. 60 Greensboro Gas Co Dearth #3 4/13/1905 N/A N/A 3143 N/A
10. 63 Manufacturers Light & Heat Co Hogsett #6 2/17/1945 N/A N/A 2793 N/A
11. 66 Manufacturers Light & Heat Co Hogsett #8 5/26/1947 N/A N/A 2475 N/A
12. 71 Peoples Natural Gas Co DiCarlo #1 N/A N/A N/A 1975 N/A
13. 120 Peoples Natural Gas Co Emery Dziak # 4/13/1945 N/A N/A 3489 N/A
14. 121 W. Burkland J.A. Baer #2 10/11/1937 N/A 215,000/1980 3610 N/A
15. 140 Atlas (Castle Gas Co) Duff, Lauretta 3/29/1905 N/A 184,000/1990 1,361 N/A
16. 184 Castle Gas Co Jacobs #5 10/1/1943 N/A 93,000 N/A N/A
17. 185 Atlas (Castle Gas Co) Dearth #1 11/23/1917 N/A 1,373,000/1990 2,384 28
18. 186 Atlas (Castle Gas Co) Conrail #1 12/2/1910 N/A 427,000/1990 3,155 N/A
19. 257 Atlas (Castle Gas Co) Graham, A. #1 N/A N/A 289,000/1990 N/A N/A
20. 20013 William E. Snee & Orville Eberly Szabo #1 8/20/1960 N/A N/A 2,640 N/A
21. 20021 Peoples Natural Gas Co C. Yuras #1 3/17/1949 N/A 149,000/1974 3493 N/A
22. 20059 M.C.Brumage DiCarlo #2 12/29/1967 N/A N/A 3093 N/A
23. 20122 R. Taylor Mosier R.T. Mosier #1 3/11/1972 N/A N/A 2642 N/A
24. 20168 R. Taylor Mosier R.T. Mosier #2 1/10/1977 N/A N/A 2600 N/A
25. 20203 Total Resources Sloan/Thompson #1 8/31/1978 N/A N/A 4060 N/A
26. 20244 Atlas (Castle Gas Co) Yoder, E. #2 9/13/1979 N/A 52,000/1990 N/A 278
30
The Production Data provided in the table below is not intended to imply that
the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of
any well to be drilled by the partnership.
TOTAL MCF
THROUGH
MOS 3/31/03 TOTAL LATEST 30
ID DATE ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
27. 20277 Ashtola Production Co R.Cerullo #1 7/13/1981 N/A N/A 4531 N/A
28. 20313 Ashtola Production Co D'Isodoro #1 12/7/1982 N/A N/A 3863 N/A
29. 20742 Kriebel Gas Inc Fairbank Rod & Gun #1 11/5/1996 N/A N/A 3895 N/A
30. 20894 Atlas Zitney #1A 2/4/1997 50 15,326 4,077 246
31. 20919 N/A USX (Coalbed methane well) N/A N/A N/A N/A N/A
32. 20991 Atlas DiCarlo #1 3/12/1998 57 13,376 4,439 76
33. 20995 Atlas Kutek #1 11/25/1998 49 25,373 3,560 348
34. 21040 Atlas Howe #1 5/4/1999 45 77,819 3,988 831
35. 21072 W.Burkland Yoho #1 N/A N/A N/A N/A N/A
36. 21075 Atlas Cerullo #1 3/7/1999 44 4,224 3,815 42
37. 21078 W.Burkland R. Jackson #1 N/A N/A N/A N/A N/A
38. 21080 Atlas Bowers/Hogsett #2 2/24/1999 46 32,246 3,528 626
39. 21161 Atlas Hall/Hogsett #1 9/29/2000 25 41,138 3,970 589
40. 21165 Atlas Hoehn #1 9/25/2000 29 54,738 3,875 1,291
41. 21207 Atlas Hall #4 11/11/2000 27 37,226 4,032 631
42. 21224 Atlas Crable #1 3/26/2001 22 20,254 3,995 926
43. 21232 Atlas Fairbank Rod & Gun #2 1/11/2001 25 1,717 3,973 0
44. 21237 Atlas Fairbank Rod & Gun #1 1/19/2001 13 8,587 4,055 212
45. 21252 Atlas Skovran #6 3/19/2001 22 66,830 4,066 1,057
46. 21255 Atlas Faverio #1 7/2/2001 19 2,158 4,113 291
47. 21263 Atlas Frankhouser #1 3/26/2001 22 4,516 1,680 60,530
48. 21265 Atlas Girolami #1 5/30/2001 20 33,447 4,110 1,131
49. 21287 Atlas Hall/Hogsett #5 6/13/2001 20 3,916 1,878 56,525
50. 21288 Atlas Frankhouser #2 9/12/2001 4 4,516 2,676 5,734
51. 21289 Atlas Cardine #1 7/18/2001 19 5,854 4,110 457
52. 21292 Atlas Skovran #8 7/7/2001 20 70,279 2,152 2,487
31
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.
TOTAL MCF
THROUGH
3/31/03 TOTAL LATEST 30
ID DATE MOS ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
53. 21296 Atlas DiCarlo #4 6/20/2001 20 77,490 3,910 1,696
54. 21297 Atlas DiCarlo #5 6/25/2001 19 18,897 3,970 761
55. 21303 Atlas Thomas #2 7/31/2001 18 11,399 3,885 395
56. 21305 Atlas Pollick #3 8/15/2001 17 16,677 4,030 782
57. 21307 Atlas Hoehn #3 9/27/2001 17 84,999 3,856 3,731
58. 21309 Atlas Hoehn #5 8/10/2002 5 22,272 4,250 3,549
59. 21310 Atlas Crable/Hogsett #2 8/15/2001 17 41,521 3,977 1,413
60. 21312 Atlas Brant #1 11/27/2001 N/A N/A 3,710 N/A
61. 21314 Atlas Thomas #1 8/5/2001 18 22,762 3,889 572
62. 21320 Atlas Hmelyar #1 8/24/2001 4 1,642 4,208 328
63. 21322 Atlas McGill #4 9/30/2001 12 28,033 3,960 1,868
64. 21325 Atlas Darr/USX #1 10/8/2001 6 3,468 4,000 262
65. 21326 Atlas Skovran #7 9/10/2001 18 26,090 4,063 1,166
66. 21328 Atlas Hall/Hogsett #10 9/2/2001 18 39,451 4,176 1,629
67. 21333 Atlas Darr/USX #2 2/18/2002 6 12,521 2,250 403
68. 21342 Atlas Szuhay #1 12/10/2001 13 55,681 4,550 2,434
69. 21343 Atlas Szuhay #2 10/14/2001 15 4,966 4,492 173
70. 21357 Atlas Bashour #1 12/18/2001 13 197,397 4,558 8,073
71. 21358 Atlas Skovran #10 12/4/2001 8 7,469 4,500 1,132
72. 21365 Atlas Barber #2 11/21/2001 10 9,179 4,395 586
73. 21368 Atlas Conrail #4 11/9/2002 7 6,657 3,850 601
74. 21369 Atlas Hall #9 12/11/2001 13 32,306 3,862 1,437
75. 21370 Atlas Hall #8 12/3/2001 10 15,862 4,010 950
76. 21372 Atlas Podolinski #1 1/26/2002 10 9,739 3,872 529
77. 21376 Atlas National Mines #3 2/13/2002 1/10/1900 12,287 4,201 1,402
78. 21382 Atlas Labash/Myers #3 1/9/2003 N/A N/A 4,389 N/A
32
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.
TOTAL MCF
THROUGH
3/31/03 TOTAL LATEST 30
ID DATE MOS ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
79. 21384 Atlas Marcinek #1 1/6/2002 5 4,514 3,907 721
80. 21398 Atlas Hall #11 (P&A'd) 1/31/2002 N/A N/A 4,203 N/A
81. 21400 Atlas Newcomer #2 2/28/2002 9 8,443 2,175 236
82. 21401 Atlas Newcomer #1 1/26/2002 9 1,176 4,446 73
83. 21402 Atlas National Mines #6 5/29/2002 8 32,808 4,250 2,515
84. 21403 Atlas National Mines Corp. #5 11/21/2002 2 5,127 4,120 3,683
85. 21404 Atlas National Mines #4 4/3/2002 9 56,666 4,320 858
86. 21409 Atlas McArdle #1 2/4/2002 9 15,139 4,054 1,185
87. 21413 Atlas Mallick #1 2/28/2002 6 15,166 4,183 908
88. 21416 Atlas Gilleland #1 1/11/2002 4 3,466 4,179 531
89. 21435 Atlas Young #7A 3/29/2002 7 1,767 3,680 125
90. 21439 Atlas Gaggiani #3A 5/8/2002 8 4,031 2,160 168
91. 21440 Atlas Gaggiani #1 3/27/2002 8 4,370 4,710 332
92. 21443 Atlas Young #6 4/10/2002 7 10,841 3,860 815
93. 21453 Atlas Rider & Ashton #1 5/15/2002 8 2,471 4,426 199
94. 21460 Atlas Henderson #1 5/21/2002 5 2,482 3,880 471
95. 21461 Atlas Rittenhouse #2 12/13/2002 2 4,206 3,912 2,922
96. 21465 Atlas Skovran #11 6/26/2002 8 4,172 4,564 500
97. 21468 Atlas Hoehn #4 6/12/2002 8 29,205 3,800 2,927
98. 21469 Atlas Conrail #5 6/5/2002 7 10,439 4,300 1,126
99. 21470 Atlas Hall/Hogsett #6 5/29/2002 7 22,691 4,452 2,498
100. 21476 Atlas Elder #3 12/10/2002 2 2,014 4,270 1,629
101. 21483 Atlas Diamond #1 6/25/2002 N/A N/A 4,209 N/A
102. 21491 Atlas Leckrone/USX #1(P&A'd) 7/17/2002 N/A N/A 3,940 N/A
103. 21503 Atlas Rittenhouse #1 3/29/2003 12 12,146 3,450 627
104. 21506 Atlas Gilleland #3 7/31/2002 4 6,508 4,027 1,538
33
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.
TOTAL MCF
THROUGH
3/31/03 TOTAL LATEST 30
ID DATE MOS ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
105. 21509 Atlas Howe #2 9/4/2002 5 19,461 1,870 747
106. 21511 Atlas Hall/Hogsett #3 8/16/2002 2 5,772 3,910 1,152
107. 21513 Atlas Cobert #1 8/15/2002 6 10,087 2,481 686
108. 21516 Atlas Conrail #6 9/19/2002 4 3,960 4,262 1,051
109. 21527 Atlas Nichols #1 8/16/2002 4 3,788 4,160 923
110. 21530 Atlas Smith #8 1/3/2003 1 171 4,090 171
111. 21539 Atlas National Mines Corp. #8 9/18/2002 4 3,987 4,370 887
112. 21551 Atlas Zitney #2 2/2/2003 N/A N/A 4,115 N/A
113. 21552 Atlas Cobert #2 3/4/2003 N/A N/A 2,405 N/A
114. 21556 Atlas Hoehn Unit #2A 10/9/2001 14 42,360 3,850 1,483
115. 21562 Atlas Kutek #2 1/29/2003 N/A N/A 3,780 N/A
116. 21569 Atlas Rosa #1 1/20/2003 N/A N/A 4,030 N/A
117. 21570 Atlas Szuhay #4 12/20/2002 1 370 4,410 370
118. 21571 Atlas Stewart #6 2/21/2003 N/A N/A 4,250 N/A
119. 21575 Atlas Elder #2 12/4/2002 2 1,323 4,000 910
120. 21577 Atlas McGill #5 11/22/2002 2 3,957 3,910 2,334
121. 21579 Atlas Gilleland #4 11/26/2002 2 747 4,250 422
122. 21587 Atlas Wivell #3 1/11/2003 N/A N/A 4,059 N/A
123. 21588 Atlas Wivell #1 1/25/2003 N/A N/A 4,030 N/A
124. 21591 Atlas National Mines #14 12/4/2002 N/A N/A 4,370 N/A
125. 21594 Atlas Free/Ogle #1 1/3/2003 N/A N/A 4,027 N/A
126. 21598 Atlas Marian #3 2/15/2003 N/A N/A 4,300 N/A
127. 21599 Atlas Carroll #3 2/4/2003 N/A N/A 4,210 N/A
128. 21601 Atlas Debord #5 1/24/2003 N/A N/A 3,860 N/A
129. 21605 Atlas Debord #2 2/6/2003 N/A N/A 4,070 N/A
130. 21606 Atlas Conrail #9 1/10/2003 N/A N/A 3,850 N/A
34
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.
TOTAL MCF
THROUGH
3/31/03 TOTAL LATEST 30
ID DATE MOS ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
131. 21607 Atlas Conrail #8 1/5/2003 1 187 3,950 187
132. 21613 Atlas Jackson Farms #2 4/10/2003 N/A N/A 3,010 N/A
133. 21614 Atlas Debord #3 2/1/2003 N/A N/A 4,080 N/A
134. 21615 Atlas Debord #4 1/19/2003 N/A N/A 3,920 N/A
135. 21621 W. Burkland E.Dziak #2 1/7/2003 N/A N/A 4,241 N/A
136. 21624 Atlas Erjavec #1 3/12/2003 N/A N/A 4,510 N/A
137. 21630 Atlas Langley #1 2/25/2003 N/A N/A 4,420 N/A
138. 21644 Atlas Yoder #17 2/15/2003 N/A N/A 4,220 N/A
139. 21645 Atlas Yoder #19 3/3/2003 N/A N/A 3,015 N/A
140. 21646 Atlas Yoder #18 2/25/2003 N/A N/A 4,120 N/A
141. 21650 Atlas Yoder #20 3/11/2003 N/A N/A 4,070 N/A
142. 21652 Atlas Jackson Farms #6 3/4/2003 N/A N/A 4,550 N/A
143. 21681 Atlas Jackson Farms #19 4/2/2003 N/A N/A 4,070 N/A
144. 90018 Manufacturers Light & Heat Co. Alva J. Wolfe #L-4190 1/15/1954 N/A N/A 542 N/A
145. 90059 Greensboro Gas Co Hogsett #4 10/23/1923 N/A N/A 3045 N/A
146. 90066 Greensboro Gas Co Hogsett #1 1/1/1911 N/A N/A 3117 N/A
147. 90067 Greensboro Gas Co Hogsett #3 6/19/1923 N/A N/A 3196 N/A
148. 90068 Greensboro Gas Co Christopher #1 1/15/1915 N/A N/A 3100 N/A
149. 90069 Greensboro Gas Co Christopher #2 2/13/1917 N/A N/A 3065 N/A
150. 90071 Greensboro Gas Co John Gibson #2 3/18/1920 N/A N/A 3108 N/A
151. 90072 Greensboro Gas Co Conwell #2 3/5/1910 N/A N/A 3240 N/A
152. 90073 Greensboro Gas Co E. Franks #1 9/21/1917 N/A N/A 2957 N/A
153. 90075 Greensboro Gas Co T. Acklin #120 5/28/1907 N/A N/A 2966 N/A
154. 90080 Greensboro Gas Co Krepps N/A N/A N/A 3099 N/A
155. 90081 Greensboro Gas Co Krepps #2 10/21/1910 N/A N/A 3106 N/A
156. 90088 Greensboro Gas Co L.W. Porter #113 9/1/1907 N/A N/A 3004 N/A
35
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.
TOTAL MCF
THROUGH
3/31/03 TOTAL LATEST 30
ID DATE MOS ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
157. 90092 Greensboro Gas Co W.J. Stewart #1 11/14/1906 N/A N/A 2925 N/A
158. 90094 Greensboro Gas Co W.J. Stewart #2 8/1/1910 N/A N/A 3090 N/A
159. 90095 Greensboro Gas Co J.V. Thompson #1 6/17/1910 N/A N/A 3309 N/A
160. 90096 Greensboro Gas Co J.C. Vernon #144 9/1/1908 N/A N/A 2333 N/A
161. 90097 Greensboro Gas Co Vernon Heirs 3/23/1905 N/A N/A 2930 N/A
162. 90100 Greensboro Gas Co Adam M. Jacobs #4 5/23/1917 N/A N/A 2751 N/A
163. 90101 Greensboro Gas Co Christopher #3 2/3/1923 N/A N/A 3206 N/A
164. 90106 Greensboro Gas Co A.M.R. Jacobs #3 1/19/1917 N/A N/A 1540 N/A
165. 90162 Greensboro Gas Co R. Fleming #1 4/1/1905 N/A N/A 4054 N/A
166. 90163 Greensboro Gas Co J.S. Rittenhouse #1 3/30/1905 N/A N/A 3788 N/A
167. 90169 Greensboro Gas Co J.R. Colley 4/1/1905 N/A N/A 4319 N/A
168. F22816 N/A Hazen #1 N/A N/A N/A 3768 N/A
169. FGN14 N/A H.C. Frick #1 before 1935 N/A N/A est 1700 N/A
170. FL38 N/A Jacobs N/A N/A N/A N/A N/A
171. FL49 N/A N/A N/A N/A N/A N/A N/A
172. G169 Greensboro Gas Co J.W. Hibbs #1 21/2/1909 N/A N/A 2885 N/A
173. G174 Greensboro Gas Co J.E. Craft #1 9/17/1909 N/A N/A 3263 N/A
174. G194 Greensboro Gas Co J.V. Thompson #2 10/13/1910 N/A N/A 3010 N/A
175. G333 Greensboro Gas Co Shanefelter #1 9/4/1915 N/A N/A 4040 N/A
176. G393 Greensboro Gas Co Shanefelter #2 2/1/1917 N/A N/A 3636 N/A
177. G469 Greensboro Gas Co Flemming #2 5/15/1919 N/A N/A 3335 N/A
178. P1230 N/A N/A N/A N/A N/A N/A N/A
179. P1233 Greensboro Gas Co N/A 9/30/1909 N/A N/A 3125 N/A
180. P1236 Greensboro Gas Co N/A 6/27/1906 N/A N/A 2838 N/A
181. P1237 Greensboro Gas Co J.M. West #1 6/18/1909 N/A N/A 2875 N/A
182. P1240 Greensboro Gas Co Dearth #1 8/12/1907 N/A N/A N/A N/A
36
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.
TOTAL MCF
THROUGH
3/31/03 TOTAL LATEST 30
ID DATE MOS ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
183. P1240 Greensboro Gas Co Porter #1 9/5/1907 N/A N/A 3004 N/A
184. P1241 Greensboro Gas Co Aeklin #1 1/11/1910 N/A N/A 2330 N/A
185. P1242 Greensboro Gas Co Porter #2 1/17/1914 N/A N/A 2974 N/A
186. P1247 Greensboro Gas Co Lightey #1 12/8/1913 N/A N/A 3121 N/A
187. P1269 Monongahela Natural Gas Co. J. Hackney 7/17/1909 N/A N/A 3140 N/A
188. P1270 Manufacturers Light & Heat Co. Hackney 12/16/1916 N/A N/A 3549 N/A
189. P1272 Greensboro Gas Co N. Dearth 9/14/1907 N/A N/A 2328 N/A
190. P1274 N/A N/A N/A N/A N/A N/A N/A
191. P1275 Greensboro Gas Co A. Arensburg #2 11/25/1907 N/A N/A 2397 N/A
192. P1276 Greensboro Gas Co A. Arnesburg #1 11/15/1907 N/A N/A 2418 N/A
193. P1281 Peoples Natural Gas Co Hackney #3 7/1/1921 N/A N/A N/A N/A
194. P16493 Greensboro Gas Co A. Jacobs #3 9/24/1922 N/A N/A 1684 N/A
195. P21257 C.D. White & Co. V. Pollack #1 4/7/1939 N/A N/A 2530 N/A
196. P22272 Wahler & Powers Reynolds #3 6/29/1940 N/A N/A N/A N/A
197. P23858 N/A McWilliams #1 before 1935 N/A N/A est 2120 N/A
198. P23860 N/A H.C. Frick before 1935 N/A N/A est 2300 N/A
199. P23862 N/A T. Hoover before 1935 N/A N/A est 2300 N/A
200. P23863 N/A Unknown before 1935 N/A N/A est 2150 N/A
201. P24176 Forest Oil Co W. Larden about 1900 N/A N/A N/A N/A
202. P24184 N/A Hess N/A N/A N/A N/A N/A
203. P24185 N/A Hoover N/A N/A N/A N/A N/A
204. P24186 N/A Hoover N/A N/A N/A N/A N/A
205. P24314 L. Williams N/A 12/1/1929 N/A N/A 2799 N/A
206. P24514 Monongahela Natural Gas Co. H. Newcomer 12/24/1907 N/A N/A 3389 N/A
207. P24515 Monongahela Natural Gas Co. N/A 1/27/1909 N/A N/A 2509 N/A
208. P25173 Monongahela Natural Gas Co. G. Acklin 12/17/1910 N/A N/A 3096 N/A
37
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.
TOTAL MCF
THROUGH
3/31/03 TOTAL LATEST 30
ID DATE MOS ON EXCEPT LOGGERS DAY
NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH PRODUCTION
209. P26665 Nollem Oil & Gas Corp. B.F. Johnson #1 9/22/1944 N/A N/A 3598 N/A
210. P27173 Nollem Oil & Gas Corp. Neff Heirs #2 7/20/1945 N/A N/A 3551 N/A
211. P27648 R.Murray et al Hibbs #1 5/19/1946 N/A N/A 1913 N/A
212. P27813 R.Murray et al Hibbs Heirs #2 9/4/1946 N/A N/A 3087 N/A
213. P29372 E.C. Metzler W. Lardin #1 1/16/1950 N/A N/A 3702 N/A
214. PNG3326 Peoples Natural Gas Co J.A. Baer #1 2/26/1942 N/A N/A 3520 N/A
215. PNG3406 Peoples Natural Gas Co W.I. Moore #3406 6/8/1943 N/A N/A 3566 N/A
216. PNG3426 Peoples Natural Gas Co J.N. Randolph #1 1/19/1944 N/A N/A 3869 N/A
217. PNG3603 Peoples Natural Gas Co Republic Colleries #1 7/27/1945 N/A N/A 2989 N/A
218. PNG3619 Peoples Natural Gas Co Girolami #1 9/25/1945 N/A N/A 3258 N/A
219. PNG3664 Peoples Natural Gas Co McCann #1 10/28/1946 N/A N/A N/A N/A
220. PNG3671 Peoples Natural Gas Co Podolinski #1 9/27/1946 N/A N/A N/A N/A
221. PNG3672 Peoples Natural Gas Co H.Hogsett #3 12/10/1946 N/A N/A 3212 N/A
222. PNG3724 Peoples Natural Gas Co H.Hogsett #4 8/14/1947 N/A N/A 3327 N/A
223. PNG3860 Peoples Natural Gas Co N/A 7/27/1949 N/A N/A 3108 N/A
224. PNG3924 Peoples Natural Gas Co C. Yuras #2 8/8/1950 N/A N/A 3501 N/A
38
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
FAYETTE AND GREENE COUNTIES, PENNSYLVANIA
39
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
Fayette Prospect Area
Pennsylvania
Dated: May 6, 2003
Program proposed by: Report submitted by:
ATLAS RESOURCES, INC. UEDC
311 Rouser Road United Energy Development Consultants, Inc.
P.O. Box 611 1715 Crafton Blvd.
Moon Township, PA 15108 Pittsburgh, PA 15205
LOCATION MAP - AREA OF INTEREST
[GRAPHIC OMITTED]
TABLE OF CONTENTS
LOCATION MAP - AREA OF INTEREST .......................................... 1
TABLE OF CONTENTS ........................................................ 1
INVESTIGATION SUMMARY .................................................... 2
OBJECTIVE ............................................................... 2
AREA OF INVESTIGATION ................................................... 2
METHODOLOGY ............................................................. 2
PROSPECT AREA HISTORY .................................................... 2
DRILLING ACTIVITY ....................................................... 2
GEOLOGY ................................................................. 2
STRATIGRAPHY, LITHOLOGY & DEPOSITION .................................. 2
RESERVOIR CHARACTERISTICS ............................................. 4
PRODUCTION .............................................................. 4
CONCLUSION .............................................................. 5
DISCLAIMER .............................................................. 5
NON-INTEREST ............................................................ 5
40
INVESTIGATION SUMMARY
OBJECTIVE
The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Fayette Prospect Area as proposed
by Atlas Resources, Inc. ("Atlas").
AREA OF INVESTIGATION
A portion of this prospect area, herein identified for drilling in Atlas
America Public #12-2003 Limited Partnership, contains acreage in Luzerne,
Redstone, Menallen, Nicholson, and Franklin Townships in Fayette County,
located in western Pennsylvania. Thirty-two (32) drilling prospects have
currently been designated for this program in the prospect area, which will be
targeted to produce natural gas from Mississippian and Upper Devonian
reservoirs, found at depths from 1300 feet to 4500 feet beneath the earth's
surface. These will be the only prospects evaluated for the purposes of this
report.
METHODOLOGY
Atlas provided the data incorporated into this report. Geological mapping
and the interpretations by Atlas geologists were also examined. Available
"electric" log, completion and production data on "key" wells within and
adjacent to the defined prospect area were utilized to determine productive
and depositional trends
PROSPECT AREA HISTORY
DRILLING ACTIVITY
The proposed drilling area lies within a region of southwestern
Pennsylvania, which has been active for the past six years in terms of
exploration for, and exploitation of natural gas reserves. Development within
and adjacent to the Fayette Prospect Area has continued steadily since 1996.
Over two hundred seventy five (275) wells have been drilled in the area during
this period. Atlas has encountered favorable drilling and production results
while solidifying a strong acreage position of nearly 50,000 acres, as Atlas
continues to identify and extend productive trends. Drilling is ongoing as of
the date of this report with recent wells displaying favorable initial
drilling and completion results.
The area of proposed drilling is situated in portions of Fayette and
Greene Counties that have had established production from shallower, historic
pay zones. Atlas will target deeper pay zones when locating a drill site
within the "old shallow field area". Otherwise, Atlas 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 producing zone in
this region, with some wells still producing long beyond fifty years. There is
not much history of production from the 2nd Gas Sand in this area.
The Upper Devonian reservoirs consist of three groups of sands, Upper
Venango, Lower Venango and Bradford. Each of these "Groups" has multiple
reservoirs making up their total rock section. The Upper Venango Group
consists of the Gantz Sand and the Fifty Foot Sand. The Lower Venango Group
consists of the Fifth Sand and the Bayard Sand. Depositional environments of
these Upper and Lower Venango Group sands are of near shore to offshore marine
settings related to the last major advance of the Catskill Delta. The Bradford
Group consists of the Lower Warren Sand, Upper Speechley Sand, Lower Speechley
Sand, Upper 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.
41
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) Fifty Foot, 5) Fifth, 6) Bayard,
7) L.Warren, 8) U.Speechley, 9) L.Speechley, 10) U. Balltown, 11) First
Bradford Sand
Stratigraphic relationships are illustrated in the diagram:
[GRAPHIC OMITTED]
o The Burgoon Sandstone is a fine to medium grained, medium to massively
bedded, light-gray sandstone ranging in thickness from 200-250 feet. Average
porosity values for this sand range from 6% to 12% regionally. It is not
uncommon to encounter porosities as high as 20% and attendant producible
natural open flows from this sand. Tracking these producible natural open flow
trends is targeted for further development. Also, this zone does produce water
in certain locales within the Fayette Prospect Area. This reservoir is
considered a secondary target in the natural open flow trend areas.
o The 2nd Gas Sand of this region has limited areal extent and therefore is
not discussed in the literature regarding lithology, thickness etc. It can be
inferred from underlying and overlying sands that it is probably a fine to
very fine grained, light gray sand. Subsurface mapping indicates that the sand
can achieve a thickness of twenty (20) feet. Average porosity values for this
sand range from 10% to 13% when this zone is present in the area. Peak
porosities of 17% have been encountered within the prospect area. This
reservoir is considered to be a secondary target when encountered.
o The Gantz Sand is a white to light-gray, medium to coarse-grained
sandstone ranging in thickness from a few feet to over sixty (60) feet.
Average porosity values for this sand range from 5% to 10% regionally. Within
the area of investigation, porosities in excess of 13% occur within localized
trends characterized by producible natural open flows. These trends are
targeted for future development. This reservoir is considered a primary target
in the natural open flow trend areas.
o The Fifty Foot Sand is a white to light gray, thinly bedded, fine-grained
sandstone ranging in thickness from ten (10) to thirty (30) feet. Average
porosity values for this sand range from 5% to 8% regionally. Within the
prospect area, porosities in excess of 12% occur within localized trends
targeted for future development. This sand reservoir is considered a secondary
target.
o The Fifth Sand is a white to light gray, very fine to fine grained
sandstone ranging in thickness from a few feet to forty (40) feet. Within the
main Fifth fairway, porosity values average from 9% to 15%. This sand is
considered a primary target and will be exploited in future development.
o The Bayard Sand in the prospect area ranges in thickness from a few feet
to more than sixty (60) feet. Average porosity values range from 5% to 12% for
this fine to coarse-grained sandstone. Discrete reservoirs within the sand
have been identified and mapped. Gas shows in the member sandstones delineate
trends within the prospect area and will be targeted for future development.
This sand is considered a primary target.
o The Lower Warren Sand is a primary target in the prospect area. Average
thickness for this sand ranges from zero (0) feet to over forty (40) feet.
Porosities average between 8% and 12% in the area. Gas shows are commonly
found in this sand, which is probably a fine-grained, well-sorted sand. This
reservoir is targeted for future development.
o The Upper Speechley Sand is considered a secondary target with average
thickness ranging from two (2) feet to ten (10) feet over much of the prospect
area. Gas shows from this sand are common throughout the area and the zone is
combined with other zones when treated.
o The Lower Speechley Sand is a primary target in the area with reservoir
thickness ranging from zero (0) to over forty (40) feet. Average porosity
values range from 5% to 12% where the sand is present. Significant natural and
after treatment flows from this sand have been encountered. This sand is being
targeted throughout the prospect area.
o The Upper Balltown Sand is currently being produced in a few wells in the
prospect area. The zone is a siltstone with fracture-enhanced porosity, based
on log interpretation, and has associated gas shows. This sand is considered a
secondary target and is usually combined with other zones when treated.
o The First Bradford Sand, like the Balltown above, is currently being
produced in a few wells in the prospect area. This silty-sand does have
porosity up to 10% in the area and is considered to be a secondary target when
encountered.
42
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping commercial quantities of natural gas in a more permeable medium. In
the Mississippian and Upper Devonian reservoirs, this occurs either
stratigraphically when a permeable sand containing hydrocarbons encounters
impermeable shale or when permeable sand changes gradually into non-permeable
sand by a cementation process known as "diagenesis". Thus, this type of trap
represents cemented-in hydrocarbon accumulations.
[GRAPHIC OMITTED]
Electric well logs can be used in conjunction with production to interpret
reservoir parameters. When sandstones in the Mississippian and Upper Devonian
reservoirs develop porosity in excess of 8%, or a bulk density of 2.50 or
less, the permeability of the reservoir can become great enough to allow
commercial production of natural gas. Small, naturally occurring cracks in the
formation, referred to as micro-fractures, can also enhance permeability.
A gamma, bulk density, neutron, induction and temperature log suite
showing sand development in both the Mississippian and Upper Devonian
reservoirs is illustrated.
The temperature log shown in the illustration at left identifies where gas
is entering the wellbore. Evidence of a temperature "kick" or cooling is also
an indication of enhanced permeability and the willingness of the reservoir to
produce natural gas.
PRODUCTION
The Fayette prospect area produces from a number of reservoirs of
different age and type. Each well has a unique combination of these reservoirs
yielding different production declines. While Atlas anticipates production
from each reservoir to be comparable to like reservoirs historically produced
throughout the Appalachian Basin, a model decline curve for this prospect area
is not included due to the multiple sets of commingled reservoirs exclusively
found in this area.
43
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the drilling area for
Atlas America Public #12-2003 Limited Partnership, which will consist of
developmental drilling of Lower Mississippian and Upper Devonian reservoirs
primarily in Fayette County, Pennsylvania. It is the professional opinion of
UEDC that the drilling of the thirty-two wells by Atlas America Public #12-
2003 Limited Partnership is supported by sufficient geologic and engineering
data.
DISCLAIMER
For the purpose of this evaluation, UEDC did not visit any leaseholds or
inspect any of the associated production equipment. Likewise, UEDC has no
knowledge as to the validity of title, liabilities, or corporate matters
affecting these properties. UEDC does not warrant individual well performance.
NON-INTEREST
We hereby confirm that UEDC is an independent consulting firm and that
neither this firm or any of it's employees, contract consultants, or officers
has, or is committed to acquire any interest, directly or indirectly, in Atlas
Resources, Inc.; nor is this firm, or any employee, contract consultant, or
officer thereof, otherwise affiliated with Atlas Resources, Inc. We also
confirm that neither the employment of, nor payment of compensation received
by UEDC in connection with this report, is on a contingent basis.
Respectfully submitted,
/s/ Robin Anthony
-----------------
UEDC, Inc.
44
LEASE INFORMATION
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA,
45
Overriding Overriding
Royalty Interest Royalty Net
Effective Expiration Landowner to the Managing Interest to 3rd Revenue
Prospect Name County Date* Date* Royalty General Partner Parties (1) Interest
-------------------------------------------------------------------------------------------------------------------------------
1. Andree#1 Armstrong 09/20/01 HBP 12.5% 0% 3.125% 63.281%
2. Kiski Sportsmen#8 Armstrong 04/27/98 HBP 12.5% 0% 3.125% 63.281%
3. Lytle#3 Armstrong 08/28/01 08/28/11 12.5% 0% 3.125% 63.281%
4. Morgan#1 Armstrong 01/22/01 01/22/04 12.5% 0% 3.125% 63.281%
5. Wheatley#5 Armstrong 11/24/97 HBP 12.5% 0% 3.125% 63.281%
6. Bosch#7 Indiana 01/07/99 HBP 12.5% 0% 3.125% 63.281%
7. Cup#1 Indiana 03/31/99 03/31/04 12.5% 0% 3.125% 63.281%
8. Deforno#1 Indiana 04/08/02 10/08/03 12.5% 0% 3.125% 63.281%
9. Lynn#1 Indiana 03/30/99 03/30/04 12.5% 0% 3.125% 63.281%
10. Speranza#4 Indiana 06/16/99 HBP 12.5% 0% 3.125% 63.281%
11. Speranza#9 Indiana 06/16/99 HBP 12.5% 0% 3.125% 63.281%
Net Acres to be
Working Net Assigned to
Prospect Name Interest Acres the Partnership
-----------------------------------------------------------------
1. Andree#1 75% 130 14.60
2. Kiski Sportsmen#8 75% 170 14.60
3. Lytle#3 75% 150 14.60
4. Morgan#1 75% 98 14.60
5. Wheatley#5 75% 240 14.60
6. Bosch#7 75% 121 14.60
7. Cup#1 75% 145 14.60
8. Deforno#1 75% 77 14.60
9. Lynn#1 75% 80 14.60
10. Speranza#4 75% 150 14.60
11. Speranza#9 75% 150 14.60
- ---------------
* HBP - Held by Production
(1) U.S. Energy Exploration, originator of the prospect and 25% working
interest owner.
46
LOCATION AND PRODUCTION MAP
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
47
[GRAPHIC OMITTED]
48
PRODUCTION DATA
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
49
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.
TOTAL MCF
MOS THROUGH 2/28/03
ID DATE ON EXCEPT WHERE
NUMBER OPERATOR WELL NAME COMPLT'D LINE NOTED
1. 02368 Dominion Peoples Wray, Et. Al. #1 5/3/1921 NA 251,497 / 1992
2. 20128 Dominion Peoples Martin #1 1/14/1958 NA 205,767 / 1992
3. 20154 Dominion Peoples Kerr #1 6/3/1958 NA 203,046 / 1992
4. 20222 Dominion Peoples Deemer #2 2/26/1896 / 12/3/1958 NA 251,637 / 1992
5. 20600 Dominion Peoples Geiger #2 10/10/1963 NA 305,774 / 1992
6. 20768 Dominion Peoples Chambers #2 7/9/1965 NA 243,610 / 1992
7. 20957 Dominion Peoples Chambers #1 3/19/1968 NA 579,140 / 1992
8. 25760 Petroleum Development Corp. (JV USEE) Becker #2 5/8/1998 25 48,880
9. 26070 Petroleum Development Corp. (JV USEE) Egley #1 10/30/00 7 12,800
10. 26078 Petroleum Development Corp. (JV USEE) Kleintop #1 12/20/98 7 10,620
11. 26090 Petroleum Development Corp. (JV USEE) Ott #1 1/19/1999 18 31,000
12. 26091 Petroleum Development Corp. (JV USEE) Becker #3 9/22/1999 10 19,660
13. 26093 Petroleum Development Corp. (JV USEE) Ott #2 9/8/1999 10 18,330
14. 26102 Petroleum Development Corp. (JV USEE) Hollabaugh #1 02/18/99 5 9,760
15. 26108 Petroleum Development Corp. (JV USEE) Wilson #2 3/15/1999 14 19,400
16. 26127 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #2 4/15/1999 14 43,010
17. 26141 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #3 6/23/1999 12 26,940
18. 26157 Petroleum Development Corp. (JV USEE) M. Couch #1 7/10/1999 12 28,440
19. 26172 Petroleum Development Corp. (JV USEE) Ott #4 9/13/1999 10 22,070
20. 26173 Petroleum Development Corp. (JV USEE) Ott #3 9/16/1999 10 16,420
21. 26188 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #4 9/25/1999 10 17,250
22. 26201 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #5 11/21/1999 6 13,300
23. 26208 Petroleum Development Corp. (JV USEE) Walker #1 12/1/1999 6 9,920
24. 26216 Petroleum Development Corp. (JV USEE) Allshouse #1 12/30/1999 7 14,190
25. 26220 Petroleum Development Corp. (JV USEE) Shearer #1 3/4/2000 6 14,580
26. 26221 Petroleum Development Corp. (JV USEE) Shearer #2 3/5/2000 4 7,550
TOTAL LATEST
ID LOGGERS 30 DAY
NUMBER OPERATOR DEPTH PROD.
1. 02368 Dominion Peoples 3096 NA
2. 20128 Dominion Peoples 3134 NA
3. 20154 Dominion Peoples 3229 NA
4. 20222 Dominion Peoples 1584/3386 NA
5. 20600 Dominion Peoples 3457 NA
6. 20768 Dominion Peoples 3604 NA
7. 20957 Dominion Peoples 3630 NA
8. 25760 Petroleum Development Corp. (JV USEE) 3510 1890
9. 26070 Petroleum Development Corp. (JV USEE) 1240 1830
10. 26078 Petroleum Development Corp. (JV USEE) 3700 1440
11. 26090 Petroleum Development Corp. (JV USEE) 3580 1650
12. 26091 Petroleum Development Corp. (JV USEE) 3500 1860
13. 26093 Petroleum Development Corp. (JV USEE) 3580 1830
14. 26102 Petroleum Development Corp. (JV USEE) 3620 1890
15. 26108 Petroleum Development Corp. (JV USEE) 3620 1350
16. 26127 Petroleum Development Corp. (JV USEE) 3680 2700
17. 26141 Petroleum Development Corp. (JV USEE) 3893 1920
18. 26157 Petroleum Development Corp. (JV USEE) 3710 2160
19. 26172 Petroleum Development Corp. (JV USEE) 3500 2130
20. 26173 Petroleum Development Corp. (JV USEE) 3560 1470
21. 26188 Petroleum Development Corp. (JV USEE) 3750 1740
22. 26201 Petroleum Development Corp. (JV USEE) 3734 2040
23. 26208 Petroleum Development Corp. (JV USEE) 4090 1530
24. 26216 Petroleum Development Corp. (JV USEE) 3560 1950
25. 26220 Petroleum Development Corp. (JV USEE) 4068 2280
26. 26221 Petroleum Development Corp. (JV USEE) 4040 1800
50
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.
TOTAL MCF
MOS THROUGH 2/28/03
ID DATE ON EXCEPT WHERE
NUMBER OPERATOR WELL NAME COMPLT'D LINE NOTED
27. 26222 Petroleum Development Corp. (JV USEE) G. Couch #1 3/10/2000 4 8,160
28. 26224 Petroleum Development Corp. (JV USEE) Walker #4 3/3/2000 4 14,100
29. 26225 Petroleum Development Corp. (JV USEE) Walker #2 3/2/2000 4 9,540
30. 26234 Petroleum Development Corp. (JV USEE) Stankay#1 3/6/2000 4 7,320
31. 26255 Petroleum Development Corp. (JV USEE) Stankay #2 3/7/2000 4 7,900
32. 26374 US Energy Exploration (JV Atlas) Sturiale #1 2/6/2002 11 1,453
33. 26426 US Energy Exploration (JV Atlas) Bafik #2 3/9/2002 10 7,776
34. 26427 US Energy Exploration (JV Atlas) Canterbury #4 5/8/2001 20 29,680
35. 26431 US Energy Exploration (JV Atlas) Canterbury #8 5/9/2001 20 14,334
36. 26437 US Energy Exploration (JV Atlas) Canterbury #12 4/30/2001 20 17,110
37. 26438 US Energy Exploration (JV Atlas) Canterbury #13 4/30/2001 20 8,563
38. 26439 US Energy Exploration (JV Atlas) Canterbury #15 7/10/2001 18 4,254
39. 26440 US Energy Exploration (JV Atlas) Canterbury #17 7/10/2001 18 4,165
40. 26442 US Energy Exploration (JV Atlas) Canterbury #20 5/22/2001 19 21,564
41. 26455 US Energy Exploration (JV Atlas) Canterbury #21 10/29/2001 14 13,445
42. 26458 US Energy Exploration (JV Atlas) Canterbury #3 5/7/2001 20 11,025
43. 26557 US Energy Exploration (JV Atlas) Barr #2 8/9/2001 17 21,014
44. 26558 US Energy Exploration (JV Atlas) Barr #3 8/25/2001 16 26,584
45. 26561 US Energy Exploration (JV Atlas) Schrecengost #2 10/29/2001 14 10,409
46. 26562 US Energy Exploration (JV Atlas) Schrecengost #3 11/6/2001 14 9,650
47. 26566 US Energy Exploration (JV Atlas) P. White #1 11/16/2001 13 6,535
48. 26596 US Energy Exploration (JV Atlas) G. Couch #3 4/24/2002 8 3,114
49. 26598 US Energy Exploration (JV Atlas) G. Couch #5 4/24/2002 8 3,497
50. 26600 US Energy Exploration (JV Atlas) Dobrosky #2 10/10/2001 15 18,539
51. 26621 US Energy Exploration (JV Atlas) Canterbury #27 10/10/2001 15 23,359
52. 26622 US Energy Exploration (JV Atlas) Canterbury #28 10/10/2001 15 21,248
TOTAL LATEST
ID LOGGERS 30 DAY
NUMBER OPERATOR DEPTH PROD.
27. 26222 Petroleum Development Corp. (JV USEE) 4070 2040
28. 26224 Petroleum Development Corp. (JV USEE) 4080 2910
29. 26225 Petroleum Development Corp. (JV USEE) 4100 1890
30. 26234 Petroleum Development Corp. (JV USEE) 4100 1560
31. 26255 Petroleum Development Corp. (JV USEE) 4098 1680
32. 26374 US Energy Exploration (JV Atlas) 3866 36
33. 26426 US Energy Exploration (JV Atlas) 3904 853
34. 26427 US Energy Exploration (JV Atlas) 3696 1348
35. 26431 US Energy Exploration (JV Atlas) 3876 585
36. 26437 US Energy Exploration (JV Atlas) 3791 493
37. 26438 US Energy Exploration (JV Atlas) 3908 227
38. 26439 US Energy Exploration (JV Atlas) 3776 163
39. 26440 US Energy Exploration (JV Atlas) 3802 325
40. 26442 US Energy Exploration (JV Atlas) 3944 1177
41. 26455 US Energy Exploration (JV Atlas) 3805 896
42. 26458 US Energy Exploration (JV Atlas) 3701 378
43. 26557 US Energy Exploration (JV Atlas) 3868 1345
44. 26558 US Energy Exploration (JV Atlas) 3898 1507
45. 26561 US Energy Exploration (JV Atlas) 3750 539
46. 26562 US Energy Exploration (JV Atlas) 3777 545
47. 26566 US Energy Exploration (JV Atlas) 3950 280
48. 26596 US Energy Exploration (JV Atlas) 4053 268
49. 26598 US Energy Exploration (JV Atlas) 4355 317
50. 26600 US Energy Exploration (JV Atlas) 3752 1428
51. 26621 US Energy Exploration (JV Atlas) 3861 1368
52. 26622 US Energy Exploration (JV Atlas) 3814 1505
51
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.
TOTAL MCF
MOS THROUGH 2/28/03
ID DATE ON EXCEPT WHERE
NUMBER OPERATOR WELL NAME COMPLT'D LINE NOTED
53. 26625 US Energy Exploration (JV Atlas) Barr #4 10/18/2001 14 21,596
54. 26627 US Energy Exploration (JV Atlas) Wilson #4 10/10/2001 15 20,472
55. 26663 US Energy Exploration (JV Atlas) Crewe #1 12/31/2001 12 20,761
56. 26669 US Energy Exploration (JV Atlas) R. White #1 11/16/2001 13 4,512
57. 26679 US Energy Exploration (JV Atlas) Canterbury #30 1/12/2002 12 15,668
58. 26680 US Energy Exploration (JV Atlas) Canterbury #34 2/18/2002 10 11,026
59. 26681 US Energy Exploration (JV Atlas) Canterbury #31 1/29/2002 11 13,293
60. 26723 US Energy Exploration (JV Atlas) Bernabo #1 1/15/2002 11 5,220
61. 26730 US Energy Exploration (JV Atlas) Canterbury #32 7/10/2002 6 5,118
62. 26741 US Energy Exploration (JV Atlas) Crewe #4 8/16/2002 4 8,148
63. 26742 US Energy Exploration (JV Atlas) Musser #1 2/11/2002 11 2,198
64. 26743 US Energy Exploration (JV Atlas) Filippini #2 2/2/2002 11 7,100
65. 26756 US Energy Exploration (JV Atlas) P. White #4 2/25/2002 10 2,631
66. 26758 US Energy Exploration (JV Atlas) Crewe #5 2/12/2002 11 16,082
67. 26788 US Energy Exploration (JV Atlas) Pomfret #1 3/29/2002 9 12,947
68. 26824 US Energy Exploration (JV Atlas) Stankay #5 N/A NA NA
69. 26827 US Energy Exploration (JV Atlas) Boggs #6 1/3/2003 NA NA
70. 26828 US Energy Exploration (JV Atlas) Boggs #7 9/28/2002 3 4,285
71. 26833 US Energy Exploration (JV Atlas) Boggs #4 8/16/2002 4 4,950
72. 26844 US Energy Exploration (JV Atlas) Filippini #3 1/9/2003 NA NA
73. 26865 US Energy Exploration (JV Atlas) Rumbaugh #1 11/14/2002 1 1,621
74. 26973 US Energy Exploration (JV Atlas) Andree #3 N/A NA NA
75. 27024 US Energy Exploration (JV Atlas) Wheatley #1 N/A NA NA
76. 27040 US Energy Exploration (JV Atlas) Pomfret #2 N/A NA NA
77. 27044 US Energy Exploration (JV Atlas) Rumbaugh #2 N/A NA NA
78. 27126 US Energy Exploration (JV Atlas) Andree #2 N/A NA NA
TOTAL LATEST
ID LOGGERS 30 DAY
NUMBER OPERATOR DEPTH PROD.
53. 26625 US Energy Exploration (JV Atlas) 3804 1518
54. 26627 US Energy Exploration (JV Atlas) 3802 1924
55. 26663 US Energy Exploration (JV Atlas) 4058 1796
56. 26669 US Energy Exploration (JV Atlas) 4062 359
57. 26679 US Energy Exploration (JV Atlas) 4151 1527
58. 26680 US Energy Exploration (JV Atlas) 4220 1289
59. 26681 US Energy Exploration (JV Atlas) 4212 1194
60. 26723 US Energy Exploration (JV Atlas) 4250 306
61. 26730 US Energy Exploration (JV Atlas) 4195 1440
62. 26741 US Energy Exploration (JV Atlas) 4153 1720
63. 26742 US Energy Exploration (JV Atlas) 4296 223
64. 26743 US Energy Exploration (JV Atlas) 3882 586
65. 26756 US Energy Exploration (JV Atlas) 4281 175
66. 26758 US Energy Exploration (JV Atlas) 4156 1782
67. 26788 US Energy Exploration (JV Atlas) 3817 1828
68. 26824 US Energy Exploration (JV Atlas) 4037 NA
69. 26827 US Energy Exploration (JV Atlas) 4104 NA
70. 26828 US Energy Exploration (JV Atlas) 4219 1542
71. 26833 US Energy Exploration (JV Atlas) 4220 1226
72. 26844 US Energy Exploration (JV Atlas) 3879 NA
73. 26865 US Energy Exploration (JV Atlas) 4600 1621
74. 26973 US Energy Exploration (JV Atlas) 4121 NA
75. 27024 US Energy Exploration (JV Atlas) 4211 NA
76. 27040 US Energy Exploration (JV Atlas) 3822 NA
77. 27044 US Energy Exploration (JV Atlas) 3808 NA
78. 27126 US Energy Exploration (JV Atlas) N/A NA
52
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.
TOTAL MCF
MOS THROUGH 2/28/03
ID DATE ON EXCEPT WHERE
NUMBER OPERATOR WELL NAME COMPLT'D LINE NOTED
79. 27127 US Energy Exploration (JV Atlas) Wheatley #3 N/A NA NA
80. 32288 Petroleum Development Corp. (JV USEE) R. Henderson #1 7/1/1999 7 17,230
81. 32418 Petroleum Development Corp. (JV USEE) C. Coleman #1 3/8/2000 4 6,960
82. 32475 Petroleum Development Corp. (JV USEE) C. Coleman #2 3/9/2000 4 7,100
83. 33016 US Energy Exploration (JV Atlas) Henderson #3 5/8/2002 8 9,691
84. 33042 US Energy Exploration (JV Atlas) Rosensteel #5 4/24/2002 8 10,752
85. 33152 US Energy Exploration (JV Atlas) Graham #1 2/12/2003 NA NA
86. 33155 US Energy Exploration (JV Atlas) Boggs #9 1/31/2003 NA NA
87. 33157 US Energy Exploration (JV Atlas) Boggs #11 N/A NA NA
88. 33159 US Energy Exploration (JV Atlas) Shearer #4 2/11/2003 NA NA
89. 33202 US Energy Exploration (JV Atlas) J. Henderson #1 1/15/2003 NA NA
90. 33273 US Energy Exploration (JV Atlas) Kapusta #2 N/A NA NA
91. 33274 US Energy Exploration (JV Atlas) Bosch #2 N/A NA NA
92. 33288 US Energy Exploration (JV Atlas) Kapusta #1 N/A NA NA
93. 33305 US Energy Exploration (JV Atlas) Bosch #4 N/A NA NA
94. 33306 US Energy Exploration (JV Atlas) Bosch #5 N/A NA NA
95. 33313 US Energy Exploration (JV Atlas) Speranza #2 N/A NA NA
TOTAL LATEST
ID LOGGERS 30 DAY
NUMBER OPERATOR DEPTH PROD.
79. 27127 US Energy Exploration (JV Atlas) 4273 NA
80. 32288 Petroleum Development Corp. (JV USEE) 5213 2400
81. 32418 Petroleum Development Corp. (JV USEE) 4220 1650
82. 32475 Petroleum Development Corp. (JV USEE) 4401 1590
83. 33016 US Energy Exploration (JV Atlas) 4502 1586
84. 33042 US Energy Exploration (JV Atlas) 4325 1645
85. 33152 US Energy Exploration (JV Atlas) 4336 NA
86. 33155 US Energy Exploration (JV Atlas) 4393 NA
87. 33157 US Energy Exploration (JV Atlas) 4361 NA
88. 33159 US Energy Exploration (JV Atlas) 4314 NA
89. 33202 US Energy Exploration (JV Atlas) 4456 NA
90. 33273 US Energy Exploration (JV Atlas) 4280 NA
91. 33274 US Energy Exploration (JV Atlas) 4392 NA
92. 33288 US Energy Exploration (JV Atlas) N/A NA
93. 33305 US Energy Exploration (JV Atlas) 4460 NA
94. 33306 US Energy Exploration (JV Atlas) 4388 NA
95. 33313 US Energy Exploration (JV Atlas) N/A NA
53
UEDC'S
GEOLOGIC EVALUATION
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
54
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
Armstrong Prospect Area
Pennsylvania
Dated: May 6, 2003
Program proposed by: Report submitted by:
ATLAS RESOURCES, INC. UEDC
311 Rouser Road United Energy Development Consultants, Inc.
P.O. Box 611 1715 Crafton Blvd.
Moon Township, PA 15108 Pittsburgh, PA 15205
LOCATION MAP - AREA OF INTEREST
[GRAPHIC OMITTED]
TABLE OF CONTENTS
LOCATION MAP - AREA OF INTEREST ............................... 1
TABLE OF CONTENTS ............................................. 1
INVESTIGATION SUMMARY ......................................... 2
OBJECTIVE ................................................. 2
AREA OF INVESTIGATION ..................................... 2
METHODOLOGY ............................................... 2
ARMSTRONG PROSPECT AREA ....................................... 2
DRILLING ACTIVITY ......................................... 2
GEOLOGY ................................................... 2
STRATIGRAPHY, LITHOLOGY & DEPOSITION .................. 2
RESERVOIR CHARACTERISTICS ............................. 3
PRODUCTION ................................................ 4
STATEMENTS .................................................... 5
CONCLUSION ................................................ 5
DISCLAIMER ................................................ 5
NON-INTEREST .............................................. 5
55
INVESTIGATION SUMMARY
OBJECTIVE
The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Armstrong Prospect Area as proposed
by Atlas Resources, Inc. ("Atlas").
AREA OF INVESTIGATION
A portion of this prospect area, herein identified for drilling in Atlas
America Public #12-2003 Limited Partnership, contains acreage in Kiskiminetas
Township of Armstrong County and Young and Conemaugh Townships of Indiana
County, Pennsylvania. These townships are located in western Pennsylvania.
Eleven (11) drilling prospects have currently been designated for this program
in the prospect area, which will be targeted to produce natural gas from Upper
Devonian reservoirs, found at depths from 1800 feet to 4500 feet beneath the
earth's surface. These will be the only prospects evaluated for the purposes
of this report.
METHODOLOGY
Atlas and the in-house archives of UEDC, Inc. provided the data
incorporated into this report. Geological mapping and the interpretations by
Atlas geologists were also examined. Available "electric" log, completion and
production data on "key" wells within and adjacent to the defined prospect
area were used to determine productive and depositional trends.
ARMSTRONG PROSPECT AREA
DRILLING ACTIVITY
The proposed drilling area lies within a region of southwestern
Pennsylvania, which has seen sporadic activity for more than the past 150
years in terms of exploration for, and exploitation of natural gas reserves.
Modern development within and adjacent to the Armstrong Prospect Area has
continued steadily since 1950. Over 1500 wells have been drilled in the area
during this period. Atlas has entered into a Joint Venture relationship with
US Energy Exploration. Located in Rural Valley, Pennsylvania (which is less
than 20 miles from the prospect area), US Energy is a local oil and gas
producer with more than 15 years experience developing this play and currently
operates over 325 wells within and adjacent to the prospect area. US Energy
currently maintains an acreage position of over 14,000 acres. Within the
prospect, Atlas and its partner adhere to the state regulations for spacing of
wells in areas of deep coal mining, which is one thousand (1000) feet in most
cases. Atlas continues to identify and extend productive trends. Drilling is
ongoing as of the date of this report with recent wells displaying favorable
initial drilling and completion results.
GEOLOGY
STRATIGRAPHY, LITHOLOGY & DEPOSITION
In southern Armstrong County the Upper Devonian Bradford Group reservoirs
are typically characterized as submarine fan deposits. They are thought to
have traveled westward (seaward) down slope from sands deposited out in front
of massive deltas throughout Indiana and surrounding counties. The Bradford
Group consists of the Lower Warren Sand; Upper and Lower Speechley Sands;
Upper, Middle, and Lower Balltown Sands and the First Bradford Sand.
[GRAPHIC OMITTED]
Stratigraphically, in descending order, the potentially productive units
of the Upper Devonian Groups are: 1.) Hundred Foot, 2.) Gordon, 3.) Fifth, 4.)
Bayard, 5.) L. Warren, 6.) Upper Speechley, 7.) Lower Speechley, 8.) Upper
Balltown, 9.) Middle Balltown, 10.) Lower Balltown, 11.) First Bradford. These
stratigraphic relationships are illustrated in the diagram.
56
The Hundred Foot Sand is the shallowest sand of Devonian age encountered
in this area. This sand is highly variable in its thickness and porosity
development. Often it is in excess of one hundred (100) feet thick with
porosities in excess of 18%. Frequently it is accompanied by gas shows and it
is used as a gas storage reservoir just to the north of the acreage. Due to
its shallow depth and attendant lower pressure this zone is not treated or
commingled with the deeper reservoirs found in the play area. However, this
zone has the potential for a producible natural completion and is considered a
secondary target.
The Gordon Sand appears sporadic across the play area and ranges in
thickness from nearly ten (10) feet to twenty (20) feet. Porosities range from
6% to about 10%. This sand is considered a secondary target.
The Fifth Sand ranges in thickness from a few feet to thirty (30) feet.
Porosity values are typically 5% to 12%. This sand is considered a secondary
target.
The Bayard Sand in the prospect area ranges in thickness from a few feet
to more than thirty (30) feet. Porosity values range from 8% to 18% for this
sandstone. This sand is also considered a secondary target.
The Warren Sands are a primary target when encountered in the prospect
area. Typically the lower portion of the Warren interval is better developed.
When sand is present in this interval the average thickness ranges from
several feet to over thirty (30) feet. Porosities range between 6% and 12% in
the area.
The Speechley Sands are considered both primary and secondary targets
depending on where in the play area they are encountered. Present are an upper
and lower sand separated by fifty (50) to seventy-five (75) feet of shale. The
upper sand thickness ranges from just a few feet to more than twenty (20) feet
and porosity typically ranges from 5% to 12%. Meanwhile the lower sand is
usually twenty (20) feet to forty (40) feet thick with porosities that are
often between 5% to 12%.
The Balltown Sands have limited extent throughout the project area.
Generally sand development in the upper portion of the Balltown interval is
most favorable and when encountered is typically fifteen (15) feet thick with
porosities as high as 20%. This sand is often accompanied by a gas show and is
thought to be a significant producer. In areas where this sand is more
prevalent it is considered a primary target, but is found sporadically across
the play area. Sand development in other portions of this interval are also
limited in extent but are treated when encountered.
The First Bradford Sand is the primary target in all wells in this
immediate area. This sand is present in every well drilled thus far on the
acreage. The First Bradford sand will generally range from ten (10) feet in
thickness to over thirty-five (35) feet in several distinct trends. Porosities
typically range from 8% to 14%. This sand is nearly always accompanied by a
gas show. Occasionally, a deeper sand, the Second Bradford sand, develops
seventy (70) to one hundred (100) feet below the First Bradford. When
warranted, this sand is also completed..
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping commercial quantities of natural gas in a more permeable medium. In
the Upper Devonian reservoirs, this occurs either stratigraphically when a
permeable sand containing hydrocarbons encounters impermeable shale or when
permeable sand changes gradually into non-permeable sand by a cementation
process known as "diagenesis". Thus, this type of trap represents cemented-in
hydrocarbon accumulations.
Electric well logs can be used in conjunction with production to interpret
reservoir parameters. When sandstones in the Upper Devonian reservoirs develop
porosity in excess of 8%, or a bulk density of 2.50 or less, the permeability
of the reservoir can become great enough to allow commercial production of
natural gas. Small, naturally occurring cracks in the formation, referred to
as micro-fractures, can also enhance permeability. A gamma, bulk density,
neutron, induction and temperature log suite showing sand development in an
Upper Devonian reservoir is illustrated on the following page.
57
[GRAPHIC OMITTED]
The temperature log shown in the illustration at left identifies where gas is
entering the wellbore. Evidence of a temperature "kick" or cooling is also an
indication of enhanced permeability and the willingness of the reservoir to
produce natural gas.
PRODUCTION
The Armstrong prospect area produces from several reservoirs of different
age and type. Each well has a unique combination of these reservoirs yielding
different production declines. While Atlas anticipates production from each
reservoir to be comparable to like reservoirs historically produced throughout
the Appalachian Basin, a model decline curve for this prospect area is not
included due to the multiple sets of commingled reservoirs exclusively found
in this area.
58
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the drilling area for Atlas
America Public #12-2003 Limited Partnership, which will consist of developmental
drilling of Upper Devonian reservoirs in Armstrong and Indiana Counties,
Pennsylvania. It is the professional opinion of UEDC that the drilling of the
eleven (11) wells by Atlas America Public #12-2003 Limited Partnership is
supported by sufficient geologic and engineering data.
DISCLAIMER
For the purpose of this evaluation, UEDC did not visit any leaseholds or
inspect any of the associated production equipment. Likewise, UEDC has no
knowledge as to the validity of title, liabilities, or corporate matters
affecting these properties. UEDC does not warrant individual well performance.
NON-INTEREST
We hereby confirm that UEDC is an independent consulting firm and that
neither this firm or any of it's employees, contract consultants, or officers
has, or is committed to acquire any interest, directly or indirectly, in Atlas
Resources, Inc.; nor is this firm, or any employee, contract consultant, or
officer thereof, otherwise affiliated with Atlas Resources, Inc. We also
confirm that neither the employment of, nor payment of compensation received
by UEDC in connection with this report, is on a contingent basis.
Respectfully submitted,
Robin Anthony
-------------
UEDC, Inc.
59
EXHIBIT (A)
FORM OF
LIMITED PARTNERSHIP AGREEMENT OF
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
[ATLAS AMERICA PUBLIC #12-2004(___) LIMITED PARTNERSHIP]
TABLE OF CONTENTS
Section No. Description Page Section No. Description Page
I. FORMATION VII. DURATION, DISSOLUTION, AND WINDING UP
1.01 Formation............................. 1 7.01 Duration.............................. 47
1.02 Certificate of Limited Partnership.... 1 7.02 Dissolution and Winding Up............ 47
1.03 Name, Principal Office and Residence.. 1
1.04 Purpose............................... 1 VIII. MISCELLANEOUS PROVISIONS
8.01 Notices............................... 48
II. DEFINITION OF TERMS 8.02 Time.................................. 49
2.01 Definitions........................... 2 8.03 Applicable Law........................ 49
8.04 Agreement in Counterparts............. 49
III. SUBSCRIPTIONS AND FURTHER CAPITAL 8.05 Amendment............................. 49
CONTRIBUTIONS 8.06 Additional Partners................... 49
3.01 Designation of Managing General 8.07 Legal Effect.......................... 49
Partner and Participants ........... 10
3.02 Participants.......................... 10 EXHIBITS
3.03 Subscriptions to the Partnership...... 11 EXHIBIT (I-A) -
3.04 Capital Contributions of the Managing Form of Managing General Partner Signature Page
General Partner....................... 12 EXHIBIT (I-B) -
3.05 Payment of Subscriptions.............. 13 Form of Subscription Agreement
3.06 Partnership Funds..................... 13 EXHIBIT (II) -
Form of Drilling and Operating Agreement
IV. CONDUCT OF OPERATIONS
4.01 Acquisition of Leases................. 14
4.02 Conduct of Operations................. 15
4.03 General Rights and Obligations of the
Participants and Restricted and
Prohibited Transactions........... 20
4.04 Designation, Compensation and Removal
of Managing General Partner and
Removal of Operator............... 30
4.05 Indemnification and Exoneration....... 32
4.06 Other Activities...................... 34
V. PARTICIPATION IN COSTS AND REVENUES, CAPITAL
ACCOUNTS, ELECTIONS AND DISTRIBUTIONS
5.01 Participation in Costs and Revenues... 35
5.02 Capital Accounts and Allocations
Thereto........................... 39
5.03 Allocation of Income, Deductions and
Credits........................... 40
5.04 Elections............................. 41
5.05 Distributions......................... 42
VI. TRANSFER OF INTERESTS
6.01 Transferability....................... 43
6.02 Special Restrictions on Transfers..... 43
6.03 Right of Managing General Partner to
Hypothecate and/or Withdraw Its
Interests............................. 45
6.04 Presentment........................... 45
i
FORM OF LIMITED PARTNERSHIP AGREEMENT OF
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
[ATLAS AMERICA PUBLIC #12-2004(_____) LIMITED PARTNERSHIP]
THIS AGREEMENT OF LIMITED PARTNERSHIP ("AGREEMENT"), is made and entered into
as of _____________________, 2003, by and among Atlas Resources, Inc.,
referred to as "Atlas" or the "Managing General Partner," and the remaining
parties from time to time signing a Subscription Agreement for Limited Partner
Units, these parties sometimes referred to as "Limited Partners," or for
Investor General Partner Units, these parties sometimes referred to as
"Investor General Partners."
ARTICLE I
FORMATION
1.01. Formation. Subject to the provisions of this agreement, the parties
hereto do hereby form a limited partnership under the Delaware Revised Uniform
Limited Partnership Act on the terms and conditions set forth in this
Agreement.
1.02. Certificate of Limited Partnership. This document is not only an
agreement among the parties, but also may be the 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 #12-2003
Limited Partnership and [Atlas America Public #12-2004(_____) Limited
Partnership].
1.03(b). Residence. The residence of the Managing General Partner is its
principal place of business at 311 Rouser Road, Moon Township, Pennsylvania
15108, which shall also serve as the principal place of business of the
Partnership.
The residence of each Participant shall be as set forth on the Subscription
Agreement executed by the Participant.
All addresses shall be subject to change on notice to the parties.
1.03(c). Agent for Service of Process. The name and address of the agent for
service of process shall be Mr. Jack L. Hollander at Atlas Resources, Inc.,
311 Rouser Road, Moon Township, Pennsylvania 15108.
1.04. Purpose. The Partnership shall engage in all phases of the natural gas
and oil business. This includes, without limitation, exploration for,
development and production of natural gas and oil on the terms and conditions
set forth below and any other proper purpose under the Delaware Revised
Uniform Limited Partnership Act.
The Managing General Partner may not, without the affirmative vote of
Participants whose Units equal a majority of the total Units, do the
following:
(i) change the investment and business purpose of the Partnership;
or
(ii) cause the Partnership to engage in activities outside the
stated business purposes of the Partnership through joint
ventures with other entities.
1
ARTICLE II
DEFINITION OF TERMS
2.01. Definitions. As used in this Agreement, the following terms shall have
the meanings set forth below:
1. "Administrative Costs" means all customary and routine expenses
incurred by the Sponsor for the conduct of Partnership
administration, including: in-house legal, finance, in-house
accounting, secretarial, travel, office rent, telephone, data
processing and other items of a similar nature. Administrative
Costs shall be limited as follows:
(i) no Administrative Costs charged shall be duplicated
under any other category of expense or cost; and
(ii) no portion of the salaries, benefits, compensation or
remuneration of controlling persons of the Managing
General Partner shall be reimbursed by the Partnership
as Administrative Costs. Controlling persons include
directors, executive officers and those holding 5% or
more equity interest in the Managing General Partner or
a person having power to direct or cause the direction
of the Managing General Partner, whether through the
ownership of voting securities, by contract, or
otherwise.
2. "Administrator" means the official or agency administering the
securities laws of a state.
3. "Affiliate" means with respect to a specific person:
(i) any person directly or indirectly owning, controlling,
or holding with power to vote 10% or more of the
outstanding voting securities of the specified person;
(ii) any person 10% or more of whose outstanding voting
securities are directly or indirectly owned, controlled,
or held with power to vote, by the specified person;
(iii) any person directly or indirectly controlling,
controlled by, or under common control with the
specified person;
(iv) any officer, director, trustee or partner of the
specified person; and
(v) if the specified person is an officer, director, trustee
or partner, any person for which the person acts in any
such capacity.
4. "Agreement" means this Amended and Restated Certificate and
Agreement of Limited Partnership, including all exhibits to
this Agreement.
5. "Anthem Securities" means Anthem Securities, Inc., whose
principal executive offices are located at 311 Rouser Road,
P.O. Box 926, Coraopolis, Pennsylvania 15108-0926.
6. "Assessments" means additional amounts of capital which may be
mandatorily required of or paid voluntarily by a Participant
beyond his subscription commitment.
7. "Atlas" means Atlas Resources, Inc., a Pennsylvania
corporation, whose principal executive offices are located at
311 Rouser Road, Moon Township, Pennsylvania 15108.
8. "Capital Account" or "account" means the account established
for each party, maintained as provided in ss.5.02 and its
subsections.
9. "Capital Contribution" means the amount agreed to be
contributed to the Partnership by a Partner pursuant to
ss.ss.3.04 and 3.05 and their subsections.
2
10. "Carried Interest" means an equity interest in the Partnership
issued to a Person without consideration, in the form of cash
or tangible property, in an amount proportionately equivalent
to that received from the Participants.
11. "Code" means the Internal Revenue Code of 1986, as amended.
12. "Cost," when used with respect to the sale or transfer of
property to the Partnership, means:
(i) the sum of the prices paid by the seller or transferor
to an unaffiliated person for the property, including
bonuses;
(ii) title insurance or examination costs, brokers'
commissions, filing fees, recording costs, transfer
taxes, if any, and like charges in connection with the
acquisition of the property;
(iii) a pro rata portion of the seller's or transferor's
actual necessary and reasonable expenses for seismic and
geophysical services; and
(iv) rentals and ad valorem taxes paid by the seller or
transferor for the property to the date of its transfer
to the buyer, interest and points actually incurred on
funds used to acquire or maintain the property, and the
portion of the seller's or transferor's reasonable,
necessary and actual expenses for geological,
engineering, drafting, accounting, legal and other like
services allocated to the property cost in conformity
with generally accepted accounting principles and
industry standards, except for expenses in connection
with the past drilling of wells which are not producers
of sufficient quantities of oil or gas to make
commercially reasonable their continued operations, and
provided that the expenses enumerated in this subsection
(iv) shall have been incurred not more than 36 months
before the sale or transfer to the Partnership.
"Cost," when used with respect to services, means the
reasonable, necessary and actual expense incurred by the seller
on behalf of the Partnership in providing the services,
determined in accordance with generally accepted accounting
principles.
As used elsewhere, "Cost" means the price paid by the seller in
an arm's-length transaction.
13. "Dealer-Manager" means:
(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.
14. "Development Well" means a well drilled within the proved area
of a natural gas or oil reservoir to the depth of a
stratigraphic Horizon known to be productive.
15. "Direct Costs" means all actual and necessary costs directly
incurred for the benefit of the Partnership and generally
attributable to the goods and services provided to the
Partnership by parties other than the Sponsor or its
Affiliates. Direct Costs:
(i) may not include any cost otherwise classified as
Organization and Offering Costs, Administrative Costs,
Intangible Drilling Costs, Tangible Costs, Operating
Costs or costs related to the Leases; but
3
(ii) may include the cost of services provided by the Sponsor
or its Affiliates if the services are provided pursuant
to written contracts and in compliance with
ss.4.03(d)(7) or pursuant to the Managing General
Partner's role as Tax Matters Partner.
16. "Distribution Interest" means an undivided interest in the
Partnership's assets after payments to the Partnership's
creditors or the creation of a reasonable reserve therefor, in
the ratio the positive balance of a party's Capital Account
bears to the aggregate positive balance of the Capital Accounts
of all of the parties determined after taking into account all
Capital Account adjustments for the taxable year during which
liquidation occurs (other than those made pursuant to
liquidating distributions or restoration of deficit Capital
Account balances). Provided, however, after the Capital
Accounts of all of the parties have been reduced to zero, the
interest in the remaining Partnership assets shall equal a
party's interest in the related Partnership revenues as set
forth in ss.5.01 and its subsections of this Agreement.
17. "Drilling and Operating Agreement" means the proposed Drilling
and Operating Agreement between the Managing General Partner or
an Affiliate as Operator, and the Partnership as Developer, a
copy of the proposed form of which is attached to this
Agreement as Exhibit (II).
18. "Exploratory Well" means a well drilled to:
(i) find commercially productive hydrocarbons in an unproved
area;
(ii) find a new commercially productive Horizon in a field
previously found to be productive of hydrocarbons at
another Horizon; or
(iii) significantly extend a known prospect.
19. "Farmout" means an agreement by the owner of the leasehold or
Working Interest to assign his interest in certain acreage or
well to the assignees, retaining some interest such as an
Overriding Royalty Interest, an oil and gas payment, offset
acreage or other type of interest, subject to the drilling of
one or more specific wells or other performance as a condition
of the assignment.
20. "Final Terminating Event" means any one of the following:
(i) the expiration of the Partnership's fixed term;
(ii) notice to the Participants by the Managing General
Partner of its election to terminate the Partnership's
affairs;
(iii) notice by the Participants to the Managing General
Partner of their similar election through the
affirmative vote of Participants whose Units equal a
majority of the total Units; or
(iv) the termination of the Partnership under ss.708(b)(1)(A)
of the Code or the Partnership ceases to be a going
concern.
21. "Horizon" means a zone of a particular formation; that part of
a formation of sufficient porosity and permeability to form a
petroleum reservoir.
22. "Independent Expert" means a person with no material relationship
to the Sponsor or its Affiliates who is qualified and in the
business of rendering opinions regarding the value of natural gas
and oil properties based on the evaluation of all pertinent
economic, financial, geologic and engineering information
available to the Sponsor or its Affiliates.
23. "Initial Closing Date" means the date after the minimum amount
of subscription proceeds has been received when subscription
proceeds are first withdrawn from the escrow account.
4
24. "Intangible Drilling Costs" or "Non-Capital Expenditures" means
those expenditures associated with property acquisition and the
drilling and completion of natural gas and oil wells that under
present law are generally accepted as fully deductible
currently for federal income tax purposes. This includes all
expenditures made for any well before production in commercial
quantities for wages, fuel, repairs, hauling, supplies and
other costs and expenses incident to and necessary for drilling
the well and preparing the well for production of natural gas
or oil, that are currently deductible pursuant to Section
263(c) of the Code and Treasury Reg. Section 1.612-4, and are
generally termed "intangible drilling and development costs,"
including the expense of plugging and abandoning any well
before a completion attempt.
25. "Interim Closing Date" means those date(s) after the Initial
Closing Date, but before the Offering Termination Date, that
the Managing General Partner, in its sole discretion, applies
additional subscription proceeds to additional Partnership
activities, including drilling activities.
26. "Investor General Partners" means:
(i) the persons signing the Subscription Agreement as
Investor General Partners; and
(ii) the Managing General Partner to the extent of any
optional subscription under ss.3.03(b)(2).
All Investor General Partners shall be of the same class and
have the same rights.
27. "Landowner's Royalty Interest" means an interest in production,
or its proceeds, to be received free and clear of all costs of
development, operation, or maintenance, reserved by a landowner
on the creation of a Lease.
28. "Leases" means full or partial interests in natural gas and oil
leases, oil and natural gas mineral rights, fee rights,
licenses, concessions, or other rights under which the holder
is entitled to explore for and produce oil and/or natural gas,
and includes any contractual rights to acquire any such
interest.
29. "Limited Partners" means:
(i) the persons signing the Subscription Agreement as
Limited Partners;
(ii) the Managing General Partner to the extent of any
optional subscription under ss.3.03(b)(2);
(iii) the Investor General Partners on the conversion of their
Investor General Partner Units to Limited Partner Units
pursuant to ss.6.01(b); and
(iv) any other persons who are admitted to the Partnership as
additional or substituted Limited Partners.
Except as provided in ss.3.05(b), with respect to the required
additional Capital Contributions of Investor General Partners,
all Limited Partners shall be of the same class and have the
same rights.
30. "Managing General Partner" means:
(i) Atlas Resources, Inc.; or
(ii) any Person admitted to the Partnership as a general
partner other than as an Investor General Partner who is
designated to exclusively supervise and manage the
operations of the Partnership.
31. "Managing General Partner Signature Page" means an execution
and subscription instrument in the form attached as Exhibit (I-
A) to this Agreement, which is incorporated in this Agreement
by reference.
5
32. "Offering Termination Date" means the date after the minimum
amount of subscription proceeds has been received on which the
Managing General Partner determines, in its sole discretion,
the Partnership's subscription period is closed and the
acceptance of subscriptions ceases, which shall not be later
than December 31, 2003 with respect to the Partnership. [and
December 31, 2004 with respect to Partnerships designated
"Atlas America Public #12-2004(_) Limited Partnership."]
33. "Operating Costs" means expenditures made and costs incurred in
producing and marketing natural gas or oil from completed
wells. These costs include, but are not limited to:
(i) labor, fuel, repairs, hauling, materials, supplies,
utility charges and other costs incident to or related
to producing and marketing natural gas and oil;
(ii) ad valorem and severance taxes;
(iii) insurance and casualty loss expense; and
(iv) compensation to well operators or others for services
rendered in conducting these operations.
Operating Costs also include reworking, workover, subsequent
equipping, and similar expenses relating to any well.
34. "Operator" means the Managing General Partner, as operator of
Partnership Wells in Pennsylvania, and the Managing General
Partner or an Affiliate as Operator of Partnership Wells in
other areas of the United States.
35. "Organization and Offering Costs" means all costs of organizing
and selling the offering including, but not limited to:
(i) total underwriting and brokerage discounts and
commissions (including fees of the underwriters'
attorneys);
(ii) expenses for printing, engraving, mailing, salaries of
employees while engaged in sales activities, charges of
transfer agents, registrars, trustees, escrow holders,
depositaries, engineers and other experts;
(iii) expenses of qualification of the sale of the securities
under federal and state law, including taxes and fees,
accountants' and attorneys' fees; and
(iv) other front-end fees.
Organization and Offering Costs also includes the 2.5% Dealer-
Manager fee, a 7% Sales Commission, a .5% accountable marketing
expense fee, and a .5% reimbursement of the Selling Agents'
bona fide accountable due diligence expenses payable to the
Dealer-Manager.
36. "Organization Costs" means all costs of organizing the offering
including, but not limited to:
(i) expenses for printing, engraving, mailing, salaries of
employees while engaged in sales activities, charges of
transfer agents, registrars, trustees, escrow holders,
depositaries, engineers and other experts;
(ii) expenses of qualification of the sale of the securities
under federal and state law, including taxes and fees,
accountants' and attorneys' fees; and
(iii) other front-end fees.
6
37. "Overriding Royalty Interest" means an interest in the natural gas and
oil produced under a Lease, or the proceeds from the sale thereof,
carved out of the Working Interest, to be received free and clear of
all costs of development, operation, or maintenance.
38. "Participants" means:
(i) the Managing General Partner to the extent of its optional
subscription under ss.3.03(b)(2);
(ii) the Limited Partners; and
(iii) the Investor General Partners.
39. "Partners" means:
(i) the Managing General Partner;
(ii) the Investor General Partners; and
(iii) the Limited Partners.
40. "Partnership" means Atlas America Public #12-2003 Limited Partnership.
41. "Partnership Net Production Revenues" means gross revenues after
deduction of the related Operating Costs, Direct Costs, Administrative
Costs and all other Partnership costs not specifically allocated.
42. "Partnership Well" means a well, some portion of the revenues from
which is received by the Partnership.
43. "Person" means a natural person, partnership, corporation, association,
trust or other legal entity.
44. "Production Purchase" or "Income" Program means any program whose
investment objective is to directly acquire, hold, operate, and/or
dispose of producing oil and gas properties. Such a program may acquire
any type of ownership interest in a producing property, including, but
not limited to, working interests, royalties, or production payments. A
program which spends at least 90% of capital contributions and funds
borrowed (excluding offering and organizational expenses) in the above
described activities is presumed to be a production purchase or income
program.
45. "Program" means one or more limited or general partnerships or other
investment vehicles formed, or to be formed, for the primary purpose
of:
(i) exploring for natural gas, oil and other hydrocarbon
substances; or
(ii) investing in or holding any property interests which permit the
exploration for or production of hydrocarbons or the receipt of
such production or its proceeds.
46. "Prospect" means an area covering lands which are believed by the
Managing General Partner to contain subsurface structural or
stratigraphic conditions making it susceptible to the accumulations of
hydrocarbons in commercially productive quantities at one or more
Horizons. The area, which may be different for different Horizons,
shall be:
(i) designated by the Managing General Partner in writing before
the conduct of Partnership operations; and
7
(ii) enlarged or contracted from time to time on the basis of
subsequently acquired information to define the anticipated
limits of the associated hydrocarbon reserves and to include
all acreage encompassed therein.
If the well to be drilled by the Partnership is to a Horizon containing
Proved Reserves, then a "Prospect" for a particular Horizon may be
limited to the minimum area permitted by state law or local practice,
whichever is applicable, to protect against drainage from adjacent
wells. Subject to the foregoing sentence, "Prospect" shall be deemed
the drilling or spacing unit for the Clinton/Medina geological
formation and the Mississippian and/or Upper Devonian Sandstone
reservoirs in Ohio, Pennsylvania, and New York.
47. "Proved Developed Oil and Gas Reserves" means reserves that can be
expected to be recovered through existing wells with existing equipment
and operating methods. Additional oil and gas expected to be obtained
through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of
primary recovery should be included as "proved developed reserves" only
after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased
recovery will be achieved.
48. "Proved Reserves" means the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions,
i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future
conditions.
(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes:
(a) that portion delineated by drilling and defined by gas-
oil and/or oil-water contacts, if any; and
(b) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically
productive on the basis of available geological and
engineering data.
In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower
proved limit of the reservoir.
(ii) Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the "proved" classification when successful testing
by a pilot project, or the operation of an installed program in
the reservoir, provides support for the engineering analysis on
which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
(a) oil that may become available from known reservoirs but
is classified separately as "indicated additional
reserves";
(b) crude oil, natural gas, and natural gas liquids, the
recovery of which is subject to reasonable doubt because
of uncertainty as to geology, reservoir characteristics,
or economic factors;
(c) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and
(d) crude oil, natural gas, and natural gas liquids, that
may be recovered from oil shales, coal, gilsonite and
other such sources.
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49. "Proved Undeveloped Reserves" means reserves that are expected to be
recovered from either:
(i) new wells on undrilled acreage; or
(ii) from existing wells where a relatively major expenditure is
required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling units
offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units can be claimed
only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Under
no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection
or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and
in the same reservoir.
50. "Roll-Up" means a transaction involving the acquisition, merger,
conversion or consolidation, either directly or indirectly, of the
Partnership and the issuance of securities of a Roll-Up Entity. The
term does not include:
(i) a transaction involving securities of the Partnership that have
been listed for at least 12 months on a national exchange or
traded through the National Association of Securities Dealers
Automated Quotation National Market System; or
(ii) a transaction involving the conversion to corporate, trust or
association form of only the Partnership if, as a consequence
of the transaction, there will be no significant adverse change
in any of the following:
(a) voting rights;
(b) the Partnership's term of existence;
(c) the Managing General Partner's compensation; and
(d) the Partnership's investment objectives.
51. "Roll-Up Entity" means a partnership, trust, corporation or other
entity that would be created or survive after the successful completion
of a proposed roll-up transaction.
52. "Sales Commissions" means all underwriting and brokerage discounts and
commissions incurred in the sale of Units payable to registered broker/
dealers, but excluding the Dealer-Manager fee, a .5% accountable
marketing expense fee, and a .5% reimbursement for bona fide
accountable due diligence expenses.
53. "Selling Agents" means those broker/dealers selected by the Dealer-
Manager which will participate in the offer and sale of the Units.
54. "Sponsor" means any person directly or indirectly instrumental in
organizing, wholly or in part, a program or any person who will manage
or is entitled to manage or participate in the management or control of
a program. The definition includes:
(i) the managing and controlling general partner(s) and any other
person who actually controls or selects the person who controls
25% or more of the exploratory, development or producing
activities of the program, or any segment thereof, even if that
person has not entered into a contract at the time of formation
of the program; and
9
(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.
55. "Subscription Agreement" means an execution and subscription instrument
in the form attached as Exhibit (I-B) to this Agreement, which is
incorporated in this Agreement by reference.
56. "Tangible Costs" or "Capital Expenditures" means those costs associated
with drilling and completing natural gas and oil wells which are
generally accepted as capital expenditures under the Code. This
includes all of the following:
(i) costs of equipment, parts and items of hardware used in
drilling and completing a well; and
(ii) those items necessary to deliver acceptable natural gas and oil
production to purchasers to the extent installed downstream
from the wellhead of any well and which are required to be
capitalized under the Code and its regulations.
57. "Tax Matters Partner" means the Managing General Partner.
58. "Units" or "Units of Participation" means up to 500 Limited Partner
interests and up to 9,500 Investor General Partner interests purchased
by Participants in the Partnership under the provisions of ss.3.03 and
its subsections, including any rights to profits, losses, income, gain,
credits, deductions, cash distributions or returns of capital or other
attributes of the Units.
59. "Working Interest" means an interest in a Lease which is subject to
some portion of the cost of development, operation, or maintenance of
the Lease.
ARTICLE III
SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
3.01. Designation of Managing General Partner and Participants. Atlas shall
serve as Managing General Partner of the Partnership. Atlas shall further serve
as a Participant to the extent of any subscription made by it pursuant to
ss.3.03(b)(2).
Limited Partners and Investor General Partners, including Affiliates of the
Managing General Partner, shall serve as Participants.
3.02. Participants.
3.02(a). Limited Partner at Formation. Atlas America, Inc., as Original
Limited Partner, has acquired one Unit and has made a Capital Contribution of
$100.
On the admission of one or more Limited Partners, the Partnership shall return
to the Original Limited Partner its Capital Contribution and shall reacquire
its Unit. The Original Limited Partner shall then cease to be a Limited
Partner in the Partnership with respect to the Unit.
3.02(b). Offering of Interests. The Partnership is authorized to admit to the
Partnership at the Initial Closing Date, any Interim Closing Date(s), and the
Offering Termination Date additional Participants whose Subscription
Agreements are accepted by the Managing General Partner if, after the
admission of the additional Participants, the total Units do not exceed the
maximum number of Units set forth in ss.3.03(c)(1).
10
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 amount of subscription proceeds set forth in ss.3.03(c)(2).
Thereafter, subscriptions may be paid directly to the Partnership account.
3.03. Subscriptions to the Partnership.
3.03(a). Subscriptions by Participants.
3.03(a)(1). Subscription Price and Minimum Subscription. The subscription
price of a Unit in the Partnership shall be $10,000, except as set forth
below, and shall be designated on each Participant's Subscription Agreement
and payable as set forth in Section 3.05(b)(1). The minimum subscription per
Participant shall be one Unit ($10,000); however, the Managing General
Partner, in its discretion, may accept one-half Unit ($5,000) subscriptions.
Larger subscriptions shall be accepted in $1,000 increments, beginning with
$6,000, $7,000, etc.
Notwithstanding the foregoing, the subscription price for:
(i) the Managing General Partner, its officers, directors, and
Affiliates, and Participants who buy Units through the officers
and directors of the Managing General Partner, shall be reduced
by an amount equal to the 2.5% Dealer-Manager fee, the 7% Sales
Commission, the .5% accountable marketing expense fee, and the
.5% reimbursement of the Selling Agents' bona fide accountable
due diligence expenses, which shall not be paid with respect to
these sales; and
(ii) the subscription price for Registered Investment Advisors and
their clients, and Selling Agents and their registered
representatives and principals, shall be reduced by an amount
equal to the 7% Sales Commission, which shall not be paid with
respect to these sales.
No more than 5% of the total Units shall be sold with the discounts described
above.
3.03(a)(2). Effect of Subscription. Execution of a Subscription Agreement
shall serve as an agreement by the Participant to be bound by each and every
term of this Agreement.
3.03(b). Subscriptions by Managing General Partner.
3.03(b)(1). Managing General Partner's Required Subscription. The Managing
General Partner, as a general partner and not as a Participant, shall:
(i) contribute to the Partnership the Leases which will be drilled
by the Partnership on the terms set forth in ss.4.01(a)(4); and
(ii) pay the costs charged to it under this Agreement.
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 the end of the calendar year.
3.03(b)(2). Managing General Partner's Optional Additional Subscription. In
addition to the Managing General Partner's required subscription under
ss.3.03(b)(1), the Managing General Partner may subscribe to up to 10% of the
Units under the provisions of ss.3.03(a) and its subsections, and, subject to
the limitations on voting rights set forth in ss.4.03(c)(3), to that extent
shall be deemed a Participant in the Partnership for all purposes under this
Agreement.
3.03(b)(3). Effect of and Evidencing Subscription. The Managing General
Partner has executed a Managing General Partner Signature Page which:
11
(i) evidences the Managing General Partner's required subscription
under ss.3.03(b)(1); and
(ii) may be amended to reflect the amount of any optional
subscription under ss.3.03(b)(2).
Execution of the Managing General Partner Signature Page serves as an
agreement by the Managing General Partner to be bound by each and every term
of this Agreement.
3.03(c). Maximum and Minimum Number of Units.
3.03(c)(1). Maximum Number of Units. The maximum number of Units may not
exceed 7,500 Units, which is up to $75,000,000 of cash subscription proceeds
excluding the subscription discounts permitted under ss.3.03(a)(1).
Notwithstanding the foregoing, the maximum number of Units in all partnerships
in Atlas America Public #12-2003 Program, in the aggregate, shall not exceed
7,500 Units which is up to $75,000,000 of cash subscription proceeds excluding
the subscription discounts permitted under ss.3.03(a)(1).
3.03(c)(2). Minimum Number of Units. The minimum number of Units shall equal
at least 100 Units, but in any event not less than that number of Units which
provides the Partnership with cash subscription proceeds of $1,000,000,
excluding the subscription discounts permitted under ss.3.03(a)(1).
If at the Offering Termination Date the minimum number of Units has not been
received and accepted, then all monies deposited by subscribers shall be
promptly returned to them. They shall receive interest earned on their
subscription proceeds from the date the monies were deposited in escrow
through the date of refund.
The partnership may break escrow and begin its drilling activities in the
Managing General Partner's sole discretion on receipt of the minimum
subscriptions.
3.03(d). Acceptance of Subscriptions.
3.03(d)(1). Discretion by the Managing General Partner. Acceptance of
subscriptions is discretionary with the Managing General Partner. The Managing
General Partner may reject any subscription for any reason it deems
appropriate.
3.03(d)(2). Time Period in Which to Accept Subscriptions. Subscriptions shall
be accepted or rejected by the Partnership within 30 days of their receipt. If
a subscription is rejected, then all funds shall be returned to the subscriber
promptly.
3.03(d)(3) Admission to the Partnership. The Participants shall be admitted to
the Partnership as follows:
(i) not later than 15 days after the release from escrow of
Participants' funds to the Partnership; and
(ii) after the close of the escrow account not later than the last
day of the calendar month in which their Subscription
Agreements were accepted by the Partnership.
3.04. Capital Contributions of the Managing General Partner.
3.04(a). Minimum Amount of Managing General Partner's Required Contribution.
The Managing General Partner is required to:
(i) make aggregate Capital Contributions to the Partnership,
including Leases contributed under ss.3.03(b)(1)(i), of not
less than 25% of all Capital Contributions to the Partnership;
and
(ii) maintain a minimum Capital Account balance equal to not less
than 1% of total positive Capital Account balances for the
Partnership.
3.04(b). On Liquidation the Managing General Partner Must Contribute Deficit
Balance in Its Capital Account. The Managing General Partner shall contribute
to the Partnership any deficit balance in its Capital Account on the
occurrence of either of the following events:
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(i) the liquidation of the Partnership; or
(ii) the liquidation of the Managing General Partner's interest in
the Partnership.
This shall be determined after taking into account all adjustments for the
Partnership's taxable year during which the liquidation occurs, other than
adjustments made pursuant to this requirement, by the end of the taxable year
in which its interest in the Partnership is liquidated or, if later, within 90
days after the date of the liquidation.
3.04(c). Interest for Contributions. The interest of the Managing General
Partner in the capital and revenues of the Partnership is in consideration
for, and is the only consideration for, its Capital Contribution to the
Partnership.
3.05. Payment of Subscriptions.
3.05(a). Managing General Partner's Subscriptions. The Managing General
Partner shall pay any optional subscription under ss.3.03(b)(2) in the same
manner as the Participants.
3.05(b). Participant Subscriptions and Additional Capital Contributions of the
Investor General Partners.
3.05(b)(1). Payment of Subscription Agreements. A Participant shall pay the
amount designated as the subscription price on the Subscription Agreement
executed by the Participant 100% in cash at the time of subscribing. A
Participant shall receive interest on the amount he pays from the time his
subscription proceeds are deposited in the escrow account, or the Partnership
account after the minimum number of Units have been received as provided in
ss.3.06(b), up until the Offering Termination Date.
3.05(b)(2). Additional Required Capital Contributions of the Investor General
Partners. Investor General Partners must make Capital Contributions to the
Partnership when called by the Managing General Partner, in addition to their
subscriptions, for their pro rata share of any Partnership obligations and
liabilities which are recourse to the Investor General Partners and are
represented by their ownership of Units before the conversion of Investor
General Units to Limited Partner Units under ss.6.01(b).
3.05(b)(3). Default Provisions. The failure of an Investor General Partner to
timely make a required additional Capital Contribution under this section
results in his personal liability to the other Investor General Partners for
the amount in default. The remaining Investor General Partners, 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 has a fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Managing General Partner's possession or
control. The Managing General Partner shall not employ, or permit another to
employ, the funds and assets in any manner except for the exclusive benefit of
the Partnership. Neither this Agreement nor any other agreement between the
Managing General Partner and the Partnership shall contractually limit any
fiduciary duty owed to the Participants by the Managing General Partner under
applicable law, except as provided in ss.ss.4.01, 4.02, 4.04, 4.05 and 4.06 of
this Agreement.
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3.06(b). Special Account After the Receipt of the Minimum Partnership
Subscriptions. Following the receipt of the minimum number of Units and
breaking escrow, the funds of the Partnership shall be held in a separate
interest-bearing account maintained for the Partnership and shall not be
commingled with funds of any other entity.
3.06(c). Investment.
3.06(c)(1). Investments in Other Entities. Partnership funds 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 ss.3.06(c)(2);
(iii) multi-tier arrangements meeting the requirements of
ss.4.03(d)(15);
(iv) investments involving less than 5% of the Partnership's
subscription proceeds which are a necessary and incidental part
of a property acquisition transaction; and
(v) investments in entities established solely to limit the
Partnership's liabilities associated with the ownership or
operation of property or equipment, provided that duplicative
fees and expenses shall be prohibited.
3.06(c)(2). Permissible Investments Before Investment in Partnership
Activities. After the Initial Closing Date and until proceeds from the
offering are invested in the Partnership's operations, the proceeds may be
temporarily invested in income producing short-term, highly liquid
investments, in which there is appropriate safety of principal, such as U.S.
Treasury Bills.
ARTICLE IV
CONDUCT OF OPERATIONS
4.01. Acquisition of Leases.
4.01(a). Assignment to Partnership.
4.01(a)(1). In General. The Managing General Partner shall select, acquire and
assign or cause to have assigned to the Partnership full or partial interests
in Leases, by any method customary in the natural gas and oil industry,
subject to the terms and conditions set forth below.
The Partnership and other partnerships in Atlas America Public #12-2003
Program may acquire and develop interests in Leases covering one or more of
the same Prospects, in the Managing General Partner's discretion.
The Partnership shall acquire only Leases reasonably expected to meet the
stated purposes of the Partnership. No Leases shall be acquired for the
purpose of a subsequent sale, Farmout, or other disposition unless the
acquisition is made after a well has been drilled to a depth sufficient to
indicate that the acquisition would be in the Partnership's best interest.
4.01(a)(2). Federal and State Leases. The Partnership is authorized to acquire
Leases on federal and state lands.
4.01(a)(3). Managing General Partner's Discretion as to Terms and Burdens of
Acquisition. Subject to the provisions of ss.4.03(d) and its subsections, the
acquisitions of Leases or other property may be made under any terms and
obligations, including:
(i) any limitations as to the Horizons to be assigned to the
Partnership; and
(ii) subject to any burdens as the Managing General Partner deems
necessary in its sole discretion.
4.01(a)(4). Cost of Leases. All Leases shall be:
14
(i) contributed to the Partnership by the Managing General Partner
or its Affiliates; and
(ii) credited towards the Managing General Partner's required
Capital Contribution set forth in ss.3.03(b)(1) at the Cost of
the Lease, unless the Managing General Partner has cause to
believe that Cost is materially more than the fair market value
of the property, in which case the credit for the contribution
must be made at a price not in excess of the fair market value.
A determination of fair market value must be:
(i) supported by an appraisal from an Independent Expert; and
(ii) maintained in the Partnership's records for six years along
with associated supporting information.
4.01(a)(5). The Managing General Partner, Operator or Their Affiliates' Rights
in the Remainder Interests. Subject to the provisions of ss.4.03(d) and its
subsections, to the extent the Partnership does not acquire a full interest in
a Lease from the Managing General Partner or its Affiliates, the remainder of
the interest in the Lease may be held by the Managing General Partner or its
Affiliates. They may either:
(i) retain and exploit the remaining interest for their own
account; or
(ii) sell or otherwise dispose of all or a part of the remaining
interest.
Profits from the exploitation and/or disposition of their retained interests
in the Leases shall be for the benefit of the Managing General Partner or its
Affiliates to the exclusion of the Partnership.
4.01(a)(6). No Breach of Duty. Subject to the provisions of ss.4.03 and its
subsections, acquisition of Leases from the Managing General Partner, the
Operator or their Affiliates shall not be considered a breach of any
obligation owed by them to the Partnership or the Participants.
4.01(b). No Overriding Royalty Interests. Neither the Managing General
Partner, the Operator nor any Affiliate shall retain any Overriding Royalty
Interest on the Leases acquired by the Partnership.
4.01(c). Title and Nominee Arrangements.
4.01(c)(1). Legal Title. Legal title to all Leases acquired by the Partnership
shall be held on a permanent basis in the name of the Partnership. However,
Partnership properties may be held temporarily in the name of:
(i) the Managing General Partner;
(ii) the Operator;
(iii) their Affiliates; or
(iv) in the name of any nominee designated by the Managing General
Partner to facilitate the acquisition of the properties.
4.01(c)(2). Managing General Partner's Discretion. The Managing General
Partner shall take the steps which are necessary in its best judgment to
render title to the Leases to be acquired by the Partnership acceptable for
the purposes of the Partnership. The Managing General Partner shall be free,
however, to use its own best judgment in waiving title requirements.
The Managing General Partner shall not be liable to the Partnership or to the
other parties for any mistakes of judgment; nor shall the Managing General
Partner be deemed to be making any warranties or representations, express or
implied, as to the validity or merchantability of the title to the Leases
assigned to the Partnership or the extent of the interest covered thereby
except as otherwise provided in the Drilling and Operating Agreement.
15
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 14.03 and its
subsections, and to any authority which may be granted the Operator under
ss.4.02(c)(3)(b), the Managing General Partner shall have full authority to do
all things deemed necessary or desirable by it in the conduct of the business
of the Partnership. Without limiting the generality of the foregoing, the
Managing General Partner is expressly authorized to engage in:
(i) the making of all determinations of which Leases, wells and
operations will be participated in by the Partnership, which
includes:
(a) which Leases are developed;
(b) which Leases are abandoned; or
(c) which leases are sold or assigned to other parties,
including other investor ventures organized by the
Managing General Partner, the Operator, or any of their
Affiliates;
(ii) the negotiation and execution on any terms deemed desirable in
its sole discretion of any contracts, conveyances, or other
instruments, considered useful to the conduct of the operations
or the implementation of the powers granted it under this
Agreement, including, without limitation:
(a) the making of agreements for the conduct of operations,
including agreements and financial instruments relating
to hedging the Partnership's natural gas and oil;
(b) the exercise of any options, elections, or decisions
under any such agreements; and
(c) the furnishing of equipment, facilities, supplies and
material, services, and personnel;
(iii) the exercise, on behalf of the Partnership or the parties, as
the Managing General Partner in its sole judgment deems best,
of all rights, elections and options granted or imposed by any
agreement, statute, rule, regulation, or order;
(iv) the making of all decisions concerning the desirability of
payment, and the payment or supervision of the payment, of all
delay rentals and shut-in and minimum or advance royalty
payments;
(v) the selection of full or part-time employees and outside
consultants and contractors and the determination of their
compensation and other terms of employment or hiring;
(vi) the maintenance of insurance for the benefit of the Partnership
and the parties as it deems necessary, but in no event less in
amount or type than the following:
(a) worker's compensation insurance in full compliance with
the laws of the Commonwealth of Pennsylvania and any
other applicable state laws;
16
(b) liability insurance, including automobile, which has a
$1,000,000 combined single limit for bodily injury and
property damage in any one accident or occurrence and in
the aggregate; and
(c) liability and excess liability insurance as to bodily
injury and property damage with combined limits of
$50,000,000 during drilling operations and thereafter,
per occurrence or accident and in the aggregate, which
includes $1,000,000 of seepage, pollution and
contamination insurance which protects and defends the
insured against property damage or bodily injury claims
from third-parties, other than a co-owner of the Working
Interest, alleging seepage, pollution or contamination
damage resulting from a pollution incident. The excess
liability insurance shall be in place and effective no
later than the date drilling operations begin, and the
Partnership shall have the benefit of the Managing
General Partner's $50,000,000 liability insurance on the
same basis as the Managing General Partner and its
Affiliates, including the Managing General Partner's
other Programs;
(vii) the use of the funds and revenues of the Partnership, and the
borrowing on behalf of, and the loan of money to, the
Partnership, on any terms it sees fit, for any purpose,
including without limitation:
(a) the conduct or financing, in whole or in part, of the
drilling and other activities of the Partnership;
(b) the conduct of additional operations; and
(c) the repayment of any borrowings or loans used initially
to finance these operations or activities;
(viii) the disposition, hypothecation, sale, exchange, release,
surrender, reassignment or abandonment of any or all assets of
the Partnership, including without limitation, the Leases,
wells, equipment and production therefrom, provided that the
sale of all or substantially all of the assets of the
Partnership shall only be made as provided in ss.4.03(d)(6);
(ix) the formation of any further limited or general partnership,
tax partnership, joint venture, or other relationship which it
deems desirable with any parties who it, in its sole and
absolute discretion, selects, including any of its Affiliates;
(x) the control of any matters affecting the rights and obligations
of the Partnership, including:
(a) the employment of attorneys to advise and otherwise
represent the Partnership;
(b) the conduct of litigation and other incurring of legal
expense; and
(c) the settlement of claims and litigation;
(xi) the operation of producing wells drilled on the Leases or on a
Prospect which includes any part of the Leases;
(xii) the exercise of the rights granted to it under the power of
attorney created under this Agreement; and
(xiii) the incurring of all costs and the making of all expenditures
in any way related to any of the foregoing.
4.02(c)(2). Scope of Powers. The Managing General Partner's powers shall
extend to any operation participated in by the Partnership or affecting its
Leases, or other property or assets, irrespective of whether or not the
Managing General Partner is designated operator of the operation by any
outside persons participating therein.
4.02(c)(3). Delegation of Authority.
4.02(c)(3)(a). In General. The Managing General Partner may subcontract and
delegate all or any part of its duties under this Agreement to any entity
chosen by it, including an entity related to it. The party shall have the same
powers in the conduct of the duties as would the Managing General Partner. The
delegation, however, shall not relieve the Managing General Partner of its
responsibilities under this Agreement.
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4.02(c)(3)(b). Delegation to Operator. The Managing General Partner is
specifically authorized to delegate any or all of its duties to the Operator
by executing the Drilling and Operating Agreement. This delegation shall not
relieve the Managing General Partner of its responsibilities under this
Agreement.
In no event shall any consideration received for operator services be in
excess of competitive rates or duplicative of any consideration or
reimbursements received under this Agreement. The Managing General Partner may
not benefit by interpositioning itself between the Partnership and the actual
provider of operator services.
4.02(c)(4). Related Party Transactions. Subject to the provisions of ss.4.03
and its subsections, any transaction which the Managing General Partner is
authorized to enter into on behalf of the Partnership under the authority
granted in this section and its subsections, may be entered into by the
Managing General Partner with itself or with any other general partner, the
Operator, or any of their Affiliates.
4.02(d). Additional Powers. In addition to the powers granted the Managing
General Partner under ss.4.02(c) and its subsections or elsewhere in this
Agreement, the Managing General Partner, when specified, shall have the
following additional express powers.
4.02(d)(1). Drilling Contracts. All Partnership Wells shall be drilled under
the Drilling and Operating Agreement on a Cost plus 15% basis. The Managing
General Partner or its Affiliates, as drilling contractor, may not do the
following:
(i) receive a rate that is not competitive with the rates charged
by unaffiliated contractors in the same geographic region;
(ii) enter into a turnkey drilling contract with the Partnership;
(iii) profit by drilling in contravention of its fiduciary
obligations to the Partnership; or
(iv) benefit by interpositioning itself between the Partnership and
the actual provider of drilling contractor services.
4.02(d)(2). Power of Attorney.
4.02(d)(2)(a). In General. Each Participant appoints the Managing General
Partner his true and lawful attorney-in-fact for him and in his name, place,
and stead and for his use and benefit, from time to time:
(i) to create, prepare, complete, execute, file, swear to, deliver,
endorse, and record any and all documents, certificates 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 Participant authorizes the attorney-in-
fact to take any further action which the attorney-in-fact considers necessary
or advisable in connection with any of the foregoing. Each party acknowledges
that the power of attorney granted under this section:
(i) is a special power of attorney coupled with an interest and
irrevocable; and
(ii) shall survive the assignment by the Participant of the whole or
a portion of his Units; except when the assignment is of all of
the Participant's Units and the purchaser, transferee, or
assignee of the Units is
18
admitted as a successor Participant, the power of attorney shall
survive the delivery of the assignment for the sole purpose of
enabling the attorney-in- fact to execute, acknowledge, and file
any agreement, certificate, instrument or document necessary to
effect the substitution.
4.02(d)(2)(c). Power of Attorney to Operator. The Managing General Partner is
hereby authorized to grant a Power of Attorney to the Operator on behalf of
the Partnership.
4.02(e). Borrowings and Use of Partnership Revenues.
4.02(e)(1). Power to Borrow or Use Partnership Revenues.
4.02(e)(1)(a). In General. If additional funds over the Participants' Capital
Contributions are needed for Partnership operations, then the Managing General
Partner may:
(i) use Partnership revenues for such purposes; or
(ii) the Managing General Partner and its Affiliates may advance to
the Partnership the funds necessary under ss.4.03(d)(8)(b),
although they are not obligated to advance the funds to the
Partnership.
4.02(e)(1)(b). Limitation on Borrowing. The borrowings, other than credit
transactions on open account customary in the industry to obtain goods and
services, shall be subject to the following limitations:
(i) the borrowings must be without recourse to the Investor General
Partners and the Limited Partners except as otherwise provided
in this Agreement; and
(ii) the amount that may be borrowed at any one time may not exceed
an amount equal to 5% of the Partnership's subscription
proceeds.
4.02(f). Tax Matters Partner.
4.02(f)(1). Designation of Tax Matters Partner. The Managing General Partner is
hereby designated the Tax Matters Partner of the Partnership under ss.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 IRS, and thereafter shall furnish all Participants periodic
reports at least quarterly on the status of the proceedings.
4.02(f)(4). Participant Restrictions. Each Participant agrees as follows:
(i) he will not file the statement described in Section
6224(c)(3)(B) of the Code prohibiting the Managing General
Partner as the Tax Matters Partner for the Partnership from
entering into a settlement on his behalf with respect to
partnership items, as that term is defined in Section
6231(a)(3) of Code, of the Partnership;
(ii) he will not form or become and exercise any rights as a member
of a group of Partners having a 5% or greater interest in the
profits of the Partnership under Section 6223(b)(2) of the
Code; and
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(iii) the Managing General Partner is authorized to file a copy of
this Agreement, or pertinent portions of this Agreement, with
the IRS under Section 6224(b) of the Code if necessary to
perfect the waiver of rights under this subsection.
4.03. General Rights and Obligations of the Participants and Restricted and
Prohibited Transactions.
4.03(a)(1). Limited Liability of Limited Partners. Limited Partners shall not
be bound by the obligations of the Partnership other than as provided under
the Delaware Revised Uniform Limited Partnership Act. Limited Partners shall
not be personally liable for any debts of the Partnership or any of the
obligations or losses of the Partnership beyond the amount of the subscription
price designated on the Subscription Agreement executed by each respective
Limited Partner unless:
(i) they also subscribe to the Partnership as Investor General
Partners; or
(ii) in the case of the Managing General Partner, it purchases
Limited Partner Units.
4.03(a)(2). No Management Authority of Participants. Participants, other than
the Managing General Partner if it buys Units, shall have no power over the
conduct of the affairs of the Partnership. No Participant, other than the
Managing General Partner if it buys Units, shall take part in the management
of the business of the Partnership, or have the power to sign for or to bind
the Partnership.
4.03(b). Reports and Disclosures.
4.03(b)(1). Annual Reports and Financial Statements. Beginning with the
calendar year in which the Partnership had its Offering Termination Date, the
Partnership shall provide each Participant an annual report within 120 days
after the close of that calendar year, and beginning with the following
calendar year, a report within 75 days after the end of the first six months
of its calendar year, containing except as otherwise indicated, at least the
information set forth below:
(i) Audited financial statements of the Partnership, including a
balance sheet and statements of income, cash flow, and Partners'
equity, which shall be prepared on an accrual basis in accordance
with generally accepted accounting principles with a
reconciliation with respect to information furnished for income
tax purposes and accompanied by an auditor's report containing an
opinion of an independent public accountant selected by the
Managing General Partner stating that his audit was made in
accordance with generally 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. Also, the independent certified public
accountant will provide written attestation annually, which
will be included in the annual report, that the method used to
make allocations was consistent with the method described in
ss.4.04(a)(2)(c) of this Agreement and that the total amount of
costs allocated did not materially exceed the amounts actually
incurred by the Managing General Partner.
If the Managing General Partner subsequently decides to
allocate expenses in a manner different from that described in
ss.4.04(a)(2)(c) of this Agreement, then the change must be
reported to the Participants together with an explanation of
the reason for the change and the basis used for determining
the reasonableness of the new allocation method.
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(iii) A description of each Prospect in which the Partnership owns an
interest, including:
(a) the cost, location, and number of acres under Lease; and
(b) the Working Interest owned in the Prospect by the
Partnership.
Succeeding reports, however, must only contain material
changes, if any, regarding the Prospects.
(iv) A list of the wells drilled or abandoned by the Partnership
during the period of the report, indicating:
(a) whether each of the wells has or has not been completed;
(b) a statement of the cost of each well completed or
abandoned; and
(c) justification for wells abandoned after production has
begun.
(v) A description of all Farmouts, farmins, and joint ventures,
made during the period of the report, including:
(a) the Managing General Partner's justification for the
arrangement; and
(b) a description of the material terms.
(vi) A schedule reflecting:
(a) the total Partnership costs;
(b) the costs paid by the Managing General Partner and the
costs paid by the Participants;
(c) the total Partnership revenues;
(d) the revenues received or credited to the Managing
General Partner and the revenues received and credited
to the Participants; and
(e) a reconciliation of the expenses and revenues in
accordance with the provisions of Article V.
Additionally, on request the Managing General Partner will provide the
information specified by Form 10-Q (if such report is required to be filed
with the SEC) within 45 days after the close of each quarterly fiscal period.
4.03(b)(2). Tax Information. The Partnership shall, by March 15 of each year,
prepare, or supervise the preparation of, and transmit to each Participant the
information needed for the Participant to file the following:
(i) his federal income tax return;
(ii) any required state income tax return; and
(iii) any other reporting or filing requirements imposed by any
governmental agency or authority.
4.03(b)(3). Reserve Report. Beginning with the second calendar year after the
Offering Termination Date and every year thereafter, the Partnership shall
provide to each Participant the following:
(i) a summary of the computation of the Partnership's total oil and
gas Proved Reserves;
(ii) a summary of the computation of the present worth of the
reserves determined using:
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(a) a discount rate of 10%;
(b) a constant price for the oil; and
(c) basing the price of gas on 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 that leads to the reduction of the Partnership's
Proved Reserves of 10% or more, excluding:
(i) reduction as a result of normal production;
(ii) sales of reserves; or
(iii) 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 in this
ss.4.03(b) shall be paid by the Partnership as Direct Costs.
4.03(b)(5). Participant Access to Records. The Participants and/or their
representatives shall be permitted access to all Partnership records. The
Participant may inspect and copy any of the records after giving adequate
notice to the Managing General Partner at any reasonable time.
Notwithstanding the foregoing, the Managing General Partner may keep logs,
well reports, and other drilling and operating data confidential for
reasonable periods of time. The Managing General Partner may release
information concerning the operations of the Partnership to the sources that
are customary in the industry or required by rule, regulation, or order of any
regulatory body.
4.03(b)(6). Required Length of Time to Hold Records. The Managing General
Partner must maintain and preserve during the term of the Partnership and for
six years thereafter all accounts, books and other relevant documents which
include:
(i) a record that a Participant meets the suitability standards
established in connection with an investment in the
Partnership; and
(ii) any appraisal of the fair market value of the Leases as set
forth in ss.4.01(a)(4) or fair market value of any producing
property as set forth in ss.4.03(d)(3).
4.03(b)(7). Participant Lists. The following provisions apply regarding access
to the list of Participants:
(i) an alphabetical list of the names, addresses, and business
telephone numbers of the Participants along with the number of
Units held by each of them (the "Participant List") must be
maintained as a part of the Partnership's books and records and
be available for inspection by any Participant or his
designated agent at the home office of the Partnership on the
Participant's request;
(ii) the Participant List must be updated at least quarterly to
reflect changes in the information contained in the Participant
List;
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(iii) a copy of the Participant List must be mailed to any
Participant requesting the Participant List within 10 days of
the written request, printed in alphabetical order on white
paper, and in a readily readable type size in no event smaller
than 10-point type and a reasonable charge for copy work will
be charged by the Partnership;
(iv) the purposes for which a Participant may request a copy of the
Participant List include, without limitation, matters relating
to Participant's voting rights under this Agreement and the
exercise of Participant's rights under the federal proxy laws;
and
(v) if the Managing General Partner neglects or refuses to exhibit,
produce, or mail a copy of the Participant List as requested,
the Managing General Partner shall be liable to any Participant
requesting the list for the costs, including attorneys fees,
incurred by that Participant for compelling the production of
the Participant List, and for actual damages suffered by any
Participant by reason of the refusal or neglect. It shall be a
defense that the actual purpose and reason for the request for
inspection or for a copy of the Participant List is to secure
the list of Participants or other information for the purpose
of selling the list or information or copies of the list, or of
using the same for a commercial purpose other than in the
interest of the applicant as a Participant relative to the
affairs of the Partnership. The Managing General Partner will
require the Participant requesting the Participant List to
represent in writing that the list was not requested for a
commercial purpose unrelated to the Participant's interest in
the Partnership. The remedies provided under this subsection to
Participants requesting copies of the Participant List are in
addition to, and shall not in any way limit, other remedies
available to Participants under federal law or the laws of any
state.
4.03(b)(8). State Filings. Concurrently with their transmittal to
Participants, and as required, the Managing General Partner shall file a copy
of each report provided for in this ss.4.03(b) with:
(i) the California Commissioner of Corporations; 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 Units equal 10% or more of the total
Units for any matters for which Participants may vote.
The call for a meeting by Participants shall be deemed to have been made on
receipt by the Managing General Partner of a written request from holders of
the requisite percentage of Units stating the purpose(s) of the meeting.
4.03(c)(1)(b). Notice Requirement. The Managing General Partner shall deposit
in the United States mail within 15 days after the receipt of the request,
written notice to all Participants of the meeting and the purpose of the
meeting. The meeting shall be held on a date not less than 30 days nor more
than 60 days after the date of the mailing of the notice, at a reasonable time
and place.
Notwithstanding the foregoing, the date for notice of the meeting may be
extended for a period of up to 60 days if, in the opinion of the Managing
General Partner, the additional time is necessary to permit preparation of
proxy or information statements or other documents required to be delivered in
connection with the meeting by the SEC or other regulatory authorities.
4.03(c)(1)(c). May Vote by Proxy. Participants shall have the right to vote at
any Participant meeting either:
23
(i) in person; or
(ii) by proxy.
4.03(c)(2). Special Voting Rights. At the request of Participants whose Units
equal 10% or more of the total Units, the Managing General Partner shall call
for a vote by Participants. Each Unit is entitled to one vote on all matters,
and each fractional Unit is entitled to that fraction of one vote equal to the
fractional interest in the Unit. Participants whose Units equal a majority of
the total Units may, without the concurrence of the Managing General Partner
or its Affiliates, vote to:
(i) dissolve the Partnership;
(ii) remove the Managing General Partner and elect a new Managing
General Partner;
(iii) elect a new Managing General Partner if the Managing General
Partner elects to withdraw from the Partnership;
(iv) remove the Operator and elect a new Operator;
(v) approve or disapprove the sale of all or substantially all of
the assets of the Partnership;
(vi) cancel any contract for services with the Managing General
Partner, the Operator, or their Affiliates without penalty on
60 days notice; and
(vii) amend this Agreement; provided however:
(a) any amendment may not increase the duties or liabilities
of any Participant or the Managing General Partner or
increase or decrease the profit or loss sharing or
required Capital Contribution of any Participant or the
Managing General Partner without the approval of the
Participant or the Managing General Partner; and
(b) any amendment may not affect the classification of
Partnership income and loss for federal income tax
purposes without the unanimous approval of all
Participants.
4.03(c)(3). Restrictions on Managing General Partner's Voting Rights. With
respect to Units owned by the Managing General Partner or its Affiliates, the
Managing General Partner and its Affiliates may vote or consent on all matters
other than the following:
(i) the matters set forth in ss.4.03(c)(2)(ii) and (iv) above; or
(ii) any transaction between the Partnership and the Managing
General Partner or its Affiliates.
In determining the requisite percentage in interest of Units necessary to
approve any Partnership matter on which the Managing General Partner and its
Affiliates may not vote or consent, any Units owned by the Managing General
Partner and its Affiliates shall not be included.
4.03(c)(4). Restrictions on Limited Partner Voting Rights. The exercise by the
Limited Partners of the rights granted Participants under ss.4.03(c), except
for the special voting rights granted Participants under ss.4.03(c)(2), shall
be subject to the prior legal determination that the grant or exercise of the
powers will not adversely affect the limited liability of Limited Partners.
Notwithstanding the foregoing, if in the opinion of counsel to the Partnership
the legal determination is not necessary under Delaware law to maintain the
limited liability of the Limited Partners, then it shall not be required. A
legal determination under this paragraph may be made either pursuant to:
24
(i) an opinion of counsel, the counsel being independent of the
Partnership and selected on the vote of Limited Partners whose
Units equal a majority of the total Units held by Limited
Partners; or
(ii) a declaratory judgment issued by a court of competent
jurisdiction.
The Investor General Partners may exercise the rights granted to the
Participants whether or not the Limited Partners can participate in the vote
if the Investor General Partners represent the requisite percentage of Units
necessary to take the action.
4.03(d). Transactions with the Managing General Partner.
4.03(d)(1). Transfer of Equal Proportionate Interest. When the Managing
General Partner or an Affiliate (excluding another Program in which the
interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) sells, transfers or
conveys any natural gas, oil or other mineral interests or property to the
Partnership, it must, at the same time, sell, transfer or convey to the
Partnership an equal proportionate interest in all its other property in the
same Prospect. Notwithstanding, a Prospect shall be deemed to consist of the
drilling or spacing unit on which the well will be drilled by the Partnership,
which is the minimum area permitted by state law or local practice on which
one well may be drilled, if the following conditions are met:
(i) the geological feature to which the well will be drilled
contains Proved Reserves; and
(ii) the drilling or spacing unit protects against drainage.
With respect to a natural gas or oil Prospect located in Ohio, Pennsylvania
and New York on which a well will be drilled by the Partnership to test the
Clinton/Medina geological formation or the Mississippian and/or Upper Devonian
Sandstone reservoirs, a Prospect shall be deemed to consist of the drilling
and spacing unit if it meets the test in the preceding sentence. Additionally,
for a period of five years after the drilling of the Partnership Well neither
the Managing General Partner nor its Affiliates may drill any well:
(i) in the Clinton/Medina geological formation within 1,650 feet of
an existing Partnership Well in Pennsylvania or within 1,000
feet of an existing Partnership Well in Ohio; or
(ii) in the Mississippian/Upper Devonian Sandstone reservoirs in
Fayette County and Greene County, Pennsylvania within 1,000
feet of an existing Partnership Well, although existing wells
may be re-entered by parties other than the Partnership even
though they are not 1,000 feet from each other.
If the Partnership abandons its interest in a well, then this restriction will
continue for one year following the abandonment.
If the area constituting the Partnership's Prospect is subsequently enlarged
to encompass any area in which the Managing General Partner or an Affiliate
(excluding another Program in which the interest of the Managing General
Partner or its Affiliates is substantially similar to or less than their
interest in the Partnership) owns a separate property interest and the
activities of the Partnership were material in establishing the existence of
Proved Undeveloped Reserves that are attributable to the separate property
interest, then the separate property interest or a portion thereof must be
sold, transferred, or conveyed to the Partnership as set forth in this section
and ss.ss.4.01(a)(4) and 4.03(d)(2).
Notwithstanding the foregoing, Prospects in the Clinton/Medina geological
formation, the Mississippian and/or Upper Devonian Sandstone reservoirs, or
any other formation or reservoir shall not be enlarged or contracted if the
Prospect was limited to the drilling or spacing unit because the well was
being drilled to Proved Reserves in the geological formation and the drilling
or spacing unit protected against drainage.
4.03(d)(2). Transfer of Less than the Managing General Partner's and its
Affiliates' Entire Interest. A sale, transfer or a conveyance to the Partnership
of less than all of the ownership of the Managing General Partner or an
Affiliate (excluding another Program in which the interest of the Managing
General Partner or its Affiliates is substantially similar to or less than their
interest in the Partnership) in any Prospect shall not be made unless:
25
(i) the interest retained by the Managing General Partner or the
Affiliate is a proportionate Working Interest;
(ii) the respective obligations of the Managing General Partner or
its Affiliates and the Partnership are substantially the same
after the sale of the interest by the Managing General Partner
or its Affiliates; and
(iii) the Managing General Partner's interest in revenues does not
exceed the amount proportionate to its retained Working
Interest.
This section does not prevent the Managing General Partner or its Affiliates
from subsequently dealing with their retained interest as they may choose with
unaffiliated parties or Affiliated partnerships.
4.03(d)(3). Limitations on Sale of Undeveloped and Developed Leases to the
Managing General Partner. Other than another Program managed by the Managing
General Partner and its Affiliates as set forth in ss.ss.4.03(d)(5) and
4.03(d)(9), the Managing General Partner and its Affiliates shall not Farmout
or purchase any undeveloped Leases from the Partnership other than at the
higher of Cost or fair market value.
The Managing General Partner and its Affiliates, other than an Affiliated
Income Program, may not purchase any producing natural gas or oil property
from the Partnership unless:
(i) the sale is in connection with the liquidation of the
Partnership; or
(ii) the Managing General Partner's well supervision fees under the
Drilling and Operating Agreement for the well have exceeded the
net revenues of the well, determined without regard to the
Managing General Partner's well supervision fees for the well,
for a period of at least three consecutive months.
In both (i) and (ii), the sale must be at fair market value supported by an
appraisal of an Independent Expert selected by the Managing General Partner.
4.03(d)(4). Limitations on Activities of the Managing General Partner and its
Affiliates on Leases Acquired by the Partnership. During a period of five
years after the Offering Termination Date of the Partnership, if the Managing
General Partner or any of its Affiliates (excluding another Program in which
the interest of the Managing General Partner or its Affiliates is
substantially similar to or less than their interest in the Partnership)
proposes to acquire an interest from an unaffiliated person in a Prospect in
which the Partnership possesses an interest or in a Prospect in which the
Partnership's interest has been terminated without compensation within one
year preceding the proposed acquisition, then the following conditions shall
apply:
(i) if the Managing General Partner or the Affiliate (excluding
another Program in which the interest of the Managing General
Partner or its Affiliates is substantially similar to or less
than their interest in the Partnership) does not currently own
property in the Prospect separately from the Partnership, then
neither the Managing General Partner nor the Affiliate shall be
permitted to purchase an interest in the Prospect; and
(ii) if the Managing General Partner or the Affiliate (excluding
another Program in which the interest of the Managing General
Partner or its Affiliates is substantially similar to or less
than their interest in the Partnership) currently owns a
proportionate interest in the Prospect separately from the
Partnership, then the interest to be acquired shall be divided
between the Partnership and the Managing General Partner or the
Affiliate in the same proportion as is the other property in the
Prospect. Provided, however, if cash or financing is not
available to the Partnership to enable it to complete a purchase
of the additional interest to which it is entitled, then neither
the Managing General Partner nor the Affiliate shall be permitted
to purchase any additional interest in the Prospect.
4.03(d)(5). Transfer of Leases Between Affiliated Limited Partnerships. The
transfer of an undeveloped Lease from the Partnership to an Affiliated Drilling
Program must be made at fair market value if the undeveloped Lease has been held
for
26
more than two years. Otherwise, if the Managing General Partner deems it to be
in the best interest of the Partnership, the transfer may be made at Cost.
An Affiliated Income Program may purchase a producing natural gas and oil
property from the Partnership at any time at:
(i) fair market value as supported by an appraisal from an
Independent Expert if the property has been held by the
Partnership for more than six months or there have been
significant expenditures made in connection with the property;
or
(ii) Cost as adjusted for intervening operations if the Managing
General Partner deems it to be in the best interest of the
Partnership.
However, these prohibitions shall not apply to joint ventures or Farmouts
among Affiliated partnerships, provided that:
(i) the respective obligations and revenue sharing of all parties
to the transaction are substantially the same; and
(ii) the compensation arrangement or any other interest or right of
either the Managing General Partner or its Affiliates is the
same in each Affiliated partnership or if different, the
aggregate compensation of the Managing General Partner or the
Affiliate is reduced to reflect the lower compensation
arrangement.
4.03(d)(6). Sale of All Assets. The sale of all or substantially all of the
assets of the Partnership, including without limitation, Leases, wells,
equipment and production therefrom, shall be made only with the consent of
Participants whose Units equal a majority of the total Units.
4.03(d)(7). Services.
4.03(d)(7)(a). Competitive Rates. The Managing General Partner and any
Affiliate shall not render to the Partnership any oil field, equipage, or
other services nor sell or lease to the Partnership any equipment or related
supplies unless:
(i) the person is engaged, independently of the Partnership and as
an ordinary and ongoing business, in the business of rendering
the services or selling or leasing the equipment and supplies
to a substantial extent to other persons in the natural gas and
oil industry in addition to the partnerships in which the
Managing General Partner or an Affiliate has an interest; and
(ii) the compensation, price, or rental therefor is competitive with
the compensation, price, or rental of other persons in the area
engaged in the business of rendering comparable services or
selling or leasing comparable equipment and supplies which
could reasonably be made available to the Partnership.
If the person is not engaged in such a business, then the compensation, price
or rental shall be the Cost of the services, equipment or supplies to the
person or the competitive rate which could be obtained in the area, whichever
is less.
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 on 60 days written notice
by Participants whose Units equal a majority of the total Units.
4.03(d)(8). Loans.
4.03(d)(8)(a). No Loans from the Partnership. No loans or advances shall be
made by the Partnership to the Managing General Partner or any Affiliate.
4.03(d)(8)(b). Loans to the Partnership. Neither the Managing General Partner
nor any Affiliate shall loan money to the Partnership if the interest to be
charged exceeds either:
27
(i) the Managing General Partner's or the Affiliate's interest
cost; or
(ii) that which would be charged to the Partnership, without
reference to the Managing General Partner's or the Affiliate's
financial abilities or guarantees, by unrelated lenders, on
comparable loans for the same purpose.
Neither the Managing General Partner nor any Affiliate shall receive points or
other financing charges or fees, regardless of the amount, although the actual
amount of the charges incurred from third-party lenders may be reimbursed to
the Managing General Partner or the Affiliate.
4.03(d)(9). Farmouts. The Managing General Partner shall not enter into a
Farmout to avoid its paying its share of costs related to drilling an
undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or
well activity to the Managing General Partner or its Affiliates except as set
forth in ss.4.03(d)(3). Notwithstanding, this restriction shall not apply to
Farmouts between the Partnership and another partnership managed by the
Managing General Partner or its Affiliates, either separately or jointly,
provided that the respective obligations and revenue sharing of all parties to
the transactions are substantially the same and the compensation arrangement
or any other interest or right of the Managing General Partner or its
Affiliates is the same in each partnership, or, if different, the aggregate
compensation of the Managing General Partner and its Affiliates is reduced to
reflect the lower compensation agreement.
The Partnership may Farmout an undeveloped lease or well activity only if the
Managing General Partner, exercising the standard of a prudent operator,
determines that:
(i) the Partnership lacks the funds to complete the oil and gas
operations on the Lease or well and cannot obtain suitable
financing;
(ii) drilling on the Lease or the intended well activity would
concentrate excessive funds in one location, creating undue
risks to the Partnership;
(iii) the Leases or well activity have been downgraded by events
occurring after assignment to the Partnership so that
development of the Leases or well activity would not be
desirable; or
(iv) the best interests of the Partnership would be served.
If the Partnership Farmouts a Lease or well activity, the Managing General
Partner must retain on behalf of the Partnership the economic interests and
concessions as a reasonably prudent oil and gas operator would or could retain
under the circumstances prevailing at the time, consistent with industry
practices.
4.03(d)(10). No Compensating Balances. Neither the Managing General Partner
nor any Affiliate shall use the Partnership's funds as compensating balances
for its own benefit.
4.03(d)(11). Future Production. Neither the Managing General Partner nor any
Affiliate shall commit the future production of a well developed by the
Partnership exclusively for its own benefit.
4.03(d)(12). Marketing Arrangements. Subject to ss.4.06(c), all benefits from
marketing arrangements or other relationships affecting the property of the
Managing General Partner or its Affiliates and the Partnership shall be fairly
and equitably apportioned according to the respective interests of each in the
property. The Managing General Partner shall treat all wells in a geographic
area equally concerning to whom and at what price the Partnership's natural gas
and oil will be sold and to whom and at what price the natural gas and oil of
other natural gas and oil Programs which the Managing General Partner has
sponsored or will sponsor will be sold. For example, the Managing General
Partner calculates a weighted average selling price for all the natural gas and
oil sold in a geographic area by taking all the money received from the sale of
all the natural gas and oil sold to its customers in a geographic area and
dividing by the volume of all natural gas and oil sold from the wells in that
geographic area. The Managing General Partner, in its sole discretion, shall
determine what constitutes a geographic area.
28
4.03(d)(13). Advance Payments. Advance payments by the Partnership to the
Managing General Partner and its Affiliates are prohibited except when advance
payments are required to secure the tax benefits of prepaid drilling costs and
for a business purpose.
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.
4.03(d)(16). Roll-Up Limitations.
4.03(d)(16)(a). Requirement for Appraisal and Its Assumptions. In connection
with a proposed Roll-Up, an appraisal of all Partnership assets shall be
obtained from a competent Independent Expert. If the appraisal will be
included in a prospectus used to offer securities of a Roll-Up Entity, then
the appraisal shall be filed with the SEC and the Administrator as an exhibit
to the registration statement for the offering. Thus, an issuer using the
appraisal shall be subject to liability for violation of Section 11 of the
Securities Act of 1933 and comparable provisions under state law for any
material misrepresentations or material omissions in the appraisal.
Partnership assets shall be appraised on a consistent basis. The appraisal
shall be based on all relevant information, including current reserve
estimates prepared by an independent petroleum consultant, and shall indicate
the value of the Partnership's assets as of a date immediately before the
announcement of the proposed Roll-Up transaction. The appraisal shall assume
an orderly liquidation of the Partnership's assets over a 12-month period.
The terms of the engagement of the Independent Expert shall clearly state that
the engagement is for the benefit of the Partnership and the Participants. A
summary of the independent appraisal, indicating all material assumptions
underlying the appraisal, shall be included in a report to the Participants in
connection with a proposed Roll-Up.
4.03(d)(16)(b). Rights of Participants Who Vote Against Proposal. In
connection with a proposed Roll-Up, Participants who vote "no" on the proposal
shall be offered the choice of:
(i) accepting the securities of the Roll-Up Entity offered in the
proposed Roll-Up; or
(ii) one of the following:
(a) remaining as Participants in the Partnership and preserving
their Units in the Partnership on the same terms and
conditions as existed previously; or
(b) receiving cash in an amount equal to the Participants' pro
rata share of the appraised value of the net assets of the
Partnership based on their respective number of Units.
4.03(d)(16)(c). No Roll-Up If Diminishment of Voting Rights. The Partnership
shall not participate in any proposed Roll-Up which, if approved, would result
in the diminishment of any Participant's voting rights under the Roll-Up
Entity's chartering agreement.
29
In no event shall the democracy rights of Participants in the Roll-Up Entity
be less than those provided for under ss.ss.4.03(c)(1) and 4.03(c)(2) of this
Agreement. If the Roll-Up Entity is a corporation, then the democracy rights
of Participants shall correspond to the democracy rights provided for in this
Agreement to the greatest extent possible.
4.03(d)(16)(d). No Roll-Up If Accumulation of Shares Would be Impeded. The
Partnership shall not participate in any proposed Roll-Up transaction which
includes provisions 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 ss.ss.4.03(b)(5), 4.03(b)(6) and 4.03(b)(7) of this
Agreement.
4.03(d)(16)(f). Cost of Roll-Up. The Partnership shall not participate in any
proposed Roll-Up transaction in which any of the costs of the transaction
would be borne by the Partnership if Participants whose Units equal 66% of the
total Units do not vote to approve the proposed Roll-Up.
4.03(d)(16)(g). Roll-Up Approval. The Partnership shall not participate in a
Roll-Up transaction unless the Roll-Up transaction is approved by Participants
whose Units equal 66% of the total Units.
4.03(d)(17). Disclosure of Binding Agreements. Any agreement or arrangement
which binds the Partnership must be disclosed in the Prospectus.
4.03(d)(18). Transactions Must Be Fair and Reasonable. Neither the Managing
General Partner nor any Affiliate shall sell, transfer, or convey any property
to or purchase any property from the Partnership, directly or indirectly,
except:
(i) under 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 it:
(i) is removed pursuant to ss.4.04(a)(3); or
(ii) withdraws pursuant to ss.4.04(a)(3)(f).
4.04(a)(2). Compensation of Managing General Partner. In addition to the
compensation set forth in ss.ss.4.01(a)(4) and 4.02(d)(1), the Managing
General Partner shall receive the compensation set forth in
ss.ss.4.04(a)(2)(b) through 4.04(a)(2)(g).
4.04(a)(2)(a). Charges Must Be Necessary and Reasonable. Charges by the
Managing General Partner for goods and services must be fully supportable as
to:
(i) the necessity of the goods and services; and
(ii) the reasonableness of the amount charged.
All actual and necessary expenses incurred by the Partnership may be paid out
of the Partnership's subscription proceeds and revenues.
30
4.04(a)(2)(b). Direct Costs. The Managing General Partner and its Affiliates
shall be reimbursed for all Direct Costs. Direct Costs, however, shall be
billed directly to and paid by the Partnership to the extent practicable.
4.04(a)(2)(c). Administrative Costs. The Managing General Partner shall
receive an unaccountable, fixed payment reimbursement for its Administrative
Costs of $75 per well per month. The unaccountable, fixed payment
reimbursement of $75 per well per month shall be subject to the following:
(i) it shall not be increased in amount during the term of the
Partnership;
(ii) it shall be proportionately reduced to the extent the
Partnership acquires less than 100% of the Working Interest in
the well;
(iii) it shall be the entire payment to reimburse the Managing
General Partner for the Partnership's Administrative Costs; and
(iv) it shall not be received for plugged or abandoned wells.
4.04(a)(2)(d). Gas Gathering. The Managing General Partner shall be
responsible for gathering and transporting the natural gas produced by the
Partnership to interstate pipeline systems, local distribution companies and
end-users in the area and shall receive a gathering fee at a competitive rate
for gathering and transporting the Partnership's gas. If the Partnership's gas
production is gathered and transported through the gathering system owned by
Atlas Pipeline Partners, then the Managing General Partner shall apply its
gathering fee towards the agreement between Atlas Pipeline Partners and Atlas
America, Inc., Resource Energy, Inc., and Viking Resources Corporation. If the
Partnership's gas production is gathered and transferred through the gathering
system owned by a third-party, then the Managing General Partner shall pay a
portion or all of its gathering fee to the third-party gathering the natural
gas.
4.04(a)(2)(e). Dealer-Manager Fee. Subject to ss.3.03(a)(1), the Dealer-
Manager shall receive on each Unit sold to investors:
(i) a 2.5% Dealer-Manager fee;
(ii) a 7% Sales Commission;
(iii) a .5% accountable marketing expense fee; 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 ss.4.03(d)(7) with the
Partnership and shall be entitled to compensation under this section.
4.04(a)(3). Removal of Managing General Partner.
4.04(a)(3)(a). Majority Vote Required to Remove the Managing General Partner.
The Managing General Partner may be removed at any time on 60 days' advance
written notice to the outgoing Managing General Partner by the affirmative
vote of Participants whose Units equal a majority of the total Units.
If the Participants vote to remove the Managing General Partner from the
Partnership, then Participants must elect by an affirmative vote of
Participants whose Units equal a majority of the total Units either to:
(i) terminate, dissolve, and wind up the Partnership; or
(ii) continue as a successor limited partnership under all the terms
of this Partnership Agreement as provided in ss.7.01(c).
31
If the Participants elect to continue as a successor limited partnership, then
the Managing General Partner shall not be removed until a substituted Managing
General Partner has been selected by an affirmative vote of Participants whose
Units equal a majority of the total Units and installed as such.
4.04(a)(3)(b). Valuation of Managing General Partner's Interest in the
Partnership. If the Managing General Partner is removed, then its interest in
the Partnership shall be determined by appraisal by a qualified Independent
Expert. The Independent Expert shall be selected by mutual agreement between
the removed Managing General Partner and the incoming Managing General
Partner. The appraisal shall take into account an appropriate discount, to
reflect the risk of recovery of natural gas and oil reserves, but not less
than that used 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 in the Partnership as Managing
General Partner and not as a Participant for the value determined by the
Independent Expert.
4.04(a)(3)(d). Method of Payment. The method of payment for the removed
Managing General Partner's interest must be fair and protect the solvency and
liquidity of the Partnership. The method of payment shall be as follows:
(i) when the termination is voluntary, the method of payment shall
be a non-interest bearing unsecured promissory note with
principal payable, if at all, from distributions which the
Managing General Partner otherwise would have received under
the Partnership Agreement had the Managing General Partner not
been terminated; and
(ii) when the termination is involuntary, the method of payment
shall be an interest bearing promissory note coming due in no
less than five years with equal installments each year. The
interest rate shall be that charged on comparable loans.
4.04(a)(3)(e). Termination of Contracts. The removed Managing General Partner,
at the time of its removal shall cause, to the extent it is legally possible,
its successor to be transferred or assigned all its rights, obligations and
interests as Managing General Partner of the Partnership in contracts entered
into by it on behalf of the Partnership. In any event, the removed Managing
General Partner shall cause its rights, obligations and interests as Managing
General Partner of the Partnership in any such contract to terminate at the
time of its removal.
Notwithstanding any other provision in this Agreement, the Partnership or the
successor Managing General Partner shall not:
(i) be a party to any natural gas supply agreement that the
Managing General Partner or its Affiliates enters into with a
third-party;
(ii) have any rights pursuant to such natural gas supply agreement;
or
(iii) receive any interest in the Managing General Partner's and its
Affiliates' pipeline or gathering system or compression
facilities.
4.04(a)(3)(f). The Managing General Partner's Right to Voluntarily Withdraw.
At any time beginning 10 years after the Offering Termination Date and the
Partnership's primary drilling activities, the Managing General Partner may
voluntarily withdraw as Managing General Partner on giving 120 days' written
notice of withdrawal to the Participants. If the Managing General Partner
withdraws, then the following conditions shall apply:
(i) the Managing General Partner's interest in the Partnership
shall be determined as described in ss.4.04(a)(3)(b) above with
respect to removal; and
(ii) the interest shall be distributed to the Managing General
Partner as described in ss.4.04(a)(3)(d)(i) above.
32
Any successor Managing General Partner shall have the option to purchase 20%
of the withdrawing Managing General Partner's interest in the Partnership at
the value determined as described above with respect to removal.
4.04(a)(3)(g). The Managing General Partner's Right to Withdraw Property
Interest. The Managing General Partner has the right at any time to withdraw a
property interest held by the Partnership in the form of a Working Interest in
the Partnership Wells equal to or less than its respective interest in the
revenues of the Partnership under the conditions set forth in ss.6.03. If the
Managing General Partner withdraws an interest, then the Managing General
Partner shall:
(i) pay the expenses of withdrawing; and
(ii) fully indemnify the Partnership against any additional expenses
which may result from a partial withdrawal of its interests
including insuring that a greater amount of Direct Costs or
Administrative Costs is not allocated to the Participants.
4.04(a)(4). Removal of Operator. The Operator may be removed and a new
Operator may be substituted at any time on 60 days advance written notice to
the outgoing Operator by the Managing General Partner acting on behalf of the
Partnership on the affirmative vote of Participants whose Units equal a
majority of the total Units.
The Operator shall not be removed until a substituted Operator has been
selected by an affirmative vote of Participants whose Units equal a majority
of the total Units and installed as such.
4.05. Indemnification and Exoneration.
4.05(a)(1). Standards for the Managing General Partner Not Incurring Liability
to the Partnership or Participants. The Managing General Partner, the
Operator, and their Affiliates shall not have any liability whatsoever to the
Partnership or to any Participant for any loss suffered by the Partnership or
Participants which arises out of any action or inaction of the Managing
General Partner, the Operator, or their Affiliates if:
(i) the Managing General Partner, the Operator, and their
Affiliates determined in good faith that the course of conduct
was in the best interest of the Partnership;
(ii) the Managing General Partner, the Operator, and their
Affiliates were acting on behalf of, or performing services
for, the Partnership; and
(iii) the course of conduct did not constitute negligence or
misconduct of the Managing General Partner, the Operator, or
their Affiliates.
4.05(a)(2). Standards for Managing General Partner Indemnification. The
Managing General Partner, the Operator, and their Affiliates shall be
indemnified by the Partnership against any losses, judgments, liabilities,
expenses, and amounts paid in settlement of any claims sustained by them in
connection with the Partnership, provided that:
(i) the Managing General Partner, the Operator, and their
Affiliates determined in good faith that the course of conduct
which caused the loss or liability was in the best interest of
the Partnership;
(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) tangible net assets;
33
(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 SEC,
the Massachusetts Securities Division, and any state securities
regulatory authority in which plaintiffs claim they were
offered or sold Units with respect to the issue of
indemnification for violation of securities laws.
4.05(a)(4). Standards for Advancement of Funds to the Managing General Partner
and Insurance. The advancement of Partnership funds to the Managing General
Partner, the Operator, or their Affiliates for legal expenses and other costs
incurred as a result of any legal action for which indemnification is being
sought is permissible only if the Partnership has adequate funds available and
the following conditions are satisfied:
(i) the legal action relates to acts or omissions with respect to
the performance of duties or services on behalf of the
Partnership;
(ii) the legal action is initiated by a third-party who is not a
Participant, or the legal action is initiated by a Participant
and a court of competent jurisdiction specifically approves the
advancement; and
(iii) the Managing General Partner or its Affiliates undertake to
repay the advanced funds to the Partnership, together with the
applicable legal rate of interest thereon, in cases in which
such party is found not to be entitled to indemnification.
The Partnership shall not bear the cost of that portion of insurance which
insures the Managing General Partner, the Operator, or their Affiliates for
any liability for which they could not be indemnified pursuant to
ss.ss.4.05(a)(1) and 4.05(a)(2).
4.05(b). Liability of Partners. Under the Delaware Uniform Limited Partnership
Act, the Investor General Partners are liable jointly and severally for all
liabilities and obligations of the Partnership. Notwithstanding the foregoing,
as among themselves, the Investor General Partners agree that each shall be
solely and individually responsible only for his pro rata share of the
liabilities and obligations of the Partnership based on his respective number
of Units.
In addition, the Managing General Partner agrees to use its corporate assets
to indemnify each of the Investor General Partners against all Partnership
related liabilities which exceed the Investor General Partner's interest in
the undistributed net assets of the Partnership and insurance proceeds, if
any. Further, the Managing General Partner agrees to indemnify each Investor
General Partner against any personal liability as a result of the unauthorized
acts of another Investor General Partner.
34
If the Managing General Partner provides indemnification, then each Investor
General Partner who has been indemnified shall transfer and subrogate his
rights for contribution from or against any other Investor General Partner to
the Managing General Partner.
4.05(c). Order of Payment of Claims. Claims shall be paid as follows:
(i) first, out of any insurance proceeds;
(ii) second, out of Partnership assets and revenues; and
(iii) last, by the Managing General Partner as provided in
ss.ss.3.05(b)(2) and (3) and 4.05(b).
No Limited Partner shall be required to reimburse the Managing General
Partner, the Operator, 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 shall be deemed a breach of any obligation owed by the Managing
General Partner, the Operator, or their Affiliates to the Partnership or the
Participants.
4.06. Other Activities.
4.06(a). The Managing General Partner May Pursue Other Natural Gas and Oil
Activities for Its Own Account. The Managing General Partner, the Operator,
and their Affiliates are now engaged, and will engage in the future, for their
own account and for the account of others, including other investors, in all
aspects of the natural gas and oil business. This includes without limitation,
the evaluation, acquisition, and sale of producing and nonproducing Leases,
and the exploration for and production of natural gas, oil and other minerals.
The Managing General Partner is required to devote only so much of its time as
is necessary to manage the affairs of the Partnership. Except as expressly
provided to the contrary in this Agreement, and subject to fiduciary duties,
the Managing General Partner, the Operator, and their Affiliates may do the
following:
(i) continue their activities, or initiate further such activities,
individually, jointly with others, or as a part of any other
limited or general partnership, tax partnership, joint venture,
or other entity or activity to which they are or may become a
party, in any locale and in the same fields, areas of operation
or prospects in which the Partnership may likewise be active;
(ii) reserve partial interests in Leases being assigned to the
Partnership or any other interests not expressly prohibited by
this Agreement;
(iii) deal with the Partnership as independent parties or through any
other entity in which they may be interested;
(iv) conduct business with the Partnership as set forth in this
Agreement; and
(v) participate in such other investor operations, as investors or
otherwise.
The Managing General Partner and its Affiliates shall not be required to
permit the Partnership or the Participants to participate in any of the
operations in which the Managing General Partner and its Affiliates may be
interested or share in any profits or other benefits from the operations.
However, except as otherwise provided in this Agreement, the 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:
35
(i) cannot be pursued by the Partnership because of insufficient
funds; or
(ii) it is not appropriate for the Partnership under the existing
circumstances.
4.06(b). Managing General Partner May Manage Multiple Partnerships. The
Managing General Partner or its Affiliates may manage multiple Programs
simultaneously.
4.06(c). Partnership Has No Interest in Natural Gas Contracts or Pipelines and
Gathering Systems. Notwithstanding any other provision in this Agreement, the
Partnership shall not:
(i) be a party to any natural gas supply agreement that the
Managing General Partner, the Operator, or their Affiliates
enter into with a third-party or have any rights pursuant to
such natural gas supply agreement; or
(ii) receive any interest in the Managing General Partner's, the
Operator's, and their Affiliates' pipeline or gathering system
or compression facilities.
ARTICLE V
PARTICIPATION IN COSTS AND REVENUES,
CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS
5.01. Participation in Costs and Revenues. Except as otherwise provided in
this Agreement, costs and revenues shall be charged and credited to the
Managing General Partner and the Participants as set forth in this section and
its subsections.
5.01(a). Costs. Costs shall be charged as set forth below.
5.01(a)(1). Organization and Offering Costs. Organization and Offering Costs
shall be charged 100% to the Managing General Partner. For purposes of sharing
in revenues under ss.5.01(b)(4), the Managing General Partner shall be
credited with Organization and Offering Costs paid by it up to and including
15% of the Partnership's subscription proceeds. Any Organization and Offering
Costs paid by the Managing General Partner in excess of this amount shall not
be credited towards the Managing General Partner's required Capital
Contribution or revenue share as set forth in ss.5.01(b)(4).
5.01(a)(2). Intangible Drilling Costs. Intangible Drilling Costs shall be
charged 100% to the Participants.
5.01(a)(3). Tangible Costs. Tangible Costs shall be charged 66% to the
Managing General Partner and 34% to the Participants. However, if the total
Tangible Costs for all of the Partnership's wells that would be charged to the
Participants exceeds an amount equal to 10% of the Partnership's subscription
proceeds, then the excess shall be charged to the Managing General Partner.
5.01(a)(4). Operating Costs, Direct Costs, Administrative Costs and All Other
Costs. Operating Costs, Direct Costs, Administrative Costs, and all other
Partnership costs not specifically allocated shall be charged to the parties
in the same ratio as the related production revenues are being credited.
5.01(a)(5). Allocation of Intangible Drilling Costs and Tangible Costs at
Partnership Closings. Intangible Drilling Costs and the Participants' share of
Tangible Costs of a well or wells to be drilled and completed with the
proceeds of a Partnership closing shall be charged 100% to the Participants
who are admitted to the Partnership in that closing and shall not be
reallocated to take into account other Partnership closings.
Although the proceeds of each Partnership closing will be used to pay the
costs of drilling different wells, not less than 90% of each Participant's
subscription proceeds shall be applied to Intangible Drilling Costs and not
more than 10% of each Participant's subscription proceeds shall be applied to
Tangible Costs regardless of when he subscribes.
5.01(a)(6). Lease Costs. The Leases shall be contributed to the Partnership by
the Managing General Partner as set forth in ss.4.01(a)(4).
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5.01(b). Revenues. Revenues shall be credited as set forth below.
5.01(b)(1). Allocation of Revenues on Disposition of Property. If the parties'
Capital Accounts are adjusted to reflect the simulated depletion of a natural
gas or oil property of the Partnership, then the portion of the total amount
realized by the Partnership on the taxable disposition of the property that
represents recovery of its simulated tax basis in the property shall be
allocated to the parties in the same proportion as the aggregate adjusted tax
basis of the property was allocated to the parties or their predecessors in
interest. If the parties' Capital Accounts are adjusted to reflect the actual
depletion of a natural gas or oil property of the Partnership, then the
portion of the total amount realized by the Partnership on the taxable
disposition of the property that equals the parties' aggregate remaining
adjusted tax basis in the property shall be allocated to the parties in
proportion to their respective remaining adjusted tax bases in the property.
Thereafter, any excess shall be allocated to the Managing General Partner in
an amount equal to the difference between the fair market value of the Lease
at the time it was contributed to the Partnership and its simulated or actual
adjusted tax basis at that time. Finally, any excess shall be credited as
provided in ss.5.01(b)(4), below.
In the event of a sale of developed natural gas and oil properties with
equipment on the properties, the Managing General Partner may make any
reasonable allocation of proceeds between the equipment and the Leases.
5.01(b)(2). Interest. Interest earned on each Participant's subscription
proceeds before the Offering Termination Date under ss.3.05(b)(1) shall be
credited to the accounts of the respective subscribers who paid the
subscription proceeds to the Partnership. The interest shall be paid to the
Participant not later than the Partnership's first cash distribution from
operations.
After the Offering Termination Date and until proceeds from the offering are
invested in the Partnership's natural gas and oil operations, any interest
income from temporary investments shall be allocated pro rata to the
Participants providing the subscription proceeds.
All other interest income, including interest earned on the deposit of
production revenues, shall be credited as provided in ss.5.01(b)(4), below.
5.01(b)(3). Sale or Disposition of Equipment. Proceeds from the sale or
disposition of equipment shall be credited to the parties charged with the
costs of the equipment in the ratio in which the costs were charged.
5.01(b)(4). Other Revenues. Subject to ss.5.01(b)(4)(a), the Managing General
Partner and the Participants shall share in all other Partnership revenues in
the same percentage as their respective Capital Contribution bears to the total
Partnership Capital Contributions, except that the Managing General Partner
shall receive an additional 7% of Partnership revenues. However, the Managing
General Partner's total revenue share may not exceed 35% of Partnership
revenues. For example, if the Managing General Partner contributes 25% of the
total Partnership Capital Contributions and the Participants contribute 75% of
the total Partnership Capital Contributions, then the Managing General Partner
shall receive 32% of the Partnership revenues and the Participants shall receive
68% of the Partnership revenues. On the other hand, if the Managing General
Partner contributes 30% of the total Partnership Capital Contributions and the
Participants contribute 70% of the total Partnership Capital Contributions, then
the Managing General Partner shall receive 35% of the Partnership revenues, not
37%, because its revenue share cannot exceed 35% of Partnership revenues, and
the Participants shall receive 65% of Partnership revenues.
5.01(b)(4)(a). Subordination. The Managing General Partner shall subordinate
up to 50% of its share of Partnership Net Production Revenues to the receipt
by Participants of cash distributions from the Partnership equal to $1,000 per
Unit (which is 10% per Unit) regardless of their actual subscription price of
the Units, in each of the first five 12-month periods beginning with the
Partnership's first cash distributions from operations. In this regard:
(i) the 60-month subordination period shall begin with the first
cash distribution from operations to the Participants, but no
subordination distributions to the Participants shall be
required until the Partnership's first cash distribution to the
Participants after substantially all Partnership wells have
been drilled, completed, and placed in production in a sales
line;
(ii) subsequent subordination distributions, if any, shall be
determined and made at the time of each subsequent distribution
of revenues to the Participants; and
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(iii) the Managing General Partner shall not subordinate more than
50% of its share of Partnership Net Production Revenues in any
subordination period.
The subordination shall be determined by:
(i) carrying forward to subsequent 12-month periods the amount, if
any, by which cumulative cash distributions to Participants,
including any subordination payments, are less than:
(a) $1,000 per Unit (10% per Unit) in the first 12-month
period;
(b) $2,000 per Unit (20% per Unit) in the second 12-month
period;
(c) $3,000 per Unit (30% per Unit) in the third 12-month
period; or
(d) $4,000 per Unit (40% per Unit) in the fourth 12-month
period (no carry forward is required if such
distributions are less than $5,000 per Unit (50% per
Unit) in the fifth 12-month period because the Managing
General Partner's subordination obligation terminates on
the expiration of the fifth 12-month period); and
(ii) reimbursing the Managing General Partner for any previous
subordination payments to the extent cumulative cash
distributions to Participants, including any subordination
payments, would exceed:
(a) $1,000 per Unit (10% per Unit) in the first 12-month
period;
(b) $2,000 per Unit (20% per Unit) in the second 12-month
period;
(c) $3,000 per Unit (30% per Unit) in the third 12-month
period;
(d) $4,000 per Unit (40% per Unit) in the fourth 12-month
period; or
(e) $5,000 per Unit (50% per Unit) in the fifth 12-month
period.
The Managing General Partner's subordination obligation shall be further
subject to the following conditions:
(i) the subordination obligation may be prorated in the Managing
General Partner's discretion (e.g. in the case of a quarterly
distribution, the Managing General Partner will not have any
subordination obligation if the distributions to Participants
equal $250 per Unit (25% of $1,000 per Unit per year) or more
assuming there is no subordination owed for any preceding
period);
(ii) the Managing General Partner shall not be required to return
Partnership distributions previously received by it, even
though a subordination obligation arises after the
distributions;
(iii) subject to the foregoing provisions of this section, only
Partnership revenues in the current distribution period shall
be debited or credited to the Managing General Partner as may
be necessary to provide, to the extent possible, subordination
distributions to the Participants and reimbursements to the
Managing General Partner;
(iv) no subordination payments to the Participants or reimbursements
to the Managing General Partner shall be made after the
expiration of the fifth 12-month subordination period; and
(v) subordination payments to the Participants shall be subject to
any lien or priority required by the Managing General Partner's
lenders pursuant to agreements previously entered into or
subsequently entered into or renewed by the Managing General
Partner.
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5.01(b)(5). Commingling of Revenues From All Partnership Wells. The revenues
from all Partnership wells will be commingled, so regardless of when a
Participant subscribes he will share in the revenues from all wells on the
same basis as the other Participants.
5.01(c). Allocations.
5.01(c)(1). Allocations among Participants. Except as provided otherwise in
this Agreement, costs (other than Intangible Drilling Costs and Tangible
Costs) and revenues charged or credited to the Participants as a group, which
includes all revenue credited to the Participants under ss.5.01(b)(4), shall
be allocated among the Participants, including the Managing General Partner to
the extent of any optional subscription under ss.3.03(b)(2), in the ratio of
their respective Units based on $10,000 per Unit regardless of the actual
subscription price for a Participant's Units.
Intangible Drilling Costs and Tangible Costs charged to the Participants as a
group shall be allocated among the Participants, including the Managing
General Partner to the extent of any optional subscription under
ss.3.03(b)(2), in the ratio of the subscription price designated on their
respective Subscription Agreements rather than the number of their respective
Units.
5.01(c)(2). Costs and Revenues Not Directly Allocable to a Partnership Well.
Costs and revenues not directly allocable to a particular Partnership Well or
additional operation shall be allocated among the Partnership Wells or
additional operations in any manner the Managing General Partner in its
reasonable discretion, shall select, and shall then be charged or credited in
the same manner as costs or revenues directly applicable to the Partnership
Well or additional operation are being charged or credited.
5.01(c)(3). Managing General Partner's Discretion in Making Allocations For
Federal Income Tax Purposes. In determining the proper method of allocating
charges or credits among the parties, 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, regardless of the number
of interests owned by the party, the class of the interests and the time or
manner in which the interests were acquired.
5.02(b). Charges and Credits.
5.02(b)(1). General Standard. Except as otherwise provided in this Agreement,
the Capital Account of each party shall be determined and maintained in
accordance with Treas. Reg. ss.1.704-l(b)(2)(iv) and shall be increased by:
(i) the amount of money contributed by him to the Partnership;
(ii) the fair market value of property contributed by him, without
regard to ss.7701(g) of the Code, to the Partnership, net of
liabilities secured by the contributed property that the
Partnership is considered to assume or take subject to under
ss.752 of the Code; and
(iii) allocations to him of Partnership income and gain, or items
thereof, including income and gain exempt from tax and income
and gain described in Treas. Reg. ss.1.704-l(b)(2)(iv)(g), but
excluding income and gain described in Treas. Reg. ss.1.704-
l(b)(4)(i);
39
and shall be decreased by:
(iv) the amount of money distributed to him by the Partnership;
(v) the fair market value of property distributed to him, without
regard to ss.7701(g) of the Code, by the Partnership, net of
liabilities secured by the distributed property that he is
considered to assume or take subject to under ss.752 of the
Code;
(vi) allocations to him of Partnership expenditures described in
ss.705(a)(2)(B) of the Code; and
(vii) allocations to him of Partnership loss and deduction, or items
thereof, including loss and deduction described in Treas. Reg.
ss.1.704-l(b)(2)(iv)(g), but excluding items described in (vi)
above, and loss or deduction described in Treas. Reg. ss.1.704-
l(b)(4)(i) or (iii).
5.02(b)(2). Exception. If Treas. Reg. ss.1.704-l(b)(2)(iv) fails to provide
guidance, Capital Account adjustments shall be made in a manner that:
(i) maintains equality between the aggregate governing Capital
Accounts of the parties and the amount of Partnership capital
reflected on the Partnership's balance sheet, as computed for
book purposes;
(ii) is consistent with the underlying economic arrangement of the
parties; and
(iii) is based, wherever practicable, on federal tax accounting
principles.
5.02(c). Payments to the Managing General Partner. The Capital Account of the
Managing General Partner shall be reduced by payments to it pursuant to
ss.4.04(a)(2) only to the extent of the Managing General Partner's
distributive share of any Partnership deduction, loss, or other downward
Capital Account adjustment resulting from the payments.
5.02(d). Discretion of Managing General Partner in the Method of Maintaining
Capital Accounts. Notwithstanding any other provisions of this Agreement, the
method of maintaining Capital Accounts may be changed from time to time, in
the discretion of the Managing General Partner, to take into consideration
ss.704 and other provisions of the Code and the related rules, regulations and
interpretations as may exist from time to time.
5.02(e). Revaluations of Property. In the discretion of the Managing General
Partner the Capital Accounts of the parties may be increased or decreased to
reflect a revaluation of Partnership property, including intangible assets
such as goodwill, on a property-by-property basis except as otherwise
permitted under ss.704(c) of the Code and the regulations thereunder, on the
Partnership's books, in accordance with Treas. Reg. ss.1.704-l(b)(2)(iv)(f).
5.02(f). Amount of Book Items. In cases where ss.704(c) of the Code or
ss.5.02(e) applies, Capital Accounts shall be adjusted in accordance with
Treas. Reg. ss.1.704-l(b)(2)(iv)(g) for allocations of depreciation,
depletion, amortization and gain and loss, as computed for book purposes, with
respect to the property.
5.03. Allocation of Income, Deductions and Credits.
5.03(a). In General.
5.03(a)(1). Deductions Are Allocated to Party Charged with Expenditure. To the
extent permitted by law and except as otherwise provided in this Agreement,
all deductions and credits, including, but not limited to, intangible drilling
and development costs and depreciation, shall be allocated to the party who
has been charged with the expenditure giving rise to the deductions and
credits; and to the extent permitted by law, these parties shall be entitled
to the deductions and credits in computing taxable income or tax liabilities
to the exclusion of any other party. Also, any Partnership deductions that
would be nonrecourse deductions if they were not attributable to a loan made
or guaranteed by the Managing General Partner or its Affiliates shall be
allocated to the Managing General Partner to the extent required by law.
40
5.03(a)(2). Income and Gain Allocated in Accordance With Revenues. Except as
otherwise provided in this Agreement, all items of income and gain, including
gain on disposition of assets, shall be allocated in accordance with the
related revenue allocations set forth in ss.5.01(b) and its subsections.
5.03(b). Tax Basis of Each Property. Subject to ss.704(c) of the Code, the tax
basis of each oil and gas property for computation of cost depletion and gain
or loss on disposition shall be allocated and reallocated when necessary based
on the capital interest in the Partnership as to the property and the capital
interest in the Partnership for this purpose as to each property shall be
considered to be owned by the parties in the ratio in which the expenditure
giving rise to the tax basis of the property has been charged as of the end of
the year.
5.03(c). Gain or Loss on Oil and Gas Properties. Each party shall separately
compute its gain or loss on the disposition of each natural gas and oil
property in accordance with the provisions of ss.613A(c)(7)D) of the Code, and
the calculation of the gain or loss shall consider the party's adjusted basis
in his property interest computed as provided in ss.5.03(b) and the party's
allocable share of the amount realized from the disposition of the property.
5.03(d). Gain on Depreciable Property. Gain from each sale or other
disposition of depreciable property shall be allocated to each party whose
share of the proceeds from the sale or other disposition exceeds its
contribution to the adjusted basis of the property in the ratio that the
excess bears to the sum of the excesses of all parties having an excess.
5.03(e). Loss on Depreciable Property. Loss from each sale, abandonment or
other disposition of depreciable property shall be allocated to each party
whose contribution to the adjusted basis of the property exceeds its share of
the proceeds from the sale, abandonment or other disposition in the proportion
that the excess bears to the sum of the excesses of all parties having an
excess.
5.03(f). Allocation If Recapture Treated As Ordinary Income. Any recapture
treated as an increase in ordinary income by reason of ss.ss.1245, 1250, or 1254
of the Code shall be allocated to the parties in the amounts in which the
recaptured items were previously allocated to them; provided that to the extent
recapture allocated to any party is in excess of the party's gain from the
disposition of the property, the excess shall be allocated to the other parties
but only to the extent of the other parties' gain from the disposition of the
property.
5.03(g). Tax Credits. As of the date of the Prospectus, tax credits are not
available to the Partnership. If this changes in the future, however, and if a
Partnership expenditure, whether or not deductible, that gives rise to a tax
credit in a Partnership taxable year also gives rise to valid allocations of
Partnership loss or deduction, or other downward Capital Account adjustments,
for the year, then the parties' interests in the Partnership with respect to
the credit, or the cost giving rise thereto, shall be in the same proportion
as the parties' respective distributive shares of the loss or deduction, and
adjustments. Identical principles shall apply in determining the parties'
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 party having a deficit Capital Account
balance as of the end of the taxable year to which the allocation relates, if
charged to the party, to the extent the Participant is not required to restore
the deficit to the Partnership, taking into account:
(i) adjustments that, as of the end of the year, reasonably are
expected to be made to the party's Capital Account for
depletion allowances with respect to the Partnership's natural
gas and oil properties;
(ii) allocations of loss and deduction that, as of the end of the
year, reasonably are expected to be made to the party under
ss.ss.704(e)(2) and 706(d) of the Code and Treas. Reg.
ss.1.751-1(b)(2)(ii); and
(iii) distributions that, as of the end of the year, reasonably are
expected to be made to the party to the extent they exceed
offsetting increases to the party's Capital Account, assuming
for this purpose that the fair market value of Partnership
property equals its adjusted tax basis, that reasonably are
expected to occur during or prior to the Partnership taxable
years in which the distributions reasonably are expected to be
made;
41
shall be charged to the Managing General Partner. Further, the Managing
General Partner shall be credited with an additional amount of Partnership
income or gain equal to the amount of the loss or deduction as quickly as
possible to the extent such chargeback does not cause or increase deficit
balances in the parties' Capital Accounts which are not required to be
restored to the Partnership.
Notwithstanding any provisions of this Agreement to the contrary, if a party
unexpectedly receives an adjustment, allocation, or distribution described in
(i), (ii), or (iii) above, or any other distribution, which causes or
increases a deficit balance in the party's Capital Account which is not
required to be restored to the Partnership, the party shall be allocated items
of income and gain, consisting of a pro rata portion of each item of
Partnership income, including gross income, and gain for the year, in an
amount and manner sufficient to eliminate the deficit balance as quickly as
possible.
5.03(i). Minimum Gain Chargeback. To the extent there is a net decrease during
a Partnership taxable year in the minimum gain attributable to a Partner
nonrecourse debt, then any Partner with a share of the minimum gain
attributable to the debt at the beginning of the year shall be allocated items
of Partnership income and gain in accordance with Treas. Reg. ss.1.704-2(i).
5.03(j). Partners' Allocable Shares. Except as otherwise provided in this
Agreement, each party's allocable share of Partnership income, gain, loss,
deductions and credits shall be determined by the use of any method prescribed
or permitted by the Secretary of the Treasury by regulations or other
guidelines and selected by the Managing General Partner which takes into
account the varying interests of the parties in the Partnership during the
taxable year. In the absence of such regulations or guidelines, except as
otherwise provided in this Agreement, the allocable share shall be based on
actual income, gain, loss, deductions and credits economically accrued each
day during the taxable year in proportion to each party's varying interest in
the Partnership on each day during the taxable year.
5.04. 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). ss.754 Election. In the event of the transfer of an interest in the
Partnership, or on the death of an individual party hereto, or in the event of
the distribution of property to any party, the Managing General Partner may
choose for the Partnership to file an election in accordance with the
applicable Treasury Regulations to cause the basis of the Partnership's assets
to be adjusted for federal income tax purposes as provided by ss.ss.734 and
743 of the Code.
5.05. Distributions.
5.05(a). In General.
5.05(a)(1). Quarterly Review of Accounts. The Managing General Partner shall
review the accounts of the Partnership at least quarterly to determine whether
cash distributions are appropriate and the amount to be distributed, if any.
5.05(a)(2). Distributions. The Partnership shall distribute funds to the
Managing General Partner and the Participants allocated to their accounts
which the Managing General Partner deems unnecessary to retain by the
Partnership.
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5.05(a)(3). No Borrowings. In no event, however, shall funds be advanced or
borrowed for distributions if the amount of the distributions would exceed the
Partnership's accrued and received revenues for the previous four quarters,
less paid and accrued Operating Costs with respect to the revenues. The
determination of revenues and costs shall be made in accordance with generally
accepted accounting principles, consistently applied.
5.05(a)(4). Distributions to the Managing General Partner. Cash distributions
from the Partnership to the Managing General Partner shall only be made as
follows:
(a) in conjunction with distributions to Participants; and
(b) out of funds properly allocated to the Managing General
Partner's account.
5.05(a)(5). Reserve. At any time after one year from the date each Partnership
Well is placed into production, the Managing General Partner shall have the
right to deduct each month from the Partnership's proceeds of the sale of the
production from the well up to $200 for the purpose of establishing a fund to
cover the estimated costs of plugging and abandoning the well. All of these
funds shall be deposited in a separate interest bearing account for the
benefit of the Partnership, and the total amount so retained and deposited
shall not exceed the Managing General Partner's reasonable estimate of the
costs.
5.05(b). Distribution of Uncommitted Subscription Proceeds. Any net subscription
proceeds not expended or committed for expenditure, as evidenced by a written
agreement, by the Partnership within 12 months of the Offering Termination Date,
except necessary operating capital, shall be distributed to the Participants in
the ratio that the subscription price designated on each Participant's
Subscription Agreement bears to the total subscription prices designated on all
of the Participants' Subscription Agreements, as a return of capital. The
Managing General Partner shall reimburse the Participants for the selling or
other offering expenses allocable to the return of capital.
For purposes of this subsection, "committed for expenditure" shall mean
contracted for, actually earmarked for or allocated by the Managing General
Partner to the Partnership's drilling operations, and "necessary operating
capital" shall mean those funds which, in the opinion of the Managing General
Partner, should remain on hand to assure continuing operation of the
Partnership.
5.05(c). Distributions on Winding Up. On the winding up of the Partnership
distributions shall be made as provided in ss.7.02.
5.05(d). Interest and Return of Capital. No party shall under any
circumstances be entitled to any interest on amounts retained by the
Partnership. Each Participant shall look only to his share of distributions,
if any, from the Partnership for a return of his Capital Contribution.
ARTICLE VI
TRANSFER OF INTERESTS
6.01. Transferability.
6.01(a). Rights of Assignee. On a transfer unless an assignee becomes a
substituted Participant in accordance with the provisions set forth below, he
shall not be entitled to any of the rights granted to a Participant under this
Agreement, other than the right to receive all or part of the share of the
profits, losses, income, gain, credits and cash distributions or returns of
capital to which his assignor would otherwise be entitled.
6.01(b). Conversion of Investor General Partner Units to Limited Partner
Units.
6.01(b)(1). Automatic Conversion. After all of the Partnership Wells have been
drilled and completed the Managing General Partner shall file an amended
certificate of limited partnership with the Secretary of State of the State of
Delaware for the purpose of converting the Investor General Partner Units to
Limited Partner Units.
43
6.01(b)(2). Investor General Partners Shall Have Contingent Liability. On
conversion the Investor General Partners shall be Limited Partners entitled to
limited liability; however, they shall remain liable to the Partnership for
any additional Capital Contribution required for their proportionate share of
any Partnership obligation or liability arising before the conversion of their
Units as provided in ss.3.05(b)(2).
6.01(b)(3). Conversion Shall Not Affect Allocations. The conversion shall not
affect the allocation to any Participant of any item of Partnership income,
gain, loss, deduction or credit or other item of special tax significance
other than Partnership liabilities, if any. Further, the conversion shall not
affect any Participant's interest in the Partnership's natural gas and oil
properties and unrealized receivables.
6.01(b)(4). Right to Convert if Reduction of Insurance. Notwithstanding the
foregoing, the Managing General Partner shall notify all Participants at least
30 days before the effective date of any adverse material change in the
Partnership's insurance coverage. If the insurance coverage is to be
materially reduced, then the Investor General Partners shall have the right to
convert their Units into Limited Partner Units before the reduction by giving
written notice to the Managing General Partner.
6.02. Special Restrictions on Transfers.
6.02(a). In General. Transfers are subject to the following general
conditions:
(i) 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 Units are subject to the following additional restrictions set
forth in ss.ss.6.02(a)(1) and 6.02(a)(2).
6.02(a)(1). Tax Law Restrictions. Subject to transfers permitted by ss.6.04
and transfers by operation of law, no sale, assignment, exchange, or transfer
of a Unit shall be made which, in the opinion of counsel to the Partnership,
would result in the Partnership being either:
(i) terminated for tax purposes under ss.708 of the Code; or
(ii) treated as a "publicly-traded" partnership for purposes of
ss.469(k) of the Code.
6.02(a)(2). Securities Laws Restriction. Subject to transfers permitted by
ss.6.04 and transfers by operation of law, no Unit shall be sold, assigned,
pledged, hypothecated, or transferred which, in the opinion of counsel to the
Partnership, would result in the violation of any applicable federal or state
securities laws.
Transfers are also subject to any conditions contained in the Subscription
Agreement and Exhibit (B) to the Prospectus.
6.02(a)(3). Substitute Participant.
6.02(a)(3)(a). Procedure to Become Substitute Participant. Subject to
ss.ss.6.02(a)(1) and 6.02(a)(2), an assignee of a Participant's Unit shall
become a substituted Participant entitled to all the rights of a Participant
if, and only if:
(i) the assignor gives the assignee the right;
(ii) the assignee pays to the Partnership all costs and expenses
incurred in connection with the substitution; and
44
(iii) the assignee executes and delivers the instruments necessary to
establish that a legal transfer has taken place and to confirm
the agreement of the assignee to be bound by all of the terms
of this Agreement.
6.02(a)(3)(b). Rights of Substitute Participant. A substitute Participant is
entitled to all of the rights attributable to full ownership of the assigned
Units including the right to vote.
6.02(b). Effect of Transfer.
6.02(b)(1). Amendment of Records. The Partnership shall amend its records at
least once each calendar quarter to effect the substitution of substituted
Participants.
Any transfer permitted under this Agreement when the assignee does not become
a substituted Participant shall be effective as follows:
(i) midnight of the last day of the calendar month in which it is
made; or
(ii) at the Managing General Partner's election, 7:00 A.M. of the
following day.
6.02(b)(2). Transfer Does Not Relieve Transferor of Certain Costs. No
transfer, including a transfer of less than all of a Participant's Units or
the transfer of Units to more than one party, shall relieve the transferor of
its responsibility for its proportionate part of any expenses, obligations and
liabilities under this Agreement related to the Units so transferred, whether
arising before or after the transfer.
6.02(b)(3). Transfer Does Not Require An Accounting. No transfer of a Unit
shall require an accounting by the Managing General Partner. Also, no transfer
shall grant rights under this Agreement, including the exercise of any
elections, as between the transferring parties and the remaining parties to
this Agreement to more than one party unanimously designated by the
transferees and, if he should have retained an interest under this Agreement,
the transferor.
6.02(b)(4). Notice. Until the Managing General Partner receives a proper
notice of designation acceptable to it, the Managing General Partner shall
continue to account only to the person to whom it was furnishing notices
before the time pursuant to ss.8.01 and its subsections. This party shall
continue to exercise all rights applicable to the Units previously owned by
the transferor.
6.03. Right of Managing General Partner to Hypothecate and/or Withdraw Its
Interests. The Managing General Partner shall have the authority without the
consent of the Participants and without affecting the allocation of costs and
revenues received or incurred under this Agreement, to hypothecate, pledge, or
otherwise encumber, on any terms it chooses for its own general purposes
either:
(i) its Partnership interest; or
(ii) an undivided interest in the assets of the Partnership equal to
or less than its respective interest in the revenues of the
Partnership.
All repayments of these borrowings and costs, interest or other charges
related to the borrowings shall be borne and paid separately by the Managing
General Partner. In no event shall the repayments, costs, interest, or other
charges related to the borrowing be charged to the account of the
Participants.
In addition, subject to a required participation of not less than 1% in the
Partnership as Managing General Partner, the Managing General Partner may
withdraw a property interest held by the Partnership in the form of a Working
Interest in the Partnership Wells equal to or less than its respective
interest in the revenues of the Partnership if:
(i) the withdrawal is necessary to satisfy the bona fide request of
its creditors; or
45
(ii) the withdrawal is approved by Participants whose Units equal a
majority of the total Units.
6.04. Presentment.
6.04(a). In General. Participants shall have the right to present their
interests to the Managing General Partner for purchase subject to the
conditions and limitations set forth in this section. A Participant, however,
is not obligated to present his Units for purchase.
The Managing General Partner shall not be obligated to purchase more than 5%
of the Units in any calendar year and this 5% limit may not be waived. The
Managing General Partner shall not purchase less than one Unit unless the
lesser amount represents the Participant's entire interest in the Partnership,
however, the Managing General Partner may waive this limitation.
A Participant may present his Units in writing to the Managing General Partner
every year beginning with the fifth calendar year after the Offering
Termination Date subject to the following conditions:
(i) the presentment must be made within 120 days of the reserve
report set forth in ss.4.03(b)(3);
(ii) in accordance with Treas. Reg. ss.1.7704-1(f), the purchase may
not be made until at least 60 calendar days after the
Participant notifies the Partnership in writing of the
Participant's intention to exercise the presentment right; and
(iii) the purchase shall not be considered effective until the
presentment price has been paid in cash to the Participant.
6.04(b). Requirement for Independent Petroleum Consultant. The amount of the
presentment price attributable to Partnership reserves shall be determined
based on the last reserve report of the Partnership prepared by the Managing
General Partner and reviewed by an Independent Expert. The Managing General
Partner shall estimate the present worth of future net revenues attributable
to the Partnership's interest in the Proved Reserves. In making this estimate,
the Managing General Partner shall use the following terms:
(i) a discount rate equal to 10%;
(ii) a constant price for the oil; and
(iii) base the price of natural gas on the existing natural gas
contracts at the time of the purchase.
The calculation of the presentment price shall be as set forth in ss.6.04(c).
6.04(c). Calculation of Presentment Price. The presentment price shall be
based on the Participant's share of the net assets and liabilities of the
Partnership and allocated pro rata to each Participant in the ratio that his
number of Units bears to the total number of Units. The presentment price
shall include the sum of the following Partnership items:
(i) an amount based on 70% of the present worth of future net
revenues from the Proved Reserves determined as described in
ss.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:
46
(i) an amount equal to all debts, obligations, and other
liabilities, including accrued expenses; and
(ii) any distributions made to the Participants between the date of
the request and the actual payment. However, if any cash
distributed was derived from the sale, after the presentment
request, of natural gas, oil or other mineral production, or of
a producing property owned by the Partnership, for purposes of
determining the reduction of the presentment price, the
distributions shall be discounted at the same rate used to take
into account the risk factors employed to determine the present
worth of the Partnership's Proved Reserves.
6.04(d). Further Adjustment May Be Allowed. The presentment price may be
further adjusted by the Managing General Partner for estimated changes therein
from the date of the report to the date of payment of the presentment price to
the Participants because of the following:
(i) the production or sales of, or additions to, reserves and lease and
well equipment, sale or abandonment of Leases, and similar matters
occurring before the request for purchase; and
(ii) any of the following occurring before payment of the presentment price
to the selling Participants:
(a) changes in well performance;
(b) increases or decreases in the market price of natural
gas, oil or other minerals;
(c) revision of regulations relating to the importing of
hydrocarbons;
(d) changes in income, ad valorem, and other tax laws such
as material variations in the provisions for depletion;
and
(e) similar matters.
6.04(e). Selection by Lot. If less than all Units presented at any time are to
be purchased, then the Participants whose Units are to be purchased will be
selected by lot.
The Managing General Partner's obligation to purchase Units presented may be
discharged for its benefit by a third-party or an Affiliate. The Units of the
selling Participant will be transferred to the party who pays for it. A
selling Participant will be required to deliver an executed assignment of his
Units, together with any other documentation as the Managing General Partner
may reasonably request.
6.04(f). No Obligation of the Managing General Partner to Establish a Reserve.
The Managing General Partner shall have no obligation to establish any reserve
to satisfy the presentment obligations under this section.
6.04(g). Suspension of Presentment Feature. The Managing General Partner may
suspend this presentment feature by so notifying Participants at any time if
it:
(i) does not have sufficient cash flow; or
(ii) is unable to borrow funds for this purpose on terms it deems
reasonable.
In addition, the presentment feature may be conditioned, in the Managing
General Partner's sole discretion, on the Managing General Partner's receipt
of an opinion of counsel that the transfers will not cause the Partnership to
be treated as a "publicly traded partnership" under the Code.
The Managing General Partner shall hold the purchased Units for its own
account and not for resale.
47
ARTICLE VII
DURATION, DISSOLUTION, AND WINDING UP
7.01. Duration.
7.01(a). Fifty Year Term. The Partnership shall continue in existence for a
term of 50 years from the effective date of this Agreement unless sooner
terminated as set forth below.
7.01(b). Termination. The Partnership shall terminate following the occurrence
of:
(i) a Final Terminating Event; or
(ii) any event which under the Delaware Revised Uniform Limited
Partnership Act causes the dissolution of a limited
partnership.
7.01(c). Continuance of Partnership Except on Final Terminating Event. Other
than the occurrence of a Final Terminating Event, the Partnership or any
successor limited partnership shall not be wound up, but shall be continued by
the parties and their respective successors as a successor limited partnership
under all the terms of this Agreement. The successor limited partnership shall
succeed to all of the assets of the Partnership. As used throughout this
Agreement, the term "Partnership" shall include the successor limited
partnerships and the parties to the successor limited partnerships.
7.02. Dissolution and Winding Up.
7.02(a). Final Terminating Event. On the occurrence of a Final Terminating
Event the affairs of the Partnership shall be wound up and there shall be
distributed to each of the parties its Distribution Interest in the remaining
Partnership assets.
7.02(b). Time of Liquidating Distribution. To the extent practicable and in
accordance with sound business practices in the judgment of the Managing
General Partner, liquidating distributions shall be made by:
(i) the end of the taxable year in which liquidation occurs,
determined without regard to ss.706(c)(2)(A) of the Code; or
(ii) if later, within 90 days after the date of the liquidation.
Notwithstanding, the following amounts are not required to be distributed
within the foregoing time periods so long as the withheld amounts are
distributed as soon as practical:
(i) amounts withheld for reserves reasonably required for
liabilities of the Partnership; and
(ii) installment obligations owed to the Partnership.
7.02(c). In-Kind Distributions. The Managing General Partner shall not be
obligated to offer in-kind property distributions to the Participants, and
shall do so, in its discretion. Any in-kind property distributions to the
Participants shall be made to a liquidating trust or similar entity for the
benefit of the Participants, unless at the time of the distribution:
(i) the Managing General Partner offers the individual Participants
the election of receiving in-kind property distributions and
the Participants accept the offer after being advised of the
risks associated with direct ownership; or
(ii) there are alternative arrangements in place which assure the
Participants that they will not, at any time, be responsible
for the operation or disposition of Partnership properties.
If the Managing General Partner has not received a Participant's consent
within 30 days after the Managing General Partner mailed the request for
consent, then it shall be presumed that the Participant has refused his
consent.
48
7.02(d). Sale If No Consent. Any Partnership asset which would otherwise be
distributed in-kind to a Participant, except for the failure or refusal of the
Participant to give his written consent to the distribution, may instead be
sold by the Managing General Partner at the best price reasonably obtainable
from an independent third-party, who is not an Affiliate of the Managing
General Partner or to itself or its Affiliates, including an Affiliated Income
Program, at fair market value as determined by an Independent Expert selected
by the Managing General Partner.
ARTICLE VIII
MISCELLANEOUS PROVISIONS
8.01. Notices.
8.01(a). Method. Any notice required under this Agreement shall be:
(i) in writing; and
(ii) given by mail or wire addressed to the party to receive the
notice at the address designated in ss.1.03.
If there is a transfer of Units under this Agreement, no notice to the
transferee shall be required, nor shall the transferee have any rights under
this Agreement, until notice has been given to the Managing General Partner.
Any transfer of rights under this Agreement shall not increase the duty to
give notice. If there is a transfer of Units under this Agreement to more than
one party, then notice to any owner of any interest in the Units shall be
notice to all owners of the Units.
8.01(b). Change in Address. The address of any party to this Agreement may be
changed by written notice as follows:
(i) to the Participants if there is a change of address by the
Managing General Partner; or
(ii) to the Managing General Partner if there is a change of address
by a Participant.
8.01(c). Time Notice Deemed Given. If the notice is given by the Managing
General Partner, then the notice shall be considered given, and any applicable
time shall run, from the date the notice is placed in the mail or delivered to
the telegraph company.
If the notice is given by any Participant, then the notice shall be considered
given and any applicable time shall run from the date the notice is received.
8.01(d). Effectiveness of Notice. Any notice to a party other than the
Managing General Partner, including a notice requiring concurrence or
nonconcurrence, shall be effective, and any failure to respond binding,
irrespective of the following:
(i) whether or not the notice is actually received; or
(ii) any disability or death on the part of the noticee, even if the
disability or death is known to the party giving the notice.
8.01(e). Failure to Respond. Except pursuant to ss.7.02(c) or when this
Agreement expressly requires affirmative approval of a Participant, any
Participant who fails to respond in writing within the time specified to a
request by the Managing General Partner as set forth below, for approval of or
concurrence in a proposed action shall be conclusively deemed to have approved
the action. The Managing General Partner shall send the first request and the
time period shall be not less than 15 business days from the date of mailing
of the request. If the Participant does not respond to the first request, then
the Managing General Partner shall send a second request. If the Participant
does not respond within seven calendar days from the date of the mailing of
the second request, then the Participant shall be conclusively deemed to have
approved the action.
8.02. Time. Time is of the essence of each part of this Agreement.
8.03. Applicable Law. The terms and provisions of this Agreement shall be
construed under the laws of the State of Delaware, provided, however, this
section shall not be deemed to limit causes of action for violations of
federal or state
49
securities law to the laws of the State of Delaware. Neither
this Agreement nor the Subscription Agreement shall require mandatory venue or
mandatory arbitration of any or all claims by Participants against the
Sponsor.
8.04. Agreement in Counterparts. This Agreement may be executed in counterpart
and shall be binding on all parties executing this or similar agreements from
and after the date of execution by each party.
8.05. Amendment.
8.05(a). Procedure for Amendment. No changes in this Agreement shall be
binding unless:
(i) proposed in writing by the Managing General Partner, and
adopted with the consent of Participants whose Units equal a
majority of the total Units; or
(ii) proposed in writing by Participants whose Units equal 10% or
more of the total Units and approved by an affirmative vote of
Participants whose Units equal a majority of the total Units.
8.05(b). Circumstances Under Which the Managing General Partner Alone May
Amend. The Managing General Partner is authorized to amend this Agreement and
its exhibits without the consent of Participants in any way deemed necessary
or desirable by it to:
(i) add or substitute in the case of an assigning party additional
Participants;
(ii) enhance the tax benefits of the Partnership to the parties; or
(iii) satisfy any requirements, conditions, guidelines, options, or
elections contained in any opinion, directive, order, ruling,
or regulation of the SEC, the IRS, or any other federal or
state agency, or in any federal or state statute, compliance
with which it deems to be in the best interest of the
Partnership.
Notwithstanding the foregoing, no amendment materially and adversely affecting
the interests or rights of Participants shall be made without the consent of
the Participants whose interests will be so affected.
8.06. Additional Partners. Each Participant hereby consents to the admission
to the Partnership of additional Participants as the Managing General Partner,
in its discretion, chooses to admit.
8.07. Legal Effect. This Agreement shall be binding on and inure to the
benefit of the parties, their heirs, devisees, personal representatives,
successors and assigns, and shall run with the interests subject to this
Agreement. The terms "Partnership," "Limited Partner," "Investor General
Partner," "Participant," "Partner," "Managing General Partner," "Operator," or
"parties" shall equally apply to any successor limited partnership, and any
heir, devisee, personal representative, successor or assign of a party.
IN WITNESS WHEREOF, the parties hereto set their hands as of the day and year
hereinabove shown.
ATLAS: ATLAS RESOURCES, INC.
Managing General Partner
By: _____________________________________
50
EXHIBIT (I-A)
FORM OF
MANAGING GENERAL PARTNER SIGNATURE PAGE
EXHIBIT (I-A)
MANAGING GENERAL PARTNER SIGNATURE PAGE
Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND
AGREEMENT OF LIMITED PARTNERSHIP of ATLAS AMERICA PUBLIC #12-2003 LIMITED
PARTNERSHIP
The undersigned agrees:
1. to serve as the Managing General Partner of ATLAS AMERICA PUBLIC #12-
2003 LIMITED PARTNERSHIP (the "Partnership"), and hereby executes,
swears to, and agrees to all the terms of the Partnership Agreement;
2. to pay the required subscription of the Managing General Partner under
ss.3.03(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_______________ , 200___.
ATLAS RESOURCES, INC.
MANAGING GENERAL PARTNER
By: ____________________________
EXHIBIT (I-B)
FORM OF
SUBSCRIPTION AGREEMENT
ATLAS AMERICA PUBLlC #12-2003 LIMITED PARTNERSHIP
- -------------------------------------------------------------------------------
SUBSCRIPTION AGREEMENT
- -------------------------------------------------------------------------------
I, the undersigned, hereby offer to purchase Units of Atlas America Public
#12-2003 Limited Partnership 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 #12-2003 Program, as supplemented or amended from time
to time. I acknowledge and agree that my execution of this Subscription
Agreement also constitutes my execution of the Agreement of Limited Partnership
(the "Partnership Agreement") the form of which is attached as Exhibit (A) to
the Prospectus and I agree to be bound by all of the terms and conditions of the
Partnership Agreement if my subscription is accepted by Atlas Resources, Inc.,
the Managing General Partner. I understand and agree that I may not assign this
offer, nor may it be withdrawn after it has been accepted by the Managing
General Partner. I hereby irrevocably constitute and appoint the Managing
General Partner, and its duly authorized agents, my agent and attorney-in-fact,
in my name, place and stead, to make, execute, acknowledge, swear to, file,
record and deliver the Agreement of Limited Partnership and any certificates
related thereto.
In order to induce the Managing General Partner to accept this subscription,
I hereby represent, warrant, covenant and agree as follows:
Investor's Co-Investor's
Initials Initials
_____ _____ I have received the Prospectus.
_____ _____ I, other than if I am a Minnesota or Maine resident, recognize and understand that:
o 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;
o the transferability of the Units is restricted; and
o 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:
o my own account;
o for investment purposes and not for the account of others; and
o with no present intention of reselling them.
_____ _____ If an individual, I am:
o a citizen of the United States of America; and
o 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. I am at least twenty-one years of age and
empowered and duly authorized under a governing document, trust instrument, charter,
certificate of incorporation, by-law provision or the like to enter into this Subscription
Agreement and to perform the transactions contemplated by the Prospectus, including its
exhibits.
(a) I have either:
_____ _____ o a net worth of at least $225,000, exclusive of home, furnishings and automobiles;
or
1
Investor's Co-Investor's
Initials Initials
_____ _____ o a net worth, exclusive of home, furnishings and automobiles, of:
o at least $60,000; and
o 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:
o Alabama, o Michigan, o Oregon,
o Arizona, o Minnesota, o Pennsylvania,
o California, o Mississippi, o South Dakota,
o Indiana, o Missouri, o Tennessee,
o Iowa, o New Hampshire, o Texas,
o Kansas, o New Mexico, o Vermont or
o Kentucky, o North Carolina, o Washington,
o Maine, o Ohio,
o Massachusetts, o Oklahoma,
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, other than if I am a Minnesota or Maine resident, understand that if I am an Investor
General Partner, then I will have unlimited joint and several liability for Partnership
obligations and liabilities including amounts in excess of my subscription to the extent
the obligations and liabilities exceed the following:
o the Partnership's insurance proceeds;
o the Partnership's assets; and
o indemnification by the Managing General Partner.
Insurance may be inadequate to cover these liabilities and there is no insurance coverage
for certain claims.
_____ _____ I, other than if I am a Minnesota or Maine resident, understand that if I am a Limited
Partner, then I may only use my Partnership losses to the extent of my net passive income
from passive activities in the year, with any excess losses being deferred.
_____ _____ I, other than if I am a Minnesota or Maine resident, understand that no state or federal
governmental authority has made any finding or determination relating to the fairness for
public investment of the Units and no state or federal governmental authority has
recommended or endorsed or will recommend or endorse the Units.
_____ _____ I, other than if I am a Minnesota or Maine resident, understand that the Selling Agent or
registered representative is required to inform me and the other potential investors of
all pertinent facts relating to the Units, including the following:
2
Investor's Co-Investor's
Initials Initials
o the risks involved in the offering, including the speculative nature of the
investment and the speculative nature of drilling for natural gas and oil;
o the financial hazards involved in the offering, including the risk of losing my
entire investment;
o the lack of liquidity of my investment;
o the restrictions on transferability of my Units;
o the background of the Managing General Partner and the Operator;
o the tax consequences of my investment; and
o 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:
o the person has been given your legal power of attorney to sign on your
behalf; and
o you meet all of the conditions in the Prospectus and this Subscription
Agreement.
In the case of sales to fiduciary accounts, the minimum standards set forth in
the Prospectus and this Subscription Agreement must be met by:
o the beneficiary;
o the fiduciary account; or
o by the donor or grantor who directly or indirectly supplies the funds to
purchase the Partnership Units if the donor or grantor is the fiduciary.
Your execution of the Subscription Agreement constitutes your binding offer to
buy Units in the Partnership. Once you subscribe you may withdraw your
subscription only by providing the Managing General Partner with written notice
of your withdrawal before your subscription is accepted by the Managing General
Partner. The Managing General Partner has the discretion to refuse to accept
your subscription without liability to you. Subscriptions will be accepted or
rejected by the Partnership within 30 days of their receipt. If your
subscription is rejected, then all of your funds will be returned to you
immediately.
If your subscription is accepted before the first closing, then you will be
admitted as a Participant not later than 15 days after the release from escrow
of the investors' funds to the Partnership. If your subscription is accepted
after the first closing, then you will be admitted into the Partnership not
later than the last day of the calendar month in which your subscription was
accepted by the Partnership.
The Managing General Partner will do the following:
o not complete a sale of Units to you until at least five business days after
the date you receive a final Prospectus; and
o send you a confirmation of purchase.
NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from
various requirements of Title 10 of the California Administrative Code. These
deviations include, but are not limited to the following: the definition of
Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule
260.140.121(1), does not require enlarging or contracting the size of the area
on the basis of geological data in all cases.
If a resident of California I acknowledge the receipt of California Rule
260.141.11 set forth in Exhibit (B) to the Prospectus.
3
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SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
- -------------------------------------------------------------------------------
I, the undersigned, agree to purchase ________ Units at $10,000 per Unit in
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP (the "Partnership") as (check
one):
| | INVESTOR GENERAL PARTNER
| | LIMITED PARTNER
Subscription Price
$ ---------------------------
(_____________________# Units)
Instructions
- -------------------------------------------------------------------------------
Make your check payable to: "Atlas America Public #12-2003 Limited Partnership,
Escrow Agent, National City Bank of PA" Minimum Subscription: one Unit
($10,000), however, the Managing General Partner, in its discretion, may accept
one-half Unit ($5,000) subscriptions. Additional Subscriptions in $1,000
increments. If you are an individual investor you must personally sign this
signature page and provide the information requested below.
- -------------------------------------------------------------------------------
Subscriber (All individual My Home Address (Do not use P.O. Box)
investors must personally
sign this Signature Page.)
- ------------------------------------- -------------------------------------
Print Name
- ------------------------------------- -------------------------------------
Signature
- ------------------------------------- -------------------------------------
Print Name
My Address for Distributions if
Different from Above
- ------------------------------------- -------------------------------------
Signature
Date:---------------
My Tax I.D. No.
(Social Security No.): ------------- Account No.: -----------------------
My Telephone No.: Business --------- Home --------------------------------
My E-mail Address:-------------------------------
(CHECK ONE): I am a: | | Calendar Year Taxpayer | | Fiscal Year
Taxpayer
(CHECK IF APPLICABLE): I am a: | | Farmer (2/3 or more of my gross income
in 2003 or 2002 is from farming)
(CHECK ONE): OWNERSHIP OF THE UNITS- | | Tenants-in-Common | | Partnership
| | Joint Tenancy | | C Corporation
| | Individual | | S Corporation
| | Trust | | Community Property
| | Limited Liability Company | | Other
NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP: Name -----------------------
(Enclose supporting documents.)
1
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TO BE COMPLETED BY REGISTERED REPRESENTATIVE (For Commission and Other Purposes)
- -------------------------------------------------------------------------------
I hereby represent that I have discharged my affirmative obligations under Rule
2810(b)(2)(B) and (b)(3)(D) of the NASD's Conduct Rules and specifically have
obtained information from the above-named subscriber concerning his/her age, net
worth, annual income, federal income tax bracket, investment objectives,
investment portfolio, and other financial information and have determined that
an investment in the Partnership is suitable for such subscriber, that such
subscriber is or will be in a financial position to realize the benefits of this
investment, and that such subscriber has a fair market net worth sufficient to
sustain the risks for this investment. I have also informed the subscriber of
all pertinent facts relating to the liquidity and marketability of an investment
in the Partnership, of the risks of unlimited liability regarding an investment
as an Investor General Partner, and of the passive loss limitations for tax
purposes of an investment as a Limited Partner.
- ------------------------------------- ---------------------------------------
Name of Registered Representative Name of Broker/Dealer
and CRD Number
- ------------------------------------- ---------------------------------------
Signature of Registered Broker/Dealer CRD Number
Representative
Registered Representative Broker/Dealer E-mail Address:----------
Office Address:
- -------------------------------------
- -------------------------------------
Phone Number:------------------------
Facsimile Number:--------------------
E-mail Address:----------------------
- -------------------------------------
Company Name (if other than
Broker/Dealer Name)
NOTICE TO BROKER-DEALER:
Send Subscription Documents completed and signed with check MADE PAYABLE TO:
"Atlas Public #12-2003 Limited Partnership, Escrow Agent, National City Bank of
PA" to:
Mr. Justin Atkinson
Anthem Securities, Inc.
311 Rouser Road
P.O. Box 926
Coraopolis, Pennsylvania 15108-0926
(412) 262-1680
(412) 262-7430 (FAX)
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TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
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ACCEPTED THIS ______ day ATLAS RESOURCES, INC.,
of _________________ , 2003 MANAGING GENERAL PARTNER
By: ------------------------------------------
2
EXHIBIT (II)
FORM OF
DRILLING AND OPERATING AGREEMENT
FOR
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
[ATLAS AMERICA PUBLIC #12-2004(_____) LIMITED PARTNERSHIP]
(This Drilling and Operating Agreement Is Written
For a Natural Gas Development Well In
The Clinton/Medina Geological Formation.
The Drilling and Operating Agreement Will Be Appropriately
Modified for Different Formations or Areas and Oil Wells.)
INDEX
Section Page
1. Assignment of Well Locations; Representations; Designation of Additional Well
Locations; Outside Activities Are Not Restricted ........................................................ 1
2. Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations ............. 2
3. Operator - Responsibilities in General; Covenants; Term ................................................. 3
4. Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole
Determination; Excess Funds and Cost Overruns - Intangible Drilling Costs; Excess Funds and Cost
Overruns - Tangible Costs ............................................................................... 4
5. Title Examination of Well Locations; Developer's Acceptance and Liability; Additional Well Locations .... 7
6. Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price
Determinations; Plugging and Abandonment ................................................................ 7
7. Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for
Sale Proceeds; Records and Reports; Additional Information .............................................. 9
8. Operator's Lien; Right to Collect From Gas Purchaser .................................................... 11
9. Successors and Assigns; Transfers; Appointment of Agent ................................................. 11
10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability ................................... 12
11. Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind ............... 13
12. Effect of Force Majeure; Definition of Force Majeure; Limitation ........................................ 14
13. Term .................................................................................................... 14
14. Governing Law; Invalidity ............................................................................... 14
15. Integration; Written Amendment .......................................................................... 15
16. Waiver of Default or Breach ............................................................................. 15
17. Notices ................................................................................................. 15
18. Interpretation .......................................................................................... 15
19. Counterparts ............................................................................................ 15
Signature Page .......................................................................................... 16
Exhibit A Description of Leases and Initial Well Locations
Exhibits A-l through A-___ Maps of Initial Well Locations
Exhibit B Form of Assignment
Exhibit C Form of Addendum
DRILLING AND OPERATING AGREEMENT
THIS AGREEMENT made this ______ day of _______________, 2003, by and between
ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as
"Atlas" or "Operator"),
and
ATLAS AMERICA PUBLIC #12-2003 Limited Partnership [Atlas America Public
#12-2004(_____) Limited Partnership], a Delaware limited partnership,
(hereinafter referred to as the "Developer").
WITNESSETH THAT:
WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the "Leases")
described on Exhibit A attached to and made a part of this Agreement, has
certain rights to develop the ____________ (______) initial well locations (the
"Initial Well Locations") identified on the maps attached to and made a part of
this Agreement as Exhibits A-l through A-______;
WHEREAS, the Developer, subject to the terms and conditions of this Agreement,
desires to acquire certain of the Operator's rights to develop the Initial Well
Locations and to provide for the development on the terms and conditions set
forth in this Agreement of additional well locations ("Additional Well
Locations") which the parties may from time to time designate; and
WHEREAS, the Operator is in the oil and gas exploration and development
business, and the Developer desires that Operator, as its independent
contractor, perform certain services in connection with its efforts to develop
the aforesaid Initial and Additional Well Locations (collectively the "Well
Locations") and to operate the wells completed on the Well Locations, on the
terms and conditions set forth in this Agreement;
NOW THEREFORE, in consideration of the mutual covenants herein contained and
subject to the terms and conditions hereinafter set forth, the parties hereto,
intending to be legally bound, hereby agree as follows:
1. Assignment of Well Locations; Representations; Designation of Additional
Well Locations; Outside Activities Are Not Restricted.
(a) Assignment of Well Locations. The Operator shall execute an assignment
of an undivided percentage of Working Interest in the Well Location
acreage for each well to the Developer as shown on Exhibit A attached
hereto, which assignment shall be limited to a depth from the surface
to the top of the Queenston formation in Pennsylvania and Ohio when
the primary objective is the Clinton/Medina geological formation. In
the event that hydrocarbons are encountered in quantities that
Operator believes to be in paying quantities and drilling ceases
before the Clinton/Medina geological formation is penetrated, then
Operator shall execute an assignment limited to a depth from the
surface to the deepest depth penetrated at the cessation of drilling
operations.
The assignment shall be substantially in the form of Exhibit B
attached to and made a part of this Agreement. The amount of acreage
included in each Initial Well Location and the configuration of the
Initial Well Location are indicated on the maps attached as Exhibits
A-l through A-______. The amount of acreage included in each
Additional Well Location and the configuration of the Additional Well
Location shall be indicated on the maps to be attached as exhibits to
the applicable addendum to this Agreement as provided in sub- section
(c) below.
(b) Representations. The Operator represents and warrants to the Developer
that:
(i) the Operator is the lawful owner of the Lease and rights and
interest under the Lease and of the personal property on the
Lease or used in connection with the Lease;
(ii) the Operator has good right and authority to sell and convey the
rights, interest, and property;
(iii) the rights, interest, and property are free and clear from all
liens and encumbrances; and
(iv) all rentals and royalties due and payable under the Lease have
been duly paid.
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These representations and warranties shall also be included in
each recorded assignment of the acreage included in each Initial
Well Location and Additional Well Location designated pursuant to
sub-section (c) below, substantially in the manner set forth in
Exhibit B.
The Operator agrees to indemnify, protect and hold the Developer
and its successors and assigns harmless from and against all
costs (including but not limited to reasonable attorneys' fees),
liabilities, claims, penalties, losses, suits, actions, causes of
action, judgments or decrees resulting from the breach of any of
the above representations and warranties. It is understood and
agreed that, except as specifically set forth above, the Operator
makes no warranty or representation, express or implied, as to
its title or the title of the lessors in and to the lands or oil
and gas interests covered by said Leases.
(c) Designation of Additional Well Locations. If the parties hereto
desire to designate Additional Well Locations to be developed in
accordance with the terms and conditions of this Agreement, then
the parties shall execute an addendum substantially in the form
of Exhibit C attached to and made a part of this Agreement
(Exhibit "C") specifying:
(i) the undivided percentage of Working Interest and the Oil
and Gas Leases to be included as Leases under this
Agreement;
(ii) the amount and configuration of acreage included in each
Additional Well Location on maps attached as exhibits to
the addendum; and
(iii) their agreement that the Additional Well Locations shall
be developed in accordance with the terms and conditions
of this Agreement.
(d) Outside Activities Are Not Restricted. It is understood and
agreed that the assignment of rights under the Leases and the
oil and gas development activities contemplated by this
Agreement relate only to the Initial Well Locations and the
Additional Well Locations. Nothing contained in this Agreement
shall be interpreted to restrict in any manner the right of
each of the parties to conduct without the participation of the
other party any additional activities relating to exploration,
development, drilling, production, or delivery of oil and gas
on lands adjacent to or in the immediate vicinity of the Well
Locations or elsewhere.
2. Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute
Well Locations.
(a) Drilling of Wells. Operator, as Developer's independent
contractor, agrees to drill, complete (or plug) and operate
____________ (_____) 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 in proportion to the share of the
Working Interest owned by the Developer in the wells with
respect to all initial wells. It is understood and agreed that,
subject to sub-section (e) below, Developer does not reserve
the right to decline participation in the drilling of any of
the initial wells to be drilled under this Agreement.
(b) Timing. Operator will use its best efforts to begin drilling the
first well within thirty (30) days after the date of this
Agreement and to begin drilling each of the other initial wells
for which payment is made pursuant to Section 4(b) of this
Agreement, on or before March 31, 2004. Subject to the foregoing
time limits, Operator shall determine the timing of and the order
of drilling the Initial Well Locations.
(c) Depth. All of the wells to be drilled under this Agreement (c)
shall be:
(i) drilled and completed (or plugged) in accordance with the
generally accepted and customary oil and gas field
practices and techniques then prevailing in the
geographical area of the Well Locations; and
(ii) drilled to a depth sufficient to test thoroughly the
objective formation or the deepest assigned depth,
whichever is less.
(d) Interest of Developer. Except as otherwise provided in this
Agreement, all costs, expenses, and liabilities incurred in
connection with the drilling and other operations and activities
contemplated by this Agreementshall be borne and paid, and all
wells, gathering lines of up to approximately 2,500 feet on the
Well
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Location, equipment, materials, and facilities acquired,
constructed or installed under this Agreement shall be owned, by
the Developer in proportion to the share of the Working Interest
owned by the Developer in the wells. Subject to the payment of
lessor's royalties and other royalties and overriding royalties,
if any, production of oil and gas from the wells to be drilled
under this Agreement shall be owned by the Developer in
proportion to the share of the Working Interest owned by the
Developer in the wells.
(e) Right to Substitute Well Locations. Notwithstanding the
provisions of sub-section (a) above, if the Operator or
Developer determines in good faith, with respect to any Well
Location, before operations begin under this Agreement on the
Well Location, that it would not be in the best interest of the
parties to drill a well on the Well Location, then the party
making the determination shall notify the other party of its
determination and its basis for its determination and, unless
otherwise instructed by Developer, the well shall not be
drilled. This determination may be based on:
(i) the production or failure of production of any other
wells which may have been recently drilled in the
immediate area of the Well Location;
(ii) newly discovered title defects; or
(iii) any other evidence with respect to the Well Location as
may be obtained.
If the well is not drilled, then Operator shall promptly propose
a new well location (including all information for the Well
Location as Developer may reasonably request) within
Pennsylvania, Ohio, or other areas of the United States to be
substituted for the original Well Location. Developer shall then
have seven (7) business days to either reject or accept the
proposed new well location. If the new well location is rejected,
then Operator shall promptly propose another substitute well
location pursuant to the provisions of this sub-section.
Once the Developer accepts a substitute well location or does not
reject it within said seven (7) day period, this Agreement shall
terminate as to the original Well Location and the substitute
well location shall become subject to the terms and conditions of
this Agreement.
3. Operator - Responsibilities in General; Covenants; Term.
(a) Operator - Responsibilities in General. Atlas shall be the
Operator of the wells and Well Locations subject to this
Agreement and, as the Developer's independent contractor, shall,
in addition to its other obligations under this Agreement do the
following:
(i) arrange for drilling and completing the wells and
installing the necessary gas gathering line systems and
connection facilities;
(ii) make the technical decisions required in drilling,
testing, completing, and operating the wells;
(iii) manage and conduct all field operations in connection
with the drilling, testing, completing, equipping,
operating, and producing the wells;
(iv) maintain all wells, equipment, gathering lines, and
facilities in good working order during their useful
lives; and
(v) perform the necessary administrative and accounting
functions.
In performing the work contemplated by this Agreement, Operator
is an independent contractor with authority to control and direct
the performance of the details of the work.
(b) Covenants. Operator covenants and agrees that under this
Agreement:
(i) it shall perform and carry on (or cause to be performed
and carried on) its duties and obligations in a good,
prudent, diligent, and workmanlike manner using
technically sound, acceptable oil and gas field practices
then prevailing in the geographical area of the Well
Locations;
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(ii) all drilling and other operations conducted by, for and
under the control of Operator shall conform in all
respects to federal, state and local laws, statutes,
ordinances, regulations, and requirements;
(iii) unless otherwise agreed in writing by the Developer, all
work performed pursuant to a written estimate shall
conform to the technical specifications set forth in the
written estimate and all equipment and materials
installed or incorporated in the wells and facilities
shall be new or used and of good quality;
(iv) in the course of conducting operations, it shall comply
with all terms and conditions, other than any minimum
drilling commitments, of the Leases (and any related
assignments, amendments, subleases, modifications and
supplements);
(v) it shall keep the Well Locations and all wells, equipment
and facilities located on the Well Locations free and
clear of all labor, materials and other liens or
encumbrances arising out of operations;
(vi) it shall file all reports and obtain all permits and
bonds required to be filed with or obtained from any
governmental authority or agency in connection with the
drilling or other operations and activities; and
(vii) it will provide competent and experienced personnel to
supervise drilling, completing (or plugging), and
operating the wells and use the services of competent and
experienced service companies to provide any third party
services necessary or appropriate in order to perform its
duties.
(c) Term. Atlas shall serve as Operator under this Agreement until
the earliest of:
(i) the termination of this Agreement pursuant to Section 13;
(ii) the termination of Atlas as Operator by the Developer at
any time in the Developer's discretion, with or without
cause on sixty (60) days' advance written notice to the
Operator; or
(iii) the resignation of Atlas as Operator under this Agreement
which may occur on ninety (90) days' written notice to
the Developer at any time after five (5) years from the
date of this Agreement, it being expressly understood and
agreed that Atlas shall have no right to resign as
Operator before the expiration of the five-year period.
Any successor Operator shall be selected by the Developer.
Nothing contained in this sub-section shall relieve or release
Atlas or the Developer from any liability or obligation under
this Agreement which accrued or occurred before Atlas' removal or
resignation as Operator under this Agreement. On any change in
Operator under this provision, the then present Operator shall
deliver to the successor Operator possession of all records,
equipment, materials and appurtenances used or obtained for use
in connection with operations under this Agreement and owned by
the Developer.
4. Operator's Charges for Drilling and Completing Wells; Payment; Completion
Determination; Dry Hole Determination; Excess Funds and Cost Overruns-
Intangible Drilling Costs; Excess Funds and Cost Overruns-Tangible Costs.
(a) Operator's Charges for Drilling and Completing Wells. All
natural gas wells which are drilled and completed under this
Agreement 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 the wells shall be set forth in
an Authority for Expenditure ("AFE") which shall be attached to
this Agreement as an Exhibit, and shall cover all ordinary costs
which may be incurred in drilling and completing each well for
production of natural gas. This includes without limitation, site
preparation, permits and bonds, roadways, surface damages, power
at the site, water, Operator's overhead and profit,
rights-of-way, drilling rigs, equipment and materials, logging,
cementing, fracturing, casing, meters (other than utility
purchase meters), connection facilities, salt water collection
tanks, separators,
4
siphon string, rabbit, tubing, an average of 2,500 feet of
gathering line per well, geological and engineering services and
completing two (2) zones. The 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 estimated price.
These extra costs, if any, 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 and Tangible Costs as those terms are defined
below, for drilling and completing all initial wells on
execution of this Agreement. Notwithstanding, Atlas' payments
for its share of the estimated Tangible Costs as that term is
defined below of drilling and completing all initial wells as
the Managing General Partner of the Developer shall be paid
within five (5) business days of notice from Operator that the
costs have been incurred. The Developer's payment shall be
nonrefundable in all events in order to enable Operator to do
the following:
(i) commence site preparation for the initial wells;
(ii) obtain suitable subcontractors for drilling and
completing the wells at currently prevailing prices; and
(iii) insure the availability of equipment and materials.
For purposes of this Agreement, "Intangible Drilling Costs" shall
mean those expenditures associated with property acquisition and
the drilling and completion of oil and gas wells that under
present law are generally accepted as fully deductible currently
for federal income tax purposes. This includes 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 under the Code and its
regulations.
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 and Tangible Costs for the
well on execution of the applicable addendum pursuant to Section
l(c) above. Notwithstanding, Atlas' payments for its share of the
estimated Tangible Costs of drilling and completing all
additional wells as the Managing General Partner of the Developer
shall be paid within five (5) business days of notice from
Operator that the costs have been incurred. The Developer's
payment shall be nonrefundable in all events in order to enable
Operator to do the following:
(i) commence site preparation;
5
(ii) obtain suitable subcontractors for drilling and
completing the wells at currently prevailing prices; and
(iii) insure the availability of equipment and materials.
Developer shall pay, in proportion to the share of the Working
Interest owned by the Developer in the wells, any extra costs
incurred for each well pursuant to sub-section (a) above within
ten (10) business days of its receipt of Operator's statement for
the extra costs.
(c) Completion Determination. Operator shall determine whether or not
to run the production casing for an attempted completion or to
plug and abandon any well drilled under this Agreement. However,
a well shall be completed only if Operator has made a good faith
determination that there is a reasonable possibility of obtaining
commercial quantities of oil and/or gas.
(d) Dry Hole Determination. If Operator determines at any time during
the drilling or attempted completion of any well under this
Agreement, in accordance with the generally accepted and
customary oil and gas field practices and techniques then
prevailing in the geographic area of the Well Location that the
well should not be completed, then it shall promptly and properly
plug and abandon the well.
(e) Excess Funds and Cost Overruns-Intangible Drilling Costs. Any
estimated Intangible Drilling Costs paid by Developer with
respect to any well which exceed Operator's price specified in
sub-section (a) above for the Intangible Drilling Costs of the
well shall be retained by Operator and shall be applied to:
(i) the Intangible Drilling Costs for an additional well or
wells to be drilled on the Additional Well Locations; or
(ii) any cost overruns owed by the Developer to Operator for
Intangible Drilling Costs on one or more of the other
wells on the Well Locations;
in proportion to the share of the Working Interest owned by the
Developer in the wells.
Conversely, if Operator's price specified in sub-section (a)
above for the Intangible Drilling Costs of any well exceeds the
estimated Intangible Drilling Costs paid by Developer for the
well, then:
(i) Developer shall pay the additional price to Operator
within five (5) business days after notice from Operator
that the additional amount is due and owing; or
(ii) Developer and Operator may agree to delete or reduce
Developer's Working Interest in one or more wells which
have not yet been spudded to provide funds to pay the
additional amounts to Operator. If doing so results in
any excess prepaid Intangible Drilling Costs, then these
funds shall be applied to:
(a) the Intangible Drilling Costs for an additional
well or wells to be drilled on the Additional
Well Locations; or
(b) any cost overruns owed by Developer to Operator
for Intangible Drilling Costs on one or more of
the other wells on the Well Locations;
in proportion to the share of the Working Interest owned
by the Developer in the wells.
The Exhibits to this Agreement with respect to the affected wells shall
be amended as appropriate.
(f) Excess Funds and Cost Overruns - Tangible Costs. Any estimated
Tangible Costs paid by Developer with respect to any well which
exceed Operator's price specified in sub-section (a) above for
the Tangible Costs of the well shall be retained by Operator and
shall be applied to:
6
(i) the Intangible Drilling Costs or Tangible Costs for an
additional well or wells to be drilled on the Additional
Well Locations; or
(ii) any cost overruns owed by Developer to Operator for
Intangible Drilling Costs or Tangible Costs on one or
more of the other wells on the Well Locations;
in proportion to the share of the Working Interest owned by the
Developer in the wells.
Conversely, if Operator's price specified in sub-section (a)
above for the Tangible Costs of any well exceeds the estimated
Tangible Costs paid by Developer for the well, then:
(i) Developer shall pay the additional price to Operator
within ten (10) business days after notice from Operator
that the additional price is due and owing; or
(ii) Developer and Operator may agree to delete or reduce
Developer's Working Interest in one or more wells which
have not yet been spudded to provide funds to pay the
additional price to Operator. If doing so results in any
excess prepaid Tangible Costs, then these funds shall be
applied to:
(a) the Intangible Drilling Costs or Tangible Costs
for an additional well or wells to be drilled on
the Additional Well Locations; or
(b) any cost overruns owed by Developer to Operator
for Intangible Drilling Costs or Tangible Costs
on one or more of the other wells on the Well
Locations;
in proportion to the share of the Working Interest owed
by the Developer in the wells.
The Exhibits to this Agreement with respect to the affected wells
shall be amended as appropriate.
5. Title Examination of Well Locations, Developer's Acceptance and Liability;
Additional Well Locations.
(a) Title Examination of Well Locations, Developer's Acceptance and
Liability. The Developer acknowledges that Operator has
furnished Developer with the title opinions identified on
Exhibit A, and other documents and information which Developer
or its counsel has requested in order to determine the adequacy
of the title to the Initial Well Locations and leased premises
subject to this Agreement. The Developer accepts the title to
the Initial Well Locations and leased premises and acknowledges
and agrees that, except for any loss, expense, cost, or
liability caused by the breach of any of the warranties and
representations made by the Operator in Section l(b), any loss,
expense, cost or liability whatsoever caused by or related to
any defect or failure of the title shall be the sole
responsibility of and shall be borne entirely by the Developer.
(b) Additional Well Locations. Before beginning drilling of any
well on any Additional Well Location, Operator shall conduct,
or cause to be conducted, a title examination of the Additional
Well Location, in order to obtain appropriate abstracts,
opinions and certificates and other information necessary to
determine the adequacy of title to both the applicable Lease
and the fee title of the lessor to the premises covered by the
Lease. The results of the title examination and such other
information as is necessary to determine the adequacy of title
for drilling purposes shall be submitted to the Developer for
its review and acceptance. No drilling on the Additional Well
Locations shall begin until the title has been accepted in
writing by the Developer. After any title has been accepted by
the Developer, any loss, expense, cost, or liability
whatsoever, caused by or related to any defect or failure of
the title shall be the sole responsibility of and shall be
borne entirely by the Developer, unless such loss, expense,
cost, or liability was caused by the breach of any of the
warranties and representations made by the Operator in Section
l(a).
6. Operations Subsequent to Completion of the Wells; Fee Adjustments;
Extraordinary Costs; Pipelines; Price Determinations; Plugging and
Abandonment.
(a) Operations Subsequent to Completion of the Wells. Beginning
with the month in which a well drilled under this Agreement
begins to produce, Operator shall be entitled to an operating
fee of $275 per month for
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each well being operated under this Agreement, proportionately
reduced to the extent the Developer owns less than 100% of the
Working Interest in the wells. This fee shall be in lieu of any
direct charges by Operator for its services or the provision by
Operator of its equipment for normal superintendence and
maintenance of the wells and related pipelines and facilities.
If a third-party serves as the actual operator of the well, then
this fee shall be $25 above the actual third-party operator's
monthly charges. The $25 will be retained by Operator each month
for reviewing the costs and expenses charged by the third-party
operator and monitoring the third- party operator's accounting
and production records for the well on behalf of the Developer.
The operating fees shall cover all normal, regularly recurring
operating expenses for the production, delivery and sale of
natural gas, including without limitation:
(i) well tending, routine maintenance and adjustment;
(ii) reading meters, recording production, pumping,
maintaining appropriate books and records;
(iii) preparing reports to the Developer and government
agencies; and
(iv) collecting and disbursing revenues.
The operating fees shall not cover costs and expenses related to
the following:
(i) the production and sale of oil;
(ii) the collection and disposal of salt water or other
liquids produced by the wells;
(iii) the rebuilding of access roads; and
(iv) the purchase of equipment, materials or third party
services;
which, subject to the provisions of sub-section (c) of this
Section 6, shall be paid by the Developer in proportion to the
share of the Working Interest owned by the Developer in the
wells.
Any well which is temporarily abandoned or shut-in continuously
for the entire month shall not be considered a producing well for
purposes of determining the number of wells in the month subject
to the operating fee.
(b) Fee Adjustments. The monthly operating fee set forth in sub-
section (a) above may in the following manner be adjusted
annually as of the first day of January (the "Adjustment Date")
each year beginning January l, 2005 with respect to the
partnership designated Atlas America Public #12-2003 Limited
Partnership, and January 1, 2006 with respect to partnerships
designated as Atlas America Public #12-2004(_____) Limited
Partnership. 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, 2002, in the case of
the first adjustment, and since the previous Adjustment Date,
in the case of each subsequent adjustment.
(c) Extraordinary Costs. Without the prior written consent of the
Developer, pursuant to a written estimate submitted by Operator,
Operator shall not undertake any single project or incur any
extraordinary cost with respect to any well being produced under
this Agreement reasonably estimated to result in an expenditure
of more than $5,000, unless the project or extraordinary cost is
necessary for the following:
(i) to safeguard persons or property; or
(ii) to protect the well or related facilities in the event of
a sudden emergency.
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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 shall be billed
at the invoice cost of third-party services performed or
materials purchased together with a reasonable charge by Operator
for services performed directly by it, in proportion to the share
of the Working Interest owned by the Developer in the wells.
Operator shall have the right to require the Developer to pay in
advance of undertaking any project all or a portion of the
estimated costs of the project in proportion to the share of the
Working Interest owned by the Developer in the wells.
(d) Pipelines. Developer shall have no interest in the pipeline
gathering system, which gathering system shall remain the sole
property of Operator or its Affiliates and shall be maintained at
their sole cost and expense.
(e) Price Determinations. Notwithstanding anything herein to the
contrary, the Developer shall 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. This responsibility shall include, without
limitation, preparing, filing, and executing all applications,
affidavits, interim collection notices, reports and other
documents necessary or appropriate to obtain price
certification, to effect sales of natural gas, or otherwise to
comply with the Act and the implementing state regulations.
Operator agrees to furnish the information and render the
assistance as the Developer may reasonably request in order to
comply with the Act and the implementing state regulations
without charge for services performed by its employees.
(f) Plugging and Abandonment. The Developer shall have the right to
direct Operator to plug and abandon any well that has been
completed under this Agreement as a producer. In addition,
Operator shall not plug and abandon any well that has been
drilled and completed as a producer before obtaining the
written consent of the Developer. However, if the Operator in
accordance with the generally accepted and customary oil and
gas field practices and techniques then prevailing in the
geographic area of the well location, determines that any well
should be plugged and abandoned and makes a written request to
the Developer for authority to plug and abandon the well and
the Developer fails to respond in writing to the request within
forty-five (45) days following the date of the request, then
the Developer shall be deemed to have consented to the plugging
and abandonment of the well.
All costs and expenses related to plugging and abandoning the
wells which have been drilled and completed as producing wells
shall be borne and paid by the Developer in proportion to the
share of the Working Interest owned by the Developer in the
wells. Also, at any time after one (1) year from the date each
well drilled and completed is placed into production, Operator
shall have the right to deduct each month from the proceeds of
the sale of the production from the well up to $200, in
proportion to the share of the Working Interest owned by the
Developer in the wells, for the purpose of establishing a fund to
cover the estimated costs of plugging and abandoning the well.
All these funds shall be deposited in a separate interest bearing
escrow account for the account of the Developer, and the total
amount so retained and deposited shall not exceed Operator's
reasonable estimate of the costs.
7. Billing and Payment Procedure with Respect to Operation of Wells;
Disbursements; Separate Account for Sale Proceeds; Records and Reports;
Additional Information.
(a) Billing and Payment Procedure with Respect to Operation of Wells.
Operator shall promptly and timely pay and discharge on behalf of
the Developer, in proportion to the share of the Working Interest
owned by the Developer in the wells the following:
(i) all expenses and liabilities payable and incurred by
reason of its operation of the wells in accordance with
this Agreement , such as severance taxes, royalties,
overriding royalties, operating fees, and pipeline
gathering charges; and
9
(ii) any third-party invoices rendered to Operator with
respect to costs and expenses incurred in connection with
the operation of the wells.
Operator, however, shall not be required to pay and discharge any
of the above costs and expenses which are being contested in good
faith by Operator.
Operator shall:
(i) deduct the foregoing costs and expenses from the
Developer's share of the proceeds of the oil and/or gas
sold from the wells; and
(ii) keep an accurate record of the Developer's account,
showing expenses incurred and charges and credits made
and received with respect to each well.
If the proceeds are insufficient to pay the costs and expenses,
then Operator shall promptly and timely pay and discharge the
costs and expenses, in proportion to the share of the Working
Interest owned by the Developer in the wells, and prepare and
submit an invoice to the Developer each month for the costs and
expenses. The invoice shall be accompanied by the form of
statement specified in sub-section (b) below, and shall be paid
by the Developer within ten (10) business days of its receipt.
(b) Disbursements. Operator shall disburse to the Developer, on a
monthly basis, the Developer's share of the proceeds received
from the sale of oil and/or gas sold from the wells operated
under this Agreement, less:
(i) the amounts charged to the Developer under sub-section
(a); and
(ii) the amount, if any, withheld by Operator for future
plugging costs pursuant to sub-section (f) of Section 6.
Each disbursement made and/or invoice submitted pursuant to
sub-section (a) above shall be accompanied by a statement
itemizing with respect to each well:
(i) the total production of oil and/or gas since the date of
the last disbursement or invoice billing period, as the
case may be, and the Developer's share of the production;
(ii) the total proceeds received from any sale of the
production, and the Developer's share of the proceeds;
(iii) the costs and expenses deducted from the proceeds and/or
being billed to the Developer pursuant to sub-section (a)
above;
(iv) the amount withheld for future plugging costs; and
(v) any other information as Developer may reasonably
request, including without limitation copies of all
third-party invoices listed on the statement for the
period.
(c) Separate Account for Sale Proceeds. Operator agrees to deposit
all proceeds from the sale of oil and/or gas sold from the wells
operated under this Agreement in a separate checking account
maintained by Operator. This account shall be used solely for
the purpose of collecting and disbursing funds constituting
proceeds from the sale of production under this Agreement.
(d) Records and Reports. In addition to the statements required under
sub-section (b) above, Operator, within seventy-five (75) days
after the completion of each well drilled, shall furnish the
Developer with a detailed statement itemizing with respect to the
well the total costs and charges under Section 4(a) and the
Developer's share of the costs and charges, and any information
as is necessary to enable the Developer:
(i) to allocate any extra costs incurred with respect to the
well between Tangible Costs and Intangible Drilling
Costs; and
(ii) to determine the amount of investment tax credit, if
applicable.
10
(e) Additional Information. On request, Operator shall promptly
furnish the Developer with any additional information as it may
reasonably request, including without limitation geological,
technical, and financial information, in the form as may
reasonably be requested, pertaining to any phase of the
operations and activities governed by this Agreement. The
Developer and its authorized employees, agents and consultants,
including independent accountants shall, at Developer's sole
cost and expense:
(i) on at least ten (10) days' written notice have access
during normal business hours to all of Operator's records
pertaining to operations, including without limitation,
the right to audit the books of account of Operator
relating to all receipts, costs, charges, expenses and
disbursements under this Agreement (including
information regarding the separate account required
under sub-section (c)); and
(ii) have access, at its sole risk, to any wells drilled by
Operator under this Agreement at all times to inspect and
observe any machinery, equipment and operations.
8. Operator's Lien; Right to Collect From Gas Purchaser.
(a) Operator's Lien. To secure the payment of all sums due from
Developer to Operator under the provisions of this Agreement the
Developer grants Operator a first and preferred lien on and
security interest in the following:
(i) the Developer's interest in the Leases covered by this
Agreement;
(ii) the Developer's interest in oil and gas produced under
this Agreement and its proceeds from the sale of the oil
and gas; and
(iii) the Developer's interest in materials and equipment under
this Agreement.
(b) Right to Collect From Gas Purchaser. If the Developer fails to
timely pay any amount owing under this Agreement by it to the
Operator, then Operator, without prejudice to other existing
remedies, may collect and retain from any purchaser or
purchasers of oil or gas the Developer's share of the proceeds
from the sale of the oil and gas until the amount owed by the
Developer, plus twelve percent (12%) interest on a per annum
basis, and any additional costs (including without limitation
actual attorneys' fees and costs) resulting from the
delinquency, has been paid. Each purchaser of oil or gas shall
be entitled to rely on Operator's written statement concerning
the amount of any default.
9. Successors and Assigns; Transfers; Appointment of Agent.
(a) Successors and Assigns. This Agreement shall be binding on and
inure to the benefit of the undersigned parties and their
respective successors and permitted assigns. However, without
the prior written consent of the Developer, the Operator may
not assign, transfer, pledge, mortgage, hypothecate, sell or
otherwise dispose of any of its interest in this Agreement, or
any of the rights or obligations under this Agreement.
Notwithstanding, this consent shall not be required in
connection with:
(i) the assignment of work to be performed for Operator by
subcontractors, it being understood and agreed, however,
that any assignment to Operator's subcontractors shall
not in any manner relieve or release Operator from any of
its obligations and responsibilities under this
Agreement;
(ii) any lien, assignment, security interest, pledge or
mortgage arising under Operator's present or future
financing arrangements; or
(iii) the liquidation, merger, consolidation, or other
corporate reorganization or sale of substantially all of
the assets of Operator.
Further, in order to maintain uniformity of ownership in the
wells, production, equipment, and leasehold interests covered by
this Agreement, and notwithstanding any other provisions to the
contrary, the Developer shall not, without the prior written
consent of Operator, sell, assign, transfer, encumber, mortgage
or
11
otherwise dispose of any of its interest in the wells,
production, equipment or leasehold interests covered by this
Agreement unless the disposition encompasses either:
(i) the entire interest of the Developer in all wells,
production, equipment and leasehold interests subject to
this Agreement; or
(ii) an equal undivided interest in all such wells,
production, equipment, and leasehold interests.
(b) Transfers. Subject to the provisions of sub-section (a) above,
any sale, encumbrance, transfer or other disposition made by the
Developer of its interests in the wells, production, equipment,
and/or leasehold interests covered by this Agreement shall be
made:
(i) expressly subject to this Agreement;
(ii) without prejudice to the rights of the Operator; and
(iii) in accordance with and subject to the provisions of the
Lease.
(c) Appointment of Agent. If at any time the interest of the
Developer is divided among or owned by co-owners, Operator may,
at its discretion, require the co-owners to appoint a single
trustee or agent with full authority to do the following:
(i) receive notices, reports and distributions of the
proceeds from production;
(ii) approve expenditures;
(iii) receive billings for and approve and pay all costs,
expenses and liabilities incurred under this Agreement;
(iv) exercise any rights granted to the co-owners under this
Agreement;
(v) grant any approvals or authorizations required or
contemplated by this Agreement;
(vi) sign, execute, certify, acknowledge, file and/or record
any agreements, contracts, instruments, reports, or
documents whatsoever in connection with this Agreement or
the activities contemplated by this Agreement; and
(vii) deal generally with, and with power to bind, the co-
owners with respect to all activities and operations
contemplated by this Agreement.
However, all the co-owners shall continue to have the right to
enter into and execute all contracts or agreements for their
respective shares of the oil and gas produced from the wells
drilled under this Agreement in accordance with sub-section (c)
of Section 11.
10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability.
(a) Operator's Insurance. Operator shall obtain and maintain at its
own expense so long as it is Operator under this Agreement all
required Workmen's Compensation Insurance and comprehensive
general public liability insurance in amounts and coverage not
less than $1,000,000 per person per occurrence for personal
injury or death and $1,000,000 for property damage per
occurrence, which shall include coverage for blow-outs and
total liability coverage of not less than $10,000,000.
Subject to the above limits, the Operator's general public
liability insurance shall be in all respects comparable to that
generally maintained in the industry with respect to services of
the type to be rendered and activities of the type to be
conducted under this Agreement. Operator's general public
liability insurance shall, if permitted by Operator's insurance
carrier:
12
(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 of the Operator's
insurance coverage shall be delivered to the Developer on
request. It is understood and agreed that Operator's insurance
coverage may not adequately protect the interests of the
Developer and that the Developer shall carry at its expense the
excess or additional general public liability, property damage,
and other insurance, if any, as the Developer deems appropriate.
(b) Subcontractors' Insurance. Operator shall require all of its
subcontractors to carry all required Workmen's Compensation
Insurance and to maintain such other insurance, if any, as
Operator in its discretion may require.
(c) Operator's Liability. Operator's liability to the Developer as
Operator under this Agreement shall be limited to, and Operator
shall indemnify the Developer and hold it harmless from, claims,
penalties, liabilities, obligations, charges, losses, costs,
damages, or expenses (including but not limited to reasonable
attorneys' fees) relating to, caused by or arising out of:
(i) the noncompliance with or violation by Operator, its
employees, agents, or subcontractors of any local, state
or federal law, statute, regulation, or ordinance;
(ii) the negligence or misconduct of Operator, its employees,
agents or subcontractors; or
(iii) the breach of or failure to comply with any provisions of
this Agreement.
11. Internal Revenue Code Election; Relationship of Parties; Right to Take
Production in Kind.
(a) Internal Revenue Code Election. With respect to this Agreement,
each of the parties elects under Section 761(a) of the Internal
Revenue Code of 1986, as amended, to be excluded from the
provisions of Subchapter K of Chapter 1 of 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 by
this Agreement is located contain, or may subsequently contain,
a similar election, each of the parties agrees that the
election shall be exercised.
Beginning with the first taxable year of operations under this
Agreement, each party agrees that the deemed election provided by
Section 1.761-2(b)(2)(ii) of the Regulations under the Internal
Revenue Code of 1986, as amended, will apply; and no party will
file an application under Section 1.761-2 (b)(3)(i) and (ii) of
the Regulations to revoke the election. Each party agrees to
execute the documents and make the filings with the appropriate
governmental authorities as may be necessary to effect the
election.
(b) Relationship of Parties. It is not the intention of the parties
to create, nor shall this Agreement be construed as creating, a
mining or other partnership or association or to render the
parties liable as partners or joint venturers for any purpose.
Operator shall be deemed to be an independent contractor and
shall perform its obligations as set forth in this Agreement or
as otherwise directed by the Developer.
(c) Right to Take Production in Kind. Subject to the provisions of
Section 8 above, the Developer shall have the exclusive right to
sell or dispose of its proportionate share of all oil and gas
produced from the wells to be drilled under this Agreement,
exclusive of production:
(i) that may be used in development and producing operations;
(ii) unavoidably lost; and
13
(iii) used to fulfill any free gas obligations under the terms
of the applicable Lease or Leases.
Operator shall not have any right to sell or otherwise dispose of
the oil and gas. The Developer shall have the exclusive right to
execute all contracts relating to the sale or disposition of its
proportionate share of the production from the wells drilled
under this Agreement.
Developer shall have no interest in any gas supply agreements of
Operator, except the right to receive Developer's share of the
proceeds received from the sale of any gas or oil from wells
developed under this Agreement. The Developer agrees to designate
Operator or Operator's designated bank agent as the Developer's
collection agent in any contracts. On request, Operator shall
assist Developer in arranging the sale or disposition of
Developer's oil and gas under this Agreement and shall promptly
provide the Developer with all relevant information which comes
to Operator's attention regarding opportunities for sale of
production.
If Developer fails to take in kind or separately dispose of its
proportionate share of the oil and gas produced under this
Agreement, then Operator shall have the right, subject to the
revocation at will by the Developer, but not the obligation, to
purchase the oil and gas or sell it to others at any time and
from time to time, for the account of the Developer at the best
price obtainable in the area for the production. Notwithstanding,
Operator shall have no liability to Developer should Operator
fail to market the production.
Any purchase or sale by Operator shall be subject always to the
right of the Developer to exercise at any time its right to take
in-kind, or separately dispose of, its share of oil and gas not
previously delivered to a purchaser. Any purchase or sale by
Operator of any other party's share of oil and gas shall be only
for reasonable periods of time as are consistent with the minimum
needs of the oil and gas industry under the particular
circumstances, but in no event for a period in excess of one (1)
year.
12. Effect of Force Majeure; Definition of Force Majeure; Limitation.
(a) Effect of Force Majeure. If Operator is rendered unable, wholly
or in part, by force majeure (as defined below) to carry out
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. After the
notice is given, the obligations of the Operator, so far as it
is affected by the force majeure, shall be suspended during but
no longer than, the continuance of the force majeure. Operator
shall use all reasonable diligence to remove the force majeure
as quickly as possible to the extent the same is within
reasonable control.
(b) Definition of Force Majeure. The term "force majeure" shall
mean an act of God, strike, lockout, or other industrial
disturbance, act of the public enemy, war, blockade, public
riot, lightning, fire, storm, flood, explosion, governmental
restraint, unavailability of equipment or materials, plant
shut-downs, curtailments by purchasers and any other causes
whether of the kind specifically enumerated above or otherwise,
which directly precludes Operator's performance under this
Agreement and is not reasonably within the control of the
Operator.
(c) Limitation. The requirement that any force majeure shall be
remedied with all reasonable dispatch shall not require the
settlement of strikes, lockouts, or other labor difficulty
affecting the Operator, contrary to its wishes. The method of
handling these difficulties shall be entirely within the
discretion of the Operator.
13. Term.
This Agreement shall become effective when executed by Operator
and the Developer. Except as provided in sub-section (c) of
Section 3, this Agreement shall continue and remain in full force
and effect for the productive lives of the wells being operated
under this Agreement.
14. Governing Law; Invalidity.
(a) Governing Law. This Agreement shall be governed by, construed and
interpreted in accordance with the laws of the Commonwealth of
Pennsylvania.
14
(b) Invalidity. The invalidity or unenforceability of any particular
provision of this Agreement shall not affect the other provisions
of this Agreement, and this Agreement shall be construed in all
respects as if the invalid or unenforceable provision were
omitted.
15. Integration; Written Amendment.
(a) Integration. This Agreement, including the Exhibits to this
Agreement, constitutes and represents the entire understanding
and agreement of the parties with respect to the subject matter
of this Agreement and supersedes all prior negotiations,
understandings, agreements, and representations relating to the
subject matter of this Agreement.
(b) Written Amendment. No change, waiver, modification, or amendment
of this Agreement shall be binding or of any effect unless in
writing duly signed by the party against which the change,
waiver, modification, or amendment is sought to be enforced.
16. Waiver of Default or Breach.
No waiver by any party to any default of or breach by any other
party under this Agreement shall operate as a waiver of any
future default or breach, whether of like or different character
or nature.
17. Notices.
Unless otherwise provided in this Agreement, all notices, statements,
requests, or demands which are required or contemplated by this
Agreement shall be in writing and shall be hand-delivered or sent by
registered or certified mail, postage prepaid, to the following
addresses until changed by certified or registered letter so addressed
to the other party:
(i) If to the Operator, to:
Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
Attention: President
(ii) If to Developer, to:
Atlas America Public #12-2003 Limited Partnership
[Atlas America Public #12-2004(____) Limited Partnership]
c/o Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
Notices which are served by registered or certified mail on the parties
in the manner provided in this Section shall be deemed sufficiently
served or given for all purposes under this Agreement at the time the
notice is mailed in any post office or branch post office regularly
maintained by the United States Postal Service or any successor. All
payments shall be hand-delivered or sent by United States mail, postage
prepaid to the addresses set forth above until changed by certified or
registered letter so addressed to the other party.
18. Interpretation.
The titles of the Sections in this Agreement are for convenience of
reference only and shall not control or affect the meaning or
construction of any of the terms and provisions of this Agreement. As
used in this Agreement, the plural shall include the singular and the
singular shall include the plural whenever appropriate.
19. Counterparts.
The parties may execute this Agreement in any number of separate
counterparts, each of which, when executed and delivered by the parties,
shall have the force and effect of an original; but all such
counterparts shall be deemed to constitute one and the same instrument.
15
IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as
of the day and year first above written.
ATLAS RESOURCES, INC.
By: ------------------------------------------------------
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
ATLAS AMERICA PUBLIC #12-2004(____) LIMITED PARTNERSHIP
By its Managing General Partner:
ATLAS RESOURCES, INC.
By: ------------------------------------------------------
16
DESCRIPTION OF LEASES AND INITIAL WELL LOCATIONS
[To be completed as information becomes available]
1. WELL LOCATION
(a) Oil and Gas Lease from ________________________________ dated
_____________________ and recorded in Deed Book Volume
__________, Page __________ in the Recorder's Office of County,
____________, covering approximately _________ acres in
____________________________ Township, ___________________
County, __________________________.
(b) The portion of the leasehold estate constituting the
____________________________________________ No. __________ Well
Location is described on the map attached hereto as Exhibit A-l.
(c) Title Opinion of ______________________________,
_______________________________________________,
_______________________________________________,
________________________________________, dated
___________________, 200___.
(d) The Developer's interest in the leasehold estate constituting
this Well Location is an undivided % Working Interest to those
oil and gas rights from the surface to the bottom of the
__________________ Formation, subject to the landowner's royalty
interest and overriding royalty interests.
Exhibit A
Well Name, Twp.
County, State
ASSIGNMENT OF OIL AND GAS LEASE
STATE OF _______________________________
COUNTY OF _____________________________
KNOW ALL MEN BY THESE PRESENTS:
THAT the undersigned _______________________________ (hereinafter called
"Assignor"), for and in consideration of One Dollar and other valuable
consideration ($1.00 ovc), the receipt whereof is hereby acknowledged, does
hereby sell, assign, transfer and set over unto _______________________________
_______________________________(hereinafter called "Assignee"), an undivided
_____________________________ in, and to, the oil and gas lease described as
follows:
together with the rights incident thereto and the personal property thereto,
appurtenant thereto, or used, or obtained, in connection therewith.
And for the same consideration, the assignor covenants with the said
assignee his or its heirs, successors, or assigns that assignor is the lawful
owner of said lease and rights and interest thereunder and of the personal
property thereon or used in connection therewith; that the undersigned has good
right and authority to sell and convey the same, and that said rights, interest
and property are free and clear from all liens and encumbrances, and that all
rentals and royalties due and payable thereunder have been duly paid.
In Witness Whereof, the undersigned owner ______ and assignor ______ ha___
signed and sealed this instrument the ______ day of _______________, 200___.
Signed and acknowledged in the ------------------------------------------
presence of
- ---------------------------------- ------------------------------------------
- ---------------------------------- ------------------------------------------
Exhibit B
(Page 1)
ACKNOWLEDGMENT BY INDIVIDUAL
STATE OF _________________________
BEFORE ME, a Notary Public, in and for said
COUNTY OF ______________________
County and State, on this day personally appeared _ who
acknowledged to me that ____ he ____ did sign the foregoing instrument and
that the same is _____________ free act and deed.
In testimony whereof, I have hereunto set my hand and official seal, at
_____________________________, this ______ day of _______________, A.D.,
200___.
--------------------------------------
Notary Public
CORPORATION ACKNOWLEDGMENT
STATE OF _________________________
BEFORE ME, a Notary Public, in and for said
COUNTY OF _______________________
County and State, on this day personally appeared _ known to me to be the
person and officer whose name is subscribed to the foregoing instrument and
acknowledged that the same was the act of the said
______________________________________________, a corporation, and that he
executed the same as the act of such corporation for the purposes and
consideration therein expressed, and in the capacity therein stated.
In testimony whereof, I have hereunto set my hand and official seal, at
_____________________________, this ______ day of _______________, A.D., 200___.
--------------------------------------
Notary Public
This instrument prepared by:
Atlas Resources, Inc.
311 Rouser Road
P.O. Box 611
Moon Township, PA 15108
Exhibit B
(Page 2)
ADDENDUM NO. __________
TO DRILLING AND OPERATING AGREEMENT
DATED ___________________ , 2003
THIS ADDENDUM NO. __________ made and entered into this ______ day of
________________, 2003, by and between ATLAS RESOURCES, INC., a Pennsylvania
corporation (hereinafter referred to as "Operator"),
and
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP [ATLAS AMERICA PUBLIC
#12-2004(____) LIMITED PARTNERSHIP], a Delaware limited partnership,
(hereinafter referred to as the Developer).
WITNESSETH THAT:
WHEREAS, Operator and the Developer have entered into a Drilling and Operating
Agreement dated ___________________, 2003, (the "Agreement"), which relates to
the drilling and operating of ________________ (______)wells on the
________________ (______) Initial Well Locations identified on the maps attached
as Exhibits A-l through A-______ to the Agreement, and provides for the
development on the terms and conditions set forth in the Agreement of Additional
Well Locations as the parties may from time to time designate; and
WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer
presently desire to designate ________________ Additional Well Locations
described below to be developed in accordance with the terms and conditions of
the Agreement.
NOW, THEREFORE, in consideration of the mutual covenants contained in this
Addendum and intending to be legally bound, the parties agree as follows:
1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes
Operator to drill, complete (or plug) and operate, on the terms and conditions
set forth in the Agreement and this Addendum No.__________, ________________
additional wells on the ________________ Additional Well Locations described on
Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits
A-______ through A-______.
2. Operator, as Developer's independent contractor, agrees to drill, complete
(or plug) and operate the additional wells on the Additional Well Locations in
accordance with the terms and conditions of the Agreement and further agrees to
use its best efforts to begin drilling the first additional well within thirty
(30) days after the date of this Addendum and to begin drilling all the
additional wells on or before March 31, 2004.
3. Developer acknowledges that:
(a) Operator has furnished Developer with the title opinions
identified on Exhibit A to this Addendum; and
(b) such other documents and information which Developer or its
counsel has requested in order to determine the adequacy of the
title to the above Additional Well Locations.
The Developer accepts the title to the Additional Well Locations and leased
premises in accordance with the provisions of Section 5 of the Agreement.
4. The drilling and operation of the additional wells on the Additional Well
Locations shall be in accordance with and subject to the terms and conditions
set forth in the Agreement as supplemented by this Addendum No. __________ and
except as previously supplemented, all terms and conditions of the Agreement
shall remain in full force and effect as originally written.
5. This Addendum No. __________ shall be legally binding on, and shall inure to
the benefit of, the parties and their respective successors and permitted
assigns.
Exhibit C
(Page 1)
WITNESS the due execution of this Addendum on the day and year first above
written.
ATLAS RESOURCES, INC.
By _________________________________________
ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
[ATLAS AMERICA PUBLIC #12-2004(____) LIMITED PARTNERSHIP]
By its Managing General Partner:
ATLAS RESOURCES, INC.
By _________________________________________
Exhibit C
(Page 2)
EXHIBIT (B)
SPECIAL SUITABILITY REQUIREMENTS
AND DISCLOSURES TO INVESTORS
SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS
If you are a resident of one of the following states, then you must meet that
state's qualification and suitability standards as follows:
Special Suitability for Subscribers to Limited Partner Units In
California, Michigan, North Carolina, New Hampshire, Ohio, and Pennsylvania.
I. If you are a resident of California and you purchase limited partners units,
then you must:
o have a net worth of not less than $250,000, exclusive of home,
home furnishings and automobiles, and expect to have gross income
in the current year of $65,000 or more; or
o have a net worth of not less than $500,000, exclusive of home,
home furnishings and automobiles; or
o have a net worth of not less than $1 million; or
o expect to have gross income in the current tax year of not less
than $200,000.
II. If you are a resident of:
o Michigan; or
o North Carolina;
and you purchase limited partner units, then you must:
o have a net worth of not less than $225,000, exclusive of home,
home furnishings and automobiles; or
o have a net worth of not less than $60,000, exclusive of home,
home furnishings and automobiles, and estimated current year
taxable income as defined in Section 63 of the Internal Revenue
Code of $60,000 or more without regard to an investment in the
partnership.
III.In addition, if you are a resident of:
o Michigan;
o Ohio; or
o Pennsylvania;
then you must not make an investment in the partnership in excess of 10% of your
net worth, exclusive of home, home furnishings and automobiles.
IV. If you are a resident of New Hampshire and you purchase limited partner
units, then you must have:
o a net worth, exclusive of home, home furnishings, and
automobiles of $250,000, or
o a net worth, exclusive of home, home furnishings, and
automobiles of $125,000, and $50,000 of taxable income.
Special Suitability for Subscribers to Investor General Partner Units.
I. If you are a resident of California and you purchase investor general partner
units, then you must:
o have a net worth of not less than $250,000, exclusive of home,
home furnishings and automobiles, and expect
1
to have annual gross income in the current year of
$120,000 or more; or
o have a net worth of not less than $500,000, exclusive of home,
home furnishings and automobiles; or
o have a net worth of not less than $1 million; or
o expect to have gross income in the current year of not less
than $200,000.
II. If you are a resident of:
o Alabama; o North Carolina; o Tennessee;
o Maine; o Ohio; o Texas; or
o Massachusetts; o Oklahoma; o Washington.
o Minnesota; o Pennsylvania;
and you purchase investor general partner units, then you must:
o 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
o have an individual or joint net worth with your spouse in excess
of $1 million, inclusive of home, home furnishings and
automobiles; or
o have an individual or joint net worth with your spouse in excess
of $500,000, exclusive of home, home furnishings and automobiles;
or
o 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.
III.If you are a resident of:
o Arizona; o Kentucky; o New Mexico;
o Indiana; o Michigan; o Oregon;
o Iowa; o Mississippi; o South Dakota; or
o Kansas; o Missouri; o Vermont;
and you purchase investor general partner units, then you must:
o 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
o have an individual or joint net worth with your spouse in excess
of $1 million, inclusive of home, home furnishings and
automobiles; or
o have an individual or joint net worth with your spouse in excess
of $500,000, exclusive of home, home furnishings and automobiles;
or
o 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.
IV. If you are a resident of New Hampshire and you purchase investor general
partner units, then you must:
2
o have a net worth, exclusive of home, home furnishings, and
automobiles of $250,000, or
o have a net worth, exclusive of home, home furnishings, and
automobiles of $125,000, and $50,000 of taxable income.
V. In addition, if you are a resident of:
o Iowa; o Ohio; or
o Michigan; o Pennsylvania;
then you must not make an investment in the partnership in excess of 10% of your
net worth, exclusive of home, furnishings and automobiles.
Special Representations For Subscribers of
California, Missouri, North Carolina and Pennsylvania.
I. 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)).
II. If a resident of California, I am aware that:
IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY,
OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION
THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER
OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED
IN THE COMMISSIONER'S RULES.
As a condition of qualification of the units for sale in the State of
California, the following rule is hereby delivered to each California purchaser.
California Administrative Code, Title 10, Ch. 3, Rule 260.141.11. Restriction
on transfer.
(a) The issuer of any security upon which a restriction on transfer
has been imposed pursuant to Sections 260.102.6, 260.141.10 and
260.534 shall cause a copy of this section to be delivered to
each issuee or transferee of such security at the time the
certificate evidencing the security is delivered to the issuee or
transferee.
(b) It is unlawful for the holder of any such security to consummate
a sale or transfer of such security, or any interest therein,
without the prior written consent of the Commissioner (until this
condition is removed pursuant to Section 260.141.12 of these
rules), except:
(i) to the issuer;
(ii) pursuant to the order or process of any court;
(iii) to any person described in Subdivision (i) of Section
25102 of the Code or Section 260.105.14 of these rules;
(iv) to the transferor's ancestors, descendants or spouse, or
any custodian or trustee for the account of the
transferor's ancestors, descendants or spouse, or to a
transferee by a trustee or custodian for the account of
the transferee or the transferee's ancestors, descendants
or spouse;
(v) to holders of securities of the same class of the same
issuer;
3
(vi) by way of gift or donation inter vivos or on death;
(vii) by or through a broker-dealer licensed under the Code
(either acting as such or as a finder) to a resident of
a foreign state, territory or country who is neither
domiciled in this state to the knowledge of the broker-
dealer, nor actually present in this state if the sale
of such securities is not in violation of any securities
law of the foreign state, territory or country
concerned;
(viii) to a broker-dealer licensed under the Code in a principal
transaction, or as an underwriter or member of an
underwriting syndicate or selling group;
(ix) if the interest sold or transferred is a pledge or other
lien given by the purchaser to the seller upon a sale of
the security for which the Commissioner's written consent
is obtained or under this rule not required;
(x) by way of a sale qualified under Sections 25111, 25112,
25113 or 25121 of the Code, of the securities to be
transferred, provided that no order under Section 25140
or Subdivision (a) of Section 25143 is in effect with
respect to such qualification;
(xi) by a corporation or wholly-owned subsidiary of such
corporation, or by a wholly-owned subsidiary of a
corporation to such corporation;
(xii) by way of an exchange qualified under Sections 25111,
25112 or 25113 of the Code, provided that no order under
Section 25140 or Subdivision (a) of Section 25143 is in
effect with respect to such qualification;
(xiii) between residents of foreign states, territories or
countries who are neither domiciled nor actually present
in this state;
(xiv) to the State Controller pursuant to the Unclaimed
Property Law or to the administrator of the unclaimed
property law of another state;
(xv) by the State Controller pursuant to the Unclaimed
Property Law or by the administrator of the unclaimed
property law of another state if, in either such case,
such person (i) discloses to potential purchasers at the
sale that transfer of the securities is restricted under
this rule, (ii) delivers to each purchaser a copy of
this rule, and (iii) advises the Commissioner of the
name of each purchaser;
(xvi) by a trustee to a successor trustee when such transfer
does not involve a change in the beneficial ownership of
the securities;
(xvii) by way of an offer and sale of outstanding securities in
an issuer transaction that is subject to the
qualification requirement of Section 25110 of the Code
but exempt from that qualification requirement by
subdivision (f) of Section 25102;
provided that any such transfer is on the condition that any
certificate evidencing the security issued to such transferee
shall contain the legend required by this section.
(c) The certificates representing all such securities subject to such
a restriction on transfer, whether upon initial issuance or upon
any transfer thereof, shall bear on their face a legend,
prominently stamped or printed thereon in capital letters of not
less than 10-point size, reading as follows:
"IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS
SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY
CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE
COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT
AS PERMITTED IN THE COMMISSIONER'S RULES."
III.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
4
ADEQUACY OF THIS DOCUMENT. ANY REPRESENTATION TO
THE CONTRARY IS A CRIMINAL OFFENSE.
IV. PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than 10%
of the maximum closing amount allowed to a partnership in this offering, you are
cautioned to carefully evaluate the partnership's ability to fully accomplish
its stated objectives and inquire as to the current dollar volume of partnership
subscriptions.
5
TABLE OF CONTENTS
Page
Summary of the Offering ....................................... 1
Risk Factors .................................................. 8
Additional Information ........................................ 16
Forward Looking Statements and Associated Risks ............... 16
Investment Objectives ......................................... 17
Actions to be Taken by Managing General Partner to Reduce
Risks of Additional Payments by Investor General Partners.... 18
Capitalization and Source of Funds and Use of Proceeds ........ 20
Compensation .................................................. 24
Terms of the Offering ......................................... 30
Prior Activities .............................................. 37
Management .................................................... 44
Management's Discussion and Analysis of Financial Condition,
Results of Operations, Liquidity and Capital Resources....... 50
Proposed Activities ........................................... 52
Competition, Markets and Regulation ........................... 66
Participation in Costs and Revenues ........................... 69
Conflicts of Interest ......................................... 75
Fiduciary Responsibility of the Managing
General Partner ............................................... 86
Tax Aspects ................................................... 88
Summary of Partnership Agreement .............................. 103
Summary of Drilling and Operating Agreement ................... 105
Reports to Investors .......................................... 106
Presentment Feature ........................................... 107
Transferability of Units ...................................... 109
Plan of Distribution .......................................... 110
Sales Material ................................................ 112
Legal Opinions ................................................ 113
Experts ....................................................... 113
Litigation .................................................... 113
Financial Information Concerning the Managing General Partner . 113
EXHIBIT (A) - Form of Partnership Agreement of Atlas America Public #12-2003
Limited Partnership and Atlas America Public #12-2004(_) Limited Partnership
EXHIBIT (I-A) - Form of Managing General Partner Signature Page
EXHIBIT (I-B) - Form of Subscription Agreement
EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas America
Public #12-2003 Limited Partnership and Atlas America Public #12-2004(_)
Limited Partnership
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 #12-2003 PROGRAM
----------
PROSPECTUS
----------
Until December 31, 2004, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealers' obligation to deliver
a prospectus when acting as underwriters and with respect to their unsold
allotments or subscriptions.
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. Other Expenses of Issuance and Distribution.
The expenses to be incurred in connection with the issuance and distribution of
the securities to be registered, other than underwriting discounts, commissions
and expense allowances, are estimated to be as follows:
Accounting Fees and Expenses ....................................... $ 75,000*
-----------
Legal Fees (including Blue Sky) and Expenses ....................... 100,000*
Printing ........................................................... 300,000*
-----------
SEC Registration Fee ............................................... 6,900
Blue Sky Filing Fees (excluding legal fees) ........................ 160,000*
NASD Filing Fee .................................................... 8,000
Miscellaneous ...................................................... 2,161,000*
-----------
Total ....................................................... $2,810,900*
===========
- ---------------
* Estimated
Item 14. Indemnification of Directors and Officers.
Section 17-108 of the Delaware 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:
o they determined in good faith that the course of conduct which
caused the loss or liability was in the best interest of the
Partnership;
o they were acting on behalf of or performing services for the
Partnership; and
o the course of conduct was not the result of their negligence or
misconduct.
Paragraph 11 of the Dealer-Manager Agreement provides for the indemnification of
the Managing General Partner, the Partnership and control persons under
specified conditions by the Dealer-Manager and/or Selling Agent.
Item 15. Recent Sales of Unregistered Securities.
None by the Registrant.
Atlas Resources, Inc. ("Atlas"), an Affiliate of the Registrant, has made sales
of unregistered and registered securities within the last three years. See the
section of the Prospectus captioned "Prior Activities" regarding the sale of
limited and general partner interests. In the opinion of Atlas, the foregoing
unregistered securities in each case have been and/or are being offered and sold
in compliance with exemptions from registration provided by the Securities Act
of 1933, as amended, including the exemptions provided by Section 4(2) of that
Act and certain rules and regulations promulgated thereunder. The securities in
each case have been and/or are being offered and sold to a limited number of
persons who had the sophistication to understand the merits and risks of the
investment and who had the financial ability to bear such risks. The units of
limited and general partner interests were sold to persons who were Accredited
Investors, as that term is defined in Regulation D (17 CFR 230.501(a)), or who
had, at the time of purchase, a net worth of at least $225,000 (exclusive of
home, furnishings and automobiles) or a net worth (exclusive of home,
furnishings and automobiles) of at least $125,000 and gross income of at least
$75,000, or otherwise satisfied Atlas that the investment was suitable.
1
Item 16. Exhibits and Financial Statement Schedules.
(a) Exhibits
1(a) Proposed form of Dealer-Manager Agreement with Anthem
Securities, Inc.
1(b) Proposed form of Dealer-Manager Agreement with Bryan
Funding, Inc.
3(a) Articles of Incorporation of Atlas Resources, Inc.
3(b) Bylaws of Atlas Resources, Inc.
4(a) Agreement of Limited Partnership for Atlas America Public
#12-2003 and Atlas America Public #12-2004(_) (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)
23(a) Consent of Grant Thornton, L.L.P.
23(b) Consent of United Energy Development Consultants, Inc.
23(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and
8)
23(d) Consent of Wright & Company, Inc.
24 Power of Attorney
---------------
(b) Financial Statement Schedules
All financial statement schedules are omitted because the information is not
required, is not material or is otherwise included in the financial statements
or related notes thereto.
Item 17. Undertakings.
(a) The undersigned Registrant hereby undertakes:
(1) To file, during any period in which offers or sales are
being made, a post-effective amendment to this
Registration Statement:
(i) To include any Prospectus required by Section
10(a)(3) of the Securities Act of 1933.
(ii) To reflect in the Prospectus any facts or events
arising after the effective date of the
Registration Statement (or of the most recent
Post-Effective Amendment thereof) which,
individually or in the aggregate, represent a
fundamental change in the information set forth
in the Registration Statement. Notwithstanding
the foregoing, any increase or decrease in volume
of securities offered (if the total dollar value
of the securities offered would not exceed that
which was registered) and any deviation from the
low or high end of the estimated maximum offering
range may be reflected in the form of prospectus
filed with the Commission pursuant to Rule 424(b)
if, in the aggregate, the changes in volume and
price represent no more than a 20% change in the
maximum aggregate offering price set forth in the
"Calculation of Registration Fee" table in the
effective registration statement.
2
(iii) To include any material information with respect
to the plan of distribution not previously
disclosed in the Registration Statement or any
material change to such information in the
Registration Statement.
Provided, however, that paragraphs (1)(i) and (1)(ii) do
not apply if the registration statement is on Form S-3 or
Form S-8 and the information required to be included in a
post-effective amendment by those paragraphs is contained
in periodic reports filed by the registrant pursuant to
section 13 or section 15(d) of the Securities Exchange
Act of 1934 that are incorporated by reference in the
registration statement.
(2) That, for the purpose of determining any liability under
the Securities Act of 1933, each such post-effective
amendment shall be deemed to be a new registration
statement relating to the securities offered therein, and
the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective
amendment any of the securities being registered which
remain unsold at the termination of the offering.
The undersigned Registrant hereby undertakes to provide at the closing
specified in the underwriting agreement certificates in such denominations and
registered in such names as required by the underwriters to permit prompt
delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 (the "Act") may be permitted to directors, officers and controlling
persons of the Registrant pursuant to the foregoing provisions, or otherwise,
the Registrant has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as expressed
in the Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
Registrant in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in connection with the
securities being registered, the registrant will, unless in the opinion of its
counsel the matter has been settled by controlling precedent, submit to a court
of appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Securities Act and will be governed by
the final adjudication of such issue.
The undersigned registrant hereby undertakes that:
o For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed
as part of this Registration Statement in reliance upon Rule
430A and contained in a form of prospectus filed by the
registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under
the Securities Act shall be deemed to be part of this
Registration Statement as of the time it was declared
effective.
o For purposes of determining any liability under the Securities
Act, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of
such securities at that time shall be deemed to be the initial
bona fide offering thereof.
3
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in Moon Township,
Pennsylvania on May 20, 2003.
ATLAS AMERICA PUBLIC #12-2003 PROGRAM
(Registrant)
By: Atlas Resources, Inc.,
Managing General Partner
By: /s/ Jack L. Hollander
---------------------------------
Jack L. Hollander, Senior Vice President -
Direct Participation Programs
Jack L. Hollander, pursuant
to the Registration Statement, has
been granted Power of Attorney and is
signing on behalf of the names shown
below, in the capacities indicated.
In accordance with the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
Signature Title Date
---------------------- ---------------------------------------------------------------------------------------- -------------
Freddie M. Kotek President, Chief Executive Officer and Chairman of the Board of Directors 5/20/2003
Frank P. Carolas Executive Vice President - Land and Geology and a Director 5/20/2003
Jeffrey C. Simmons Executive Vice President - Operations and a Director 5/20/2003
Nancy J. McGurk Senior Vice President, Chief Financial Officer and Chief Accounting Officer 5/20/2003
As filed with the Securities and Exchange Commission on June 3, 2003
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------------------------
EXHIBITS
TO
FORM S-1
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933
----------------------------------
ATLAS AMERICA PUBLIC #12-2003 PROGRAM
(Exact name of Registrant as Specified in its Charter)
----------------------------------
Jack L. Hollander, Senior Vice President - Direct Participation Programs
Atlas Resources, Inc.
311 Rouser Road, Moon Township, Pennsylvania 15108
(412) 262-2830
(Name, Address and Telephone Number of Agent for Service)
----------------------------------
Copies to:
Wallace W. Kunzman, Jr., Esq. Jack L. Hollander
Kunzman & Bollinger, Inc. Atlas Resources, Inc.
5100 N. Brookline, Suite 600 311 Rouser Road
Oklahoma City, Oklahoma 73112 Moon Township, Pennsylvania 15108
EXHIBIT INDEX
Exhibit No. Description
1(a) Proposed form of Dealer-Manager Agreement with Anthem Securities, Inc.
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(b) Agreement of Limited Partnership for Atlas America Public #12-2003 and Atlas America Public #12-2004(_) (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 for Atlas America Public #12-2003 Limited Partnership
10(b) Escrow Agreement for Atlas America Public #12-2004(A) Limited Partnership
10(c) Escrow Agreement for Atlas America Public #12-2004(B) Limited Partnership
10(d) Escrow Agreement for Atlas America Public #12-2004(C) Limited Partnership
10(e) 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)
23(a) Consent of Independent Certified Public Accountants
23(b) Consent of United Energy Development Consultants, Inc.
23(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)
23(d) Consent of Wright & Company, Inc.
24 Power of Attorney
-----------------