PROSPECTUS DATED MARCH 3, 2005
ATLAS AMERICA PUBLIC #14-2004 PROGRAM
Up to 6,732.55 Investor General Partner Units and 6,732.55 converted Limited Partner Units and up
to 510.50 Limited Partner Units, which are collectively referred to as the "Units," at $10,000 per Unit
$2 Million (200 Units) Minimum Aggregate Subscriptions
$72,430,500 (7,243.05 Units) Maximum Aggregate Subscriptions
Atlas America Public #14-2004 Program is a series of up The Offering: In addition to the information in the table below for not
to three limited partnerships which will drill less than 95% of the units (6,881 units), up to 5% of the units (362.05
primarily natural gas development wells. The first units), in the aggregate, may be sold at $8,950 per unit to the managing
partnership in the program, Atlas America Public general partner, its officers, directors and affiliates, and investors
#14-2004 L.P., was completed on November 15, 2004 for who buy units through the officers and directors of the managing general
$52,506,570. This prospectus relates to the offering partner; or at $9,300 per unit to registered investment advisors and
of securities of the program's remaining two limited their clients, and selling agents and their registered representatives
partnerships, Atlas America Public #14-2005(A) L.P. and and principals. These discounted prices reflect certain fees, sales
Atlas America Public #14-2005(B) L.P. See "Terms of commissions and reimbursements which will not be paid for these sales.
the Offering - Subscription to a Partnership," (See "Plan of Distribution.") To the extent that units are sold at
beginning on page 33 for a detailed description of the discounted prices, a partnership's subscription proceeds will be
offering of these limited partnerships. They will be reduced.
managed by Atlas Resources, Inc. of Pittsburgh, Total Total
Pennsylvania. Per Unit Minimum Maximum (2)
If you invest in a partnership, then you will not have
any interest in any of the other partnerships unless Public Price $10,000 $2,000,000 $72,430,500.00
you also make a separate investment in the other
partnerships. Dealer-manager fee,
The units will be offered on a "best efforts" sales commissions,
"minimum-maximum" basis. This means the broker/dealers accountable
must sell at least 200 units and receive subscription reimbursements for
proceeds of at least $2 million in order for a permissible non-cash
partnership to close, and they must use only their best compensation, and
efforts to sell the remaining units in the accountable due
partnership. diligence
Subscription proceeds for each partnership will be held reimbursements (1) $ 1,050 $ 210,000 $ 7,605,202.50
in an interest bearing escrow account until $2 million
has been received. The offering of Atlas America Proceeds to partnership $10,000 $2,000,000 $72,430,500.00
Public #14-2005(A) L.P. and Atlas America Public
#14-2005(B) L.P. will not extend beyond December 31, ----------
2005. If the minimum subscription proceeds are not (1) These fees, sales commissions and reimbursements will be paid by
received by a partnership's offering termination date, the managing general partner as a part of its capital contribution
then your subscription will be promptly returned to you and not from subscription proceeds.
from the escrow account with interest and without (2) The first partnership in the program, Atlas America Public
deduction for any fees. #14-2004 L.P., was completed on November 15, 2004 for $52,506,570,
which includes units sold at the discounted prices described above.
Thus, the total remaining maximum subscriptions from the original
$125 million, based on the number of units previously sold, are
$72,430,500, which is 7,243.05 units at $10,000 per unit and
assumes no units are sold at the discounted prices described above.
o A partnership's drilling operations involve the possibility of a substantial or partial loss of your investment because of
wells which are productive, but do not produce enough revenue to return the investment made and dry holes.
o A partnership's revenues are directly related to the ability to market the natural gas and natural gas and oil prices, which
are volatile and uncertain. If natural gas and oil prices decrease, then your investment return will decrease.
o Unlimited joint and several liability for partnership obligations if you choose to invest as an investor general partner
until you are converted to a limited partner.
o Lack of liquidity or a market for the units, which makes it extremely difficult for you to sell your units.
o Lack of conflict of interest resolution procedures.
o Total reliance on the managing general partner and its affiliates.
o Authorization of substantial fees to the managing general partner and its affiliates.
o You and the managing general partner will share in costs disproportionately to your sharing of revenues.
o Possible allocation of taxable income to you in excess of your cash distributions from your partnership.
o No guaranty of cash distributions every 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
BRYAN FUNDING, INC. - DEALER-MANAGER IN MINNESOTA AND NEW HAMPSHIRE
TABLE OF CONTENTS
SUMMARY OF THE OFFERING...................................1
Business of the Partnerships and the Managing
General Partner....................................1
Risk Factors..........................................1
Terms of the Offering.................................3
Description of Units..................................3
Investor General Partner Units.....................4
Limited Partner Units..............................4
Use of Proceeds.......................................5
Five Year-50% Subordination, Participation in Costs
and Revenues, and Distributions....................5
Compensation..........................................7
RISK FACTORS..............................................8
Risks Related To The Partnerships' Oil and
Gas Operations.......................................8
No Guarantee of Return of Investment or Rate of
Return on Investment Because of Speculative
Nature of Drilling Natural Gas and Oil Wells....8
Because Some Wells May Not Return Their Drilling
and Completion Costs, It May Take Many Years
to Return Your Investment in Cash, If
Ever............................................8
Nonproductive Wells May be Drilled Even Though
the Partnerships' Operations are Primarily
Limited to Development Drilling.................8
Partnership Distributions May be Reduced if
There is a Decrease in the Price of Natural
Gas and Oil.....................................8
Adverse Events in Marketing a Partnership's
Natural Gas Could Reduce Partnership
Distributions...................................9
Possible Leasehold Defects.........................9
Transfer of the Leases Will Not Be Made Until
Well is Completed............................. 10
Participation with Third-Parties in Drilling
Wells May Require the Partnerships to Pay
Additional Costs...............................10
Risks Related to an Investment In a Partnership.....10
If You Choose to Invest as a General Partner,
Then You Have Greater Risk Than a Limited
Partner...........................................10
The Managing General Partner May Not
Meet Its Capital Contributions, Indemnification
and Purchase Obligations If Its Liquid Net
Worth Is Not Sufficient........................11
An Investment in a Partnership Must be for the
Long-Term Because the Units Are Illiquid and
Not Readily Transferable.......................12
Spreading the Risks of Drilling Among a Number
of Wells Will be Reduced if Less than the
Maximum Subscription Proceeds are Received and
Fewer Wells are Drilled........................12
The Partnerships Do Not Own Any Prospects, the
Managing General Partner Has Complete
Discretion to Select Which Prospects Are
Acquired By a Partnership, and The Possible
Lack of Information for a Majority of the
Prospects Decreases Your Ability to Evaluate
the Feasibility of a Partnership...............12
Drilling Prospects in One Area May Increase Risk..13
Lack of Production Information Increases Your
Risk and Decreases Your Ability to Evaluate
the Feasibility of a Partnership's Drilling
Program........................................13
The Partnerships Composing This Program and Other
Partnerships Sponsored by the Managing General
Partner May Compete With Each Other for
Prospects, Equipment, Contractors, and
Personnel......................................14
Managing General Partner's Subordination is Not a
Guarantee of the Return of Any of Your
Investment.....................................14
Borrowings by the Managing General Partner Could
Reduce Funds Available for Its Subordination
Obligation.....................................14
Compensation and Fees to the Managing General
Partner Regardless of Success of a
Partnership's Activities Will Reduce Cash
Distributions..................................14
The Intended Quarterly Distributions to
Investors May be Reduced or Delayed............14
There Are Conflicts of Interest Between the
Managing General Partner and the Investors.....15
The Presentment Obligation May Not Be Funded
and the Presentment Price May Not Reflect
Full Value.....................................16
The Managing General Partner May Not Devote the
Necessary Time to the Partnerships Because Its
Management Obligations Are Not Exclusive.......16
Prepaying Subscription Proceeds to the Managing
General Partner May Expose the Subscription
Proceeds to Claims of the Managing General
Partner's Creditors............................16
Lack of Independent Underwriter May Reduce Due
Diligence Investigation of the Partnerships
and the Managing General Partner...............16
A Lengthy Offering Period May Result in Delays
in the Investment of Your Subscription and
Any Cash Distributions From the Partnership
to You.........................................17
Tax Risks............................................17
Changes in the Law May Reduce to Some Degree
Your Tax Benefits From an Investment in a
Partnership....................................17
You May Owe Taxes in Excess of Your Cash
Distributions from a Partnership...............17
Your Deduction for Intangible Drilling Costs May
Be Limited for Purposes of the Alternative
Minimum Tax....................................17
Investment Interest Deductions of Investor
General Partners May Be Limited................17
Your Tax Benefits Are Not Contractually Protected.17
An IRS Audit of Your Partnership May Result in
an IRS Audit of Your Personal Federal Income
Tax Returns....................................18
Your Partnership Deductions May Be Challenged by
the IRS........................................18
ADDITIONAL INFORMATION...................................19
FORWARD LOOKING STATEMENTS AND
ASSOCIATED RISKS.........................................19
INVESTMENT OBJECTIVES....................................20
ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE
RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL
PARTNERS............................................21
CAPITALIZATION AND SOURCE OF FUNDS
AND USE OF PROCEEDS......................................23
Source of Funds......................................23
Use of Proceeds......................................24
COMPENSATION.............................................27
Natural Gas and Oil Revenues.........................27
Lease Costs..........................................27
Drilling Contracts...................................28
Per Well Charges.....................................29
Gathering Fees.......................................30
Dealer-Manager Fees..................................32
Interest and Other Compensation......................32
Estimate of Administrative Costs and Direct Costs
to be Borne by the Partnerships...................32
i
TERMS OF THE OFFERING...................................33
Subscription to a Partnership.......................33
Partnership Closings and Escrow.....................35
Acceptance of Subscriptions.........................35
Activation of the Partnerships......................36
Suitability Standards...............................36
In General.......................................36
General Suitability Requirements for Purchasers
of Limited Partner Units......................37
Special Suitability Requirements for Purchasers
of Limited Partner Units in California,
Michigan, New Hampshire, New Jersey and
North Carolina................................37
General Suitability Requirements for Purchasers
of Investor General Partner Units.............38
Special Suitability Requirements for Purchasers
of Investor General Partner Units in either:
(i) Alabama, Arkansas, 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..39
Special Suitability Requirements for Purchasers
of Investor General Partner Units in
California, New Hampshire or New Jersey.......40
Fiduciary Accounts...............................40
PRIOR ACTIVITIES........................................41
MANAGEMENT..............................................51
Managing General Partner and Operator...............51
Officers, Directors and Other Key Personnel.........52
Atlas America, Inc., a Delaware Holding Company.....55
Organizational Diagram and Security Ownership of
Beneficial Owners...................................56
Remuneration........................................56
Code of Business Conduct and Ethics.................56
Transactions with Management and Affiliates.........57
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION, RESULTS OF OPERATIONS, LIQUIDITY AND
CAPITAL RESOURCES.................................. 57
PROPOSED ACTIVITIES.....................................58
Overview of Drilling Activities.....................58
Primary Areas of Operations.........................59
Mississippian/Upper Devonian Sandstone
Reservoirs, Fayette County, Pennsylvania......61
Clinton/Medina Geological Formation in
Western Pennsylvania..........................61
Upper Devonian Sandstone Reservoirs,
Armstrong County, Pennsylvania................62
Upper Devonian Sandstone Reservoirs in
McKean County, Pennsylvania...................62
Mississippian Carbonate and Devonian Shale
Reservoirs in Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee...........62
Secondary Areas of Operations.......................63
Clinton/Medina Geological Formation
in Western New York...........................63
Clinton/Medina Geological Formation
in Southern Ohio..............................63
Acquisition of Leases...............................64
Deep Drilling Rights Retained by Managing
General Partner...............................65
Interests of Parties................................65
Primary Areas.......................................66
Clinton/Medina Geological Formation
in Western Pennsylvania and Mississippian/Upper
Devonian Sandstone Reservoirs in Fayette and
Greene Counties, Pennsylvania and Upper
Devonian Sandstone Reservoirs in McKean
County, Pennsylvania..........................66
Upper Devonian Sandstone Reservoirs in
Armstrong County, Pennsylvania................67
Mississippian Carbonate and Devonian Shale
Reservoirs in Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee...........67
Secondary Areas.....................................67
Title to Properties.................................67
Drilling and Completion Activities; Operation
of Producing Wells...............................68
Sale of Natural Gas and Oil Production..............69
Policy of Treating All Wells Equally in a
Geographic Area...............................69
Gathering of Natural Gas.........................70
Natural Gas Contracts............................70
Marketing of Natural Gas Production from Wells
in Other Areas of the United States..............73
Crude Oil...........................................73
Insurance...........................................73
Use of Consultants and Subcontractors...............73
COMPETITION, MARKETS AND REGULATION.....................74
Natural Gas Regulation..............................74
Crude Oil Regulation................................74
Competition and Markets.............................74
State Regulations...................................76
Environmental Regulation............................76
Proposed Regulation.................................77
PARTICIPATION IN COSTS AND REVENUES.....................77
In General..........................................77
Costs...............................................78
Revenues............................................79
Subordination of Portion of Managing General
Partner's Net Revenue Share......................80
Table of Participation in Costs and Revenues........81
Allocation and Adjustment Among Investors...........82
Distributions.......................................83
Liquidation.........................................83
CONFLICTS OF INTEREST...................................84
In General..........................................84
Conflicts Regarding Transactions with the
Managing General Partner and its Affiliates......84
Conflict Regarding the Drilling and Operating
Agreement........................................85
Conflicts Regarding Sharing of Costs and Revenues...85
Conflicts Regarding Tax Matters Partner.............85
Conflicts Regarding Other Activities of the
Managing General Partner, the Operator and
Their Affiliates.................................86
Conflicts Involving the Acquisition of Leases.......86
Conflicts Between Investors and the Managing
General Partner as an Investor...................91
Lack of Independent Underwriter and Due Diligence
Investigation....................................91
Conflicts Concerning Legal Counsel..................91
Conflicts Regarding Presentment Feature.............91
Conflicts Regarding Managing General Partner
Withdrawing an Interest..........................92
Conflicts Regarding Order of Pipeline Construction
and Gathering Fees..............................92
Procedures to Reduce Conflicts of Interest..........92
Policy Regarding Roll-Ups...........................93
ii
FIDUCIARY RESPONSIBILITY OF THE
MANAGING GENERAL PARTNER................................94
In General..........................................94
Limitations on Managing General Partner Liability
as Fiduciary.....................................95
MATERIAL FEDERAL INCOME TAX CONSEQUENCES................96
Introduction........................................96
Disclosures and Limitation on Your Use of Special
Counsel's Tax Opinion Letter.................... 96
Special Counsel's Opinions..........................97
Special Counsel's Assumptions.......................97
Managing General Partner's Representations..........97
Special Counsel's Opinions..........................99
Summary Discussion of the Material Federal Income
Tax Consequences and any Significant Federal
Tax Issues of an Investment in a Partnership....104
Introduction.......................................104
Partnership Classification.........................104
Limitations on Passive Activity Losses and
Credits.........................................104
Publicly Traded Partnership Rules..................105
Conversion from Investor General Partner to
Limited Partner.................................105
Taxable Year and Method of Accounting..............106
2005 Expenditures..................................106
Business Expenses..................................106
Intangible Drilling Costs..........................107
Drilling Contracts.................................108
Depletion Allowance................................110
Marginal Well Production Credits...................110
Depreciation - Modified Accelerated Cost Recovery
System ("MACRS")................................112
Lease Acquisition Costs and Abandonment............112
Tax Basis of Units.................................112
"At Risk" Limitation For Losses....................113
Distributions From a Partnership...................113
Sale of the Properties.............................113
Disposition of Units...............................114
Alternative Minimum Tax............................115
Limitations on Deduction of Investment Interest....117
Allocations........................................117
Partnership Borrowings.............................118
Partnership Organization and Offering Costs........118
Tax Elections......................................118
Termination of a Partnership.......................120
Tax Returns and IRS Audits.........................120
Tax Returns.....................................120
Profit Motive, IRS Anti-Abuse Rule and Judicial
Doctrines Limitations on Deductions.............120
Federal Interest and Tax Penalties.................121
State and Local Taxes..............................123
Severance and Ad Valorem (Real Estate) Taxes.......123
Social Security Benefits and Self-Employment Tax...123
Farmouts...........................................124
Foreign Partners...................................124
Estate and Gift Taxation...........................124
Changes in the Law.................................124
SUMMARY OF PARTNERSHIP AGREEMENT.......................125
Liability of Limited Partners......................125
Amendments.........................................125
Notice.............................................125
Voting Rights......................................125
Access to Records..................................126
Withdrawal of Managing General Partner.............126
Return of Subscription Proceeds if Funds Are Not
Invested in Twelve Months.......................127
SUMMARY OF DRILLING AND OPERATING
AGREEMENT..............................................127
REPORTS TO INVESTORS...................................128
PRESENTMENT FEATURE....................................129
TRANSFERABILITY OF UNITS...............................131
Restrictions on Transfer Imposed by the Securities
Laws, the Tax Laws and the Partnership
Agreement.......................................131
Conditions to Becoming a Substitute Partner........131
PLAN OF DISTRIBUTION...................................132
Commissions........................................132
Indemnification....................................135
SALES MATERIAL.........................................135
LEGAL OPINIONS.........................................136
EXPERTS................................................136
LITIGATION.............................................136
FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL
PARTNER AND ATLAS AMERICA PUBLIC #14-2005(A) L.P...137
Exhibits
Appendix A Information Regarding Currently
Proposed Prospects for Atlas America
Public #14-2005(A) L.P.
Exhibit (A) Form of Amended and Restated Certificate
and Agreement of Limited Partnership for
Atlas America Public #2005(A) L.P.
[Form of Amended and Restated Certificate
and Agreement of Limited Partnership for
Atlas America Public #14-2005(B) L.P.]
Exhibit (I-A) Form of Managing General Partner
Signature Page
Exhibit (I-B) Form of Subscription Agreement
Exhibit (II) Form of Drilling and Operating Agreement
for Atlas America Public #14-2005(A) L.P.
[Atlas America Public #14-2005(B) L.P.]
Exhibit (B) Special Suitability Requirements and
Disclosures to Investors
iii
SUMMARY OF THE OFFERING
This is a summary and does not include all of the information which may be
important to you. You should read the entire prospectus and the attached
exhibits and appendix before you decide to invest. Throughout this prospectus
when there is a reference to you it is a reference to you as a potential
investor or participant in a partnership.
BUSINESS OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER
Atlas America Public #14-2004 Program, which is sometimes referred to in this
prospectus as the "program," consists of up to three Delaware limited
partnerships. The first partnership in the program, Atlas America Public
#14-2004 L.P., was completed on November 15, 2004 for $52,506,570. This
prospectus relates to the offering of securities of the program's remaining two
limited partnerships, Atlas America Public #14-2005(A) L.P. and Atlas America
Public #14-2005(B) L.P. These limited partnerships are sometimes referred to in
this prospectus in the singular as a "partnership" or in the plural as the
"partnerships." Units of Atlas America Public #14-2005(A) L.P. and Atlas America
Public #14-2005(B) L.P. will be offered and sold in a series in 2005, although
the managing general partner has the sole discretion to sell all of the
remaining units in Atlas America Public #14-2005(A) L.P. and not offer and sell
any units in Atlas America Public #14-2005(B) L.P. See "Terms of the Offering"
for a discussion of the terms and conditions involved in making an investment in
a partnership.
Each partnership in the program will be a separate business entity from the
other partnerships. A limited partnership agreement will govern the rights and
obligations of the partners of each partnership. A form of the limited
partnership agreement is attached to this prospectus as Exhibit (A). For a
summary of the material provisions of the limited partnership agreement which
are not covered elsewhere in this prospectus see "Summary of Partnership
Agreement." You will be a partner only in the partnership in which you invest.
You will have no interest in the business, assets or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the partnership in which you invest.
The offering proceeds of each partnership will be used to drill primarily
natural gas development wells in the Appalachian Basin located in western
Pennsylvania, eastern and southern Ohio, western New York and north central
Tennessee as described in "Proposed Activities." A development well means a well
drilled within the proved area of a natural gas or oil reservoir to the depth of
a stratigraphic horizon known to be productive. Currently, the partnerships do
not hold any interests in any properties or prospects on which the wells will be
drilled.
The managing general partner of each partnership is Atlas Resources, Inc., a
Pennsylvania corporation, which was incorporated in 1979, and is sometimes
referred to in this prospectus as "Atlas Resources." As set forth in "Prior
Activities," the managing general partner has sponsored and serves as managing
general partner of 35 private drilling partnerships which raised a total of
$254,432,892, and 13 public drilling partnerships which raised a total of
$220,117,468. 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 September 30, 2004, the managing
general partner and its affiliates operated approximately 4,861 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 risks related to each
partnership's oil and gas operations, risks related to a partnership investment,
and tax risks. You should carefully consider a number of significant risk
factors inherent in and affecting the business of a partnership and this
offering, including the following.
o 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 from time to time dry holes.
1
o Each partnership's revenues are directly related to the
ability to market the natural gas and natural gas and oil
prices, which are volatile and uncertain, and if natural gas
and oil prices decrease then your investment return will
decrease.
o Unlimited joint and several liability for partnership
obligations if you choose to invest as an investor general
partner until you are converted to a limited partner.
o Lack of liquidity or a market for the units, necessitates a
long-term commitment and makes it extremely difficult for you
to sell your units.
o Total reliance on the managing general partner and its
affiliates.
o Authorization of substantial fees to the managing general
partner and its affiliates.
o Possible allocation of taxable income to investors in excess
of their cash distributions from a partnership, and there may
not be any partnership marginal well production tax credits to
offset a portion or all of the resulting federal income tax
liability.
o Each partnership must receive minimum subscriptions of $2
million to close, and the subscription proceeds of both
partnerships, in the aggregate, may not exceed $72,430,500,
which is the remaining portion of the unsold units from the
original $125 million registration. There are no other
requirements regarding the size of a partnership, and the
subscription proceeds of one partnership may be substantially
more or less than the subscription proceeds of the other
partnerships. If only the minimum subscriptions are received
in a partnership, the partnership's ability to spread the
risks of drilling will be greatly reduced as described in
"Compensation - Drilling Contracts."
o Certain conflicts of interest between the managing general
partner and you and the other investors and lack of procedures
to resolve the conflicts.
o You and the other investors and the managing general partner
will share in costs disproportionately to the sharing of
revenues.
o Currently, the partnerships do not hold any interests in any
properties or prospects on which the wells will be drilled.
Although the managing general partner has absolute discretion
in determining which properties or prospects will be drilled
by a partnership, the managing general partner intends that
Atlas America Public #14-2005(A) L.P. will drill the prospects
described in "Appendix A - Information Regarding Currently
Proposed Prospects for Atlas America Public #14-2005(A) L.P."
These prospects represent a majority of the wells to be
drilled if the nonbinding targeted subscription proceeds
described in "Terms of the Offering - Subscription to a
Partnership" are received, although the managing general
partner has the sole discretion to sell all of the remaining
units in Atlas America Public #14-2005(A) L.P. and not offer
and sell any units in Atlas America Public #14-2005(B) L.P. If
there are adverse events with respect to any of the currently
proposed prospects, the managing general partner will
substitute the partnership's prospects. The managing general
partner also anticipates that it will designate a portion of
the prospects in the partnership designated Atlas America
Public #14-2005(B) L.P. by a supplement or an amendment to the
registration statement of which this prospectus is a part.
o In each partnership the managing general partner may
subordinate a portion of its share of that partnership's net
production revenues. This subordination is not a guaranty by
the managing general partner, and if the wells in that
partnership produce small volumes of natural gas and oil
and/or natural gas and oil prices decrease, then even with
subordination your cash flow from the partnership may not
return your entire investment.
2
o In each partnership quarterly cash distributions to investors
may be deferred if revenues are used for partnership
operations or reserves.
TERMS OF THE OFFERING
The offering period will begin on the date of this prospectus. Each partnership
will offer a minimum of 200 units, which is $2 million, and both partnerships,
in the aggregate, will offer a maximum of 7,243.05 units which is $72,430,500,
which is the remaining portion of the unsold units from the original $125
million registration. The maximum subscription proceeds for each partnership
will be the lesser of:
o the amount of $72,430,500; or
o the number of units which remain unsold from the above amount.
The targeted subscription proceeds and closing date for each partnership, which
are not binding on the managing general partner, are set forth in a table in
"Terms of the Offering - Subscription to a Partnership." The managing general
partner, however, has the discretion to accept subscriptions for the entire
$72,430,500 in Atlas America Public #14-2005(A) L.P. and not offer and sell any
units in Atlas America Public #14-2005(B) L.P.
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 in "- Description of Units," below.
Under the partnership agreement no investor, including investor general
partners, may participate in the management of a partnership's business. The
managing general partner will have exclusive management authority for the
partnerships.
Subscription proceeds for a partnership will be held in a separate interest
bearing escrow account at National City Bank of Pennsylvania until receipt of
the minimum subscription proceeds. Each partnership has been formed as a limited
partnership under the Delaware Revised Uniform Limited Partnership Act. In
addition, a partnership may not break escrow as described in "Terms of the
Offering - Partnership Closings and Escrow," unless the partnership is in
receipt of the minimum subscription proceeds after the discounts described in
"Plan of Distribution" and excluding any subscriptions by the managing general
partner or its affiliates. However, on receipt of the minimum subscription
proceeds, the managing general partner on behalf of a partnership may break
escrow, transfer the escrowed funds to a partnership account, and begin its
activities, including drilling to the extent the prospects have been identified
in this prospectus or by a supplement or an amendment to the registration
statement. After breaking escrow additional subscription proceeds may be paid
directly to the partnership account for that partnership and will continue to
earn interest until the offering of that partnership closes. (See "Terms of the
Offering.")
DESCRIPTION OF UNITS
In the partnership being offered at the time you subscribe you may buy either:
o investor general partner units; or
o limited partner units.
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.
3
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 limitation on losses 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 " Material
Federal Income Tax Consequences - Limitations on Passive
Activity Losses and Credits.")
o Intangible drilling costs generally means those costs
of drilling and completing a well that are currently
deductible, as compared to lease costs which must be
recovered through the depletion allowance and costs
for equipment in the well which must be recovered
through depreciation deductions.
o LIABILITY. If you invest in a partnership as an investor
general partner, then you will have unlimited liability
regarding the partnership's activities. This means if:
o the insurance proceeds;
o the managing general partner's indemnification; and
o the partnership's assets
were not sufficient to satisfy a partnership liability for
which you and the other investor general partners were also
liable, 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.
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"
4
trade or business activities. Passive trade or business
activities generally include the partnership and other limited
partner investments, but passive income does not include
dividends and interest. This means that you will not be able
to deduct your share of the partnership's intangible drilling
costs in the year in which you invest unless you have passive
income from investments other than the partnership. (See
"Material Federal Income Tax Consequences - Limitations on
Passive Activity Losses and Credits.")
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."
USE OF PROCEEDS
Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of Atlas America Public #14-2005(A) L.P.
and Atlas America Public #14-2005(B) L.P., in the aggregate, may not exceed
$72,430,500. The subscription proceeds of one partnership may be substantially
more or less than the subscription proceeds of the other partnerships. In this
regard, the managing general partner has the discretion to accept subscriptions
for the entire $72,430,500 in Atlas America Public #14-2005(A) L.P. and not
offer and sell any units in Atlas America Public #14-2005(B) L.P. The
subscription proceeds of each partnership, regardless of whether the number of
units sold to you and the other investors in a partnership is the minimum or up
to the maximum, 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 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.
The managing general partner also will be charged with 100% of the organization
and offering costs for each partnership. A portion of these contributions to
each partnership will be in the form of payments to itself, its affiliates and
third-parties and the remainder will be in the form of services related to
organizing this offering. The managing general partner will receive a credit
towards its required capital contribution to each partnership for these payments
and services as discussed in "Participation in Costs and Revenues." (See
"Capitalization and Source of Funds and Use of Proceeds" and "Material Federal
Income Tax Consequences - Intangible Drilling Costs.")
FIVE YEAR-50% SUBORDINATION, PARTICIPATION IN COSTS AND REVENUES, AND
DISTRIBUTIONS Each partnership will be a separate business entity from the other
partnerships, and you will be a partner only in the partnership in which you
invest. You will have no interest in the business, assets or tax benefits of the
other partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest. Each partnership is
structured to provide you and 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, which
will be up to between 16% and 17.5% of total 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 have been drilled, completed, and
begun 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 of
capital described above. The specific formula is set forth in Section
5.01(b)(4)(a) of the partnership agreement.
The following table sets forth the partnership costs and revenues charged and
credited between the managing general partner and you and the other investors
for each partnership after deducting from the partnership's gross revenues the
landowner royalties and any other lease burdens.
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 a
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. Equipment proceeds, if any, will be
credited in the same percentage in which the equipment costs were
charged.
(2) These costs will be charged to the parties in the same ratio as the
related production revenues are being credited. These costs also include
the plugging and abandonment costs of the wells as described in
"Participation in Costs and Revenues."
(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 a partnership will
share in all of that partnership's other revenues in the same percentage
as their respective capital contributions bears to the total partnership
capital contributions (the managing general partner's capital
contribution will not be less than 25% of 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 in which you invest 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 from the investors to the
managing general partner of its general and administrative
overhead which cannot exceed $12,780 per well for the
investors' share.
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 reimbursement for permissible non-cash
compensation, and up to 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 48 partnerships since 1985,
however, 36 of the 48 partnerships have not yet returned to the investor 100% of
his capital contributions without taking tax savings into account. Thus, it may
take many years to return your investment in cash, if ever. (See "Prior
Activities.")
NONPRODUCTIVE WELLS MAY BE DRILLED EVEN THOUGH THE PARTNERSHIPS' OPERATIONS ARE
PRIMARILY LIMITED TO DEVELOPMENT DRILLING. Each partnership may drill some
development wells which are nonproductive, which is referred to as a "dry hole,"
and must be plugged and abandoned. If one or more of 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" and "Proposed Activities.")
PARTNERSHIP DISTRIBUTIONS MAY BE REDUCED IF THERE IS A DECREASE IN THE PRICE OF
NATURAL GAS AND OIL. The prices at which a partnership's natural gas and oil
will be sold are uncertain and as discussed in "- Adverse Events in Marketing a
Partnership's Natural Gas Could Reduce Partnership Distributions," the
partnerships are not guaranteed a specific natural gas price for the sale of
their natural gas production. Historically, natural gas and oil prices have been
volatile and will likely continue to be volatile in the future. Prices for
natural gas and oil will depend on supply and demand factors largely beyond the
control of the partnerships. For example, the demand for natural gas is usually
greater in the winter months because of residential heating requirements than in
the summer months, and generally results in lower natural gas prices in the
summer months than in the winter months. See "Competition, Markets and
Regulation - Competition and Markets" for other factors affecting the supply and
demand of natural gas and oil. These factors make it extremely difficult to
predict natural gas and oil price movements with any certainty.
If natural gas and oil prices decrease in the future, then your partnership
distributions will decrease accordingly. Also, natural gas and oil prices may
decrease during the first years of production from your partnership's wells
which is when the wells typically achieve their greatest level of production.
This would have a greater adverse effect on your partnership distributions than
price decreases in later years when the wells have a lower level of production.
(See "Appendix A -
8
Information Regarding Currently Proposed Prospects for Atlas America Public
#14-2005(A) L.P." for a discussion of flush production and "Proposed Activities
- - Sale of Natural Gas and Oil Production.")
ADVERSE EVENTS IN MARKETING A PARTNERSHIP'S NATURAL GAS COULD REDUCE PARTNERSHIP
DISTRIBUTIONS. In addition to the risk of decreased natural gas and oil prices
described above, there are risks associated with marketing natural gas which
could reduce a partnership's distributions to you and the other investors. These
risks are set forth below.
o Competition from other natural gas producers and marketers in
the Appalachian Basin as well as competition from alternative
energy sources may make it more difficult to market each
partnership's natural gas.
o The majority of each partnership's natural gas production will
be sold to a limited number of different natural gas
purchasers as described in "Proposed Activities - Sale of
Natural Gas and Oil Production." One of the natural gas
purchasers has a 10-year agreement, which began on April 11,
1999, to buy all of the managing general partner's and its
affiliates', which includes the partnerships, natural gas
production, subject to various exceptions. The most
significant exception from this agreement for the partnerships
is for natural gas produced from Fayette County, Pennsylvania,
which is where the managing general partner anticipates that
the majority of the prospects which will be drilled by each
partnership will be situated, natural gas produced from
McKean County and Armstrong County, Pennsylvania and Anderson,
Campbell, Morgan and Roane Counties, Tennessee. The majority,
if not all, of the natural gas produced from Fayette County,
Pennsylvania will be sold to one purchaser under a natural gas
contract which ends March 31, 2007. These contracts, including
the contracts for natural gas in McKean County and Armstrong
County, Pennsylvania and Anderson, Campbell, Morgan and Roane
Counties, Tennessee, provide that the price may be adjusted
upward or downward in accordance with the spot market price
and market conditions as described in "Proposed Activities -
Sale of Natural Gas and Oil Production." Thus, the
partnerships will depend primarily on a limited number of
natural gas purchasers and will not be guaranteed a specific
natural gas price, other than through hedging. The price for
each partnership's natural gas may decrease in the future
because of market conditions. Also, even though hedging
provides the partnerships some protection against falling
natural gas prices, hedging also could reduce the potential
benefits of price increases if at the time the natural gas is
to be delivered the spot market natural gas price is higher
than the price paid under the hedging arrangement.
o There is a credit risk associated with a natural gas
purchaser's ability to pay. Each partnership may not be paid
or may experience delays in receiving payment for natural gas
that has already been delivered. In accordance with industry
practice, a partnership typically will deliver natural gas to
a purchaser for a period of up to 60 to 90 days before it
receives payment. Thus, it is possible that the partnership
may not be paid for natural gas that already has been
delivered if the natural gas purchaser fails to pay for any
reason, including bankruptcy. This ongoing credit risk also
may delay or interrupt the sale of the partnership's natural
gas or its negotiation of different terms and arrangements for
selling its natural gas to other purchasers. Finally, this
credit risk may reduce the price benefit derived by the
partnerships from the managing general partner's natural gas
hedging as described in "Proposed Activities - Sale of Natural
Gas and Oil Production - Natural Gas Contracts," since the
majority of the managing general partner's natural gas hedges
are implemented through the natural gas purchasers.
o Partnership revenues may be less the farther the natural gas
is transported because of increased transportation costs.
o Production from wells drilled in certain areas, such as the
wells in Crawford County, Pennsylvania and to a lesser extent,
Fayette County, Pennsylvania and Anderson, Campbell, Morgan
and Roane Counties, Tennessee, may be delayed until
construction of the necessary gathering lines and production
facilities is completed. (See "Proposed Activities - Sale of
Natural Gas and Oil Production.")
9
POSSIBLE LEASEHOLD DEFECTS. There may be defects in a partnership's title to its
leases. Although the managing general partner will obtain a favorable formal
title opinion for the leases before each well is drilled, it will not obtain a
division order title opinion after the well is completed. A partnership may
experience losses from title defects which arose during drilling that would have
been disclosed by a division order title opinion, such as liens that may arise
during drilling or transfers made after drilling begins. Also, the managing
general partner may use its own judgment in waiving title requirements and will
not be liable for any failure of title of leases transferred to the partnership.
(See "Proposed Activities - Title to Properties.")
TRANSFER OF THE LEASES WILL NOT BE MADE UNTIL WELL IS COMPLETED. Because the
leases will not be transferred from the managing general partner to a
partnership until after the wells are drilled and completed, the transfer could
be set aside by a creditor of the managing general partner, or the trustee in
the event of the voluntary or involuntary bankruptcy of the managing general
partner, if it were determined that the managing general partner received less
than a reasonably equivalent value for the leases. In this event, the leases and
the wells would revert to the creditors or trustee, and the partnership would
either recover nothing or only the amount paid for the leases and the cost of
drilling the wells. Assigning the leases to a partnership after the wells are
drilled and completed, however, will not affect the availability of the tax
deductions for intangible drilling costs since the partnership will have an
economic interest in the wells under the drilling and operating agreement before
the wells are drilled. (See "Proposed Activities - Title to Properties.")
PARTICIPATION WITH THIRD-PARTIES IN DRILLING WELLS MAY REQUIRE THE PARTNERSHIPS
TO PAY ADDITIONAL COSTS. Third-parties will participate with each partnership in
drilling some of the wells. Financial risks exist when the cost of drilling,
equipping, completing, and operating wells is shared by more than one person. If
a partnership pays its share of the costs, but another interest owner does not
pay its share of the costs, then the partnership would have to pay the costs of
the defaulting party. In this event, the partnership would receive the
defaulting party's revenues from the well, if any, under penalty arrangements
set forth in the operating agreement.
If the managing general partner is not the actual operator of the well, then
there is a risk that the managing general partner cannot supervise the
third-party operator closely enough. For example, decisions related to the
following would be made by the third-party operator and may not be in the best
interests of the partnerships and you and the other investors:
o how the well is operated;
o expenditures related to the well; and
o possibly the marketing of the natural gas and oil production.
Further, the third-party operator may have financial difficulties and fail to
pay for materials or services on the wells it drills or operates, which would
cause the partnership to incur extra costs in discharging materialmen's and
workmen's liens. The managing general partner may not be the operator of the
well if the partnership owns less than a 50% working interest in the well, or if
the managing general partner acquired the working interest in the well from a
third-party which required that the third-party be named operator as one of the
terms of the acquisition.
RISKS RELATED TO AN INVESTMENT IN A PARTNERSHIP IF YOU CHOOSE TO INVEST AS A
GENERAL PARTNER, THEN YOU HAVE GREATER RISK THAN A LIMITED PARTNER. If you
invest 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.
10
Also, each partnership will own less than 100% of the working interest in some
of its wells. If a court holds you and the other third-party working interest
owners of the well liable for the development and operation of a well and the
third-party working interest owners do not pay their proportionate share of the
costs and liabilities associated with the well, then the partnership and you and
the other investor general partners also would be liable for those costs and
liabilities.
As an investor general partner you may become subject to the following:
o contract liability, which is not covered by insurance;
o liability for pollution, abuses of the environment, and other
environmental damages such as the release of toxic gas, spills
or uncontrollable flows of natural gas, oil or fluids, against
which the managing general partner cannot insure because
coverage is not available or against which it may elect not to
insure because of high premium costs or other reasons; and
o liability for drilling hazards which result in property
damage, personal injury, or death to third-parties in amounts
greater than the insurance coverage. The drilling hazards
include, but are not limited to well blowouts, fires, and
explosions.
If your partnership's insurance proceeds and assets, the managing general
partner's indemnification of you and the other investor general partners, and
the liability coverage provided by major subcontractors were not sufficient to
satisfy the liability, then the managing general partner would call for
additional funds from you and the other investor general partners to satisfy the
liability. (See "Actions To Be Taken By Managing General Partner To Reduce Risks
of Additional Payments by Investor General Partners.")
THE MANAGING GENERAL PARTNER MAY NOT MEET ITS CAPITAL CONTRIBUTIONS,
INDEMNIFICATION AND PURCHASE OBLIGATIONS IF ITS LIQUID NET WORTH IS NOT
SUFFICIENT. The managing general partner has made commitments to you and the
other investors in each partnership regarding the following:
o the payment of organization and offering costs and the
majority of equipment costs;
o indemnification of the investor general partners for
liabilities in excess of their pro rata share of partnership
assets and insurance proceeds ; and
o purchasing units presented by an investor, although this may
be suspended by the managing general partner if it determines,
in its sole discretion, that it does not have the necessary
cash flow or cannot borrow funds for this purpose on
reasonable terms.
A significant financial reversal for the managing general partner could
adversely affect its ability to honor these obligations.
The managing general partner's net worth is based primarily on the estimated
value of its producing natural gas properties and is not available in cash
without borrowings or a sale of the properties. Also, if natural gas prices
decrease, then the estimated value of the properties and the managing general
partner's net worth will be reduced. Further, price decreases will reduce the
managing general partner's revenues, and may make some reserves uneconomic to
produce. This would reduce the managing general partner's reserves and cash
flow, and could cause the lenders of the managing general partner and its
affiliates to reduce the borrowing base for the managing general partner and its
affiliates. Also, because approximately 92% of the managing general partner's
proved reserves are currently natural gas reserves, the managing general
partner's net worth is more susceptible to movements in natural gas prices than
in oil prices.
The managing general partner's net worth may not be sufficient, either currently
or in the future, to meet its financial commitments under the partnership
agreement. These risks are increased because the managing general partner has
made similar financial commitments in 42 other partnerships and will make this
same commitment in future partnerships. (See "Financial Information Concerning
the Managing General Partner and Atlas America Public #14-2005(A) L.P.")
11
AN INVESTMENT IN A PARTNERSHIP MUST BE FOR THE LONG-TERM BECAUSE THE UNITS ARE
ILLIQUID AND NOT READILY TRANSFERABLE. If you invest in a partnership, then you
must assume the risks of an illiquid investment. The transferability of the
units is limited by the federal securities laws, the tax laws, and the
partnership agreement. The units generally cannot be liquidated since there is
not a readily available market for the sale of the units. Further, the
partnerships do not intend to register the units and list the units on any
exchange.
Finally, a sale of your units could create adverse tax and economic consequences
for you. The sale or exchange of all or part of your units held for more than 12
months generally will result in a recognition of long-term capital gain or loss.
However, previous deductions for depreciation, depletion and IDCs may be
recaptured as ordinary income rather than capital gain regardless of how long
you have owned the units. If the units are held for 12 months or less, then the
gain or loss generally will be short-term gain or loss. Your pro rata share of a
partnership's liabilities, if any, as of the date of the sale or exchange must
be included in the amount realized by you. Thus, the gain recognized by you may
result in a tax liability greater than the cash proceeds, if any, received by
you from the sale or other taxable disposition of your units. (See "Material
Federal Income Tax Consequences-Disposition of Units" and "Presentment
Feature.")
SPREADING THE RISKS OF DRILLING AMONG A NUMBER OF WELLS WILL BE REDUCED IF LESS
THAN THE MAXIMUM SUBSCRIPTION PROCEEDS ARE RECEIVED AND FEWER WELLS ARE DRILLED.
Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of both of the partnerships, in the
aggregate, may not exceed $72,430,500, which is the remaining portion of the
unsold units from the original $125 million registration. 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 with a smaller amount of subscription proceeds will
drill fewer wells which decreases the partnership's ability to spread the risks
of drilling. For example, the managing general partner anticipates that a
partnership will drill approximately nine net wells if the minimum subscriptions
of $2 million are received, which is compared with approximately 394 net wells
if subscription proceeds of $72,430,500 are received by a partnership. A gross
well is a well in which a partnership owns a working interest. This is compared
with a net well which is the sum of the fractional working interests owned in
the gross wells. For example, a 50% working interest owned in three wells is
three gross wells, but 1.5 net wells.
On the other hand, to the extent more than the minimum subscriptions are
received by a partnership and the number of wells drilled increases, the
partnership's overall investment return may decrease if the managing general
partner is unable to find enough suitable wells to be drilled. Also, in a large
partnership greater demands will be placed on the managing general partner's
management capabilities. In this regard, the managing general partner has the
discretion to accept subscriptions for the entire $72,430,500 in Atlas America
Public #14-2005(A) L.P. and not offer and sell any units in Atlas America Public
#14-2005(B) L.P.
Finally, the cost of drilling and completing a well is often uncertain and there
may be cost overruns in drilling and completing the wells because the wells will
not be drilled and completed on a turnkey basis for a fixed price, which would
shift the risk of loss to the managing general partner as drilling contractor.
The majority of the equipment costs of 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. Also, unanticipated costs can adversely
affect the economics of the partnerships' wells, since each partnership's wells
will be drilled on a cost plus 15% basis. For example, the managing general
partner and its affiliates have experienced an increase in the cost of tubular
steel as a result of rising steel prices which has increased well costs.
THE PARTNERSHIPS DO NOT OWN ANY PROSPECTS, THE MANAGING GENERAL PARTNER HAS
COMPLETE DISCRETION TO SELECT WHICH PROSPECTS ARE ACQUIRED BY A PARTNERSHIP, AND
THE POSSIBLE LACK OF INFORMATION FOR A MAJORITY OF THE PROSPECTS DECREASES YOUR
ABILITY TO EVALUATE THE FEASIBILITY OF A PARTNERSHIP. The partnerships do not
currently hold
12
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 #14-2005(A) L.P. will drill the prospects
described in "Appendix A - Information Regarding Currently Proposed Prospects
for Atlas America Public #14-2005(A) L.P." These prospects represent the wells
currently proposed to be drilled if the majority of the targeted nonbinding
amount of subscription proceeds is received as described in "Terms of the
Offering - Subscription to a Partnership." If there are adverse events with
respect to any of the currently proposed prospects, the managing general partner
will substitute the partnership's prospects. The managing general partner also
anticipates that it will designate a portion of the prospects in the partnership
designated Atlas America Public #14-2005(B) L.P. by a supplement or an amendment
to the registration statement of which this prospectus is a part. With respect
to the identified prospects for a partnership, the managing general partner has
the right on behalf of the partnership to:
o substitute prospects;
o take a lesser working interest in the prospects;
o drill in other areas; or
o do any combination of the foregoing.
Thus, you do not have any geological or production information to evaluate any
additional and/or substituted prospects and wells. Also, if the subscription
proceeds received in a partnership are insufficient to drill all of the
identified prospects, then the managing general partner will choose those
prospects which it believes are most suitable for the partnership. You must rely
entirely on the managing general partner to select the prospects and wells for a
partnership.
Finally, the partnerships do not have the right of first refusal in the
selection of prospects from the inventory of the managing general partner and
its affiliates, and they may sell their prospects to other partnerships,
companies, joint ventures, or other persons at any time.
DRILLING PROSPECTS IN ONE AREA MAY INCREASE RISK. To the extent that the
prospects are drilled in one area at the same time, this may increase the risk
of loss. For example, if multiple wells in one area are drilled at approximately
the same time, then there is a greater risk of loss if the wells are marginal or
nonproductive since the managing general partner will not be using the drilling
results of one or more of those wells to decide whether or not to continue
drilling prospects in that area or to substitute other prospects in other areas.
This is compared with the situation in which the managing general partner drills
one well and assesses the drilling results before it decides to drill a second
well in the same area or to substitute a different prospect in another area.
This risk is further increased with wells which are prepaid because of the 90
day time constraint and potential adverse weather conditions where the managing
general partner is required to drill many wells at the same time. For example,
"frost laws" prohibit drilling rigs and other heavy equipment from using certain
roads during the winter, which may delay drilling and completing wells within
the 90 day time constraint. Also, there could be shortages of drilling rigs,
equipment, supplies and personnel during this time period. (See " Material
Federal Income Tax Consequences - Drilling Contracts" regarding prepaid wells
and the 90 day time constraint.)
LACK OF PRODUCTION INFORMATION INCREASES YOUR RISK AND DECREASES YOUR ABILITY TO
EVALUATE THE FEASIBILITY OF A PARTNERSHIP'S DRILLING PROGRAM. Production
information from surrounding wells in the area is an important indicator in
evaluating the economic potential of a proposed well to be drilled. However, the
data set forth in "Appendix A - Information Concerning Currently Proposed Wells
for Atlas America Public #14-2005(A) L.P." for the proposed wells in
Pennsylvania may not show all of the surrounding wells drilled and/or production
from those wells because there was a third-party operator and the Pennsylvania
Department of Environmental Resources keeps production data confidential for the
first five years from the time a well starts producing. If the managing general
partner is the operator and no production data is shown, it is
13
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 to you and the
other investors.
THE PARTNERSHIPS COMPOSING THIS PROGRAM AND OTHER PARTNERSHIPS SPONSORED BY THE
MANAGING GENERAL PARTNER MAY COMPETE WITH EACH OTHER FOR PROSPECTS, EQUIPMENT,
CONTRACTORS, AND PERSONNEL. One or more partnerships in this program or other
partnerships sponsored by the managing general partner may have unexpended
capital funds at the same time. Thus, these partnerships may compete for
suitable prospects and the availability of equipment, contractors, and the
managing general partner's personnel. For example, a partnership previously
organized by the managing general partner may still be acquiring prospects to
drill when the partnerships composing this program are attempting to acquire
prospects. This may make it more difficult to complete the prospect acquisition
activities for the partnerships composing this program and may make each
partnership less profitable.
MANAGING GENERAL PARTNER'S SUBORDINATION IS NOT A GUARANTEE OF THE RETURN OF ANY
OF YOUR INVESTMENT. If your cash distributions from the partnership in which you
invest are less than a 10% return of capital for each of the first five 12-month
periods beginning with the partnership's first cash 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 of capital for each of the first five years as described above, or a
return of your capital during the term of the partnership. Also, at any time
during the subordination period the managing general partner is entitled to an
additional share of partnership revenues to recoup previous subordination
distributions to the extent your cash distributions from the partnership exceed
the 10% return of capital described above. (See "Participation in Costs and
Revenues - Subordination of Portion of the Managing General Partner's Net
Revenue Share.")
BORROWINGS BY THE MANAGING GENERAL PARTNER COULD REDUCE FUNDS AVAILABLE FOR ITS
SUBORDINATION OBLIGATION. With respect to each partnership, the managing general
partner has or will pledge either its partnership interest and/or an undivided
interest in the partnership's assets equal to or less than its revenue interest,
which will range from 32% to 35% depending on the amount of its capital
contribution, to secure borrowings for its and its affiliates' corporate
purposes. (See "Participation in Costs and Revenues.") Under agreements
previously entered into as described in "Management's Discussion and Analysis of
Financial Condition, Results of Operations, Liquidity and Capital Resources,"
the managing general partner's lenders have required a first lien in the
property and will have priority over the managing general partner's
subordination obligation under each partnership agreement. Thus, if there was a
default to the lenders under this pledge arrangement, this would reduce or
eliminate the amount of each partnership's net production revenues available to
the managing general partner for its subordination obligation to you and the
other investors. Also, under certain circumstances, if the managing general
partner made a subordination distribution to you and the other investors after a
default to its lenders, then the lenders may be able to recoup that
subordination distribution from you and the other investors.
COMPENSATION AND FEES TO THE MANAGING GENERAL PARTNER REGARDLESS OF SUCCESS OF A
PARTNERSHIP'S ACTIVITIES WILL REDUCE CASH DISTRIBUTIONS. The managing general
partner and its affiliates will profit from their services in drilling,
completing, and operating each partnership's wells, and will receive the other
fees and reimbursement of direct costs 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;
14
o cost overruns;
o remedial work to improve a well's producing capability;
o direct costs and general and administrative expenses of the
partnership;
o reserves, including a reserve for the estimated costs of
eventually plugging and abandoning the wells; or
o indemnification of the managing general partner and its
affiliates by the partnership for losses or liabilities
incurred in connection with the partnership's activities. (See
"Participation in Costs and Revenues - Distributions.")
THERE ARE CONFLICTS OF INTEREST BETWEEN THE MANAGING GENERAL PARTNER AND THE
INVESTORS. There are conflicts of interest between you and the managing general
partner and its affiliates. These conflicts of interest, which are not otherwise
discussed in this "Risk Factors" section, include the following:
o the managing general partner has determined the compensation
and reimbursement that it and its affiliates will receive in
connection with the partnerships without any unaffiliated
third-party dealing at arms' length on behalf of the
investors;
o the managing general partner must monitor and enforce, on
behalf of the partnerships, its own compliance with the
drilling and operating agreement and the partnership
agreement;
o because the managing general partner will receive a percentage
of revenues greater than the percentage of costs that it pays,
there may be a conflict of interest concerning which wells
will be drilled based on the wells' risk and profit potential;
o the allocation of all intangible drilling costs to you and the
other investors and the majority of the equipment costs to the
managing general partner may create a conflict of interest
concerning whether to complete a well;
o if the managing general partner, as tax matters partner,
represents a partnership before the IRS, potential conflicts
include whether or not to expend partnership funds to contest
a proposed adjustment by the IRS, if any, to the amount of
your deduction for intangible drilling costs, or the credit to
the managing general partner's capital account for
contributing the leases to the partnership;
o which wells will be drilled by the managing general partner's
and its affiliates' other affiliated partnerships or
third-party programs in which they serve as driller/operator
and which wells will be drilled by the partnerships, 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 causing the partnerships to drill wells that
will connect to the gathering system owned by Atlas Pipeline
Partners; and
15
o the obligation of the managing general partner's affiliates,
which does not include the partnerships for this purpose, to
pay Atlas Pipeline Partners the difference between the
gathering fees to be paid by each partnership to the managing
general partner 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. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact way, and the accuracy of the reserve estimate is a function
of the quality of the available data and of engineering and geological
interpretation and judgment. Also, the reserves and future net revenues are
based on various assumptions as to natural gas and oil prices, taxes,
development expenses, capital expenses, operating expenses and availability of
funds. Any significant variance in these assumptions could materially affect the
estimated quantity of the reserves. As a result, the managing general partner's
estimates are inherently imprecise and may not correspond to realizable value.
The presentment price paid for your units and any revenues received by you
before the presentment may not be equal to the purchase price of the units. In
addition, because the presentment price is a contractual price it is not reduced
by discounts such as minority interests and lack of marketability that generally
are used to value partnership interests for tax and other purposes. (See
"Presentment Feature.")
Finally, see "- An Investment in a Partnership Must be for the Long-Term Because
the Units Are Illiquid and Not Readily Transferable," above, concerning the tax
effects of presenting your units for purchase.
THE MANAGING GENERAL PARTNER MAY NOT DEVOTE THE NECESSARY TIME TO THE
PARTNERSHIPS BECAUSE ITS MANAGEMENT OBLIGATIONS ARE NOT EXCLUSIVE. The managing
general partner may not devote the necessary time to the partnerships. The
managing general partner and its affiliates will be engaged in other oil and gas
activities, including other partnerships and unrelated business ventures for
their own account or for the account of others, during the term of each
partnership. (See "Management.")
PREPAYING SUBSCRIPTION PROCEEDS TO THE MANAGING GENERAL PARTNER MAY EXPOSE THE
SUBSCRIPTION PROCEEDS TO CLAIMS OF THE MANAGING GENERAL PARTNER'S CREDITORS.
Under the drilling and operating agreement each partnership will be required to
immediately pay the managing general partner the investors' share of the entire
estimated price for drilling and completing the partnership's wells. Thus, these
funds could be subject to claims of the managing general partner's creditors.
(See "Financial Information Concerning the Managing General Partner and Atlas
America Public #14-2005(A) L.P.")
LACK OF INDEPENDENT UNDERWRITER MAY REDUCE DUE DILIGENCE INVESTIGATION OF THE
PARTNERSHIPS AND THE MANAGING GENERAL PARTNER. There has not been an extensive
in-depth "due diligence" investigation of the existing and proposed business
activities of the partnerships and the managing general partner that would be
provided by independent underwriters. Anthem Securities, which is affiliated
with the managing general partner, serves as dealer-manager and will receive
reimbursement of accountable due diligence expenses for certain due diligence
investigations conducted by the selling agents which it will reallow to the
selling agents. However, its due diligence examination concerning the
partnerships cannot be considered to be independent or as comprehensive as an
investigation that would be conducted by an independent broker/dealer. (See
"Conflicts of Interest.")
16
A LENGTHY OFFERING PERIOD MAY RESULT IN DELAYS IN THE INVESTMENT OF YOUR
SUBSCRIPTION AND ANY CASH DISTRIBUTIONS FROM THE PARTNERSHIP TO YOU. Because the
offering period for a particular partnership can extend for many months, it is
likely that there will be a delay in the investment of your subscription
proceeds. This may create a delay in the partnership's cash distributions to you
which will be paid only after payment of the managing general partner's fees and
expenses and only if there is sufficient cash available. See "Terms of the
Offering" for a discussion of the procedures involved in the offering of the
units and the formation of a partnership.
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, the top four federal income tax brackets
for individuals have been reduced, including reducing the top bracket to 35%
from 38.6%, until December 31, 2010. The lower federal income tax rates will
reduce to some degree the amount of taxes you save by virtue of your share of
your partnership's deductions for intangible drilling costs, depletion, and
depreciation, and its marginal well production credits, if any. Also, the
federal income tax rates described above may be changed again before
January 1, 2011.
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 and any marginal well production credits you actually receive from a
partnership in which you invest. For example:
o if the partnership in which you invest 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 your
partnership in one tax year, although payment is not actually received
by the partnership until the next tax year;
o taxable income or gain from your partnership 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 your partnership's revenues may be expended by the managing general
partner for nondeductible 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's property or your units may
result in income tax liability to you in excess of the cash you
receive.
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 in a partnership as
a limited partner you may not have enough passive income from the partnership or
your other passive activities, if any, to use a portion or all of your passive
share of the partnership's deduction for intangible drilling costs in the year
in which you invest.
INVESTMENT INTEREST DEDUCTIONS OF INVESTOR GENERAL PARTNERS MAY BE LIMITED. If
you invest in a partnership as an investor general partner, your share of the
partnership's deduction for intangible drilling costs will reduce your
investment income and may reduce the amount of your investment interest expense,
if any.
YOUR TAX BENEFITS ARE NOT CONTRACTUALLY PROTECTED. An investment in a
partnership does not give you any contractual protection against the possibility
that part or all of the intended tax benefits of your investment will be
disallowed by the IRS. No one provides any insurance, tax indemnity or similar
agreement for the tax treatment of your investment in a partnership. You have no
right to rescind your investment in your partnership or to receive a refund of
any of your investment in the partnership if a portion or all of the intended
tax consequences of your investment in the partnership are ultimately disallowed
by the IRS or the courts. Also, none of the fees paid by your partnership to the
managing general partner, its
17
affiliates or independent third-parties (including special counsel which issued
the tax opinion letter) are refundable or contingent on whether the intended tax
consequences of your investment in a partnership are ultimately sustained.
AN IRS AUDIT OF YOUR PARTNERSHIP MAY RESULT IN AN IRS AUDIT OF YOUR PERSONAL
FEDERAL INCOME TAX RETURNS. The IRS may audit your partnership's federal
information income tax returns, particularly since all of the partnership's
investors will receive a deduction for intangible drilling costs equal to not
less than 90% of their investment amount in 2005. In addition, it is possible
that the IRS could determine in the future that natural gas and oil drilling
programs such as the partnerships are reportable transactions. In that event,
you and the other investors in your partnership and the partnership's material
advisors would all be required to disclose to the IRS that your partnership was
a reportable transaction. This would increase the risk that both your
partnership's federal information income tax returns and your personal federal
income tax returns would be audited by the IRS, including items on your returns
which are unrelated to the partnership and your returns for prior years. Also,
if the IRS were to impose a penalty on you for a reportable transaction
understatement, you could not use special counsel's tax opinion to establish
that you reasonably believed that the tax treatment of the partnership tax
item(s) that resulted in a reportable transaction understatement on your
personal federal income tax return, if any, was more likely than not the proper
tax treatment. However, if the IRS were to determine that your partnership is a
reportable transaction, that determination would have no legal effect on whether
the tax treatment for federal tax purposes of any transaction or tax item by
your partnership or you was proper or improper. (See "Material Federal Income
Tax Consequences - Disclosures and Limitation on Your Use of Special Counsel's
Tax Opinion Letter," "- Tax Returns and IRS Audits" and "- Federal Interest and
Tax Penalties.")
YOUR PARTNERSHIP DEDUCTIONS MAY BE CHALLENGED BY THE IRS. If the IRS audits your
partnership, it may challenge the amount of your partnership's deductions and
the taxable year in which the deductions were claimed, including the deductions
for intangible drilling costs and depreciation. Any adjustments made by the IRS
to your partnership's federal information income tax returns could lead to
adjustments on your personal federal income tax returns and could reduce the
amount of your deductions from your partnership in 2005 and subsequent tax
years. The IRS also could seek to recharacterize a portion of your partnership's
intangible drilling costs for drilling and completing its wells as some other
type of expense, such as lease costs or equipment costs, which would reduce or
defer your share of the partnership's deductions for those costs. (See "Material
Federal Income Tax Consequences - Business Expenses," and "- Drilling
Contracts.")
In addition, depending primarily on when its subscription proceeds are received,
it is possible that the partnership in which you invest may prepay its
investors' share of the intangible drilling costs and equipment costs for wells
the drilling of which will not begin until 2006. In that event, you will not
receive a deduction in 2005 for your share of the amount of your partnership's
prepaid intangible drilling costs for any of those prepaid wells unless the
drilling of those prepaid wells, if any, begins on or before March 31, 2006.
However, the drilling of any partnership well may be delayed due to
circumstances beyond the control of the managing general partner or the drilling
subcontractors. If for any reason the drilling of a prepaid well in your
partnership does not begin on or before March 31, 2006, deductions claimed by
you in 2005 for prepaid intangible drilling costs for that well would be
disallowed and deferred to 2006, when the well is actually drilled. Also, there
is a greater risk that the IRS will attempt to defer your 2005 deduction for
your share of your partnership's intangible drilling costs for drilling and
completing any prepaid wells to 2006 if there are other working interest owners
of those wells, because those other working interest owners will not be required
to prepay their share of the costs of drilling and completing the wells. (See
"Material Federal Income Tax Consequences - Drilling Contracts.")
ADDITIONAL INFORMATION
The program and the partnerships composing the program, other than Atlas America
Public #14-2004 L.P. which closed November 15, 2004, 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.
18
You may read and copy any materials filed as a part of the registration
statement, including the tax opinion included as Exhibit 8, at the SEC's Public
Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The SEC
maintains an internet world wide web site that contains registration statements,
reports, proxy statements, and other information about issuers who file
electronically with the SEC, including the program. The address of that site is
http://www.sec.gov. Also, you may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, a copy
of the tax opinion may be obtained by you or your advisors from the managing
general partner at no cost. The delivery of this prospectus does not imply that
its information is correct as of any time after its date.
FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS
Statements, other than statements of historical facts, included in this
prospectus and its exhibits address activities, events or developments that the
managing general partner and the partnerships anticipate will or may occur in
the future. For example, the words "believes," "anticipates," and "expects" are
intended to identify forward-looking statements. These forward-looking
statements include such things as:
o investment objectives;
o references to future success;
o business strategy;
o estimated future capital expenditures;
o competitive strengths and goals; and
o other similar matters.
These statements are based on certain assumptions and analyses made by the
partnerships and the managing general partner in light of their experience and
their perception of historical trends, current conditions, and expected future
developments. However, whether actual results will conform with these
expectations is subject to a number of risks and uncertainties, many of which
are beyond the control of the partnerships, 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 natural gas and oil prices, which could
decrease in the future.
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 with a minimum annual
cash flow of 10% during the first five years beginning with your
19
partnership's first revenue distribution based on $10,000 per unit for
all units sold. These distributions of a 10% return of capital during
the first five years are not guaranteed, but are subject to the
managing general partner's subordination obligation. The managing
general partner anticipates that investors in a partnership will begin
to receive quarterly cash distributions approximately seven months
after the offering period for the 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.
o Obtain income tax deductions from the partnership in which you invest,
in the year that you invest, from intangible drilling costs to offset
a portion of your taxable income from sources other than the
partnership, subject to the passive activity rules if you invest as a
limited partner. For example, if you pay $10,000 for a unit your
investment will produce an income tax deduction of approximately
$9,000 per unit, 90%, in the year you invest against:
o ordinary income, or capital gain in some situations, if you
invest as an investor general partner in a partnership; and
o passive income if you invest as a limited partner in a
partnership.
In 2003, the top four tax brackets for individual taxpayers were
reduced from 38.6% to 35%, 35% to 33%, 30% to 28%, and 27% to 25%.
These changes are scheduled to expire December 31, 2010. If you are in
either the 35% or 33% tax bracket, you will save approximately $3,150
or $2,970, respectively, per $10,000 unit, in federal income taxes in
the year that you invest. Most states also allow this type of a
deduction against the state income tax. If the partnership in which
you invest begins selling natural gas and oil production from its
wells in the year in which you invest, however, then you may be
allocated a share of partnership income in that year which will be
offset by a portion of your intangible drilling cost deduction and
your share of the other partnership deductions discussed below.
o Offset a portion of any gross production income generated by your
partnership with tax deductions from percentage depletion, which is
15% in 2005. The percentage depletion rate may fluctuate from year to
year depending on the price of oil, but under current tax law it will
not be less than the statutory rate of 15% nor more than 25%.
o Obtain income tax deductions of the remaining 10% of your investment
over a seven-year cost recovery period, beginning in the year the
wells are drilled, completed and placed in service for production of
natural gas or oil. For example, if you pay $10,000 for a unit, you
will receive additional income tax deductions which total
approximately $1,000 per unit, in the aggregate, over the seven-year
cost recovery period for depreciation of your partnership's equipment
costs for its productive wells.
o If you are self-employed and invest in a partnership as an investor
general partner, then you may use your share of the partnership's
deduction for intangible drilling costs to offset a portion of your
net earnings from self-employment in the year you invest.
Attainment of these investment objectives by a partnership will depend on many
factors, including the ability of the managing general partner to select
suitable wells that will be productive and produce enough revenue to return the
investment made. The success of each partnership depends largely on future
economic conditions, especially the future price of natural gas which is
volatile and may decrease. Also, the extent to which each partnership attains
the foregoing investment objectives will be different, because each partnership
is a separate business entity which:
o generally will drill different wells;
o will likely receive a different amount of subscription proceeds, which
generally will be the primary factor in determining the number of
wells that can be drilled by each partnership; and
20
o may drill wells situated in different geographical areas, where the
wells will be drilled to different formations, reservoirs or depths,
which will affect the cost of the wells and, thus, will also affect
the number of wells that can be drilled by each partnership.
There can be no guarantee that the foregoing objectives will be attained.
ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS
You may choose to invest in a partnership as an investor general partner so that
you can receive an immediate tax deduction against any type of income. To help
reduce the risk that you and other investor general partners could be required
to make additional payments to the partnership, the managing general partner
will take the actions set forth below.
o INSURANCE. The managing general partner will obtain and maintain
insurance coverage in amounts and for purposes which would be carried
by a reasonable, prudent general contractor and operator in accordance
with industry standards. Each partnership will be included as an
insured under these general, umbrella, and excess liability policies.
In addition, the managing general partner requires all of its
subcontractors to certify that they have acceptable insurance coverage
for worker's compensation and general, auto, and excess liability
coverage. Major subcontractors are required to carry general and auto
liability insurance with a minimum of $1 million combined single limit
for bodily injury and property damage in any one occurrence or
accident. In the event of a loss caused by a major subcontractor, the
managing general partner or partnership may attempt to draw on the
insurance policy of the particular subcontractor before the insurance
of the managing general partner or that of the partnership, but
currently would be unable to do so since none of its major
subcontractors have insurance which would allow this. Also, even if a
major subcontractor's insurance was initially available, the managing
general partner or partnership may choose to draw on its own insurance
coverage before that of the major subcontractor so that its insurance
carrier will control the payment of claims.
The managing general partner's current insurance coverage satisfies
the following specifications:
o worker's compensation insurance in full compliance with the laws
of the Commonwealth of Pennsylvania and any other applicable
state laws where the wells will be drilled;
o commercial general liability covering bodily injury and property
damage third party liability, including products/completed
operations, blow out, cratering, and explosion with limits of $1
million per occurrence/$2 million general aggregate; and $1
million products/completed operations aggregate;
o underground resources and equipment property damages liability to
others with a limit of $1 million;
o automobile liability with a $1 million combined single limit;
o employer's liability with a $500,000 policy limit;
o pollution liability resulting from a "pollution incident," which
is defined as the discharge, dispersal, seepage, migration,
release or escape of one or more pollutants directly from a well
site, with a limit of $1 million for bodily injury and property
damage and a limit of $100,000 for clean-up for third-parties;
however, coverage does not apply to pollution damage to the well
site itself or the property of the insured;
21
o commercial umbrella liability composed of:
o primary umbrella limit of $25 million over general
liability, automobile liability, and employer's liability
and a $10 million sublimit for pollution liability; and
o excess liability providing excess limits of $24 million over
the $25 million provided in the commercial umbrella, but
excluding pollution liability.
Because the managing general partner is driller and operator of other
partnerships, the insurance available to each partnership could be
substantially less if insurance claims are made in the other
partnerships.
This insurance has deductibles, which would first have to be paid by a
partnership, of:
o $2,500 per occurrence for bodily injury and property damage; and
o $10,000 per pollution incident for pollution damage.
The insurance 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 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 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 and conversion will occur no more than 12
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 by a partnership will be repaid from that
partnership's revenues.
The amount that may be borrowed at any one time by a partnership may
not exceed an amount equal to 5% of the investors' 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.
22
o INDEMNIFICATION. The managing general partner will indemnify you from
any liability incurred in connection with your partnership that is in
excess of your interest in the partnership's:
o undistributed net assets; and
o insurance proceeds, if any, from all potential sources.
The managing general partner's indemnification obligation, however,
will not eliminate your potential liability if the managing general
partner's assets are insufficient to satisfy its indemnification
obligation. There can be no assurance that the managing general
partner's assets, including its liquid assets, will be sufficient to
satisfy its indemnification obligation.
CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS
SOURCE OF FUNDS
Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of both partnerships, in the aggregate, may
not exceed $72,430,500, which is the remaining portion of the unsold units from
the original $125 million registration. 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. In this regard, the managing general partner has the
discretion to accept subscriptions for the entire $72,430,500 in Atlas America
Public #14-2005(A) L.P. and not offer and sell any units in Atlas America Public
#14-2005(B) L.P. (See "Terms of the Offering - Subscription to a Partnership.")
On completion of an offering for a partnership, the partnership's source of
funds will be as follows assuming each unit is sold for $10,000:
o the subscription proceeds of you and the other investors, which will
be:
o $2 million if 200 units are sold; and
o $72,430,500 if 7,243.05 units are sold; and
o the managing general partner's capital contribution, which must be at
least 25% of all capital contributions, and includes its credit for
organization and offering costs and contributing the leases, which
will be:
o not less than $500,000 if 200 units are sold; and
o not less than $18,107,625 if 7,243.05 units are sold.
Thus, the total amount available to a partnership will be not less than
$2,500,000 if 200 units are sold ranging to not less than $90,538,125 if
7,243.50 units are sold.
The managing general partner has made the largest single capital contribution in
each of its prior partnerships and no individual investor has contributed more,
although the total investor contributions in each partnership have exceeded the
managing general partner's contribution. The managing general partner expects to
make the largest single capital contribution in each of the partnerships.
USE OF PROCEEDS
The subscription proceeds received from you and the other investors for a
partnership will be used to pay:
o 100% of the intangible drilling costs of drilling and completing that
partnership's wells; and
23
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 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 which would otherwise be charged to you and the other
investors.
The managing general partner also will be charged with 100% of the organization
and offering costs for each partnership. A portion of these contributions to
each partnership will be in the form of payments to itself, its affiliates and
third-parties and the remainder will be in the form of services related to
organizing this offering. The managing general partner will receive a credit
towards its required capital contribution to each partnership for these payments
and services as discussed in "Participation in Costs and Revenues."
The following tables present information concerning each partnership's use of
the proceeds provided by both you and the other investors and the managing
general partner. The tables are based in part on the managing general partner's
estimate of its capital contribution to a partnership based on the applicable
number of units sold as shown in the table. The managing general partner's
estimated capital contribution shown in the tables includes its credit for
organization and offering costs and contributing the leases, and exceeds in each
case its required capital contribution of not less than 25% of all capital
contributions for a partnership. Anthem Securities, an affiliate of the managing
general partner, will be the dealer-manager and it will receive the
dealer-manager fee, the sales commissions, the .5% accountable reimbursement for
permissible non-cash compensation, and the .5% reimbursement for bona fide
accountable due diligence expenses. A portion of these payments and
reimbursements, including all of the sales commissions and the .5% reimbursement
for bona fide accountable due diligence expenses, will be reallowed by the
dealer-manager to the broker/dealers, which are referred to as selling agents,
as discussed in "Plan of Distribution." Subject to the above, the organizational
costs will be paid to the managing general partner, its affiliates and various
third-parties, and the intangible drilling costs and tangible costs will be paid
to the managing general partner as general drilling contractor and operator
under the drilling and operating agreement.
The tables are presented based on:
o the sale of 200 units ($2 million), which is the minimum number of
units for each partnership; and
o the sale of 7,243.05 units, which are all of the remaining unsold
units from the original 12,500 units ($125 million) registered.
Substantially all of the proceeds available to each partnership will be expended
for the following purposes and in the following manner:
24
INVESTOR CAPITAL
200 7,243.05
UNITS UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1)
- -------------------------------------------------------------------- ------------- ------ ------------- -----
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions, .5% accountable
reimbursement for permissible non-cash compensation, and up to .5%
reimbursement for bona fide accountable due diligence expenses .... - 0 - - 0 - - 0 - - 0 -
Organization costs ................................................. - 0 - - 0 - - 0 - - 0 -
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs (2) ...................................... $ 1,800,000 90% $ 65,187,450 90%
Equipment costs (2) ................................................ $ 200,000 10% $ 7,243,050 10%
Leases ............................................................. - 0 - - 0 - - 0 - - 0 -
------------- ------ ------------- ------
TOTAL INVESTOR CAPITAL ............................................. $ 2,000,000 100% $ 72,430,500 100%
============= ====== ============= ======
- ----------
(1) The percentage is based on total investor subscription proceeds and
excludes the managing general partner's capital contribution.
(2) 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. 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 the investors' subscription proceeds as
discussed in "Participation in Costs and Revenues." Because the actual
costs are not known, this table assumes that the maximum 10% of the
investors' subscription proceeds is used to pay equipment costs in order to
avoid the possibility of overstating the amount of currently deductible
intangible drilling costs charged to the investors. In contrast, the
managing general partner's share of equipment costs in the "- Managing
General Partner Capital" and the "- Total Partnership Capital" tables below
is based on the managing general partner's estimate of the average cost of
drilling and completing wells in the partnership's primary areas as
discussed in "Compensation - Drilling Contracts." In making this estimate,
the managing general partner determined that the investors' share of the
equipment costs would exceed the 10% limit set forth above if all of the
equipment costs were charged 34% to the investors and 66% to the managing
general partner. Thus, in the "- Managing General Partner Capital" and the
"-Total Partnership Capital" tables below, the managing general partner was
allocated more than 66% of the total estimated equipment costs and the
investors' share of the total estimated equipment costs was limited to 10%
of the investors' subscription proceeds.
MANAGING GENERAL PARTNER CAPITAL
200 7,243.05
UNITS UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1)
- -------------------------------------------------------------------- ------------- ------ ------------- -----
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions, .5% accountable
reimbursement for permissible non-cash compensation, and up to .5%
reimbursement for bona fide accountable due diligence expenses (2). $ 210,000 21.23% $ 7,605,202 21.51%
Organization costs (2) ............................................. $ 90,000 9.10% $ 1,073,700 3.03%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs .......................................... - 0 - - 0 - - 0 - - 0 -
Equipment costs (3) ................................................ $ 642,024 64.91% $ 24,623,080 69.63%
Leases (4) ......................................................... $ 47,088 4.76% $ 2,061,408 5.83%
------------- ------ ------------- ------
TOTAL MANAGING GENERAL PARTNER CAPITAL ............................. $ 989,112 100% $ 35,363,390 100%
============= ====== ============= ======
25
- ----------
(1) The percentage is based on the managing general partner's capital
contribution and excludes the investors' subscription proceeds.
(2) As discussed in "Participation in Costs and Revenues," if these fees, sales
commissions, reimbursements and organization costs exceed 15% of the
investors' subscription proceeds in a partnership, then the excess will be
charged to the managing general partner, but will not be included as part
of its capital contribution.
(3) The managing general partner's share of equipment costs is described in
"Compensation - Drilling Contracts." However, these costs will vary
depending on the actual costs of drilling and completing the wells. Also,
see footnote (2) to the "- Investor Capital" table above.
(4) Instead of contributing cash for the leases, the managing general partner
will assign to each partnership the leases covering the acreage on which
the partnership's wells will be drilled. Generally, as described in
"Compensation - Lease Costs," the managing general partner's lease cost is
approximately $5,232 per prospect and for purposes of this table the
managing general partner's lease costs have been quantified using this
amount based on its estimate of the number of net wells that will be
drilled. However, the managing general partner's lease costs on a prospect
may be significantly higher than the above-referenced amount, and its
credit for the leases contributed will equal its cost, unless it has a
reason to believe that cost is materially more than fair market value of
the property, in which case its credit for its lease contribution must not
exceed fair market value.
TOTAL PARTNERSHIP CAPITAL
200 7,243.05
UNITS UNITS
NATURE OF PAYMENT SOLD % (1) SOLD % (1)
- -------------------------------------------------------------------- ------------- ------ ------------- -----
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions, .5% accountable
reimbursement for permissible non-cash compensation, and up to .5%
reimbursement for bona fide accountable due diligence expenses (2). $ 210,000 7.03% $ 7,605,202 7.06%
Organization costs (2) ............................................. $ 90,000 3.01% $ 1,073,700 1.00%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs (3) ...................................... $ 1,800,000 60.22% $ 65,187,450 60.47%
Equipment costs (3) ................................................ $ 842,024 28.17% $ 31,866,130 29.56%
Leases (4) ......................................................... $ 47,088 1.57% $ 2,061,408 1.91%
------------- ------ ------------- ------
TOTAL PARTNERSHIP CAPITAL .......................................... $ 2,989,112 100% $ 107,793,890 100%
============= ====== ============= ======
- ----------
(1) The percentage is based on total investor subscription proceeds and the
managing general partner's estimate of its capital contributions.
(2) As discussed in "Participation in Costs and Revenues," if these fees, sales
commissions, reimbursements and organization costs exceed 15% of the
investors' subscription proceeds in a partnership, then the excess will be
charged to the managing general partner, but will not be included as part
of its capital contribution.
(3) The managing general partner's share of equipment costs is described in
"Compensation - Drilling Contracts." However, 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, above.
(4) Instead of contributing cash for the leases, the managing general partner
will assign to each partnership the leases covering the acreage on which
the partnership's wells will be drilled. Generally, as described in
"Compensation - Lease Costs," the managing general partner's lease cost is
approximately $5,232 per prospect and for purposes of this table the
managing general partner's lease costs have been quantified using this
amount based on its estimate of the number of net wells that will be
drilled. However, the managing general partner's lease costs on a prospect
may be significantly higher than the above-referenced amount, and its
credit for the leases contributed will equal its cost, unless it has a
reason to believe that cost is materially more than fair market value of
the property, in which case its credit for its lease contribution must not
exceed fair market value.
26
COMPENSATION
The items of compensation to be paid to the managing general partner and its
affiliates from each partnership are set forth below. Most of these items of
compensation depend on how many wells a partnership drills and how much of the
working interest in each of the wells is owned by the partnership. In this
regard, the managing general partner estimates that approximately nine gross and
net wells will be drilled if the minimum required subscription proceeds of $2
million are received by a partnership, and approximately 407 gross wells, which
will be approximately 394 net wells, will be drilled, in the aggregate, if
subscription proceeds of $72,430,500 are received by a partnership or the
partnerships. A gross well is a well in which a partnership owns a working
interest. This is compared with a net well which is the sum of the fractional
working interests owned in the gross wells. For example, a 50% working interest
owned in three wells is three gross wells, but 1.5 net wells. However, the
managing general partner's estimate set forth above of the number of wells to be
drilled is subject to risks which can cause actual results to vary. (See "Risk
Factors - Risks Related to an Investment in a Partnership - The Partnerships Do
Not Own Any Prospects, the Managing General Partner Has Complete Discretion to
Select Which Prospects are Acquired By a Partnership, and The Possible Lack of
Information for a Majority of the Prospects Decreases Your Ability to Evaluate
the Feasibility of a Partnership.")
NATURAL GAS AND OIL REVENUES
Subject to the managing general partner's subordination obligation, the
investors and the managing general partner will share in each partnership's
revenues in the same percentages as their respective capital contributions bear
to the total partnership capital contributions for that partnership except that
the managing general partner will receive an additional 7% of that partnership's
revenues. However, the managing general partner's total revenue share may not
exceed 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.
As noted above, the managing general partner's revenue share from each
partnership is subject to its subordination obligation as described in
"Participation in Costs and Revenues - Subordination of Portion of the Managing
General Partner's Net Revenue Share" and the accompanying tables. For example,
if the managing general partner's revenue share is 35% of the partnership
revenues, then up to 17.5% of the managing general partner's partnership net
revenues could be used for its subordination obligation.
LEASE COSTS
Under the partnership agreement the managing general partner will contribute to
each partnership all the undeveloped leases necessary to cover each of the
partnership's prospects. The managing general partner will receive a credit to
its capital account equal to:
o the cost of the leases; or
o the fair market value of the leases if the managing general partner
has reason to believe that cost is materially more than the fair
market value.
The cost of the leases will include a portion of the managing general partner's
reasonable, necessary, and actual expenses for services allocated to a
partnership's leases by it using industry guidelines.
In the primary areas of interest, the managing general partner's lease cost is
approximately $5,232 per prospect assuming a partnership acquires 100% of the
working interest in the prospect, although from time to time the managing
general partner's lease costs on a prospect may be significantly higher than
this amount. The managing general partner's credit for lease costs will be
proportionally reduced to the extent a partnership acquires less than 100% of
the working interest in the prospect. In
27
this regard, a working interest generally means an interest in the lease under
which the owner of the working interest must pay some portion of the cost of
development, operation, or maintenance of the well. Assuming all the leases are
situated in these areas, the managing general partner estimates that its credit
for lease costs will be:
o $47,088 if $2 million is received, which is nine net wells times
$5,232 per prospect; and
o $2,061,408 if $72,430,500 is received, which is 394 net wells times
$5,232 per prospect.
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 each partnership's 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 2002 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 2002.
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 its general and
administrative overhead as discussed below. This amount will be proportionately
reduced to the extent a partnership acquires less than 100% of the working
interest in the prospect. The cost of the well also includes all ordinary costs
of drilling, testing and completing the well. This includes the cost of the
following for a natural gas well, which will be the classification of the
majority of the wells:
o multiple completions, which means, in general, treating separately all
potentially productive geological formations in an attempt to enhance
the 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 where the wells
are drilled and their depths, the method used to complete the well, and the
number of wells drilled.
28
Assuming the maximum subscription proceeds of $72,430,500 are received, the
managing general partner anticipates that the partnerships' weighted average
cost of drilling and completing approximately 394 net wells, excluding lease
costs, will be approximately $246,300 per net well, which includes reimbursement
to the managing general partner of the investors' share of its general and
administrative overhead of approximately $12,690, as described below. This
estimate was based on:
o the number of wells that the managing general partner estimates will
be drilled in each area;
o the percentage of working interest that the managing general partner
anticipates the partnerships will acquire in the prospects in each
area; and
o the associated estimated drilling and completion costs, which are
different for each area based primarily on different depths and
completion methods.
Thus, the managing general partner's estimated weighted average cost of drilling
and completing one net well as set forth above, in all likelihood, will vary
from the actual average cost of the wells in each of the primary areas.
Based on the assumptions and the estimated weighted average cost for one net
well as set forth above, the managing general partner expects that its 15%
profit will be approximately $23,976 per net well with respect to the intangible
drilling costs and the portion of equipment costs paid by you and the other
investors. In making this estimate, the managing general partner further assumed
that the investors' 34% share of the equipment costs would be reduced so that it
would not exceed the limit of 10% of investor subscription proceeds as discussed
in footnote (2) to the "- Investor Capital" table in "Capitalization and Source
of Funds and Use of Proceeds." For this reason and because the managing general
partner anticipates that the partnerships will not acquire 100% of the working
interest in some of their respective prospects, the managing general partner
estimates that the investors' share of its reimbursement for general and
administrative overhead will be a weighted average of approximately $12,690 for
one net well, rather than the maximum of $12,780 per well assuming a 34% share
of the equipment costs and a 100% working interest in the well. The actual
compensation received by the managing general partner as a result of each
partnership's drilling operations will vary from these estimates, but the
managing general partner's profit will not in any event exceed 15% of the costs
of drilling and completing the wells. Also, to the extent that a partnership
acquires less than a 100% working interest in a well, its drilling and
completion costs of that well will be proportionately decreased.
Subject to the foregoing, the managing general partner estimates that its
general and administrative overhead reimbursement of approximately $12,690 and
profit of 15% (approximately $23,976) for one net well, which totals $36,666,
will be:
o $329,994 if $2 million is received, which is 9 net wells times
$36,666; and
o $14,446,404 if $72,430,500 is received, which is 394 net wells times
$36,666.
The managing general partner's estimated weighted average cost of $246,300 for
one net well as discussed above consists of:
o intangible drilling costs of approximately $165,431 (67.2%); and
o equipment costs of approximately $80,869 (32.8%).
In this regard, the managing general partner further anticipates that a
partnership's cost of drilling and completing any given well in the
partnerships' primary areas as described in "Proposed Activities," excluding
lease costs, may range from as low as approximately $120,000 to as high as
$350,000 or more, depending on the area.
PER WELL CHARGES
Under the drilling and operating agreement the managing general partner, as
operator of the wells, will receive the following from each partnership when the
wells begin producing:
o reimbursement at actual cost for all direct expenses incurred on
behalf of the partnership; and
29
o well supervision fees for operating and maintaining the wells during
producing operations at a competitive rate.
Currently the competitive rate for well supervision fees is $285 per well per
month in the primary and secondary areas. The well supervision fees will be
proportionately reduced to the extent the partnership acquires less than 100% of
the working interest in the well, and may be adjusted for inflation annually
beginning with the second calendar year after a partnership closes. If in the
future the foregoing rate exceeds competitive rates available from other
non-affiliated persons in the area engaged in the business of providing
comparable services or equipment, then the rate will be adjusted to the
competitive rate. The managing general partner may not benefit by
interpositioning itself between the partnership and the actual provider of
operator services. In no event will any consideration received for operator
services be duplicative of any consideration or reimbursement received under the
partnership agreement.
The well supervision fees cover 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 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 $30,780 if $2 million is received, which is nine net wells at $285 per
well per month; and
o $1,347,480 if $72,430,500 is received, which is 394 net wells at $285
per well per month.
GATHERING FEES
Under the partnership agreement the managing general partner will be responsible
for gathering and transporting the natural gas produced by the partnerships to
interstate pipeline systems, local distribution companies, and/or end-users in
the area. The managing general partner anticipates that it will use the
gathering system owned by Atlas Pipeline Partners for the majority of the
natural gas as described in "Proposed Activities - Sale of Natural Gas and Oil
Production - Gathering of Natural Gas." The managing general partner's
affiliate, Atlas America, Inc., which is sometimes referred to in this
prospectus as "Atlas America," or another affiliate controls and manages the
gathering system for Atlas Pipeline Partners. Also, Atlas America and the
managing general partner's affiliates, Resource Energy, Inc., sometimes referred
to in this prospectus as "Resource Energy," and Viking Resources Corporation,
sometimes referred to in this prospectus as "Viking Resources," (the "Resource
Entities"), which do not include the partnerships, have an agreement with Atlas
Pipeline Partners which provides that generally all of the gas produced by their
affiliated partnerships, which includes each partnership composing the program,
will be gathered and transported through the gathering system owned by Atlas
Pipeline Partners and that the Resource Entities must pay the greater of $.35
per mcf or 16% of the gross sales price for each mcf transported by these
affiliated partnerships through Atlas Pipeline Partners' gathering system.
30
Each partnership will pay a gathering fee directly to the managing general
partner at competitive rates. If the gathering system owned by Atlas Pipeline
Partners is used by the partnership, the managing general partner will apply the
gathering fee it receives towards the payments owed by the Resource Entities
under their agreement with Atlas Pipeline Partners. If a third-party gathering
system is used, the managing general partner will pay a portion or all of its
gathering fee to the third-party gathering the natural gas. If a gathering
system owned by the managing general partner or its affiliates other than Atlas
Pipeline Partners is used, then the managing general partner or its affiliates
will receive, or retain in the case of the managing general partner, the
gathering fee paid to the managing general partner.
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.
CURRENT AMOUNT OF GATHERING FEES
EACH PARTNERSHIP'S PRIMARY TO BE PAID BY EACH PARTNERSHIP TO
AND SECONDARY DRILLING AREAS MANAGING GENERAL PARTNER (1)
------------------------ ---------------------------------
Clinton/Medina Geological Formation in Western Pennsylvania in Crawford,
Mercer, Lawrence, Warren, and Venango Counties, and Eastern Ohio
primarily in Stark, Mahoning, Trumbull and Portage Counties ............ $ .29 per mcf
Mississippian/Upper Devonian Sandstone Reservoirs in
Fayette and Greene Counties, Pennsylvania............................... $ .35 per mcf
Upper Devonian Sandstone Reservoirs in
Armstrong County, Pennsylvania.......................................... (2)
Upper Devonian Sandstone Reservoirs in
McKean County, Pennsylvania............................................. $ .70 per mcf (3)
Mississippian and Devonian Shale Reservoirs in Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee..................................... (4)
Clinton/Medina Geological Formation in New York............................. $ .35 per mcf
Clinton/Medina Geological Formation in Southern Ohio........................ $ .35 per mcf
- ----------
(1) The gathering fee paid by each partnership must not exceed a competitive
rate as determined by the managing general partner, and the managing
general partner may increase or decrease the gathering fee to a competitive
rate from time to time 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 natural gas. If the managing general partner markets the
natural gas for the partnership, then the partnership will pay a gathering
fee to the managing general partner equal to that charged by the
third-party, which the managing general partner anticipates will be $.20
per mcf.
(3) A partnership will deliver natural gas produced in this area into a
gathering system, a segment of which will be provided by Atlas Pipeline
Partners and a segment of which will be provided by a third-party. The
third-party will receive fees of $.25 per mcf for transportation and $.10
per mcf for compression. From the gathering fees charged the partnership by
the managing general partner, the managing general partner will pay $.35
per mcf to the third-party and $.35 per mcf to Atlas Pipeline Partners.
(4) In this area, a partnership will deliver natural gas into a gathering
system provided by Knox Energy, which is referred to as the Coalfield
Pipeline. See "Proposed Activities - Interest of Parties." The Coalfield
Pipeline will receive gathering fees of $.55 per mcf plus fees for
compression. If the Coalfield Pipeline does not have sufficient capacity to
compress and transfer the natural gas produced from a partnership's wells
as determined by Atlas America, then Atlas America or an affiliate other
than Atlas Pipeline Partners will construct an additional gathering system
and/or enhancements to the Coalfield Pipeline. On completion of the
construction, Atlas America will transfer its ownership
31
in the additional gathering system and/or enhancements to the owners of the
Coalfield Pipeline, which will then pay Atlas America an amount equal to
$.12 per mcf of natural gas transported through the newly constructed
and/or enhanced gathering system. Also, if Atlas America or an affiliate
(which may or may not be Atlas Pipeline Partners) constructs any other
gathering or pipeline system, in addition to the gathering system described
above to connect to the Coalfield Pipeline gathering system, then Atlas
America may receive a competitive gathering fee.
The actual amount of gathering fees to be paid by a partnership to the managing
general partner cannot be quantified because the volume of natural gas that will
be produced and transported from the partnership's wells cannot be predicted.
DEALER-MANAGER FEES
Subject to certain exceptions described in "Plan of Distribution," Anthem
Securities, the dealer-manager and an affiliate of the managing general partner,
will receive on each unit sold to an investor:
o a 2.5% dealer-manager fee;
o a 7% sales commission;
o a .5% reimbursement for accountable permissible non-cash compensation;
and
o an up to .5% reimbursement of the selling agents' bona fide
accountable due diligence expenses.
Assuming the above amounts are paid for all units sold, the dealer-manager will
receive:
o $210,000 if $2 million is received by a partnership; and
o $7,605,202.50 if $72,430,500 is received by the partnerships.
All of the reimbursement of the selling agents' bona fide accountable due
diligence expenses, and generally all of the accountable permissible non-cash
compensation reimbursement and sales commissions, will be reallowed to the
selling agents. Most of the 2.5% dealer-manager fee will be reallowed to the
wholesalers who are associated with the managing general partner and registered
through Anthem Securities for subscriptions obtained through their efforts. The
dealer-manager will retain any of the compensation which is not reallowed. See
"Management" for the ownership of Anthem Securities.
INTEREST AND OTHER COMPENSATION
The managing general partner or an affiliate will have the right to charge a
competitive rate of interest on any loan it may make to or on behalf of a
partnership. If the managing general partner provides equipment, supplies, and
other services to a partnership, then it may do so at competitive industry
rates. The managing general partner will determine a competitive rate of
interest and competitive industry rates for equipment, supplies and other
services by conducting a survey of the interest and/or fees charged by
unaffiliated third-parties in the same geographic area engaged in similar
businesses. If possible, the managing general partner will contact at least two
unaffiliated third-parties, however, the managing general partner will have sole
discretion in determining the amount to be charged a partnership.
ESTIMATE OF ADMINISTRATIVE COSTS AND DIRECT COSTS TO BE BORNE BY THE
PARTNERSHIPS
The managing general partner and its affiliates will receive from each
partnership an unaccountable, fixed payment reimbursement for their
administrative costs, which has been determined by the managing general partner
to be $75 per well per month. This payment per well is subject to the following:
o it will not be increased in amount during the term of the partnership;
o it will be proportionately reduced to the extent the partnership
acquires less than 100% of the working interest in the well;
32
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 $8,100 if $2 million is received, which is nine net wells at $75 per
well per month; and
o $354,600 if $72,430,500 is received, which is 394 net wells at $75 per
well per month.
Direct costs will be determined by the managing general partner, in its sole
discretion, including the provider of the services or goods and the amount of
the provider's compensation. Direct costs will be billed directly to and paid by
each partnership to the extent practicable. The anticipated direct costs set
forth below for a partnership's first 12 months of operation after all of its
wells have been placed into production may vary from the estimates shown for
numerous reasons which cannot accurately be predicted. These reasons include:
o the number of investors;
o the number of wells drilled;
o the partnership's degree of success in its activities;
o the extent of any production problems;
o inflation; and
o various other factors involving the administration of the partnership.
Minimum Maximum
Subscriptions Subscriptions
of $2 million of $72,430,500 (1)
------------- ------------------
DIRECT COSTS
External Legal................................... $ 6,000 $ 10,000
Accounting Fees for Audit and Tax Preparation.... 42,000 73,000
Independent Engineering Reports.................. 1,500 23,000
--------- -----------
TOTAL ........................................... $ 49,500 $ 106,000
========= ===========
- ----------
(1) This assumes two partnerships are formed as described below in "Terms of
the Offering - Subscription to a Partnership" and the targeted nonbinding
subscriptions of each partnership are received.
TERMS OF THE OFFERING
SUBSCRIPTION TO A PARTNERSHIP
Atlas America Public #14-2004 Program was formed to offer for sale an aggregate
of $125 million of units in a series of up to three limited partnerships formed
under the Delaware Revised Uniform Limited Partnership Act. The first
partnership in the program, Atlas America Public #14-2004 L.P., was completed on
November 15, 2004 for $52,506,570, which included units sold on a discounted
basis as described in "Plan of Distribution." Thus, the total maximum
subscriptions remaining from the original $125 million, based on the number of
units previously sold, are $72,430,500, which is 7,243.05 units at $10,000 per
unit assuming no units are sold at the discounted prices described in "Plan of
Distribution." The units will be
33
offered for sale over a period which may extend from the date of this prospectus
up to December 31, 2005, but may end earlier.
The minimum required aggregate subscription proceeds for the offering of units
in each partnership will be $2 million after the discounts described in "Plan of
Distribution" and excluding any subscriptions by the managing general partner or
its affiliates. If this minimum amount of aggregate subscriptions is not
received in the offering of units of any partnership by its offering termination
date, 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
deduction for any fees from the escrowed funds.
Set forth below are the targeted subscriptions for each partnership, although
these targeted amounts are not mandatory and the managing general partner may
determine the subscription amount for each partnership in its sole discretion,
including selling all of the units in Atlas America Public #14-2005(A) L.P. and
not offering and selling any units in Atlas America Public #14-2005(B) L.P. The
maximum subscription of any partnership must be the lesser of:
o $72,430,500; or
o the number of units remaining unsold from the above amount.
Also, the targeted ending dates for each partnership, which are not binding on
the partnerships except that the units in each partnership may not be offered
beyond that partnership's offering termination date, are set forth below.
Otherwise the managing general partner may close the offering of units in a
partnership before its offering termination date or withdraw the offering of
units in the partnership at any time.
REQUIRED TARGETED TARGETED OFFERING
PARTNERSHIP MINIMUM SUBSCRIPTION ENDING TERMINATION
NAME SUBSCRIPTION PROCEEDS (1) DATE (1) DATE (1)
------------------------------- ------------ ------------ -------- -----------
Atlas America Public #14-2005(A) $ 2 million $ 35 million 03/31/05 12/31/05
Atlas America Public #14-2005(B) $ 2 million $ 37,430,500 08/31/05 12/31/05
o The units in the above partnerships will be sold only during 2005.
- ----------
(1) The managing general partner may close the subscription period of any
partnership at any time once the partnership is in receipt of the minimum
required subscription proceeds.
Units are offered at a subscription price of $10,000 per unit, subject to
certain exceptions which are described in "Plan of Distribution," and must be
paid 100% in cash at the time of subscribing. The subscription price of the
units has been arbitrarily determined by the managing general partner because
the partnerships do not have any prior operations, assets, earnings, liabilities
or present value. Your minimum subscription is one unit; however, the managing
general partner, in its discretion, may accept one-half unit ($5,000)
subscriptions from you at any time in each partnership. Larger fractional
subscriptions will be accepted in $1,000 increments, beginning with either
$11,000, $12,000, etc. if you pay $10,000 for a full unit or $6,000, $7,000,
etc. if you pay $5,000 for a one-half unit.
You will have the election to purchase units in a partnership as either an
investor general partner or a limited partner. However, the managing general
partner will have exclusive management authority for each partnership. Each
partnership will be a separate business entity from the other partnerships.
Thus, as an investor, you will be a partner only in the partnership in which you
invest. You will have no interest in the business, 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.
34
PARTNERSHIP CLOSINGS AND ESCROW
Subscription proceeds for each partnership will be held in a separate interest
bearing escrow account at National City Bank of Pennsylvania until receipt of
the minimum subscription proceeds. A partnership may not break escrow unless the
partnership is in receipt of subscription proceeds of $2 million after the
discounts described in "Plan of Distribution" and excluding any subscriptions by
the managing general partner or its affiliates. However, on receipt of the
minimum subscription proceeds and written instructions to the escrow agent from
the managing general partner and the dealer-manager, the managing general
partner on behalf of a partnership may:
o break escrow; and
o transfer the escrowed funds to a partnership account and begin
drilling operations as set forth in "- Activation of the
Partnerships," below.
If the minimum subscription proceeds are not received by the offering
termination date of a partnership, then the sums deposited in the escrow account
will be promptly returned to you and the other subscribers in that partnership
with interest and without deduction for any fees. In this regard, the latest
offering termination date is December 31, 2005 for both Atlas America Public
#14-2005(A) L.P., and Atlas America Public #14-2005(B) L.P. Although the
managing general partner and its affiliates may buy up to 5% 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 subscription proceeds
required for a partnership to break escrow and begin operations.
You will receive interest on your subscription proceeds from the time they are
deposited in the escrow account, or the partnership account if you subscribe
after the minimum subscription proceeds have been received and escrow has been
broken, until the final closing of the partnership to which you subscribed. The
interest will be paid to you not later than your partnership's first cash
distribution from operations.
During each partnership's escrow period its subscription proceeds will be
invested only in institutional investments comprised of or secured by securities
of the United States government. After the funds are transferred to 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 "Atlas
America Public #14-2005(A) L.P., Escrow Agent, National City Bank of PA," or
"Atlas America Public #14-2005(B) L.P., Escrow Agent, National City Bank of PA,"
as appropriate, and give your check to your broker/dealer for submission to the
dealer-manager and escrow agent. 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 subscription proceeds
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.
Also, the managing general partner will:
35
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.
Thus, you have five business days to rescind your purchase after you receive the
final prospectus and execute your subscription agreement. To rescind or withdraw
your offer, you must give written notice to the managing general partner before
your offer is accepted by the managing general partner. As noted above, the
managing general partner will not complete any sale to you until at least five
business days after the date you receive a final prospectus. Subject to that
condition, 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:
o before breaking escrow, then you will be admitted to the partnership
to which you subscribed not later than 15 days after the release from
escrow of the investors' funds to that partnership; and
o after breaking escrow, then you will be admitted to the partnership to
which you subscribed not later than the last day of the calendar month
in which your subscription was accepted by that partnership.
Your execution of the subscription agreement and the managing general partner's
acceptance also constitutes your:
o execution of the partnership agreement and agreement to be bound by
its terms as a partner; and
o grant of a special power of attorney to the managing general partner
to file amended certificates of limited partnership and governmental
reports, and perform certain other actions on behalf of you and the
other investors.
ACTIVATION OF THE PARTNERSHIPS
The managing general partner has organized each partnership under the Delaware
Revised Uniform Limited Partnership Act. (See "Financial Information Concerning
the Managing General Partner and Atlas America Public #14-2005(A) L.P.") After
the initial closing of a partnership and the transfer of the escrowed funds to a
partnership account, the managing general partner on behalf of a partnership
may:
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 in
this prospectus or by a supplement or an amendment to the registration
statement of which this prospectus is a part.
SUITABILITY STANDARDS
IN GENERAL. It is the obligation of persons selling the units to make every
reasonable effort to assure that the units are suitable for you based on your
investment objectives and financial situation, regardless of your income or net
worth. However, you should invest in a partnership only if you are willing to
assume the risk of a speculative, illiquid, and long-term investment. Also,
subscriptions to a partnership will not be accepted from IRAs, Keogh plans and
qualified retirement plans because the partnership's income would be
characterized as unrelated business taxable income, which is subject to federal
income tax.
The decision to accept or reject your subscription will be made by the managing
general partner, in its sole discretion, and is final. The managing general
partner will not accept your subscription until it has reviewed your apparent
qualifications, and
36
the suitability determination must be maintained by the managing general partner
during the partnership's term and for at least six years thereafter.
GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS. If you
are a resident of any of the following states or jurisdictions:
o ALABAMA, o KANSAS, o OHIO,
o ALASKA, o KENTUCKY, o OKLAHOMA,
o ARIZONA, o LOUISIANA, o OREGON,
o ARKANSAS, o MAINE, o PENNSYLVANIA,
o COLORADO, o MARYLAND, o RHODE ISLAND,
o CONNECTICUT, o MASSACHUSETTS, o SOUTH CAROLINA,
o DELAWARE, o MINNESOTA, o SOUTH DAKOTA,
o DISTRICT OF COLUMBIA, o MISSISSIPPI, o TENNESSEE,
o FLORIDA, o MISSOURI, o TEXAS,
o GEORGIA, o MONTANA, o UTAH,
o HAWAII, o NEBRASKA, o VERMONT,
o IDAHO, o NEVADA, o VIRGINIA,
o ILLINOIS, o NEW MEXICO, o WASHINGTON,
o INDIANA, o NEW YORK, o WEST VIRGINIA,
o IOWA, o NORTH DAKOTA, o WISCONSIN, OR
o WYOMING,
then limited partner units will be sold to you if you meet either of the
following requirements:
o a minimum net worth of $225,000, exclusive of home, home furnishings,
and automobiles; or
o a minimum net worth of $60,000, exclusive of home, home furnishings,
and automobiles, and had during the last tax year or estimate that you
will have during the current tax year "taxable income" as defined in
Section 63 of the Internal Revenue Code of at least $60,000, without
regard to an investment in the partnership.
In addition, if you are a resident of OHIO, or PENNSYLVANIA, then you must not
make an investment in a partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings and automobiles. Finally, if you are a
resident of KANSAS, it is recommended by the Office of the Kansas Securities
Commissioner that Kansas investors should limit their investment in the program
and substantially similar programs to no more than 10% of their net worth,
excluding home, furnishings and automobiles.
However, if you are a resident of the states set forth below, then additional
suitability requirements apply to you.
SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS IN
CALIFORNIA, MICHIGAN, NEW HAMPSHIRE, NEW JERSEY AND NORTH CAROLINA.
o If you are a resident of CALIFORNIA or NEW JERSEY and you purchase
limited partner units, then you must meet any one of the following
special suitability requirements:
37
o a net worth of not less than $250,000, exclusive of home, home
furnishings, and automobiles, and expect to have gross income in the
current tax year of $65,000 or more; or
o a net worth of not less than $500,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $1 million; or
o expected gross income in the current tax year of not less than
$200,000.
o If you are a resident of MICHIGAN or NORTH CAROLINA and you purchase
limited partner units, then you must meet either of the following special
suitability requirements:
o a net worth of not less than $225,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $60,000, exclusive of home, home
furnishings, and automobiles, and estimated current tax year taxable
income as defined in Section 63 of the Internal Revenue Code of
$60,000 or more without regard to an investment in the partnership.
Additionally, if you are a resident of MICHIGAN, then you must not make an
investment in a partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings and automobiles.
o If you are a resident of NEW HAMPSHIRE and you purchase limited partner
units, then you must meet either of the following special suitability
requirements:
o a net worth of not less than $250,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $125,000, exclusive of home, home
furnishings, and automobiles and $50,000 of taxable income.
GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS. If you are a resident of any of the following states or jurisdictions:
o ALASKA, o IDAHO, o NORTH DAKOTA,
o COLORADO, o ILLINOIS, o RHODE ISLAND,
o CONNECTICUT, o LOUISIANA, o SOUTH CAROLINA,
o DELAWARE, o MARYLAND, o UTAH,
o DISTRICT OF COLUMBIA, o MONTANA, o VIRGINIA,
o FLORIDA, o NEBRASKA, o WEST VIRGINIA,
o GEORGIA, o NEVADA, o WISCONSIN, OR
o HAWAII, o NEW YORK, o WYOMING,
then investor general partner units will be sold to you if you meet either of
the following requirements:
o a minimum net worth of $225,000, exclusive of home, home furnishings,
and automobiles; or
o a minimum net worth of $60,000, exclusive of home, home furnishings,
and automobiles, and had during the last tax year or estimate that you
will have during the current tax year "taxable income" as defined in
Section 63 of the Internal Revenue Code of at least $60,000, without
regard to an investment in the partnership.
38
However, if you are a resident of the states set forth below, then additional
suitability requirements apply to you if you purchase investor general partner
units.
SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS IN EITHER: (I) ALABAMA, ARKANSAS, 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 any of the following states:
o ALABAMA, o MINNESOTA, o PENNSYLVANIA,
o ARKANSAS, o NORTH CAROLINA, o TENNESSEE,
o MAINE, o OHIO, o TEXAS, OR
o MASSACHUSETTS, o OKLAHOMA, o WASHINGTON
and you purchase investor general partner units, then you must meet
any one of the following special suitability requirements:
o an individual or joint net worth with your spouse of $225,000 or
more, without regard to the investment in the partnership,
exclusive of home, home furnishings, and automobiles, and A
COMBINED GROSS INCOME OF $100,000 OR MORE FOR THE CURRENT YEAR
AND FOR THE TWO PREVIOUS YEARS; or
o an individual or joint net worth with your spouse in excess of $1
million, inclusive of home, home furnishings, and automobiles; or
o an individual or joint net worth with your spouse in excess of
$500,000, exclusive of home, home furnishings, and automobiles;
or
o a combined "gross income" as defined in 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 a partnership which is in excess of 10%
of your net worth, exclusive of home, home furnishings, and
automobiles.
o If you are a resident of any of the following states:
o ARIZONA, o KENTUCKY, o NEW MEXICO,
o INDIANA, o MICHIGAN, o OREGON,
o IOWA, o MISSISSIPPI, o SOUTH DAKOTA, OR
o KANSAS, o MISSOURI, o VERMONT
and you purchase investor general partner units, then you must meet
any one of the following special suitability requirements:
o an individual or joint net worth with your spouse of $225,000 or
more, without regard to the investment in the partnership,
exclusive of home, home furnishings, and automobiles, and A
COMBINED "TAXABLE INCOME" OF $60,000 OR MORE FOR THE PREVIOUS
YEAR AND EXPECT TO HAVE A
39
COMBINED "TAXABLE INCOME" OF $60,000 OR MORE FOR THE CURRENT
YEAR AND FOR THE SUCCEEDING YEAR; or
o an individual or joint net worth with your spouse in excess of $1
million, inclusive of home, home furnishings, and automobiles; or
o an individual or joint net worth with your spouse in excess of
$500,000, exclusive of home, home furnishings, and automobiles;
or
o a combined "gross income" as defined in Internal Revenue Code
Section 61 in excess of $200,000 in the current year and the two
previous years.
o In addition, if you are a resident of IOWA OR MICHIGAN, then you must
not make an investment in a partnership which is in excess of 10% of
your net worth, exclusive of home, home furnishings, and automobiles.
o Finally, if you are a resident of KANSAS, it is recommended by the
Office of the Kansas Securities Commissioner that Kansas investors
should limit their investment in the program and substantially similar
programs to no more than 10% of their net worth, excluding home,
furnishings and automobiles.
SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS IN CALIFORNIA, NEW HAMPSHIRE OR NEW JERSEY.
o If you are a resident of CALIFORNIA or NEW JERSEY and you purchase
investor general partner units, then you must meet any one of the
following special suitability requirements:
o a net worth of not less than $250,000, exclusive of home, home
furnishings, and automobiles, and expect to have gross income in
the current tax year of $120,000 or more; or
o a net worth of not less than $500,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $1 million; or
o expected gross income in the current tax year of not less than
$200,000.
o If you are a resident of NEW HAMPSHIRE and you purchase investor
general partner units, then you must meet either of the following
special suitability requirements:
o a net worth of not less than $250,000, exclusive of home, home
furnishings, and automobiles; or
o a net worth of not less than $125,000, exclusive of home, home
furnishings, and automobiles, and $50,000 of taxable income.
FIDUCIARY ACCOUNTS. If there is a sale of a unit to a fiduciary account, then
all the suitability standards set forth above must be met by:
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.
40
Generally, you are required to execute your own subscription agreement, and the
managing general partner will not accept any subscription agreement that has
been executed by someone other than you. The only exception is if you have given
someone else the legal power of attorney to sign on your behalf and you meet all
of the conditions in this prospectus.
PRIOR ACTIVITIES
The following tables reflect certain historical data with respect to 35 private
drilling partnerships which raised a total of $254,432,892, and 13 public
drilling partnerships which raised a total of $220,117,468, that the managing
general partner has sponsored. The tables also reflect certain historical data
with respect to 1999 Viking Resources LP, a private drilling program which
raised $4,555,210, and is the only drilling program sponsored by Viking
Resources after it was acquired by Resource America, Inc. in August 1999.
Information concerning 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. Additional information concerning this program
will be provided on written request to the managing general partner. The tables
also do not include information concerning wells acquired by Atlas Resources
through merger or other form of acquisition and this information also will be
available on written request.
Although past performance is no guarantee of future results, the investor
general partners in the managing general partner's prior partnerships have not
had to make additional capital contributions to their partnerships because of
their status as investor general partners.
IT SHOULD NOT BE ASSUMED THAT YOU AND THE OTHER INVESTORS WILL EXPERIENCE
RETURNS, IF ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS IN THE PRIOR
DRILLING PARTNERSHIPS FOR SEVERAL REASONS, INCLUDING, BUT NOT LIMITED TO,
DIFFERENCES IN:
o PARTNERSHIP TERMS;
o PROPERTY LOCATIONS;
o PARTNERSHIP SIZE; AND
o ECONOMIC CONSIDERATIONS.
THE RESULTS OF THE PRIOR DRILLING PARTNERSHIPS SHOULD BE VIEWED ONLY AS A
MEASURE OF THE LEVEL OF ACTIVITY AND EXPERIENCE OF THE MANAGING GENERAL PARTNER
WITH RESPECT TO DRILLING PARTNERSHIPS.
41
Table 1 sets forth certain sales information of previous development drilling
partnerships sponsored by the managing general partner and its affiliates.
TABLE 1
EXPERIENCE IN RAISING FUNDS
AS OF DECEMBER 15, 2004
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 18.97 -0-
2. A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 17.97 -0-
3. A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 16.97 -0-
4. A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 15.97 -0-
5. A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 14.97 -0-
6. A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 13.97 -0-
7. A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 13.75 -0-
8. A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 12.92 -0-
9. A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 12.75 -0-
10. A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 12.67 -0-
11. A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 12.00 -0-
12. A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 11.50 -0-
13. A.E. Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 11.25 -0-
14. A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 10.92 -0-
15. A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 10.67 -0-
16. A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 10.42 -0-
17. A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 9.92 -0-
18. A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 9.67 -0-
19. A.E. Nineties-Public #3 391 5,800,990 928,546 6,729,536 12/31/94 06/05/95 9.67 -0-
20. A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96 8.84 -0-
21. A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96 8.42 -0-
22. A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96 8.67 -0-
23. A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 8.00 -0-
24. A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97 7.67 -0-
25. A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 7.67 -0-
26. A.E. Nineties-17 217 8,813,488 2,113,947 10,927,435 08/29/97 12/12/97 7.09 -0-
27. A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98 6.67 -0-
28. A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98 6.50 -0-
29. A.E. Nineties-18 225 11,391,673 3,448,751 14,840,424 07/31/98 01/07/99 5.75 -0-
30. A.E. Nineties-Public #7 366 11,988,350 3,812,150 15,800,500 12/31/98 07/10/99 5.42 -0-
31. A.E. Partners 1998 26 1,740,000 756,360 2,496,360 12/31/98 07/02/99 5.42 -0-
32. A.E. Nineties-19 288 15,720,450 4,776,598 20,497,048 09/30/99 01/14/00 4.92 -0-
33. A.E. Nineties-Public #8 380 11,088,975 3,148,181 14,237,156 12/31/99 06/09/00 4.42 -0-
34. A.E. Partners 1999 8 450,000 196,500 646,500 12/31/99 10/02/00 4.42 -0-
35. 1999 Viking Resources LP 131 4,555,210 1,678,038 6,233,248 12/31/99 06/01/00 4.42 -0-
36. Atlas America-Series 20 361 18,809,150 6,297,945 25,107,095 09/30/00 01/30/01 4.17 -0-
37. Atlas America - Public 530 14,905,465 5,563,527 20,468,992 12/31/00 07/13/01 3.77 -0-
#9
38. Atlas America - Series 282 12,510,713 4,535,799 17,046,512 05/15/01 11/16/01 3.52 -0-
21-A
39. Atlas America - Series 360 17,411,825 6,442,761 23,854,586 09/19/01 03/02/02 2.92 -0-
21-B
40. Atlas America - Public 818 21,281,170 7,227,432 28,508,602 12/31/01 06/20/02 2.67 -0-
#10
41. Atlas America - Series 258 10,156,375 3,481,591 13,637,966 05/31/02 11/12/02 2.17 -0-
22
42. Atlas America - Series 246 9,644,550 3,214,850 12,859,400 09/30/02 02/18/03 1.92 -0-
23
43. Atlas America - Public 1017 31,178,145 11,757,568 42,935,713 12/31/02 7/15/2003 1.67 -0-
#11-2002
44. Atlas America - Series 325 14,363,955 4,949,143 19,313,098 05/31/03 12/05/03 1.17 -0-
#24-2003 (A)
45. Atlas America - Series 422 20,542,850 7,300,020 27,842,870 08/29/03 02/05/04 .92 -0-
#24-2003 (B)
46. Atlas America - Public 1102 40,170,308 13,708,076 53,878,384 12/31/03 6/15/04 .67 -0-
#12-2003
47. Atlas America Series 635 27,601,053 10,266,771 37,867,824 05/31/04 11/5/04 .42 -0-
# 25-2004 (A)
48. Atlas America Series 634 31,531,035 16,006,953 47,537,988 08/31/04 (1) (1) -0-
# 25-2004 (B)
49. Atlas America Public 1494 52,506,570 25,971,721 78,478,291 11/15/04 (2) (2) -0-
# 14-2004
- ----------
(1) This program closed August 31, 2004, and its first distribution is expected
in Winter 2005.
(2) This program closed November 15, 2004, and its first distribution is
expected in Summer 2005.
42
Table 2 reflects the drilling activity of previous development drilling
partnerships sponsored by the managing general partner and its affiliates. All
the wells were development wells. YOU SHOULD NOT ASSUME THAT THE PAST
PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE
PARTNERSHIPS.
TABLE 2
WELL STATISTICS - DEVELOPMENT WELLS
AS OF DECEMBER 15, 2004
GROSS WELLS (1) NET WELLS (2)
--------------------- -----------------------
Partnership Oil Gas Dry (3) Oil Gas Dry (3)
----------------------------------- --- ---- -------- --- ------- -------
1. Atlas L.P. #1 - 1985 0 6 1 0 2.83 0.50
2. A.E. Partners 1986 0 8 0 0 3.50 0.00
3. A.E. Partners 1987 0 9 0 0 4.10 0.00
4. A.E. Partners 1988 0 9 0 0 3.80 0.00
5. A.E. Partners 1989 0 10 0 0 3.30 0.00
6. A.E. Partners 1990 0 12 0 0 5.00 0.00
7. A.E. Nineties-10 0 12 0 0 11.50 0.00
8. A.E. Nineties-11 0 14 0 0 4.30 0.00
9. A.E. Partners 1991 0 12 0 0 4.95 0.00
10. A.E. Nineties-12 0 14 0 0 12.50 0.00
11. A.E. Nineties-JV 92 0 52 0 0 24.44 0.00
12. A.E. Partners 1992 0 7 0 0 3.50 0.00
13. A.E. Nineties-Public #1 0 14 0 0 14.00 0.00
14. A.E. Nineties-1993 Ltd. 0 20 1 0 19.40 1.00
15. A.E. Partners 1993 0 8 0 0 4.00 0.00
16. A.E. Nineties-Public #2 0 16 0 0 15.31 0.00
17. A.E. Nineties-14 0 53 2 0 53.00 2.00
18. A.E. Partners 1994 0 12 0 0 5.00 0.00
19. A.E. Nineties-Public #3 0 26 1 0 25.50 1.00
20. A.E. Nineties-15 0 61 1 0 55.50 1.00
21. A.E. Partners 1995 0 6 0 0 3.00 0.00
22. A.E. Nineties-Public #4 0 32 0 0 30.50 0.00
23. A.E. Nineties-16 0 51 6 0 40.50 4.50
24. A.E. Partners 1996 0 13 0 0 4.84 0.00
25. A.E. Nineties-Public #5 0 36 0 0 35.91 0.00
26. A.E. Nineties-17 0 47 5 0 42.00 3.50
27. A.E. Nineties-Public #6 0 55 0 0 44.45 0.00
28. A.E. Partners 1997 0 6 0 0 2.81 0.00
29. A.E. Nineties-18 0 63 0 0 58.00 0.00
30. A.E. Nineties-Public #7 0 64 0 0 57.50 0.00
31. A.E. Partners 1998 0 19 0 0 9.50 0.00
32. A.E. Nineties-19 0 82 4 0 75.75 4.00
33. A.E. Nineties-Public #8 0 58 0 0 54.66 0.00
34. A.E. Partners 1999 0 5 0 0 2.50 0.00
35. 1999 Viking Resources LP 0 23 2 0 23.00 2.00
36. Atlas America - Series 20 0 106 1 0 100.25 1.00
37. Atlas America - Public #9 0 83 2 0 78.75 2.00
38. Atlas America - Series 21-A 0 68 0 0 62.50 0.00
39. Atlas America - Series 21-B 0 89 2 0 84.05 1.00
40. Atlas America - Public #10 0 107 3 0 100.15 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 #11-2002 0 167 0 0 160.50 0.00
44. Atlas America - Series #24-2003 (A) 0 76 0 0 69.50 0.00
45. Atlas America - Series #24-2003 (B) 0 121 1 0 113.00 1.00
46. Atlas America-Public #12-2003 0 226 1 0 214.25 1.00
47. Atlas America Series # 25-2004 (A) 0 129 1 0 124.35 1.00
48. Atlas America Series # 25-2004 (B) 0 109 1 0 101.85 1.00
49. Atlas America Public # 14-2004 0 25 0 0 24.00 0.00
--- ---- -------- --- ------- -------
0 2339 37 0 2090.05 32.50
--- ---- -------- --- ------- -------
- ----------
(1) A "gross well" is one in which a leasehold interest is owned.
(2) A "net well" equals the actual leasehold interest owned in one gross well
divided by one hundred. For example, a 50% leasehold interest in a well is
one gross well, but a .50 net well.
(3) For purposes of this Table only, a "Dry Hole" means a well which is plugged
and abandoned with or without a completion attempt because the operator has
determined that it will not be productive of gas and/or oil in commercial
quantities.
43
TABLE 3 PROVIDES INFORMATION CONCERNING THE OPERATING RESULTS OF PREVIOUS
DEVELOPMENT DRILLING PARTNERSHIPS SPONSORED BY THE MANAGING GENERAL PARTNER AND
ITS AFFILIATES. YOU SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIPS.
TABLE 3
INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
AS OF DECEMBER 15, 2004
TOTAL COSTS
Investor ----------------------------------- Cash Cash
Partnership Capital (1) Operating (6) Admin. Direct Distributions (2)(4) Return (4)
---------------------------------- ------------ ------------- --------- --------- -------------------- ----------
1. Atlas L.P. #1 - 1985 $ 600,000 $ 222,888 $ 45,557 $ 13,364 $ 1,599,044 267%
2. A.E. Partners 1986 631,250 177,393 73,055 12,400 758,872 120%
3. A.E. Partners 1987 721,000 177,479 62,232 12,569 766,573 106%
4. A.E. Partners 1988 617,050 148,295 59,536 11,340 704,761 114%
5. A.E. Partners 1989 550,000 144,223 63,977 11,204 885,163 161%
6. A.E. Partners 1990 887,500 217,871 91,850 15,540 1,279,582 144%
7. A.E. Nineties - 10 2,200,000 464,809 102,033 41,006 1,952,558 89%
8. A.E. Nineties - 11 750,000 176,989 102,272 67,650 1,095,364 146%
9. A.E. Partners 1991 868,750 196,102 118,924 26,161 1,379,394 159%
10. A.E. Nineties - 12 2,212,500 466,559 100,750 133,491 2,117,766 96%
11. A.E. Nineties - JV 92 4,004,813 788,558 161,880 226,777 4,461,965 (3) 111%
12. A.E. Partners 1992 600,000 110,911 59,138 13,536 918,193 153%
13. A.E. Nineties - Public #1 2,988,960 492,647 101,518 125,612 2,407,049 81%
14. A.E. Nineties - 1993 Ltd. 3,753,937 561,434 110,528 61,990 2,240,928 60%
15. A.E. Partners 1993 700,000 145,353 43,688 12,789 1,078,667 154%
16. A.E. Nineties - Public #2 3,323,920 495,861 90,362 88,979 2,310,288 70%
17. A.E. Nineties - 14 9,940,045 1,498,726 287,962 82,689 6,104,162 61%
18. A.E. Partners 1994 892,500 147,455 53,305 16,577 1,140,728 128%
19. A.E. Nineties - Public #3 5,800,990 806,252 153,932 103,031 3,993,751 69%
20. A.E. Nineties - 15 10,954,715 1,509,731 289,136 84,210 7,757,736 71%
21. A.E. Partners 1995 600,000 85,540 20,658 9,536 385,895 64%
22. A.E. Nineties - Public #4 6,991,350 911,261 167,281 90,648 3,342,926 48%
23. A.E. Nineties - 16 10,955,465 1,301,433 218,987 101,673 5,593,619 51%
24. A.E. Partners 1996 800,000 119,557 26,877 47,164 549,649 69%
25. A.E. Nineties - Public #5 7,992,240 917,545 165,732 100,837 3,985,988 50%
26. A.E. Nineties - 17 8,813,488 990,464 165,815 162,396 5,196,251 59%
27. A.E. Nineties - Public #6 9,901,025 1,151,631 190,403 119,736 5,769,680 58%
28. A.E. Partners 1997 506,250 69,438 15,397 31,657 378,818 75%
29. A.E. Nineties - 18 11,391,673 1,267,479 200,511 267,919 5,931,151 52%
30. A.E. Nineties - Public #7 11,988,350 1,111,286 166,015 64,368 4,477,768 37%
31. A.E. Partners 1998 1,740,000 211,937 26,694 58,016 1,123,157 65%
32. A.E. Nineties - 19 15,720,450 1,471,063 215,493 16,783 6,571,323 42%
33. A.E. Nineties - Public #8 11,088,975 966,369 145,733 78,783 4,891,476 44%
34. A.E. Partners 1999 450,000 32,843 4,397 12,518 348,964 78%
35. 1999 Viking Resources LP 4,555,210 1,298,419 0 170,741 6,383,149 140%
36. Atlas America - Series 20 18,809,150 2,510,613 231,262 157,357 12,695,324 67%
37. Atlas America - Public #9 14,905,465 1,548,572 155,490 64,346 7,112,622 48%
38. Atlas America - Series 21-A 12,510,713 982,546 112,676 11,641 5,053,399 40%
39. Atlas America - Series 21-B 17,411,825 1,209,346 131,794 11,565 5,978,993 34%
40. Atlas America - Public #10 21,281,170 1,437,068 157,060 58,192 8,199,940 39%
41. Atlas America - Series 22 10,156,375 577,636 63,123 9,035 4,024,045 40%
42. Atlas America - Series 23 9,644,550 516,082 54,621 8,717 3,137,664 33%
43. Atlas America - Public #11-2002 31,178,145 1,313,546 137,751 46,786 8,475,116 27%
44. Atlas America - Series 24-2003 (A) 14,363,955 390,310 43,466 5,595 2,469,559 17%
Present Value of
Estimated Future Estimated Future Net
Latest Quarterly Net Cash Flows from Cash Flows from Proved
Cash Distribution Proved Reserves as of Reserves Discounted at 10%
Partnership As of Date of Table January 1, 2004 (8) (9) as of January 1, 2004 (8) (10)
---------------------------------- ------------------- ----------------------- ------------------------------
1. Atlas L.P. #1 - 1985 $ 15,440 (7) (7)
2. A.E. Partners 1986 10,483 (7) (7)
3. A.E. Partners 1987 7,921 (7) (7)
4. A.E. Partners 1988 7,971 (7) (7)
5. A.E. Partners 1989 9,144 (7) (7)
6. A.E. Partners 1990 14,885 (7) (7)
7. A.E. Nineties - 10 30,388 2,177,542 1,036,946
8. A.E. Nineties - 11 11,759 674,653 342,924
9. A.E. Partners 1991 19,277 (7) (7)
10. A.E. Nineties - 12 29,411 1,532,203 784,424
11. A.E. Nineties - JV 92 52,492 3,376,157 1,658,496
12. A.E. Partners 1992 7,572 (7) (7)
13. A.E. Nineties - Public #1 29,129 2,069,313 1,036,487
14. A.E. Nineties - 1993 Ltd. 11,772 972,192 543,842
15. A.E. Partners 1993 13,116 (7) (7)
16. A.E. Nineties - Public #2 44,003 2,657,838 1,246,663
17. A.E. Nineties - 14 83,675 5,020,367 2,588,203
18. A.E. Partners 1994 21,939 (7) (7)
19. A.E. Nineties - Public #3 61,214 3,949,556 1,932,637
20. A.E. Nineties - 15 145,051 8,315,478 4,140,949
21. A.E. Partners 1995 4,779 (7) (7)
22. A.E. Nineties - Public #4 67,123 4,030,938 2,012,399
23. A.E. Nineties - 16 145,881 7,786,397 3,820,440
24. A.E. Partners 1996 17,096 (7) (7)
25. A.E. Nineties - Public #5 85,390 5,467,002 2,706,277
26. A.E. Nineties - 17 160,884 8,402,544 4,103,870
27. A.E. Nineties - Public #6 167,160 9,352,853 4,606,067
28. A.E. Partners 1997 13,318 (7) (7)
29. A.E. Nineties - 18 189,071 8,951,046 4,645,657
30. A.E. Nineties - Public #7 131,359 6,113,949 3,231,862
31. A.E. Partners 1998 36,033 (7) (7)
32. A.E. Nineties - 19 271,261 9,972,011 5,241,372
33. A.E. Nineties - Public #8 193,816 7,121,442 3,873,011
34. A.E. Partners 1999 9,284 (7) (7)
35. 1999 Viking Resources LP 234,745 (7) (7)
36. Atlas America - Series 20 512,285 18,847,947 10,051,213
37. Atlas America - Public #9 411,033 14,747,539 7,686,704
38. Atlas America - Series 21-A 386,219 13,220,267 7,099,896
39. Atlas America - Series 21-B 516,092 17,525,890 9,467,539
40. Atlas America - Public #10 705,292 21,608,356 11,856,286
41. Atlas America - Series 22 377,828 14,439,110 7,669,447
42. Atlas America - Series 23 326,264 8,753,542 5,324,954
43. Atlas America - Public #11-2002 1,331,138 31,239,303 18,758,873
44. Atlas America - Series 24-2003 (A) 678,524 (7) (7)
44
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 DECEMBER 15, 2004
TOTAL COSTS
Investor ----------------------------------- Cash Cash
Partnership Capital (1) Operating (6) Admin. Direct Distributions (2)(4) Return (4)
-------------------------------------- ------------ ------------- --------- --------- -------------------- ----------
45. Atlas America - Series 24-2003 (B) (5) 20,542,850 470,253 49,860 5,320 3,925,742 19%
46. Atlas America - Public #12-2003 (5) 40,170,308 404,528 49,137 29,302 2,999,701 7%
47. Atlas America Series # 25-2004 (A) (5) 27,601,053 41,597 5,302 1,403 255,358 1%
48. Atlas America Series # 25-2004 (B) (5) 31,531,035 0 0 0 0 0%
49. Atlas America Public # 14-2004 (5) 52,506,570 0 0 0 0 0%
Present Value of
Estimated Future Estimated Future Net
Latest Quarterly Net Cash Flows from Cash Flows from Proved
Cash Distribution Proved Reserves as of Reserves Discounted at 10%
Partnership As of Date of Table January 1, 2004 (8) (9) as of January 1, 2004 (8) (10)
-------------------------------------- ------------------- ----------------------- ------------------------------
45. Atlas America - Series 24-2003 (B) (5) 1,388,359 (7) (7)
46. Atlas America - Public #12-2003 (5) 2,142,010 20,203,301 (7) 12,219,333 (7)
47. Atlas America Series # 25-2004 (A) (5) 255,358 (7) (7)
48. Atlas America Series # 25-2004 (B) (5) 0 (7) (7)
49. Atlas America Public # 14-2004 (5) 0 (7) (7)
- ----------
(1) There have been no partnership borrowings other than from the managing
general partner. The approximate principal amounts of such borrowings are
as follows:
o A.E. Nineties-10 - $330,000; and
o A.E. Nineties-11 - $125,000; and
o A.E. Nineties-12 - $365,500.
A portion of each partnership's cash distributions was used to repay that
partnership's loan.
(2) All cash distributions were from the sale of gas, 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 of the wells are drilled or on-line to sell production.
(6) Operating costs consist of gathering fees, water hauling fees, meter
reading fees, repairs and maintenance, insurance and severance tax.
(7) Current reserve information is either not available for these partnerships
or has been prepared more than 15 months before this prospectus. Also,
reserve information for Public # 12-2003 which closed at 12/31/03 is
incomplete since not all of its wells were drilled at 1/1/04.
(8) The information presented in this column has been prepared in conformity
with SEC guidelines by making the standardized estimates of future net cash
flow from proved reserves using natural gas and oil prices in effect asfor
the date of the estimates, which was a weighted average price of $ 6.69 per
mcf for the natural gas, and which are held constant throughout the life of
the properties. The information presented for future net cash flows based
on estimated proved reserves has been prepared by the managing general
partner's petroleum engineers and reviewed by an independent petroleum
consultant, Wright & Company, Inc., as noted below with respect to the
managing general partner's prior public partnerships: Atlas-Energy for the
Nineties-Public # 1 Ltd., Atlas-Energy for the Nineties-Public # 2 Ltd.,
Atlas-Energy for the Nineties-Public # 3 Ltd., Atlas-Energy for the
Nineties-Public # 4 Ltd., Atlas-Energy for the Nineties-Public # 5 Ltd.,
Atlas-Energy for the Nineties-Public # 6 Ltd., Atlas-Energy not been
reviewed by Wright & Company, Inc. You should understand that reserve
estimates are imprecise and may change. There are inherent uncertainties in
interpreting the engineering data and the projection of future rates of
production. Also, prices received from the sale of natural gas and oil may
be different from those estimates in preparing the reports, and the amounts
and timing of future operating and development costs may also differ from
those used. The cash flow information based on estimated proved reserves
shown for a partnership does not include this information for the managing
general partner.
(9) This column represents a partnership's estimate of future net cash flows
from its proved reserves using natural gas sales prices in effect as of the
dates of the estimates which are held constant throughout the life of the
partnership's properties. As natural gas prices change, these estimates
will change. The information in this column has not been discounted.
(10) This column represents a partnership's estimate of future net cash flows
from its proved reserves using natural gas sales prices in effect as of the
dates of the estimates which are held constant throughout the life of the
partnership's properties. As natural gas prices change, these estimates
will change. The present value of estimated future net cash flows is
calculated by discounting estimated future net cash flows by 10% annually
in accordance with SEC guidelines. You should not construe the estimated
PV-10 values as representative of the fair market value of a partnership's
properties.
45
Table 3A provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates.
TABLE 3A
MANAGING GENERAL PARTNER
OPERATING RESULTS - INCLUDING EXPENSES
AS OF DECEMBER 15, 2004
Total Costs
Managing General --------------------------------- Cash
Partnership Partner Capital Operating (3) Admin. Direct Distributions (1) Cash Return
-------------------------------------- ---------------- ------------- -------- -------- ----------------- -----------
1. Atlas L.P. #1 - 1985 $ 114,800 $ 42,455 $ 8,677 $ 2,546 $ 304,580 265%
2. A.E. Partners 1986 120,400 33,789 13,915 2,362 144,547 120%
3. A.E. Partners 1987 158,269 51,172 17,943 3,624 163,941 104%
4. A.E. Partners 1988 135,450 47,759 19,174 3,652 148,792 110%
5. A.E. Partners 1989 120,731 31,659 14,044 2,459 174,261 144%
6. A.E. Partners 1990 244,622 72,624 0 0 414,266 169%
7. A.E. Nineties - 10 484,380 154,936 0 0 694,792 143%
8. A.E. Nineties - 11 268,003 75,852 43,831 23,935 347,974 130%
9. A.E. Partners 1991 318,063 65,367 0 0 488,989 154%
10. A.E. Nineties - 12 791,833 199,954 43,179 31,703 907,614 115%
11. A.E. Nineties - JV 92 1,414,917 388,394 79,732 30,156 1,269,494 90%
12. A.E. Partners 1992 176,100 36,970 0 0 322,671 183%
13. A.E. Nineties - Public #1 528,934 155,573 32,058 27,860 705,574 133%
14. A.E. Nineties - 1993 Ltd. 1,264,183 240,615 47,369 22,985 486,752 39%
15. A.E. Partners 1993 219,600 48,451 0 0 372,221 169%
16. A.E. Nineties - Public #2 587,340 156,588 28,535 28,099 564,533 96%
17. A.E. Nineties - 14 3,584,027 738,178 141,832 33,548 1,839,199 51%
18. A.E. Partners 1994 231,500 49,152 0 0 398,449 172%
19. A.E. Nineties - Public #3 928,546 268,751 51,311 34,344 1,270,063 137%
20. A.E. Nineties - 15 3,435,936 647,027 123,915 36,090 2,405,581 70%
21. A.E. Partners 1995 244,725 28,513 0 0 137,801 56%
22. A.E. Nineties - Public #4 1,287,752 303,754 55,760 30,216 931,719 72%
23. A.E. Nineties - 16 1,643,320 356,443 59,977 23,041 1,134,958 69%
24. A.E. Partners 1996 367,416 39,853 0 0 195,201 53%
25. A.E. Nineties - Public #5 1,654,740 305,848 55,244 33,612 983,754 59%
26. A.E. Nineties - 17 2,113,947 357,106 59,784 29,206 1,726,432 82%
27. A.E. Nineties - Public #6 1,950,345 383,877 63,468 39,912 1,825,995 94%
28. A.E. Partners 1997 231,050 23,146 0 0 133,733 58%
29. A.E. Nineties - 18 3,448,751 582,855 92,206 10,333 2,521,578 73%
30. A.E. Nineties - Public #7 3,812,150 499,273 74,587 28,919 1,092,224 29%
31. A.E. Partners 1998 756,360 70,646 0 0 389,383 51%
32. A.E. Nineties - 19 4,776,598 676,474 99,095 7,718 2,571,084 54%
33. A.E. Nineties - Public #8 3,148,181 394,714 59,525 32,179 1,813,096 58%
34. A.E. Partners 1999 196,500 10,948 0 0 121,913 62%
35. 1999 Viking Resources LP 1,678,038 432,806 0 56,914 2,127,716 127%
36. Atlas America - Series 20 6,297,945 928,583 85,535 58,201 4,698,436 75%
37. Atlas America - Public #9 5,563,527 632,515 63,510 26,282 2,901,910 52%
38. Atlas America - Series 21-A 4,535,799 502,416 57,616 5,953 2,584,011 57%
39. Atlas America - Series 21-B 6,442,761 622,997 67,894 5,958 3,080,087 48%
40. Atlas America - Public #10 7,227,432 676,270 73,910 27,385 3,858,813 53%
41. Atlas America - Series 22 3,481,591 278,502 29,705 4,356 1,940,160 56%
42. Atlas America - Series 23 3,214,850 242,867 25,704 4,102 1,476,579 46%
43. Atlas America - Public #11-2002 11,757,568 676,675 70,963 24,102 4,364,098 37%
Latest Quarterly Cash
Distribution As of
Partnership Date of Table
-------------------------------------- --------------------
1. Atlas L.P. #1 - 1985 2,941
2. A.E. Partners 1986 1,997
3. A.E. Partners 1987 2,284
4. A.E. Partners 1988 2,568
5. A.E. Partners 1989 2,007
6. A.E. Partners 1990 5,941
7. A.E. Nineties - 10 11,523
8. A.E. Nineties - 11 5,040
9. A.E. Partners 1991 7,734
10. A.E. Nineties - 12 12,605
11. A.E. Nineties - JV 92 25,854
12. A.E. Partners 1992 3,268
13. A.E. Nineties - Public #1 9,199
14. A.E. Nineties - 1993 Ltd. 5,045
15. A.E. Partners 1993 5,021
16. A.E. Nineties - Public #2 13,896
17. A.E. Nineties - 14 41,213
18. A.E. Partners 1994 8,475
19. A.E. Nineties - Public #3 20,405
20. A.E. Nineties - 15 62,165
21. A.E. Partners 1995 2,077
22. A.E. Nineties - Public #4 22,374
23. A.E. Nineties - 16 39,955
24. A.E. Partners 1996 6,433
25. A.E. Nineties - Public #5 28,463
26. A.E. Nineties - 17 58,006
27. A.E. Nineties - Public #6 55,720
28. A.E. Partners 1997 4,930
29. A.E. Nineties - 18 86,945
30. A.E. Nineties - Public #7 59,016
31. A.E. Partners 1998 13,346
32. A.E. Nineties - 19 69,519
33. A.E. Nineties - Public #8 40,828
34. A.E. Partners 1999 3,768
35. 1999 Viking Resources LP 58,686
36. Atlas America - Series 20 189,475
37. Atlas America - Public #9 167,887
38. Atlas America - Series 21-A 197,490
39. Atlas America - Series 21-B 265,866
40. Atlas America - Public #10 331,903
41. Atlas America - Series 22 182,167
42. Atlas America - Series 23 153,539
43. Atlas America - Public #11-2002 683,946
46
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 DECEMBER 15, 2004
Total Costs
Managing General --------------------------------- Cash
Partnership Partner Capital Operating (3) Admin. Direct Distributions (1) Cash Return
-------------------------------------- ---------------- ------------- -------- -------- ----------------- -----------
44. Atlas America - Series 24-2003(A) 4,949,143 189,043 21,052 2,710 1,196,095 24%
45. Atlas America - Series 24-2003(B) (2) 7,300,020 233,930 24,803 2,646 1,952,871 27%
46. Atlas America - Public #12-2003 (2) 13,708,076 194,240 23,594 14,070 1,440,351 11%
47. Atlas America Series # 25-2004 (A) (2) 10,266,771 21,534 2,855 726 137,501 1%
48. Atlas America Series # 25-2004 (B) (2) 16,006,953 0 0 0 0 0%
49. Atlas America Public # 14-2004 (2) 25,971,721 0 0 0 0 0%
Latest Quarterly Cash
Distribution As of
Partnership Date of Table
-------------------------------------- --------------------
44. Atlas America - Series 24-2003(A) 328,633
45. Atlas America - Series 24-2003(B) (2) 690,643
46. Atlas America - Public #12-2003 (2) 1,028,522
47. Atlas America Series # 25-2004 (A) (2) 137,501
48. Atlas America Series # 25-2004 (B) (2) 0
49. Atlas America Public # 14-2004 (2) 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.
(3) Operating costs consist of gathering fees, water hauling fees, meter
reading fees, repairs and maintenance, insurance and severance tax.
47
Table 4 sets forth the managing general partner's estimate of the federal tax
savings to investors in the managing general partner's prior development
drilling partnerships, based on the maximum marginal tax rate in each year, the
share of tax deductions as a percentage of their subscriptions, and the
aggregate cash distributions. YOU ARE URGED TO CONSULT WITH YOUR OWN TAX
ADVISORS CONCERNING YOUR SPECIFIC TAX SITUATION AND SHOULD NOT ASSUME THAT THE
PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF
THE PARTNERSHIPS.
TABLE 4
SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
AS OF DECEMBER 15, 2004
1st Year Estimated Federal Tax Savings From (1):
Tax Eff ---------------------------------------------------------
Investor Deduct. Tax 1st Year I.D.C. Depletion Depreci- Section 29
Partnership Capital (2) Rate Deduct. (3) Allowance (3) ation (3) Tax Credit (4)
------------------------------------- ------------ -------- ---- --------------- ------------- --------- --------------
1. Atlas L.P. #1 - 1985 $ 600,000 99% 50.0% $ 298,337 $ 126,232 N/A $ 55,915
2. A.E. Partners 1986 631,250 99% 50.0% 312,889 71,097 N/A 13,507
3. A.E. Partners 1987 721,000 99% 38.5% 356,895 54,110 N/A N/A
4. A.E. Partners 1988 617,050 99% 33.0% 244,351 48,831 N/A N/A
5. A.E. Partners 1989 550,000 99% 33.0% 179,685 67,943 N/A N/A
6. A.E. Partners 1990 887,500 99% 33.0% 275,125 96,201 N/A 281,660
7. A.E. Nineties - 10 2,200,000 100% 33.0% 726,000 160,070 N/A 521,602
8. A.E. Nineties - 11 750,000 100% 31.0% 232,500 99,280 N/A 329,800
9. A.E. Partners 1991 868,750 100% 31.0% 269,313 108,953 N/A 315,893
10. A.E. Nineties - 12 2,212,500 100% 31.0% 685,875 201,228 N/A 617,285
11. A.E. Nineties - JV 92 4,004,813 92.5% 31.0% 1,322,905 349,531 N/A 1,002,109
12. A.E. Partners 1992 600,000 100% 31.0% 186,000 78,318 N/A 224,631
13. A.E. Nineties - Public #1 2,988,960 80.5% 36.0% 877,511 219,356 254,729 N/A
14. A.E. Nineties - 1993 Ltd. 3,753,937 92.5% 39.6% 1,378,377 208,066 N/A N/A
15. A.E. Partners 1993 700,000 100% 39.6% 273,216 84,756 N/A N/A
16. A.E. Nineties - Public #2 3,323,920 78.7% 39.6% 1,036,343 192,901 279,039 N/A
17. A.E. Nineties - 14 9,940,045 95% 39.6% 3,739,445 506,883 N/A N/A
18. A.E. Partners 1994 892,500 100% 39.6% 353,430 80,838 N/A N/A
19. A.E. Nineties - Public #3 5,800,990 76.2% 39.6% 1,752,761 334,224 521,115 N/A
20. A.E. Nineties - 15 10,954,715 90.0% 39.6% 3,904,261 599,582 N/A N/A
21. A.E. Partners 1995 600,000 100% 39.6% 237,600 25,627 N/A N/A
22. A.E. Nineties - Public #4 6,991,350 80.0% 39.6% 2,214,860 290,353 537,551 N/A
23. A.E. Nineties - 16 10,955,465 86.8% 39.6% 3,361,289 410,746 868,417 N/A
24. A.E. Partners 1996 800,000 100% 39.6% 316,800 40,363 N/A N/A
25. A.E. Nineties - Public #5 7,992,240 84.9% 39.6% 2,530,954 301,268 578,516 N/A
26. A.E. Nineties - 17 8,813,488 85.2% 39.6% 2,966,366 383,214 415,744 N/A
27. A.E. Nineties - Public #6 9,901,025 80.0% 39.6% 3,166,406 431,114 639,248 N/A
28. A.E. Partners 1997 506,250 100% 39.6% 200,475 27,393 N/A N/A
29. A.E. Nineties - 18 11,391,673 90.0% 39.6% 4,030,884 289,916 380,121 N/A
30. A.E. Nineties - Public #7 11,988,350 85.0% 39.6% 4,043,670 294,269 517,298 N/A
31. A.E. Partners 1998 1,740,000 100.0% 39.6% 689,040 80,129 N/A N/A
32. A.E. Nineties - 19 15,720,450 90.0% 39.6% 5,602,767 424,685 426,553 N/A
33. A.E. Nineties - Public #8 11,088,975 85.0% 39.6% 3,734,654 328,084 437,497 N/A
34. A.E. Partners 1999 450,000 100.0% 39.6% 178,200 20,939 N/A N/A
35. 1999 Viking Resources LP 4,555,210 92.0% 39.6% 1,678,038 419,915 N/A N/A
36. Atlas America - Series 20 18,809,150 90.0% 39.6% 6,712,802 720,855 405,737 N/A
37. Atlas America - Public #9 14,905,465 90.0% 39.6% 5,349,744 438,302 N/A N/A
38. Atlas America - Series 21-A 12,510,713 91.0% 39.1% 4,468,617 255,134 198,934 N/A
39. Atlas America - Series 21-B 17,411,825 91.0% 39.1% 6,197,907 289,680 246,390 N/A
40. Atlas America - Public #10 21,281,170 91.0% 39.1% 7,550,729 371,759 419,544 N/A
41. Atlas America - Series 22 10,156,375 91.0% 38.6% 3,564,312 162,808 191,168 N/A
42. Atlas America - Series 23 9,644,550 91.0% 38.6% 3,404,803 121,594 164,846 N/A
43. Atlas America - Public #11-2002 31,178,145 91.0% 38.6% 11,003,503 259,394 384,143 N/A
Total Cumulative
Cash Distribution Cash Dist. Percent of Cash
As of And Tax Dist. And Tax
Partnership Total Date of Table (5) (6) Savings (5) (6) Savings to Date (5)(6)(7)
------------------------------------- ------------ --------------------- --------------- -------------------------
1. Atlas L.P. #1 - 1985 $ 480,484 $ 1,599,044 $ 2,079,528 347%
2. A.E. Partners 1986 397,493 758,872 1,156,365 183%
3. A.E. Partners 1987 411,005 766,573 1,177,579 163%
4. A.E. Partners 1988 293,182 704,761 997,943 162%
5. A.E. Partners 1989 247,628 885,163 1,132,791 206%
6. A.E. Partners 1990 652,986 1,279,582 1,932,568 218%
7. A.E. Nineties - 10 1,407,672 1,952,558 3,360,229 153%
8. A.E. Nineties - 11 661,580 1,095,364 1,756,944 234%
9. A.E. Partners 1991 694,159 1,379,394 2,073,554 239%
10. A.E. Nineties - 12 1,504,388 2,117,766 3,622,154 164%
11. A.E. Nineties - JV 92 2,674,545 4,461,965 7,136,510 178%
12. A.E. Partners 1992 488,950 918,193 1,407,142 235%
13. A.E. Nineties - Public #1 1,351,596 2,407,049 3,758,645 126%
14. A.E. Nineties - 1993 Ltd. 1,586,443 2,240,928 3,827,371 102%
15. A.E. Partners 1993 357,972 1,078,667 1,436,638 205%
16. A.E. Nineties - Public #2 1,508,282 2,310,288 3,818,570 115%
17. A.E. Nineties - 14 4,246,328 6,104,162 10,350,491 104%
18. A.E. Partners 1994 434,268 1,140,728 1,574,996 176%
19. A.E. Nineties - Public #3 2,608,101 3,993,751 6,601,851 114%
20. A.E. Nineties - 15 4,503,843 7,757,736 12,261,580 112%
21. A.E. Partners 1995 263,227 385,895 649,122 108%
22. A.E. Nineties - Public #4 3,042,764 3,342,926 6,385,690 91%
23. A.E. Nineties - 16 4,640,451 5,593,619 10,234,070 93%
24. A.E. Partners 1996 357,163 549,649 906,812 113%
25. A.E. Nineties - Public #5 3,410,738 3,985,988 7,396,725 93%
26. A.E. Nineties - 17 3,765,325 5,196,251 8,961,576 102%
27. A.E. Nineties - Public #6 4,236,768 5,769,680 10,006,448 101%
28. A.E. Partners 1997 227,868 378,818 606,686 120%
29. A.E. Nineties - 18 4,700,921 5,931,151 10,632,072 93%
30. A.E. Nineties - Public #7 4,855,237 4,477,768 9,333,005 78%
31. A.E. Partners 1998 769,169 1,123,157 1,892,326 109%
32. A.E. Nineties - 19 6,454,005 6,571,323 13,025,329 83%
33. A.E. Nineties - Public #8 4,500,235 4,891,476 9,391,711 85%
34. A.E. Partners 1999 199,139 348,964 548,102 122%
35. 1999 Viking Resources LP 2,097,953 6,383,149 8,481,101 186%
36. Atlas America - Series 20 7,839,394 12,695,324 20,534,717 109%
37. Atlas America - Public #9 5,788,046 7,112,622 12,900,668 87%
38. Atlas America - Series 21-A 4,922,685 5,053,399 9,976,084 80%
39. Atlas America - Series 21-B 6,733,978 5,978,993 12,712,970 73%
40. Atlas America - Public #10 8,342,032 8,199,940 16,541,973 78%
41. Atlas America - Series 22 3,918,288 4,024,045 7,942,333 78%
42. Atlas America - Series 23 3,691,243 3,137,664 6,828,907 71%
43. Atlas America - Public #11-2002 11,647,040 8,475,116 20,122,156 65%
48
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 DECEMBER 15, 2004
1st Year Estimated Federal Tax Savings From (1):
Tax Eff ---------------------------------------------------------
Investor Deduct. Tax 1st Year I.D.C. Depletion Depreci- Section 29
Partnership Capital (2) Rate Deduct. (3) Allowance (3) ation (3) Tax Credit (4)
------------------------------------- ------------ -------- ---- --------------- ------------- --------- --------------
44. Atlas America - Series 24-2003(A) 14,363,955 91.0% 35.0% 4,578,250 17,862 185,944 N/A
45. Atlas America - Series 24-2003(B) (8) 20,542,850 91.0% 35.0% 6,514,764 4,978 365,751 N/A
46. Atlas America - Public #12-2003 (8) 40,170,308 91.0% 35.0% 12,879,332 0 0 N/A
47. Atlas America Series # 25-2004(A) (8) 27,601,053 91.0% 35.0% 0 0 0 N/A
48. Atlas America Series # 25-2004(B) (8) 31,531,035 91.0% 35.0% 0 0 0 N/A
49. Atlas America Public # 14-2004 (8) 52,506,570 91.0% 35.0% 0 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) (6) Savings (5) (6) Savings to Date (5)(6)(7)
------------------------------------- ------------ --------------------- --------------- -------------------------
44. Atlas America - Series 24-2003(A) 4,782,056 2,469,559 7,251,615 50%
45. Atlas America - Series 24-2003(B) (8) 6,885,493 3,925,742 10,811,235 53%
46. Atlas America - Public #12-2003 (8) 12,879,332 2,999,701 15,879,033 40%
47. Atlas America Series # 25-2004(A) (8) 0 255,358 255,358 1%
48. Atlas America Series # 25-2004(B) (8) 0 0 0 0%
49. Atlas America Public # 14-2004 (8) 0 0 0 0%
- ----------
(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 Resources anticipates that approximately 90% of an investor general
partner's subscription to a partnership will be deductible in the year in
which he invests.
(3) The I.D.C. Deductions, Depletion Allowance and MACRS depreciation
deductions have been reduced to credit equivalents.
(4) The Section 29 tax credit is not available with respect to wells drilled
after December 31, 1992. N/A means not applicable.
(5) These distributions were all from production revenues.
(6) This column reflects total cash distributions beginning with the first
production from the program and includes the return of investor's capital.
(7) These percentages are calculated by dividing the entry for each partnership
in the "Total Cash Dist. And Tax Savings" column by that partnership 's
entry in the "Investor Capital" column.
(8) As of the date of this table there is not twelve months of production
and/or not all wells are drilled or on-line to sell production.
49
Table 5 sets forth payments made to the managing general partners and its
affiliates from its previous partnerships.
TABLE 5
SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES
FROM PRIOR PARTNERSHIPS (1)
AS OF DECEMBER 15, 2004
Cumulative
Leasehold Reimbursement
Cumulative Drilling and Cumulative of General and
Investor Gathering Completion Operator's Administrative
Partnership Capital Fees (1) Costs (2) Charges Overhead
---------------------------------- ------------- ---------- ------------ ----------- --------------
1. Atlas L.P. #1 - 1985 $ 600,000 0 $ 600,000 $ 265,343 $ 54,234
2. A.E. Partners 1986 631,250 0 631,250 210,867 86,971
3. A.E. Partners 1987 721,000 0 721,000 228,651 80,176
4. A.E. Partners 1988 617,050 0 617,050 196,054 78,710
5. A.E. Partners 1989 550,000 0 550,000 175,881 78,020
6. A.E. Partners 1990 887,500 0 887,500 290,495 91,850
7. A.E. Nineties-10 2,200,000 0 2,200,000 619,745 102,033
8. A.E. Nineties-11 750,000 0 761,802 (3) 252,841 146,103
9. A.E. Partners 1991 868,750 0 867,500 261,470 118,924
10. A.E. Nineties-12 2,212,500 0 2,272,017 (3) 666,513 143,929
11. A.E. Nineties-JV 92 4,004,813 0 4,157,700 1,176,952 241,612
12. A.E. Partners 1992 600,000 0 600,000 147,881 59,138
13. A.E. Nineties-Public #1 2,988,960 0 3,026,348 (3) 648,220 133,576
14. A.E. Nineties-1993 Ltd. 3,753,937 0 3,480,656 (3) 802,049 157,898
15. A.E. Partners 1993 700,000 0 689,940 193,804 43,688
16. A.E. Nineties-Public #2 3,323,920 0 3,324,668 (3) 652,449 118,897
17. A.E. Nineties-14 9,940,045 0 9,512,015 (3) 2,236,905 429,794
18. A.E. Partners 1994 892,500 0 892,500 196,607 53,305
19. A.E. Nineties-Public #3 5,800,990 0 5,800,990 1,075,003 205,242
20. A.E. Nineties-15 10,954,715 0 9,859,244 (3) 2,156,758 413,051
21. A.E. Partners 1995 600,000 0 600,000 114,054 20,658
22. A.E. Nineties-Public #4 6,991,350 0 6,991,350 1,215,015 223,041
23. A.E. Nineties-16 10,955,465 0 10,955,465 1,657,877 278,964
24. A.E. Partners 1996 800,000 0 800,000 159,410 26,877
25. A.E. Nineties-Public #5 7,992,240 0 7,992,240 1,223,393 220,975
26. A.E. Nineties-17 8,813,488 0 8,813,488 1,347,571 225,599
27. A.E. Nineties-Public #6 9,901,025 0 9,901,025 1,535,508 253,871
28. A.E. Partners 1997 506,250 0 506,250 92,584 15,397
29. A.E. Nineties-18 11,391,673 0 11,391,673 1,850,334 292,717
30. A.E. Nineties-Public #7 11,988,350 0 11,988,350 1,610,559 240,602
31. A.E. Partners 1998 1,740,000 0 1,740,000 282,582 26,694
32. A.E. Nineties-19 15,720,450 0 15,720,450 2,147,537 314,589
33. A.E. Nineties-Public #8 11,088,975 0 11,088,975 1,361,084 205,258
34. A.E. Partners 1999 450,000 0 450,000 43,791 4,397
35. 1999 Viking Resources LP 4,555,210 0 4,555,210 1,731,226 0
36. Atlas America-Series 20 18,809,150 0 18,809,150 3,439,195 316,798
37. Atlas America-Public #9 14,905,465 786,366 14,905,465 1,394,721 219,000
38. Atlas America-Series 21-A 12,510,713 514,610 12,510,713 970,352 170,291
39. Atlas America-Series 21-B 17,411,825 653,669 17,411,825 1,178,674 199,688
40. Atlas America-Public #10 21,281,170 893,335 21,281,170 1,220,003 230,970
41. Atlas America-Series 22 10,156,375 380,829 10,156,375 475,309 92,828
42. Atlas America-Series 23 9,644,550 348,500 9,644,550 410,448 80,325
43. Atlas America-Public #11-2002 31,178,145 823,107 31,178,145 1,167,115 208,713
44. Atlas America - Series 24-2003 (A) 14,363,955 218,353 14,363,955 360,999 64,519
45. Atlas America - Series 24-2003 (B) 20,542,850 294,067 20,542,850 410,116 74,663
46. Atlas America - Public 12-2003 40,170,308 295,449 40,170,308 303,319 72,731
47. Atlas America Series # 25-2004 (A) 27,601,053 24,698 27,601,053 38,433 8,156
48. Atlas America Series # 25-2004 (B) 31,531,035 0 31,531,035 0 0
49. Atlas America Public # 14-2004 52,506,570 0 52,506,570 0 0
- ----------
(1) The amount of gathering fees paid to the managing general partner and its
affiliates from 2001 to the date of this table are shown for those
partnerships which began operations on or after December 31, 2000. The
books and records of the earlier partnerships do not separately allocate
all of the gathering fees paid by them. Additional information concerning
the gathering fees paid by those partnerships will be provided to you on
written request to the managing general partner.
(2) Excluding the managing general partner's capital contributions.
(3) Includes additional drilling costs paid with production revenues.
50
MANAGEMENT
MANAGING GENERAL PARTNER AND OPERATOR
The partnerships will have no officers, directors or employees. Instead, Atlas
Resources, Inc., a Pennsylvania corporation which was incorporated in 1979, will
serve as the managing general partner of each partnership. 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 September 30, 2004, the managing general partner and its affiliates
operated approximately 4,861 natural gas and oil wells located in Ohio,
Pennsylvania and New York.
Since 1985 the managing general partner has sponsored 13 public and 35 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, which is a subsidiary of Resource America, Inc., a publicly-traded
company, which is sometimes referred to in this prospectus as Resource America.
In May 2004 Resource America conducted a public offering of a portion of its
common stock (the "shares") in Atlas America. Two million six hundred forty-five
thousand shares were registered and sold at a price of at $15.50 per share
resulting in gross proceeds of $41 million of which approximately 3.5 million
was applied to underwriting discounts and commissions and approximately $530,000
of which was applied to related costs. The net proceeds of the offering of $37
million after deducting underwriting discounts were distributed to Resource
America in the form of a repayment of inter-company debt and a non-taxable
dividend. Resource America continues to own approximately 80.2% of Atlas
America's common stock. Also, in May 2004, in connection with the Atlas America
offering, the following officers and key employees of the managing general
partner and Atlas America set forth in "- Officers, Directors and Other Key
Personnel," below, resigned their positions with Resource America and all of its
subsidiaries which are not also subsidiaries of Atlas America: Mr. Freddie M.
Kotek, Mr. Frank P. Carolas, Mr. Jeffrey C. Simmons, Ms. Nancy J. McGurk, Mr.
Michael L. Staines, and Ms. Marci Bleichmar.
Resource America has advised the managing general partner that it intends to
distribute its remaining ownership interest in Atlas America to its common
stockholders. Resource America expects the distribution to take the form of a
spin-off by means of a tax free dividend to Resource America common stockholders
of all of Atlas America's common stock owned by Resource America. Resource
America further has advised the managing general partner that it anticipates
that the distribution will occur on or about March 31, 2005, but it has sole
discretion if and when to complete the distribution and its terms. Also,
Resource America does not intend to complete the distribution unless it receives
an IRS ruling and/or an opinion from its tax counsel as to the tax-free nature
of the distribution to Resource America and its stockholders for U.S. federal
income tax purposes. The IRS requirements for tax-free distributions of this
nature are complex and the IRS has broad discretion, so there is significant
uncertainty as to whether Resource America will be able to obtain such a ruling.
Because of this uncertainty and the fact that the timing and completion of the
distribution is in Resource America's sole discretion, the distribution may not
occur by the contemplated time or may not occur at all.
If the distribution occurs, the managing general partner believes the principal
effect on Atlas America will be that Resource America will no longer own any of
Atlas America's common stock and, thus, will no longer be in a position to
determine the outcome of corporate actions requiring stockholder approval such
as:
o the election and removal of directors;
o mergers or other business combinations involving Atlas America;
o future issuances of Atlas America's common stock or other securities;
and
o amendments to Atlas America's certificate of incorporation and bylaws.
51
These actions will be passed on by Atlas America's stockholders existing at the
record dates for such matters. Resource America's rights following the
distribution will be defined by agreements between Resource America and Atlas
America.
Atlas America is headquartered at 311 Rouser Road, Moon Township, Pennsylvania
15108, near the Pittsburgh International Airport, which is also the managing
general partner's primary office.
OFFICERS, DIRECTORS AND OTHER KEY PERSONNEL
The officers and directors of the managing general partner will serve until
their successors are elected. The officers, directors, and key personnel of the
managing general partner are as follows:
NAME AGE POSITION OR OFFICE
- ------------------- --- ---------------------------------------------------------------------------
Freddie M. Kotek 49 Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas 45 Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons 46 Executive Vice President - Operations and a Director
Jack L. Hollander 48 Senior Vice President - Direct Participation Programs
Nancy J. McGurk 49 Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines 55 Senior Vice President, Secretary and a Director
Michael G. Hartzell 48 Vice President - Land Administration
Donald R. Laughlin 56 Vice President - Drilling and Production
Marci F. Bleichmar 34 Vice President of Marketing
Sherwood S. Lutz 53 Senior Geologist/Manager of Geology
Michael W. Brecko 46 Director of Energy Sales
Karen A. Black 44 Vice President - Partnership Administration
Justin T. Atkinson 31 Director of Due Diligence
Winifred C. Loncar 63 Director of Investor Services
With respect to the biographical information set forth below:
o the approximate amount of an individual's professional time devoted to
the business and affairs of the managing general partner and Atlas
America have been aggregated because there is no reasonable method for
them to distinguish their activities between the two companies; and
o for those individuals who also hold senior positions with other
affiliates of the managing general partner, if it is stated that they
devote approximately 100% of their professional time to the managing
general partner and Atlas America, it is because either the other
affiliates are not currently active in drilling new wells, such as
Viking Resources or Resource Energy, and the individuals are not
required to devote a material amount of their professional time to the
affiliates, or there is no reasonable method to distinguish their
activities between the managing general partner and Atlas America as
compared with the other affiliates of the managing general partner,
such as Viking Resources or Resource Energy.
FREDDIE M. KOTEK. President and Chief Executive Officer since January 2002 and
Chairman of the Board of Directors since September 2001. Mr. Kotek has been
Executive Vice President and Chief Financial Officer of Atlas America since
February 2004 and served as a director from September 2001 until February 2004.
Mr. Kotek was a Senior Vice President of Resource America and President of
Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995
until May 2004 when he resigned from Resource America and all of its
subsidiaries which are not subsidiaries of Atlas America. Mr. Kotek was
President of Resource Properties from September 2000 to October 2001 and its
Executive Vice President from 1993 to August 1999. Mr. Kotek received a Bachelor
of Arts degree from Rutgers College in 1977 with high honors in Economics. He
also received a Master in Business Administration degree from the Harvard
Graduate School of Business Administration in 1981. Mr. Kotek will devote
approximately 95% of his professional time to the business and affairs of the
managing general partner and Atlas America, and the remainder of his
professional time to the business and affairs of the managing general partner's
affiliates.
52
FRANK P. CAROLAS. Executive Vice President-Land and Geology and a Director since
January 2001. Mr. Carolas has been an Executive Vice President of Atlas America
since January 2001 and served as a Director of Atlas America from January 2002
until February 2004. Mr. Carolas was a Vice President of Resource America from
April 2001 until May 2004 when he resigned from Resource America. Mr. Carolas
served as Vice President of Land and Geology for the managing general partner
from July 1999 until December 2000 and for Atlas America from 1998 until
December 2000. Before that Mr. Carolas served as Vice President of Atlas Energy
Group, Inc. from 1997 until 1998, which was the former parent company of the
managing general partner. Mr. Carolas is a certified petroleum geologist and has
been with the managing general partner and its affiliates since 1981. He
received a Bachelor of Science degree in Geology from Pennsylvania State
University in 1981 and is an active member of the American Association of
Petroleum Geologists. Mr. Carolas devotes approximately 100% of his professional
time to the business and affairs of the managing general partner and Atlas
America.
JEFFREY C. SIMMONS. Executive Vice President-Operations and a Director since
January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America
since January 2001 and was a Director of Atlas America from January 2002 until
February 2004. Mr. Simmons was a Vice President of Resource America from April
2001 until May 2004 when he resigned from Resource America. Mr. Simmons served
as Vice President of Operations for the managing general partner from July 1999
until December 2000 and for Atlas America from 1998 until December 2000. Mr.
Simmons joined Resource America in 1986 as a senior petroleum engineer and has
served in various executive positions with its energy subsidiaries since then.
Before Mr. Simmons' career with Resource America, he had worked with Core
Laboratories, Inc., of Dallas, Texas, and PNC Bank of Pittsburgh. Mr. Simmons
received his Petroleum Engineering degree from Marietta College in 1981 and his
Masters degree in Business Administration from Ashland University in 1992. Mr.
Simmons devotes approximately 80% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates, primarily Viking Resources and Resource Energy.
JACK L. HOLLANDER. Senior Vice President - Direct Participation Programs since
January 2002 and before that he served as Vice President - Direct Participation
Programs from January 2001 until December 2001. Mr. Hollander also serves as
Senior Vice President - Direct Participation Programs of Atlas America since
January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak,
concentrating in tax matters and real estate transactions, from 1990 to January
2001, and served as in-house counsel for Integrated Resources, Inc. (a
diversified financial services company) from 1982 to 1990. Mr. Hollander earned
a Bachelor of Science degree from the University of Rhode Island in 1978, his
law degree from Brooklyn Law School in 1981, and a Master of Law degree in
Taxation from New York University School of Law Graduate Division in 1982. Mr.
Hollander is a member of the New York State bar, 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 since January 2002, Chief Financial
Officer and Chief Accounting Officer since January 2001. Ms. McGurk also serves
as Senior Vice President since January 2002 and Chief Accounting Officer of
Atlas America since January 2001. Ms. McGurk served as Chief Financial Officer
for Atlas America from January 2001 until February 2004. Ms. McGurk was a Vice
President of Resource America from 1992 until May 2004 and its Treasurer and
Chief Accounting Officer from 1989 until May 2004 when she resigned from
Resource America. Also, since 1995 Ms. McGurk has served as Vice President -
Finance of Resource Energy, Inc. Ms. McGurk received a Bachelor of Science
degree in Accounting from Ohio State University in 1978, and has been a
Certified Public Accountant since 1982. Ms. McGurk will devote approximately 80%
of her professional time to the business and affairs of the managing general
partner and Atlas America, and the remainder of her professional time to the
business and affairs of the managing general partner's affiliates.
MICHAEL L. STAINES. Senior Vice President, Secretary, and a Director since 1998.
Mr. Staines has been an Executive Vice President and Secretary of Atlas America
since 1998. Mr. Staines was a Senior Vice President of Resource America from
1989 until May 2004 when he resigned from Resource America. Mr. Staines was a
director of Resource America from 1989 to February 2000 and Secretary from 1989
to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP
since January 2001 and its Chief Operating Officer and a member of its Managing
Board since its formation in November 1999. Mr. Staines is a member of the Ohio
Oil and Gas Association and the Independent Oil and Gas Association of New York.
53
Mr. Staines received a Bachelor of Science degree from Cornell University in
1971 and a Master of Business degree from Drexel University in 1977. Mr. Staines
will devote approximately 5% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates, including Atlas Pipeline Partners GP.
MICHAEL G. HARTZELL. Vice President - Land Administration since September 2001.
Mr. Hartzell has been Vice President - Land Administration of Atlas America
since January 2002, and before that served as Senior Land Coordinator from
January 1999 to January 2002. Mr. Hartzell has been with the managing general
partner and its affiliates since 1980 when he began his career as a land
department representative. Mr. Hartzell manages all Land Department functions.
Mr. Hartzell serves on the Environmental Committee of the Independent Oil and
Gas Association of Pennsylvania and is a past Chairman of the Committee. Mr.
Hartzell devotes approximately 100% of his professional time to the business and
affairs of the managing general partner and Atlas America.
DONALD R. LAUGHLIN. Vice President-Drilling and Production since September 2001.
Mr. Laughlin also serves as Vice President - Drilling and Production for Atlas
America since January 2002, and before that served as Senior Drilling Engineer
since May 2001 when he joined Atlas America. Mr. Laughlin has over thirty years
of experience as a petroleum engineer in the Appalachian Basin, having been
employed by Columbia Gas Transmission Corporation from October 1995 to May 2001
as a senior gas storage engineer and team leader, Cabot Oil & Gas Corporation
from 1989 to 1995 as Manager of Drilling Operations and Technical Services,
Doran & Associates, Inc. (an industrial engineering firm) from 1977 until 1989
as Vice President--Operations, and Columbia Gas from 1970 to 1977 as Drilling
Engineer and Gas Storage Engineer. Mr. Laughlin received his Petroleum
Engineering degree from the University of Pittsburgh in 1970. He is a member of
the Society of Petroleum Engineers. Mr. Laughlin devotes approximately 100% of
his professional time to the business and affairs of the managing general
partner and Atlas America.
MARCI F. BLEICHMAR. Vice President of Marketing since February 2001. Ms.
Bleichmar also serves as Vice President of Marketing for Atlas America since
February 2001 and was with Resource America from February 2001 until May 2004
when she resigned from Resource America. From March 2000 until February 2001,
Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a
mutual fund manager), and from March 1998 until March 2000, she was an account
executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms.
Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms.
Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in
1992. Ms. Bleichmar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.
SHERWOOD S. LUTZ. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined
Viking Resources, which was purchased by Resource America in 1999 as senior
geologist. Since 1999 Mr. Lutz has been a senior geologist for the managing
general partner and Atlas America. Mr. Lutz received his Bachelor of Science
degree in Geological Sciences from the Pennsylvania State University in 1973.
Mr. Lutz is a certified petroleum geologist with the American Association of
Petroleum Geologists as well as a licensed professional geologist in
Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to
the business and affairs of the managing general partner and Atlas America.
MICHAEL W. BRECKO. Director of Energy Sales since November 2002. Mr. Brecko has
over 16 years of natural gas marketing experience in the oil and natural gas
industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University
with a Bachelor of Science degree in Civil Engineering. His career in natural
gas marketing began when he joined Equitable Gas Company, a local distribution
company, as a marketing representative in the commercial/ industrial marketing
division from May 1986 to August 1992. He subsequently joined O&R Energy, a
subsidiary of Orange and Rockland Utilities, as regional marketing manager from
August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr.
Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and
natural gas producer, as an account executive and he was promoted in August 1998
to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a
multi-energy sourced company, as a regional account manager before joining Atlas
America in 2002. Mr. Brecko devotes approximately 100% of his professional time
to the business and affairs of the managing general partner and Atlas America.
54
KAREN A. BLACK. Vice President - Partnership Administration since February 2003.
Ms. Black is also Vice President and Financial and Operations Principal of
Anthem Securities since October 2002. Ms. Black joined the managing general
partner and Atlas America in July 2000 and served as manager of production,
revenue and partnership accounting from July 2000 through October 2001, after
which she served as manager and financial analyst until her appointment as Vice
President - Partnership Administration. Before joining the managing general
partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as
controller from April 1997 through June 2000. Ms. Black was employed as a tax
accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997.
Ms. Black received a Bachelor of Arts degree from the University of Pittsburgh,
Johnstown in 1982. Ms. Black devotes approximately 50% of her professional time
to the business and affairs of the managing general partner and Atlas America,
and the remainder of her professional time to the business and affairs of Anthem
Securities.
JUSTIN T. ATKINSON. Director of Due Diligence since February 2003. Mr. Atkinson
also serves as President of Anthem Securities since February 2004 and as Chief
Compliance Officer since October 2002. Before that Mr. Atkinson served as
assistant compliance officer of Anthem Securities from December 2001 until
October 2002 and Vice President from October 2002 until February 2004. Before
his employment with the managing general partner, Mr. Atkinson was a manager of
investor and broker/dealer relations with Viking Resources Corporation from 1996
until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business
Management in 1995 from Walsh University in North Canton, Ohio. Mr. Atkinson
devotes approximately 25% of his professional time to the business and affairs
of the managing general partner and Atlas America, and the remainder of his
professional time to the business and affairs of Anthem Securities.
WINIFRED C. LONCAR, Director of Investor Services since February 2003. Ms.
Loncar previously held the position of manager of investor services from the
inception of the investor service department in 1990 to February 2003. Before
that she was executive secretary to the managing general partner. Ms. Loncar
received a Bachelor of Science degree in Business from Point Park University in
1998. Ms. Loncar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.
ATLAS AMERICA, INC., A DELAWARE HOLDING COMPANY
As of February 2004, the officers and directors for Atlas America include the
following:
NAME AGE POSITION
- ------------------- --- ----------------------------------------------------
Edward E. Cohen 65 Chairman, Chief Executive Officer and President
Frank P. Carolas 45 Executive Vice President
Freddie M. Kotek 49 Executive Vice President and Chief Financial Officer
Jeffrey C. Simmons 46 Executive Vice President
Michael L. Staines 55 Executive Vice President and Secretary
Nancy J. McGurk 49 Senior Vice President and Chief Accounting Officer
Jonathan Z. Cohen 34 Vice Chairman
Carlton M. Arrendell 42 Director
William R. Bagnell 41 Director
Donald W. Delson 53 Director
Nicholas DiNubile 52 Director
Dennis A. Holtz 64 Director
See "- Officers, Directors and Other Key Personnel," above, for biographical
information on certain of these individuals who are also officers of the
managing general partner. Biographical information on the other officers and
directors will be provided by the managing general partner on request.
As of June 1, 2004, the managing general partner and its affiliates under Atlas
America employ a total of approximately 205 persons.
At September 30, 2004 Atlas America and its affiliates had more than $998
million of energy assets under management.
55
ORGANIZATIONAL DIAGRAM AND SECURITY OWNERSHIP OF BENEFICIAL OWNERS
See "- Managing General Partner and Operator" above for a discussion of Atlas
America's stock offering and the percentage of stock owned by Resource America
in Atlas America, the Delaware holding company, which owns 100% of the common
stock of AIC, Inc., which owns 100% of the common stock of the managing general
partner. The directors of AIC, Inc. are Jonathan Z. Cohen, Michael L. Staines,
and Jeffrey C. Simmons. The biographies of Messrs. Staines, and Simmons are set
forth above.
This organizational diagram does not include all of the subsidiaries of Resource
America, as discussed above.
Resource America, Inc.
Atlas Energy Holdings, Inc.
Atlas America, Inc. (Delaware)
(holding company) (1)
Viking AIC, Inc. Atlas America, Inc. Resource Energy, Atlas Noble
Resources (Pennsylvania) Inc. (2) Corporation (2)
Corporation (2) (operating company)
Atlas Resources, Inc., Atlas Energy Pennsylvania Anthem Securities, Atlas Energy
managing general Corporation, Industrial Energy, Inc., registered Group, Inc.,
partner of Atlas managing general Inc. broker/dealer and driller and
America Public partner of dealer-manager operator in Ohio
#14-2004 Program, exploratory
driller and operator drilling
in Pennsylvania partnerships and
driller and operator
ARD Investments, AED Investments,
Inc. Inc.
- ----------
(1) See "- Managing General Partner and Operator," above, for the discussion of
Atlas America's stock offering.
(2) Viking Resources, Resource Energy, and Atlas Noble Corporation are also
engaged in the oil and gas business. 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 partnerships. These persons will
receive compensation solely from affiliated companies of the managing general
partner.
CODE OF BUSINESS CONDUCT AND ETHICS
Because the partnerships do not directly employ any persons, the managing
general partner has determined that the partnerships will rely on a Code of
Business Conduct and Ethics adopted by Atlas America, Inc. that applies to the
principal executive officer, principal financial officer and principal
accounting officer of the managing general partner, as well as to
56
persons performing services for the managing general partner generally. You may
obtain a copy of this code of ethics by a request to the managing general
partner at Atlas Resources, Inc., 311 Rouser Road, Moon Township, Pennsylvania
15108.
TRANSACTIONS WITH MANAGEMENT AND AFFILIATES
The managing general partner depends on its parent company, Atlas America, for
management and administrative functions and financing for capital expenditures.
The managing general partner pays a management fee to Atlas America for
management and administrative services, which amounted to $23.2 million, $13.1
million, and $10.5 million for the years ended September 30, 2004, 2003, and
2002, respectively. (See "Financial Information Concerning the Managing General
Partner and Atlas America Public #14-2005(A) L.P.")
The managing general partner and its officers, directors and affiliates have in
the past invested, and may in the future invest, in partnerships sponsored by
the managing general partner. They may also subscribe for units in each
partnership as described in "Plan of Distribution."
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION, RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL
RESOURCES
Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P.
have been formed as limited partnerships under the Delaware Revised Uniform
Limited Partnership Act. The partnerships, however, have not included any
historical information in this prospectus since they:
o have no net worth;
o do not own any properties on which wells will be drilled;
o have no third-party investors; and
o have not conducted any operations.
(See "Capitalization and Source of Funds and Use of Proceeds," "Proposed
Activities," "Competition, Markets and Regulation," and "Financial Information
Concerning the Managing General Partner and Atlas America Public #14-2005(A)
L.P.")
Each partnership will depend on the proceeds of this offering and the managing
general partner's capital contributions to carry out its proposed activities.
Each partnership intends to use its subscription proceeds to pay the intangible
drilling costs, the investors' share of equipment costs, and the investors'
share of any cost overruns of drilling and completing the partnership's wells.
The managing general partner believes that each partnership's liquidity
requirements will be satisfied from the following:
o subscription proceeds of this offering;
o the managing general partner's capital contributions;
o cash flow from future operations; and
o partnership borrowings, if necessary.
The managing general partner also anticipates that no additional funds will be
required for operating costs before a partnership begins receiving production
revenues from its wells.
57
Substantially all of the subscription proceeds of you and the other investors in
a partnership will be committed or expended after the offering of the
partnership closes. If a partnership requires additional funds for cost overruns
or additional development or remedial work after a well begins producing, then
these funds may be provided by:
o subscription proceeds, if available, drilling fewer wells, or
acquiring a lesser working interest in one or more wells;
o borrowings from the managing general partner or its affiliates; or
o retaining partnership revenues.
There will be no borrowings from third-parties. The amount that may be borrowed
by a partnership from the managing general partner and its affiliates may not at
any time exceed 5% of the partnership's subscription proceeds from you and the
other investors and must be without recourse to you and the other investors. The
partnership's repayment of any borrowings would be from partnership production
revenues and would reduce or delay your cash distributions.
If the managing general partner loans money to a partnership, which it is not
required to do, then:
o the interest charged to the partnership must not exceed the managing
general partner's interest cost or the interest that would be charged
to the partnership without reference to the managing general partner's
financial abilities or guarantees by unrelated lenders, on comparable
loans for the same purpose; and
o the managing general partner may not receive points or other financing
charges or fees, although the actual amount of the charges incurred
from third-party lenders may be reimbursed to the managing general
partner.
Currently, Atlas America (the "borrower") has a $75 million revolving credit
facility with a group of banks with Wachovia Bank, N.A. as the agent and issuing
bank. The managing general partner, Resource America and various energy
subsidiaries of Atlas America are guarantors of the credit agreement. As of
September 30, 2004, this facility had a borrowing base of $75 million.
Borrowings under the facility are collateralized by substantially all of the
assets of Atlas America, the managing general partner and the other guarantors.
This includes the managing general partner's interests in its partnerships, but
does not include any investor's interest in a partnership. A breach of the
credit agreement by the borrower is a default under the loan. The credit
facility's term ends in July 2005. At September 30, 2004, the borrower had an
outstanding balance of approximately $25.0 million and also had a $1.7 million
letter of credit issued under the facility.
The managing general partner depends on its parent company, Atlas America, for
management and administrative functions and financing for capital expenditures.
The managing general partner pays a management fee to Atlas America for
management and administrative services, as described in "Management -
Transactions with Management and Affiliates." See the footnotes to the managing
general partner's audited financial statements and the footnotes to the managing
general partner's unaudited financial statements for more details concerning the
credit facility and inter-company borrowings in "Financial Information
Concerning the Managing General Partner and Atlas America Public #14-2005(A)
L.P."
PROPOSED ACTIVITIES
OVERVIEW OF DRILLING ACTIVITIES
The managing general partner anticipates that the subscription proceeds of each
partnership will be used to drill primarily natural gas development wells, which
means a well drilled within the proved area of a natural gas or oil reservoir to
the depth of a stratigraphic horizon known to be productive. Stratigraphic means
a layer of rock which has characteristics that differentiate it from the rocks
above and below it. Stratigraphic horizon generally means that part of a
formation or layer of rock with sufficient porosity and permeability to form a
petroleum reservoir. Currently, the partnerships do not hold any interests in
any properties or prospects on which the wells will be drilled.
58
Although the majority of the wells will be classified as natural gas wells,
which may produce a small amount of oil, some of the wells, such as those in
McKean County, Pennsylvania, may be classified as oil or combination oil and
natural gas wells.
Each partnership will be a separate business entity from the other partnerships,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnerships unless you also invest in the other partnerships. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest.
Each partnership generally will drill different wells, but they may own working
interests and participate in drilling and completing one or more of the same
wells. The number of wells to be drilled by a partnership cannot be determined
precisely before the funding of the partnership and is determined primarily by:
o the amount of subscription proceeds raised by the partnership;
o the geographical areas in which wells are drilled by the partnership;
o the partnership's percentage of working interest owned in the wells,
which could range from 25% to 100%; and
o the cost of the partnership's wells, including any cost overruns for
intangible drilling costs of the wells which are paid 100% by you and
the other investors in the partnership.
For the estimated number of wells to be drilled at the minimum subscription
proceeds of $2 million and the maximum subscription proceeds of $72,430,500 for
a partnership, see "Risk Factors - Risks Related to an Investment in a
Partnership - Spreading the Risks of Drilling Among a Number of Wells Will be
Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer
Wells are Drilled."
Before the managing general partner selects a prospect on which a well will be
drilled by a partnership, it will review all available geologic and production
data for wells located in the vicinity of the proposed well including, but not
limited to:
o various well logs;
o completion reports;
o plugging reports; and
o production reports.
For example, production information from surrounding wells in the area is an
important indicator in evaluating the economic potential of a proposed well to
be drilled. It has been the managing general partner's experience that natural
gas production from wells drilled to the formations or the reservoirs in the
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 on contiguous prospects. However, production information is
only one factor and the managing general partner may propose a well to be
drilled by a partnership because geologic trends in the immediate area, such as
sand thickness, porosities and water saturations, lead the managing general
partner to believe that the proposed well locations will be productive.
PRIMARY AREAS OF OPERATIONS
The managing general partner will not decide on the specific wells to be drilled
in either partnership until the offering of units in that partnership has ended.
However, the managing general partner intends that Atlas America Public
#14-2005(A) L.P. will drill the prospects described in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #14-2005(A)
L.P." These prospects represent the wells to be drilled if the majority of the
nonbinding targeted subscription proceeds as described in "Terms of the Offering
- - Subscription to a Partnership" are received, although the managing general
partner has the sole discretion to sell all of the remaining units in Atlas
America Public #14-2005(A) L.P.
59
and not offer and sell any units in Atlas America Public #14-2005(B) L.P. If
there are adverse events with respect to any of the currently proposed
prospects, the managing general partner will substitute the partnership's
prospects as discussed below in "- Interests of Parties." The managing general
partner also anticipates that it will designate a portion of the prospects in
the partnership designated Atlas America Public #14-2005(B) L.P. by a supplement
or an amendment to the registration statement of which this prospectus is a
part.
Because not all of the prospects for each partnership will be specified, you
will not be able to evaluate some or the majority of the specific prospects that
will be drilled by your partnership. However, by waiting as long as possible
before selecting all of the specific prospects to be drilled by a partnership,
the managing general partner may acquire additional information to help it
select better prospects for the partnership, and it may be able to include
prospects which were not available when this prospectus was written or even when
the offering of units in the partnership 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 five primary areas for the partnerships' drilling activities are:
o the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and
Greene Counties, Pennsylvania;
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 Upper Devonian Sandstone reservoirs in Armstrong County,
Pennsylvania;
o the Upper Devonian Sandstone reservoirs in McKean County,
Pennsylvania; and
o the Mississippian (carbonates) and Devonian Shale reservoirs in
Anderson, Campbell, Morgan and Roane Counties, Tennessee.
Fayette County, Greene County, Armstrong County and McKean County are in western
Pennsylvania. The Clinton/Medina geological formation in Pennsylvania and Ohio
is the same geological formation, although in Pennsylvania it is often referred
to as the Medina/Whirlpool geological formation. For purposes of this
prospectus, the term Clinton/Medina geological formation is used for both Ohio
and Pennsylvania. The wells drilled to the Clinton/Medina geological formation,
regardless of whether they are situated in western Pennsylvania, eastern Ohio,
western New York, or southern Ohio, the Mississippian and/or Upper Devonian
Sandstone reservoirs and the Mississippian (carbonates) and Devonian Shale
reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
have the following similarities:
o geological features such as structure and faulting are not generally
factors used in finding commercial production from a well drilled to
this formation or these reservoirs and the governing factors appear to
be sand or oolite (carbonate sand) quality in terms of net pay zone
thickness, porosity, and the effectiveness of fracture stimulation;
o a well drilled to this formation or these reservoirs usually requires
hydraulic fracturing of the formation to stimulate productive
capacity;
o generally, natural gas from a well drilled to this formation or these
reservoirs is produced at rates which decline rapidly during the first
few years of operations, and although the well can produce for many
years, a proportionately larger amount of production can be expected
within the first several years; and
o it has been the managing general partner's experience that natural gas
production from wells drilled to this formation or these reservoirs is
reasonably consistent with nearby wells, although from time to time
there can be great differences in the natural gas volumes and
performance of wells on contiguous prospects.
60
The managing general partner anticipates that the majority of the subscription
proceeds of each partnership will be expended in the primary areas, although
some of the subscription proceeds of each partnership may be expended in the
secondary areas or in areas which are not currently known. In the primary areas,
the managing general partner anticipates that more prospects will be drilled in
Fayette County than the other areas in each partnership.
MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS, FAYETTE COUNTY, PENNSYLVANIA.
The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous
lens-shaped accumulations found throughout most of the Appalachian Basin. These
reservoirs have porosities ranging from 5% to 20% with attendant permeabilities.
Porosity is the percentage of void space between sand grains that is available
for occupancy by either liquids or gases; and permeability is the property of
porous rock that allows fluids or gas to flow through it. See the geologic
evaluation prepared by United Energy Development Consultants, Inc., an
independent geological and engineering firm, for a discussion of the development
of the Mississippian/Upper Devonian Sandstone reservoirs in Fayette 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;
o drilled at least 1,000 feet from a producing well, although a
partnership may drill a new well or re-enter an existing well which is
closer than 1,000 feet to a plugged and abandoned well;
o drilled from approximately 1,900 to 5,500 feet in depth;
o classified as natural gas wells which may produce a small amount of
oil; and
o primarily connected to the gathering system owned by Atlas Pipeline
Partners and have their natural gas production primarily marketed to
UGI Energy Services as described below in "- Sale of Natural Gas and
Oil Production" for the period from November 1, 2004 through March 31,
2007.
CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA. The Clinton/Medina
geological formation is a blanket sandstone found throughout most of the
northwestern edge of the Appalachian Basin. The Clinton/Medina is described in
petroleum industry terms as a "tight" sandstone with porosity ranging from 6% to
12% and with very low natural permeability. Based on the managing general
partner's experience, it anticipates that all of the natural gas wells drilled
to the Clinton/Medina will be completed and fraced in two different zones of the
Clinton/Medina geological feature. See the geologic evaluation and the model
decline curve prepared by United Energy Development Consultants, Inc. in
"Appendix A - Information Regarding Currently Proposed Prospects for Atlas
America Public #14-2005(A) L.P." 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
61
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.
UPPER DEVONIAN SANDSTONE RESERVOIRS, ARMSTRONG COUNTY, PENNSYLVANIA. The Upper
Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found
throughout most of the Appalachian Basin. These reservoirs have porosities
ranging from greater than 5% to 20% with attendant permeabilities. See the
geologic evaluation prepared by United Energy Development Consultants, Inc. 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 "-
Interests of Parties," and U.S. Energy will participate in the drilling of the
wells with the partnerships.
The wells in the Upper Devonian Sandstone reservoirs will be:
o situated on approximately 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 some of the wells the managing general partner has drilled to date
in this general area have been drilled less than 1,000 feet apart, but
even in those cases the wells were approximately 980 feet or more from
each other;
o drilled from approximately 1,800 to 4,400 feet in depth;
o classified as natural gas wells which may produce a small amount of
oil; and
o connected to a gathering system owned by U.S. Energy and have their
natural gas production marketed by U.S. Energy as described below in
"- Sale of Natural Gas and Oil Production."
UPPER DEVONIAN SANDSTONE RESERVOIRS IN MCKEAN COUNTY, PENNSYLVANIA. See "- Upper
Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania," above, for a
description of these reservoirs and also see the geologic evaluation prepared by
United Energy Development Consultants, Inc. for a discussion of the Upper
Devonian Sandstone Reservoirs in McKean County, Pennsylvania. Wells located in
McKean County and drilled to the Upper Devonian Sandstone reservoirs will be:
o situated on approximately 6 acres subject to adjustments to take into
account lease boundaries;
o drilled from approximately 2,000 to 2,500 feet in depth;
o classified as combination wells producing both natural gas and oil;
and
o connected to the gathering systems owned by Atlas Pipeline Partners
and M&M Royalty, LTD. and have their natural gas production primarily
marketed to M&M Royalty, LTD. as described below in "- Sale of Natural
Gas and Oil Production."
MISSISSIPPIAN CARBONATE AND DEVONIAN SHALE RESERVOIRS IN ANDERSON, CAMPBELL,
MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE. The Mississippian carbonate
reservoirs are discontinuous lens shaped accumulations found in the southern
Appalachian states of West Virginia, Virginia, Kentucky and Tennessee. These
reservoirs have porosities ranging from 6% to 20% with attendant permeabilities.
The Devonian shale is found throughout the Appalachian Basin. When the shale is
highly fractured it becomes a reservoir. See the geologic evaluation prepared by
United Energy Development Consultants, Inc.,
62
an independent engineering firm for a discussion of the development of the
Mississippian carbonate and Devonian Shale reservoirs in Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee.
The wells in the Mississippian carbonate and Devonian Shale reservoirs will be:
o situated on 40 acres;
o drilled 1,320 feet from each other unless topography dictates
otherwise, however, in all cases no less than 700 feet;
o drilled from approximately 2,000 to 4,600 feet in depth;
o classified as natural gas wells which may produce a small amount of
oil; and
o primarily connected to the gathering system owned by Knox Energy LLC,
which is referred to as the Coalfield Pipeline, and have their natural
gas production primarily marketed to Duke Energy as described below in
"- Sale of Natural Gas and Oil Production."
The prospects in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
were acquired from Knox Energy LLC as described below in "- Interests of
Parties" and Knox Energy may participate in the drilling of the wells with the
partnership.
SECONDARY AREAS OF OPERATIONS
The managing general partner also has reserved the right to use a portion of the
subscription proceeds of each partnership to drill development wells in other
areas of the Appalachian Basin. The secondary areas anticipated by the managing
general partner are discussed below.
CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN NEW YORK. Wells located in
western New York and drilled to the Clinton/Medina geological formation will be:
o primarily situated in Chautauqua County;
o situated on approximately 40 acres, subject to adjustment to take into
account lease boundaries;
o drilled from approximately 3,800 to 4,000 feet in depth;
o drilled on leases with a net revenue interest of approximately 84.375%
to 87.5%;
o classified as natural gas wells which may produce a small amount of
oil; and
o connected to the gathering system owned by Atlas Pipeline Partners and
have their natural gas production primarily marketed to First Energy
Solutions Corporation as described below, and/or commercial end 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."
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;
63
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 partnerships.
ACQUISITION OF LEASES
The managing general partner will have the right, in its sole discretion, to
select the prospects which each partnership will drill. The managing general
partner intends that Atlas America Public #14-2005(A) L.P. will drill the
prospects described in "Appendix A - Information Regarding Currently Proposed
Prospects for Atlas America Public #14-2005(A) L.P." The managing general
partner also anticipates that it will designate a portion of the prospects in
the partnership designated Atlas America Public #14-2005(B) L.P. by a supplement
or an amendment to the registration statement of which this supplement is a
part.
The leases covering each prospect on which one well will be drilled will be
acquired by a partnership from the managing general partner or its affiliates
and credited to the managing general partner as a part of its required capital
contribution to the partnership. Neither the managing general partner nor its
affiliates will receive any royalty or overriding royalty interest on any well.
The managing general partner anticipates that it will select the prospects for
each partnership, including any additional and/or substituted prospects, from
the following:
o leases in its and its affiliates' existing leasehold inventory;
o leases that are subsequently acquired by it or its affiliates; or
o leases owned by independent third-parties that may participate with
the partnership in drilling wells.
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 September 30, 2004, the managing general partner's and
its affiliates' undeveloped leasehold acreage was as follows:
64
UNDEVELOPED LEASE ACREAGE
-------------------------
GROSS NET (1)
------- -------
Kentucky......................................... 9,710 4,855
Montana.......................................... 2,650 2,650
New York......................................... 37,365 37,365
Ohio............................................. 39,547 36,308
Pennsylvania..................................... 149,613 149,613
West Virginia.................................... 10,806 5,403
Wyoming.......................................... 80 80
------- -------
Total...................... 249,771 236,274
======= =======
(1) The net acreage as to which leases expire in fiscal 2004, 2005 and 2006 are
as follows: New York: 2006 - 188 acres; Ohio: 2004 - 155 acres, 2005 - 255
acres, 2006 - 96 acres; Pennsylvania: 2004 - 484 acres, 2005 - 31,667
acres, 2006 - 25,274 acres.
Most, if not all, of the prospects to be selected for the partnerships are
expected by the managing general partner to be single well proved undeveloped
prospects. Thus, only one well will be drilled on those prospects and the number
of prospects the managing general partner will assign to each partnership will
be the same as the number of wells which the partnership has the funds to drill.
This also means that the partnership, in all likelihood, will not farmout any
acreage associated with those prospects. However, the need for a farmout might
arise, for example, if during drilling or subsequently the managing general
partner determines there might be a productive horizon situated above (i.e.
uphole) the target horizon, but the partnership does not have the funds to
complete the well in the horizon or the completion of the horizon would be
inconsistent with the partnership's objectives. In this event, the managing
general partner might determine to farmout the activity for the partnership.
Generally, a farmout is an agreement in which the owner of the lease or existing
well agrees to assign its interest in certain acreage under the lease or the
existing well to an assignee subject to the assignee drilling one or more wells
or completing or recompleting the existing well in one or more horizons. The
owner would retain some interest in the assigned acreage or well. See "Conflicts
of Interest - Conflicts Involving the Acquisition of Leases" for the procedure
for a farmout, and "Material Federal Income Tax Consequences - Farmouts."
DEEP DRILLING RIGHTS RETAINED BY MANAGING GENERAL PARTNER. The lease assignments
to each partnership generally will be limited to a depth of from the surface
through the completion total depth of the well (in the case of wells drilled in
north central Tennessee the assignment will include an additional 100 feet below
the deepest producing formation in the well), and the managing general partner
will retain the deeper drilling rights including ownership of any coal bed
methane production that might be obtained from the deeper formations.
Conversely, as between a partnership and the managing general partner, the
partnership will own any coal bed methane production that might be obtained from
the shallower formations that are not included in the deeper drilling rights
retained by the managing general partner.
The amount of the credit the managing general partner receives for the leases it
contributes to a partnership does not include any value allocable to the deeper
drilling rights retained by it. If in the future the managing general partner
undertakes any activities with respect to the deeper formations, 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 that is
created in favor of someone other than the landowner. In either case, the owner
of the interest receives a specific percentage of the natural gas and oil
production free and clear of all costs of development, operation, or maintenance
of the well. This is compared
65
with a working interest, which generally means an interest in the lease under
which the owner of the interest must pay some portion of the cost of
development, operation, or maintenance of the well. Also, the leases will be
subject to terms that are customary in the industry such as free gas to the
landowner-lessor for home heating requirements, etc.
The managing general partner anticipates that each partnership generally will
have a net revenue interest in its leases in its primary drilling areas as set
forth in the chart below. Net revenue interest generally means the percentage of
revenues the owner of an interest in a well is entitled to receive under the
lease. The following chart expresses the percentage of production revenues that
the managing general partner, the landowner, other third-parties, and you and
the other investors in a partnership will share in from the wells in three of
the five primary proposed areas. The fourth and fifth primary proposed areas in
Armstrong County, Pennsylvania and Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee are discussed following the chart. The chart assumes that
the partnership owns 100% of the working interest in the well. If a partnership
acquires a lesser percentage working interest in a well, which will be the case
for all of the proposed wells situated in Armstrong County, Pennsylvania and may
be the case in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee,
then the partnership's net revenue interest in that well will decrease
proportionately.
The actual number, identity and percentage of working interests or other
interests in prospects to be acquired by the partnerships will depend on, among
other things:
o the amount of subscription proceeds received in a partnership;
o the latest geological and production data;
o potential title or spacing problems;
o availability and price of drilling services, tubular goods and
services;
o approvals by federal and state departments or agencies;
o agreements with other working interest owners in the prospects;
o farmins and farmouts; and
o continuing review of other prospects that may be available.
PRIMARY AREAS.
CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA AND
MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS IN FAYETTE AND GREENE
COUNTIES, PENNSYLVANIA AND UPPER DEVONIAN SANDSTONE RESERVOIRS IN MCKEAN COUNTY,
PENNSYLVANIA.
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP
ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST (2)
- ------ --------------------------- -------------------------------- ------------------------
Managing General Partner............ 32% partnership interest(1) 28.0%
Investors........................... 68% partnership interest(1) 59.5%
Third Party......................... 12.5% Landowner Royalty Interest 12.5%
------
100.0%
======
- ----------
(1) These percentages are for illustration purposes only and assume the
managing general partner's minimum required capital contribution to each
partnership of 25% and capital contributions of 75% from you and the other
investors. The actual percentages are likely to be different because they
will be based on the actual capital contributions of the managing general
partner and you and the other investors. However, the managing general
partner's total revenue share may not exceed 35% of partnership revenues
regardless of the amount of its capital contributions.
66
(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 to a partnership of 84.375% which
would reduce the investors' net revenue interest in the above chart to 57.375%
assuming a 100% working interest. U.S. Energy, the originator of the leases,
however, will retain a 25% working interest in the wells and participate with
the partnership in the costs of drilling, completing, and operating the wells to
the extent of its retained working interest. Thus, the net revenue interest to
the investors will be reduced to approximately 43% which is 75% of 57.375%.
MISSISSIPPIAN CARBONATE AND DEVONIAN SHALE RESERVOIRS IN ANDERSON, CAMPBELL,
MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE. The leases in Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee will have a net revenue interest to
a partnership ranging from 83.4375% to 81.875% assuming a 15% landowner royalty
interest, and depending on whether Knox Energy LLC and its affiliates, the
originators of the leases, participate as a working interest owner in the
leases. Knox Energy and its affiliates may retain up to a 50% working interest
in the wells and participate with the partnership in the costs of drilling,
completing, and operating the wells to the extent of its retained working
interest. If Knox Energy does not retain a working interest in a well, then its
overriding royalty interest will be 3.125%. However, if Knox Energy retains a
50% working interest in a well, then its overriding royalty interest of 3.125%
will be reduced to 1.5625%. To the extent that Knox Energy participates in a
well as a working interest owner for less than a 50% working interest, the
overriding royalty interest to Knox Energy will be prorated between an
overriding royalty interest of 3.125% and 1.5625%. The investors' net revenue
interest in the above example would range from 56.7375% to 55.675% if presented
on a 100% working interest basis. The managing general partner anticipates that
two of the seven specified properties will be subject to a 15% landowner royalty
interest, and four of the other five leases have a 12.5% landowner royalty
interest. The landowner royalty interest in the seventh specified prospect, 1HW
in Morgan County, Tennessee, is determined by a formula based on the price of
natural gas received by the partnership from the sale of the natural gas
production from the well, if any, and will either be 12.5% or 15.5%. (See
footnote (4) on page 81 of Appendix A for a description of this formula.)
Pursuant to the acquisition terms between the managing general partner and its
affiliates and Knox Energy and its affiliates, no well drilled by the managing
general partner and its affiliates in this area may produce coalbed methane gas,
and the managing general partner or its affiliates must drill 300 commitment
wells during the initial three year term of the agreement or it is a breach of
the agreement.
SECONDARY AREAS. Although the managing general partner anticipates that each
partnership will have a net revenue interest ranging from 81% to 87.5% in the
secondary areas described above, there is no minimum net revenue interest that a
partnership is required to own before drilling a well in other areas of the
United States. The leases in these other areas may be subject to interests in
favor of third-parties that are not currently known such as:
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:
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o the managing general partner;
o the operator;
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. Although past performance is no guarantee of future results, as
of September 30, 2004 the previous partnerships sponsored by the managing
general partner and its affiliates have participated in drilling more than 3,376
wells in the Appalachian Basin since 1985, and none of the wells have been lost
because of title failure. (See "Prior Activities.")
DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS
The managing general partner intends that Atlas America Public #14-2005(A) L.P.
will drill the prospects described in "Appendix A - Information Regarding
Currently Proposed Prospects for Atlas America Public #14-2005(A) L.P." These
prospects represent the majority of the wells to be drilled if the nonbinding
targeted subscription proceeds described in "Terms of the Offering -
Subscription to a Partnership" are received, although the managing general
partner has the sole discretion to sell all of the remaining units in Atlas
America Public #14-2005(A) L.P. and not offer and sell any units in Atlas
America Public #14-2005(B) L.P. The managing general partner also anticipates
that it will designate a portion of the prospects in the partnership designated
Atlas America Public #14-2005(B) L.P. by a supplement or an amendment to the
registration statement of which this prospectus is a part. On receipt of the
minimum subscription proceeds the managing general partner on behalf of a
partnership may break escrow, transfer the escrowed funds to a partnership
account, enter into the drilling and operating agreement, which is attached to
the partnership agreement as Exhibit II, with itself or an affiliate as
operator, and begin drilling to the extent the prospects have been identified in
this prospectus or in a supplement or an amendment to the registration
statement.
Under the drilling and operating agreement, the responsibility for drilling and
either completing or plugging partnership wells will be on the managing general
partner or an affiliate as the operator and the general drilling contractor.
Under the drilling and operating agreement, each partnership is required to
prepay the investors' share of the drilling and completion costs of its wells to
the managing general partner as the operator. If one or more of a partnership's
wells will be drilled in the calendar year after the year in which the advance
payment is made, the required advance payment allows the partnership to secure
tax benefits of prepaid intangible drilling costs based on a substantial
business purpose for the advance payment under the drilling and operating
agreement. The managing general partner as operator and general drilling
contractor will begin drilling the wells no later than March 31, 2006 for Atlas
America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. (See
"Material Federal Income Tax Consequences - Drilling Contracts.")
During drilling operations the managing general partner's duties as operator and
general drilling contractor will include:
o making the necessary arrangements for drilling and completing
partnership wells and related facilities for which it has
responsibility under the drilling and operating agreement;
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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 development 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 $3.30 per mcf, which means 1,000 cubic feet of natural gas, in 2000;
o $4.08 per mcf in 2001;
o $3.34 per mcf in 2002;
o $4.78 per mcf in 2003; and
o $5.82 per mcf in 2004.
These prices were after the effects of hedging.
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If all the natural gas produced cannot be sold because of limited gathering line
or pipeline capacity, or limited demand for the natural gas, which increases
pipeline pressure, then the production that is sold will be from those wells
which have the greatest well pressure and are able to feed into the pipeline,
regardless of which partnerships own the wells. The proceeds from these natural
gas sales will be credited only to the partnerships whose wells produced the
natural gas sold.
GATHERING OF NATURAL GAS. Under the partnership agreement the managing general
partner will be responsible for gathering and transporting the natural gas
produced by the partnerships to interstate pipeline systems, local distribution
companies, and/or end-users in the area. For the majority of each partnership's
natural gas production, including natural gas in the primary areas, as discussed
below, the managing general partner anticipates that it will use the gathering
system owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating
Partnership) which is a master limited partnership formed by a subsidiary of
Atlas America as managing general partner using Atlas America and Viking
Resources personnel who act as its officers and employees. Atlas Pipeline
Partners acquired the natural gas gathering system and related facilities of
Atlas America, Resource Energy, and Viking Resources in February 2000. At
December 31, 2003, the gathering system consists of approximately 1,380 miles of
intrastate pipelines located in Pennsylvania, Ohio, and New York. If a
partnership's natural gas is not transported through the Atlas Pipeline Partners
gathering system, it is because there is a third-party operator or the gathering
system has not been extended to the wells. In these cases, which includes the
McKean County area and the north central Tennessee area of Anderson, Campbell,
Morgan, Roane and Scott Counties, as described in "Compensation - Gathering
Fees," the natural gas will be transported through a third-party gathering
system, and the partnership will pay the managing general partner a competitive
gathering fee, all or a portion of which will be paid by it to the third-party.
Also, in the north central Tennessee area, the managing general partner and its
affiliates may construct a gathering system in the future for which it will
receive gathering fees as described in "Compensation - Gathering Fees."
As a part of the sale of the gathering system to Atlas Pipeline Partners in
February 2000, Atlas America and its affiliates, Resource Energy and Viking
Resources, made 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 and the Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee 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. Finally,
Atlas America, Resource Energy and Viking Resources agreed to assist Atlas
Pipeline Partners in identifying existing gathering systems for possible
acquisition and Atlas America 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. Initially, the majority of each partnership's natural gas
production will be sold to UGI Energy Services, Inc. As set forth in "- Primary
Areas of Operations" above, the managing general partner anticipates that more
prospects will be drilled in Fayette County than the other areas, and the
majority, if not all, of the natural gas produced from Fayette County will be
sold to UGI Energy Services until March 31, 2007. UGI Corporation has provided a
$7 million guaranty of the payment obligations of UGI Energy Services, Inc.
until March 31, 2007 subject to termination by UGI Corporation on 45 days prior
written notice. Also, the natural gas produced from Armstrong County will be
sold to U.S. Energy Exploration Corporation, the natural gas produced from
McKean County will be sold to M&M Royalty Ltd. and the natural gas produced from
Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee will be sold to
Duke Energy. The managing general partner anticipates that the remainder of the
natural gas produced by each partnership from wells
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drilled in the other primary and secondary areas will be sold to First Energy
Solutions Corporation. See "Appendix A - Information Regarding Currently
Proposed Prospects for Atlas America Public #14-2005(A) L.P."
The managing general partner and its affiliates have an agreement with First
Energy Solutions Corporation, which is the marketing affiliate of First Energy
Corporation, based in Akron, Ohio which is a large regional electric utility
listed on the New York Stock Exchange trading under the symbol (FE). As of
October 31, 2004 the managing general partner and its affiliates, including its
prior affiliated partnerships, were selling approximately 49.55% of their
natural gas production under the agreement with First Energy Solutions
Corporation. The parties to the agreement are the managing general partner,
Resource Energy and Atlas Energy Group, Inc., and the agreement is for a 10-year
term which began on April 1, 1999. Subject to the exceptions set forth below,
First Energy Solutions Corporation has the right 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.
However, initially natural gas from four of the five primary drilling areas will
not be sold to First Energy Solutions Corporation.
The agreement with First Energy Solutions Corporation requires the parties to
negotiate a new pricing arrangement at each delivery point for subsequent
contract periods which is usually one year. 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. The agreement with First Energy Solutions Corporation may be suspended
for force majeure, which means generally such things as an act of God, 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. The managing general partner agreed to a new pricing arrangement with
First Energy Solutions Corporation which is effective through March 2007. First
Energy Corporation has provided a guaranty of the monetary obligations of First
Energy Solutions Corporation of an amount up to $15 million for a period until
March 31, 2007, which will continue on a monthly basis thereafter unless
terminated on 30 days notice.
Initially natural gas from four of the five primary drilling areas will not be
sold to First Energy Solutions Corporation because of the exceptions to the
agreement set forth below.
o Natural gas sold through interconnects established after the agreement
with First Energy Solutions Corporation which includes the majority of
the natural gas produced from wells in Fayette County.
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 such as:
o natural gas produced from wells in Armstrong County,
Pennsylvania;
o natural gas produced from wells in McKean County, Pennsylvania;
and
o natural gas produced from wells in Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee.
o Natural gas that at the time of the agreement was already dedicated
for the life of the well to another buyer.
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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.
The pricing arrangements with UGI Energy Services, First Energy Solutions
Corporation, U.S. Energy Exploration Corporation, M&M Royalty Ltd., Duke Energy
and the other third-parties are tied to the New York Mercantile Exchange
Commission ("NYMEX") monthly futures contracts price, which is reported daily in
the Wall Street Journal. The total price received for each partnership's natural
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 natural gas (the Appalachian Basin)
in relation to the natural gas market which is referred to as the basis. The
premium over quoted prices on the NYMEX received by the managing general partner
and its affiliates has ranged between $0.34 to $0.65 per Mcf during the past
three fiscal years. These figures are based on the overall weighted average that
the managing general partner and its affiliates use in their annual reserve
reports, for the past three fiscal years. See "- Policy of Treating All Wells
Equally in a Geographic Area" for the average natural gas prices since 2000.
Pricing for natural gas and oil has been volatile and unpredictable for many
years. To limit the managing general partner's and its partnerships' exposure to
changes in natural gas prices the managing general partner uses hedges through
its natural gas purchasers as described below, and through contracts including
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.
First Energy Solutions Corporation, UGI Energy Services and other third-party
marketers also use NYMEX based financial instruments to hedge their pricing
exposure and make price hedging opportunities available to the managing general
partner. As of November 16, 2004, the majority of the managing general partner's
hedges were implemented through the natural gas purchasers. These transactions
are similar to NYMEX based futures contracts, swaps and options, but also
require firm delivery of the hedged quantity. Thus, the managing general partner
limits these arrangements to much smaller quantities than those projected to be
available at any delivery point. The price paid by First Energy Solutions
Corporation, 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 and/or costless collar pricing, which is a floor
price with a cap, etc.) changes from time to time. As of November 16, 2004, the
managing general partner's overall price hedging position for the future months
ending March 31, 2006 was approximately as follows:
o 71% was hedged with a fixed price;
o 2.2% was hedged with a floor price and/or costless collar price; and
o 26.8% was not hedged and was subject to market based pricing.
Approximately 63% of these hedges were implemented through First Energy
Solutions Corporation and 32% were implemented through UGI Energy Services. It
is difficult to project what portion of these hedges will be allocated to each
partnership by the managing general partner because of uncertainty about the
quantity, timing, and delivery locations of natural gas that may be produced by
a partnership. Although hedging provides the partnerships some protection
against falling prices, these activities also could reduce the potential
benefits of price increases.
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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:
o $26.21 per barrel in 2000;
o $22.60 per barrel in 2001;
o $18.92 per barrel in 2002;
o $29.06 per barrel in 2003; and
o $34.41 per barrel in 2004.
During the term of the partnerships it is anticipated that the price of oil will
be uncertain and volatile.
INSURANCE
Since 1972 the managing general partner and its affiliates, including its
partnerships, have been involved in the drilling of approximately 5,300 wells,
most of which were developmental wells, in Ohio, Pennsylvania, and other areas
of the Appalachian Basin. They have made only one material insurance claim. In
February 2004, one of the wells in another investment partnership incurred an
uncontrolled flow of natural gas and oil with a fire during drilling. These
problems with the well were subsequently controlled, but they resulted in the
loss of a subcontractor's drilling rig and third-party claims. As of October 22,
2004, the managing general partner's insurance carrier has paid approximately
$1,556,602 to third-parties for property damage claims and additional claims
have been submitted which have not yet been paid. The managing general partner's
insurance company is exploring all avenues for subrogation. See "Actions to be
Taken by Managing General Partner to Reduce Risks of Additional Payments by
Investor General Partners - Insurance" for a discussion of the insurance
coverage.
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.
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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 have not been regulated since 1993, 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.
Since 1985 FERC has sought to promote greater competition in natural gas markets
in the United States. Traditionally, natural gas was sold by producers to
interstate pipeline companies which served as wholesalers that resold the
natural gas to local distribution companies for resale to end-users. FERC
changed this market structure by requiring interstate pipeline companies to
transport natural gas for third-parties. In 1992 FERC issued Order 636 and a
series of related orders which required pipeline companies to, among other
things, separate their sales services from their transportation services and
provide an open access transportation service that is comparable in quality for
all natural gas producers or suppliers. The premise behind FERC Order 636 was
that the interstate pipeline companies had an unfair advantage over other
natural gas producers or suppliers because they could bundle their sales and
transportation services together. FERC Order 636 is designed to ensure that no
natural gas seller has a competitive advantage over another natural gas seller
because it also provides transportation services.
In 2000 FERC issued Order 637 and subsequent orders to enhance competition by
removing price ceilings on short-term capacity release transactions. It also
enacted other regulatory policies that are intended to enhance competition in
the natural gas market and increase the flexibility of interstate natural gas
transportation. FERC has further required pipeline companies to develop
electronic bulletin boards to provide standardized access to information
concerning capacity and prices.
CRUDE OIL REGULATION
Oil prices are not regulated, and the price is subject to the supply and demand
for oil, along with qualitative factors such as the gravity of the crude oil and
sulfur content differentials.
COMPETITION AND MARKETS
There are many companies engaged in natural gas and oil drilling operations in
the Appalachian Basin, where all or most of the wells in each partnership will
be located. According to the Energy Information Administration, the independent
statistical and analytical agency within the Department of Energy, in 2002 there
were 23 TCF (a "TCF" means one trillion cubic feet of natural gas) of natural
gas consumed in the United States which represented approximately 23.6% of the
total energy used. The Appalachian Basin accounted for approximately 3.4% of the
total domestic natural gas production in the United States in 2002. Also,
according to the Natural Gas Annual 2002 Report, which is published by the
Energy Information Administration Office of Oil and Gas, as of December 31,
2002, the Appalachian Basin's economically recoverable natural gas reserves
represented approximately 5.7% of total domestic natural gas reserves. Further,
World Oil magazine predicted in its February 2004 issue that approximately 5,576
oil and gas wells would be drilled in the Appalachian Basin during 2004,
representing approximately 16.7% of the total number of wells it predicted would
be drilled in the United States during 2004. This would be an increase of 12.8%
over the number of Appalachian wells to have been drilled during 2003, compared
to an increase of 9.7% in the total wells to have been drilled in the United
States during 2003.
The natural gas and oil industry is highly competitive in all phases, including
acquiring suitable leases to drill and marketing natural gas and oil production
from the wells. Product availability and price are the principal means of
competing in selling natural gas and oil. Many of the partnerships' competitors
will have financial resources and staffs larger than those available to the
partnerships. This may enable them to identify and acquire desirable leases and
market their natural gas and oil production more effectively than the managing
general partner and the partnerships. While it is impossible to accurately
determine the partnerships' industry position, the managing general partner does
not consider that the partnerships' intended operations will be a significant
factor in the industry.
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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 and oil
price increases which have occurred from time to time may increase the demand
for drilling rigs and other related equipment. This may increase the cost to
drill the partnerships' wells, which will be drilled on a cost plus 15% basis,
or reduce the availability of drilling rigs and related equipment, both of which
could adversely affect the partnerships. In this regard, the cost of a
partnership well has increased recently primarily because the cost of tubular
steel has increased as a result of rising steel prices.
The natural gas and oil produced by your partnership's wells must be marketed
for you to receive revenues. During the fiscal years ending 2004, 2003, and
2002, the managing general partner did not experience any problems in selling
natural gas and oil, although the prices varied significantly during those
periods. As set forth above, natural gas and oil prices are not regulated, but
instead are subject to factors which are generally beyond the partnerships'
control such as the supply and demand for the natural gas and oil. For example,
reduced natural gas demand and/or excess natural gas supplies will result in
lower prices. Other factors affecting the price and/or marketing of natural gas
and oil production, which are also beyond the control of the 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 competition from alternative fuels when large consumers of natural gas
are able to convert to alternative fuel use systems;
o local, state, and federal regulations regarding production and
transportation;
o the general level of market demand for natural gas and oil on a
regional, national and worldwide basis;
o fluctuating seasonal supply and demand for natural gas and oil because
of various factors such as home heating requirements in the winter
months;
o political instability and/or war in natural gas and oil producing
countries;
o the amount of domestic production of natural gas and oil; and
o the amount of foreign imports of natural gas and oil, including liquid
natural gas from Canada (which the managing general partner believes
becomes economic when natural gas prices are at or above $3.50 per
mcf), and the actions of the members of the Organization of Petroleum
Exporting Countries ("OPEC"), which include production quotas for
petroleum products from time to time with the intent of increasing,
maintaining, or decreasing price levels.
For example, the North American Free Trade Agreement ("NAFTA") eliminated trade
and investment barriers in the United States, Canada, and Mexico. From time to
time since then there have been increased imports into the United States of
Canadian natural gas. Without a corresponding increase in demand in the United
States, the imported natural gas would have an adverse effect on both the price
and volume of natural gas sales from the partnerships' wells.
The managing general partner is unable to predict what effect the various
factors set forth above will have on the future price of the natural gas and oil
sold from the partnerships' wells. However, according to the Energy Information
Administration in 2001, the use of natural gas in the United States is projected
to increase approximately 51% to 69% between 1999 and 2020. In addition, 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."
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Also, the accelerating deregulation of electricity transmission has caused a
convergence between the natural gas and electric industries. In 2003, according
to information from the Energy Information Administration, the breakout of
energy sources for the generation of electricity in the United States was as
follows:
o natural gas fired power plants were used to produce approximately 15%;
o coal-fired power plants were used to produce approximately 53%;
o nuclear power plants were used to produce approximately 21%; and
o large scale hydroelectric projects were used to produce approximately
7%.
In recent years, the electric industry has increased its reliance on natural gas
because of increased competition in the electric industry and the enforcement of
stringent environmental regulations. According to the Energy Information
Administration, the demand for natural gas by producers of electricity is
expected to increase through the decade. For example, the Environmental
Protection Agency has sought to enforce environmental regulations which increase
the cost of operating coal-fired power plants. Also, the last nuclear power
plant to come online in the United States was in June 1996, although the
existing nuclear power plants have increased their capacity and there have been
recent proposals for constructing new nuclear power plants. The managing general
partner believes that natural gas is the preferred fuel for producers of
electricity since they have started moving away from dirtier-burning fuels, such
as coal and oil. Also, some of the new natural gas fired power plants which are
coming into service are not designed to allow for switching to other fuels.
STATE REGULATIONS
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, including supervising the
production activities and the transportation of natural gas sold in intrastate
markets, which creates additional financial and operational burdens. Among other
things, these regulations involve:
o new well permit and well registration requirements, procedures, and
fees;
o landowner notification requirements;
o certain bonding or other security measures;
o minimum well spacing requirements;
o restrictions on well locations and underground gas storage;
o certain well site restoration, groundwater protection, and safety
measures;
o discharge permits for drilling operations;
o various reporting requirements; and
o well plugging standards and procedures.
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
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Protection Agency and state and local agencies will require the partnerships to
obtain permits and take other measures with respect to:
o the discharge of pollutants into navigable waters;
o disposal of wastewater; and
o air pollutant emissions.
If these requirements or permits are violated there can be substantial civil and
criminal penalties which will increase if there was willful negligence or
misconduct. In addition, the partnerships may be subject to fines, penalties and
unlimited liability for cleanup costs under various federal laws such as the
Federal Clean Water Act, the Clean Air Act, the Resource Conservation and
Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and
the Comprehensive Environmental Response, Compensation and Liability Act of 1980
for oil and/or hazardous substance contamination or other pollution caused by
the drilling activities or the well and its production.
Also, a partnership's liability can extend to pollution costs that occurred on
the leases before they were acquired by the partnership. Although the managing
general partner will not transfer any lease to a partnership if it has actual
knowledge that there is an existing potential environmental liability on the
lease, there will not be an independent environmental audit of the leases before
they are transferred to a partnership. Thus, there is a risk that the leases
will have potential environmental liability even before drilling begins.
A partnership's required compliance with these environmental laws and
regulations may cause delays or increase the cost of the partnership's drilling
and producing activities. Because these laws and regulations are frequently
changed, the managing general partner is unable to predict the ultimate costs of
complying with present and future environmental laws and regulations. Also, the
managing general partner is unable to obtain insurance to protect against many
environmental claims.
PROPOSED REGULATION
From time to time there are a number of proposals considered in Congress and in
the legislatures and agencies of various states that if enacted would
significantly and adversely affect the natural gas and oil industry and the
partnerships. The proposals involve, among other things:
o limiting the disposal of waste water from wells, which could
substantially increase a partnership's operating costs and make the
partnership's wells uneconomical to produce;
o changes in the tax laws as discussed in "Material Federal Income Tax
Consequences - Changes in the Law"; and
o tax credits and other incentives for the creation or expansion of
alternative energy sources.
Also, Congress could re-enact price controls in the future. However, it is
impossible to accurately predict what proposals, if any, will be enacted and
their subsequent effect on a partnership's activities.
PARTICIPATION IN COSTS AND REVENUES
IN GENERAL
The partnership agreement provides for the sharing of costs and revenues among
the managing general partner and you and the other investors. A tabular summary
of the following discussion appears below. Each partnership will be a separate
business entity from the other partnerships, and you will be a partner only in
the partnership in which you invest. You will have no interest in the business,
assets, or tax benefits of the other partnerships unless you also invest in the
other partnerships. Thus, your investment return will depend solely on the
operations and success or lack of success of the particular partnership in which
you invest.
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COSTS
1. ORGANIZATION AND OFFERING COSTS. Organization and offering costs will be
charged 100% to the managing general partner. However, the managing general
partner will not receive any credit towards its required capital
contribution or its revenue share for any organization and offering costs
charged to it in excess of 15% of a partnership's subscription proceeds.
o Organization and offering costs generally means all costs of
organizing and selling the offering and includes the
dealer-manager fee, sales commissions, the up to .5%
reimbursement for bona fide accountable due diligence expenses,
and the .5% accountable reimbursement for permissible non-cash
compensation.
The managing general partner will pay a portion of a partnership's
organization and offering costs to itself, its affiliates and third-parties
and it will contribute the remainder to the partnership in the form of
services related to organizing this offering. The managing general partner
will receive a credit for these payments and services towards its required
capital contribution in each partnership. The managing general partner's
credit for its contribution of services for organization costs will be
determined based on generally accepted accounting principles. The
definition of organization and offering costs is set forth in the
partnership agreement.
2. LEASE COSTS. Each partnership's leases will be contributed to it by the
managing general partner. The managing general partner will be credited
with a capital contribution for each lease valued at:
o its cost; or
o fair market value if the managing general partner has reason to
believe that cost is materially more than fair market value.
3. INTANGIBLE DRILLING COSTS. 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. See the discussion of equipment costs in 5, below.
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.
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o These costs generally include all costs of partnership
administration and producing and maintaining the partnership's
wells.
Each well in a partnership will have a different productive life. When the
managing general partner determines that a well has become uneconomic to
produce, it will cause the partnership to plug and abandon the well. The
costs of plugging and abandoning a well (other than those incurred in
connection with the drilling of a nonproductive well) are shared between
the managing general partner and you and the other investors in the same
percentage as the related production revenues are being shared. For
example, if the investors are receiving 68% of the partnership revenues and
the managing general partner is receiving 32% of the partnership revenues,
then the cost of plugging and abandoning the wells will be shared in the
same percentages. Typically, the managing general partner will apply the
salvage value of the equipment, which generally is shared 66% by the
managing general partner and 34% by you and the other investors, towards
this obligation. These sharing percentages, however, may vary to a small
degree as discussed in 4, above, depending on the total equipment costs for
your partnerships wells compared to 10% of the subscription proceeds of you
and the other investors in the partnership. See "Compensation - Drilling
Contracts," for a discussion of the partnerships' equipment costs estimated
by the managing general partner for an average well in the primary drilling
areas. To cover any shortfall for you and the other investors between your
share of the equipment proceeds and your share of the plugging and
abandoning costs of the well, the managing general partner has the right
beginning one year after a partnership well begins producing to retain up
to $200 per month to cover future plugging and abandonment costs of the
well. This $200 also includes a proportionate share of the managing general
partner's share of partnership revenues, which will be used exclusively for
the managing general partner's share of the plugging and abandonment costs
of the well. To the extent any portion of the reserve ultimately is not
needed for the plugging and abandonment costs of the well, then it will be
returned to the general operating revenues of the partnership.
6. THE MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTION. The managing
general partner's aggregate capital contributions to each partnership must
not be less than 25% of all capital contributions to that partnership. This
includes such items as the managing general partner's:
o credit for the cost of the leases contributed to the partnership,
or the fair market value of the leases if the managing general
partner has a reason to believe that cost is materially more than
fair market value;
o credit for organization and offering costs, including the costs
of services contributed as organization costs; and
o share of partnership equipment costs paid by it to itself as
operator under the drilling and operating agreement, which
includes its administrative overhead reimbursement and profit on
those costs.
The managing general partner's capital contributions must be paid or made at the
time the costs are required to be paid by the partnership, but not later than
the end of the year immediately following the year in which the partnership had
its final closing.
REVENUES
Each partnership's production revenues from all of its wells will be commingled.
Thus, regardless of when you subscribe to a partnership you will share in the
production revenues and any marginal well production credits from all of the
wells in that partnership on the same basis as the other investors in the
partnership in proportion to your number of units.
1. PROCEEDS FROM THE SALE OF LEASES. If a partnership well is sold, a portion
of the sales proceeds will be allocated to the partners in the same
proportion as their share of the adjusted tax basis of the property. In
addition, proceeds will be allocated to the managing general partner to the
extent of the pre-contribution appreciation in value of the property, if
any. Any excess will be credited as provided in 4, below.
2. INTEREST PROCEEDS. Interest income earned on your subscription proceeds
before your partnership's final closing will be credited to your account
and paid not later than the partnership's first cash distributions from
operations. After your partnership's final closing and until the
subscription proceeds are invested in your partnership's operations, any
interest
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income from temporary investments will be allocated pro rata to you and the
other investors providing the subscription proceeds. All other interest
income, including interest earned on the deposit of production revenues,
will be credited as provided in 4, below.
3. EQUIPMENT PROCEEDS. Proceeds from the sale or other disposition of
equipment will be credited to the parties charged with the costs of the
equipment in the ratio in which the costs were charged.
4. PRODUCTION REVENUES. Subject to the managing general partner's
subordination obligation as described below, the managing general partner
and the investors in a partnership will share in all of that partnership's
other revenues, including production revenues, in the same percentage as
their respective capital contribution bears to the total partnership
capital contributions, except that the managing general partner will
receive an additional 7% of that partnership's revenues. However, the
managing general partner's total revenue share may not exceed 35% of that
partnership's revenues regardless of the amount of its capital
contributions. For example, if the managing general partner contributes the
minimum of 25% of the total partnership capital contributions and the
investors contribute 75% of the total partnership capital contributions,
then the managing general partner will receive 32% of the partnership
revenues and the investors will receive 68% of the partnership revenues. On
the other hand, if the managing general partner contributes 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.
5. MARGINAL WELL PRODUCTION CREDITS. Any marginal well production credits
earned by a partnership will be allocated between the managing general
partner and you and the other investors in the partnership in the same
ratio in which the production revenues of the partnership are being shared
as described in "- 4. Production Revenues," above. (See "Material Federal
Income Tax Consequences - Marginal Well Production Credits.")
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, which will be up to
between 16% and 17.5% of the total 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 have been drilled, completed,
and begun 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 of capital described
above. The specific formula is set forth in Section 5.01(b)(4)(a) of the
partnership agreement.
The managing general partner anticipates that you will benefit from the
subordination if the price of natural gas and oil received by the partnership
and/or the results of the partnership's drilling activities are unable to
provide the required return. However, if the wells produce small natural gas and
oil volumes or natural gas and oil prices decrease, then even with subordination
your cash flow may be very small and you may not receive the 10% return of
capital for each of the first five years beginning with the partnership's first
cash distribution from operations.
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As of December 15, 2004, the managing general partner was subordinating a
portion or all of its net revenues in two of its fourteen limited partnerships
that currently have the subordination feature in effect. Since 1993 the managing
general partner has had a subordination feature in 28 of its partnerships and
from time to time it has subordinated its partnership net revenues in 16 of
these partnerships. The managing general partner is entitled to recoup these
subordination distributions during the subordination period to the extent cash
distributions to the investors in these previous partnerships would exceed the
specified return to the investors.
EXAMPLE OF NET REVENUE SHARING DURING A SUBORDINATION PERIOD.
NET REVENUES TO MANAGING
MAXIMUM AMOUNT OF GENERAL PARTNER AND
MANAGING GENERAL INVESTORS IF MAXIMUM AMOUNT
PERCENTAGE OF PERCENTAGE OF PARTNER'S SHARE OF OF MANAGING GENERAL
PARTNERSHIP PARTNERSHIP NET PARTNERSHIP NET PARTNER'S SHARE OF
CAPITAL REVENUES WITHOUT REVENUES AVAILABLE FOR PARTNERSHIP NET REVENUES IS
ENTITY CONTRIBUTIONS (1) SUBORDINATION (1) SUBORDINATION (2) SUBORDINATED (1)(2)
- ------ ----------------- ----------------- ----------------- -------------------
Managing General Partner....... 25% 32% 16% 16%
Investors...................... 75% 68% 84%
- ----------
(1) These percentages are for illustration purposes only and assume the
managing general partner's minimum required capital contribution of 25% to
each partnership and capital contributions of 75% from you and the other
investors. The actual percentages are likely to be different because they
will be based on the actual capital contributions of the managing general
partner and you and the other investors. However, the managing general
partner's total revenue share may not exceed 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 investment feature, the
managing general partner will subordinate up to 50% of its share of
partnership net production revenues, which will be up to between 16% and
17.5% of the total partnership net production revenues, during this
subordination period.
EXAMPLE OF NET REVENUE SHARING AFTER THE END OF A SUBORDINATION PERIOD.
NET REVENUES TO MANAGING
MAXIMUM AMOUNT OF GENERAL PARTNER AND
MANAGING GENERAL INVESTORS IF MAXIMUM AMOUNT
PERCENTAGE OF PERCENTAGE OF PARTNER'S SHARE OF OF MANAGING GENERAL
PARTNERSHIP PARTNERSHIP NET PARTNERSHIP NET PARTNER'S SHARE OF
CAPITAL REVENUES WITHOUT REVENUES AVAILABLE FOR PARTNERSHIP NET REVENUES IS
ENTITY CONTRIBUTIONS (1) SUBORDINATION (1) SUBORDINATION 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 partnership costs and revenues charged and
credited between the managing general partner and you and the other investors in
each partnership after deducting from the partnership's gross revenues, the
landowner royalties, and any other lease burdens.
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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 AND CREDITS
Intangible drilling costs.................................................... 0% 100%
Depreciation (1)............................................................. 66% 34%
Percentage depletion allowance............................................... (4)(5)(6) (4)(5)(6)
Marginal well production credits............................................. (4)(5)(6) (4)(5)(6)
- ----------
(1) These percentages may vary. If the total equipment costs for all of a
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 that partnership, then the excess will be charged to the
managing general partner. Equipment proceeds, if any, will be credited in
the same percentage in which the equipment costs were charged.
(2) These costs, which also include plugging and abandonment costs of the wells
after the wells have been drilled and produced, will be charged to the
parties in the same ratio as the related production revenues are being
credited.
(3) Interest earned on your subscription proceeds before a partnership's final
closing will be credited to your account and paid not later than the
partnership's first cash distributions from operations. After the
partnership's final closing and until proceeds from the offering are
invested in the partnership's operations any interest income from temporary
investments will be allocated pro rata to the investors providing the
subscription proceeds. All other interest income in the partnership,
including interest earned on the deposit of operating revenues, will be
credited as production revenues are credited.
(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 and any marginal well production
credits will be in the same percentages as the production revenues.
ALLOCATION AND ADJUSTMENT AMONG INVESTORS
The investors' share as a group of each partnership's revenues, gains, income,
costs, marginal well production credits, expenses, losses, and other charges and
liabilities generally will be charged and credited among you and the other
investors in that partnership in accordance with the ratio that your respective
number of units bears to the number of units held by all investors as a group in
that partnership, based on $10,000 per unit regardless of the actual
subscription price set forth on the subscription agreement for an investor's
units. These allocations will take into account any investor general partner's
status as a defaulting investor general partner. Certain investors, however,
will pay a reduced amount for their units as described in "Plan of
Distribution." Thus, intangible drilling costs and the investors' share of the
equipment costs of drilling and
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completing the partnership's wells will be charged among you and the other
investors in a partnership as set forth above, except that these allocations
will be based on the respective subscription price you and the other investors
paid for the units as set forth on the subscription agreements rather than
$10,000 per unit for all units.
DISTRIBUTIONS
The managing general partner will review each partnership's accounts at least
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.
Also, funds will not be advanced or borrowed for distributions if the
distribution amount would exceed the partnership's accrued and received revenues
for the previous four quarters, less paid and accrued operating costs with
respect to the revenues. Any cash distributions from a partnership to the
managing general partner will be made only in conjunction with distributions to
you and the other investors in that partnership and only out of funds properly
allocated to the managing general partner's account.
LIQUIDATION
Each partnership will continue for 50 years unless it is terminated earlier by a
final terminating event as described below, or an event which causes the
dissolution of a limited partnership under the Delaware Revised Uniform Limited
Partnership Act. However, if a partnership terminates on an event which causes a
dissolution under state law and it is not a final terminating event, then a
successor limited partnership will automatically be formed. Thus, only on a
final terminating event will a partnership be liquidated. A final terminating
event is any of the following:
o the election to terminate the partnership by the managing general
partner or the affirmative vote of investors whose units equal a
majority of the total units;
o the termination of the partnership under Section 708(b)(1)(A) of the
Internal Revenue Code because no part of its business is being carried
on; or
o the partnership ceases to be a going concern.
On the partnership's liquidation you will receive your interest in the
partnership to which you subscribed. Generally, your interest in the partnership
means an undivided interest in the partnership's assets, after payments to the
partnership's creditors, in the ratio your capital account bears to all of 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 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
83
ownership or there are alternative arrangements in place which assure that you
will not be responsible for the operation or disposition of the partnership's
properties. If the managing general partner has not received your written
consent to the in-kind distribution within 30 days after it is mailed, then it
will be presumed that you have not consented. The managing general partner may
then sell the asset at the best price reasonably obtainable from an independent
third-party, or to itself or its affiliates at fair market value as determined
by an independent expert selected by the managing general partner. Also, if a
partnership is liquidated, the managing general partner will be repaid for any
debts owed to it by the partnership before there are any payments to you and the
other investors in that partnership.
CONFLICTS OF INTEREST
IN GENERAL
Conflicts of interest are inherent in natural gas and oil partnerships involving
non-industry investors because the transactions are entered into without arms'
length negotiation. Your interests and those of the managing general partner and
its affiliates may be inconsistent in some respects or in certain instances, and
the managing general partner's actions may not be the most advantageous to you.
The following discussion describes certain possible conflicts of interest that
may arise for the managing general partner and its affiliates in the course of
each partnership. For some of the conflicts of interest, but not all, there are
certain limitations on the managing general partner that are designed to reduce,
but which will not eliminate, the conflicts. Other than these limitations the
managing general partner has no procedures to resolve a conflict of interest and
under the terms of the partnership agreement the managing general partner may
resolve the conflict of interest in its sole discretion and best interest.
The following discussion is materially complete; however, other transactions or
dealings may arise in the future that could result in conflicts of interest for
the managing general partner and its affiliates.
CONFLICTS REGARDING TRANSACTIONS WITH THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES
Although the managing general partner believes that the compensation and
reimbursement that it and its affiliates will receive in connection with each
partnership are reasonable, the compensation has been determined solely by the
managing general partner and did not result from negotiations with any
unaffiliated third-party dealing at arms' length. The managing general partner
and its affiliates will receive compensation and reimbursement from each
partnership for their services in drilling, completing, and operating that
partnership's wells under the drilling and operating agreement and will receive
the other fees described in "Compensation" regardless of the success of that
partnership's wells. The managing general partner and its affiliates providing
the services or equipment can be expected to profit from the transactions, and
it is usually in the managing general partner's best interest to enter into
contracts with itself and its affiliates rather than unaffiliated third-parties
even if the contract terms, skill, and experience, offered by the unaffiliated
third-parties is comparable.
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
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o cancelable without penalty on 60 days written notice by investors
whose units equal a majority of the total units.
The compensation, if any, will be reported to you in your partnership's annual
and semiannual reports, and a copy of the contract will be provided to you on
request.
There is also a conflict of interest concerning the purchase price if the
managing general partner or an affiliate purchases a property from a
partnership, which they may do in certain limited circumstances as described in
"- Conflicts Involving the Acquisition of Leases - (6) Limitations on Sale of
Undeveloped and Developed Leases to the Managing General Partner," below.
CONFLICT REGARDING THE DRILLING AND OPERATING AGREEMENT
The managing general partner anticipates that all of the wells drilled by each
partnership will be drilled and operated under the drilling and operating
agreement. This creates a continuing conflict of interest because the managing
general partner must monitor and enforce, on behalf of each partnership, its own
compliance with the drilling and operating agreement and the partnership
agreement.
CONFLICTS REGARDING SHARING OF COSTS AND REVENUES
The managing general partner will receive a percentage of revenues greater than
the percentage of costs that it pays. This sharing arrangement may create a
conflict of interest between the managing general partner and you and the other
investors in a partnership concerning the determination of which wells will be
drilled by the partnership based on the risk and profit potential associated
with the wells.
In addition, the allocation of all of the intangible drilling costs to you and
the other investors and the majority of the equipment costs to the managing
general partner creates a conflict of interest between the managing general
partner and you and the other investors concerning whether to complete a well.
For example, the completion of a marginally productive well might prove
beneficial to you and the other investors, but not to the managing general
partner. When a completion decision is made you and the other investors will
have already paid the majority of your costs so you will want to pay your share
of the additional costs to complete the well if there is a reasonable
opportunity to recoup your share of the completion costs plus any portion of the
costs paid by you before the completion attempt. You will want to plug the well,
however, if it appears likely that you will not recoup all of your share of the
additional costs to complete the well.
On the other hand, the managing general partner will have paid only a portion of
its costs before this time, and it will want to pay its additional equipment
costs to complete the well only if it is reasonably certain of recouping its
share of the completion costs and making a profit. However, based on its past
experience the managing general partner anticipates that most of the wells in
the primary areas will have to be completed before it can determine the well's
productivity, which would eliminate this potential conflict of interest. In any
event, the managing general partner will not cause any well to be plugged and
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
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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 if the proposed adjustment would
decrease the managing general partner's liquidation interest in
the partnership; or
o the amount of the managing general partner's reimbursement from a
partnership for expenses incurred by it in its role as the tax matters
partner as a reasonable, ordinary and necessary business deduction.
CONFLICTS REGARDING OTHER ACTIVITIES OF THE MANAGING GENERAL PARTNER, THE
OPERATOR AND THEIR AFFILIATES
The managing general partner will be required to devote to each partnership the
time and attention that it considers necessary for the proper management of the
partnership's activities. However, the managing general partner has sponsored
and continues to manage other natural gas and oil drilling partnerships, which
may be concurrent, and will engage in unrelated business activities, either for
its own account or on behalf of other partnerships, joint ventures,
corporations, or other entities in which it has an interest. This creates a
continuing conflict of interest in allocating management time, services, and
other activities among the partnerships in this program and its other
activities. The managing general partner will determine the allocation of its
management time, services, and other functions on an as-needed basis consistent
with its fiduciary duties among the partnerships in this program and its other
activities.
Subject to its fiduciary duties, the managing general partner will not be
restricted from participating in other businesses or activities, even if these
other businesses or activities compete with a partnership's activities and
operate in the same areas as the partnership. However, the managing general
partner and its affiliates may pursue business opportunities that are consistent
with the partnership's investment objectives for their own account only after
they have determined that the opportunity either:
o cannot be pursued by the partnership because of insufficient funds; or
o it is not appropriate for the partnership under the existing
circumstances.
CONFLICTS INVOLVING THE ACQUISITION OF LEASES
The managing general partner will select, in its sole discretion, the wells to
be drilled by each partnership. Conflicts of interest may arise concerning which
wells will be drilled by each partnership in this program and which wells will
be drilled by the managing general partner's and its affiliates' other
affiliated partnerships or third-party programs in which they serve as
driller/operator. It may be in the managing general partner's or its affiliates'
advantage to have a partnership in this program bear the costs and risks of
drilling a particular well rather than another affiliate. These potential
conflicts of interest will be increased if the managing general partner
organizes and allocates wells to more than one partnership at a time. To lessen
this conflict of interest the managing general partner generally takes a similar
interest in other partnerships when it serves as managing general partner and/or
driller/operator.
When the managing general partner must provide prospects to two or more
partnerships at the same time it will attempt to treat each partnership fairly
on a basis consistent with:
o the funds available to the partnerships; and
o the time limitations on the investment of funds for the partnerships.
Generally, the managing general partner follows a policy of developing prospects
in the order of what it believes is the "best available prospect." However, the
managing general partner will constantly change its assessment of available
prospects based on the acquisition of new leases and information derived from
wells already drilled.
When more than one partnership in this program has funds available for drilling
at the same time, 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,
including the following factors:
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o estimated reserves;
o the targeted geological formations;
o natural gas and oil markets;
o geological and natural gas and oil market diversification within the
partnerships;
o the prospect's net revenue interest;
o estimated drilling costs; and
o limitations imposed by the prospectus and/or the partnership
agreement.
The partnership agreement gives the managing general partner the authority to
cause each partnership in this program to acquire undivided interests in natural
gas and oil properties, and to participate with other parties, including other
drilling programs previously or subsequently conducted by the managing general
partner or its affiliates, in the conduct of its drilling operations on those
properties. If conflicts between the interest of a partnership in this program
and other drilling partnerships do arise, then the managing general partner may
be unable to resolve those conflicts to the maximum advantage of the partnership
in this program because the managing general partner must deal fairly with the
investors in all of its drilling partnerships.
In addition, subject to the restrictions set forth below, the managing general
partner decides which prospects and what interest in the prospects to transfer
to a partnership. This will result in a subsequent partnership sponsored by the
managing general partner benefiting from knowledge gained through a prior
partnership's drilling experience in an area and acquiring a prospect adjacent
to the prior partnership's prospect.
No procedures, other than the guidelines set forth below and in " - Procedures
to Reduce Conflicts of Interest," have been established by the managing general
partner to resolve any conflicts that may arise. The partnership agreement
provides that the managing general partner and its affiliates will abide by the
guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and
(9) there is an exception in the partnership agreement for another program in
which the interest of the managing general partner is substantially similar to
or less than its interest in the partnerships.
(1) TRANSFERS AT COST. All leases will be acquired from the managing general
partner and credited towards its required capital contribution at the cost
of the lease, unless the managing general partner has a reason to believe
that cost is materially more than the fair market value of the property. If
the managing general partner believes cost is materially more than fair
market value, then the managing general partner's credit for the
contribution must be at a price not in excess of the fair market value.
o A determination of fair market value must be supported by an
appraisal from an independent expert and maintained in the
partnership's records for at least six years.
(2) EQUAL PROPORTIONATE INTEREST. When the managing general partner sells or
transfers an oil and gas interest to a partnership, it must, at the same
time, sell or transfer to the partnership an equal proportionate interest
in all of its other property in the same prospect.
o The term "prospect" generally means an area which is believed to
contain commercially productive quantities of natural gas or oil.
However, a prospect will be limited to the drilling or spacing unit on
which one well will be drilled if the following two conditions are met:
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o the well is being drilled to a geological feature which contains
proved reserves as defined below; and
o the drilling or spacing unit protects against drainage.
The managing general partner believes that for a prospect located in the primary
drilling areas as described in "Proposed Activities - Primary Areas of
Operations," a prospect will consist of the drilling and spacing unit because it
will meet the test in the preceding sentence.
o Proved reserves, generally, are the estimated quantities of
natural gas and oil which have been demonstrated to be
recoverable in future years with reasonable certainty under
existing economic and operating conditions. Proved reserves
include proved undeveloped reserves which generally are reserves
expected to be recovered from existing wells where a relatively
major expenditure is required for recompletion or from new wells
on undrilled acreage. Reserves on undrilled acreage will be
limited to those drilling units offsetting productive units that
are reasonably certain of production when drilled. Proved
Reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation.
In the primary areas the managing general partner anticipates that the drilling
of these wells by each partnership may provide the managing general partner with
offset sites by allowing it to determine, at the partnership's expense, the
value of adjacent acreage in which the partnership would not have any interest.
The managing general partner owns acreage throughout the primary areas where
each partnership's wells will be situated. To lessen this conflict of interest,
for five years the managing general partner may not drill any well:
o in the Clinton/Medina geologic formation within 1,650 feet of an
existing partnership well in Pennsylvania or within 1,000 feet of
an existing partnership well in Ohio; or
o in the Mississippian/Upper Devonian Sandstone reservoirs in
Fayette and Green Counties, Pennsylvania within at least 1,000
feet from a producing well, although a partnership may drill a
new well or re-enter an existing well which is closer than 1,000
feet to a plugged and abandoned well.
If a partnership abandons its interest in a well, then this restriction will
continue for one year following the abandonment. There are no similar
prohibitions for the other areas.
(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;
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o the managing general partner's obligations and the partnership's
obligations must be substantially the same after the sale of the
interest by the managing general partner or its affiliates; and
o the managing general partner's revenue interest must not exceed
the amount proportionate to its retained working interest.
For example, if the managing general partner transfers 50% of its working
interest in a prospect to a partnership and retains a 50% working interest,
then the partnership will not pay any of the costs associated with the
managing general partner's retained working interest as a part of the
transfer. This limitation does not prevent the managing general partner and
its affiliates from subsequently dealing with their retained working
interest as they may choose with unaffiliated parties or affiliated
partnerships. For example, the managing general partner may sell its
retained working interest to a third-party for a profit.
(5) LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES ON LEASES ACQUIRED BY A PARTNERSHIP. For a five year period
after the final closing of a partnership, if the managing general partner
proposes to acquire an interest from an unaffiliated person in a prospect
in which the partnership owns an interest or in a prospect in which the
partnership's interest has been terminated without compensation within one
year before the proposed acquisition, then the following conditions apply:
o if the managing general partner does not currently own property
in the prospect separately from the partnership, then the
managing general partner may not buy an interest in the prospect;
and
o if the managing general partner currently owns a proportionate
interest in the prospect separately from the partnership, then
the interest to be acquired must be divided in the same
proportion between the managing general partner and the
partnership as the other property in the prospect. However, if
the partnership does not have the cash or financing to buy the
additional interest, then the managing general partner is also
prohibited from buying the additional interest.
(6) LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE MANAGING
GENERAL PARTNER. The managing general partner and its affiliates, other
than an affiliated partnership as set forth in (7) below, may not purchase
undeveloped leases or receive a farmout from a partnership other than at
the higher of cost or fair market value. Farmouts to the managing general
partner and its affiliates also must be made as set forth in (9) below.
The managing general partner and its affiliates, other than an affiliated
income program, may not purchase any producing natural gas or oil property
from a partnership unless:
o the sale is in connection with the liquidation of the
partnership; or
o the managing general partner's well supervision fees under the
drilling and operating agreement for the well have exceeded the
net revenues of the well, determined without regard to the
managing general partner's well supervision fees for the well,
for a period of at least three consecutive months.
In both cases, the sale must be at fair market value supported by an
appraisal of an independent expert selected by the managing general
partner. The appraisal of the property must be maintained in the
partnership's records for at least six years.
(7) TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The transfer of
an undeveloped lease from a partnership to an affiliated drilling limited
partnership must be made at fair market value if the undeveloped lease has
been held for more than two years. Otherwise, the transfer may be made at
cost if the managing general partner deems it to be in the best interest of
the partnership.
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An affiliated income program may purchase a producing natural gas and oil
property from a partnership at any time at:
o fair market value as supported by an appraisal from an
independent expert if the property has been held by the
partnership for more than six months or there have been
significant expenditures made in connection with the property; or
o cost as adjusted for intervening operations if the managing
general partner deems it to be in the best interest of the
partnership.
However, these prohibitions do not apply to joint ventures or farmouts
among affiliated partnerships, provided that:
o the respective obligations and revenue sharing of all parties to
the transaction are substantially the same; and
o the compensation arrangement or any other interest or right of
either the managing general partner or its affiliates is the same
in each affiliated partnership or if different, the aggregate
compensation of the managing general partner or the affiliate is
reduced to reflect the lower compensation arrangement.
(8) LEASES WILL BE ACQUIRED ONLY FOR STATED PURPOSE OF THE PARTNERSHIP. Each
partnership must acquire only leases that are reasonably expected to meet
the stated purposes of the partnership. Also, no leases may be acquired for
the purpose of a subsequent sale, farmout or other disposition unless the
acquisition is made after a well has been drilled to a depth sufficient to
indicate that the acquisition would be in the partnership's best interest.
(9) FARMOUT. The managing general partner will not assign to a partnership the
working interest in a prospect for the purpose of a subsequent farmout,
sale or other disposition. The managing general partner will not enter into
a farmout to avoid paying its share of the costs related to drilling an
undeveloped lease. However, the managing general partner's decision with
respect to making a farmout and the terms of a farmout from a partnership
involve conflicts of interest since the managing general partner may
benefit from cost savings and reduction of risk.
The partnership may farmout an undeveloped lease or well activity to the
managing general partner, its affiliates or an unaffiliated third-party
only if the managing general partner, exercising the standard of a prudent
operator, determines that:
o the partnership lacks the funds to complete the oil and gas
operations on the lease or well and cannot obtain suitable
financing;
o drilling on the lease or the intended well activity would
concentrate excessive funds in one location, creating undue risks
to the partnership;
o the leases or well activity have been downgraded by events
occurring after assignment to the partnership so that development
of the leases or well activity would not be desirable; or
o the best interests of the partnership would be served.
If the partnership farmouts a lease or well activity, the managing general
partner must retain on behalf of the partnership the economic interests and
concessions as a reasonably prudent oil and gas operator would or could
retain under the circumstances prevailing at the time, consistent with
industry practices. However, if the farmout is made to the managing general
partner or its affiliates there is a conflict of interest since the
managing general partner will represent both the partnership and itself or
an affiliate. Although the conflict of interest may be resolved to the
managing general partner's benefit, the managing general partner must still
retain on behalf of the partnership
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the economic interests and concessions as a reasonably prudent oil and gas
operator would or could retain under the circumstances prevailing at the
time, consistent with industry practices.
CONFLICTS BETWEEN INVESTORS AND THE MANAGING GENERAL PARTNER AS AN INVESTOR
The managing general partner, its officers, directors, and affiliates may
subscribe for units in each partnership and the price of their units will be
reduced by 10.5% as described in "Plan of Distribution." Even though they pay a
reduced price for their units these investors generally will:
o share in the partnership's costs, revenues, and distributions on the
same basis as the other investors as described in "Participation in
Costs and Revenues - Allocation and Adjustment Among Investors"; 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."
LACK OF INDEPENDENT UNDERWRITER AND DUE DILIGENCE INVESTIGATION
The terms of this offering, the partnership agreement, and the drilling and
operating agreement were determined by the managing general partner without
arms' length negotiations. You and the other investors have not been separately
represented by legal counsel, who might have negotiated more favorable terms for
you and the other investors in this offering and the agreements.
Also, there was not an extensive in-depth "due diligence" investigation of the
existing and proposed business activities of the partnerships and the managing
general partner that would be provided by independent underwriters. Although
Anthem Securities, which is affiliated with the managing general partner, serves
as dealer-manager and will receive reimbursement of 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.
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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 or eliminate the amount of the
managing general partner's partnership net production revenues available for its
subordination obligation to you and the other investors. Also under certain
circumstances, if the managing general partner made a subordination distribution
to you and the other investors after a default, then the lender may be able to
recoup from you and the other investors that subordination distribution.
CONFLICTS REGARDING ORDER OF PIPELINE CONSTRUCTION AND GATHERING FEES
The managing general partner may choose well locations along the Atlas Pipeline
Partners gathering system which would benefit its parent company by providing
more gathering fees to Atlas Pipeline Partners, even if there are other well
locations available in the area or other areas which offer the partnerships a
greater potential return. However, the managing general partner believes this
conflict of interest is substantially reduced because the managing general
partner expects to make the largest single capital contribution in each
partnership as explained in "Capitalization and Source of Funds and Use of
Proceeds." Thus, it is in the best interest of its parent company for the
managing general partner to choose prospects for a partnership to drill which
have the greatest potential reserves even if they are not connected to the Atlas
Pipeline Partners gathering system. In addition, Atlas America or an affiliate
will operate the Atlas Pipeline Partners gathering system. Thus, the expansion
of the Atlas Pipeline Partners gathering system will be within the control of
the managing general partner's affiliate, which will attempt to expand the Atlas
Pipeline Partners gathering system to those areas with the greatest number of
wells with the greatest potential reserves.
The managing general partner's affiliates are obligated through their agreement
with Atlas Pipeline Partners to pay the difference between the amount each
partnership pays for gathering fees to the managing general partner as set forth
in "Compensation - Gathering Fees," and the greater of $.35 per mcf or 16% of
the gross sales price for the natural gas. This provides an incentive to the
managing general partner to increase the amount of the gathering fees paid by
each partnership to it, which are not fixed and may change as described in
"Compensation-Gathering Fees." However, the gathering fees paid to the managing
general partner may not exceed competitive rates.
PROCEDURES TO REDUCE CONFLICTS OF INTEREST
In addition to the procedures set forth in "- Conflicts Involving the
Acquisition of Leases," the managing general partner and its affiliates will
comply with the following procedures in the partnership agreement to reduce some
of the conflicts of interest with you and the other investors. The managing
general partner does not have any other conflict of interest resolution
procedures. Thus, conflicts of interest between the managing general partner and
you and the other investors may not necessarily be resolved in your best
interests. However, the managing general partner believes that its significant
capital contribution to each partnership will reduce the conflicts of interest.
(1) FAIR AND REASONABLE. The managing general partner may not sell, transfer,
or convey any property to, or purchase any property from, a partnership
except pursuant to transactions that are fair and reasonable; nor take any
action with respect to the assets or property of a partnership which does
not primarily benefit the partnership.
(2) NO COMPENSATING BALANCES. The managing general partner may not use a
partnership's funds as a compensating balance for its own benefit. Thus, a
partnership's funds may not be used to satisfy any deposit requirements
imposed by a bank or other financial institution on the managing general
partner for its own corporate purposes.
(3) FUTURE PRODUCTION. The managing general partner may not commit the future
production of a partnership well exclusively for its own benefit.
(4) DISCLOSURE. Any agreement or arrangement that binds a partnership must be
fully disclosed in this prospectus.
(5) NO LOANS FROM A PARTNERSHIP. A partnership may not loan money to the
managing general partner.
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(6) NO REBATES. The managing general partner may not participate in any
business arrangements which would circumvent these guidelines including
receiving rebates or give-ups.
(7) SALE OF ASSETS. The sale of all or substantially all of the assets of a
partnership may only be made with the consent of investors whose units
equal a majority of the total units.
(8) PARTICIPATION IN OTHER PARTNERSHIPS. If a partnership participates in other
partnerships or joint ventures, then the terms of the arrangements must not
circumvent any of the requirements contained in the partnership agreement,
including the following:
o there may be no duplication or increase in organization and offering
expenses, the managing general partner's compensation, partnership
expenses, or other fees and costs;
o there may be no substantive change in the fiduciary and contractual
relationship between the managing general partner and you and the
other investors; and
o there may be no diminishment in your voting rights.
(9) INVESTMENTS. A partnership's funds may not be invested in the securities of
another person except in the following instances:
o investments in working interests made in the ordinary course of the
partnership's business;
o temporary investments in income producing short-term highly liquid
investments, in which there is appropriate safety of principal, such
as U.S. Treasury Bills;
o multi-tier arrangements meeting the requirements of (8) above;
o investments involving less than 5% of the total subscription proceeds
of the partnership that are a necessary and incidental part of a
property acquisition transaction; and
o investments in entities established solely to limit the partnership's
liabilities associated with the ownership or operation of property or
equipment, provided that duplicative fees and expenses are prohibited.
(10) SAFEKEEPING OF FUNDS. The managing general partner may not employ, or
permit another to employ, the funds or assets of a partnership in any
manner except for the exclusive benefit of the partnership. The managing
general partner has a fiduciary responsibility for the safekeeping and use
of all funds and assets of each partnership whether or not in its
possession or control.
(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;
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o listing the units on a national securities exchange or on NASDAQ;
o changing the partnership's fundamental investment objectives; or
o materially altering the partnership's duration.
If a roll-up should occur in the future the partnership agreement provides
various policies which include the following:
o an independent expert must appraise all partnership assets, and you
must receive a summary of the appraisal in connection with a proposed
roll-up;
o if you vote "no" on the roll-up proposal, then you will be offered a
choice of:
o accepting the securities of the roll-up entity; or
o one of the following:
o remaining a partner in the partnership and preserving your
units in the partnership on the same terms and conditions as
existed previously; or
o receiving cash in an amount equal to your pro-rata share of
the appraised value of the partnership's net assets; and
o the partnership will not participate in a proposed roll-up:
o unless approved by investors whose units equal 66% of the total
units;
o which would result in the diminishment of your voting rights
under the roll-up entity's chartering agreement;
o which includes provisions which would operate to materially
impede or frustrate the accumulation of shares by you of the
securities of the roll-up entity;
o in which your right of access to the records of the roll-up
entity would be less than those provided by the partnership
agreement; or
o in which any of the transaction costs would be borne by the
partnership if the proposed roll-up is not approved by investors
whose units equal 66% of the total units.
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
IN GENERAL
The managing general partner will manage your partnership and its assets. In
conducting your partnership's affairs the managing general partner is
accountable to you as a fiduciary, which under Delaware law generally means that
the managing general partner must exercise due care and deal fairly with you and
the other investors. Neither the partnership agreement nor any other agreement
between the managing general partner and each partnership may contractually
limit any fiduciary duty owed to you and the other investors by the managing
general partner under applicable law except as set forth in Sections 4.01, 4.02,
4.03, 4.04, 4.05, and 4.06 of the partnership agreement. In this regard, the
partnership agreement does permit the managing general partner and its
affiliates to:
o have business interests or activities that may conflict with the
partnerships if they determine that the business opportunity either:
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o cannot be pursued by the partnership because of insufficient
funds; or
o it is not appropriate for the partnership under the existing
circumstances;
o devote only so much of their time as is necessary to manage the
affairs of each partnership;
o conduct business with the partnerships in a capacity other than as
managing general partner or sponsor as described in Sections 4.01,
4.02, 4.03, 4.04, 4.05 and 4.06 of the partnership agreement;
o manage multiple programs simultaneously; and
o be indemnified and held harmless as described below in "- Limitations
on Managing General Partner Liability as Fiduciary."
Other than as set forth above, the partnership agreement does not excuse the
managing general partner from liability or provide it with any defense for
breach of its fiduciary duty. The fiduciary duty owed by the managing general
partner to the partnership is analogous to the fiduciary duty owed by directors
to a corporation and its stockholders and is subject to the same rule, commonly
referred to as the "business judgment rule," that directors are not liable for
mistakes made in the good faith exercise of honest business judgment or for
losses incurred in the good faith performance of their duties when performed
with such care as an ordinarily prudent person would use. As a result of the
business judgment rule, the managing general partner may not be held liable for
mistakes made or losses incurred in the good faith exercise of reasonable
business judgment as described below in " - Limitations on Managing General
Partner Liability as Fiduciary."
If the managing general partner breaches its fiduciary responsibilities, then
you are entitled to an accounting and the recovery of any economic loss caused
by the breach. The Delaware Revised Uniform Limited Partnership Act provides
that a limited partner may institute legal action (a "derivative" action) on a
partnership's behalf to recover damages from a third-party when the managing
general partner refuses to institute the action or where an effort to cause the
managing general partner to do so is not likely to succeed. In addition, the
statutory or case law may permit a limited partner to institute legal action on
behalf of himself and all other similarly situated limited partners (a "class
action") to recover damages from the managing general partner for violations of
its fiduciary duties to the limited partners. Because this is a rapidly
expanding and changing area of the law, you are urged to consult your own
counsel if you have questions concerning the managing general partner's duties.
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 the following:
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o the partnership's tangible net assets, which include its revenues; and
o any insurance proceeds from the types of insurance for which the
managing general partner, the operator and their affiliates may be
indemnified under the partnership agreement.
Still, use of partnership funds or assets for indemnification of the managing
general partner, the operator, or an affiliate would reduce amounts available
for partnership operations or for distribution to you and the other investors.
A partnership may not pay the cost of the portion of any insurance that insures
the managing general partner, the operator, or an affiliate against any
liability for which they cannot be indemnified. However, a partnership's funds
can be advanced to them for legal expenses and other costs incurred in any legal
action for which indemnification is being sought if the partnership has adequate
funds available and certain conditions in the partnership agreement are met.
The effect of the foregoing provisions and the business judgment rule may be to
limit your recourse against the managing general partner.
MATERIAL FEDERAL INCOME TAX CONSEQUENCES
INTRODUCTION
The managing general partner has obtained a tax opinion letter from Kunzman &
Bollinger, Inc., special counsel for this offering. Accordingly, the managing
general partner will rely on special counsel's tax opinion letter, and no
advance ruling on any tax consequence of an investment in a partnership will be
requested from the IRS. This section of this prospectus is a summary of special
counsel's tax opinion letter. You are urged to read the tax opinion letter,
which has been filed as Exhibit 8 to the registration statement of which this
prospectus is a part. (See "Additional Information," for information on how to
obtain a copy of special counsel's tax opinion letter.)
DISCLOSURES AND LIMITATION ON YOUR USE OF SPECIAL COUNSEL'S TAX OPINION LETTER
o Atlas Resources, Inc., as managing general partner of each
partnership, has retained Kunzman & Bollinger, Inc. as special counsel
to assist in the organization and documentation of this offering and
to provide its tax opinion letter to support the marketing of units in
the partnerships to potential investors. Special counsel's
compensation arrangement with the managing general partner is not
refundable or contingent on all or any part of the intended tax
consequences from an investment in a partnership ultimately being
sustained if challenged by the IRS, or on the investors' realization
of tax benefits from the partnership in which they invest. Also,
special counsel has no compensation or referral arrangement with any
person other than the managing general partner in connection with this
offering, and special counsel has no fee-sharing arrangement with
anyone in connection with this offering.
o Because special counsel has entered into a compensation arrangement
with the managing general partner to provide the legal services to the
partnerships discussed above, its tax opinion letter was not written,
and cannot be used by you and the other investors, for the purpose of
establishing your reasonable belief that your tax treatment of any
partnership tax item on your federal income tax returns was more
likely than not the proper treatment in order to avoid any reportable
transaction understatement penalty under Section 6662A of the Internal
Revenue Code (the "Code") that may be imposed on you.
o Special counsel's tax opinion letter is not confidential. There are no
limitations on the disclosure by the Partnerships or you or any other
potential investor to any other person of the tax treatment or tax
structure of the partnerships or the contents of the tax opinion
letter.
o You have no contractual protection against the possibility that a
portion or all of your intended tax benefits from an investment in a
partnership ultimately are not sustained if challenged by the IRS.
(See "Risk
96
Factors - Tax Risks - Your Tax Benefits Are Not Contractually
Protected" and "- Federal Interest and Tax Penalties," below.)
o You are urged to seek advice based on your particular circumstances
from an independent tax advisor with respect to the federal tax issues
of an investment in a partnership.
The limitation set forth above on your use of special counsel's tax opinion
letter with respect to the reportable transaction understatement penalty applies
only for federal tax purposes. It does not apply to your right to rely on the
tax opinion letter and this discussion in "Material Federal Income Tax
Consequences" under the federal securities laws.
SPECIAL COUNSEL'S OPINIONS
Although special counsel's tax opinions express what it believes a court would
probably conclude if presented with the applicable federal tax issues, special
counsel's tax opinions are only predictions, and are not guarantees, of the
outcome of the particular tax issues being addressed. The IRS could challenge
special counsel's tax opinions, and the challenge could be sustained in the
courts if litigated and cause adverse tax consequences to you and your
partnership's other investors. Special counsel's tax opinions set forth below
are based in part on representations made by the managing general partner (see
"Forward Looking Statements and Associated Risks") and assumptions made by
special counsel relating to the partnerships which are described in the tax
opinion letter.
Set forth below is a synopsis of the principal assumptions made by special
counsel and the principal representations made the managing general partner on
which special counsel relied in giving its tax opinion letter.
SPECIAL COUNSEL'S ASSUMPTIONS
In giving its opinions, special counsel made the principal assumptions
summarized below.
o You will not borrow money to buy units in a partnership from any other
investor in the same partnership.
o You will be personally liable to repay any money you borrow to buy
units in a partnership.
o You will not protect yourself from losing the money you invest in a
partnership through nonrecourse financing, guarantees, stop loss
agreements or other similar arrangements.
o The partnership in which you invest will begin drilling all of its
wells before March 31, 2006, and the wells will be drilled
continuously until completed, if warranted, or abandoned.
MANAGING GENERAL PARTNER'S REPRESENTATIONS.
In giving its opinions, special counsel relied on representations from the
managing general partner, including the principal representations summarized
below.
o Each partnership will operate its business as described in this
prospectus and in accordance with the terms of the partnership
agreement, the drilling and operating agreement and any applicable
limited partnership acts.
o A typical investor in each partnership will be a natural person who
purchases units in this offering and is a U.S. citizen.
o The managing general partner anticipates that the investor general
partner units in each partnership will be converted to limited partner
units in 2006.
o Each partnership will elect to deduct the intangible drilling costs of
all of its wells.
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o The managing general partner anticipates that all of the subscription
proceeds of each partnership will be expended in 2005, and you and the
other investors in your partnership will include the related deduction
for intangible drilling costs on your 2005 federal income tax returns,
subject to your right to elect to capitalize and amortize over a
60-month period a portion or all of your share of your partnership's
deduction for intangible drilling costs.
o The managing general partner does not anticipate that any of the
partnerships' production of natural gas and oil from their respective
wells in 2005 will qualify for the marginal well production credit in
2005, because natural gas and oil prices in 2004 were substantially
higher than the prices where the credit phases out completely.
o Depending primarily on when its subscription proceeds are received,
the managing general partner further anticipates that each partnership
may prepay in 2005 most, if not all, of its intangible drilling costs
for drilling activities that will begin in 2006.
o Each Partnership will have a calendar year taxable year.
o The managing general partner anticipates that most, if not all, of
each partnership's natural gas and oil production will be marginal
production which will qualify for potentially higher rates of
percentage depletion.
o The principal purpose of each partnership is to locate, produce and
market natural gas and oil on a profitable basis, apart from tax
benefits, as discussed in this prospectus.
o Based primarily on the managing general partner's past experience as
shown in "Prior Activities," each partnership's total abandonment
losses under Section 165 of the Code, if any, which could include, for
example, the abandonment by a partnership of wells drilled which are
nonproductive (i.e. a "dry hole") or wells which have been operated
until their commercial natural gas and oil reserves have been depleted
(and each investor's allocable share of those abandonment losses),
will be less, in the aggregate, than $2 million in any taxable year of
a partnership and less than an aggregate total of $4 million during
the partnership's first six taxable years.
Additional details, assumptions of special counsel, representations of the
managing general partner, and other matters affecting special counsel's opinions
are contained in special counsel's tax opinion letter. You are urged to obtain a
copy of the tax opinion letter from the managing general partner or the SEC, as
set forth in "Additional Information," and read the entire tax opinion letter to
assist your understanding of the federal tax benefits and risks of an investment
in a partnership.
SPECIAL COUNSEL'S OPINIONS
Taxpayers bear the burden of proof to support claimed deductions and tax
credits, and special counsel's opinions are not binding on the IRS or the
courts. In special counsel's opinion the federal tax treatment with respect to
each federal tax issue arising from an investment in a partnership by a typical
investor as set forth below is the proper federal tax treatment of that issue
and will be upheld on the merits if challenged by the IRS and litigated.
(1) PARTNERSHIP CLASSIFICATION. Each Partnership will be classified as a
partnership for federal income tax purposes, and not as a corporation.
The Partnerships, as such, will not pay any federal income taxes, and
all items of income, gain, loss, deduction, and credit, if any, of the
Partnerships will be reportable by the Partners in the Partnership in
which they invest.
(2) PASSIVE ACTIVITY CLASSIFICATION.
o The passive activity limitations on losses and credits under
Section 469 of the Code will apply to:
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o the Limited Partners in a Partnership; and
o will not apply to the Investor General Partners in the
Partnership until after the conversion of the Investor
General Partner Units to Limited Partner Units in the
Partnership.
o A Partnership's income, gain and credits, if any, from its
natural gas and oil properties which are allocated to its Limited
Partners, other than net income and any related credits allocated
to former Investor General Partners who have been converted to
Limited Partners, will be characterized as:
o passive activity income which may be offset by passive
activity losses; and
o passive activity credits which a Limited Partner may use to
offset a portion or all of the Limited Partner's regular
federal income tax liability from passive income received by
the Limited Partner from the Partnership or other passive
activities, other than publicly traded partnership passive
activities.
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, and will not
generate any marginal well production credits.
For a discussion of the types of entities whose investments in a
Partnership also will be subject to the passive activity limitations
on losses and credits, see the Summary Discussion "- Limitations on
Passive Activity Losses and Credits," below.
(3) NOT A PUBLICLY TRADED PARTNERSHIP. Neither Partnership will be treated
as a publicly traded partnership under the Code.
(4) BUSINESS EXPENSES. Business expenses, including payments for personal
services actually rendered in the taxable year in which accrued, which
are reasonable, ordinary and necessary and do not include amounts for
items such as Lease acquisition costs, Tangible Costs, organization
and syndication fees and other items which are required to be
capitalized, are currently deductible.
o POTENTIAL LIMITATIONS ON DEDUCTIONS. A Participant's ability to
use the Participant's share of these deductions on the
Participant's personal federal income tax returns may be reduced,
eliminated or deferred by the following limitations:
o the Participant's personal tax situation, such as the amount
of the Participant's taxable income, alternative minimum
taxable income, losses, deductions, exemptions, etc., which
are not related to the Participant's investment in a
Partnership;
o the amount of the Participant's adjusted basis in the
Participant's Units at the end of the Partnership's taxable
year;
o the amount of the Participant's "at risk" amount in the
Partnership in which he invests at the end of the
Partnership's taxable year; and
o in the case of the Limited Partners (including the Investor
General Partners after their Units are converted to Limited
Partner Units by their Partnership) who are natural persons,
the passive activity limitations on losses and credits.
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See "- Tax Basis of Units," "- `At Risk' Limitation For Losses," "-
Alternative Minimum Tax" and "- Limitations on Passive Activity Losses
and Credits" in the Summary Discussion section.
(5) INTANGIBLE DRILLING COSTS. Although each Partnership will elect to
deduct currently all Intangible Drilling Costs, each Participant may
still elect to capitalize and deduct all or part of his share of his
Partnership's Intangible Drilling Costs (other than drilling and
completion costs of a re-entry well which are not related to deepening
the well) ratably over a 60 month period as discussed in "-
Alternative Minimum Tax," below. Subject to the foregoing, Intangible
Drilling Costs paid by a Partnership under the terms of bona fide
drilling contracts for the Partnership's wells will be deductible by
Participants who elect to currently deduct their share of their
Partnership's Intangible Drilling Costs in the taxable year in which
the payments are made and the drilling services are rendered.
A Participant's ability to use the Participant's share of these
deductions on the Participant's personal federal income tax returns
may be reduced, eliminated or deferred by the "Potential Limitations
on Deductions" set forth in opinion (4) above.
(6) PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Subject to each
Participant's election to capitalize and amortize a portion or all of
the Participant's share of his Partnership's deductions for Intangible
Drilling Costs as set forth in opinion (5) above, any prepayments in
2005 of Intangible Drilling Costs for wells the drilling of which will
not begin until on or before March 31, 2006, by a Partnership will be
deductible by the Participants in that Partnership in 2005.
A Participant's ability to use the Participant's share of these
deductions on the Participant's personal federal income tax returns
may be reduced, eliminated or deferred by the "Potential Limitations
on Deductions" set forth in opinion (4) above.
(7) DEPLETION ALLOWANCE. The greater of the cost depletion allowance or
the percentage depletion allowance will be available to qualified
Participants as a current deduction against their share of their
Partnership's natural gas and oil production income, subject to the
following restrictions:
o a Participant's cost depletion allowance cannot exceed the
Participant's share of the adjusted tax basis of the natural gas
or oil property to which it relates; and
o a Participant's percentage depletion allowance:
o may not exceed 100% of the Participant's share of his
Partnership's net income from each natural gas and oil
property before the deduction for depletion, however, this
limitation is suspended in 2005 with respect to marginal
properties; and
o is limited to 65% of the Participant's taxable income for
the year computed without regard to percentage depletion,
net operating loss carry-backs and capital loss carry-backs.
See "- Depletion Allowance" in the Summary Discussion section.
(8) MACRS. Each Partnership's reasonable costs for equipment placed in its
respective productive wells which cannot be deducted immediately
("Tangible Costs") will be eligible for cost recovery deductions under
the Modified Accelerated Cost Recovery System ("MACRS") over a seven
year "cost recovery period" beginning in the taxable year each well is
drilled, completed and made capable of production, i.e. placed in
service.
100
A Participant's ability to use the Participant's share of these
deductions on the Participant's personal federal income tax returns
may be reduced, eliminated or deferred by the "Potential Limitations
on Deductions" set forth in opinion (4), above.
(9) TAX BASIS OF UNITS. Each Participant's initial adjusted tax basis in
his Units will be the amount of money that the Participant paid for
his Units.
(10) AT RISK LIMITATION ON LOSSES. Each Participant's initial "at risk"
amount in the Partnership in which he invests will be the amount of
money that the Participant paid for his Units.
(11) ALLOCATIONS. The allocations of income, gain, loss, deduction, and
credit, or items thereof, and distributions set forth in the
Partnership Agreement for each Partnership, including the allocations
of basis and amount realized with respect to a Partnership's natural
gas and oil properties, will govern each Participant's allocable share
of those items to the extent the allocations do not cause or increase
a deficit balance in his Capital Account.
(12) SUBSCRIPTION. No gain or loss will be recognized by the Participants
on payment of their subscriptions to the Partnership in which they
invest.
(13) PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND POTENTIALLY RELEVANT JUDICIAL
DOCTRINES. The Partnerships will possess the requisite profit motive
under Section 183 of the Code. Also, the IRS anti-abuse rule in Treas.
Reg. Section 1.701-2 and potentially relevant judicial doctrines will
not have a material adverse effect on the tax consequences of an
investment in a Partnership by a Participant as described in our
opinions.
(14) REPORTABLE TRANSACTIONS. It is more likely than not that each
Partnership will not be a reportable transaction under the Code, and
their Participants will not be subject to the reportable transaction
understatement penalty under the Code with respect to their investment
in a Partnership.
(15) OVERALL CONCLUSION. Our overall conclusion is that the federal tax
treatment of a typical Participant's investment in a Partnership as
set forth above in our opinions is the proper federal tax treatment
and will be upheld on the merits if challenged by the IRS and
litigated. The reason we have reached this overall conclusion is that
our evaluation of the federal income tax laws and the expected
activities of the Partnerships as represented to us by the Managing
General Partner in the tax opinion letter and as described in this
Prospectus causes us to believe that the deduction by a Participant of
all, or substantially all, of his allocable share of his Partnership's
Intangible Drilling Costs in 2005 (even if the drilling of a portion
or all of his Partnership's wells begins after December 31, 2005, but
on or before March 31, 2006), as set forth in opinions (5) and (6)
above, is the principal tax benefit offered by the Partnerships to
potential Participants and is also the proper federal tax treatment,
subject to each Participant's election to capitalize and amortize a
portion or all of the Participant's deduction for Intangible Drilling
Costs as discussed in the Summary Discussion "- Alternative Minimum
Tax," below.
A Participant's ability to use the Participant's share of these
deductions on the Participant's personal federal income tax returns
may be reduced, eliminated or deferred by the "Potential Limitations
on Deductions" set forth in opinion (4), above.
The discussion in this Prospectus under the caption "MATERIAL FEDERAL
INCOME TAX CONSEQUENCES," insofar as it contains statements of federal
income tax law, is correct in all material respects.
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SUMMARY DISCUSSION OF THE MATERIAL FEDERAL INCOME TAX CONSEQUENCES
AND ANY SIGNIFICANT FEDERAL TAX ISSUES OF AN INVESTMENT IN A PARTNERSHIP
("Summary Discussion")
INTRODUCTION
Special counsel's tax opinions are limited to those set forth above. The
following is a summary of all of the material federal income tax consequences,
and any significant federal tax issues, of the purchase, ownership and
disposition of investor general partner units and limited partner units
discussed in the tax opinion letter which will apply to typical investors in
each partnership. Except as otherwise noted below, however, different tax
considerations from those addressed in this discussion may apply to foreign
persons, corporations, partnerships, trusts and other prospective investors
which are not treated as typical investors for federal income tax purposes.
Also, the proper treatment of the tax attributes of a partnership by a typical
investor on his individual federal income tax return may vary from that of
another typical investor. This is because the practical utility of the tax
aspects of any investment depends largely on each investor's particular income
tax position in the year in which items of income, gain, loss, deduction or
credit are properly taken into account in computing his federal income tax
liability. In addition, the IRS may challenge the deductions and credits claimed
by a Partnership or a Participant, or the taxable year in which the deductions
and credits are claimed, and it is possible that the challenge would be upheld
if litigated. Accordingly, you are urged to seek qualified, professional advice
based on your particular circumstances from an independent tax advisor in
evaluating the potential tax consequences to you of an investment in a
partnership.
PARTNERSHIP CLASSIFICATION
For federal income tax purposes a partnership is not a taxable entity. Thus, the
partners, rather than the partnership, receive any deductions and tax credits,
as well as the income, from the partnership's operations. A business entity with
two or more members is classified for federal tax purposes as either a
corporation or a partnership. Each partnership has been formed as a limited
partnership under the Delaware Revised Uniform Limited Partnership Act which
describes each partnership as a "partnership." Thus, each partnership
automatically will be classified as a partnership since the managing general
partner has represented that neither partnership will elect to be taxed as a
corporation.
LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS
Under the passive activity rules of the Code, all income of a taxpayer who is
subject to the rules is categorized as:
o income from passive activities such as limited partners' interests in
a business;
o active income such as salary, bonuses, etc.; or
o portfolio income, such as gain, interest, dividends and royalties
unless earned in the ordinary course of a trade or business.
Losses generated by passive activities can offset only passive income and cannot
be applied against active income or portfolio income. Similar rules apply with
respect to tax credits. (See "- Marginal Well Production Credits," below.)
Suspended passive losses and passive credits which an investor cannot use in his
current tax year may be carried forward indefinitely, but not back, and used to
offset future years' passive activity income, or offset passive activity regular
income tax liability (in the case of passive activity credits).
Passive activities include any trade or business in which the taxpayer does not
materially participate on a regular, continuous, and substantial basis. Under
the partnership agreement, limited partners will not have material participation
in the partnership in which they invest. Thus, if you are an individual you will
be subject to the passive activity limitations. The passive activity rules also
apply to other types of investors, including, for example, trusts, partnerships,
some types of limited liability companies which elect to be treated as
corporations for federal tax purposes, and some types of corporations, as
described in more detail in special counsel's tax opinion letter.
Investor general partners also do not materially participate in the partnership
in which they invest. However, because each partnership will own only "working
interests," as defined by the Code, in its wells, and investor general partners
will not have limited liability under Delaware law until they are converted to
limited partners, their deductions and any credits from
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their partnership will not be treated as passive deductions or credits under the
Code before the conversion, unless they invest in a partnership through an
entity which limits their liability. For example, if an individual invests in a
partnership indirectly as an investor general partner by using an entity which
limits his personal liability under state law to purchase his units, such as a
limited partnership in which he is not a general partner, a limited liability
company or an S corporation, he will be subject to the passive activity
limitations the same as a limited partner. (See "- Conversion from Investor
General Partner to Limited Partner" and "- Marginal Well Production Credits,"
below.)
Contractual limitations on the liability of investor general partners under the
partnership agreement, as compared with limitations on liability under state law
as discussed above, such as insurance, limited indemnification by the managing
general partner, etc. will not cause investor general partners to be subject to
the passive activity loss limitations. Investor general partners, however, may
be subject to an additional limitation on their deduction of investment interest
expense as a result of their deduction of intangible drilling costs. (See "-
Limitations on Deduction of Investment Interest," below.)
PUBLICLY TRADED PARTNERSHIP RULES
Net losses and most net credits of a partner from a publicly traded partnership
are suspended and carried forward to be netted against income or regular federal
income tax liability, respectively, from that publicly traded partnership only.
In addition, net losses from other passive activities may not be used to offset
net passive income from a publicly traded partnership. A publicly traded
partnership is a partnership in which interests in the partnership are traded on
an established securities market, or in which interests in the partnership are
readily tradable on either a secondary market or the substantial equivalent of a
secondary market. However, in special counsel's opinion neither partnership will
be treated as a publicly traded partnership under the Code. This opinion is
based primarily on the substantial restrictions in the partnership agreement on
your ability to transfer your units in your partnership. (See "Transferability
of Units - Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws
and the Partnership Agreement.") Also, the managing general partner has
represented that neither partnership's units will be traded on an established
securities market.
CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER
If you invest in a partnership as an investor general partner, then your share
of the partnership's deduction for intangible drilling costs in 2005 will not be
subject to the passive activity loss limitation. This is because the managing
general partner has represented that the investor general partner units in a
partnership will not be converted to limited partner units until after all of
the wells in that partnership have been drilled and completed. The managing
general partner anticipates that the conversion will be in 2006 for both
partnerships. (See "Actions to be Taken by Managing General Partner to Reduce
Risks of Additional Payments by Investor General Partners," and "- Drilling
Contracts," below.) After the investor general partner units have been converted
to limited partner units, each former investor general partner will have limited
liability as a limited partner under the Delaware Revised Uniform Limited
Partnership Act with respect to his interest in his partnership's activities
after the date of the conversion.
Concurrently, the former investor general partner will become subject to the
passive activity rules as a limited partner. However, the former investor
general partner previously will have received a non-passive loss as an investor
general partner in 2005 as a result of the partnership's deduction for
intangible drilling costs. Therefore, the Code requires that his net income from
the partnership's wells after his conversion to a limited partner must continue
to be characterized as non-passive income which cannot be offset with passive
losses. For a discussion of the effect of this rule on an investor general
partner's tax credits from his partnership, if any, see "- Marginal Well
Production Credits," below. The conversion of the investor general partner units
into limited partner units should not have any other adverse tax consequences on
an investor general partner unless his share of any partnership liabilities is
reduced as a result of the conversion. A reduction in a partner's share of
liabilities is treated as a constructive distribution of cash to the partner,
which reduces the basis of the partner's interest in the partnership and is
taxable to the partner to the extent it exceeds his basis. (See "- Tax Basis of
Units," below.)
TAXABLE YEAR AND METHOD OF ACCOUNTING
Each partnership will adopt a calendar year taxable year and will use the
accrual method of accounting for federal income tax purposes.
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2005 EXPENDITURES
The managing general partner anticipates that all of the subscription proceeds
of each partnership will be expended in 2005, and the related income and
deductions, including the deduction for intangible drilling costs, will be
reflected on its investors' federal income tax returns for that period. In this
regard, the managing general partner does not anticipate that any of the
partnerships' production of natural gas and oil from their respective wells in
2005, if any, will qualify for the marginal well production credit in 2005,
because the prices for natural gas and oil in 2004 were substantially above the
$2.00 per mcf and $18.00 per barrel prices where the credit phases out
completely. (See "- Drilling Contracts" and " - Marginal Well Production
Credits," below.)
Depending primarily on when each partnership's subscription proceeds are
received, the managing general partner anticipates that either or both of Atlas
America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P., which
may both have their final closing on any date up to and including December 31,
2005, may prepay in 2005 most, if not all, of its respective intangible drilling
costs for drilling activities that will begin in 2006. However, Atlas America
Public #14-2005(A) L.P. has a targeted ending date of March 31, 2005 (which is
not binding on the partnership), and depending primarily on when it receives its
subscriptions, it may not prepay in 2005 any of its intangible drilling costs
for drilling activities that will begin in 2006. (See "- Drilling Contracts,"
below.) The offering of units in Atlas America Public #14-2005(B) L.P. will not
begin until after the final closing of Atlas America Public #14-2005(A) L.P.
(See "- Drilling Contracts," below.)
BUSINESS EXPENSES
Ordinary and necessary business expenses, including reasonable compensation for
personal services actually rendered, are deductible in the year incurred. In
this regard, the managing general partner has represented that the amounts
payable by each partnership to it and its affiliates, including the amounts
payable to it or its affiliates as general drilling contractor, are reasonable
and competitive amounts which would ordinarily be paid for similar services in
similar transactions in the proposed areas of both partnerships' operations.
(See "Compensation" and "- Drilling Contracts," below.) The fees paid to the
managing general partner and its affiliates by the partnerships will not be
currently deductible, however, to the extent it is determined by the IRS or the
courts that they are:
o in excess of reasonable compensation;
o properly characterized as organization or syndication fees or other
capital costs such as 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.
Your ability to use your share of these deductions on your personal federal
income tax returns may be reduced, eliminated or deferred by the "Potential
Limitations on Deductions" set forth in special counsel's opinion (4) in
"Special Counsel's Opinions," above.
Although the partnerships will engage in the production of natural gas and oil
from wells drilled in the United States, the partnerships will not qualify for
the "U.S. production activities deduction." This is because the deduction cannot
exceed 50% of the IRS Form W-2 wages paid by a taxpayer for a tax year, and the
partnerships will not pay any Form W-2 wages since they will not have any
employees. Instead, the partnerships will rely on the managing general partner
and its affiliates to manage them and their respective businesses. (See
"Management.")
INTANGIBLE DRILLING COSTS
You may elect to deduct your share of your partnership's intangible drilling
costs, which include items which do not have salvage value, such as labor, fuel,
repairs, supplies and hauling necessary to the drilling of a well in the taxable
year your
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partnership's wells are drilled and completed. For a discussion of the earlier
deduction of prepaid intangible drilling costs, see "- Drilling Contracts,"
below.
If a partnership re-enters an existing well as described in "Proposed Activities
- - Primary Areas of Operations - Mississippian/Upper Devonian Sandstone
Reservoirs, Fayette County, Pennsylvania," the costs of deepening the well and
completing it to deeper reservoirs, if any, other than equipment costs and lease
costs, will be treated as intangible drilling costs. The intangible drilling
costs of drilling and completing a re-entry well which are not related to
deepening the well, if any, however, will be treated as operating expenses which
should be expensed in the taxable year they are incurred for federal income tax
purposes. Any intangible drilling costs of a re-entry well which are treated as
operating expenses for federal income tax purposes, however, will not be
characterized as operating costs, instead of intangible drilling costs, for
purposes of allocating the payment of the costs between the managing general
partner and the investors under the partnership agreement. (See "Participation
in Costs and Revenues.")
Your share of the partnership's gain (if a partnership well is sold at a gain),
or your gain (if your units are sold at a gain), will be treated as ordinary
income rather than capital gain to the extent of the previous deductions for
intangible drilling costs you have claimed, but not for the deductions for
operating expenses related to a re-entry well, if any. (See "- Sale of the
Properties" and "- Disposition of Units," below.) Also, productive-well
intangible drilling costs may subject you to an alternative minimum tax in
excess of regular tax unless you elect to deduct all or part of these costs
ratably over a 60 month period. (See "- Alternative Minimum Tax," below.)
Under the partnership agreement, not less than 90% of the subscription proceeds
received by each partnership from its investors will be used to pay 100% of the
partnership's intangible drilling costs of drilling and completing its wells.
(See "Application of Proceeds" and "Participation in Costs and Revenues.") The
IRS could challenge the characterization of a portion of these costs as
currently deductible intangible drilling costs and recharacterize the costs as
some other item which may not be currently deductible. However, this would have
no effect on the allocation and payment of the intangible drilling costs by you
and the other investors under the partnership agreement.
Your ability to use your share of these deductions on your personal federal
income tax returns may be reduced, eliminated or deferred by the "Potential
Limitations on Deductions" set forth in special counsel's opinion (4) in
"Special Counsel's Opinions," above.
You are urged to seek advice based on your particular circumstances from an
independent tax advisor concerning the tax benefits to you of the deduction for
intangible drilling costs in the partnership in which you invest.
DRILLING CONTRACTS
Each partnership will enter into the drilling and operating agreement with the
managing general partner or its affiliates, acting as a third-party general
drilling contractor, to drill and complete the partnership's 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, assuming a 100% working interest in each well, it
will have reimbursement of general and administrative overhead of approximately
$12,690 per well and a profit of 15% (approximately $23,976) per well, with
respect to the intangible drilling costs and the portion of equipment costs paid
by you and the other investors in your partnership as described in "Compensation
- - Drilling Contracts." However, the actual cost of drilling and completing the
wells may be more or less than the estimated amount, due primarily to the
uncertain nature of drilling operations. Therefore, the managing general
partner's 15% profit per well as described above also could be more or less than
the dollar 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 being unreasonable and
disallowed as a deductible intangible drilling cost.
As discussed in "- 2005 Expenditures," above, depending primarily on when their
respective subscription proceeds are received, the managing general partner
anticipates that either or both of the partnerships may prepay in 2005 most, if
not all, of their respective intangible drilling costs for drilling activities
that will begin in 2006. In Keller v. Commissioner, 79 T.C.
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7 (1982), aff'd 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part
test for the current deductibility of prepaid intangible drilling and
development costs. The test is:
o the expenditure must be a payment rather than a refundable deposit;
and
o the deduction must not result in a material distortion of income
taking into substantial consideration the business purpose aspects of
the transaction.
Each partnership will attempt to comply with the guidelines set forth in Keller
with respect to any prepaid intangible drilling costs. The drilling and
operating agreement will require your partnership to prepay in 2005 all of your
partnership's share of the estimated intangible drilling costs, and all of the
investors' share of your partnership's share of the estimated equipment costs,
for drilling and completing specified wells, the drilling of which may begin in
2006. These prepayments of intangible drilling costs should not result in a loss
of a current deduction for the intangible drilling costs if:
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 each partnership to prepay the
managing general partner's estimate of the intangible drilling costs and the
investor's share of the equipment costs to drill and complete the wells
specified in the drilling and operating agreement in order to enable the
operator to:
o begin site preparation for the wells;
o obtain suitable subcontractors at the then current prices; and
o insure the availability of equipment and materials.
Under the drilling and operating agreement excess prepaid intangible drilling
costs, if any, will not be refundable to a partnership, but instead will be
applied only to intangible drilling cost overruns, if any, on the other
specified wells being drilled or completed by the partnership or to intangible
drilling costs to be incurred by the partnership in drilling and completing
substitute wells. Under Keller, a provision for substitute wells should not
result in the prepayments being characterized as refundable deposits.
The likelihood that prepayments of intangible drilling costs will be challenged
by the IRS on the grounds that there is no business purpose for the prepayments
is increased if prepayments are not required with respect to 100% of the working
interest in the well. In this regard, the managing general partner anticipates
that less than 100% of the working interest will be acquired by each partnership
in one or more of its wells, and prepayments of intangible drilling costs will
not be required of the other owners of working interests in those wells. In the
view of special counsel, however, a legitimate business purpose for the required
prepayments of intangible drilling costs by the partnerships may exist under the
guidelines set forth in Keller, even though prepayments are not required by the
drilling contractor with respect to a portion of the working interest in the
wells.
In addition, a current deduction for prepaid intangible drilling costs is
available only if the drilling of the wells begins before the close of the 90th
day after the close of the taxable year in which the prepayment was made.
Therefore, under the drilling and operating agreement, the managing general
partner as operator and general drilling contractor must begin drilling each of
the prepaid wells, if any, of both partnerships no later than March 31, 2006.
However, the drilling of any partnership well may be delayed due to
circumstances beyond the control of the managing general partner or the drilling
subcontractors. These circumstances include, for example:
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o the unavailability of drilling rigs;
o decisions of third-party operators to delay drilling the wells;
o poor weather conditions;
o inability to obtain drilling permits or access right to the drilling
site; or
o title problems;
and the managing general partner will have no liability to any partnership or
its investors if these types of events delay beginning the drilling of the
prepaid wells past March 31, 2006.
If the drilling of a prepaid well in your partnership does not begin on or
before March 31, 2006, deductions claimed by you for prepaid intangible drilling
costs for the well in 2005, the year in which you invested in the partnership,
would be disallowed and deferred to the next taxable year, 2006, when the well
is actually drilled.
Your ability to use your share of these deductions on your personal federal
income tax returns may be reduced, eliminated or deferred by the "Potential
Limitations on Deductions" set forth in special counsel's opinion (4) in
"Special Counsel's Opinions," above.
DEPLETION ALLOWANCE
Proceeds from the sale of each partnership's natural gas and oil production will
constitute ordinary income. A portion of that income will not be taxable under
the depletion allowance which permits the deduction from gross income for
federal income tax purposes of either the percentage depletion allowance or the
cost depletion allowance, whichever is greater. Your share of the partnership's
gain (if a partnership well is sold at a gain), or your gain (if you sell your
units at a gain), will be treated as ordinary income rather than capital gain to
the extent of your previous deductions for depletion which reduced your adjusted
basis in the property or your units. (See "- Sale of the Properties" and "-
Disposition of Units," below.)
Cost depletion for any year is determined by dividing the adjusted tax basis for
the property by the total units of natural gas or oil expected to be recoverable
from the property and then multiplying the resultant quotient by the number of
units actually sold during the year. Cost depletion cannot exceed the adjusted
tax basis of the property to which it relates.
Percentage depletion is available to taxpayers other than "integrated oil
companies," which term does not include the partnerships. 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 managing general partner has
represented that most, if not all, of the natural gas and oil production from
each partnership's wells will be marginal production under this definition in
the Code. Therefore, most, if not all, of each partnership's gross income from
the sale of its natural gas and oil production will qualify for these
potentially higher rates of percentage depletion. The rate of percentage
depletion for marginal production in 2005 is 15%. This rate may fluctuate from
year to year depending on the price of oil, but will not be less than the
statutory rate of 15% nor more than 25%.
Also, percentage depletion:
o may not exceed 100% of the net income from each natural gas and oil
property before the deduction for depletion, however, this limitation
is suspended in 2005 with respect to marginal properties, which the
managing general partner has represented will include most, if not
all, of each partnership's wells; and
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o is limited to 65% of the taxpayer's taxable income for the year
computed without regard to percentage depletion, net operating loss
carry-backs and capital loss carry-backs.
Availability of percentage depletion must be computed separately by you and not
by your partnership or for investors in your partnership as a whole. You are
urged to seek advice based on your particular circumstances from an independent
tax advisor with respect to the availability of percentage depletion to you.
MARGINAL WELL PRODUCTION CREDITS
There is a marginal well production credit of 50(cent) per mcf of qualified
natural gas production and $3 per barrel of qualified oil production for
purposes of the regular federal income tax. This credit, however, cannot be used
to reduce alternative minimum tax. (See " - Alternative Minimum Tax," below.)
Because natural gas and oil production which qualifies as marginal production
under the percentage depletion rules discussed above, which the managing general
partner has represented will include most, if not all of the natural gas and oil
production from each partnership's productive wells, is also qualified marginal
production for purposes of this credit, the natural gas and oil production from
most, if not all, of each partnership's wells will be eligible for this credit.
To the extent an investor's share of his partnership's marginal well production
credits, if any, exceeds the investor's regular federal income tax owed on his
share of his partnership's taxable income, the excess credits, if any, can be
used by the investor to offset any other regular federal income taxes owed by
the investor, on a dollar-for-dollar basis, subject to the passive activity loss
limitation in the case of limited partners. (See "- Limitations on Passive
Activity Losses and Credits," above.) The credit will be reduced proportionately
for reference prices between $1.67 and $2.00 per mcf for natural gas and $15 and
$18 per barrel for oil. The applicable reference price for a tax year is
determined by the IRS based on the average price of natural gas and oil in the
previous calendar year.
The reference price for oil was $27.56 in 2003, and it has not been under the
$18.00 threshold necessary to qualify for any marginal well production credit
for oil since 1999. Similarly, the managing general partner received an average
selling price after deducting all expenses, including transportation expenses,
of approximately $4.78 per mcf in 2003, and the average price it has received
for natural gas production in each calendar year since 1999 has not been less
than the $3.30 it received in 2000. In this regard, the managing general partner
has represented that it does not anticipate that any of the partnerships'
production of natural gas and oil from their respective wells in 2005, if any,
will qualify for this credit in 2005, because the prices for natural gas and oil
in 2004 were substantially above the $2.00 per mcf of natural gas and $18.00 per
barrel of oil prices where the credit phases out completely. Based on the prices
set forth in "Proposed Activities - Sale of Natural Gas and Oil Production" for
natural gas and oil in the past several years, it may appear unlikely that a
partnership's natural gas and oil production will ever qualify for this credit.
However, prices for natural gas and oil are volatile and could decrease in the
future. (See "Risk Factors - Risks Related To The Partnerships' Oil and Gas
Operations - Partnership Distributions May be Reduced if There is a Decrease in
the Price of Natural Gas and Oil.") Thus, it is possible that the partnerships'
production of natural gas or oil in one or more taxable years after 2005 could
qualify for the marginal well production credit, depending primarily on the
applicable reference prices for natural gas and oil in the future.
The maximum amount of marginal production of natural gas and oil from a well on
which the credit can be claimed by a partnership in any taxable year is 1,095
barrels of oil or barrel-of-oil equivalents per well. Subject to a post-2005
inflation adjustment, the maximum dollar amount of the credit in any tax year
will be $3,110 for qualified natural gas production from each qualified marginal
well (6,220 mcf x 50(cent)), and $3,285 for qualified crude oil production from
each qualified marginal well ($3.00 x 1,905 barrels). There is no limit on the
number of qualified marginal wells on which your partnership and you can claim
the credit.
Only holders of a working interest in a qualified well can claim the credit. For
purposes of the credit, you and the other investors in a partnership will be
treated as working interest owners because of your flow-through ownership
interest in the partnership. As a result of this rule, owners of non-working
interests in a well, such as the owner of a landowner's royalty interest, will
not receive any of these credits from the well. For a qualified marginal well in
which there is more than one owner of the working interests, which will be the
case for one or more wells in each partnership, the amount of qualifying natural
gas and oil production that each owner of a partial working interest in the well
is entitled to will be based on the ratio which each working interest owner's
revenue interest in the production from the well bears to the aggregate of the
revenue
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interests of all working interest owners in the production from the well. (See
"Proposed Activities - Interests of Parties.") You will share in your
partnership's marginal well production credits, if any, in the same proportion
as your share of your partnership's production revenues. (See "Participation in
Costs and Revenues.")
Unused marginal well production credits can be carried back for up to five
years, and forward for up to 20 years. However, any unused marginal well
production credits at the end of the 20-year carryforward period cannot be
deducted, and will be lost.
An investor general partner's share of his partnership's marginal well
production credits, if any, will be an active credit which may offset the
investor general partner's regular federal income tax liability on any type of
income. However, after the investor general partner is converted to a limited
partner in his partnership, his share of the partnership's marginal well
production credits, if any, will be active credits only to the extent of the
converted investor general partner's regular federal income tax liability which
is allocable to his share of any net income of his partnership, which is still
treated as non-passive income even after the investor general partner has been
converted to a limited partner. (See " - Conversion from Investor General
Partner to Limited Partner," above.) Any excess credits allocable to the
converted investor general partner, as well as all of the marginal well
production credits allocable to those investors who originally invest in a
partnership as limited partners, will be passive credits which can reduce only
an investor's regular income tax liability attributable to passive income from
the partnership or other passive activities.
DEPRECIATION - MODIFIED ACCELERATED COST RECOVERY SYSTEM ("MACRS")
Equipment costs (i.e. "Tangible Costs") and the related depreciation deductions
of each partnership 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 otherwise be charged to you and the other
investors exceeds an amount equal to 10% of the partnership's subscription
proceeds, then the excess equipment costs, together with the related
depreciation deductions, will be charged and allocated to the managing general
partner.
Each partnership's reasonable equipment costs for equipment placed in its
respective wells which cannot be deducted immediately will be recovered through
depreciation deductions over a seven year cost recovery period, using the 200%
declining balance method, with a switch to straight-line to maximize the
deduction, beginning in the taxable year each well is "placed in service" by the
partnership. In the case of a short tax year the MACRS deduction is prorated on
a 12-month basis. No distinction is made between new and used property and
salvage value is disregarded. All property assigned to the 7-year class is
treated as placed in service, or disposed of, in the middle of the year, unless
more than 40% of the total bases of all personal property placed in service
during the year is placed in service during the last three months of the year.
If that happens, the depreciation for the full year will be multiplied by a
fraction based on the quarter the personal property is placed in service: 87.5%
for the first quarter, 62.5% for the second, 37.5% for the third, and 12.5% for
the fourth. All of these cost recovery deductions claimed by the partnerships
and their respective investors are subject to recapture as ordinary income
rather than capital gain on the sale or other taxable disposition of the
property or an investor's units. (See "- Sale of the Properties" and "-
Disposition of Units," below.) Depreciation for alternative minimum tax purposes
is computed using the 150% declining balance method, switching to straight-line,
for most personal property. This means that a partnership's depreciation
deductions in its early years for alternative minimum tax purposes will be less
than the partnership's depreciation deductions in those years for regular tax
purposes, and greater in the partnership's later years. This will result in
adjustments in computing the alternative minimum taxable income of each of the
partnership's investors. (See "- Alternative Minimum Tax," below.)
Your ability to use your share of these deductions on your personal federal
income tax returns may be reduced, eliminated or deferred by the "Potential
Limitations on Deductions" set forth in special counsel's opinion (4) in
"Special Counsel's Opinions," above.
109
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 the Leases
to each Partnership as a part of its Capital Contribution.
TAX BASIS OF UNITS
Your share of your partnership's losses is allowable only to the extent of the
adjusted basis of your units at the end of your partnership's taxable year. The
adjusted basis of your units will be adjusted, but not below zero, for any gain
or loss to you from a sale or other taxable disposition by the partnership of a
natural gas or oil property, and will be increased by your:
o cash subscription payment;
o share of partnership income; and
o share, if any, of partnership debt.
The adjusted basis of your units will be reduced by your:
o share of partnership losses;
o share of partnership expenditures that are not deductible in computing
its taxable income and are not properly chargeable to capital account;
o depletion deductions, but not below zero; and
o cash distributions from the partnership.
The reduction in your share of partnership liabilities, if any, is considered a
cash distribution to you. Should cash distributions to you from your partnership
exceed the tax basis of your units, taxable gain would result to you to the
extent of the excess.
"AT RISK" LIMITATION FOR LOSSES
Subject to the limitations on "passive losses" generated by a partnership in the
case of limited partners, your particular alternative minimum tax situation, and
your basis in your units, you may use your share of your 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 your partnership at the end of a
taxable year. (See "- Limitations on Passive Activity Losses and Credits" and "-
Tax Basis of Units," above, and "- Alternative Minimum Tax," below.) This "at
risk" limitation on your deductions from your partnership, however, does not
apply to you if you are a corporation which is neither an S corporation nor a
corporation in which at any time during the last half of the taxable year five
or fewer individuals own more than 50% (in value) of the stock. Your initial "at
risk" amount is equal to the amount of money you pay for your units. However,
any amounts borrowed by you to buy your units will not be considered "at risk"
if the amounts are borrowed from another investor in your partnership or anyone
related to another investor in your partnership. In this regard, the managing
general partner has represented that it and its affiliates will not make or
arrange financing for you or any other potential investors to use to purchase
units in a partnership. Also, the amount you have "at risk" in your partnership
may not include the amount of any loss that you are protected against through:
o nonrecourse loans;
o guarantees;
o stop loss agreements; or
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o other similar arrangements.
DISTRIBUTIONS FROM A PARTNERSHIP
A cash distribution from your partnership to you in excess of the adjusted basis
of your units immediately before the distribution is treated as gain to you from
the sale or exchange of your units to the extent of the excess. Different rules
apply, however, to payments by a partnership to a deceased investor's successor
in interest and to payments for an investor's share of his partnership's
unrealized receivables and inventory items as those terms are defined in
Section 751 of the Code. No loss can be recognized by you on these types of
distributions, unless the distribution is made to liquidate your units in your
partnership and then only to the extent of the excess, if any, of your adjusted
basis in your units over the sum of the amount of money distributed to you plus
your share of the basis of any unrealized receivables and inventory items of
your partnership. (See "- Disposition of Units," below, for a discussion of
unrealized receivables and inventory items under Section 751 of the Code.) Other
distributions of cash, disproportionate distributions of property, if any, and
liquidating distributions of your partnership may result in taxable gain or loss
to you. (See "- Termination of a Partnership," below.)
SALE OF THE PROPERTIES
The maximum tax rate on a noncorporate taxpayer's adjusted net capital gain on
the sale of assets held more than a year is 15%, or 5% to the extent the gain
would have been taxed at a 10% or 15% rate if it had been ordinary income,
respectively, for most capital assets. In addition, for 2008 only, the 5% tax
rate on adjusted net capital gain is reduced to 0%. The former maximum tax rates
of 18% and 8%, respectively, on qualified five-year gain have been eliminated.
These capital gain rates also apply for purposes of the alternative minimum tax.
(See "- Alternative Minimum Tax," below.) However, the former tax rates of 20%
and 10%, respectively, are scheduled to be reinstated on January 1, 2009.
"Adjusted net capital gain" means net capital gain determined without taking
qualified dividend income into account:
o reduced (but not below zero) by:
o any amount of qualified dividend income taken into account as
investment income;
o net capital gain that is taxed a maximum rate of 28% (such as
gain on the sale of most collectibles and gain on the sale of
qualified small business stock); and
o net capital gain that is taxed at a maximum rate of 25% (gain
attributable to real estate depreciation); and
o increased by the amount of qualified dividend income.
"Net capital gain" means the excess of net long-term gain (excess of long-term
gains over long-term losses) over net short-term loss (excess of short-term
gains over short-term losses). The annual capital loss limitation for
noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000,
which is reduced to $1,500 for married persons filing separate returns, or the
excess of capital losses over capital gains.
Gains from sales of natural gas and oil properties held for more than 12 months
will be treated as a long-term capital gain, while a net loss will be an
ordinary deduction. However, if a natural gas or oil property owned by your
partnership is sold, gain will be treated as ordinary income to the extent of
the lesser of:
o the amounts which were deducted as intangible drilling costs rather
than added to the basis of the property, plus deductions for depletion
which reduced the adjusted basis of the property; or
o the excess of:
o the amount realized, in the case of a sale, exchange or
involuntary conversion; or
111
o the fair market value of the interest, in all other cases;
minus the property's adjusted basis.
In addition, all equipment depreciation deductions, and losses on previous sales
of a partnership's assets which have not yet been used for the purpose of
treating a portion or all of gains on previous sales of the partnership's
properties for the partnership's five most recent taxable years as ordinary
income will be treated as ordinary income to the extent of any gain on the sale
or other taxable disposition of the property. (See "- Depreciation - Modified
Accelerated Cost Recovery System ("MACRS").") Other gains and losses on sales of
natural gas and oil properties held by the partnership for less than 12 months,
if any, will result in ordinary gains or losses.
DISPOSITION OF UNITS
The sale or exchange, including a purchase by the managing general partner, of
all or some of your units held by you for more than 12 months will result in a
recognition by you of long-term capital gain or loss, except for previous
deductions for depreciation, depletion and intangible drilling costs, and your
share of the partnership's "Section 751 assets" (i.e. inventory items and
unrealized receivables). "Unrealized receivables" includes any right to payment
for goods delivered, or to be delivered, to the extent the proceeds would be
treated as amounts received from the sale or exchange of non-capital assets, or
services rendered or to be rendered, to the extent not previously includable in
income under the Partnerships' accounting methods. "Inventory items" includes
property properly includable in inventory and property held primarily for sale
to customers in the ordinary course of business and any other property that
would produce ordinary income if sold, including accounts receivable for goods
and services. These tax items are sometimes referred to in this discussion as
"Section 751 assets." All of these tax items may be recaptured as ordinary
income rather than capital gain regardless of how long you have owned your
units. (See "- Sale of the Properties," above.)
If your units are held for 12 months or less, your gain or loss will be
short-term gain or loss. Also, your pro rata share of your partnership's
liabilities, if any, as of the date of the sale or exchange must be included in
the amount realized. Therefore, the gain recognized by you may result in a tax
liability to you greater than the cash proceeds, if any, received by you from
the disposition. In addition to gain from a passive activity, a portion of any
gain recognized by a limited partner on the sale or other taxable disposition of
his units will be characterized as portfolio income under the passive activity
loss rules to the extent the gain is attributable to portfolio income, e.g.
interest income on investments of working capital. (See "- Limitations on
Passive Activity Losses and Credits," above.)
A gift of your units may result in federal and/or state income tax and gift tax
liability to you. Also, interests in different partnerships do not qualify for
tax-free like-kind exchanges. Other dispositions of your units may or may not
result in recognition of taxable gain. However, no gain should be recognized by
an investor general partner on the conversion of his investor general partner
units to limited partner units so long as there is no change in his share of his
partnership's liabilities or Section 751 assets as a result of the conversion.
In addition, if you sell or exchange all or some of your units you are required
by the Code to notify your partnership within 30 days or by January 15 of the
following year, if earlier. The partnership will then report any information
required to be reported by the IRS regarding the transfer of the units to the
IRS, including your share of the partnership's Section 751 assets which are
subject to recapture as ordinary income as discussed above.
If you die, or sell or exchange all of your units, the taxable year of your
partnership will close with respect to you, but not the remaining investors, on
the date of death, sale or exchange, with a proration of partnership items for
the partnership's taxable year. If you sell less than all of your units, the
partnership's taxable year will not terminate with respect to you, but your
proportionate share of the partnership's items of income, gain, loss, deduction
and credit will be determined by taking into account your varying interests in
the partnership during the taxable year.
You are urged to seek advice based on your particular circumstances from an
independent tax advisor before any disposition of your units, including any
purchase of your units by the managing general partner.
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ALTERNATIVE MINIMUM TAX
With limited exceptions, you must pay an alternative minimum tax if it exceeds
your regular federal income tax for the year. Alternative minimum taxable income
is taxable income, plus or minus various adjustments, plus tax preference items.
The principal adjustments and preference items which may apply to typical
investors in a partnership are summarized below.
The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500
for married individuals filing separately, of a taxpayer's alternative minimum
taxable income in excess of the exemption amount; and additional alternative
minimum taxable income is taxed at 28%. However, the regular tax rates on
capital gains also will apply for purposes of the alternative minimum tax. (See
"- Sale of the Properties," above.) Subject to the phase-out provisions
summarized below, the exemption amounts for 2005 are $58,000 for married
individuals filing jointly and surviving spouses, $40,250 for single persons
other than surviving spouses, and $29,000 for married individuals filing
separately. For years beginning after 2005, these exemption amounts are
scheduled to decrease to $45,000 for married individuals filing jointly and
surviving spouses, $33,750 for single persons other than surviving spouses, and
$22,500 for married individuals filing separately. The exemption amount for
estates and trusts is $22,500 in 2005 and subsequent years.
The exemption amounts set forth above are reduced by 25% of alternative minimum
taxable income in excess of:
o $150,000, in the case of married individuals filing a joint return and
surviving spouses - the $58,000 exemption amount is completely phased
out when alternative minimum taxable income is $382,000 or more, and
the $45,000 amount phases out completely at $330,000;
o $112,500, in the case of unmarried individuals other than surviving
spouses - the $40,250 exemption amount is completely phased out when
alternative minimum taxable income is $273,500 or more, and the
$33,750 amount phases out completely at $247,500; and
o $75,000, in the case of married individuals filing a separate return -
the $29,000 exemption amount is completely phased out when alternative
minimum taxable income is $191,000 or more and the $22,500 amount
phases out completely at $165,000. In addition, in 2005 the
alternative minimum taxable income of married individuals filing
separately is increased by the lesser of $29,000 ($22,500 after 2005)
or 25% of the excess of the person's alternative minimum taxable
income (determined without regard to this provision) over $191,000
($165,000 after 2005).
Some of the principal adjustments to taxable income that are used to determine
alternative minimum taxable income include those summarized below:
o Depreciation deductions of the costs of the equipment in the wells may
not exceed deductions computed using the 150% declining balance
method. (See "- Depreciation - Modified Accelerated Cost Recovery
System ("MACRS"), above.)
o Miscellaneous itemized deductions are not allowed.
o Medical expenses are deductible only to the extent they exceed 10% of
adjusted gross income.
o State and local property taxes and income taxes (or sales taxes,
instead of state and local income taxes, at your election in the 2005
tax year), which are itemized and deducted for regular tax purposes,
are not deductible.
o Interest deductions are restricted.
o The standard deduction and personal exemptions are not allowed.
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o Only some types of operating losses are deductible.
o Different rules under the Code apply to incentive stock options that
may require earlier recognition of income.
The principal tax preference items that must be added to taxable income for
alternative minimum tax purposes include:
o excess intangible drilling costs, as discussed below; and
o tax-exempt interest earned on specified private activity bonds, less
any deductions that would have been allowable if the interest were
included in gross income for regular income tax purposes.
For taxpayers other than "integrated oil companies" as that term is defined in
"- Intangible Drilling Costs," above, which does not include the partnerships,
the 1992 National Energy Bill repealed:
o the preference for excess intangible drilling costs; and
o the excess percentage depletion preference for natural gas and oil.
The repeal of the excess intangible drilling costs preference, however, under
current law may not result in more than a 40% reduction in the amount of the
taxpayer's alternative minimum taxable income computed as if the excess
intangible drilling costs preference had not been repealed. Under the prior
rules, the amount of intangible drilling costs which is not deductible for
alternative minimum tax purposes is the excess of the "excess intangible
drilling costs" over 65% of net income from natural gas and oil properties. Net
natural gas and oil income is determined for this purpose without subtracting
excess intangible drilling costs. Excess intangible drilling costs is the
regular intangible drilling costs deduction minus the amount that would have
been deducted under 120-month straight-line amortization, or, at the taxpayer's
election, under the cost depletion method. There is no preference item for costs
of nonproductive wells.
Also, you may elect under Section59(e) of the Code to capitalize all or part of
your share of your partnership's intangible drilling costs and deduct the costs
ratably over a 60-month period beginning with the month in which the costs were
paid or incurred by the partnership. This election also applies for regular tax
purposes and can be revoked only with the IRS' consent. Making this election,
therefore, will include the following principal consequences to you:
o your regular tax deduction for intangible drilling costs in the year
in which you invest will be reduced because you must spread the
deduction for the amount of intangible drilling costs which you elect
to capitalize over the 60-month amortization period; and
o the capitalized intangible drilling costs will not be treated as a
preference that is included in your alternative minimum taxable
income.
Other than intangible drilling costs as discussed above, the principal tax item
that may have an impact on your alternative minimum taxable income as a result
of investing in a partnership is depreciation of the partnership's equipment
expenses. As noted in "- Depreciation - Modified Accelerated Cost Recovery
System ("MACRS")," above, each partnership's cost recovery deductions for
regular income tax purposes will be computed using the 200% declining balance
method rather than the 150% declining balance method used for alternative
minimum tax purposes. This means that in the early years of a partnership your
depreciation deductions from the partnership will be smaller for alternative
minimum tax purposes than your depreciation deductions for regular income tax
purposes on the same equipment. This, in turn, could cause you to incur, or may
increase, your alternative minimum tax liability in the partnership's early
years. Conversely, this adjustment may decrease your alternative minimum taxable
income in your partnership's later years.
Your share of your partnership's marginal well production credits, if any, may
not be used to reduce your alternative minimum tax liability, if any. Also, the
rules relating to the alternative minimum tax for corporations are different
from those
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summarized above. All prospective investors contemplating purchasing units in a
partnership are urged to seek advice based on their particular circumstances
from an independent tax advisor as to the likelihood of them incurring or
increasing any alternative minimum tax liability as a result of an investment in
a partnership.
LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST
Investment interest expense is deductible by a noncorporate taxpayer only to the
extent of net investment income each year, with an indefinite carryforward of
disallowed amounts. An investor general partner's share of any interest expense
incurred by the partnership in which he invests before his investor general
partner units are converted to limited partner units will be subject to the
investment interest limitation. In addition, the investor general partner's
share of the partnership's income and losses, including the deduction for
intangible drilling costs, will be considered to be investment income and
losses. Thus, for example, a loss allocated to an investor general partner from
the partnership in the year in which he invests in the partnership as a result
of the deduction for intangible drilling costs will reduce his net investment
income and may reduce or eliminate the deductibility of his investment interest
expenses, if any, in that taxable year with the disallowed portion to be carried
forward to the next taxable year. These rules, however, do not apply to a
partnership's income or expenses taken into account in computing income or loss
from a passive activity. (See "- Limitations on Passive Activity Losses and
Credits," above.)
ALLOCATIONS
The partnership agreement allocates to you your share of your partnership's
income, gains, losses, deductions, and credits, if any, including the deductions
for intangible drilling costs and depreciation. Your capital account in the
partnership in which you invest will be adjusted to reflect your share of these
allocations and your capital account, as adjusted, will be given effect in
distributions made to you on liquidation of the partnership or your units. Your
capital account in the partnership in which you invest will be:
o increased by the amount of money you contribute to the partnership and
allocations to you of income and gain; and
o decreased by the value of property or cash distributed to you by the
partnership and allocations to you of losses and deductions.
Also, any marginal well production credits of a partnership, will be allocated
among the managing general partner and you and the other investors in the
partnership in which you invest in accordance with your respective interests in
the partnership's production revenues from the sale of its natural gas and oil
production. (See "Participation in Costs and Revenues" and " - Marginal Well
Production Credits," above.)
It should also be noted that your share of items of income, gain, loss,
deduction and credit in the partnership in which you invest must be taken into
account by you whether or not you receive any cash distributions from the
partnership. For example, your share of partnership revenues applied by your
partnership to the repayment of loans or the reserve for plugging wells will be
included in your gross income in a manner analogous to an actual distribution of
the revenues (and income) to you. Thus, you may have tax liability on taxable
income from your partnership for a particular year in excess of any cash
distributions from the partnership to you with respect to that year. To the
extent a partnership has cash available for distribution, however, it is the
managing general partner's policy that partnership cash distributions to its
investors will not be less than the managing general partner's estimate of the
investors' income tax liability with respect to that partnership's income.
If any allocation under the partnership agreement is not recognized for federal
income tax purposes, your share of the items subject to the allocation will be
determined in accordance with your interest in the partnership in which you
invest by considering all of the relevant facts and circumstances. To the extent
deductions or credits allocated by the partnership agreement exceed deductions
or credits which would be allowed under a reallocation by the IRS, you may incur
a greater tax burden.
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PARTNERSHIP BORROWINGS
Under the partnership agreement the managing general partner and its affiliates
may make loans to the partnerships. The use of partnership revenues taxable to
you to repay borrowings by your partnership could create income tax liability
for you in excess of your cash distributions from the partnership, since
repayments of principal are not deductible for federal income tax purposes. In
addition, interest on the loans will not be deductible unless the loans are bona
fide loans that will not be treated as capital contributions to the partnership
by the managing general partner or its affiliates in light of all of the
surrounding facts and circumstances.
PARTNERSHIP ORGANIZATION AND OFFERING COSTS
Expenses connected with the offer and sale of units in a partnership, such as
the dealer-manager fee, sales commissions, and other selling expenses,
professional fees, and printing costs, which are charged under the partnership
agreement 100% to the managing general partner as organization and offering
costs, are not deductible. Although expenses incident to the creation of a
partnership may be amortized over a period of not less than 180 months, these
expenses also will be paid by the managing general partner as part of each
partnership's organization and offering costs. Thus, any related deductions,
which the managing general partner does not anticipate will be material in
amount as compared to the total subscription proceeds of the partnerships, will
be allocated to the managing general partner.
TAX ELECTIONS
Each partnership may elect to adjust the basis of its property on the transfer
of a unit in the partnership by sale or exchange or on the death of an investor,
and on the distribution of property (other than money) by the partnership to an
investor (the Section754 election). If the Section754 election is made,
transferees of the units are treated, for purposes of depreciation and gain, as
though they had acquired a direct interest in the partnership assets and the
partnership is treated for these purposes, on distributions to the investors, as
though it had newly acquired an interest in the partnership assets and therefore
acquired a new cost basis for the assets. Any election, once made, may not be
revoked without the consent of the IRS.
In this regard, the managing general partner has represented that due to the
complexities and added expense of the tax accounting required to implement a
Section754 election to adjust the basis of a partnership's property when units
are sold, taking into account the limitations on the sale of the partnership's
units, neither partnership will make the Section754 election. Even though the
partnerships will not make the Section754 election, the basis adjustment
described above is mandatory under the Code with respect to the transferee
partner only, if at the time a unit is transferred by sale or exchange, or on
the death of an investor, the partnership's adjusted basis in its property
exceeds the fair market value of the property by more than $250,000 immediately
after the transfer of the unit. Similarly, a basis adjustment is mandatory under
the Code if a partnership distributes property in-kind to a partner, and the sum
of the partner's loss on the distribution and the basis increase to the
distributed property is more than $250,000. In this regard, under the
partnership agreement the partnerships will not distribute their assets in-kind
to their respective investors, except to a liquidating trust or similar entity
for the benefit of you and its other investors, unless at the time of the
distribution you and the other investors have been offered the election of
receiving in-kind property distributions, and you accept the offer after being
advised of the risks associated with direct ownership; or there are alternative
arrangements in place which assure you and the other investors that you will
not, at any time, be responsible for the operation or disposition of the
partnership's properties.
If the basis of a partnership's assets must be adjusted as discussed above, the
primary effect on the partnership, other than the federal income tax
consequences discussed above, would be an increase in its administrative and
accounting expenses to make the required basis adjustments to its properties and
separately account for those adjustments after they are made. In this regard,
the partnerships will not make in-kind property distributions to their
respective investors except in the limited circumstances described above, and
the units have no readily available market and are subject to substantial
restrictions on their transfer. (See "Transferability of Units - Restrictions on
Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement.") These factors will tend to limit the additional expense to a
partnership if the mandatory basis adjustments to a partnership's assets
described above apply to it. In addition to the Section754 election, each
partnership may make various elections under the Code for federal tax reporting
purposes which could result in the deductions of intangible drilling costs and
depreciation, and the depletion allowance, being treated differently for tax
purposes than for accounting purposes.
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Also, under the Code "start-up expenditures" may be capitalized and amortized
over a 180-month period. The term "start-up expenditure" for this purpose
includes any amount:
o paid or incurred in connection with:
o investigating the creation of an active trade or business; or
o creating an active trade or business, or
o any activity engaged in for profit and for the production of
income before the day on which the active trade or business
begins, in anticipation of that activity becoming an active trade
or business; and
o which would be allowed as a deduction if paid or incurred in
connection with the expansion of an existing business.
If it is ultimately determined by the IRS or the courts that any of a
partnership's expenses constituted start-up expenditures, the partnership's
deductions for those expenses would be amortized over the 180-month period.
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
the partnership exceeds the adjusted basis of your units. The conversion of
investor general partner units to limited partner units, however, will not
terminate a partnership. Also, due to the restrictions on transfers of units in
the partnership agreement, the managing general partner does not anticipate that
either partnership will ever be considered as terminated for this reason for
federal income tax purposes.
TAX RETURNS AND IRS AUDITS
The tax treatment of most partnership items is determined at the partnership,
rather than the partner level. Also, the partners are required to treat
partnership items on their individual federal income tax returns in a manner
which is consistent with the treatment of the partnership items on the
partnership's federal information income tax return, unless they disclose to the
IRS that their tax treatment of partnership tax items on their personal federal
income tax return is different from their partnership's tax treatment of those
tax items. The IRS must conduct an administrative determination as to
partnership items at the partnership level before conducting deficiency
proceedings against a partner, and the partners must file a request for an
administrative determination before filing suit for any credit or refund. The
period for assessing tax against you and the other investors attributable to a
partnership item may be extended by agreement between the IRS and the managing
general partner, which will serve as each partnership's representative ("Tax
Matters Partner") in all administrative tax proceedings and tax litigation
conducted at the partnership level.
The Tax Matters Partner may enter into a settlement on behalf of, and binding
on, any investor owning less than a 1% profits interest in a partnership if
there are more than 100 partners in the partnership, unless that investor timely
files a statement with the Secretary of the Treasury providing that the Tax
Matters Partner does not have authority to enter into a settlement agreement on
behalf of that investor. The managing general partner anticipates, based on its
past experience, that there will be more than 100 investors in each of the
partnerships, including Atlas America Public #14-2005(B) L.P. if units in that
partnership are offered. 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 Tax Matters Partner does not
have binding settlement authority. In addition, a partnership with at least 100
partners may elect to be governed under simplified tax reporting and audit rules
as an "electing large partnership." These rules would help the IRS match
partnership items with its investors' personal federal income tax returns. In
addition, most limitations affecting the calculation of the taxable income and
tax credits of an electing large partnership are applied at the partnership
level and not the partner level. Thus, the managing general partner does not
anticipate that either partnership will make this election.
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All expenses of any tax proceedings involving a partnership and the managing
general partner acting as Tax Matters Partner, which might be substantial, will
be paid for by the partnership and not by the managing general partner from its
own funds. The managing general partner, however, is not obligated to contest
adjustments made by the IRS. The managing general partner will notify you of any
IRS audits or other tax proceedings involving your partnership, and will provide
you any other information regarding the proceedings as may be required by the
partnership agreement or law.
TAX RETURNS. Your individual income tax returns are your responsibility. Each
partnership will provide its investors with the tax information applicable to
their investment in the partnership necessary to prepare their tax returns.
PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND JUDICIAL DOCTRINES LIMITATIONS ON
DEDUCTIONS
Your ability to deduct your share of your partnership's deductions could be
limited or lost if the partnership lacks the appropriate profit motive. The Code
creates a presumption that an activity is engaged in for profit if, in any three
of five consecutive taxable years, the gross income derived from the activity
exceeds the deductions attributable to the activity. Thus, if your partnership
fails to show a profit in at least three out of five consecutive years this
presumption will not be available and the possibility that the IRS could
successfully challenge the partnership deductions claimed by you would be
substantially increased. The fact that the possibility of ultimately obtaining
profits is uncertain, standing alone, does not appear under the Treasury
Regulations to be sufficient grounds for the denial of losses. Also, if a
principal purpose of a partnership is to reduce substantially the partners'
federal income tax liability in a manner that is inconsistent with the intent of
the partnership rules of the Code, based on all the facts and circumstances, the
IRS is authorized under Treasury Regulation Section 1.701-2 to remedy the abuse.
Finally, under potentially relevant judicial doctrines including the step
transaction, business purpose, economic substance, substance over form, and sham
transaction doctrines, tax deductions and tax credits from a transaction will be
disallowed if the transaction has no economic substance apart from the tax
benefits.
With respect to these issues, special counsel has given its opinions that the
partnerships will possess the requisite profit motive, and the IRS anti-abuse
rule in Treas. Reg. Section 1.701-2 and the potentially relevant judicial
doctrines listed above will not have a material adverse effect on the tax
consequences of an investment in a partnership by a typical investor as
described in special counsel's opinions. These opinions are based in part on the
results of the previous partnerships sponsored by the managing general partner
as set forth in "Prior Activities" and the managing general partner's
representations. These representations include that each partnership will be
operated as described in this prospectus (see "Management" and "Proposed
Activities") and the principal purpose of each partnership is to locate, produce
and market natural gas and oil on a profitable basis, apart from tax benefits,
as described in this prospectus. These representations are supported by the
geological evaluations and the other information for the partnerships' proposed
drilling areas, and the specific prospects proposed to be drilled by Atlas
America Public #14-2005(A) L.P. included in Appendix A to this prospectus. Also,
the managing general partner has represented that Appendix A in this prospectus
will be supplemented or amended to cover a portion of the specific prospects
proposed to be drilled by Atlas America Public #14-2005(B) L.P. when units in
that partnership are first offered to prospective investors.
FEDERAL INTEREST AND TAX PENALTIES
Taxpayers must pay tax and interest on underpayments of federal income taxes and
the Code contains various penalties, including a penalty equal to 20% of the
amount of a substantial understatement of federal income tax liability. An
understatement occurs if the correct income tax, as finally determined, exceeds
the income tax liability actually shown on the taxpayer's federal income tax
return. An understatement on a non-corporate taxpayer's federal income tax
return is substantial if it exceeds the greater of 10% of the correct tax, or
$5,000. A taxpayer may avoid this penalty if the understatement was not
attributable to a "tax shelter," and there was substantial authority for the
taxpayer's tax treatment of the item that caused the understatement, or if the
relevant facts were adequately disclosed on the taxpayer's tax return and the
taxpayer had a "reasonable basis" for the tax treatment of that item. In the
case of an understatement that is attributable to a "tax shelter," however,
which may include each of the partnerships for this purpose, the penalty may be
avoided only if there was reasonable cause for the underpayment and the taxpayer
acted in good faith, or there is or was substantial authority for the taxpayer's
treatment of the item, and the taxpayer reasonably believed that his or her
treatment of the item on the tax return was more likely than not the proper
treatment.
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In addition, there is a 20% penalty for reportable transaction understatements
for any tax year. If the disclosure rules for reportable transactions are not
met, then this penalty is increased from 20% to 30%, and the "reasonable cause"
exception to the penalty, which is discussed below, will not be available. A
reportable transaction understatement is:
o the amount of the increase (if any) in taxable income resulting from
the proper tax treatment of a tax item subject to this rule, as
discussed below, instead of the taxpayer's treatment of the tax item
on the taxpayer's tax return, multiplied by the highest noncorporate
income tax rate (or corporate income tax rate, in the case of a
corporation); and
o the amount of the decrease (if any) in the aggregate amount of credits
resulting from a difference between the taxpayer's treatment of a tax
item subject to this rule, as discussed below, and the proper tax
treatment.
A tax item is subject to the reportable transaction rules if the tax item is
attributable to:
o any listed transaction, which is a transaction that the IRS has
publicly pronounced that it has specifically found to be a tax
avoidance transaction; and
o any reportable transaction (other than a listed transaction) if a
significant purpose of the transaction is federal income tax avoidance
or evasion.
Due to the many inherently factual determinations involved, special counsel is
unable to give an opinion as to whether the partnerships have a "significant"
purpose, as defined under the Code for this purpose, of federal income tax
avoidance. However, special counsel has given its opinion that, more likely than
not, the partnerships will not be treated as reportable transactions under the
Code. This opinion is based in part on the managing general partner's
representation, which special counsel believes is reasonable in light of the
partnerships' intended activities as described in this prospectus, that each
partnership's total abandonment losses under Section 165 of the Code, which
could include, for example:
o the abandonment by a partnership of wells drilled which are
nonproductive (i.e. a "dry hole"), in which case the intangible
drilling costs, the equipment costs, and possibly the lease costs of
the abandoned wells would be deducted as Section 165 losses; or
o wells which have been operated until their commercial natural gas and
oil reserves have been depleted, in which case the undepreciated
equipment costs, possibly the lease costs, and any intangible drilling
costs which have not previously been deducted (all of an investor's
intangible drilling costs may not have been deducted if the investor
elected to amortize all or a portion of the investor's share of the
partnership's intangible drilling costs over a 60-month period as
discussed in "- Alternative Minimum Tax," above, and the well is
abandoned within that 60-month period), would be deducted as
Section 165 losses;
(and each investor's allocable share of those abandonment losses), will be less
than $2 million in any taxable year of a partnership and less than an aggregate
total of $4 million during a partnership's first six taxable years.
Because the determination of what transactions will be determined by the
IRS to be "listed transactions," which is one type of reportable transaction, is
in the sole discretion of the IRS, there is always a possibility that the IRS
could determine in the future that natural gas and oil drilling programs such as
the partnerships should be listed transactions. Being a reportable transaction
would increase the risk that a partnership's federal information income tax
returns and the personal federal income tax returns of its investors would be
audited by the IRS. In this regard, however, merely being designated as a
reportable transaction has no legal effect on whether the tax treatment of any
transaction by a partnership or its investors for federal tax purposes was
proper or improper.
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There is a defense to the reportable transaction understatement penalty if the
taxpayer acted in good faith, the tax treatment of the item in question was
adequately disclosed to the IRS, there is or was substantial authority for the
tax treatment, and the taxpayer reasonably believed that its tax treatment was
more likely than not the proper tax treatment. Under the Code, however, special
counsel's tax opinion letter cannot be relied on by you to establish your
"reasonable belief" as a defense if the penalty is asserted against you by the
IRS based on your partnership's tax treatment of any tax item. You cannot use
special counsel's tax opinion letter for this purpose, because special counsel
has been compensated directly by the managing general partner for providing its
tax opinion letter and helping organize and document this offering. Therefore,
if the situation ever arises, you must establish your "reasonable belief" for
this purpose by some means other than special counsel's tax opinion letter. (See
"- Disclosures and Limitation on Your Use of Special Counsel's Tax Opinion
Letter," above.)
However, the obligation of you and the other investors in your partnership, and
your partnership's material advisors, to disclose your partnership to the IRS as
a reportable transaction, if your partnership is determined by the IRS to be a
reportable transaction in the future, will apply whether or not there actually
is a reportable transaction understatement. Disclosure is made by you and each
of the other investors by attaching IRS Form 8886 "Reportable Transaction
Disclosure Statement" to your personal federal income tax return in each tax
year you continue to be an investor in your partnership and (for the first
filing only) filing a copy of your Form 8886 with the IRS' Office of Tax Shelter
Analysis. The penalty for each failure to properly disclose a reportable
transaction is $10,000 in the case of a natural person, and $50,000 in any other
case. However, if the transaction is a listed transaction, the penalty is
$100,000 in the case of a natural person, and $200,000 in any other case. The
penalty is imposed in addition to any other penalty imposed. If the partnership
in which you invest were ever to be determined to be a reportable transaction,
the managing general partner will advise you of that determination so that you
can begin complying with your reporting obligations to the IRS.
In addition, persons who are treated as material advisors to the partnerships
must maintain a list that identifies each person with respect to whom the
advisor acted as a material advisor for the reportable transaction (which may
include the Participants in a Partnership if the Managing General Partner
determines that either or both of the Partnerships is a reportable transaction
or if either or both of the Partnerships is ultimately found by the IRS or the
courts to be a reportable transaction) and contains any other information
concerning the transaction as may be required by the IRS.
STATE AND LOCAL TAXES
Each partnership will operate in states and localities which may impose a tax on
it or on you and the partnership's other investors based on its assets or its
income. The partnerships also may be subject to state income tax withholding
requirements on their income whether or not their revenues that created the
income are distributed to their investors or not. Deductions and credits,
including the federal marginal well production credit, which may be available to
you for federal income tax purposes, may not be available for state or local
income tax purposes. If the state or locality in which you reside imposes income
taxes on you, you will likely be required under those income tax laws to include
your share of the net income or net loss of the partnership in which you invest
in determining your reportable income for state or local tax purposes in the
jurisdiction in which you reside. To the extent that you pay tax to a state
because of partnership operations within that state, you may be entitled to a
deduction or credit against tax owed to your state of residence with respect to
the same income. Also, due to a partnership's operations in a state or other
local jurisdiction, state or local estate or inheritance taxes may be payable on
the death of an investor in addition to taxes imposed by his own domicile.
You are urged to seek advice based on your particular circumstances from an
independent tax advisor to determine the effect state and local taxes, including
gift and death taxes as well as income taxes, may have on you in connection with
an investment in a partnership.
SEVERANCE AND AD VALOREM (REAL ESTATE) TAXES
Each partnership may incur various ad valorem or severance taxes imposed by
state or local taxing authorities on its natural gas and oil wells and/or
natural gas and oil production from the wells. These taxes would reduce the
amount of the partnership's cash available for distribution to you and its other
investors.
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SOCIAL SECURITY BENEFITS AND SELF-EMPLOYMENT TAX
A limited partner's share of income or loss from a partnership is excluded from
the definition of "net earnings from self-employment." No increased benefits
under the Social Security Act will be earned by limited partners and if any
limited partners are currently receiving Social Security benefits, their shares
of partnership taxable income will not be taken into account in determining any
reduction in benefits because of "excess earnings."
An investor general partner's share of income or loss from a partnership will
constitute "net earnings from self-employment" for these purposes. The ceiling
for social security tax of 12.4% in 2005 is $90,000. There is no ceiling for
medicare tax of 2.9%. Self-employed individuals can deduct one-half of their
self-employment tax.
FARMOUTS
Under a farmout by a partnership, if a property interest, other than an interest
in the drilling unit assigned to the partnership well in question, is earned by
the farmee (anyone other than the partnership) from the farmor (the partnership)
as a result of the farmee drilling or completing the well, then the farmee must
recognize income equal to the fair market value of the outside interest earned,
and the farmor must recognize gain or loss on a deemed sale equal to the
difference between the fair market value of the outside interest and the
farmor's tax basis in the outside interest. Neither the farmor nor the farmee
would have received any cash to pay the tax. The managing general partner has
represented that it will attempt to eliminate or reduce any gain to a
partnership from a farmout, if any. However, if the IRS claims that a farmout by
a partnership results in taxable income to the partnership and its position is
ultimately sustained, the investors in that partnership would be required to
include their share of the resulting taxable income on their personal income tax
returns, even though the partnership and its investors received no cash from the
farmout.
FOREIGN PARTNERS
Each partnership will be required to withhold and pay income tax to the IRS at
the highest rate under the Code applicable to partnership income allocable to
its foreign investors, even if no cash distributions are made to them. In the
event of overwithholding a foreign investor must file a United States tax return
to obtain a refund. Under the Code, for withholding purposes a foreign investor
means an investor who is not a United States person and includes a nonresident
alien individual, a foreign corporation which is subject to U.S. income tax,
except qualified corporations formed under the laws of Guam, American Samoa, the
Northern Mariana Islands, or the Virgin Islands, a foreign partnership, and a
foreign trust or estate, if the investor has not certified to his partnership
the investor's nonforeign status on Form W-9 or any other form permitted under
the Code. Foreign investors are urged to seek advice based on their particular
circumstances from an independent tax advisor regarding the applicability of
these rules and the other tax consequences of an investment in a partnership to
them.
ESTATE AND GIFT TAXATION
There is no federal tax on lifetime or testamentary transfers of property
between spouses. The gift tax annual exclusion in 2005 is $11,000 per donee,
which will be adjusted in subsequent years for inflation. Under the Economic
Growth and Tax Relief Reconciliation Act of 2001 (the "2001 Tax Act"), the
maximum estate and gift tax rate of 47% in 2005 will be reduced in stages to 46%
in 2006 and 45% from 2007 through 2009. Estates of $1.5 million in 2005, which
increases in stages to $2 million in 2006, 2007 and 2008, and $3.5 million in
2009, or less are not subject to federal estate tax to the extent those
exemption amounts were not previously used by the decedent to avoid gift taxes
on lifetime gifts in excess of the annual exclusion amount. Under the 2001 Tax
Act, the federal estate tax will be repealed in 2010, and the maximum gift tax
rate in 2010 will be 35%. In 2011 the federal estate and gift taxes are
scheduled to be reinstated under the rules in effect before the 2001 Tax Act was
enacted.
CHANGES IN THE LAW
Your investment in a partnership may be affected by changes in the tax laws. For
example, in 2003 the top four federal income tax brackets for individuals were
reduced through December 31, 2010, including reducing the top bracket to 35%
from 38.6%. The lower federal income tax rates will reduce to some degree the
amount of taxes you can save by virtue of your share of your partnership's
deductions for intangible drilling costs, depletion and depreciation, and
marginal well production credits, if any. On the other hand, the lower federal
income tax rates also will reduce the amount of federal
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income tax liability incurred by you on your share of the net income of your
partnership. There is no assurance that the federal income tax brackets
discussed above will not be changed again before 2011. You are urged to seek
advice based on your particular circumstances from an independent tax advisor
with respect to the impact of recent legislation on an investment in a
partnership and the status of legislative, regulatory or administrative
developments and proposals and their potential effect on you if you invest in a
partnership.
SUMMARY OF PARTNERSHIP AGREEMENT
The rights and obligations of the managing general partner and you and the other
investors are governed by the form of partnership agreement 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;
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.
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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.
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
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the investors, however, choose not to continue the partnership and select a
substitute managing general partner, then the partnership would terminate and
dissolve which could result in adverse tax and other consequences to you.
Also, subject to a required participation of not less than 1% of each
partnership's revenues, the managing general partner may withdraw a property
interest in the form of a working interest in the partnership's wells equal to
or less than its revenue interest if the withdrawal is:
o to satisfy the bona fide request of its creditors; or
o approved by investors in the partnership whose units equal a majority
of the total units.
RETURN OF SUBSCRIPTION PROCEEDS IF FUNDS ARE NOT INVESTED IN TWELVE MONTHS
Although the managing general partner anticipates that each partnership will
spend all of its subscription proceeds soon after the offering of the
partnership closes, each partnership will have 12 months in which to use or
commit funds to drilling activities. If within the 12-month period the
partnership has not used or committed for use all the subscription proceeds,
then the managing general partner will distribute the remaining subscription
proceeds to you and the other investors in the partnership in accordance with
your subscription proceeds as a return of capital.
SUMMARY OF DRILLING AND OPERATING AGREEMENT
The managing general partner will serve as the operator under the drilling and
operating agreement, Exhibit (II) to the partnership agreement. The operator may
be replaced at any time on 60 days' advance written notice by the managing
general partner acting on behalf of a partnership on the affirmative vote of
investors whose units equal a majority of the total units in the partnership.
You are urged 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.
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;
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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. (See
"Material Federal Income Tax Consequences - Drilling Contracts.")
REPORTS TO INVESTORS
Under the partnership agreement for each partnership you and certain state
securities commissions will be provided the reports and information set forth
below for your partnership, which your partnership will pay as a direct cost.
o Beginning with the calendar year in which your partnership closes, you
will be provided an annual report within 120 days after the close of
the calendar year, and beginning with the following calendar year, a
report within 75 days after the end of the first six months of its
calendar year, containing at least the following information.
o Audited financial statements of the partnership prepared on an
accrual basis in accordance with generally accepted accounting
principles with a reconciliation for information furnished for
income tax purposes. Independent certified public accountants
will audit the financial statements to be included in the annual
report, but semiannual reports will not be audited.
o A summary of the total fees and compensation paid by the
partnership to the managing general partner, the operator, and
their affiliates, including the percentage that the annual
unaccountable, fixed payment reimbursement for administrative
costs bears to annual partnership revenues. In this regard, the
independent certified public accountant will provide written
attestation annually, which will be included in the annual
report, that the method used to make allocations was consistent
with the method described in Section 4.04(a)(2)(c) of the
partnership agreement and that the total amount of costs
allocated did not materially exceed the amounts actually incurred
by the managing general partner.
If the managing general partner subsequently decides to allocate
expenses in a manner different from that described in
Section 4.04(a)(2)(c) of the partnership agreement, then the
change must be reported to you and the other investors with an
explanation of the reason for the change and the basis used for
determining the reasonableness of the new allocation method.
o A description of each prospect owned by the partnership,
including the cost, location, number of acres, and the interest.
o A list of the wells drilled or abandoned by the partnership
indicating:
o whether each of the wells has or has not been completed; and
o a statement of the cost of each well completed or abandoned.
o A description of all farmouts, farmins, and joint ventures.
o A schedule reflecting:
o the total partnership costs;
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o the costs paid by the managing general partner and the costs
paid by the investors;
o the total partnership revenues; and
o the revenues received or credited to the managing general
partner and the revenues received or credited to you and the
other investors.
o On request the managing general partner will provide you the
information specified by Form 10-Q (if that report is required to be
filed with the SEC) within 45 days after the close of each quarterly
fiscal period. Also, this information is available at the SEC website
www.sec.gov.
o By March 15 of each year you will receive the information that is
required for you to file your federal and state income tax returns.
o Beginning with the second calendar year after your partnership closes,
and every year thereafter, you will receive a computation of the
partnership's total natural gas and oil proved reserves and its dollar
value. The reserve computations will be based on engineering reports
prepared by the managing general partner and reviewed by an
independent expert.
PRESENTMENT FEATURE
Beginning with the fifth calendar year after your partnership closes you and the
other investors in your partnership may present your units to the managing
general partner to purchase your units. However, you are not required to offer
your units to the managing general partner, and you may receive a greater return
if you retain your units. The managing general partner will not purchase less
than one unit unless the fractional unit represents your entire interest.
The managing general partner has no obligation 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. Section 1.7704-1(f) the purchase may
not be made by the managing general partner until at least 60 calendar
days after you notify the partnership in writing of your intent to
present your unit; and
o the purchase will not be considered effective until the presentment
price has been paid to you in cash.
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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
o similar matters.
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As of November 15, 2004, approximately 140 units have been presented to the
managing general partner for purchase in its previous 48 limited partnerships.
TRANSFERABILITY OF UNITS
RESTRICTIONS ON TRANSFER IMPOSED BY THE SECURITIES LAWS, THE TAX LAWS AND THE
PARTNERSHIP AGREEMENT
Your ability to sell or otherwise transfer your units in your partnership is
restricted by the securities laws, the tax laws, and the partnership agreement
as described below. Also, the transfer may create negative tax consequences to
you as described in "Material Federal Income Tax Consequences - Disposition of
Units."
First, under the tax laws you will not be able to sell, assign, exchange, or
transfer your unit if it would, in the opinion of counsel for the partnership,
result in the following:
o the termination of your partnership for tax purposes; or
o your partnership being treated as a "publicly-traded" partnership for
tax purposes.
Second, under the partnership agreement transfers are subject to the following
limitations:
o except as provided by operation of law, the partnership will recognize
the transfer of only one or more whole units unless you own less than
a whole unit, in which case your entire fractional interest must be
transferred;
o the costs and expenses associated with the transfer must be paid by
the person transferring the unit;
o the form of transfer must be in a form satisfactory to the managing
general partner; and
o the terms of the transfer must not contravene those of the partnership
agreement.
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 unless there is an opinion of counsel acceptable to the managing
general partner that the registration and qualification under any applicable
federal or state securities laws are not required.
CONDITIONS TO BECOMING A SUBSTITUTE PARTNER
On a transfer unless an assignee becomes a substituted partner in accordance
with the provisions set forth below, he will not be entitled to any of the
rights granted to a partner under the 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.
The conditions to become a substitute partner are as follows:
o the assignor gives the assignee the right;
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o the assignee pays all costs and expenses incurred in connection with
the substitution; and
o the assignee executes and delivers the instruments necessary to
establish that a legal transfer has taken place and to confirm his
agreement to be bound by all terms and provisions of the partnership
agreement.
A substitute partner is entitled to all of the rights of full ownership of the
assigned units, including the right to vote. Each partnership will amend its
records at least once each calendar quarter to effect the substitution of
substituted partners.
PLAN OF DISTRIBUTION
COMMISSIONS
The units in each partnership will be offered on a "best efforts" basis by
Anthem Securities, which is an affiliate of the managing general partner, acting
as dealer-manager 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 this offering in the states of Minnesota
and New Hampshire, and will receive the same compensation as Anthem Securities
for sales in those states. The term "dealer-manager" as used in this prospectus
includes both Anthem Securities, Inc. and Bryan Funding, Inc.
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, Atkinson and Hollander, Ms. Bleichmar and Ms. Black, who are
associated with Anthem Securities, will not make any offers or sales under the
SEC safe harbor from broker/dealer registration provided by SEC Rule 3a4-1
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;
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o a 7% sales commission;
o an up to .5% reimbursement of the selling agent's bona fide
accountable due diligence expenses; and
o a .5% accountable reimbursement for permissible non-cash compensation.
Under Rule 2810 of the NASD Conduct Rules, non-cash compensation means
any form of compensation received in connection with the sale of the
units that is not cash compensation, including but not limited to
merchandise, gifts and prizes, travel expenses, meals and lodging.
Permissible non-cash compensation includes the following:
o an accountable reimbursement for training and education meetings
for associated persons of the selling agents;
o gifts that do not exceed $100 per year and are not preconditioned
on achievement of a sales target;
o an occasional meal, a ticket to a sporting event or the theater,
or comparable entertainment which is neither so frequent nor so
extensive as to raise any question of propriety and is not
preconditioned on achievement of a sales target; and
o contributions to a non-cash compensation arrangement between a
selling agent and its associated persons, provided that neither
the managing general partner nor the dealer-manager directly or
indirectly participates in the selling agent's organization of a
permissible non-cash compensation arrangement.
All of the reimbursement of the selling agents' bona fide accountable due
diligence expenses and generally all of the 7% sales commission will be
reallowed to the selling agents. With respect to the up to .5% reimbursement of
a selling agent's bona fide accountable due diligence expenses, any bill
presented by a selling agent to the dealer-manager for reimbursement of costs
associated with its due diligence activities must be for actual costs, including
overhead, incurred by the selling agent and may not include a profit margin. It
is the responsibility of the managing general partner and the dealer-manager to
ensure compliance with the above guideline. Although the dealer-manager is not
required to obtain an itemized expense statement before paying out due diligence
expenses, any bill for due diligence submitted by the selling agent to the
dealer-manager must be based on the selling agent's actual expenses incurred in
conducting due diligence. If the dealer-manager receives a non-itemized bill for
due diligence that it has reason to question, then it has the obligation to
ensure compliance by requesting an itemized statement to support the bill
submitted by the selling agent. If the due diligence bill cannot be justified,
any excess over actual due diligence expenses that is paid is considered by the
NASD to be undisclosed underwriting compensation and is required to be included
within the 10% compensation guideline under NASD Conduct Rule 2810, and
reflected on the books and records of the selling agent. However, if the selling
agent provides the dealer-manager an itemized bill for actual due diligence
expenses which is in excess of .5%, then the excess over .5% will not be
included within the 10% compensation guideline, but instead will be included
within the 4.5% organization and offering cost guideline under NASD Conduct Rule
2810.
The dealer-manager or managing general partner may make certain non-cash
compensation arrangements with the selling agents and their registered
representatives, which will be included in the accountable reimbursement for
permissible non-cash compensation. The dealer-manager is responsible for
ensuring that all permissible non-cash compensation arrangements comply with
Rule 2810 of the NASD Conduct Rules. For example, payments or reimbursements by
the dealer-manager or the managing general partner may be made in connection
with meetings held by the dealer-manager or the managing general partner for the
purpose of training or education of registered representatives of a selling
agent only if the following conditions are met:
o the registered representative obtains his selling agent's prior
approval to attend the meeting and attendance by the registered
representative is not conditioned by his selling agent on the
achievement of a sales target;
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o the location of the training and education meeting is appropriate to
the purpose of the meeting as defined in NASD Conduct Rule 2810;
o the payment or reimbursement is not applied to the expenses of guests
of the registered representative;
o the payment or reimbursement by the dealer-manager or the managing
general partner is not conditioned by the dealer-manager or the
managing general partner on the achievement of a sales target; and
o the recordkeeping requirements are met.
The dealer-manager will retain any of the accountable reimbursement for
permissible non-cash compensation not reallowed to the selling agents.
The managing general partner is also using the services of wholesalers who are
employed by it or its affiliates and are registered through Anthem Securities.
The wholesalers include four Regional Marketing Directors, Mr. Bruce Bundy, Mr.
Robert Gourlay, Ms. Vicki Burbridge and Mr. Jim O'Mara. Most of the 2.5%
dealer-manager fee will be reallowed to the affiliated wholesalers for
subscriptions obtained through their efforts, which includes expense
reimbursements to them and a salary to Mr. O'Mara in connection with the
offering. The dealer-manager will retain the remainder of the dealer-manager fee
not reallowed to the wholesalers, which may be used for such items as legal fees
associated with underwriting and salaries of dual employees of the
dealer-manager and the managing general partner which are required to be
included in underwriting compensation under NASD Conduct Rule 2810 as determined
jointly by the managing general partner and the dealer-manager.
The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules
and all compensation, including non-cash compensation, to broker/dealers and
wholesalers, regardless of the source, will be limited to 10% of the gross
proceeds of the offering plus the .5% reimbursement for bona fide 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 bona fide accountable due
diligence expenses, and the .5% accountable reimbursement for
permissible non-cash compensation, which will not be paid with respect
to these sales; and
o the subscription price for registered investment advisors and their
clients, and selling agents and their registered representatives and
principals, will be reduced by an amount equal to the 7% sales
commission, which will not be paid with respect to these sales.
No more than 5% of the total units in each partnership may be sold with the
discounts described above.
These investors who pay a reduced price for their units generally will share in
a partnership's costs, revenues, and distributions on the same basis as the
other investors who pay $10,000 per unit as discussed in "Participation in Costs
and Revenues - Allocation and Adjustment Among Investors." Although the managing
general partner and its affiliates may buy up to 5% of the units, they do not
currently anticipate buying any units. If they do buy units, then those units
will not be applied towards the minimum subscription proceeds required for a
partnership to begin operations.
131
After the minimum subscriptions are received in a partnership and the checks
have cleared the banking system, the dealer-manager fee and the sales
commissions will be paid to the dealer-manager and selling agents approximately
every two weeks until the offering closes.
INDEMNIFICATION
The dealer-manager is an underwriter as that term is defined in the 1933 Act and
the sales commissions and dealer-manager fees will be deemed underwriting
compensation. The managing general partner and the dealer-managers have agreed
to indemnify each other, and it is anticipated that the dealer-managers and each
selling agent will agree to indemnify each other against certain liabilities,
including liabilities under the 1933 Act.
SALES MATERIAL
In addition to the prospectus the managing general partner intends to use the
following sales material with the offering of the units:
o a flyer entitled "Atlas America Public #14-2004 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 #14-2004 Program Can Help Achieve an Investor's Tax
Objectives";
o a brochure entitled "Investing in Atlas America Public #14-2004
Program";
o a booklet entitled "Outline of Tax Consequences of Oil and Gas
Drilling Programs";
o a brochure entitled "The Appalachian Basin: A Prime Drilling Location
Which Commands a Premium";
o a brochure entitled "Investment Insights - Tax Time";
o a brochure entitled "Frequently Asked Questions";
o a brochure entitled "AMT - A Little History and Reducing AMT through
Natural Gas Partnerships";
o a brochure entitled "The Drilling Process"; and
o possibly other supplementary materials.
The managing general partner has not authorized the use of other sales material
and the offering of units is made only by means of this prospectus. The sales
material is subject to the following considerations:
o it must be preceded or accompanied by this prospectus;
o it is not complete;
o it does not contain any information which is not consistent with this
prospectus; and
o it should not be considered a part of or incorporated into this
prospectus or the registration statement of which this prospectus is a
part.
In addition, supplementary materials, including prepared presentations for group
meetings, must be submitted to the state administrators before they are used and
their use must either be preceded by or accompanied by a prospectus. Also, all
132
advertisements of, and oral or written invitations to, "seminars" or other group
meetings at which the units are to be described, offered, or sold will clearly
indicate the following:
o that the purpose of the meeting is to offer the units for sale;
o the minimum purchase price of the units;
o the suitability standards to be employed; and
o the name of the person selling the units.
Also, no cash, merchandise, or other items of value may be offered as an
inducement to you or any 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 federal income tax consequences to
individual typical investors in the partnerships. However, the factual
statements in this prospectus are those of the partnerships or the managing
general partner, and counsel has not given any opinions with respect to any of
the tax or other legal aspects of this offering except as expressly set forth
above.
EXPERTS
The financial statements included in this prospectus for the managing general
partner as of and for the years ended September 30, 2004 and 2003 and the
balance sheet for Atlas America Public #14-2005(A) L.P. as of November 30, 2004,
have been audited by Grant Thornton LLP, as of the dates indicated in its
reports which appear elsewhere in this prospectus. These financial statements
have been included in reliance upon the reports of Grant Thornton LLP upon the
authority of such firm as experts in accounting and auditing.
The geologic evaluations of United Energy Development Consultants, Inc., which
is not affiliated with the managing general partner or its affiliates, appearing
in Appendix A to this prospectus for the areas where potential prospects have
been identified for Atlas America Public #14-2005(A) L.P. have 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 evaluations and in the
giving of the evaluations.
The information concerning the prior public partnerships' estimated future net
cash flows from proved reserves presented under "Prior Activities - Table 3
Investor Operating Results-Including Expenses" was reviewed by Wright & Company,
Inc., Brentwood, Tennessee, independent petroleum consultants in reliance on
Wright & Company, Inc. as an expert in petroleum consulting.
LITIGATION
The managing general partner knows of no litigation pending or threatened to
which the managing general partner or the partnerships are subject or may be a
party, which it believes would have a material adverse effect on the
partnerships or their business, and no such proceedings are known to be
contemplated by governmental authorities or other parties.
133
FINANCIAL INFORMATION CONCERNING THE MANAGING
GENERAL PARTNER AND ATLAS AMERICA PUBLIC #14-2005(A) L.P.
Financial information concerning the managing general partner and the first
partnership in the program, Atlas America Public #14-2005(A) L.P., which is the
only partnership that has been formed, 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.
134
Audit report
Atlas America Public #14-2005(A) L.P.
(A Delaware Limited Partnership)
November 30, 2004
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners
Atlas America Public #14-2005(A) L.P.
We have audited the accompanying balance sheet of Atlas America Public
#14-2005(A) L.P. (a Delaware Limited Partnership) as of November 30, 2004. This
financial statement is the responsibility of the Partnership's management. Our
responsibility is to express an opinion on this financial statement based on our
audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statement is free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statement. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statement referred to above presents fairly, in
all material respects, the financial position of Atlas America Public
#14-2005(A) L.P. as of November 30, 2004, in conformity with accounting
principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
December 16, 2004
F-2
Atlas America Public #14-2005(A) L.P.
(A Delaware Limited Partnership)
BALANCE SHEET
November 30, 2004
ASSETS
Cash $ 100
=========
PARTNERS' CAPITAL
Partners' capital: $ 100
=========
The accompanying notes are an integral part of this financial statement.
F-3
Atlas America Public #14-2005(A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT
November 30, 2004
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
Atlas America Public #14-2005(A) L.P. (the "Partnership") is a Delaware
limited partnership in which Atlas Resources, Inc. ("Atlas Resources")
of Pittsburgh, Pennsylvania (a second-tier wholly-owned subsidiary of
Atlas America, Inc., a publicly traded company, which is a second-tier
subsidiary of Resource America, Inc., a publicly traded company) will
be Managing General Partner and Operator, and subscribers to Units will
be either Limited Partners or Investor General Partners depending upon
their election.
The Partnerships will be funded to drill development wells which are
proposed to be located primarily in the Appalachian Basin located in
western Pennsylvania, eastern and southern Ohio and western New York.
Subscriptions at a cost of $10,000 per unit, subject to discounts for
certain investors, generally will be sold using wholesalers and through
broker-dealers including Anthem Securities, Inc., an affiliated
company, which will receive, on each unit sold to an investor, a 2.5%
dealer-manager fee, a 7% sales commission, a .5% accountable
reimbursement for permissible non-cash compensation, and an up to .5%
reimbursement of bona fide accountable due diligence expenses.
Commencement of Partnership operations is subject to the receipt of
minimum Partnership subscriptions of $2,000,000 (up to a maximum of
$72,430,500 ) by December 31, 2005.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF ACCOUNTING
-------------------
The Partnership will prepare its financial statements in accordance
with accounting principles generally accepted in the United States of
America.
OIL AND GAS PROPERTIES
----------------------
The Partnership will use the successful efforts method of accounting
for oil and gas producing activities. Costs to acquire mineral
interests in oil and gas properties and to drill and equip wells will
be capitalized. Depreciation and depletion will be computed on a
field-by-field basis using the unit-of-production method based on
periodic estimates of oil and gas reserves.
Undeveloped leaseholds and proved properties will be assessed for
impairment periodically or whenever events or circumstances indicate
that the carrying amount of these assets may not be recoverable. Proved
properties will be assessed based on estimates of future cash flows.
F-4
Atlas America Public #14-2005(A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT - CONTINUED
November 30, 2004
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
USE OF ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the amounts
reported in the financial statements and accompanying notes. Actual
results could differ from those estimates.
3. FEDERAL INCOME TAXES
The Partnership will not be treated as a taxable entity for federal
income tax purposes. Any item of income, gain, loss, deduction or
credit would flow through to the partners as though each partner has
incurred such item directly. As a result, each partner must take into
account their pro rata share under the partnership agreement of all
items of partnership income and deductions in computing their federal
income tax liability.
4. PARTICIPATION IN REVENUES AND COSTS
The Managing General Partner and the investor partners will participate
in revenues and costs in the following manner:
MANAGING
GENERAL INVESTOR
PARTNER PARTNERS
------- --------
PARTNERSHIP COSTS
Organization and offering costs............................................100% 0%
Lease costs................................................................100% 0%
Intangible drilling costs....................................................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 the investor partners
exceeds an amount equal to 10% of the subscription proceeds of investor
partners in the partnership, then the excess will be charged to the
managing general partner. Equipment proceeds, if any, will be credited
in the same percentage in which the equipment costs were charged.
F-5
Atlas America Public #14-2005(A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT - CONTINUED
November 30, 2004
4. PARTICIPATION IN REVENUES AND COSTS -CONTINUED
(2) These costs will be charged to the parties in the same ratio as the
related production revenues are being credited. These costs also
include plugging and abandonment costs of the wells after the wells
have been drilled and produced.
(3) Interest earned on subscription proceeds before the final closing of
the partnership will be credited to their account and paid not later
than the partnership's first cash distributions from operations. After
the final closing of the partnership and until the subscription
proceeds are invested in the partnership's natural gas and oil
operations any interest income from temporary investments will be
allocated pro rata to the investor partners providing the subscription
proceeds. All other interest income, including interest earned on the
deposit of operating revenues, will be credited as natural gas and oil
production revenues are credited.
(4) The managing general partner and the investor partners in the
partnership will share in all of the partnership's other revenues in
the same percentage as their respective capital contributions 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 investor partners 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 in
note 7.
5. TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES
The Partnership intends to enter into the following significant
transactions with Atlas Resources and its affiliates as provided under
the Partnership agreement:
The partnership will enter into a drilling and operating
agreement with Atlas Resources to drill and complete all of the
Partnership wells at cost plus 15%. The cost of the wells
includes reimbursement to Atlas Resources of the investor
partners' share of its general and administrative overhead cost
(approximately $12,690 per well, which will be proportionately
reduced if the Partnership's working interest in a well is less
than 100 %) and all ordinary and actual costs of drilling,
testing and completing the wells.
Atlas Resources will receive an unaccountable, fixed payment
reimbursement for their administrative costs at $75 per well per
month, which will be proportionately reduced if the
partnership's working interest in a well is less than 100%.
Atlas Resources will receive well supervision fees for operating
and maintaining the wells during producing operations at a
competitive rate (currently the competitive rate is $285 per
well per month in the primary and secondary drilling areas). The
well supervision fees will be proportionately reduced if the
partnership's working interest in a well is less than 100%.
F-6
Atlas America Public #14-2005(A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT - CONTINUED
November 30, 2004
5. TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES - CONT.
Atlas Resources will charge the partnership a fee for gathering and
transportation at a competitive rate (currently in the range of $.29 to
$.70 per MCF in the primary and secondary drilling areas).
Atlas Resources will contribute all the undeveloped leases necessary to
cover each of the partnership's prospects and will receive a credit for
its capital account in the partnership equal to the cost of the leases
(approximately $5,232 per prospect which will be proportionately
reduced if the Partnership's working interest is the prospect is less
than 100%).
As the Managing General Partner, Atlas Resources will perform all
administrative and management functions for the partnership including
billing and collecting revenues and paying expenses. Atlas Resources
will be reimbursed for all direct costs expended on behalf of the
partnership.
6. PURCHASE COMMITMENT
Subject to certain conditions, investor partners may present their
interests beginning with the fifth calendar year after the partnership
closes for purchase by the Managing General Partner. The Managing
General Partner is not obligated to purchase more than 5% of the units
in any calendar year. In the event that the Managing General Partner is
unable to obtain the necessary funds, the Managing General Partner may
suspend its purchase obligation.
7. SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S
NET REVENUE SHARE
The Managing General Partner will subordinate up to 50% of its share of
production revenues of the Partnership, net of related operating costs,
direct costs, administrative costs and all other costs not specifically
allocated to the receipt by the other partners of cash distributions
from the Partnership equal to at least 10% per unit, based on $10,000
per unit regardless of the actual price paid, determined on a
cumulative basis, in each of the first five 12-month periods beginning
with the Partnership's first cash distributions from operations.
8. INDEMNIFICATION
In order to limit the potential liability of the investor general
partners, Atlas Resources has agreed to indemnify each investor general
partner from any liability incurred which exceeds such partner's share
of Partnership net assets and insurance proceeds.
The managing general partner's indemnification obligation, however,
will not eliminate an investor general partner's 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.
F-7
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
ATLAS RESOURCES, INC.
We have audited the accompanying consolidated balance sheets of ATLAS RESOURCES,
INC. (a Pennsylvania corporation) and subsidiary as of September 30, 2004 and
2003, and the related consolidated statements of income, comprehensive income,
changes in stockholder's equity, and cash flows for the years then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with Standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of ATLAS RESOURCES,
INC. and subsidiary as of September 30, 2004 and 2003, and the consolidated
results of their operations and cash flows for the years then ended, in
conformity with accounting principles generally accepted in the United States of
America.
As discussed in Note 2 to the consolidated financial statements, effective
October 1, 2002, the Company adopted Statement of Financial Accounting Standards
No. 143, Accounting for Asset Retirement Obligations, and changed its method of
accounting for its plugging and abandonment liability related to its oil and gas
wells and associated pipelines and equipment.
/s/ Grant Thornton LLP
Cleveland, Ohio
November 22, 2004
F-8
ATLAS RESOURCES , INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2004 AND 2003
2004 2003
--------- ---------
(in thousands, except share
data)
ASSETS
Current assets:
Cash and cash equivalents........................................................... $ 242 $ 4,702
Accounts receivable ................................................................ 7,080 4,895
Prepaid expenses.................................................................... 1,488 532
--------- ---------
Total current assets.............................................................. 8,810 10,129
Property and equipment:
Oil and gas properties and equipment (successful efforts)........................... 120,506 85,199
Buildings and land.................................................................. 2,947 2,830
Other............................................................................... 368 414
--------- ---------
123,821 88,443
Less - accumulated depreciation, depletion, and amortization........................... (23,654) (16,388)
--------- ---------
Net property and equipment.......................................................... 100,167 72,055
Goodwill (net of accumulated amortization of $2,320)................................... 20,868 20,868
Intangible assets (net of accumulated amortization of $2,909 and $2,431)............... 3,444 3,922
--------- ---------
$ 133,289 $ 106,974
========= =========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt................................................... $ 56 $ 56
Accounts payable.................................................................... 5,304 6,223
Liabilities associated with drilling contracts...................................... 29,375 18,609
Accrued liabilities................................................................. 3,174 4,423
Advances and note from parent....................................................... 66,725 51,150
--------- ---------
Total current liabilities......................................................... 104,634 80,461
Asset retirement obligation............................................................ 1,910 701
Long-term debt......................................................................... 82 138
Stockholder's equity:
Common stock, stated at $10 per share;
500 authorized shares; 200 shares issued and outstanding.......................... 2 2
Additional paid-in capital.......................................................... 16,505 16,505
Retained earnings................................................................... 10,156 9,167
--------- ---------
Total stockholder's equity........................................................ 26,663 25,674
--------- ---------
$ 133,289 $ 106,974
========= =========
See accompanying notes to consolidated financial statements
F-9
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2004 AND 2003
2004 2003
--------- --------
(in thousands)
REVENUES
Well Drilling................................................................ $ 86,880 $ 52,879
Gas and Oil Production....................................................... 23,098 16,091
Well Services................................................................ 4,137 3,507
Transportation............................................................... 2,476 2,507
Other........................................................................ 44 130
--------- --------
116,635 75,114
COSTS AND EXPENSES
Well Drilling................................................................ 75,548 45,982
Gas and oil production and exploration....................................... 2,580 2,312
Well Services................................................................ 1,648 923
Non-direct................................................................... 24,831 15,985
Depreciation, depletion and amortization..................................... 8,197 6,229
Interest..................................................................... 2,625 2,375
--------- --------
115,429 73,806
--------- --------
Income from operations before income taxes................................... 1,206 1,308
Provision for income taxes................................................... 217 275
--------- --------
Income before cumulative effect of accounting change......................... 989 1,033
Cumulative effect of change in accounting principle,
net of income taxes of $65................................................ - 120
--------- --------
Net income................................................................... $ 989 $ 1,153
========= ========
See accompanying notes to consolidated financial statements
F-10
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2004 AND 2003
2004 2003
------ -------
(in thousands)
Net income................................................................................... $ 989 $ 1,153
Other comprehensive income (loss):
Unrealized holding losses on natural gas futures arising during the period , net of taxes of
$245.................................................................................... - (541)
Less: reclassification adjustment for losses realized in net income, net of taxes of
$355.................................................................................... - 753
------ -------
- 212
------ -------
Comprehensive income.......................................................................... $ 989 $ 1,365
====== =======
See accompanying notes to consolidated financial statements
F-11
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
YEARS ENDED SEPTEMBER 30, 2004 AND 2003
(in thousands, except share data)
Accumulated
Common Stock Additional Other Totals
-------------------------- Paid-In Comprehensive Retained Stockholder's
Shares Amount Capital Income (Loss) Earnings Equity
-------------------------------------------------------------------------------------
Balance, October 1, 2002............. 200 $ 2 $ 16,505 $ (212) $ 8,014 $ 24,309
Net unrealized gain.................. - - - 212 - 212
Net income........................... - - - 1,153 1,153
-
- ----------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2003.......... 200 2 16,505 - 9,167 25,674
Net income........................... - - - - 989 989
- ----------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2004 200 $ 2 $ 16,505 $ - $ 10,156 $ 26,663
See accompanying notes to consolidated financial statements
F-12
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2004 AND 2003
2004 2003
-------- --------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................................. $ 989 $ 1,153
Adjustments to reconcile net income to net cash provided by operating
activities:
Cumulative effect of change in accounting principle..................... - (120)
Depreciation, depletion and amortization................................ 8,197 6,229
Management fees and interest on intercompany note due to parent......... 32,809 15,074
Gain on sale of assets.................................................. (11) (19)
Change in operating assets and liabilities.............................. 4,016 17,637
-------- --------
Net cash provided by operating activities.................................. 46,000 39,954
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures....................................................... (33,051) (21,106)
Proceeds from sale of assets............................................... 33 19
-------- --------
Net cash used in investing activities...................................... (33,018) (21,087)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings........................................... (56) (34)
Net payments to Parent..................................................... (17,386) (14,829)
-------- --------
Net cash used in financing activities...................................... (17,442) (14,863)
-------- --------
Increase (decrease) in cash and cash equivalents........................... (4,460) 4,004
Cash and cash equivalents at beginning of year............................. 4,702 698
-------- --------
Cash and cash equivalents at end of year................................... $ 242 $ 4,702
======== ========
See accompanying notes to consolidated financial statements
F-13
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF OPERATIONS
Atlas Resources, Inc. (the "Company"), a Pennsylvania corporation, and
its subsidiary, ARD Investments, are engaged in the exploration for development
and production of natural gas and oil primarily in the Appalachian Basin Area.
In addition, the Company performs contract drilling and well operation services.
The Company is a second-tier wholly-owned subsidiary of Atlas America,
Inc. (Atlas), a publicly traded company trading under the symbol ATLS on the
NASDAQ System. The Company's operations are dependent upon the resources and
services provided by Atlas. The Company finances a substantial portion of its
drilling activities through drilling partnerships it sponsors and typically acts
as the managing general partner of these partnerships and has a material
partnership interest.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
RECLASSIFICATIONS
Certain reclassifications have been made to the fiscal 2003
consolidated financial statements to conform to the fiscal 2004 presentation.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiary. The Company also owns individual
interests in the assets, and is separately liable for its share of the
liabilities of energy partnerships, whose activities include only exploration
and production activities. In accordance with established practice in the oil
and gas industry, the Company includes in its consolidated financial statements
its pro-rata share of assets, liabilities, income and costs and expenses of the
energy partnerships in which the Company has an interest. All material
intercompany transactions have been eliminated.
USE OF ESTIMATES
Preparation of the consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the consolidated financial statements and the
reported amounts of revenues and costs and expenses during the reporting period.
Actual results could differ from these estimates.
IMPAIRMENT OF LONG LIVED ASSETS
The Company reviews its long-lived assets for impairment whenever events or
circumstances indicate that the carrying amount of an asset may not be
recoverable. If it is determined that an asset's estimated future cash flows
will not be sufficient to recover its carrying amount, an impairment charge will
be recorded to reduce the carrying amount for that asset to its estimated fair
value.
F-14
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
COMPREHENSIVE INCOME
Comprehensive income includes net income and all other changes in the
equity of a business during a period from transactions and other events and
circumstances from non-owner sources. These changes, other than net income, are
referred to as "other comprehensive income" and for the Company only include
changes in the fair value, net of taxes, of unrealized hedging gains and losses.
PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
At September 30,
2004 2003
--------- ---------
(in thousands)
Mineral interest in properties:
Proved properties........................................................ $ 1 $ 1
Unproved properties...................................................... 463 25
Wells and related equipment.................................................. 118,942 84,435
Support equipment............................................................ 1,100 738
Other........................................................................ 3,315 3,244
--------- ---------
123,821 88,443
Accumulated depreciation, depletion, amortization and valuation allowances:
Oil and gas properties................................................... (22,623) (15,834)
Other (1,031) (554)
--------- ---------
(23,654) (16,388)
--------- ---------
$ 100,167 $ 72,055
========= =========
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting.
Accordingly, property acquisition costs, costs of successful exploratory wells,
all development costs, and the cost of support equipment and facilities are
capitalized. Costs of unsuccessful exploratory wells are expensed when such
wells are determined to be nonproductive or, if this determination cannot be
made, within twelve months of completion of drilling. The costs associated with
drilling and equipping wells not yet completed are capitalized as uncompleted
wells, equipment, and facilities. Geological and geophysical costs and the costs
of carrying and retaining undeveloped properties, including delay rentals, are
expensed as incurred. Production costs, overhead and all exploration costs other
than the costs of exploratory drilling are charged to expense as incurred.
The Company assesses unproved and proved properties
periodically to determine whether there has been a decline in value and, if a
decline is indicated, a loss is recognized. The assessment of significant
unproved properties for impairment is on a property-by-property basis. The
Company considers whether a dry hole has been drilled on a portion of, or in
close proximity to, the property, the Company's intentions of further drilling,
the remaining lease term of the property, and its experience in similar fields
in close proximity. The Company assesses unproved properties whose costs are
individually insignificant in the aggregate. This assessment includes
considering the Company's experience with similar situations, the primary lease
terms, the average holding period of unproved properties and the relative
proportion of such properties on which proved reserves have been found in the
past.
F-15
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
OIL AND GAS PROPERTIES - (CONTINUED)
The Company compares the carrying value of its proved developed gas and
oil producing properties to the estimated future cash flow from such properties
in order to determine whether their carrying values should be reduced. No
adjustment was necessary during the fiscal years ended September 30, 2004 and
2003.
Upon the sale or retirement of a complete unit of a proved property,
the cost and related accumulated depletion are eliminated from the property
accounts, and the resultant gain or loss is recognized in the statement of
operations. Upon the sale of an entire interest in an unproved property where
the property had been assessed for impairment individually, a gain or loss is
recognized in the statement of operations. If a partial interest in either a
proved or unproved property is sold, any funds received are accounted for as a
reduction of the cost in the interest retained.
DEPRECIATION, DEPLETION AND AMORTIZATION
The Company amortizes proved gas and oil properties, which include
intangible drilling and development costs, tangible well equipment and leasehold
costs, on the unit-of-production method using the ratio of current production to
the estimated aggregate proved developed gas and oil reserves.
The Company computes depreciation on property and equipment, other than
gas and oil properties, using the straight-line method over the estimated
economic lives, which range from three to 39 years.
ASSET RETIREMENT OBLIGATIONS
Effective October 1, 2002, the Company adopted SFAS 143 which requires
the Company to recognize an estimated liability for the plugging and abandonment
of its oil and gas wells and associated pipelines and equipment. Under SFAS 143,
the Company must currently recognize a liability for future asset retirement
obligations if a reasonable estimate of the fair value of that liability can be
made. The present values of the expected asset retirement costs are capitalized
as part of the carrying amount of the long-lived asset. SFAS 143 requires the
Company to consider estimated salvage value in the calculation of depletion,
depreciation and amortization. Consistent with industry practice, historically
the Company had determined the cost of plugging and abandonment on its oil and
gas properties would be offset by salvage values received. The adoption of SFAS
143 resulted in (i) an increase of total liabilities because retirement
obligations are required to be recognized, (ii) an increase in the recognized
cost of assets because the retirement costs are added to the carrying amount of
the long-lived assets and (iii) a decrease in depletion expense, because the
estimated salvage values are now considered in the depletion calculation.
The estimated liability is based on historical experience in plugging
and abandoning wells, estimated remaining lives of those wells based on reserves
estimates, external estimates as to the cost to plug and abandon the wells in
the future, and federal and state regulatory requirements. The liability is
discounted using an assumed credit-adjusted risk-free interest rate. Revisions
to the liability could occur due to changes in estimates of plugging and
abandonment costs or remaining lives of the wells, or if federal or state
regulators enact new plugging and abandonment requirements.
The adoption of SFAS 143 as of October 1, 2002 resulted in a cumulative
effect adjustment of $185,000 before taxes to record (i) a $558,000 increase in
the carrying values of proved properties, (ii) a $308,000 decrease in
accumulated depletion and (iii) a $681,000 increase in non-current plugging and
abandonment liabilities.
F-16
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
The Company has no assets legally restricted for purposes of settling
asset retirement obligations. Except for the item previously referenced, the
Company has determined that there are no other material retirement obligations
associated with tangible long-lived assets.
A reconciliation of the Company's liability for well plugging and
abandonment costs for the years ended September 30, 2004 and 2003 is as follows
(in thousands):
2004 2003
---- ----
Asset retirement obligations, beginning of year ........... $ 701 $ -
Adoption of SFAS 143....................................... - 681
Liabilities incurred....................................... 1,212 93
Liabilities settled........................................ (40) (53)
Revision in estimates...................................... (60) (66)
Accretion expense.......................................... 97 46
------- ------
Asset retirement obligations, end of year.................. $ 1,910 $ 701
======= ======
The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of income and the asset
retirement obligation liabilities are classified as long-term liabilities in the
Company's consolidated balance sheet.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company used the following methods and assumptions in estimating
the fair value of each class of financial instruments for which it is
practicable to estimate fair value.
For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments.
For long-term debt, the carrying value approximates fair value because
interest rates approximate current market rates.
CONCENTRATION OF CREDIT RISK
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of periodic temporary
investments of cash. The Company places its temporary cash investments in
high-quality short-term money market instruments and deposits with high-quality
financial institutions and brokerage firms. At September 30, 2004, the Company
had $242,000 in deposits at various banks, of which $132,000 is over the
insurance limit of the Federal Deposit Insurance Corporation. No losses have
been experienced on such investments.
F-17
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Company has
established procedures for the ongoing evaluation of its operations, to identify
potential environmental exposures and to comply with regulatory policies and
procedures.
The Company accounts for environmental contingencies in accordance with
SFAS No. 5 "Accounting for Contingencies." Environmental expenditures that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable, and the costs can be reasonably estimated. The Company maintains
insurance that may cover in whole or in part certain environmental expenditures.
For the two years ended September 30, 2004, the Company had no environmental
matters requiring specific disclosure or requiring recording of a liability.
REVENUE RECOGNITION
The Company conducts certain energy activities through, and a portion
of its revenues are attributable to, sponsored energy limited partnerships.
These energy partnerships raise capital from investors to drill gas and oil
wells. The income from the Company's general partner interest is
recorded when the gas and oil are sold by a partnership.
The Company contracts with the energy partnerships to drill partnership
wells. The contracts require that the energy partnerships must pay the Company
the full contract price upon execution. The income from a drilling contract is
recognized as the services are performed. The contracts are typically completed
in less than 90 days. The Company classifies the difference between the contract
payments it has received and the revenue earned as a current liability, included
in liabilities associated with drilling contracts.
The Company recognizes transportation revenues at the time the natural
gas is delivered to the purchaser.
The Company recognizes well services revenues at the time the services
are performed.
The Company is entitled to receive well operating fees according to the
respective partnership agreements. The Company recognizes such fees as income
when earned and includes them in well services revenues.
The Company retains a working interest and/or overriding royalty in the
wells it contracts to drill on behalf of its sponsored energy partnership. The
Company records the income from the working interests and overriding royalties
when the gas and oil are sold.
F-18
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
SUPPLEMENTAL CASH FLOW INFORMATION
The Company considers temporary investments with maturity at the date
of acquisition of 90 days or less to be cash equivalents.
Supplemental disclosure of cash flow information:
Years Ended September 30,
-------------------------
2004 2003
---------- ----------
(in thousands)
CASH PAID DURING THE YEARS FOR:
Interest..................................................................... $ 3 $ 110
Income taxes (refunded) paid................................................. $ (223) $ 363
NON-CASH ACTIVITIES INCLUDE THE FOLLOWING:
Fixed asset purchases financed with long-term debt........................... $ - $ 228
INCOME TAXES
The Company is included in the consolidated federal income tax return
of RAI. Income taxes are presented as if the Company had filed a return on a
separate company basis utilizing its calculated effective rate of 18% and 21%
for fiscal years 2004 and 2003 respectively. The Company's effective tax rate is
lower than the federal statutory rate due to the benefit of percentage depletion
and fuel credits. Deferred taxes, which are included in Advances from Parent,
reflect the tax effect of temporary differences between the tax basis of the
Company's assets and liabilities and the amounts reported in the financial
statements. Separate company state tax returns are filed in those states in
which the Company is registered to do business.
NOTE 3 -- OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL
INTANGIBLE ASSETS
Intangible assets consist of partnership management and operating
contracts acquired through acquisitions and recorded at fair value on their
acquisition dates. The Company amortizes contracts acquired on a declining
balance method, over their respective estimated lives, ranging from five to
thirteen years. Amortization expense for the years ended September 30, 2004 and
2003 was approximately $478,000. The estimated amortization expense for each of
the next five fiscal years is $478,000.
GOODWILL
The Company adopted SFAS No. 142 ("SFAS 142") "Goodwill and Other
Intangible Assets," which requires that goodwill no longer be amortized, but
instead evaluated for impairment at least annually. The Company performs an
annual evaluation and will reflect the impairment of goodwill, if any, in
operating income in the statement of operations in the period in which the
impairment is indicated.
F-19
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The Company conducts certain energy activities through, and a
substantial portion of its revenues are attributable to energy limited
partnerships ("Partnerships"). The Company serves as general partner of the
Partnerships and assumes customary rights and obligations for the Partnerships.
As the general partner, the Company is liable for Partnership liabilities and
can be liable to limited partners if it breaches its responsibilities with
respect to the operations of the Partnerships. The Company is entitled to
receive management fees, reimbursement for administrative costs incurred, and to
share in the Partnerships' revenue and costs and expenses according to the
respective Partnership agreements.
Advances and note from Parent represents amounts owed for advances and
transactions in the normal course of business and a note payable to the parent.
Both the note and the advances, which have no repayment terms, are subordinated
to any third-party debt. The note, which together with any unpaid interest is
due on demand by the Parent, has a face amount of $15.0 million and accrues
interest at an annual rate of 9.50% on any unpaid balances. Interest expense
related to the note, which is being deferred, was $2.1 million and $1.9 million
for the years ended September 30, 2004 and 2003. The advances have no repayment
terms, therefore, the Company has classified the amounts due the Parent as a
current liability on its Consolidated Balance Sheets.
The Company is dependent on it's Parent for management and
administrative functions and financing for its capital expenditures. The Company
pays a management fee to its Parent for management and administrative services,
which amounted to $23.7 million and $13.1 million for the years ended September
30, 2004 and 2003, respectively.
NOTE 5 - DEBT
At September 30,
--------------------
2004 2003
----- -----
(in thousands)
Long-term debt..................................... $ 138 $ 194
Less current portion............................... (56) (56)
----- -----
$ 82 $ 138
===== =====
F-20
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 5 - DEBT - (CONTINUED)
Future annual debt principal payments are as follows: (in thousands):
2005............................. $ 56
2006............................. 56
2007............................. 26
During the fiscal year ended September 30, 2003, the Company entered
into two loans through General Motors Acceptance Corporation to finance the
purchase of ten trucks used in its well drilling and oil and gas production
activities. One loan has a principal amount of $115,378 and bears an annual
interest rate of 2.9%. The second loan has a principal amount of $113,046 and
bears an annual interest rate of 1.9%. Both loans had an original term of 48
months.
NOTE 6 - COMMITMENTS AND CONTINGENCIES
The Company is the managing general partner of various energy
partnerships, and has agreed to indemnify each investor partner from any
liability that exceeds such partner's share of partnership assets. Subject to
certain conditions, investor partners in certain energy partnerships have the
right to present their interests for purchase by the Company, as managing
general partner. The Company is not obligated to purchase more than 5% to 10% of
the units in any calendar year. Based on past experience, the Company believes
that any liability incurred would not be material.
The Company may be required to subordinate a part of its net
partnership revenues to the receipt by investor partners of cash distributions
from the energy partnerships equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.
The Parent may draw from its revolving credit facility on behalf of
the Company. In July 2002, the Company's parent entered into a $75.0 million
credit facility led by Wachovia Bank, which has a current borrowing base of
$75.0 million. The facility permits draws based on the remaining proved
developed non-producing and proved undeveloped natural gas and oil reserves
attributable to the Parent's wells and the projected fees and revenues from
operation of the wells and the administration of the energy partnerships. Up to
$10.0 million of the facility may be in the form of standby letters of credit.
The facility is secured by the Parent's assets, including those of the Company.
The revolving credit facility has a term ending in March 2007, when all
outstanding borrowings must be repaid, and bears interest at one of two rates
(elected at the borrower's option) which increase as the amount outstanding
under the facility increases: (i) Wachovia prime rate plus between 25 to 75
basis points, or (ii) LIBOR plus between 175 and 225 basis points. At September
30, 2004 and 2003, $26.7 million and $32.3 million, respectively, were
outstanding under this facility, including $1.7 million and $1.3 million at
September 30, 2004 and 2003 under letters of credit. The interest rates ranged
from 3.69% to 5.0% at September 30, 2004. The Company had no amounts due under
this facility at September 30, 2004 and 2003 for borrowings on its behalf.
The Company is a party to various routine legal proceedings arising out
of the ordinary course of its business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on the Company's financial position or results of operations.
F-21
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 7 - HEDGING ACTIVITIES
The Company from time to time enters into natural gas futures and
option contracts to hedge its exposure to changes in natural gas prices. At any
point in time, such contracts may include regulated New York Mercantile Exchange
("NYMEX") futures and options contracts and non-regulated over-the-counter
futures contracts with qualified counterparties. NYMEX contracts are generally
settled with offsetting positions, but may be settled by the delivery of natural
gas.
The Company formally documents all relationships between hedging
instruments and the items being hedged, including the Company's risk management
objective and strategy for undertaking the hedging transactions. This includes
matching the natural gas futures and options contracts to the forecasted
transactions. The Company assesses, both at the inception of the hedge and on an
ongoing basis, whether the derivatives are highly effective in offsetting
changes in the fair value of hedged items. Historically these contracts have
qualified and been designated as cash flow hedges and recorded at their fair
values. Gains or losses on future contracts are determined as the difference
between the contract price and a reference price, generally prices on NYMEX.
Such gains and losses are charged or credited to accumulated other comprehensive
income (loss) and recognized as a component of sales revenue in the month the
hedged gas is sold. If it were to be determined that a derivative is not highly
effective as a hedge due to the loss of correlation between changes in gas
reference prices under a hedging instrument and actual gas prices, the Company
would discontinue hedge accounting for the derivative and subsequent changes in
its fair value would be recognized immediately into earnings.
At September 30, 2004 and 2003, the Company had no open natural gas
futures contracts related to natural gas sales and accordingly, had no
unrealized loss or gain related to such contracts at those dates. The Company
recognized a loss of $1.1 million on settled contracts covering natural gas
production for the year ended September 30, 2003. The Company recognized no
gains or losses during the periods ended September 30, 2004 and September 30,
2003 for hedge ineffectiveness or from the discontinuance of cash flow hedges.
Although hedging provides the Company some protection against falling
prices, these activities could also reduce the potential benefits of price
increases, depending upon the instrument.
NOTE 8 - MAJOR CUSTOMERS
The Company's natural gas is sold under contract to various purchasers.
For the years ended September 30, 2004 and 2003, gas sales to First Energy
Solutions Corporation accounted for 10% and 15%, respectively, of total
revenues.
F-22
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION
Results of operations from oil and gas producing activities:
Years Ended September 30,
------------------------
2004 2003
-------- ---------
(in thousands)
Revenues..................................................................... $ 23,098 $ 16,091
Production costs............................................................. (2,107) (1,992)
Exploration expenses......................................................... (473) (320)
Depreciation, depletion and amortization..................................... (7,445) (5,605)
Income taxes................................................................. (4,256) (2,609)
-------- ---------
Results of operations from oil and gas producing activities.................. $ 8,817 $ 5,565
-------- ---------
Capitalized Costs Related to Oil and Gas Producing Activities. The
components of capitalized costs related to the Company's oil and gas producing
activities are as follows:
At September 30,
------------------------
2004 2003
-------- ---------
(in thousands)
Proved properties............................................................ $ 1 $ 1
Unproved properties.......................................................... 463 25
Wells and related equipment and facilities................................... 118,942 84,435
Support equipment and facilities............................................. 1,100 738
-------- ---------
120,506 85,199
Accumulated depreciation, depletion, amortization and
valuation allowances....................................................... (22,623) (15,834)
-------- ---------
Net capitalized costs................................................... $ 97,883 $ 69,365
-------- ---------
Costs Incurred in Oil and Gas Producing Activities. The costs incurred
by the Company in its oil and gas activities during the periods indicated are as
follows:
Years Ended September 30,
------------------------
2004 2003
-------- ---------
(in thousands)
Property acquisition costs:
Unproved properties........................................................ $ 438 $ -
Proved properties.......................................................... $ - $ -
Exploration costs............................................................ $ 473 $ 320
Development costs............................................................ $ 32,766 $ 24,588
The development costs above for the years ended September 30, 2004 and
2003 were substantially all incurred for the development of proved undeveloped
properties.
F-23
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
Oil and Gas Reserve Information (Unaudited). The estimates of the
Company's proved and unproved gas reserves are based upon evaluations made by
management and verified by Wright & Company, Inc., an independent petroleum
engineering firm, as of September 30, 2004 and 2003. All reserves are located
within the United States. Reserves are estimated in accordance with guidelines
established by the Securities and Exchange Commission and the Financial
Accounting Standards Board which require that reserve estimates be prepared
under existing economic and operating conditions with no provisions for price
and cost escalation except by contractual arrangements.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e. prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
o Reservoirs are considered proved if economic feasibility is
supported by either actual production or conclusive formation tests.
The area of a reservoir considered proved includes (a) that portion
delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any; and (b) the immediately adjoining portions not yet
drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower
proved limit of the reservoir.
o Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included
in the "proved" classification when successful testing by a pilot
project, or the operation of an installed program in the reservoir,
provides support for the engineering analysis on which the project
or program was based.
o Estimates of proved reserves do not include the following: (a) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reservoirs"; (b) crude oil,
natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics or economic factors; (c) crude oil,
natural gas and natural gas liquids, that may occur in undrilled
prospects; and (d) crude oil and natural gas, and natural gas
liquids, that may be recovered from oil shales, coal, gilsonite and
other such sources.
Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operation
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
There are numerous uncertainties inherent in estimating quantities of
proven reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates only
and should not be construed as being exact. In addition, the standardized
measures of discounted future net cash flows may not represent the fair market
value of the Company's oil and gas reserves or the present value of future cash
flows of equivalent reserves, due to anticipated future changes in oil and gas
prices and in production and development costs and other factors for effects
have not been proved.
F-24
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
The Company's reconciliation of changes in proved reserve quantities is
as follows (unaudited):
Gas Oil
(Mcf) (Bbls)
---------- -------
Balance September 30, 2002............................................ 74,137,386 54,548
Current additions................................................ 21,663,845 29,394
Transfers to limited partnerships................................ (8,688,298) (31,386)
Revisions........................................................ 44,613 16,631
Production....................................................... (3,327,168) (6,772)
---------- -------
Balance September 30, 2003............................................ 83,830,378 62,415
========== =======
Current additions................................................ 26,806,939 235,902
Transfers to limited partnerships................................ (7,808,942) (15,217)
Revisions........................................................ (6,493,890) (7,135)
Production....................................................... (3,872,923) (15,898)
---------- -------
Balance September 30, 2004............................................ 92,461,562 260,067
========== =======
Proved developed reserves at:
September 30, 2004............................................... 46,580,498 111,168
September 30, 2003............................................... 39,021,728 33,021
The following schedule presents the standardized measure of estimated
discounted future net cash flows relating to proved oil and gas reserves. The
estimated future production is priced at fiscal year-end prices, adjusted only
for fixed and determinable increases in natural gas and oil prices provided by
contractual agreements. The resulting estimated future cash inflows are reduced
by estimated future costs to develop and produce the proved reserves based on
fiscal year-end cost levels. The future net cash flows are reduced to present
value amounts by applying a 10% discount factor. The standardized measure of
future cash flows was prepared using the prevailing economic conditions existing
at September 30, 2004 and 2003 and such conditions continually change.
Accordingly such information should not serve as a basis in making any judgment
on the potential value of recoverable reserves or in estimating future results
of operations (unaudited).
Years Ended September 30,
----------------------------
2004 2003
--------- ---------
(in thousands)
Future cash inflows..................................................... $ 652,811 $ 413,066
Future production costs................................................. (79,989) (83,577)
Future development costs................................................ (91,195) (71,299)
Future income tax expense............................................... (122,962) (63,138)
--------- ---------
Future net cash flows................................................... 358,665 195,052
Less 10% annual discount for estimated timing of cash flows........... (222,143) (117,318)
--------- ---------
Standardized measure of discounted future net cash flows.............. $ 136,522 $ 77,734
========= =========
The future cash flows estimated to be spent to develop proved
undeveloped properties in the years ended September 30, 2005, 2006 and 2007 are
$36.0 million, $36.0 million and $19.2 million, respectively.
F-25
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
The following table summarizes the changes in the standardized measure
of discounted future net cash flows from estimated production of proved oil and
gas reserves after income taxes (unaudited):
Years Ended September 30,
---------------------------
2004 2003
--------- --------
(in thousands)
Balance, beginning of year.............................................. $ 77,734 $ 48,602
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs.............. (20,991) (14,099)
Net changes in prices and production costs............................ 59,345 20,455
Revisions of previous quantity estimates.............................. (10,197) 3,678
Purchases of reserves in place........................................ 270 -
Estimated settlement of asset retirement obligations.................. (1,209) (701)
Estimated proceeds on disposal of well equipment...................... 190 100
Development costs incurred............................................ 4,838 3,689
Changes in future development costs................................... (1,033) (158)
Transfers to limited partnerships..................................... (9,835) (3,326)
Extensions, discoveries, and improved recovery less
related costs...................................................... 54,979 24,574
Accretion of discount................................................. 9,697 17,082
Net changes in future income taxes.................................... (23,737) (7,085)
Other................................................................. (3,529) (15,077)
--------- --------
Balance, end of year.................................................... $ 136,522 $ 77,734
========= ========
F-26
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
ATLAS RESOURCES, INC. AND SUBSIDIARY
DECEMBER 31, 2004
F-27
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
DECEMBER 31, SEPTEMBER 30,
2004 2004
--------------- ---------------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents ............................................ $ 4,658 $ 242
Accounts receivable .................................................. 7,954 7,080
Prepaid expenses ..................................................... 1,748 1,488
--------------- ---------------
Total current assets ............................................... 14,360 8,810
Property and equipment:
Oil and gas properties and equipment(successful efforts) ............. 133,561 120,506
Buildings and land ................................................... 2,990 2,947
Other ................................................................ 370 368
--------------- ---------------
136,921 123,821
Less - accumulated depreciation, depletion and amortization ............ (25,820) (23,654)
--------------- ---------------
Net property and equipment ........................................... 111,101 100,167
Goodwill (net of accumulated amortization of $2,320) ................... 20,868 20,868
Intangible assets (net of accumulated amortization of $3,028 and $2,909) 3,325 3,444
--------------- ---------------
$ 149,654 $ 133,289
=============== ===============
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt .................................... $ 56 $ 56
Accounts payable ..................................................... 9,867 5,304
Liabilities associated with drilling contracts ....................... 52,610 29,375
Accrued liabilities .................................................. 3,169 3,174
Advances and note from Parent ........................................ 54,068 66,725
--------------- ---------------
Total current liabilities .......................................... 119,770 104,634
Asset retirement obligations ........................................... 2,594 1,910
Long-term debt ......................................................... 68 82
Stockholder's equity:
Common stock, stated at $10 per share;
500 authorized shares; 200 shares issued and outstanding ........... 2 2
Additional paid-in capital ........................................... 16,505 16,505
Retained earnings .................................................... 10,715 10,156
--------------- ---------------
Total stockholder's equity ......................................... 27,222 26,663
--------------- ---------------
$ 149,654 $ 133,289
=============== ===============
See accompanying notes to consolidated financial statements
F-28
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
THREE MONTHS ENDED DECEMBER 31, 2004 AND 2003
(UNAUDITED)
2004 2003
--------------- ---------------
(in thousands)
REVENUES
Well drilling .......................................................... $ 30,559 $ 21,959
Gas and oil production ................................................. 7,051 4,932
Well services .......................................................... 1,234 987
Transportation ......................................................... 590 621
Other .................................................................. 48 38
--------------- ---------------
39,482 28,537
COSTS AND EXPENSES
Well drilling .......................................................... 26,573 19,095
Gas and oil production and exploration ................................. 572 576
Well services .......................................................... 527 290
Non-direct ............................................................. 7,942 5,384
Depreciation, depletion and amortization ............................... 2,323 1,840
Interest ............................................................... 863 677
--------------- ---------------
38,800 27,862
--------------- ---------------
Income from operations before income taxes ............................. 682 675
Provision for income taxes ............................................. 123 142
--------------- ---------------
Net income ............................................................. $ 559 $ 533
=============== ===============
See accompanying notes to consolidated financial statements
F-29
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
THREE MONTHS ENDED DECEMBER 31, 2004
(UNAUDITED)
(in thousands, except share data)
Common Stock Additional Totals
----------------------- Paid-In Retained Stockholder's
Shares Amount Capital Earnings Equity
---------- ---------- ---------- ---------- -------------
Balance, October 1, 2004 ........... 200 $ 2 $ 16,505 $ 10,156 $ 26,663
Net income ......................... - - - 559 559
---------- ---------- ---------- ---------- -------------
Balance, December 31, 2004 ......... 200 $ 2 $ 16,505 $ 10,715 $ 27,222
========== ========== ========== ========== =============
See accompanying notes to consolidated financial statements
F-30
ATLAS RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
THREE MONTHS ENDED DECEMBER 31, 2004 AND 2003
(UNAUDITED)
2004 2003
--------------- ---------------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................................. $ 559 $ 533
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization ............................. 2,323 1,840
Management fees, cost allocation and, intercompany interest .......... 9,450 7,419
Gain on sale of assets ............................................... (8) (9)
Change in operating assets and liabilities ........................... 24,705 20,956
--------------- ---------------
Net cash provided by operating activities .............................. 37,029 30,739
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ................................................... (10,500) (7,234)
Proceeds from sale of assets ........................................... 8 9
--------------- ---------------
Net cash used in investing activities .................................. (10,492) (7,225)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings ....................................... (14) (14)
Net payments to Parent ................................................. (22,107) (27,608)
--------------- ---------------
Net cash used in financing activities .................................. (22,121) (27,622)
--------------- ---------------
Increase (decrease) in cash and cash equivalents ....................... 4,416 (4,108)
Cash and cash equivalents at beginning of year ......................... 242 4,702
--------------- ---------------
Cash and cash equivalents at end of year ............................... $ 4,658 $ 594
=============== ===============
See accompanying notes to consolidated financial statements
F-31
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - INTERIM FINANCIAL STATEMENTS
The consolidated financial statements of Atlas Resources, Inc. and its
wholly-owned subsidiary (the "Company") as of December 31, 2004 are unaudited.
Atlas Resources, Inc. is a wholly-owned subsidiary of Atlas America, Inc. (the
"Parent" or "Atlas"). These consolidated financial statements have been prepared
in accordance with accounting principles generally accepted in the United States
of America ("US GAAP") for interim financial information and certain rules and
regulations of the Securities and Exchange Commission. Accordingly, they do not
include all of the information and footnotes required by US GAAP for complete
financial statements.
The preparation of financial statements in conformity with US GAAP requires
management to make estimates and assumptions that affect (i) the reported
amounts of assets and liabilities, (ii) disclosure of contingent assets and
liabilities as of the dates of the financial statements and (iii) the reported
amounts of revenues and expenses during the reporting periods. In the opinion of
management, all adjustments (consisting only of normal recurring adjustments and
certain cost allocations for expenses paid by either the Parent or its'
affiliates on behalf of the Company) considered necessary for a fair
presentation have been reflected in these consolidated financial statements.
Operating results for the three months ended December 31, 2004, are not
necessarily indicative of the results that may be expected for the year ending
September 30, 2005. Certain reclassifications have been made to the fiscal 2004
consolidated financial statements to conform to the fiscal 2005 presentation.
These financial statements should be read in conjunction with the Company's
audited September 30, 2004 consolidated financial statements.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
The Company considers temporary investments with maturity at the date of
acquisition of 90 days or less to be cash equivalents.
Supplemental disclosure of cash flow information:
Three Months Ended
December 31,
-----------------------
2004 2003
---------- ----------
(in thousands)
CASH PAID DURING THE PERIODS FOR:
Interest............................................ $ 854 $ 190
Income taxes paid................................... $ - $ -
COMPREHENSIVE INCOME
Comprehensive income includes net income and all other changes in the
equity of a business during a period from transactions and other events and
circumstances from non-owner sources. These changes, other than net income, are
referred to as "other comprehensive income." The Company has no elements of
comprehensive income other than net income to report.
F-32
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 3 - ASSET RETIREMENT OBLIGATIONS
The Company accounts for the estimated plugging and abandonment of its oil
and gas properties in accordance with Statement of Financial Accounting
Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations".
A reconciliation of the Company's liability for well plugging and
abandonment costs for the periods indicated is as follows (in thousands):
December 31, December 31,
2004 2003
------------ ------------
Asset retirement obligations, beginning of period .. $ 1,910 $ 701
Liabilities incurred................................ 650 1,212
Liabilities settled................................. (4) (40)
Revision of estimates............................... - (60)
Accretion expense................................... 38 97
------------ ------------
Asset retirement obligations, end of period......... $ 2,594 $ 1,910
============ ============
NOTE 4 - COMMITMENTS AND CONTINGENCIES
The Company is the managing general partner of various energy partnerships,
and has agreed to indemnify each investor partner from any liability that
exceeds such partner's share of partnership assets. Subject to certain
conditions, investor partners in certain energy partnerships have the right to
present their interests for purchase by the Company, as managing general
partner. The Company is not obligated to purchase more than 5% to 10% of the
units in any calendar year. Based on past experience, the Company believes that
any liability incurred would not be material.
The Company may be required to subordinate a part of its net partnership
revenues to the receipt by investor partners of cash distributions from their
energy partnerships equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.
The Parent may draw from its revolving credit facility on behalf of the
Company. In July 2002, the Company's parent entered into a credit facility led
by Wachovia Bank, which has a current borrowing base of $75.0 million. The
facility permits draws based on the remaining proved developed producing and
non-producing and proved undeveloped natural gas and oil reserves attributable
to the Parent's interest in wells and the projected fees and revenues from
operation of the wells and the administration of their energy partnerships. The
facility is secured by the Parent's assets, including those of the Company. The
revolving credit facility has a term ending in March 2007. At December 31, 2004,
the Parent had $7.75 million outstanding under this facility, including $1.7
million under letters of credit. The Company had no amounts outstanding under
this facility for borrowings on its behalf at December 31, 2004.
The Company is a party to various routine legal proceedings arising out of
the ordinary course of its business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on the Company's financial position or results of operations.
F-33
ATLAS RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 5- INCOME TAXES
The Company is included in the consolidated federal income tax return of
Atlas' parent, Resource America, Inc. Income taxes are presented as if the
Company had filed a return on a separate company basis utilizing their
calculated effective rate of 18% and 21% for the three months ended December 31,
2004 and 2003, respectively. The Company's effective tax rate is lower than the
federal statutory rate due to the benefit of percentage depletion. Deferred
taxes, which are included in Advances and note from Parent in the Company's
consolidated balance sheet, reflect the tax effect of temporary differences
between the tax basis of the Company's assets and liabilities and the amounts
reported in the financial statements. Separate company state tax returns are
filed in those states in which the Company is registered to do business.
F-34
APPENDIX A
INFORMATION REGARDING
CURRENTLY PROPOSED PROSPECTS
FOR
ATLAS AMERICA PUBLIC #14-2005(A) L.P.
INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS
The partnerships do not currently hold any interests in any prospects on which
the wells will be drilled, and the managing general partner has absolute
discretion in determining which prospects will be acquired to be drilled.
However, set forth below is information relating to 105 proposed prospects and
the wells which will be drilled on the prospects by Atlas America Public
#14-2005(A) L.P., which is the second partnership in the program and must be
closed by December 31, 2005. It is referred to in this section as the "2005(A)
Partnership." One well will be drilled on each development prospect, and for
purposes of this section the well and prospect are referred to together as the
"well." 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 2005(A) 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 $35 million
is raised and the 2005(A) Partnership takes the working interest in the wells
which is set forth below in the "Lease Information" for each well. The managing
general partner has not proposed any other wells if:
o a greater amount of subscription proceeds is raised;
o a lesser working interest in the wells is acquired; or
o the wells are substituted for any of the reasons set forth below.
The managing general partner has not authorized any person to make any
representations to you concerning the possible inclusion of any other wells
which will be drilled by the 2005(A) Partnership or 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 2005(A)
Partnership;
o the latest geological and production data available;
o potential title or spacing problems;
o availability and price of drilling services, tubular goods and
services;
o approvals by federal and state departments or agencies;
o agreements with other working interest owners in the wells;
o farmins; and
o continuing review of other properties which may be available.
Any substituted and/or additional wells will meet the same general criteria for
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.
1
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 2005(A) Partnership may not experience production
comparable to the production experienced by wells in the surrounding area since
the geological conditions in these areas can change in a short distance. Also,
the managing general partner has not been able to obtain production information
for previously drilled wells in the immediate areas where a portion of the
currently proposed wells in Pennsylvania are situated because the information is
not available to the managing general partner as discussed in "Risk Factors -
Risks Related to an Investment In a Partnership - Lack of Production Information
Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a
Partnership's Drilling Program." 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 because
geologic trends in the immediate area, such as sand thickness, porosities and
water saturations, lead the managing general partner to believe that the
proposed wells also will be productive.
When reviewing production information for each well offsetting or in the general
area of a proposed well to be drilled you should consider the factors set forth
below.
o The length of time that the well has been on-line, and the period
for which production information is shown. Generally, the shorter
the period for which production information is shown the less
reliable this information is, when used for predicting the
ultimate recovery of a well.
o Production from a well declines throughout the life of the well.
The rate of decline, the "decline curve," varies based on which
geological formation is producing, and may be affected by the
operation of the well. For example, the wells in the
Clinton/Medina geological formation will have a different decline
curve from the wells in the Mississippian/Upper Devonian
Sandstone Reservoir in Fayette and Greene Counties. Also, each
well in a geological formation or reservoir will have a different
rate of decline from the other wells in the same formation or
reservoirs.
o The greatest volume of production ("flush production") from a
well usually occurs in the early period of well operations and
may indicate a greater reserve volume than the well actually will
produce. This period of flush production can vary depending on
how the well is operated and the location of the well.
o The production information for some wells is incomplete or very
limited. The designation "N/A" means:
o the production information was not available to the managing
general partner for the reasons discussed in "Risk Factors -
Risks Related to an Investment In a Partnership - Lack of
Production Information Increases Your Risk and Decreases
Your Ability to Evaluate the Feasibility of a Partnership's
Drilling Program"; or
o if the managing general partner was the operator, then when
the information was prepared the well was:
o not completed;
o not on-line to sell production; or
o producing for only a short period of time.
o Production information for wells located close to a proposed well
tends to be more relevant than production information for wells
located farther away, although performance and volume of
production from wells located on contiguous prospects can be much
different.
2
o Consistency in production among wells tends to confirm the
reliability and predictability of the production.
To help you become familiar with the proposed wells the information set forth
below is included.
o A map of western Pennsylvania and eastern Ohio showing their counties...................................5
o Fayette County, Pennsylvania (Mississippian/Upper Devonian Sandstone Reservoirs)
o Lease information for Fayette and Greene Counties, Pennsylvania.....................................7
o Location and Production Maps for Fayette and Greene Counties, Pennsylvania showing the proposed
wells and the wells in the area....................................................................10
o Production data for Fayette and Greene Counties, Pennsylvania......................................17
o United Energy Development Consultants, Inc.'s geologic evaluation for the currently proposed
wells in Fayette and Greene Counties, Pennsylvania.................................................28
o Western Pennsylvania (Clinton/Medina Geological Formation)
o Lease information for western Pennsylvania and eastern Ohio........................................34
o Location and Production Map for western Pennsylvania and eastern Ohio showing the proposed
wells and the wells in the area....................................................................36
o Production data for western Pennsylvania and eastern Ohio..........................................38
o United Energy Development Consultants, Inc.'s geologic evaluation for the currently proposed
wells in western Pennsylvania and eastern Ohio.....................................................40
o Armstrong County, Pennsylvania (Upper Devonian Sandstone Reservoirs)
o Lease information for Armstrong and Indiana Counties, Pennsylvania.................................46
o Location and Production Map for Armstrong and Indiana Counties, Pennsylvania showing the
proposed wells and the wells in the area...........................................................48
o Production data for Armstrong and Indiana Counties, Pennsylvania...................................50
o United Energy Development Consultants, Inc.'s geologic evaluation for the currently proposed
wells in Armstrong and Indiana Counties, Pennsylvania..............................................54
o McKean County, Pennsylvania (Upper Devonian Sandstone Reservoirs)
o Lease information for McKean County, Pennsylvania..................................................60
o Location and Production Maps for McKean County, Pennsylvania showing the proposed wells and the
wells in the area..................................................................................62
o Production data for McKean County, Pennsylvania....................................................68
o United Energy Development Consultants, Inc.'s geologic evaluation for the currently proposed
wells in McKean County, Pennsylvania...............................................................73
3
o Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee (Mississippian Carbonate and Devonian
Shale Reservoirs)
o A map of Tennessee showing its Counties............................................................78
o Lease information for Anderson, Campbell, Morgan, Roane and Scott Counties, Tennssesee.............80
o Location and Production Maps for Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
showing the proposed wells and the wells in the area...............................................82
o Production data for Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee................87
o United Energy Development Consultants, Inc.'s geologic evaluation for the currently proposed
wells in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee...........................90
4
MAP OF WESTERN PENNSYLVANIA
AND
EASTERN OHIO
5
[GRAPHIC OMITTED]
6
LEASE INFORMATION
FOR
FAYETTE AND GREENE COUNTIES, PENNSYLVANIA
7
OVERRIDING
ROYALTY
INTEREST
TO THE
MANAGIN
EFFECTIVE EXPIRATION LANDOWNER GENERAL
PROSPECT NAME COUNTY DATE* DATE* ROYALTY PARTNER
1 Anden #5 Fayette 12/15/2002 12/15/2005 12.5% 0%
2 Baily #2 Fayette 8/22/2002 8/22/2005 12.5% 0%
3 Baily #5 Fayette 8/22/2002 8/22/2005 12.5% 0%
4 Behanna #3 Fayette 1/14/2002 1/14/2005 12.5% 0%
5 Bezjak #5 Fayette 6/7/2003 6/7/2006 12.5% 0%
6 Bezjak #7 Fayette 6/7/2003 6/7/2006 12.5% 0%
7 Bezjak #11 Fayette 6/7/2003 6/7/2006 12.5% 0%
8 Bezjak #14 Fayette 6/7/2003 6/7/2006 12.5% 0%
9 Bezjak #17 Fayette 6/7/2003 6/7/2006 12.5% 0%
10 Brooks #2 Fayette 10/4/2002 10/4/2005 12.5% 0%
11 Campbell Farms #3 Fayette 1/31/2001 HBP 12.5% 0%
12 Canestrale #8 Fayette 4/16/2002 HBP 12.5% 0%
13 Canestrale #16 Fayette 4/16/2002 HBP 12.5% 0%
14 Canestrale #19 Fayette 4/16/2002 HBP 12.5% 0%
15 Carson #6 Fayette 11/9/2001 HBP 12.5% 0%
16 Chellini #2 Fayette 8/29/2001 8/29/2006 12.5% 0%
17 Clemmer #2 Fayette 5/18/2004 5/18/2007 12.5% 0%
18 D'Antonio #2 Fayette 5/1/1918 HBP 12.5% 0%
19 Delansky #1 Fayette 1/17/2003 1/17/2006 12.5% 0%
20 Doty #1 Fayette 10/17/2001 HBP 12.5% 0%
21 Doty #3 Fayette 10/17/2001 HBP 12.5% 0%
22 Dunay #3 Fayette 4/23/1935 HBP 12.5% 0%
23 Farquhar #9 Fayette 10/27/2000 10/27/2005 12.5% 0%
24 Fugozzotto Enterprises #2 Fayette 9/29/2004 3/29/2005 12.5% 0%
25 Garafalo #2 Fayette 7/31/2003 7/31/2008 12.5% 0%
26 Grlovich #1 Fayette 11/3/2003 11/3/2006 12.5% 0%
27 Hart #2 Greene 5/18/2001 5/17/2006 12.5% 0%
28 Heffner #3 Fayette 9/28/2000 9/28/2005 12.5% 0%
29 Heffner #4 Fayette 9/28/2000 9/28/2005 12.5% 0%
30 Joren/Burkland #1 Fayette 6/16/2004 6/16/2005 12.5% 0%
31 Kadar #1 Fayette 12/26/2003 12/26/2005 12.5% 0%
OVERRIDING
ROYALTY ACRES TO BE
INTEREST NET ASSIGNED TO
TO 3RD REVENUE WORKING NET THE
PROSPECT NAME PARTIES INTEREST INTEREST ACRES PARTNERSHIP
1 Anden #5 0% 87.5% 100% 297 20
2 Baily #2 0% 87.5% 100% 168 20
3 Baily #5 0% 87.5% 100% 168 20
4 Behanna #3 0% 87.5% 100% 88 20
5 Bezjak #5 0% 87.5% 100% 63 20
6 Bezjak #7 0% 87.5% 100% 189 20
7 Bezjak #11 0% 87.5% 100% 189 20
8 Bezjak #14 0% 87.5% 100% 189 20
9 Bezjak #17 0% 87.5% 100% 189 20
10 Brooks #2 0% 87.5% 100% 98 20
11 Campbell Farms #3 0% 87.5% 100% 199 20
12 Canestrale #8 0% 87.5% 100% 245 20
13 Canestrale #16 0% 87.5% 100% 554 20
14 Canestrale #19 0% 87.5% 100% 554 20
15 Carson #6 0% 87.5% 100% 83 20
16 Chellini #2 0% 87.5% 100% 100 20
17 Clemmer #2 0% 87.5% 100% 51 20
18 D'Antonio #2 0% 87.5% 100% 108 20
19 Delansky #1 0% 87.5% 100% 13 13
20 Doty #1 0% 87.5% 100% 161 20
21 Doty #3 0% 87.5% 100% 161 20
22 Dunay #3 0% 87.5% 100% 90 20
23 Farquhar #9 0% 87.5% 100% 90 20
24 Fugozzotto Enterprises #2 0% 87.5% 100% 58 20
25 Garafalo #2 0% 87.5% 100% 53 20
26 Grlovich #1 0% 87.5% 100% 11 11
27 Hart #2 0% 87.5% 100% 84 20
28 Heffner #3 0% 87.5% 100% 233 20
29 Heffner #4 0% 87.5% 100% 233 20
30 Joren/Burkland #1 0% 87.5% 100% 221 20
31 Kadar #1 0% 87.5% 100% 44 20
8
OVERRIDING
ROYALTY
INTEREST
TO THE
MANAGIN
EFFECTIVE EXPIRATION LANDOWNER GENERAL
PROSPECT NAME COUNTY DATE* DATE* ROYALTY PARTNER
32 Keffer #5 Fayette 11/16/2000 11/16/2005 12.5% 0%
33 Kirmeyer #2 Fayette 6/16/2001 6/16/2006 12.5% 0%
34 Kubala #2 Fayette 7/28/2001 7/28/2007 12.5% 0%
35 Lee #7 Fayette 5/27/2003 HBP 12.5% 0%
36 Luxner #3 Greene 12/12/1913 HBP 12.5% 0%
37 Lynch #3 Fayette 11/14/2002 11/14/2005 12.5% 0%
38 Lyons #3 Fayette 6/3/2002 6/3/2007 12.5% 0%
39 Murray #4 Fayette 1/15/2003 HBP 12.5% 0%
40 Novobilsky #3 Fayette 11/1/2002 11/1/2007 12.5% 0%
41 Old Stone School House #2 Fayette 6/24/2003 6/24/2008 12.5% 0%
42 Olexa #7 Fayette 10/11/2000 10/11/2005 12.5% 0%
43 Osley #4 Fayette 12/26/2000 HBP 12.5% 0%
44 Patterson #14 Westmoreland 12/5/2002 12/5/2005 12.5% 0%
45 Pevarnik #1 Greene 10/23/2001 10/22/2006 12.5% 0%
46 Rathway #1 Fayette 3/12/2002 3/12/2004 12.5% 0%
47 S.A.G.P. #2 Fayette 6/4/2003 6/4/2008 12.5% 0%
48 Schad #1 Fayette 12/11/2003 12/11/2006 12.5% 0%
49 Sedlak #2 Fayette 1/27/2003 1/27/2006 12.5% 0%
50 Sellman #3 Fayette 7/31/2002 7/31/2005 12.5% 0%
51 Star Junction/USX #25 Fayette 10/5/2000 HBP 12.5% 0%
52 Stoffa/Robinson #1 Fayette 4/27/2004 4/27/2006 12.5% 0%
53 Strickler #1 Fayette 12/1/2000 12/1/2005 12.5% 0%
54 Sveda #1 Fayette 9/28/2000 9/28/2005 12.5% 0%
55 Tarka/Burkland #1 Fayette 6/16/2004 6/16/2005 12.5% 0%
56 USX #8 Fayette 7/24/2003 HBP 12.5% 0%
57 Voytek/Burkland #1 Fayette 6/16/2004 6/16/2005 12.5% 0%
58 Wise #4 Fayette 3/12/2003 3/12/2007 12.5% 0%
59 Wolfe #17 Fayette 7/11/2001 HBP 12.5% 0%
60 Zinn #1 Fayette 9/22/2004 9/22/2007 12.5% 0%
*HBP - Held by Production.
OVERRIDING
ROYALTY ACRES TO BE
INTEREST NET ASSIGNED TO
TO 3RD REVENUE WORKING NET THE
PROSPECT NAME PARTIES INTEREST INTEREST ACRES PARTNERSHIP
32 Keffer #5 0% 87.5% 100% 168 20
33 Kirmeyer #2 0% 87.5% 100% 94 20
34 Kubala #2 0% 87.5% 100% 26 20
35 Lee #7 0% 87.5% 100% 118 20
36 Luxner #3 0% 87.5% 100% 106 20
37 Lynch #3 0% 87.5% 100% 146 20
38 Lyons #3 0% 87.5% 100% 150 20
39 Murray #4 0% 87.5% 100% 29 20
40 Novobilsky #3 0% 87.5% 100% 48 20
41 Old Stone School House #2 0% 87.5% 100% 47 20
42 Olexa #7 0% 87.5% 100% 166 20
43 Osley #4 0% 87.5% 100% 160 20
44 Patterson #14 0% 87.5% 100% 110 20
45 Pevarnik #1 0% 87.5% 100% 145 20
46 Rathway #1 0% 87.5% 100% 38 20
47 S.A.G.P. #2 0% 87.5% 100% 112 20
48 Schad #1 0% 87.5% 100% 30 20
49 Sedlak #2 0% 87.5% 100% 38 20
50 Sellman #3 0% 87.5% 100% 104 20
51 Star Junction/USX #25 0% 87.5% 100% 2109 20
52 Stoffa/Robinson #1 0% 87.5% 100% 32 20
53 Strickler #1 0% 87.5% 100% 137 20
54 Sveda #1 0% 87.5% 100% 155 20
55 Tarka/Burkland #1 0% 87.5% 100% 221 20
56 USX #8 0% 87.5% 100% 310 20
57 Voytek/Burkland #1 0% 87.5% 100% 221 20
58 Wise #4 0% 87.5% 100% 95 20
59 Wolfe #17 0% 87.5% 100% 53 20
60 Zinn #1 0% 87.5% 100% 137 20
*HBP - Held by Production.
9
LOCATION AND PRODUCTION MAPS FOR
FAYETTE AND GREENE COUNTIES, PENNSYLVANIA
10
[GRAPHIC OMITTED]
11
[GRAPHIC OMITTED]
12
[GRAPHIC OMITTED]
13
[GRAPHIC OMITTED]
14
[GRAPHIC OMITTED]
15
[GRAPHIC OMITTED]
16
PRODUCTION DATA
FOR
FAYETTE AND GREENE COUNTIES, PENNSYLVANIA
17
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
7 Greensboro Gas Co. David Gans #2-427 11/18/1918 N/A N/A 2530 N/A
00014 H.E. Wallker Donald E. Cunningham #1 7/8/1956 N/A N/A 1385 N/A
00022 Manufacturers Light & Heat Co. Republic Colleries #2 N/A N/A N/A N/A N/A
25 Duquesne Natural Gas Co. L.L. Robinson #2 6/14/1930 N/A N/A 2458 N/A
26 Duquesne Natural Gas Co. L.L. Robinson #1 8/15/1929 N/A N/A 1692 N/A
34 Greensboro Gas Co. J.V.Thompson #3 2/1/1911 N/A N/A 2900 N/A
00045 Greensboro Gas Co. Rebecca Shouffler #2 2/26/1925 N/A N/A 2971 N/A
00052 Greensboro Gas Co. Thompson Heirs #827 N/A N/A N/A 2108 N/A
109 W.Burkland Combs #2 12/19/1939 N/A N/A 1259 N/A
00190 Columbia Gas Transmission Corp Areford #1 11/18/1897 N/A N/A 2147 N/A
198 Red Lion Gas Cooperative Assn. Willson #1 N/A N/A N/A N/A N/A
211 W. Burkland Linn Coal #1 1942 N/A N/A N/A N/A
00235 W. Burkland C. Bixler #1 1927 N/A N/A N/A N/A
247 Bernandine Captain Captain #1 N/A N/A N/A N/A N/A
01200 Equitable Gas Co. Rebecca Hart 1941 N/A N/A 2790 N/A
01336 Carnegie Natural Gas Co. W. Hart #1 1923 N/A N/A 2887 N/A
01337 Carnegie Natural Gas Co. W. Huston #1 1925 N/A N/A 3025 N/A
01426 Columbia Gas Transmission Corp John R. Lovingood #603828 2/23/1945 N/A N/A 3505 N/A
01663 Greensboro Gas Co. W.D. Smith #2 6/2/1923 N/A N/A 2953 N/A
01975 George Sabocheck Sabocheck #1 N/A N/A N/A N/A N/A
01976 George Sabocheck Sabocheck #2 N/A N/A N/A N/A N/A
01978 E. Tague Crumrine #1 1/8/1927 N/A N/A 2530 N/A
02061 George Sabocheck Sabocheck #3 N/A N/A N/A N/A N/A
20001 G.A. Burgly, Jr. Mark & Leona Williams #1 10/31/1956 N/A N/A 1532 N/A
20004 G.A. Burgly, Jr. Bertha Lester #1 12/15/1961 N/A N/A 2800 N/A
20033 McCormick Drilling Co. McCarty #1 8/1/1958 N/A N/A 845 N/A
20054 M.C. Brumage & Sons A.G. Miller #963 9/15/1966 N/A N/A 2811 N/A
20093 N/A N/A N/A N/A N/A N/A N/A
20097 Fayette County Gas Co. William B. Graham #3 3/5/1943 N/A N/A 1521 N/A
20099 Peoples Natural Gas Co. Pauline Bozek #1 10/2/1969 N/A N/A 5300 N/A
20105 Pennsynd Petroleum, Inc. J.H. Hillman & Sons #2 7/29/1967 N/A N/A 519 N/A
18
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
20106 Pennsynd Petroleum, Inc. J.H. Hillman & Sons #3 5/3/1967 N/A N/A 490 N/A
20116 N/A N/A N/A N/A N/A N/A N/A
20117 N/A N/A N/A N/A N/A N/A N/A
20147 Peoples Natural Gas Co. Emery Anden #1 9/16/1974 N/A N/A 4004 N/A
20148 Peoples Natural Gas Co. Michael J. Gillock #1 8/23/1974 N/A N/A 3902 N/A
20150 Peoples Natural Gas Co. John E. Dunay #1 9/25/1974 N/A N/A 3815 N/A
20151 Nollem Oil & Gas Co. Robert Gabler/ Combs #1 N/A N/A N/A N/A N/A
20165 By Energy Leighty #3482 3/24/2000 N/A N/A 4209 N/A
20177 G.A. Burgly, Jr. Robert Warfel #1 7/29/1983 N/A N/A 3770 N/A
20178 G.A. Burgly, Jr. Geo. J. Elliott #123 8/26/1936 N/A N/A 1460 N/A
20255 James E. Brumage Smith Rose #1 N/A N/A N/A N/A N/A
20404 Greensboro Gas Co. Leander Dills #894 1931 N/A N/A 1815 N/A
20668 Rejiss Associates James Joshowitz et al #4 11/21/1992 N/A N/A 4142 N/A
20694 N/A N/A N/A N/A N/A N/A N/A
20716 Snyder Brothers, Inc. USX Corporation #1 2/2/1994 N/A N/A 3660 N/A
20807 W.Burkland Graham Heirs #1 3/7/1996 N/A N/A 1500 N/A
20918 LAHD Energy, Inc. Angelo #1 9/2/1997 N/A N/A 290 N/A
21062 Oil & Gas Management, Inc. Uphold #1 12/29/1998 N/A N/A 3765 N/A
21078 W.Burkland R. Jackson #1 N/A N/A N/A N/A N/A
21086 N/A N/A N/A N/A N/A N/A N/A
21087 Oil & Gas Management, Inc. Burchinal #2 5/26/1999 N/A N/A 2700 N/A
21093 Penneco Oil Company, Inc. Swiantek #1 7/9/1999 N/A N/A 3922 N/A
21181 N/A N/A N/A N/A N/A N/A N/A
21190 Belden & Blake Corporation Luz-Hogsett #1 1/20/2001 N/A N/A 1461 N/A
21230 Belden & Blake Corporation Garafalo #1 1/23/2001 N/A N/A 1484 N/A
21263 Atlas Frankhouser #1 3/26/2001 41 79,185 4516 656
21278 Penneco Oil Company, Inc. Swiantek #2 8/3/2001 N/A N/A 3422 N/A
21279 Penneco Oil Company, Inc. Swiantek #3 7/30/2001 N/A N/A 3422 N/A
21301 N/A N/A N/A N/A N/A N/A N/A
21336 Great Lakes Energy Partners, LLC Langley #1 12/29/2002 N/A N/A 3883 N/A
21348 Great Lakes Energy Partners, LLC Yoder #1 11/5/2001 N/A N/A 4122 N/A
19
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
21361 Atlas Podolinski #3 2/3/2002 29 6,383 3920 208
21371 Atlas Podolinski #2 5/21/2002 27 3,830 3800 103
21372 Atlas Podolinski #1 1/26/2002 27 16,225 3872 219
21376 Atlas National Mines #3 2/13/2002 29 31,717 4201 1,002
21388 Atlas Snyder #9 12/17/2001 29 55,533 3733 993
21402 Atlas National Mines #6 5/29/2002 27 75,259 4250 1,773
21403 Atlas National Mines #5 11/21/2002 21 57,517 4120 1,876
21404 Atlas National Mines #4 4/3/2002 29 63,651 4320 324
21405 Great Lakes Energy Partners, LLC Constantine #3 1/14/2002 N/A N/A 3965 N/A
21410 Atlas Gorley #1 3/13/2002 29 183,199 1310 4,160
21432 Atlas Madonna Church #1 2/2/2003 18 3,039 4404 133
21439 Atlas Gaggiani #3A 5/8/2002 27 5,945 3160 68
21440 Atlas Gaggiani #1 3/27/2002 27 8,739 4710 196
21450 Kriebel Minerals, Inc. Grimm #1 8/22/2002 N/A N/A 4416 N/A
21459 Great Lakes Energy Partners, LLC Yoder #2 4/26/2002 N/A N/A 4030 N/A
21462 Great Lakes Energy Partners, LLC Randolph, et al #1 8/3/2002 N/A N/A 4054 N/A
21463 Great Lakes Energy Partners, LLC Randolph, et al #2 8/4/2002 N/A N/A 1545 N/A
21471 Atlas Thomas #3 6/20/2002 26 25,052 4370 839
21492 Atlas Osley #1 7/17/2002 13 8,446 4380 358
21508 Atlas Osley #2 8/27/2002 25 2,726 4353 78
21528 Great Lakes Energy Partners, LLC Miller, Donald #1 11/25/2002 N/A N/A 4150 N/A
21532 Atlas Beadling #1A 10/8/2002 22 11,576 4269 345
21565 Great Lakes Energy Partners, LLC Edson Farms Unit #2 7/18/2003 N/A N/A 4028 N/A
21566 Great Lakes Energy Partners, LLC Edson Farms Unit #1 12/5/2002 N/A N/A 4122 N/A
21581 Atlas Snyder #10 12/19/2002 20 4,884 4310 293
21590 Atlas Ramage #1 2/21/2003 18 117,822 1850 5,804
21591 Atlas National Mines #14 12/4/2002 21 38,194 4370 1,948
21597 Atlas Marian Unit #1A 6/8/2003 15 10,578 4325 586
21598 Atlas Marian #3 2/15/2003 18 14,018 4300 590
21603 Great Lakes Energy Partners, LLC Yoder #4 8/19/2003 N/A N/A 4205 N/A
21612 W.Burkland James E. Frey #1 1/14/2003 N/A N/A 3766 N/A
20
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
21618 Great Lakes Energy Partners, LLC Randolph, et al #3 12/18/2002 N/A N/A 1440 N/A
21623 Atlas Porter #1 3/1/2003 15 12,244 4250 705
21624 Atlas Erjavec #1 3/12/2003 17 16,074 4510 509
21631 Atlas Langley #2 12/4/2003 6 2,848 4320 290
21647 Atlas Harper #3 6/25/2003 14 7,406 4500 345
21654 Kriebel Minerals, Inc. W. Orr #3 2/26/2003 N/A N/A 4466 N/A
21655 Atlas Harper #4 4/21/2003 17 9,685 4400 428
21658 Atlas National Mines #15 3/25/2003 17 15,102 3950 952
21667 Great Lakes Energy Partners, LLC Keffer #2 4/11/2003 N/A N/A 3786 N/A
21673 Atlas Porter #4 3/13/2003 16 14,973 4290 939
21675 Atlas Porter #2 6/3/2003 16 4,452 4275 219
21707 Great Lakes Energy Partners, LLC Langley #2 6/22/2003 N/A N/A 3777 N/A
21714 Atlas Augustine #1 6/3/2003 15 83,010 4250 4,293
21727 Interstate Gas Marketing, Inc. Filchock #2 5/13/2003 N/A N/A 3855 N/A
21729 Atlas Augustine #4 8/14/2003 12 4,090 4200 334
21757 W. Burkland E. Siegel #1 6/11/2004 N/A N/A 4012 N/A
21771 Atlas Noble #12 7/30/2003 12 3,564 4350 279
21772 Atlas Croftcheck #9 9/4/2003 11 45,610 4370 4,899
21789 Atlas Porter #3 9/18/2003 11 15,734 3950 1,792
21790 Atlas Augustine #2 8/7/2003 12 10,262 4210 775
21818 Atlas Mullen/National City #1 10/5/2003 6 23,451 4550 6,429
21820 Atlas Jackson Farms #20 10/13/2003 9 40,000 2940 2,214
21825 Kriebel Minerals, Inc. W. Orr #4 12/11/2003 N/A N/A 4481 N/A
21833 Atlas Wozniak #3 10/8/2003 5 2,383 4470 416
21844 Atlas Noble #11 10/18/2003 9 7,318 4150 531
21856 Atlas Teslovich #01 10/25/2003 8 39,758 4500 4,179
21858 Atlas Janco #2 12/10/2003 N/A N/A 1900 N/A
21859 Atlas Janco #3 10/25/2003 N/A N/A 4150 N/A
21860 Atlas Chalfant #1 11/3/2003 N/A N/A 3950 N/A
21863 Atlas Croftcheck #5 12/10/2003 7 46,543 4500 10,747
21867 Atlas Croftcheck #8 5/26/2004 1 3,894 4540 3,894
21
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
21868 Atlas Croftcheck #3 11/24/2003 7 20,760 4450 3,540
21873 Atlas Croftcheck #7 2/24/2004 5 1,791 4550 484
21874 Atlas Harper #5 10/20/2003 10 71,026 4303 9,060
21884 Atlas Hogsett Unit #1 10/22/2003 7 4,293 3870 338
21889 Atlas Teslovich #2 3/28/2004 4 8,444 4458 3,290
21903 W. Burkland Wise-LTV-Searights #1 6/18/2004 N/A N/A 3858 N/A
21921 Atlas Peton/Hogsett #2 1/23/2004 4 1,808 4210 530
21923 Atlas Marian #2 11/13/2003 8 11,734 3920 1,021
21924 Atlas Yowonske-Hogsett #2 4/21/2004 1 547 4250 547
21937 Atlas Langley #8 12/11/2003 6 2,284 3850 267
21938 Atlas King Unit #8 6/4/2004 4 11,222 3850 4,690
21944 Atlas Brady #2 4/22/2004 3 2,613 4340 1,140
21951 Atlas Williams #23 12/17/2003 4 3,974 3750 430
21952 Atlas Yowonske-Hogsett #1 4/13/2004 1 461 4160 461
21960 Atlas Croftcheck #4 12/4/2003 7 34,347 4020 6,734
21978 Great Lakes Energy Partners, LLC Commercial Tire #1 3/19/2004 N/A N/A 3894 N/A
21988 Atlas Congelio #2 1/31/2004 2 1,651 4520 1,528
22004 Atlas Allison/Hogsett #05 2/25/2004 4 19,889 4420 6,159
22007 Atlas Gorley #2 3/13/2004 4 2,425 3750 955
22008 Atlas Gorley #3 3/8/2004 4 277 3810 196
22012 Atlas Constantine #1 3/24/2004 2 1,317 4100 799
22013 Atlas Constantine #2 3/30/2004 2 263 4200 251
22014 Atlas Constantine #3 4/6/2004 2 218 4378 209
22026 Atlas Allison/Hogsett #06 3/1/2004 4 9,984 4400 3,370
22035 Atlas Dancho-Brown #2 4/14/2004 3 2,373 4357 771
22047 Atlas Getsie #1 2/18/2004 5 28,043 1740 3,502
22048 Atlas Getsie #2 2/27/2004 5 5,225 4560 893
22055 Atlas King #9 5/5/2004 2 2,683 4510 2,090
22057 Atlas Canestrale #3 9/3/2004 N/A N/A 4460 N/A
22058 Atlas Congelio #1A 3/15/2004 2 805 4550 741
22098 Atlas Wilkinson #2 8/29/2004 N/A N/A 3990 N/A
22
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
22099 Atlas Wilkinson #3 3/25/2004 N/A N/A 4200 N/A
22102 Atlas Congelio #4 6/9/2004 2 4,167 4460 4,051
22112 Atlas Congelio #3 5/27/2004 2 1,763 4100 1,706
22121 Atlas Shaw #3 5/19/2004 N/A N/A 4350 N/A
22126 Atlas Canestrale #9 6/22/2004 N/A N/A 4410 N/A
22127 Atlas Teslovich #15 6/4/2004 2 2,793 4420 2,420
22128 Atlas Chan #1 5/12/2004 1 11 4690 11
22129 Atlas Teslovich #14 5/27/2004 2 2,652 4470 2,316
22141 Atlas Croftcheck #6 6/16/2004 1 183 4700 183
22151 Atlas Crawford Unit #5 6/10/2004 N/A N/A 4440 N/A
22462 Equitrans, Inc. Joseph J. Stajnrajh #2 1/19/1993 N/A N/A 2557 N/A
22523 Equitrans, Inc. Thomas & Melissa Luxner #2 10/2/1993 N/A N/A 2924 N/A
23409 N/A N/A N/A N/A N/A N/A N/A
90011 Greensboro Gas Co. S.Gorley #2 6/21/1944 N/A N/A 2989 N/A
90021 Duquesne Natural Gas Co. G.W. Weltner #301 2/11/1938 N/A N/A 2600 N/A
90022 Greensboro Gas Co. American Coke & Fuel 9/14/1942 N/A N/A 2807 N/A
90023 Greensboro Gas Co. American Coke & Fuel #5-964 12/9/1943 N/A N/A 2773 N/A
90027 Greensboro Gas Co. G.O. Morris #1-958 4/23/1943 N/A N/A 2509 N/A
90034 Manufacturers Light & Heat Co. W.A. Gilleland #4214 2/19/1954 N/A N/A 3731 N/A
90054 Greensboro Gas Co. J.W. Fast #889 1931 N/A N/A 2840 N/A
90055 Greensboro Gas Co. American Coke & Fuel 3/12/1931 N/A N/A 1609 N/A
90060 Greensboro Gas Co. Estella Gibson #416 1917 N/A N/A 2959 N/A
90061 Greensboro Gas Co. J. P. Horner #2 N/A N/A N/A 2885 N/A
90062 Greensboro Gas Co. J. H. Horner #788 1927 N/A N/A 3084 N/A
90063 Greensboro Gas Co. J. P. Horner #2 1918 N/A N/A 3178 N/A
90067 Greensboro Gas Co. J. Hogsett #3 1923 N/A N/A 3196 N/A
90070 Greensboro Gas Co. L.W. Ernest #800 1927 N/A N/A 3213 N/A
90071 Greensboro Gas Co. E.M. Gibson #2 1920 N/A N/A 3108 N/A
90074 Greensboro Gas Co. Geo. A. Cox #256 8/27/1917 N/A N/A 3005 N/A
90081 Greensboro Gas Co. Krepps #2 10/21/1910 N/A N/A 3106 N/A
90082 Greensboro Gas Co. Mary Lawrence #428 1918 N/A N/A 3127 N/A
23
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
90083 Greensboro Gas Co. J. C. Miller #1 1920 N/A N/A 1790 N/A
90085 Greensboro Gas Co. Moore #798 1927 N/A N/A 2801 N/A
90087 Greensboro Gas Co. J.W. Porter #1 1918 N/A N/A 3212 N/A
90089 Greensboro Gas Co. E.M. Robinson #2 1918 N/A N/A 3082 N/A
90090 Greensboro Gas Co. E. M. Robinson #1 1918 N/A N/A 3073 N/A
90091 Greensboro Gas Co. S. Rose #1 3/29/1905 N/A N/A 4470 N/A
90095 Greensboro Gas Co. J.V. Thompson #1 6/17/1910 N/A N/A 3309 N/A
90118 Greensboro Gas Co. David Gans #3 1921 N/A N/A 3654 N/A
90119 Greensboro Gas Co. A.A. Stevenson #884 12/1/1930 N/A N/A 2665 N/A
90120 Greensboro Gas Co. John Vesey 11/24/1938 N/A N/A 1473 N/A
90121 Greensboro Gas Co. O.P. Eberhart #35 12/19/1901 N/A N/A 1665 N/A
90122 Greensboro Gas Co. Samuel Fast #592 1924 N/A N/A 1920 N/A
90123 Greensboro Gas Co. S.C. Fast #34 1/1/1901 N/A N/A 1755 N/A
90124 Greensboro Gas Co. M.W. Frank Heirs #47 6/1/1901 N/A N/A 1424 N/A
90125 Greensboro Gas Co. A.C. Fretts #801 1927 N/A N/A 1840 N/A
90126 Greensboro Gas Co. C.W. Fox #1 1923 N/A N/A 3497 N/A
90127 Greensboro Gas Co. John Morris #48 7/1/1901 N/A N/A 1797 N/A
90128 Greensboro Gas Co. Woodside Coal & Coke Co. #896 N/A N/A N/A 1063 N/A
90129 Greensboro Gas Co. J.A. Searights #38 N/A N/A N/A 1693 N/A
90130 Greensboro Gas Co. J.C. Ramsey #2 1925 N/A N/A 2601 N/A
90131 Greensboro Gas Co. James Ramsey #61 N/A N/A N/A 2134 N/A
90132 Greensboro Gas Co. Springer Heirs #45 1901 N/A N/A 1351 N/A
90133 Greensboro Gas Co. J.K. Dils #43 1901 N/A N/A 1856 N/A
90134 Greensboro Gas Co. E.D. Fulton #1 N/A N/A N/A 1287 N/A
90135 Greensboro Gas Co. J.K. Dils #3 1928 N/A N/A 2656 N/A
90136 Greensboro Gas Co. D. Rhodes #418 1918 N/A N/A 2831 N/A
90137 Greensboro Gas Co. Stoner #27 N/A N/A N/A 2050 N/A
90138 Greensboro Gas Co. Ellen Provance #595 1925 N/A N/A 1535 N/A
90139 Greensboro Gas Co. M. Stoner #71 1904 N/A N/A 1952 N/A
90140 Greensboro Gas Co. W.J. Coleman #40 2/1/1901 N/A N/A 2644 N/A
90148 Greensboro Gas Co. Rebecca Stouffer #2 1929 N/A N/A 2934 N/A
24
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
90149 Greensboro Gas Co. E.S. Stephens #724 1925 N/A N/A 2935 N/A
90152 Greensboro Gas Co. C.G. & Sarah Lutz 1930 N/A N/A 2137 N/A
90152 Greensboro Gas Co. C.G. & Sarah Lutz 8/7/1930 N/A N/A 3137 N/A
90154 Greensboro Gas Co. Robert Gilbert #900 1931 N/A N/A 3081 N/A
90156 Greensboro Gas Co. A.H. Elliott #228 1911 N/A N/A 2876 N/A
90156 Greensboro Gas Co. H. E. Elliott #1 8/23/1911 N/A N/A 2876 N/A
90157 Greensboro Gas Co. C.S. Brown #1 1923 N/A N/A 2759 N/A
90157 Greensboro Gas Co. Charles S. Brown #640 7/20/1923 N/A N/A 2754 N/A
90161 Carnegie Natural Gas Co. James Clark N/A N/A N/A 2844 N/A
90161 Greensboro Gas Co. James Clark #107 N/A N/A N/A 2844 N/A
90189 N/A N/A N/A N/A N/A N/A N/A
CAR220 Carnegie Natural Gas Co. J.H. Rea #1 1/24/1915 N/A N/A 2946 N/A
CAR224 Carnegie Natural Gas Co. Ella M. Ross #1 1/12/1916 N/A N/A 4515 N/A
CAR248 Carnegie Natural Gas Co. C.J. Hart #1 8/11/1916 N/A N/A 2937 N/A
CAR263 Carnegie Natural Gas Co. Ella M. Ross #2 12/4/1916 N/A N/A 2952 N/A
CAR272 Carnegie Natural Gas Co. Earl S. Anford #1-272 7/19/1917 N/A N/A 2859 N/A
CAR340 Carnegie Natural Gas Co. W.F. Flenniken #2-340 11/6/1920 N/A N/A 2960 N/A
CAR422 Carnegie Natural Gas Co. John Longanecker #2-422 10/12/1922 N/A N/A 2985 N/A
CAR443 Carnegie Natural Gas Co. Thos. H. Hawkins #1-443 4/13/1925 N/A N/A 2940 N/A
CAR760 Carnegie Natural Gas Co. J.H. Baily #2-760 5/6/1930 N/A N/A 3050 N/A
F22960 Dr. S.W. Huston A.E. Langley #1 8/17/1945 N/A N/A 1411 N/A
FC35 Fayette County Gas Co. Jeffries 1921 N/A N/A 3381 N/A
FC96 Fayette County Gas Co. Graham #1 N/A N/A N/A 1897 N/A
FGN5 N/A N/A before 1935 N/A N/A 2200 (est.) N/A
FL49 N/A N/A N/A N/A N/A N/A N/A
G113 Greensboro Gas Co. Richard Drew #1-113 11/26/1906 N/A N/A 2449 N/A
G122 Greensboro Gas Co. Dils Heirs /W. Hatfield #1-122 6/4/1907 N/A N/A 1283 N/A
G158 Greensboro Gas Co. West Bros. #1-158 6/18/1909 N/A N/A 2911 N/A
G163 Greensboro Gas Co. N. E. Porter #2-163 8/14/1909 N/A N/A 2974 N/A
G173 Greensboro Gas Co. W.H. Campbell #1 11/30/1909 N/A N/A 2822 N/A
G19 Greensboro Gas Co. W. Fast #19 6/21/1900 N/A N/A 2070 N/A
25
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
G194 Greensboro Gas Co. J.V. Thompson #2-194 10/13/1910 N/A N/A 3010 N/A
G273 Greensboro Gas Co. W. Townsend #2-273 8/27/1913 N/A N/A 2039 N/A
G302 Greensboro Gas Co. I. N. Craft #1-302 8/14/1914 N/A N/A 3117 N/A
G51 N/A N/A N/A N/A N/A N/A N/A
G524 Greensboro Gas Co. Champion Connellsville
Coal & Coke Co. #1 10/14/1920 N/A N/A 2715 N/A
G625 Greensboro Gas Co. Hartley 1924 N/A N/A 3137 N/A
G917 Greensboro Gas Co. Mary Keys Graham #1 6/7/1940 N/A N/A 1182 N/A
G953 Greensboro Gas Co. Margaret Bowie Heirs #2 2/26/1943 N/A N/A 1401 N/A
P01969 N/A N/A N/A N/A N/A N/A N/A
P01970 N/A N/A N/A N/A N/A N/A N/A
P01973 N/A N/A N/A N/A N/A N/A N/A
P01974 N/A N/A N/A N/A N/A N/A N/A
P1201 Greensboro Gas Co. John Longnecker 9/10/1921 N/A N/A 2992 N/A
P1202 N/A N/A N/A N/A N/A N/A N/A
P1204 Greensboro Gas Co. Geo. A. Schroyer #1-463 7/17/1919 N/A N/A 3315 N/A
P1206 Greensboro Gas Co. A.M. Stephenson #1-459 1/2/1919 N/A N/A 3088 N/A
P1797 N/A N/A N/A N/A N/A N/A N/A
P21214 Bickerton & Vaugh G. McGill #1 3/31/1939 N/A N/A 1540 N/A
P22026 N/A N/A N/A N/A N/A N/A N/A
P22140 N/A N/A N/A N/A N/A N/A N/A
P22410 N/A N/A N/A N/A N/A N/A N/A
P22694 N/A N/A N/A N/A N/A N/A N/A
P22917 N/A N/A N/A N/A N/A N/A N/A
P22918 N/A N/A N/A N/A N/A N/A N/A
P23112 N/A N/A N/A N/A N/A N/A N/A
P23318 D. Mayne, et al Atlas Coal Co. #1 7/3/1941 N/A N/A 1414 N/A
P23453 N/A N/A N/A N/A N/A N/A N/A
P23644 N/A N/A N/A N/A N/A N/A N/A
P23645 Nollem Oil & Gas Co. Mahlon Coombs #4 10/10/1941 N/A N/A 3200 N/A
P23857 N/A N/A N/A N/A N/A N/A N/A
P23857 N/A N/A before 1935 N/A N/A N/A N/A
26
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 TOTAL LATEST 30
MOS ON THROUGH LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE 09/30/04 DEPTH - 09/30/04
- --------- -------- --------- ------------- ---- -------- ----- ----------
P24125 N/A N/A N/A N/A N/A N/A N/A
P24125 Smock Gas Co. J. Hess #1 1905 N/A N/A 1905 N/A
P24257 N/A N/A N/A N/A N/A N/A N/A
P24459 N/A N/A N/A N/A N/A N/A N/A
P24502 N/A N/A N/A N/A N/A N/A N/A
P25531 Duquesne Natural Gas Co. Elizabeth Provence 5/11/1931 N/A N/A 2710 N/A
P25531 N/A N/A N/A N/A N/A N/A N/A
P26094 H.K.Porter Thompson-Connellsville #1 12/17/1943 N/A N/A 2930 N/A
P26321 Greensboro Gas Co. J. Edgar Baily #636 9/8/1923 N/A N/A 2952 N/A
P26448 N/A N/A N/A N/A N/A N/A N/A
P27181 N/A N/A N/A N/A N/A N/A N/A
PNG3860 Peoples Natural Gas Co. N/A 7/27/1949 N/A N/A 3108 N/A
27
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
FAYETTE AND GREENE COUNTIES, PENNSYLVANIA
28
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #14-2005(A) LIMITED PARTNERSHIP
FAYETTE PROSPECT AREA
PENNSYLVANIA
Dated: November 22, 2004
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
29
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 #14-2005(A) LIMITED PARTNERSHIP, contains acreage in Luzerne,
Redstone, Menallen, Nicholson, German, Washington, Jefferson and Perry Townships
of Fayette County, Cumberland Township of Greene County and Rostraver Township
of Westmoreland County, located in southwestern Pennsylvania. Sixty (60)
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 1900 feet to 5500 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 four hundred
seventy five (475) 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 over 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 drill at least 1000 feet from producing wells, although Atlas
may drill a new well or re-enter an existing well closer than 1000 feet from
plugged and abandoned wells.
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.
30
[GRAPHIC OMITTED]
Stratigraphically, in descending order, the potentially productive units of the
Mississippian and Upper Devonian Groups are: Burgoon, 2nd Gas Sand, Gantz, Fifty
Foot, Fifth, Bayard, Lower Warren, Upper Speechley, Lower Speechley, Upper
Balltown, and First Bradford Sand. Stratigraphic relationships are illustrated
in the diagram.
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.
31
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.
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 multiple sets of commingled reservoirs exclusively found in this
area.
32
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #14-2005(A) LIMITED PARTNERSHIP, which will consist of
developmental drilling of Lower Mississippian and Upper Devonian reservoirs in
Fayette, Greene and Westmoreland Counties, Pennsylvania. It is the professional
opinion of UEDC that the drilling of the sixty (60) wells by ATLAS AMERICA
PUBLIC #14-2005(A) 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.
33
LEASE INFORMATION
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
34
OVERRIDING
ROYALTY
INTEREST
TO THE OVERRIDING ACRES TO BE
MANAGING ROYALTY ASSIGNED TO
EFFECTIVE EXPIRATION LANDOWNER GENERAL INTEREST TO NET REVENUE WORKING NET THE
PROSPECT NAME COUNTY DATE* DATE* ROYALTY PARTNER 3RD PARTIES INTEREST INTEREST ACRES PARTNERSHIP
------------- ------ ----- ----- ------- ------- ----------- -------- -------- ----- -----------
1 McIntyre #3 Crawford 08/11/03 08/11/06 12.5% 0% 0% 87.5% 100% 106 50
2 Scott #2 Crawford 08/11/03 08/11/06 12.5% 0% 0% 87.5% 100% 100 50
3 Ernst Farms #1 Crawford 07/23/03 07/23/06 12.5% 0% 0% 87.5% 100% 126 50
4 Coleman #6 Crawford 04/28/04 04/28/07 12.5% 0% 0% 87.5% 100% 55 50
5 Hood #6 Crawford 03/25/02 HBP 12.5% 0% 0% 87.5% 100% 113 50
6 Helbig #2 Crawford 08/20/02 08/20/05 12.5% 0% 0% 87.5% 100% 25 25
7 Mullenax #1 Crawford 02/24/03 02/24/06 12.5% 0% 0% 87.5% 100% 73 50
8 Conley #2 Crawford 11/29/02 11/29/05 12.5% 0% 0% 87.5% 100% 75 25
*HBP - Held by Production.
35
LOCATION AND PRODUCTION MAP
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
36
[GRAPHIC OMITTED]
37
PRODUCTION DATA
FOR
WESTERN PENNSYLVANIA AND EASTERN OHIO
38
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 LATEST 30
DATE MOS ON 09/30/04 EXCEPT TOTAL LOGGERS DAY PROD.
ID NUMBER OPERATOR WELL NAME COMPLT'D LINE WHERE NOTED DEPTH - 09/30/04
--------- -------- --------- -------- ---- ----------- ----- ----------
21928 Great Lakes Energy Partners Sousa #1 01/23/83 N/A N/A 4532 N/A
22074 George Lapradd Stephens (J. Free Unit #1) 03/13/84 N/A N/A 4578 N/A
24201 Atlas Resources, Inc. Hood #5 11/04/04 N/A N/A 4719 N/A
24208 Atlas Resources, Inc. Hebert #4 05/18/04 3 N/A 4749 N/A
24229 Atlas Resources, Inc. Moyers #1 09/07/04 N/A N/A 4584 N/A
24254 Atlas Resources, Inc. Shearer #2 12/30/03 5 1869 4746 1371
24258 Atlas Resources, Inc. Merlin Enterprises #3 01/29/04 N/A N/A 4668 N/A
24268 Atlas Resources, Inc. Grudoski #1 01/17/04 5 1497 4754 743
24269 Atlas Resources, Inc. Feidler #1 01/27/04 4 233 4746 233
24272 Atlas Resources, Inc. Crum Unit #1 02/13/04 7 4308 4836 976
24273 Atlas Resources, Inc. Unger #1 02/07/04 4 877 4742 877
24362 Atlas Resources, Inc. Leslie #1 08/23/04 N/A N/A 4550 N/A
24373 Atlas Resources, Inc. Williams #28 09/13/04 N/A N/A 4638 N/A
24390 Atlas Resources, Inc. Helderlein Unit #1 10/30/04 N/A N/A 4639 N/A
24396 Atlas Resources, Inc. Oswald Farms #4 11/10/04 N/A N/A 4705 N/A
90003 United Natural Gas Naylor, James #1 11/17/23 N/A N/A 4400 N/A
39
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
WESTERN PENNSYLVANIA AND EASTERN OHIO
40
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #14-2005(A) LIMITED PARTNERSHIP
CRAWFORD PROSPECT AREA
PENNSYLVANIA
Dated: November 22, 2004
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
41
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 #14-2005(A) LIMITED PARTNERSHIP, contains acreage in West
Fallowfield, East Fallowfield, Vernon and Sadsbury Townships of Crawford County,
located in northwestern Pennsylvania. Eight (8) 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 fourteen hundred (1400) 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".
[GRAPHIC OMITTED]
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.
42
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.
[GRAPHIC OMITTED]
Electric well logs can be used in conjunction with production to interpret
reservoir parameters. When sandstones in the Thorold, Grimsby, Cabot Head or
Whirlpool develop porosity in excess of 6%, or a bulk density of 2.55 or less,
the permeability of the reservoir (which ranges from <0.l to >0.2 mD) can become
great enough to allow commercial production of natural gas. Small, naturally
occurring cracks in the formation, referred to as micro-fractures, can also
enhance permeability. A gamma, bulk density, density porosity and neutron log
suite showing sand development in the Grimsby, Cabot Head and Whirlpool is
illustrated.
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.
43
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. As shown in the example, 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.
[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.
44
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #14-2005(A) LIMITED PARTNERSHIP, which will consist of
developmental drilling of the Clinton-Medina Group sands in Crawford County,
Pennsylvania. It is the professional opinion of UEDC that the drilling of the
eight (8) wells by ATLAS AMERICA PUBLIC #14-2005(A) 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.
45
LEASE INFORMATION
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
46
OVERRIDING
ROYALTY
INTEREST
TO THE OVERRIDING ACRES TO BE
MANAGING ROYALTY NET ASSIGNED TO
EFFECTIVE EXPIRATION LANDOWNER GENERAL INTEREST TO REVENUE WORKING NET THE
PROSPECT NAME COUNTY DATE* DATE* ROYALTY PARTNER 3RD PARTIES INTEREST INTEREST ACRES PARTNERSHIP
------------- ------ ----- ----- ------- ------- ----------- -------- -------- ----- -----------
1 M. Filippini # 3 Armstrong 07/27/04 07/27/07 12.5% 0% 3.125% 63.281% 75% 17 14.60%
2 Paul Heirs # 3 Indiana 11/18/03 11/18/08 12.5% 0% 3.125% 63.281% 75% 201 14.60%
3 Lawry # 3 Indiana 03/28/03 03/28/05 12.5% 0% 3.125% 63.281% 75% 120 14.60%
4 Nowrytown # 3 Indiana 11/05/04 11/05/09 12.5% 0% 3.125% 63.281% 75% 108 14.60%
5 Gais # 1 Indiana 05/07/03 05/07/08 12.5% 0% 3.125% 63.281% 75% 50 14.60%
*HBP - Held by Production.
47
LOCATION AND PRODUCTION MAP
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
48
[GRAPHIC OMITTED]
49
PRODUCTION DATA
FOR
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
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
THROUGH
09/30/04
ID MOS ON EXCEPT TOTAL LATEST 30
NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE WHERE NOTED LOGGERS DEPTH DAY PROD.
- ------ -------- --------- ------------- ---- ----------- ------------- ---------
02368 Dominion Peoples Wray, Et. Al. #1 5/3/1921 NA 251,497/1992 3096 NA
20128 Dominion Peoples Martin #1 1/14/1958 NA 205,767/1992 3134 NA
20154 Dominion Peoples Kerr #1 6/3/1958 NA 203,046/1992 3229 NA
20222 Dominion Peoples Deemer #2 2/26/1896 / NA 251,637/1992 1584 / 3386 NA
12/3/1958
20600 Dominion Peoples Geiger #2 10/10/1963 NA 305,774/1992 3457 NA
20768 Dominion Peoples Chambers #2 7/9/1965 NA 243,610/1992 3604 NA
20957 Dominion Peoples Chambers #1 3/19/1968 NA 579,140/1992 3630 NA
25760 Petroleum Development Corp. (JV USEE) Becker #2 5/8/1998 25 48,880 3510 1890
26070 Petroleum Development Corp. (JV USEE) Egley #1 10/30/00 7 12,800 1240 1830
26078 Petroleum Development Corp. (JV USEE) Kleintop #1 12/20/98 7 10,620 3700 1440
26090 Petroleum Development Corp. (JV USEE) Ott #1 1/19/1999 18 31,000 3580 1650
26091 Petroleum Development Corp. (JV USEE) Becker #3 9/22/1999 10 19,660 3500 1860
26093 Petroleum Development Corp. (JV USEE) Ott #2 9/8/1999 10 18,330 3580 1830
26102 Petroleum Development Corp. (JV USEE) Hollabaugh #1 02/18/99 5 9,760 3620 1890
26108 Petroleum Development Corp. (JV USEE) Wilson #2 3/15/1999 14 19,400 3620 1350
26127 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #2 4/15/1999 14 43,010 3680 2700
26141 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #3 6/23/1999 12 26,940 3893 1920
26157 Petroleum Development Corp. (JV USEE) M. Couch #1 7/10/1999 12 28,440 3710 2160
26172 Petroleum Development Corp. (JV USEE) Ott #4 9/13/1999 10 22,070 3500 2130
26173 Petroleum Development Corp. (JV USEE) Ott #3 9/16/1999 10 16,420 3560 1470
26188 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #4 9/25/1999 10 17,250 3750 1740
26201 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #5 11/21/1999 6 13,300 3734 2040
26208 Petroleum Development Corp. (JV USEE) Walker #1 12/1/1999 6 9,920 4090 1530
26216 Petroleum Development Corp. (JV USEE) Allshouse #1 12/30/1999 7 14,190 3560 1950
26220 Petroleum Development Corp. (JV USEE) Shearer #1 3/4/2000 6 14,580 4068 2280
26221 Petroleum Development Corp. (JV USEE) Shearer #2 3/5/2000 4 7,550 4040 1800
26222 Petroleum Development Corp. (JV USEE) G. Couch #1 3/10/2000 4 8,160 4070 2040
26224 Petroleum Development Corp. (JV USEE) Walker #4 3/3/2000 4 14,100 4080 2910
26225 Petroleum Development Corp. (JV USEE) Walker #2 3/2/2000 4 9,540 4100 1890
26234 Petroleum Development Corp. (JV USEE) Stankay #1 3/6/2000 4 7,320 4100 1560
26255 Petroleum Development Corp. (JV USEE) Stankay #2 3/7/2000 4 7,900 4098 1680
26374 US Energy Exploration (JV Atlas) Sturiale #1 2/6/2002 30 2,271 3866 13
26426 US Energy Exploration (JV Atlas) Bafik #2 3/9/2002 29 16,308 3904 340
51
TOTAL MCF
THROUGH
09/30/04
ID MOS ON EXCEPT TOTAL LATEST 30
NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE WHERE NOTED LOGGERS DEPTH DAY PROD.
- ------ -------- --------- ------------- ---- ----------- ------------- ---------
26427 US Energy Exploration (JV Atlas) Canterbury #4 5/8/2001 39 46,758 3696 1073
26431 US Energy Exploration (JV Atlas) Canterbury #8 5/9/2001 39 24,452 3876 426
26437 US Energy Exploration (JV Atlas) Canterbury #12 4/30/2001 39 23,140 3791 449
26438 US Energy Exploration (JV Atlas) Canterbury #13 4/30/2001 39 11,700 3908 240
26439 US Energy Exploration (JV Atlas) Canterbury #15 7/10/2001 37 6,703 3776 65
26440 US Energy Exploration (JV Atlas) Canterbury #17 7/10/2001 37 8,832 3802 24
26442 US Energy Exploration (JV Atlas) Canterbury #20 5/22/2001 38 37,244 3944 753
26455 US Energy Exploration (JV Atlas) Canterbury #21 10/29/2001 33 24,347 3805 727
26458 US Energy Exploration (JV Atlas) Canterbury #3 5/7/2001 39 15,768 3701 252
26557 US Energy Exploration (JV Atlas) Barr #2 8/9/2001 36 38,741 3868 940
26558 US Energy Exploration (JV Atlas) Barr #3 8/25/2001 35 62,712 3898 1864
26561 US Energy Exploration (JV Atlas) Schrecengost #2 10/29/2001 33 17,858 3750 447
26562 US Energy Exploration (JV Atlas) Schrecengost #3 11/6/2001 33 16,469 3777 334
26566 US Energy Exploration (JV Atlas) P. White #1 11/16/2001 32 10,973 3950 557
26596 US Energy Exploration (JV Atlas) G. Couch #3 4/24/2002 27 6,033 4053 82
26598 US Energy Exploration (JV Atlas) G. Couch #5 4/24/2002 27 7,184 4355 134
26600 US Energy Exploration (JV Atlas) Dobrosky #2 10/10/2001 34 39,138 3752 989
26621 US Energy Exploration (JV Atlas) Canterbury #27 10/10/2001 34 52,429 3861 1234
26622 US Energy Exploration (JV Atlas) Canterbury #28 10/10/2001 34 60,547 3814 1638
26625 US Energy Exploration (JV Atlas) Barr #4 10/18/2001 33 39,637 3804 878
26627 US Energy Exploration (JV Atlas) Wilson #4 10/10/2001 34 49,537 3802 1742
26663 US Energy Exploration (JV Atlas) Crewe #1 12/31/2001 31 53,699 4058 1914
26669 US Energy Exploration (JV Atlas) R. White #1 11/16/2001 32 8,661 4062 266
26679 US Energy Exploration (JV Atlas) Canterbury #30 1/12/2002 31 46,997 4151 1595
26680 US Energy Exploration (JV Atlas) Canterbury #34 2/18/2002 29 30,644 4220 966
26681 US Energy Exploration (JV Atlas) Canterbury #31 1/29/2002 30 30,832 4212 753
26723 US Energy Exploration (JV Atlas) Bernabo #1 1/15/2002 31 9,889 4250 247
26730 US Energy Exploration (JV Atlas) Canterbury #32 7/10/2002 25 24,545 4195 892
26741 US Energy Exploration (JV Atlas) Crewe #4 8/16/2002 24 45,424 4153 1716
26742 US Energy Exploration (JV Atlas) Musser #1 2/11/2002 30 5,698 4296 304
26743 US Energy Exploration (JV Atlas) Filippini #2 2/2/2002 30 15,248 3882 421
52
TOTAL MCF
THROUGH
09/30/04
ID MOS ON EXCEPT TOTAL LATEST 30
NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE WHERE NOTED LOGGERS DEPTH DAY PROD.
- ------ -------- --------- ------------- ---- ----------- ------------- ---------
26756 US Energy Exploration (JV Atlas) P. White #4 2/25/2002 29 5,799 4281 243
26758 US Energy Exploration (JV Atlas) Crewe #5 2/12/2002 30 59,622 4156 2325
26788 US Energy Exploration (JV Atlas) Pomfret #1 3/29/2002 28 28,361 3817 462
26824 US Energy Exploration (JV Atlas) Stankay #5 1/9/2003 19 4,172 4037 411
26827 US Energy Exploration (JV Atlas) Boggs #6 1/3/2003 19 21,883 4104 709
26828 US Energy Exploration (JV Atlas) Boggs #7 9/28/2002 22 43,332 4219 1864
26833 US Energy Exploration (JV Atlas) Boggs #4 8/16/2002 24 20,065 4220 561
26844 US Energy Exploration (JV Atlas) Filippini #3 1/9/2003 19 23,303 3879 974
26865 US Energy Exploration (JV Atlas) Rumbaugh #1 11/14/2002 21 10,539 4600 515
26973 US Energy Exploration (JV Atlas) Andree #3 2/28/2003 17 9,146 4121 731
27024 US Energy Exploration (JV Atlas) Wheatley #1 2/6/2003 18 7,930 4211 580
27040 US Energy Exploration (JV Atlas) Pomfret #2 3/28/2003 16 10,731 3822 465
27044 US Energy Exploration (JV Atlas) Rumbaugh #2 3/26/2003 16 16,802 3808 585
27126 US Energy Exploration (JV Atlas) Andree #2 3/14/2003 17 13,579 3790 1107
27127 US Energy Exploration (JV Atlas) Wheatley #3 3/6/2003 17 20,023 4273 1930
32288 Petroleum Development Corp. (JV USEE) R. Henderson #1 7/1/1999 7 17,230 5213 2400
32418 Petroleum Development Corp. (JV USEE) C. Coleman #1 3/8/2000 4 6,960 4220 1650
32475 Petroleum Development Corp. (JV USEE) C. Coleman #2 3/9/2000 4 7,100 4401 1590
33016 US Energy Exploration (JV Atlas) Henderson #3 5/8/2002 27 27,283 4502 671
33042 US Energy Exploration (JV Atlas) Rosensteel #5 4/24/2002 27 36,409 4325 1023
33152 US Energy Exploration (JV Atlas) Graham #1 2/12/2003 18 24,600 4336 1196
33155 US Energy Exploration (JV Atlas) Boggs #9 1/31/2003 18 33,244 4393 1820
33157 US Energy Exploration (JV Atlas) Boggs #11 1/27/2003 18 16,467 4361 763
33159 US Energy Exploration (JV Atlas) Shearer #4 2/11/2003 18 14,629 4314 674
33202 US Energy Exploration (JV Atlas) J. Henderson #1 1/15/2003 19 16,229 4456 608
33273 US Energy Exploration (JV Atlas) Kapusta #2 1/31/2003 18 7,224 4280 396
33274 US Energy Exploration (JV Atlas) Bosch #2 1/21/2003 18 12,275 4392 517
33288 US Energy Exploration (JV Atlas) Kapusta #1 3/13/2003 17 12,395 4202 678
33305 US Energy Exploration (JV Atlas) Bosch #4 3/21/2003 16 19,715 4460 918
33306 US Energy Exploration (JV Atlas) Bosch #5 3/29/2003 16 11,137 4388 438
33313 US Energy Exploration (JV Atlas) Speranza #2 3/6/2003 17 8,978 4270 602
53
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA
54
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #14-2005(A) LIMITED PARTNERSHIP
ARMSTRONG PROSPECT AREA
PENNSYLVANIA
Dated: November 22, 2004
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...................................4
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 #14-2005(A) LIMITED PARTNERSHIP, contains acreage in Kiskiminetas
Township of Armstrong County and Young and Conemaugh Townships of Indiana
County, located in western Pennsylvania. Five (5) 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.
56
[GRAPHIC OMITTED]
Stratigraphically, in descending order, the potentially productive units of
the Upper Devonian Groups are: Hundred Foot, Gordon, Fifth, Bayard, Lower
Warren, Upper Speechley, Lower Speechley, Upper Balltown, Middle Balltown, Lower
Balltown, and First Bradford sands. These stratigraphic relationships are
illustrated in the diagram.
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.
57
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 at left.
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.
[GRAPHIC OMITTED]
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 #14-2005(A) 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 five (5) wells by ATLAS AMERICA PUBLIC #14-2005(A) 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.
59
LEASE INFORMATION
FOR
MCKEAN COUNTY, PENNSYLVANIA
60
OVERRIDING
ROYALTY
INTEREST TO
EFFECTIVE EXPIRATION LANDOWNER THE MANAGING
PROSPECT NAME COUNTY DATE* DATE* ROYALTY GENERAL PARTNER
------------- ------ ----- ----- ------- ---------------
1 Montgomery #4 McKean 5/7/2004 2/7/2005 12.5% 0%
2 Montgomery #5 McKean 5/7/2004 2/7/2005 12.5% 0%
3 Montgomery #6 McKean 5/7/2004 2/7/2005 12.5% 0%
4 Montgomery #9 McKean 5/7/2004 2/7/2005 12.5% 0%
5 Montgomery #10 McKean 5/7/2004 2/7/2005 12.5% 0%
6 Young Pine Run #22 McKean 2/6/2004 HBP 12.5% 0%
7 Young Pine Run #23 McKean 2/6/2004 HBP 12.5% 0%
8 Young Pine Run #24 McKean 2/6/2004 HBP 12.5% 0%
9 Young Pine Run #25 McKean 2/6/2004 HBP 12.5% 0%
10 Young Pine Run #26 McKean 2/6/2004 HBP 12.5% 0%
11 Young Pine Run #17 McKean 2/6/2004 HBP 12.5% 0%
12 Young Pine Run #18 McKean 2/6/2004 HBP 12.5% 0%
13 Young Pine Run #19 McKean 2/6/2004 HBP 12.5% 0%
14 Young Pine Run #20 McKean 2/6/2004 HBP 12.5% 0%
15 Young Pine Run #21 McKean 2/6/2004 HBP 12.5% 0%
16 Mallory WT. 4874 #1 McKean 8/12/2004 8/12/2005 12.5% 0%
17 Mallory WT. 4874 #2 McKean 8/12/2004 8/12/2005 12.5% 0%
18 Mallory WT. 4874 #3 McKean 8/12/2004 8/12/2005 12.5% 0%
19 Mallory WT. 4874 #4 McKean 8/12/2004 8/12/2005 12.5% 0%
20 Mallory WT. 4874 #5 McKean 8/12/2004 8/12/2005 12.5% 0%
21 Young-Kane #11 McKean 10/31/2003 10/31/2013 12.5% 0%
22 Young-Kane #12 McKean 10/31/2003 10/31/2013 12.5% 0%
23 Young-Kane #13 McKean 10/31/2003 10/31/2013 12.5% 0%
24 Young-Kane #14 McKean 10/31/2003 10/31/2013 12.5% 0%
25 Young-Kane #15 McKean 10/31/2003 10/31/2013 12.5% 0%
* HBP - Held by Production.
OVERRIDING ACRES TO BE
ROYALTY NET ASSIGNED TO
INTEREST TO REVENUE WORKING THE
PROSPECT NAME 3RD PARTIES INTEREST INTEREST NET ACRES PARTNERSHIP
------------- ----------- -------- -------- --------- -----------
1 Montgomery #4 0% 87.5% 100% 103.60 6
2 Montgomery #5 0% 87.5% 100% 103.60 6
3 Montgomery #6 0% 87.5% 100% 103.60 6
4 Montgomery #9 0% 87.5% 100% 103.60 6
5 Montgomery #10 0% 87.5% 100% 103.60 6
6 Young Pine Run #22 0% 87.5% 100% 1,400.60 5
7 Young Pine Run #23 0% 87.5% 100% 1,400.60 5
8 Young Pine Run #24 0% 87.5% 100% 1,400.60 5
9 Young Pine Run #25 0% 87.5% 100% 1,400.60 5
10 Young Pine Run #26 0% 87.5% 100% 1,400.60 5
11 Young Pine Run #17 0% 87.5% 100% 1,400.60 5
12 Young Pine Run #18 0% 87.5% 100% 1,400.60 5
13 Young Pine Run #19 0% 87.5% 100% 1,400.60 5
14 Young Pine Run #20 0% 87.5% 100% 1,400.60 5
15 Young Pine Run #21 0% 87.5% 100% 1,400.60 5
16 Mallory WT. 4874 #1 0% 87.5% 100% 8,884.81 5
17 Mallory WT. 4874 #2 0% 87.5% 100% 8,884.81 5
18 Mallory WT. 4874 #3 0% 87.5% 100% 8,884.81 5
19 Mallory WT. 4874 #4 0% 87.5% 100% 8,884.81 5
20 Mallory WT. 4874 #5 0% 87.5% 100% 8,884.81 5
21 Young-Kane #11 0% 87.5% 100% 2,432.00 5
22 Young-Kane #12 0% 87.5% 100% 2,432.00 5
23 Young-Kane #13 0% 87.5% 100% 2,432.00 5
24 Young-Kane #14 0% 87.5% 100% 2,432.00 5
25 Young-Kane #15 0% 87.5% 100% 2,432.00 5
* HBP - Held by Production.
61
LOCATION AND PRODUCTION MAPS
FOR
MCKEAN COUNTY, PENNSYLVANIA
62
[GRAPHIC OMITTED]
63
[GRAPHIC OMITTED]
64
[GRAPHIC OMITTED]
65
[GRAPHIC OMITTED]
66
[GRAPHIC OMITTED]
67
PRODUCTION DATA
FOR
MCKEAN COUNTY, PENNSYLVANIA
68
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
MAP DATE PRODUCTION TOTAL MCF LOGGERS LATEST 30
ID NUMBER OPERATOR WELL NAME REF COMPLT'D PERIOD GAS EQUIV. DEPTH DAY PROD.
- --------- -------- --------- --- -------- ------ ---------- ----- ---------
Atlas America, Inc. BRADFORD AIRPORT METER A - 4/04 - 9/04 44,430 (2) - 7,385
49406 Atlas America, Inc. Bradford Airport #16 02/06/04 - (1) 1946 -
49404 Atlas America, Inc. Bradford Airport #17 02/10/04 - (1) 1950 -
49405 Atlas America, Inc. Bradford Airport #18 01/27/04 - (1) 1944 -
49403 Atlas America, Inc. Bradford Airport #19 02/02/04 - (1) 1944 -
49402 Atlas America, Inc. Bradford Airport #20 02/04/04 - (1) 1944 -
49164 Atlas America, Inc. Bradford Airport #21 12/31/03 - (1) 1950 -
49165 Atlas America, Inc. Bradford Airport #22 01/03/04 - (1) 1950 -
49166 Atlas America, Inc. Bradford Airport #23 01/06/04 - (1) 1950 -
49167 Atlas America, Inc. Bradford Airport #24 01/08/04 - (1) 1950 -
49168 Atlas America, Inc. Bradford Airport #25 01/12/04 - (1) 1950 -
Atlas America, Inc. L MILLER METER #1 B - 6/04 - 9/04 48,255 (2) - 10,408
49318 Atlas America, Inc. Miller #1 01/30/04 - (1) 1944 -
49319 Atlas America, Inc. Miller #2 02/03/04 - (1) 1954 -
49320 Atlas America, Inc. Miller #3 02/05/04 - (1) 1950 -
49321 Atlas America, Inc. Miller #4 02/09/04 - (1) 1952 -
49322 Atlas America, Inc. Miller #5 02/11/04 - (1) 1954 -
49488 Atlas America, Inc. Miller #6 03/20/04 - (1) 1954 -
49475 Atlas America, Inc. Miller #7 03/23/04 - (1) 1953 -
49476 Atlas America, Inc. Miller #8 03/25/04 - (1) 1952 -
49477 Atlas America, Inc. Miller #9 03/27/04 - (1) 1954 -
49478 Atlas America, Inc. Miller #10 03/30/04 - (1) 1952 -
Atlas America, Inc. L MILLER METER #2 C
49816 Atlas America, Inc. Miller #11 11/14/04 - (1) 2755 NA
49799 Atlas America, Inc. Miller #12 11/16/04 - (1) -
49428 Atlas America, Inc. Miller #14 11/12/04 - (1) 2751 -
49429 Atlas America, Inc. Miller #15 11/9/04 - (1) 2765 -
48790 Atlas America, Inc. Miller #24 11/6/04 - (1) 2655 -
Atlas America, Inc. YOUNG PINE RUN METER D
49589 Atlas America, Inc. Young Pine Run #1 08/03/04 - (1) 2417' NA
49590 Atlas America, Inc. Young Pine Run #2 08/04/04 - (1) 2437' -
69
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
MAP DATE PRODUCTION TOTAL MCF LOGGERS LATEST 30
ID NUMBER OPERATOR WELL NAME REF COMPLT'D PERIOD GAS EQUIV. DEPTH DAY PROD.
- --------- -------- --------- --- -------- ------ ---------- ----- ---------
49638 Atlas America, Inc. Young Pine Run #3 08/06/04 - (1) 2258' -
49591 Atlas America, Inc. Young Pine Run #4 08/10/04 - (1) 2256' -
49592 Atlas America, Inc. Young Pine Run #5 08/12/04 - (1) 2204' -
YOUNG PINE RUN AREA (4) E
35713 Canton Oil & Gas Co Tally Ho #101 04/03/78 1991-1994 7,805 (3) 2344 NA
35714 Canton Oil & Gas Co Tally Ho #102 06/27/78 1991-1994 8,177 (3) 2400 -
35715 Canton Oil & Gas Co Tally Ho #103 02/23/78 1991-1994 8,177 (3) 2244 -
35716 Canton Oil & Gas Co Tally Ho #104 06/05/78 1991-1994 8,177 (3) 2195 -
35717 Canton Oil & Gas Co Tally Ho #105 11/10/78 1991-1994 7,805 (3) 2170 -
35718 Canton Oil & Gas Co Tally Ho #106 06/14/79 1991-1994 7,805 (3) 2550 -
35719 Canton Oil & Gas Co Tally Ho #107 07/17/79 1991-1994 7,805 (3) 2550 -
35720 Canton Oil & Gas Co Tally Ho #108 09/11/78 1991-1994 7,805 (3) 2475 -
35721 Canton Oil & Gas Co Tally Ho #109 02/28/78 1991-1994 7,805 (3) 2344 -
35722 Canton Oil & Gas Co Tally Ho #110 03/25/78 1991-1994 7,805 (3) 2244 -
35723 Canton Oil & Gas Co Tally Ho #111 05/22/79 1991-1994 7,805 (3) 2600 -
35724 Canton Oil & Gas Co Tally Ho #112 04/16/79 1991-1994 7,805 (3) 2600 -
35725 Canton Oil & Gas Co Tally Ho #113 04/03/79 1991-1994 7,805 (3) 2600 -
35726 Canton Oil & Gas Co Tally Ho #114 06/14/78 1991-1994 7,805 (3) 2465 -
35727 Canton Oil & Gas Co Tally Ho #115 06/14/78 1991-1994 7,805 (3) 2350 -
35734 Canton Oil & Gas Co Tally Ho #W-107 07/25/78 1993-1994 334 (3) 2395 -
35735 Canton Oil & Gas Co Tally Ho #W-108 07/12/78 1993-1994 334 (3) 2475 -
35736 Canton Oil & Gas Co Tally Ho #W-109 07/07/78 1993-1994 334 (3) 2475 -
35737 Canton Oil & Gas Co Tally Ho #W-110 05/18/78 1993-1994 334 (3) 2281 -
35738 Canton Oil & Gas Co Tally Ho #W-111 05/26/78 1993-1994 334 (3) 2208 -
35739 Canton Oil & Gas Co Tally Ho #W-112 11/03/78 1993-1994 334 (3) 2168 -
35740 Canton Oil & Gas Co Tally Ho #W-113 05/29/79 1993-1994 334 (3) 1960 -
35741 Canton Oil & Gas Co Tally Ho #W-114 04/20/79 1993-1994 334 (3) 2600 -
35742 Canton Oil & Gas Co Tally Ho #W-115 03/13/79 1993-1994 334 (3) 2575 -
35743 Canton Oil & Gas Co Tally Ho #W-116 02/07/79 1993-1994 334 (3) 2460 -
35744 Canton Oil & Gas Co Tally Ho #W-117 06/20/78 1993-1994 334 (3) 2350 -
35745 Canton Oil & Gas Co Tally Ho #W-118 03/08/78 1993-1994 334 (3) 2244 -
YOUNG KANE AREA F NA
70
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
MAP DATE PRODUCTION TOTAL MCF LOGGERS LATEST 30
ID NUMBER OPERATOR WELL NAME REF COMPLT'D PERIOD GAS EQUIV. DEPTH DAY PROD.
- --------- -------- --------- --- -------- ------ ---------- ----- ---------
7051 East Resources Inc WT 3131 #58 1922 1990-91, 1998 338 (3) 2028 -
7057 East Resources Inc WT 3131 #71 1927 1990-91, 1998 338 (3) 1886 -
7060 East Resources Inc WT 3131 #76 10/24/39 1998 64 (3) 2624 -
46055 MSL Oil & Gas Corp Lot 263 #12 02/16/89 1990-1998 7,488 (3) 1325 -
46056 MSL Oil & Gas Corp Lot 263 #13 02/09/89 1990-1998 7,488 (3) 1800 -
46068 MSL Oil & Gas Corp Brian Lease Lot 263 #7 08/22/89 1990-1998 1,128 (3) 1748 -
46069 MSL Oil & Gas Corp Brian Lease Lot 263 #8 08/15/89 1990-1998 1,128 (3) 1619 -
46070 MSL Oil & Gas Corp Brian Lease Lot 263 #9 08/11/89 1990-1998 1,128 (3) 1536 -
46072 MSL Oil & Gas Corp Brian Lease Lot 263 #11 08/10/89 1990-1998 1,128 (3) 1870 -
46935 PA Gen Energy Co Lot 222 #1024 07/08/97 1997-1998 18,618 (3) 2097 -
MALLORY WARRANT 4874 G
12384 F & Wm Cardamone Cardamone #2 01/01/64 NA NA 1225 NA
12273 Cotton Well Drilling Stoltz #5 1901 06/94-11/94 72 (3) 1100 NA
12274 Cotton Well Drilling Stoltz #6 1901 06/94-11/95 72 (3) 1100 NA
12275 Cotton Well Drilling Stoltz #7 1901 06/94-11/96 72 (3) 1100 NA
22957 Pecora Enterprises Roy Williams #5 08/27/63 1996 & 1998 42 (3) 913 NA
23161 Pecora Enterprises Williams #6 06/23/64 1996 & 1998 42 (3) 924 NA
23169 Ward Brothers Cardamone #1 05/23/64 NA NA 1112 NA
23170 Ward Brothers Cardamone #2 05/18/64 NA NA 1085 NA
23193 Pecora Enterprises Williams #7 08/25/64 NA NA 786 NA
23195 Pecora Enterprises Erickson #1 09/25/64 NA NA 1067 NA
23196 Pecora Enterprises Erickson #2 11/64 NA NA 1005 NA
23285 Pecora Enterprises Williams #8 05/11/65 NA NA 960 NA
23394 Duane Vaughn Gloria Jack Dresser USA #1 08/18/65 NA NA 867 NA
23396 David L Hill Cobb #1 09/24/65 1996 & 1998 42 (3) 978 NA
23484 David L Hill Cobb #2 04/07/66 1996 & 1998 42 (3) 990 NA
23517 S & M Enterprises Hopley #1 11/10/65 NA NA 1008 NA
23518 Smith & Mitchno McConnel #1 08/10/65 NA NA 1028 NA
23519 Smith & Mitchno McConnel #2 11/01/65 NA NA 1036 NA
23520 David L Hill Cobb #3 06/18/66 1996 & 1998 42 (3) 1042 NA
23573 David L Hill Cobb #4 08/26/66 1996 & 1998 42 (3) 1055 NA
23687 David L Hill Cobb #5 04/05/67 1996 & 1998 42 (3) 1000 NA
23792 David L Hill Cobb #6 06/18/67 1996 & 1998 42 (3) 1062 NA
71
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
MAP DATE PRODUCTION TOTAL MCF LOGGERS LATEST 30
ID NUMBER OPERATOR WELL NAME REF COMPLT'D PERIOD GAS EQUIV. DEPTH DAY PROD.
- --------- -------- --------- --- -------- ------ ---------- ----- ---------
23899 David L Hill Cobb #7 08/10/67 1996 & 1998 42 (3) 1000 NA
24055 Pecora Enterprises Williams #9 1968 1996 & 1998 42 (3) 980 NA
24056 Pecora Enterprises Williams #10 06/68 NA NA 962 NA
24192 Pecora Enterprises Williams #11 08/07/68 1996 & 1998 42 (3) 1004 NA
26057 David L Hill Cobb #8 05/12/70 1996 & 1998 42 (3) 1004 NA
26664 Pecora Enterprises Erickson #5 09/25/71 NA NA 1060 NA
32058 F & Wm Cardamone Cardamone #3 07/30/72 NA NA 1552 NA
39972 Witco Corp Mallory Wt 4874 #M31 11/19/81 NA NA 1600 NA
39973 Witco Corp Mallory Wt 4874 #M32 11/25/81 NA NA 2000 NA
42362 Cotton Well Drilling Stoltz #T-1 12/08/83 NA NA 1096 NA
42363 Cotton Well Drilling Stoltz #T-2 12/10/83 NA NA 1100 NA
46170 Belden & Blake Corp Bradford Water Auth #BWA-84 03/02/90 1991-1998 18,041 1411 NA
46215 Belden & Blake Corp Mallory (Wt 4339) #24 06/22/90 1991-1998 14,695 1469 NA
46358 Belden & Blake Corp Mallory Wt 4339 #H-7 07/02/92 06/92-1998 15,720 1497 NA
46446 Belden & Blake Corp Mallory Wt 4339 #H-10 10/04/93 1994-1998 6,471 1400 NA
46496 Belden & Blake Corp Mallory Wt 4339 #H-23 05/10/94 05/94-1998 24,624 1350 NA
46566 Belden & Blake Corp Habgood #H-11 08/31/95 1995-1998 5,019 1485 NA
(1) Individual well production is not monitored. Instead, production from a
well is combined with production from other wells and the combined
production is measured at one meter site. The volume of production from
each well connected to the same meter could vary significantly from well
to well. Thus, you are not able to analyze the consistency of the
production among the various wells.
(2) This amount represents the combined production from multiple wells.
(3) Combined meters, jointly produced, or common facility production is
allocated to individual wells reported to the Pennsylvania Department of
Environmental Protection, which in turn makes this reported production
available to the public. Thus, despite what the Pennsylvania Department of
Environmental Protection reports, the volume of production could vary
significantly from well to well. Thus, you are not able to analyze the
consistency of the production among the various wells. Also, annual
production totals do not always represent 365 days of continuous
production, offsets to the Young Kane lease have in some years, less than
30 days of reported production.
(4) The wells are representative, but not inclusive of all wells in the area
since many wells were produced before production records were required.
Thus, the production information for wells offsetting the Young Pine Run
lease are representative of production from area wells in an established
Bradford 3rd trend and water flood operation and are not intended to set
forth the actual production from the wells since that information is not
available.
72
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
MCKEAN COUNTY, PENNSYLVANIA
73
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #14-2005(A) LIMITED PARTNERSHIP
MCKEAN PROSPECT AREA
PENNSYLVANIA
Dated: November 22, 2004
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
OBJECTIVE.............................................................2
AREA OF INVESTIGATION.................................................2
METHODOLOGY...........................................................2
MCKEAN PROSPECT AREA...........................................................2
DRILLING ACTIVITY.....................................................2
GEOLOGY...............................................................2
STRATIGRAPHY, LITHOLOGY & DEPOSITION.........................2
RESERVOIR CHARACTERISTICS....................................3
PRODUCTION............................................................3
STATEMENTS.....................................................................4
CONCLUSION............................................................4
DISCLAIMER............................................................4
NON-INTEREST..........................................................4
74
INVESTIGATION SUMMARY
OBJECTIVE
The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the McKean 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 #14-2005(A) LIMITED PARTNERSHIP, contains acreage in Lafayette,
Corydon and Wetmore Townships of McKean County, Pennsylvania. Twenty-five (25)
drilling prospects have currently been designated for this program in the
prospect area, which will be targeted to produce oil and natural gas from Upper
Devonian reservoirs, found at depths from 1200 feet to 2500 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.
MCKEAN PROSPECT AREA
DRILLING ACTIVITY
The proposed drilling area lies within a region of north central
Pennsylvania which has seen activity for more than the past 150 years in terms
of oil production. Modern development within and adjacent to the McKean Prospect
Area has seen increased activity in the past several years with exploration for,
and exploitation of primarily natural gas reserves. Atlas continues to identify
and extend productive trends and has drilled 65 wells. Drilling is ongoing as of
the date of this report with recent wells displaying favorable initial drilling
and completion results.
GEOLOGY
STRATIGRAPHY, LITHOLOGY & DEPOSITION
Depositional environments in the Upper Devonian Bradford Group of McKean
County are of near shore to offshore marine settings.
The Bradford Group reservoir sands in this area consist of the Bradford
First, Watsonville, Dewdrop, Cherry Grove, Tiona, Bradford Second, Harrisburg
Run, Bradford Third and Lewis Run. Diagram illustrates stratigraphic
relationships.
[GRAPHIC OMITTED]
75
The TIONA SAND is a primary target in all wells in this area.
Stratigraphically, it is the highest, or youngest Balltown sand within the
Bradford Group. Generally sand development in the Tiona interval is most
favorable when sand encountered is typically twenty (20) or more feet thick with
10-15% porosities.
The BRADFORD SECOND SAND is another primary target in the area. It directly
underlies the Tiona in the Balltown section of the Bradford Group. The Bradford
Second interval is most favorable when ten (10) or more feet of sand is
encountered. Porosities typically range from 9% to 16%.
Secondary targets may also show development. Production has occurred from
the BRADFORD FIRST, CHERRY GROVE, BRADFORD THIRD and the LEWIS RUN sand within
the prospect area.
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 typical log suite with gamma,
bulk density, neutron, induction and temperature logs showing sand development
in the primary Upper Devonian reservoirs in this area is illustrated.
[GRAPHIC OMITTED]
PRODUCTION
The McKean prospect area produces from several reservoir sands. 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 found in this area.
76
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #14-2005(A) LIMITED PARTNERSHIP, which will consist of
developmental drilling of Upper Devonian reservoirs in McKean County,
Pennsylvania. It is the professional opinion of UEDC that the drilling of the
twenty-five (25) wells by ATLAS AMERICA PUBLIC #14-2005(A) 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.
77
MAP OF TENNESSEE
78
[GRAPHIC OMITTED]
79
LEASE INFORMATION
FOR
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
80
OVERRIDING ROYALTY
INTEREST TO THE
PROSPECT EFFECTIVE EXPIRATION LANDOWNER MANAGING GENERAL
NAME COUNTY DATE DATE* ROYALTY PARTNER
---- ------ ---- ----- ------- -------
1 1BR Scott 10/12/2001 10/12/2006 15.00% 0.00%
2 2BR Scott 10/13/2001 10/12/2006 15.00% 0.00%
3 1CC Morgan 1/1/2001 1/1/2006 12.50% 0.00%
4 3CC Anderson 1/2/2001 1/1/2006 12.50% 0.00%
5 2CC Anderson 9/1/2001 9/1/2006 12.50% 0.00%
6 4CC Morgan 9/2/2001 9/1/2006 12.50% 0.00%
7 1HW Morgan 10/1/2001 HBP(1) 12.50% (4) 0.00%
OVERRIDING ACRES TO BE
ROYALTY INTEREST ASSIGNED TO
PROSPECT TO 3RD PARTY NET REVENUE WORKING THE
NAME (KNOX ENERGY) INTEREST INTEREST NET ACRES PARTNERSHIP
---- ------------- -------- -------- --------- -----------
1 1BR 3.125% (2) 81.87500% 100.00% (2) 45,755.00 40
2 2BR 3.125% (2) 81.87500% 100.00% (2) 45,755.00 40
3 1CC 3.125% (2) 84.375% 100.00% (2) 26,776.00 40 (3)
4 3CC 3.125% (2) 84.375% 100.00% (2) 26,777.00 40 (3)
5 2CC 3.125% (2) 84.375% 100.00% (2) 27,639.00 40 (3)
6 4CC 3.125% (2) 84.375% 100.00% (2) 27,639.00 40 (3)
7 1HW 3.125% (2) 84.375% 100.00% (2) 28,483.00 40
(1) Held by production, provided the lessee maintains its annual drilling
commitment.
(2) The 3.125% overriding royalty interest to Knox Energy, LLC in a well will
be reduced if Knox chooses to participate in the development of a well.
Knox has the right to participate in any or all wells by taking 50% or
less of the working interest in the well. If Knox participates in a well
for a 50% working interest, then the overriding royalty will be 1.5625%.
If Knox participates in a well for less than 50% of the working interest,
then its overriding royalty interest in the well will be pro rated between
3.125% and 1.5625% based on the percentage of its working interest in the
well. See "Proposed Activities - Interests of Parties."
(3) Forty acres are earned for each oil well and 160 acres are earned for each
gas well.
(4) 12.5% of the gross proceeds free of all costs and expenses whatsoever for
all gas sold at a price of $3.00 per MMBtu or less. For all gross proceeds
in excess of $3.00 per MMBtu, Heartwood will receive an additional royalty
equal to 3% of the gross proceeds received by Lessee in excess of $3.00
per MMBtu. The additional payment to Heartwood for gas sold at a price
greater than $3.00 per MMBtu will proportionately reduce the Net Revenue
Interests of all of the working interest owners in the well as set forth
in the table by a total of 3%.
81
LOCATION AND PRODUCTION MAPS
FOR
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
82
[GRAPHIC OMITTED]
83
[GRAPHIC OMITTED]
84
[GRAPHIC OMITTED]
85
[GRAPHIC OMITTED]
86
PRODUCTION DATA
FOR
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
87
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 ON 10/31/04 EXCEPT TOTAL LATEST 30
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE WHERE NOTED LOGGERS DEPTH DAY PROD.
- --------- -------- --------- ------------- ---- ----------- ------------- ---------
09813 New River Energy RA 1001 12/20/01 28 8,227 5748 223
09917 Knox Energy BR 1007 09/04/02 18 6,582 6081 156
10177 Knox Energy BR 1009 09/24/03 N/A N/A 2755 N/A
10185 Knox Energy BR 1014 09/30/03 N/A N/A 4225 N/A
10425 Knox Energy BR 1017 10/08/04 N/A N/A 2816 N/A
10424 Knox Energy BR1018 10/01/04 N/A N/A 2665 N/A
08660 Knox Energy HW 1002 05/23/03 20 11,486 4578 62
10062 Knox Energy HW 1004 05/20/03 16 4,140 4591 81
09897 Knox Energy HW 1005 05/29/03 20 21,358 4716 554
10061 Knox Energy HW 1007 05/15/03 17 613 4588 11
09907 Knox Energy HW 1009 08/15/02 20 27,055 4713 691
10114 Knox Energy HW 1010 07/14/03 15 18,976 2557 703
10156 Knox Energy HW 1011 09/04/03 12 16,177 2267 687
10172 Knox Energy HW 1012 09/09/03 4 2,043 4188 N/A
9724 New River Energy CC 1001 04/24/01 28 17,598 5732 473
9738 New River Energy CC 1002 04/29/01 28 10,143 3344 251
9790 New River Energy CC 1003 03/25/01 28 23,464 3184 531
9801 Knox Energy CC 1004 10/03/02 28 36,978 5007 914
9834 Knox Energy CC 1005 12/20/01 28 166,291 6171 4,135
9840 Knox Energy CC 1006 01/15/02 28 13,032 6159 N/A
9855 Knox Energy CC 1007 02/17/02 28 4,406 5930 74
9858 Knox Energy CC 1008 02/28/02 28 4,511 6010 N/A
10110 Knox Energy CC 1012 07/11/03 12 6,962 3303 496
10200 Knox Energy CC 1014 11/02/03 8 14,608 5883 1,875
10152 Knox Energy CC 1015 09/17/03 13 17,929 3980 718
9867 Knox Energy CC 1016 07/18/03 15 15,852 4187 1,444
10136 Knox Energy CC 1017 12/16/01 15 44,007 4329 2,604
10153 Knox Energy CC 1021 08/29/03 14 9,561 3464 1,069
10209 Knox Energy CC 1022 11/06/03 7 33,200 3955 3,787
10208 Knox Energy CC 1023 11/04/03 8 30,577 4409 3,198
10218 Knox Energy CC 1024 10/28/03 8 22,524 3926 2,363
10219 Knox Energy CC 1025 10/28/03 7 23,891 3611 2,830
10220 Knox Energy CC 1026 12/05/03 5 8,387 4685 1,283
88
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 ON 10/31/04 EXCEPT TOTAL LATEST 30
ID NUMBER OPERATOR WELL NAME DATE COMPLT'D LINE WHERE NOTED LOGGERS DEPTH DAY PROD.
- --------- -------- --------- ------------- ---- ----------- ------------- ---------
10236 Knox Energy CC 1027 11/09/03 10 48,716 3932 3,233
10086 Knox Energy CC 2001 06/16/03 11 2,384 6918 138
10125 Knox Energy CC 2004 08/10/03 11 8,631 4616 316
10123 Knox Energy CC 2005 07/29/03 13 5,088 6709 246
10144 Knox Energy CC 2006 08/22/03 11 36,719 5074 3,635
10207 Knox Energy CC 2007 10/18/03 10 18,906 4406 1,743
10225 Knox Energy CC 2008 11/11/03 10 2,660 5092 314
10226 Knox Energy CC 2009 02/05/04 10 19,793 4418 1,190
- --------------------------------------------------------------------------------
The Production Data below is presented on the basis of all of the wells in an
entire field, rather than on a well-by-well basis. The volume of production from
any given well in the field could vary significantly from that of the other
wells in the field. Thus, you are not able to analyze the consistency of the
production from the wells in the field.
MAP FIELD DISCOVERY NO. TOTAL MCF PRODUCING
REFERENCE NAME DATE OF WELLS EQUIV. FORMATION
- --------- ---- ---- -------- ------ ---------
A Lick Branch 1976 27 7,229,450/1993 Fort Payne
B Low Gap/Rueben Hollow 1976 58 6,621,000/1993 Monteagle/Fort Payne
C Pilot Mountain 1981 13 1,100,300/1993 Fort Payne
D Wind Rock 1976 6 743,400/1993 Monteagle
89
UEDC'S
GEOLOGIC EVALUATION
FOR THE
CURRENTLY PROPOSED WELLS
IN
ANDERSON, CAMPBELL, MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE
90
GEOLOGIC EVALUATION
ATLAS AMERICA PUBLIC #14-2005(A) LIMITED PARTNERSHIP
TENNESSEE KNOX ENERGY PROSPECT AREA
PENNSYLVANIA
Dated: November 22, 2004
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
TENNESSEE KNOX ENERGY PROSPECT AREA............................................2
DRILLING ACTIVITY.....................................................2
GEOLOGY...............................................................3
STRATIGRAPHY, LITHOLOGY & DEPOSITION.........................3
RESERVOIR CHARACTERISTICS....................................4
PRODUCTION............................................................4
STATEMENTS.....................................................................5
CONCLUSION............................................................5
DISCLAIMER............................................................5
NON-INTEREST..........................................................5
91
INVESTIGATION SUMMARY
OBJECTIVE
The purpose of the following investigation is to evaluate the geologic
feasibility and further development of the Tennessee Knox Energy 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 #14-2005(A) L.P. PROGRAM, contains acreage in Scott, Anderson and
Morgan Counties of Tennessee. Seven (7) drilling prospects have currently been
designated for this program in the prospect area, which will be targeted to
produce natural gas from Mississippian and Devonian reservoirs, found at depths
from 1500 feet to 5000 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.
TENNESSEE KNOX ENERGY PROSPECT AREA
DRILLING ACTIVITY
The proposed drilling area lies in the Appalachian Plateau portion of
northern Tennessee. This historically oil producing area has seen recent
activity targeting zones that have yielded commercial gas production. Knox
Energy (KXE) has been actively drilling for natural gas for over three years and
has established production in a few locales within this vast area. Drilling is
ongoing as of the date of this report with recent wells displaying favorable
initial drilling and completion results.
92
GEOLOGY
STRATIGRAPHY, LITHOLOGY & DEPOSITION
The depositional environments for the Mississippian carbonates range from
shelf to lagoon and near shore settings. The Devonian or Chattanooga Shale
formed in an organic rich sea offshore from the Catskill Delta.
The Mississippian reservoirs consist of the Monteagle limestone, St. Louis
dolomite, Warsaw limey siltstone and the Ft. Payne cherty limestone. The
Chattanooga Shale underlies the Ft. Payne. Diagram illustrates stratigraphic
relationships.
The primary target in all wells in this area is the MONTEAGLE LIMESTONE.
This limestone contains thick deposits of Oolites, which provide porosity as
high as 20%. Some wells have encountered as much as 30 feet of this reservoir.
The DEVONIAN SHALE is another primary target in the area. This reservoir
underlies the Mississippian carbonates and is found in all wells throughout the
area. This formation is not only a reservoir when fractured, but is considered
the source of the hydrocarbons found in the overlying carbonates.
Secondary targets may also show development. The FT. PAYNE is the primary
reservoir for the oil in adjacent fields found north and west of the prospect
area. The ST. LOUIS and WARSAW reservoirs have been encountered less often, but
could be considerable contributors in yet to be developed parts of the vast
prospect area.
[GRAPHIC OMITTED]
93
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable barrier
trapping commercial quantities of natural gas or oil in a more permeable medium.
In the Mississippian carbonate reservoirs this occurs in two ways. One way is
when ooids (carbonate sands) are formed and deposited (oolites) and are encased
in less permeable limestones. Another way is when limestone changes to dolomite
during a change ("diagenesis") at the atomic level of the rock.
Electric well logs (right) can be used in conjunction with production to
interpret reservoir parameters. When the carbonates in the Mississippian
reservoirs develop porosity in excess of 5%, the permeability of the reservoir
can become great enough to allow commercial production of natural gas. When
small, naturally occurring cracks or fractures exist in the Chattanooga Shale,
permeability of the reservoir is enhanced. Audio logs can detect the small
amounts of natural gas that flow from the shale.
[GRAPHIC OMITTED]
PRODUCTION
The Tennessee Knox Energy 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.
94
STATEMENTS
CONCLUSION
UEDC has conducted a geologic feasibility study of the drilling area for
ATLAS AMERICA PUBLIC #14-2005(A) L.P. PROGRAM, which will consist of
developmental drilling of Mississippian and Devonian reservoirs in Scott,
Anderson and Morgan Counties of Tennessee. It is the professional opinion of
UEDC that the drilling of the seven (7) wells by ATLAS AMERICA PUBLIC
#14-2005(A) L.P. PROGRAM is supported by sufficient geologic and engineering
data.
DISCLAIMER
For the purpose of this evaluation, UEDC did not visit any leaseholds or
inspect any of the associated production equipment. Likewise, UEDC has no
knowledge as to the validity of title, liabilities, or corporate matters
affecting these properties. UEDC does not warrant individual well performance.
NON-INTEREST
We hereby confirm that UEDC is an independent consulting firm and that
neither this firm or any of it's employees, contract consultants, or officers
has, or is committed to acquire any interest, directly or indirectly, in Atlas
Resources, Inc.; nor is this firm, or any employee, contract consultant, or
officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm
that neither the employment of, nor payment of compensation received by UEDC in
connection with this report, is on a contingent basis.
Respectfully submitted,
/s/ Robin Anthony
UEDC, INC.
95
EXHIBIT (A)
FORM OF
AMENDED AND RESTATED CERTIFICATE
AND AGREEMENT OF LIMITED PARTNERSHIP
FOR
ATLAS AMERICA PUBLIC #14-2005(A) L.P.
[FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED
PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2005(B) L.P.]
TABLE OF CONTENTS
SECTION NO. DESCRIPTION PAGE
I. FORMATION
1.01 Formation.....................................1
1.02 Certificate of Limited Partnership............1
1.03 Name, Principal Office and Residence..........1
1.04 Purpose.......................................1
II. DEFINITION OF TERMS
2.01 Definitions...................................2
III. SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
3.01 Designation of Managing General Partner and
Participants.............................10
3.02 Participants.................................10
3.03 Subscriptions to the Partnership.............11
3.04 Capital Contributions of the Managing
General Partner..........................12
3.05 Payment of Subscriptions.....................13
3.06 Partnership Funds............................13
IV. CONDUCT OF OPERATIONS
4.01 Acquisition of Leases........................14
4.02 Conduct of Operations........................16
4.03 General Rights and Obligations of the
Participants and Restricted and
Prohibited Transactions..................20
4.04 Designation, Compensation and
Removal of Managing General
Partner and Removal of Operator..........30
4.05 Indemnification and Exoneration..............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..................................38
5.03 Allocation of Income, Deductions and
Credits..................................40
5.04 Elections....................................41
5.05 Distributions................................42
VI. TRANSFER OF INTERESTS
6.01 Transferability..............................42
6.02 Special Restrictions on Transfers............43
6.03 Right of Managing General
Partner to Hypothecate and/or
Withdraw Its Interests.......................44
6.04 Presentment..................................45
TABLE OF CONTENTS
SECTION NO. DESCRIPTION PAGE
VII. DURATION, DISSOLUTION, AND WINDING UP
7.01 Duration.....................................47
7.02 Dissolution and Winding Up...................47
VIII. MISCELLANEOUS PROVISIONS
8.01 Notices......................................48
8.02 Time.........................................49
8.03 Applicable Law...............................49
8.04 Agreement in Counterparts....................49
8.05 Amendment....................................49
8.06 Additional Partners..........................49
8.07 Legal Effect.................................49
EXHIBITS
EXHIBIT (I-A) - Form of Managing General Partner Signature Page
EXHIBIT (I-B) - Form of Subscription Agreement
EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas
America Public #14-2005(A) L.P. [Atlas America
Public #14-2005(B) L.P.]
i
FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2005(A) L.P.
[FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2005(B) L.P.]
THIS AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP
("AGREEMENT"), amending and restating the original Certificate of Limited
Partnership, is made and entered into as of _____________________, 2005, by and
among Atlas Resources, Inc., referred to as "Atlas" or the "Managing General
Partner," and the remaining parties from time to time signing a Subscription
Agreement for Limited Partner Units, these parties sometimes referred to as
"Limited Partners," or for Investor General Partner Units, these parties
sometimes referred to as "Investor General Partners."
ARTICLE I
FORMATION
1.01. FORMATION. The parties have formed a limited partnership under the
Delaware Revised Uniform Limited Partnership Act on the terms and conditions set
forth in this Agreement.
1.02. CERTIFICATE OF LIMITED PARTNERSHIP. This document is not only an agreement
among the parties, but also is the Amended and Restated Certificate and
Agreement of Limited Partnership of the Partnership. This document shall be
filed or recorded in the public offices required under applicable law or deemed
advisable in the discretion of the Managing General Partner. Amendments to the
certificate of limited partnership shall be filed or recorded in the public
offices required under applicable law or deemed advisable in the discretion of
the Managing General Partner.
1.03. NAME, PRINCIPAL OFFICE AND RESIDENCE.
1.03(a). NAME. The name of the Partnership is Atlas America Public #14-2005(A)
L.P. [Atlas America Public #14-2005(B) L.P.].
1.03(b). RESIDENCE. The residence of the Managing General Partner is its
principal place of business at 311 Rouser Road, Moon Township, Pennsylvania
15108, which shall also serve as the principal place of business of the
Partnership.
The residence of each Participant shall be as set forth on the Subscription
Agreement executed by the Participant.
All addresses shall be subject to change on notice to the parties.
1.03(c). AGENT FOR SERVICE OF PROCESS. The name and address of the agent for
service of process shall be Andrew M. Lubin at 110 S. Poplar Street, Suite 101,
Wilmington, Delaware 19801.
1.04. PURPOSE. The Partnership shall engage in all phases of the natural gas and
oil business. This includes, without limitation, exploration for, development
and production of natural gas and oil on the terms and conditions set forth
below and any other proper purpose under the Delaware Revised Uniform Limited
Partnership Act.
The Managing General Partner may not, without the affirmative vote of
Participants whose Units equal a majority of the total Units, do the following:
(i) change the investment and business purpose of the Partnership; or
(ii) cause the Partnership to engage in activities outside the stated
business purposes of the Partnership through joint ventures with other
entities.
1
ARTICLE II
DEFINITION OF TERMS
2.01. DEFINITIONS. As used in this Agreement, the following terms shall have the
meanings set forth below:
1. "Administrative Costs" means all customary and routine expenses
incurred by the Sponsor for the conduct of Partnership administration,
including: in-house legal, finance, in-house accounting, secretarial,
travel, office rent, telephone, data processing and other items of a
similar nature. Administrative Costs shall be limited as follows:
(i) no Administrative Costs charged shall be duplicated under any
other category of expense or cost; and
(ii) no portion of the salaries, benefits, compensation or
remuneration of controlling persons of the Managing General
Partner shall be reimbursed by the Partnership as
Administrative Costs. Controlling persons include directors,
executive officers and those holding 5% or more equity
interest in the Managing General Partner or a person having
power to direct or cause the direction of the Managing General
Partner, whether through the ownership of voting securities,
by contract, or otherwise.
2. "Administrator" means the official or agency administering the
securities laws of a state.
3. "Affiliate" means with respect to a specific person:
(i) any person directly or indirectly owning, controlling, or
holding with power to vote 10% or more of the outstanding
voting securities of the specified person;
(ii) any person 10% or more of whose outstanding voting securities
are directly or indirectly owned, controlled, or held with
power to vote, by the specified person;
(iii) any person directly or indirectly controlling, controlled by,
or under common control with the specified person;
(iv) any officer, director, trustee or partner of the specified
person; and
(v) if the specified person is an officer, director, trustee or
partner, any person for which the person acts in any such
capacity.
4. "Agreement" means this Amended and Restated Certificate and Agreement
of Limited Partnership, including all exhibits to this Agreement.
5. "Anthem Securities" means Anthem Securities, Inc., whose principal
executive offices are located at 311 Rouser Road, P.O. Box 926, Moon
Township, Pennsylvania 15108-0926.
6. "Assessments" means additional amounts of capital which may be
mandatorily required of or paid voluntarily by a Participant beyond
his subscription commitment.
7. "Atlas" means Atlas Resources, Inc., a Pennsylvania corporation, whose
principal executive offices are located at 311 Rouser Road, Moon
Township, Pennsylvania 15108.
8. "Atlas America Public #14-2004 Program" means a series of up to three
limited partnerships entitled Atlas America Public #14-2004 L.P.,
Atlas America Public #14-2005(A) L.P. and Atlas America Public
#14-2005(B) L.P.
9. "Capital Account" or "account" means the account established for each
party, maintained as provided in ss.5.02 and its subsections.
2
10. "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.
11. "Carried Interest" means an equity interest in the Partnership issued
to a Person without consideration, in the form of cash or tangible
property, in an amount proportionately equivalent to that received
from the Participants.
12. "Code" means the Internal Revenue Code of 1986, as amended.
13. "Cost," when used with respect to the sale or transfer of property to
the Partnership, means:
(i) the sum of the prices paid by the seller or transferor to an
unaffiliated person for the property, including bonuses;
(ii) title insurance or examination costs, brokers' commissions,
filing fees, recording costs, transfer taxes, if any, and like
charges in connection with the acquisition of the property;
(iii) a pro rata portion of the seller's or transferor's actual
necessary and reasonable expenses for seismic and geophysical
services; and
(iv) rentals and ad valorem taxes paid by the seller or transferor
for the property to the date of its transfer to the buyer,
interest and points actually incurred on funds used to acquire
or maintain the property, and the portion of the seller's or
transferor's reasonable, necessary and actual expenses for
geological, engineering, drafting, accounting, legal and other
like services allocated to the property cost in conformity
with generally accepted accounting principles and industry
standards, except for expenses in connection with the past
drilling of wells which are not producers of sufficient
quantities of oil or gas to make commercially reasonable their
continued operations, and provided that the expenses
enumerated in this subsection (iv) shall have been incurred
not more than 36 months before the sale or transfer to the
Partnership.
"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.
14. "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.
15. "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.
16. "Direct Costs" means all actual and necessary costs directly incurred
for the benefit of the Partnership and generally attributable to the
goods and services provided to the Partnership by parties other than
the Sponsor or its Affiliates. Direct Costs may not include any cost
otherwise classified as Organization and Offering Costs,
Administrative Costs, Intangible Drilling Costs, Tangible Costs,
Operating Costs or costs related to the Leases, but may include the
cost of services provided by the Sponsor or its Affiliates if the
services are provided pursuant to written contracts and in compliance
with ss.4.03(d)(7) or pursuant to the Managing General Partner's role
as Tax Matters Partner.
3
17. "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.
18. "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).
19. "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.
20. "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.
21. "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.
22. "Horizon" means a zone of a particular formation; that part of a
formation of sufficient porosity and permeability to form a petroleum
reservoir.
23. "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.
24. "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.
25. "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.
4
26. "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.
27. "Investor General Partners" means:
(i) the persons signing the Subscription Agreement as Investor
General Partners; and
(ii) the Managing General Partner to the extent of any optional
subscription as an Investor General Partner under
ss.3.03(b)(2).
All Investor General Partners shall be of the same class and have the
same rights.
28. "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.
29. "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.
30. "Limited Partners" means:
(i) the persons signing the Subscription Agreement as Limited
Partners;
(ii) the Managing General Partner to the extent of any optional
subscription as a Limited Partner under 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.
31. "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.
32. "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.
33. "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 be March 31, 2005, but may be extended up to
December 31, 2005.
5
Notwithstanding the above, the Offering Termination Date may not
extend beyond the time that subscriptions for the maximum number of
Units set forth in ss.3.03(c)(1) have been received and accepted by
the Managing General Partner.
34. "Operating Costs" means expenditures made and costs incurred in
producing and marketing natural gas or oil from completed wells. These
costs include, but are not limited to:
(i) labor, fuel, repairs, hauling, materials, supplies, utility
charges and other costs incident to or related to producing
and marketing natural gas and oil;
(ii) ad valorem and severance taxes;
(iii) insurance and casualty loss expense; and
(iv) compensation to well operators or others for services rendered
in conducting these operations.
Operating Costs also include reworking, workover, subsequent
equipping, and similar expenses relating to any well, but do not
include the costs to re-enter and deepen an existing well, complete
the well to deeper reservoirs or plug the well if it is nonproductive
from the targeted deeper reservoirs.
35. "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.
36. "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.
37. "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.
38. "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.
39. "Participants" means:
(i) the Managing General Partner to the extent of its optional
subscription under ss.3.03(b)(2);
6
(ii) the Limited Partners; and
(iii) the Investor General Partners.
40. "Partners" means:
(i) the Managing General Partner;
(ii) the Investor General Partners; and
(iii) the Limited Partners.
41. "Partnership" means Atlas America Public #14-2005(A) L.P. [Atlas
America Public #14-2005(B) L.P.].
42. "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.
43. "Partnership Well" means a well, some portion of the revenues from
which is received by the Partnership.
44. "Person" means a natural person, partnership, corporation,
association, trust or other legal entity.
45. "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.
46. "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.
47. "Prospect" means an area covering lands which are believed by the
Managing General Partner to contain subsurface structural or
stratigraphic conditions making it susceptible to the accumulations of
hydrocarbons in commercially productive quantities at one or more
Horizons. The area, which may be different for different Horizons,
shall be:
(i) designated by the Managing General Partner in writing before
the conduct of Partnership operations; and
(ii) enlarged or contracted from time to time on the basis of
subsequently acquired information to define the anticipated
limits of the associated hydrocarbon reserves and to include
all acreage encompassed therein.
If the well to be drilled by the Partnership is to a Horizon
containing Proved Reserves, then a "Prospect" for a particular Horizon
may be limited to the minimum area permitted by state law or local
practice, whichever is applicable, to protect against drainage from
adjacent wells. Subject to the foregoing sentence, "Prospect" shall be
deemed the drilling or spacing unit for the Clinton/Medina geological
formation and the Mississippian and/or Upper Devonian Sandstone
reservoirs in Ohio, Pennsylvania, and New York and the Mississippian
Carbonate or the Devonian Shale reservoirs in Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee.
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48. "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.
49. "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.
50. "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.
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51. "Reimbursement for Permissible Non-Cash Compensation" means a .5%
accountable reimbursement for permissible non-cash compensation, which
includes:
(i) an accountable reimbursement for training and education
meetings for associated persons of the Selling Agents;
(ii) gifts that do not exceed $100 per year and are not
preconditioned on achievement of a sales target;
(iii) an occasional meal, a ticket to a sporting event or the
theater, or comparable entertainment which is neither so
frequent nor so extensive as to raise any question of
propriety and is not preconditioned on achievement of a sales
target; and
(iv) contributions to a non-cash compensation arrangement between a
Selling Agent and its associated persons, provided that
neither the Managing General Partner nor the Dealer-Manager
directly or indirectly participates in the Selling Agent's
organization of a permissible non-cash compensation
arrangement.
52. "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.
53. "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.
54. "Sales Commissions" means all underwriting and brokerage discounts and
commissions incurred in the sale of Units payable to registered
broker/dealers, but excluding the following:
(i) the 2.5% Dealer-Manager fee;
(ii) the .5% accountable Reimbursement for Permissible Non-Cash
Compensation; and
(iii) the up to .5% reimbursement for bona fide accountable due
diligence expenses.
55. "Selling Agents" means those broker/dealers selected by the
Dealer-Manager which will participate in the offer and sale of the
Units.
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56. "Sponsor" means any person directly or indirectly instrumental in
organizing, wholly or in part, a program or any person who will manage
or is entitled to manage or participate in the management or control
of a program. The definition includes:
(i) the managing and controlling general partner(s) and any other
person who actually controls or selects the person who
controls 25% or more of the exploratory, development or
producing activities of the program, or any segment thereof,
even if that person has not entered into a contract at the
time of formation of the program; and
(ii) whenever the context so requires, the term "sponsor" shall be
deemed to include its affiliates.
"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.
57. "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.
58. "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.
59. "Tax Matters Partner" means the Managing General Partner.
60. "Units" or "Units of Participation" means up to 510.50 Limited Partner
interests and up to 6,732.55 Investor General Partner interests, which
will be converted to Limited Partner Units as set forth in ss.6.01(b),
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.
61. "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.
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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).
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 ss.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 a
2.5% Dealer-Manager fee, a 7% Sales Commission, a .5% accountable
Reimbursement for Permissible Non-Cash Compensation, and a .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 a 7% Sales
Commission, which shall not be paid with respect to these sales.
No more than 5% of the total Units, in the aggregate, 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 or make the required contributions charged to it under
this Agreement.
These Capital Contributions shall be paid or made by the Managing General
Partner at the time the costs are required to be paid by the Partnership, but no
later than December 31, 2006.
3.03(b)(2). MANAGING GENERAL PARTNER'S OPTIONAL ADDITIONAL SUBSCRIPTION. In
addition to the Managing General Partner's required subscription under
ss.3.03(b)(1), the Managing General Partner may subscribe to up to 5% 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.
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3.03(b)(3). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing General Partner
has executed a Managing General Partner Signature Page which:
(i) evidences the Managing General Partner's required subscription under
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
7,243.05 Units, which is up to $72,430,500 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 #14-2004 Program, in the aggregate, shall not exceed
12,500 Units which is up to $125,000,000 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 200 Units, but in any event not less than that number of Units which
provides the Partnership with cash subscription proceeds of $2,000,000,
excluding the subscription discounts permitted under 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
subscription proceeds.
3.03(d). ACCEPTANCE OF SUBSCRIPTIONS.
3.03(d)(1). DISCRETION BY THE MANAGING GENERAL PARTNER. Acceptance of
subscriptions is discretionary with the Managing General Partner. The Managing
General Partner may reject any subscription for any reason it deems appropriate.
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.
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3.04(b). ON LIQUIDATION THE MANAGING GENERAL PARTNER MUST CONTRIBUTE DEFICIT
BALANCE IN ITS CAPITAL ACCOUNT. The Managing General Partner shall contribute to
the Partnership any deficit balance in its Capital Account on the occurrence of
either of the following events:
(i) the liquidation of the Partnership; or
(ii) the liquidation of the Managing General Partner's interest in the
Partnership.
This shall be determined after taking into account all adjustments for the
Partnership's taxable year during which the liquidation occurs, other than
adjustments made pursuant to this requirement, by the end of the taxable year in
which its interest in the Partnership is liquidated or, if later, within 90 days
after the date of the liquidation.
3.04(c). INTEREST FOR CONTRIBUTIONS. The interest of the Managing General
Partner, as Managing General Partner and not as a Participant, in the capital
and revenues of the Partnership is in consideration for, and is the only
consideration for, its required Capital Contributions to the Partnership.
3.05. PAYMENT OF SUBSCRIPTIONS.
3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing General Partner
shall pay any optional subscription under ss.3.03(b)(2) as set forth in
ss.3.05(b)(1).
3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL CONTRIBUTIONS OF THE
INVESTOR GENERAL PARTNERS.
3.05(b)(1). PAYMENT OF SUBSCRIPTION AGREEMENTS. A Participant shall pay the
amount designated as the subscription price on the Subscription Agreement
executed by the Participant 100% in cash at the time of subscribing. A
Participant shall receive interest on the amount he pays from the time his
subscription proceeds are deposited in the escrow account, or the Partnership
account after the minimum number of Units have been received as provided in
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, in proportion to
their respective number of Units, 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, in proportion to their respective
number of Units, until the amount in default is recovered in full
plus interest at the legal rate; and
(iii) may commence legal action to collect the amount due plus interest at
the legal rate.
3.06. PARTNERSHIP FUNDS.
3.06(a). FIDUCIARY DUTY. The Managing General Partner has a fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Managing General Partner's possession or
control. The Managing General Partner shall not employ, or permit another to
employ, the funds and assets in any manner except for the exclusive benefit of
the Partnership.
13
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, 4.03, 4.04, 4.05 and 4.06 of this Agreement.
3.06(b). SPECIAL ACCOUNT AFTER THE RECEIPT OF THE MINIMUM PARTNERSHIP
SUBSCRIPTIONS. Following the receipt of the minimum number of Units and breaking
escrow, the funds of the Partnership shall be held in a separate
interest-bearing account maintained for the Partnership and shall not be
commingled with funds of any other entity.
3.06(c). INVESTMENT.
3.06(c)(1). INVESTMENTS IN OTHER ENTITIES. Partnership funds 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 the other partnerships in Atlas America Public #14-2004
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
14
(ii) subject to any burdens as the Managing General Partner deems necessary
in its sole discretion.
4.01(a)(4). COST OF LEASES. All Leases shall be:
(i) contributed to the Partnership by the Managing General Partner or its
Affiliates other than an affiliated Program; and
(ii) credited towards the Managing General Partner's required Capital
Contribution set forth in 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'S, OPERATOR'S 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 ss.4.03 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, government
reports, or other instruments as may be required by law, 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 powers and rights granted to
the Managing General Partner under this section and its subsections. Each party
acknowledges that the power of attorney granted under subsection 4.02(d)(2)(a):
(i) is a special power of attorney coupled with an interest and
irrevocable; and
(ii) shall survive the assignment by the Participant of the whole or a
portion of his Units; except when the assignment is of all of the
Participant's Units and the purchaser, transferee, or assignee of the
Units is admitted as a successor Participant, the power of attorney
shall survive the delivery of the assignment for the sole purpose of
enabling the attorney-in-fact to execute, acknowledge, and file any
agreement, certificate, instrument or document necessary to effect the
substitution.
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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 Section
6231(a)(7) of the Code. The Managing General Partner is authorized to act in
this capacity on behalf of the Partnership and the Participants and to take any
action, including settlement or litigation, which it in its sole discretion
deems to be in the best interest of the Partnership.
4.02(f)(2). COSTS INCURRED BY TAX MATTERS PARTNER. Costs incurred by the Tax
Matters Partner shall be considered a Direct Cost of the Partnership.
4.02(f)(3). NOTICE TO PARTICIPANTS OF IRS PROCEEDINGS. The Tax Matters Partner
shall notify all Participants of any partnership administrative or other legal
proceedings involving the IRS, and thereafter shall furnish all Participants
periodic reports at least quarterly on the status of the proceedings.
4.02(f)(4). PARTICIPANT RESTRICTIONS. Each Participant agrees as follows:
(i) he will not file the statement described in Section 6224(c)(3)(B)
of the Code prohibiting the Managing General Partner as the Tax
Matters Partner for the Partnership from entering into a
settlement on his behalf with respect to partnership items, as
that term is defined in Section 6231(a)(3) of Code, of the
Partnership;
(ii) he will not form or become and exercise any rights as a member of
a group of Partners having a 5% or greater interest in the profits
of the Partnership under Section 6223(b)(2) of the Code; and
(iii) the Managing General Partner is authorized to file a copy of this
Agreement, or pertinent portions of this Agreement, with the IRS
under Section 6224(b) of the Code if necessary to perfect the
waiver of rights under this subsection.
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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 shall
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.
(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:
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(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:
(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.
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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;
(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
22
(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;
(ii) the Arizona Corporation Commission; and
(iii) the securities commissions of other states which request the
report.
4.03(c). MEETINGS OF PARTICIPANTS.
4.03(c)(1). PROCEDURE FOR A PARTICIPANT MEETING.
4.03(c)(1)(a). MEETINGS MAY BE CALLED BY MANAGING GENERAL PARTNER OR
PARTICIPANTS. Meetings of the Participants may be called as follows:
(i) by the Managing General Partner; or
(ii) by Participants whose Units equal 10% or more of the total
Units for any matters for which Participants may vote.
The call for a meeting by Participants shall be deemed to have been made on
receipt by the Managing General Partner of a written request from holders of the
requisite percentage of Units stating the purpose(s) of the meeting.
4.03(c)(1)(b). NOTICE REQUIREMENT. The Managing General Partner shall deposit in
the United States mail within 15 days after the receipt of the request, written
notice to all Participants of the meeting and the purpose of the meeting. The
meeting shall be held on a date not less than 30 days nor more than 60 days
after the date of the mailing of the notice, at a reasonable time and place.
Notwithstanding the foregoing, the date for notice of the meeting may be
extended for a period of up to 60 days if, in the opinion of the Managing
General Partner, the additional time is necessary to permit preparation of proxy
or information statements or other documents required to be delivered in
connection with the meeting by the SEC or other regulatory authorities.
4.03(c)(1)(c). MAY VOTE BY PROXY. Participants shall have the right to vote at
any Participant meeting either:
(i) in person; or
(ii) by proxy.
4.03(c)(2). SPECIAL VOTING RIGHTS. At the request of Participants whose Units
equal 10% or more of the total Units, the Managing General Partner shall call
for a vote by Participants. Each Unit is entitled to one vote on all matters,
and each fractional Unit is entitled to that fraction of one vote equal to the
fractional interest in the Unit. Participants whose Units equal a majority of
the total Units may, without the concurrence of the Managing General Partner or
its Affiliates, vote to:
(i) dissolve the Partnership;
23
(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:
(i) an opinion of counsel, the counsel being independent of the
Partnership and selected on the vote of Limited Partners whose
Units equal a majority of the total Units held by Limited
Partners; or
(ii) a declaratory judgment issued by a court of competent
jurisdiction.
The Investor General Partners may exercise the rights granted to the
Participants whether or not the Limited Partners can participate in the vote if
the Investor General Partners represent the requisite percentage of Units
necessary to take the action.
4.03(d). TRANSACTIONS WITH THE MANAGING GENERAL PARTNER.
4.03(d)(1). TRANSFER OF EQUAL PROPORTIONATE INTEREST. When the Managing General
Partner or an Affiliate (excluding another Program in which the interest of the
Managing General Partner or its Affiliates is substantially similar to or less
than their interest in the Partnership) sells, transfers or conveys any natural
gas, oil or other mineral interests or property to the Partnership, it must, at
the same time, sell, transfer or convey to the Partnership an equal
proportionate interest in all its other property in the same Prospect.
Notwithstanding, a Prospect shall be deemed to consist of the drilling or
spacing unit on which the well will be drilled by the Partnership, which is the
minimum area permitted by state law or local practice on which one well may be
drilled, if the following two conditions are met:
24
(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 or for a prospect located in Anderson, Campbell, Morgan,
Roane and Scott Counties, Tennessee on which a well will be drilled to test the
Mississippian carbonate or Devonian Shale reservoirs, a Prospect shall be
deemed to consist of the drilling and spacing unit if it meets the test in the
preceding sentence. Additionally, for a period of five years after the drilling
of the Partnership Well neither the Managing General Partner nor its Affiliates
may drill any well:
(i) in the Clinton/Medina geological formation within 1,650 feet
of an existing Partnership Well in Pennsylvania or within
1,000 feet of an existing Partnership Well in Ohio; or
(ii) in the Mississippian/Upper Devonian Sandstone reservoirs in
Fayette County and Greene County, Pennsylvania within at least
1,000 feet from a producing well, although a partnership may
drill a new well or re-enter an existing well which is closer
than 1,000 feet to a plugged and abandoned well.
If 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, the
Mississippian carbonate or Devonian Shale reservoirs, or any other formation or
reservoir shall not be enlarged or contracted if the Prospect was limited to the
drilling or spacing unit because the well was being drilled to Proved Reserves
in the geological formation and the drilling or spacing unit protected against
drainage.
4.03(d)(2). TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS
AFFILIATES' ENTIRE INTEREST. A sale, transfer or a conveyance to the Partnership
of less than all of the ownership of the Managing General Partner or an
Affiliate (excluding another Program in which the interest of the Managing
General Partner or its Affiliates is substantially similar to or less than their
interest in the Partnership) in any Prospect shall not be made unless:
(i) the interest retained by the Managing General Partner or the
Affiliate is a proportionate Working Interest;
(ii) the respective obligations of the Managing General Partner or
its Affiliates and the Partnership are substantially the same
after the sale of the interest by the Managing General Partner
or its Affiliates; and
(iii) the Managing General Partner's interest in revenues does not
exceed the amount proportionate to its retained Working
Interest.
This section does not prevent the Managing General Partner or its Affiliates
from subsequently dealing with their retained interest as they may choose with
unaffiliated parties or Affiliated partnerships.
4.03(d)(3). LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE
MANAGING GENERAL PARTNER. Other than another Program managed by the Managing
General Partner and its Affiliates as set forth in ss.ss.4.03(d)(5) and
4.03(d)(9), the Managing General Partner and its Affiliates shall not receive a
Farmout or purchase any undeveloped Leases from the Partnership other than at
the higher of Cost or fair market value.
25
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 more than two years. Otherwise, if the Managing General Partner deems it to
be in the best interest of the Partnership, the transfer may be made at Cost.
An Affiliated Income Program may purchase a producing natural gas and oil
property from the Partnership at any time at:
(i) fair market value as supported by an appraisal from an
Independent Expert if the property has been held by the
Partnership for more than six months or significant
expenditures have been made in connection with the property;
or
(ii) Cost as adjusted for intervening operations if the Managing
General Partner deems it to be in the best interest of the
Partnership.
However, these prohibitions shall not apply to joint ventures or Farmouts among
Affiliated partnerships, provided that:
(i) the respective obligations and revenue sharing of all parties
to the transaction are substantially the same; and
(ii) the compensation arrangement or any other interest or right of
either the Managing General Partner or its Affiliates is the
same in each Affiliated partnership or if different, the
aggregate compensation of the Managing General Partner or the
Affiliate is reduced to reflect the lower compensation
arrangement.
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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:
(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:
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(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, each seller of natural gas
and oil in a given area will be paid a weighted average selling price for all
natural gas and oil sold in that geographic area. The Managing General Partner,
in its sole discretion, shall determine what constitutes a geographic area.
4.03(d)(13). ADVANCE PAYMENTS. Advance payments by the Partnership to the
Managing General Partner and its Affiliates are prohibited except when advance
payments are required to secure the tax benefits of prepaid Intangible Drilling
Costs and for a business purpose.
4.03(d)(14). NO REBATES. No rebates or give-ups may be received by the Managing
General Partner or any Affiliate nor may the Managing General Partner or any
Affiliate participate in any reciprocal business arrangements which would
circumvent these guidelines.
4.03(d)(15). PARTICIPATION IN OTHER PARTNERSHIPS. If the Partnership
participates in other partnerships or joint ventures (multi-tier arrangements),
then the terms of any of these arrangements shall not result in the
circumvention of any of the requirements or prohibitions contained in this
Agreement, including the following:
(i) there shall be no duplication or increase in Organization and
Offering Costs, the Managing General Partner's compensation,
Partnership expenses or other fees and costs;
(ii) there shall be no substantive alteration in the fiduciary and
contractual relationship between the Managing General Partner
and the Participants; and
(iii) there shall be no diminishment in the voting rights of the
Participants.
4.03(d)(16). ROLL-UP LIMITATIONS.
4.03(d)(16)(a). REQUIREMENT FOR APPRAISAL AND ITS ASSUMPTIONS. In connection
with a proposed Roll-Up, an appraisal of all Partnership assets shall be
obtained from a competent Independent Expert. If the appraisal will be included
in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal
shall be filed with the SEC and the Administrator as an exhibit to the
registration statement for the offering. Thus, an issuer using the appraisal
shall be subject to liability for violation of Section 11 of the Securities Act
of 1933 and comparable provisions under state law for any material
misrepresentations or material omissions in the appraisal.
28
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.
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 that would operate to materially impede or frustrate the
accumulation of shares by any purchaser of the securities of the Roll-Up Entity,
except to the minimum extent necessary to preserve the tax status of the Roll-Up
Entity.
The Partnership shall not participate in any proposed Roll-Up transaction which
would limit the ability of a Participant to exercise the voting rights of its
securities of the Roll-Up Entity on the basis of the number of Units held by
that Participant.
4.03(d)(16)(e). NO ROLL-UP IF ACCESS TO RECORDS WOULD BE LIMITED. The
Partnership shall not participate in a Roll-Up in which Participants' rights of
access to the records of the Roll-Up Entity will be less than those provided for
under 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
under transactions that are fair and reasonable, nor take any action with
respect to the assets or property of the Partnership which does not primarily
benefit the Partnership.
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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.
4.04(a)(2)(b). DIRECT COSTS. The Managing General Partner and its Affiliates
shall be reimbursed for all Direct Costs. Direct Costs, however, shall be billed
directly to and paid by the Partnership to the extent practicable.
4.04(a)(2)(c). ADMINISTRATIVE COSTS. The Managing General Partner shall receive
an unaccountable, fixed payment reimbursement for its Administrative Costs of
$75 per well per month. The unaccountable, fixed payment reimbursement of $75
per well per month shall be subject to the following:
(i) it shall not be increased in amount during the term of the
Partnership;
(ii) it shall be proportionately reduced to the extent the
Partnership acquires less than 100% of the Working Interest in
the well;
(iii) it shall be the entire payment to reimburse the Managing
General Partner for the Partnership's Administrative Costs;
and
(iv) it shall not be received for plugged or abandoned wells.
4.04(a)(2)(d). GAS GATHERING. The Managing General Partner shall be responsible
for gathering and transporting the natural gas produced by the Partnership to
interstate pipeline systems, local distribution companies and/or end-users in
the area and shall receive a gathering fee at a competitive rate for gathering
and transporting the Partnership's gas. If the Partnership's natural gas
production is gathered and transported through the gathering system owned by
Atlas Pipeline Partners, then the Managing General Partner shall apply its
gathering fee towards the agreement between Atlas Pipeline Partners and Atlas
America, Inc., Resource Energy, Inc., and Viking Resources Corporation. If the
Partnership's natural gas production is gathered and transported through a
gathering system owned by a third-party, then the Managing General Partner shall
pay a portion or all of its gathering fee to the third-party gathering and
transporting the natural gas. If the Partnership's natural gas production is
gathered and transported through a gathering system owned by the Managing
General Partner or its affiliates other than Atlas Pipeline Partners, then the
Managing General Partner or its Affiliates shall receive, or retain in the case
of the Managing General Partner, the gathering fee paid to the Managing General
Partner.
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:
30
(i) a 2.5% Dealer-Manager fee;
(ii) a 7% Sales Commission;
(iii) a .5% accountable Reimbursement for Permissible Non-Cash
Compensation; and
(iv) an up to .5% reimbursement of the Selling Agents' bona fide
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 that 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).
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.
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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.
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;
32
(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) the Partnership's tangible net assets, which include its
revenues; and
(ii) any insurance proceeds from the types of insurance for which
the Managing General Partner, the Operator and their
Affiliates may be indemnified under this Agreement.
4.05(a)(3). STANDARDS FOR SECURITIES LAW INDEMNIFICATION. Notwithstanding
anything to the contrary contained in the above, the Managing General Partner,
the Operator, and their Affiliates and any person acting as a broker/dealer
shall not be indemnified for any losses, liabilities or expenses arising from or
out of an alleged violation of federal or state securities laws by such party
unless:
(i) there has been a successful adjudication on the merits of each
count involving alleged securities law violations as to the
particular indemnitee;
(ii) the claims have been dismissed with prejudice on the merits by
a court of competent jurisdiction as to the particular
indemnitee; or
(iii) a court of competent jurisdiction approves a settlement of the
claims against a particular indemnitee and finds that
indemnification of the settlement and the related costs should
be made, and the court considering the request for
indemnification has been advised of the position of the SEC,
the Massachusetts Securities Division, and any state
securities regulatory authority in which plaintiffs claim they
were offered or sold Units with respect to the issue of
indemnification for violation of securities laws.
4.05(a)(4). STANDARDS FOR ADVANCEMENT OF FUNDS TO THE MANAGING GENERAL PARTNER
AND INSURANCE. The advancement of Partnership funds to the Managing General
Partner, the Operator, or their Affiliates for legal expenses and other costs
incurred as a result of any legal action for which indemnification is being
sought is permissible only if the Partnership has adequate funds available and
the following conditions are satisfied:
(i) the legal action relates to acts or omissions with respect to
the performance of duties or services on behalf of the
Partnership;
(ii) the legal action is initiated by a third-party who is not a
Participant, or the legal action is initiated by a Participant
and a court of competent jurisdiction specifically approves
the advancement; and
33
(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 Revised Uniform Limited
Partnership Act, the Investor General Partners are liable jointly and severally
for all liabilities and obligations of the Partnership. Notwithstanding the
foregoing, as among themselves, the Investor General Partners agree that each
shall be solely and individually responsible only for his pro rata share of the
liabilities and obligations of the Partnership based on his respective number of
Units.
In addition, the Managing General Partner agrees to use its corporate assets to
indemnify each of the Investor General Partners against all Partnership related
liabilities which exceed the Investor General Partner's interest in the
undistributed net assets of the Partnership and insurance proceeds, if any.
Further, the Managing General Partner agrees to indemnify each Investor General
Partner against any personal liability as a result of the unauthorized acts of
another Investor General Partner.
If the Managing General Partner provides indemnification, then each Investor
General Partner who has been indemnified shall transfer and subrogate his rights
for contribution from or against any other Investor General Partner to the
Managing General Partner.
4.05(c). ORDER OF PAYMENT OF CLAIMS. Claims shall be paid as follows:
(i) first, out of any insurance proceeds;
(ii) second, out of Partnership assets and revenues; and
(iii) last, by the Managing General Partner as provided in
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, 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, 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;
34
(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:
(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 and for services provided by it
as Organization Costs up to and including 15% of the Partnership's subscription
proceeds. Any Organization and Offering Costs paid and/or provided in services
by the Managing General Partner in excess of this amount shall not be credited
towards the Managing General Partner's required Capital Contribution or revenue
share set forth in ss.5.01(b)(4). The Managing General Partner's credit for
services provided to the Partnership as Organization Costs shall be determined
based on generally accepted accounting principles.
5.01(a)(2). INTANGIBLE DRILLING COSTS. 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.
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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).
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.
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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
(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);
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(ii) the Managing General Partner shall not be required to return
Partnership distributions previously received by it, even
though a subordination obligation arises after the
distributions;
(iii) 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.
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.
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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);
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.
39
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.
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. If a Partnership expenditure, whether or not deductible,
that gives rise to a tax credit in a Partnership taxable year also gives rise to
valid allocations of Partnership loss or deduction, or other downward Capital
Account adjustments, for the year, then the parties' interests in the
Partnership with respect to the credit, or the cost giving rise thereto, shall
be in the same proportion as the parties' respective distributive shares of the
loss or deduction, and adjustments. If Partnership receipts, whether or not
taxable, that give rise to a tax credit, including a marginal well production
credit under ss.45I of the Code, in a Partnership taxable year also give rise to
valid allocations of Partnership income or gain, or other upward Capital Account
adjustments, for the year, then the parties' interests in the Partnership with
respect to the credit, or the Partnership's receipts or production of natural
gas and oil production giving rise thereto, shall be in the same proportion as
the parties' respective shares of the Partnership's production revenues from the
sales of its natural gas and oil production as provided in ss.5.01(b)(4).
40
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;
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.
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5.05. DISTRIBUTIONS.
5.05(a). IN GENERAL.
5.05(a)(1). QUARTERLY REVIEW OF ACCOUNTS. The Managing General Partner shall
review the accounts of the Partnership at least quarterly to determine whether
cash distributions are appropriate and the amount to be distributed, if any.
5.05(a)(2). DISTRIBUTIONS. The Partnership shall distribute funds to the
Managing General Partner and the Participants allocated to their accounts which
the Managing General Partner deems unnecessary to retain by the Partnership.
5.05(a)(3). NO BORROWINGS. In no event, however, shall funds be advanced or
borrowed for 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, if any, allocable to the return of capital.
For purposes of this subsection, "committed for expenditure" shall mean
contracted for, actually earmarked for or allocated by the Managing General
Partner to the Partnership's drilling operations, and "necessary operating
capital" shall mean those funds which, in the opinion of the Managing General
Partner, should remain on hand to assure continuing operation of the
Partnership.
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.
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6.01(b). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER UNITS.
6.01(b)(1). AUTOMATIC CONVERSION. After all of the Partnership Wells have been
drilled and completed, as determined by the Managing General Partner, the
Managing General Partner shall file an amended certificate of limited
partnership with the Secretary of State of the State of Delaware for the purpose
of converting the Investor General Partner Units to Limited Partner Units.
6.01(b)(2). INVESTOR GENERAL PARTNERS SHALL HAVE CONTINGENT LIABILITY. On
conversion the Investor General Partners shall be Limited Partners entitled to
limited liability; however, they shall remain liable to the Partnership for any
additional Capital Contribution required for their proportionate share of any
Partnership obligation or liability arising before the conversion of their Units
as provided in 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) except as provided by operation of law:
(a) only whole Units may be assigned unless the Participant
owns less than a whole Unit, in which case his entire
fractional interest must be assigned; and
(b) Units may not be assigned to a person who is under the
age of 18 or incompetent (unless an attorney-in-fact,
guardian, custodian or conservator has been appointed
to handle the affairs of that person) without the
Managing General Partner's consent;
(ii) the costs and expenses associated with the assignment must be
paid by the assignor Participant;
(iii) the assignment must be in a form satisfactory to the Managing
General Partner; and
(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.
43
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
(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.
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All repayments of these borrowings and costs, interest or other charges related
to the borrowings shall be borne and paid separately by the Managing General
Partner. In no event shall the repayments, costs, interest, or other charges
related to the borrowing be charged to the account of the Participants.
In addition, subject to a required participation of not less than 1% in the
Partnership as Managing General Partner, the Managing General Partner may
withdraw a property interest held by the Partnership in the form of a Working
Interest in the Partnership's Wells equal to or less than its respective
interest in the revenues of the Partnership if:
(i) the withdrawal is necessary to satisfy the bona fide request
of its creditors; or
(ii) the withdrawal is approved by Participants whose Units equal a
majority of the total Units.
6.04. PRESENTMENT.
6.04(a). IN GENERAL. Participants shall have the right to present their Units to
the Managing General Partner for purchase subject to the conditions and
limitations set forth in this section. A Participant, however, is not obligated
to present his Units for purchase.
The Managing General Partner shall not be obligated to purchase more than 5% of
the Units in any calendar year and this 5% limit may not be waived. The Managing
General Partner shall not purchase less than one Unit unless the lesser amount
represents the Participant's entire interest in the Partnership, however, the
Managing General Partner may waive this limitation.
A Participant may present his Units in writing to the Managing General Partner
every year beginning with the fifth calendar year after the Offering Termination
Date subject to the following conditions:
(i) the presentment must be made within 120 days of the reserve
report set forth in 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);
45
(ii) cash on hand;
(iii) prepaid expenses and accounts receivable less a reasonable
amount for doubtful accounts; and
(iv) the estimated market value of all assets, not separately
specified above, determined in accordance with standard
industry valuation procedures.
There shall be deducted from the foregoing sum the following items:
(i) an amount equal to all debts, obligations, and other
liabilities, including accrued expenses; and
(ii) any distributions made to the Participants between the date of
the request and the actual payment. However, if any cash
distributed was derived from the sale, after the presentment
request, of natural gas, oil or other mineral production, or
of a producing property owned by the Partnership, for purposes
of determining the reduction of the presentment price, the
distributions shall be discounted at the same rate used to
take into account the risk factors employed to determine the
present worth of the Partnership's Proved Reserves.
6.04(d). FURTHER ADJUSTMENT MAY BE ALLOWED. The presentment price may be further
adjusted by the Managing General Partner for estimated changes therein from the
date of the report to the date of payment of the presentment price to the
Participants because of the following:
(i) the production or sales of, or additions to, reserves and
lease and well equipment, sale or abandonment of Leases, and
similar matters occurring before the request for purchase; and
(ii) any of the following occurring before payment of the
presentment price to the selling Participants:
(a) changes in well performance;
(b) increases or decreases in the market price of natural
gas, oil or other minerals;
(c) revision of regulations relating to the importing of
hydrocarbons;
(d) changes in income, ad valorem, and other tax laws such
as material variations in the provisions for depletion;
and
(e) similar matters.
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.
46
In addition, the presentment feature may be conditioned, in the Managing General
Partner's sole discretion, on the Managing General Partner's receipt of an
opinion of counsel that the transfers will not cause the Partnership to be
treated as a "publicly traded partnership" under the Code.
The Managing General Partner shall hold the purchased Units for its own account
and not for resale.
ARTICLE VII
DURATION, DISSOLUTION, AND WINDING UP
7.01. DURATION.
7.01(a). FIFTY YEAR TERM. The Partnership shall continue in existence for a term
of 50 years from the effective date of this Agreement unless sooner terminated
as set forth below.
7.01(b). TERMINATION. The Partnership shall terminate following the occurrence
of:
(i) a Final Terminating Event; or
(ii) any event which under the Delaware Revised Uniform Limited
Partnership Act causes the dissolution of a limited
partnership.
7.01(c). CONTINUANCE OF PARTNERSHIP EXCEPT ON FINAL TERMINATING EVENT. Other
than the occurrence of a Final Terminating Event, the Partnership or any
successor limited partnership shall not be wound up, but shall be continued by
the parties and their respective successors as a successor limited partnership
under all the terms of this Agreement. The successor limited partnership shall
succeed to all of the assets of the Partnership. As used throughout this
Agreement, the term "Partnership" shall include the successor limited
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, but may
do so, in its discretion. Any in-kind property distributions to the Participants
shall be made to a liquidating trust or similar entity for the benefit of the
Participants, unless at the time of the distribution:
(i) the Managing General Partner offers the individual
Participants the election of receiving in-kind property
distributions and the Participants accept the offer after
being advised of the risks associated with direct ownership;
or
47
(ii) there are alternative arrangements in place which assure the
Participants that they will not, at any time, be responsible
for the operation or disposition of Partnership properties.
If the Managing General Partner has not received a Participant's consent within
30 days after the Managing General Partner mailed the request for consent, then
it shall be presumed that the Participant has refused his consent.
7.02(d). SALE IF NO CONSENT. Any Partnership asset which would otherwise be
distributed in-kind to a Participant, except for the failure or refusal of the
Participant to give his written consent to the distribution, may instead be sold
by the Managing General Partner at the best price reasonably obtainable from an
independent third-party, who is not an Affiliate of the Managing General Partner
or to itself or its Affiliates, including an Affiliated Income Program, at fair
market value as determined by an Independent Expert selected by the Managing
General Partner.
ARTICLE VIII
MISCELLANEOUS PROVISIONS
8.01. NOTICES.
8.01(a). METHOD. Any notice required under this Agreement shall be:
(i) in writing; and
(ii) given by mail or wire addressed to the party to receive the
notice at the address designated in 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.
48
8.02. TIME. Time is of the essence of each part of this Agreement.
8.03. APPLICABLE LAW. The terms and provisions of this Agreement shall be
construed under the laws of the State of Delaware, provided, however, this
section shall not be deemed to limit causes of action for violations of federal
or state securities law to the laws of the State of Delaware. Neither this
Agreement nor the Subscription Agreement shall require mandatory venue or
mandatory arbitration of any or all claims by Participants against the Sponsor.
8.04. AGREEMENT IN COUNTERPARTS. This Agreement may be executed in counterpart
and shall be binding on all parties executing this or similar agreements from
and after the date of execution by each party.
8.05. AMENDMENT.
8.05(a). PROCEDURE FOR AMENDMENT. No changes in this Agreement shall be binding
unless:
(i) proposed in writing by the Managing General Partner, and
adopted with the consent of Participants whose Units equal a
majority of the total Units; or
(ii) proposed in writing by Participants whose Units equal 10% or
more of the total Units and approved by an affirmative vote of
Participants whose Units equal a majority of the total Units.
8.05(b). CIRCUMSTANCES UNDER WHICH THE MANAGING GENERAL PARTNER ALONE MAY AMEND.
The Managing General Partner is authorized to amend this Agreement and its
exhibits without the consent of Participants in any way deemed necessary or
desirable by it to do any or all of the following:
(i) add or substitute in the case of an assigning party additional
Participants;
(ii) enhance the tax benefits of the Partnership to the parties;
(iii) satisfy any requirements, conditions, guidelines, options, or
elections contained in any opinion, directive, order, ruling,
or regulation of the SEC, the IRS, or any other federal or
state agency, or in any federal or state statute, compliance
with which it deems to be in the best interest of the
Partnership; or
(iv) to cure any ambiguity, to correct or supplement any provision
herein that may be inconsistent with any other provision
herein, or to add any other provision to this Agreement with
respect to matters or questions arising under this Agreement
that is not inconsistent with the terms of this Agreement.
Notwithstanding the foregoing, no amendment materially and adversely affecting
the interests or rights of Participants shall be made without the consent of the
Participants whose interests will be so affected.
8.06. ADDITIONAL PARTNERS. Each Participant hereby consents to the admission to
the Partnership of additional Participants as the Managing General Partner, in
its discretion, chooses to admit.
8.07. LEGAL EFFECT. This Agreement shall be binding on and inure to the benefit
of the parties, their heirs, devisees, personal representatives, successors and
assigns, and shall run with the interests subject to this Agreement. The terms
"Partnership," "Limited Partner," "Investor General Partner," "Participant,"
"Partner," "Managing General Partner," "Operator," or "parties" shall equally
apply to any successor limited partnership, and any heir, devisee, personal
representative, successor or assign of a party.
49
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 #14-2005(A) L.P.
The undersigned agrees:
1. to serve as the Managing General Partner of ATLAS AMERICA PUBLIC
#14-2005(A) L.P. (the "Partnership"), and hereby executes, swears
to, and agrees to all the terms of the Partnership Agreement;
2. to pay the required subscription of the Managing General Partner
under 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 _______ , 2005.
ATLAS RESOURCES, INC.
MANAGING GENERAL PARTNER
By: _____________________________
EXHIBIT (I-B)
FORM OF
SUBSCRIPTION AGREEMENT
ATLAS AMERICA PUBLIC #14-2005(A) L.P.
SUBSCRIPTION AGREEMENT
I, the undersigned, hereby offer to purchase Units of Atlas America Public
#14-2005(A) L.P. in the amount set forth on the Signature Page of this
Subscription Agreement and on the terms described in the current Prospectus for
Atlas America Public #14-2004 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 a citizen of the
United States of America and at least
twenty-one years of age.
_____ _____ If a partnership, corporation or trust, then
I am at least twenty-one years of age and
empowered and duly authorized under a
governing document, trust instrument,
charter, certificate of incorporation,
by-law provision or the like to enter into
this Subscription Agreement and to perform
the transactions contemplated by the
Prospectus, including its exhibits.
_____ _____ I (other than if I am a Minnesota or Maine
resident) understand that if I am an
Investor General Partner, then I will have
unlimited joint and several liability for
Partnership obligations and liabilities
including amounts in excess of my
subscription to the extent the obligations
and liabilities exceed the Partnership's
insurance proceeds, the Partnership's
assets, and indemnification by the Managing
General Partner. Also, the insurance may be
inadequate to cover these liabilities and
there is no insurance coverage for certain
claims.
_____ _____ I (other than if I am a Minnesota or Maine
resident) understand that if I am a Limited
Partner, then I may only use my Partnership
losses to the extent of my net passive
income from passive activities in the year,
with any excess losses being deferred.
1
INVESTOR'S CO-INVESTOR'S
INITIALS INITIALS
_____ _____ (a) If I purchase limited partner units
and I am a resident of:
o ALABAMA, o KENTUCKY, o OREGON,
o ALASKA, o LOUISIANA, o PENNSYLVANIA,
o ARIZONA, o MAINE, o RHODE ISLAND,
o ARKANSAS, o MARYLAND, o SOUTH CAROLINA,
o COLORADO, o MASSACHUSETTS, o SOUTH DAKOTA,
o CONNECTICUT, o MINNESOTA, o TENNESSEE,
o DELAWARE, o MISSISSIPPI, o TEXAS,
o DISTRICT OF COLUMBIA, o MISSOURI, o UTAH,
o FLORIDA, o MONTANA, o VERMONT,
o GEORGIA, o NEBRASKA, o VIRGINIA,
o HAWAII, o NEVADA, o WASHINGTON
o IDAHO, o NEW MEXICO o WEST VIRGINIA,
o ILLINOIS, o NEW YORK, o WISCONSIN, OR
o INDIANA, o NORTH DAKOTA, o WYOMING,
o IOWA, o OHIO,
o KANSAS, o OKLAHOMA,
then I must have either: a minimum net worth of
$225,000, exclusive of home, home furnishings,
and automobiles, or a minimum net worth of
$60,000, exclusive of home, home furnishings, and
automobiles, and had during the last tax year or
estimate that I will have during the current tax
year "taxable income" as defined in Section 63 of
the Internal Revenue Code of at least $60,000,
without regard to an investment in the
partnership.
In addition, if I am a resident of OHIO, or
PENNSYLVANIA, then I must not make an investment
in a partnership which is in excess of 10% of my
net worth, exclusive of home, home furnishings
and automobiles. Finally, if I am a resident of
KANSAS, it is recommended by the Office of the
Kansas Securities Commissioner that I should
limit my investment in the partnership and
substantially similar programs to no more than
10% of my net worth, excluding home, furnishings
and automobiles.
_____ _____ (b) If I purchase limited partner units and I
am a resident of:
o CALIFORNIA, o NEW HAMPSHIRE, o NORTH CAROLINA,
o MICHIGAN, o NEW JERSEY, OR
THEN I REPRESENT THAT I AM AWARE OF AND MEET
THAT STATE'S QUALIFICATIONS AND SUITABILITY
STANDARDS SET FORTH IN EXHIBIT (B) TO THE
PROSPECTUS.
2
INVESTOR'S CO-INVESTOR'S
INITIALS INITIALS
_____ _____ (c) If I purchase investor general partner units and I am a resident of:
o ALASKA, o ILLINOIS, o RHODE ISLAND,
o COLORADO, o LOUISIANA, o SOUTH CAROLINA,
o CONNECTICUT, o MARYLAND, o UTAH,
o DELAWARE, o MONTANA, o VIRGINIA,
o DISTRICT OF COLUMBIA, o NEBRASKA, o WEST VIRGINIA,
o FLORIDA, o NEVADA, o WISCONSIN, OR
o GEORGIA, o NEW YORK, o WYOMING,
o HAWAII, o NORTH DAKOTA,
o IDAHO,
then I must have either: a net worth of at
least $225,000, exclusive of home,
furnishings and automobiles, or a net worth,
exclusive of home, furnishings and
automobiles, of at least $60,000, and had
during the last tax year, or estimate that I
will have during the current tax year,
"taxable income" as defined in Section 63 of
the Code of at least $60,000, without regard
to an investment in the Partnership.
_____ _____ (d) IF I PURCHASE INVESTOR GENERAL PARTNER UNITS AND I AM A RESIDENT OF:
o ALABAMA, o MASSACHUSETTS, o OHIO,
o ARIZONA, o MICHIGAN, o OKLAHOMA,
o ARKANSAS, o MINNESOTA, o OREGON,
o CALIFORNIA, o MISSISSIPPI, o PENNSYLVANIA,
o INDIANA, o MISSOURI, o SOUTH DAKOTA,
o IOWA, o NEW HAMPSHIRE, o TENNESSEE,
o KANSAS, o NEW JERSEY, o TEXAS,
o KENTUCKY, o NEW MEXICO, o VERMONT OR
o MAINE, o NORTH CAROLINA, o WASHINGTON,
THEN I REPRESENT THAT I AM AWARE OF AND MEET THAT STATE'S QUALIFICATIONS AND
SUITABILITY STANDARDS SET FORTH IN EXHIBIT (B) TO THE PROSPECTUS.
_____ _____ (e) If I am a fiduciary, then I am purchasing for a person or entity having the
appropriate income and/or net worth specified in (a) (b), (c) or (d) above.
_____ _____ 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.
3
INVESTOR'S CO-INVESTOR'S
INITIALS INITIALS
_____ _____ 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:
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 the person has been given your legal
power of attorney to sign on your behalf, and you meet all of the conditions in
the Prospectus and this Subscription Agreement. In the case of sales to
fiduciary accounts, the minimum standards set forth in the Prospectus and this
Subscription Agreement must be met by the beneficiary, the fiduciary account, or
by the donor or grantor who directly or indirectly supplies the funds to
purchase the Partnership Units if the donor or grantor is the fiduciary.
Your execution of the Subscription Agreement constitutes your binding offer to
buy Units in the Partnership. Once you subscribe you may withdraw your
subscription only by providing the Managing General Partner with written notice
of your withdrawal before your subscription is accepted by the Managing General
Partner. The Managing General Partner has the discretion to refuse to accept
your subscription without liability to you. Subscriptions will be accepted or
rejected by the Partnership within 30 days of their receipt. If your
subscription is rejected, then all of your funds will be returned to you
immediately. If your subscription is accepted before the first closing, then you
will be admitted as a Participant not later than 15 days after the release from
escrow of the investors' funds to the Partnership. If your subscription is
accepted after the first closing, then you will be admitted into the Partnership
not later than the last day of the calendar month in which your subscription was
accepted by the Partnership.
The Managing General Partner will not complete a sale of Units to you until at
least five business days after the date you receive a final Prospectus, and send
you a confirmation of purchase. Thus, you have five business days to rescind
your purchase after you receive the final prospectus and execute your
subscription agreement.
NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from
various requirements of Title 10 of the California Administrative Code. These
deviations include, but are not limited to the following: the definition of
Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule
260.140.121(1), does not require enlarging or contracting the size of the area
on the basis of geological data in all cases. If a resident of California I
acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B)
to the Prospectus.
4
- ----------------------------------------------------------------------------------------------------------------------------
SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
- ----------------------------------------------------------------------------------------------------------------------------
I, the undersigned, agree to purchase ________ Units at $10,000 per Unit in ATLAS AMERICA PUBLIC #14-2005(A) L.P.
(the "Partnership") as (check one):
|_| INVESTOR GENERAL PARTNER SUBSCRIPTION PRICE
|_| LIMITED PARTNER $ ____________________________
(______________________# Units)
INSTRUCTIONS
============================================================================================================================
Make your check payable to: "Atlas America Public #14-2005(A) L.P., Escrow Agent, National City Bank of PA"
Minimum Subscription: one Unit ($10,000), however, the Managing General Partner, in its discretion, may accept one-half
Unit ($5,000) subscriptions. Additional Subscriptions in $1,000 increments. If you are an individual investor you must
personally sign this signature page and provide the information requested below.
============================================================================================================================
Subscriber (All individual investors must personally My Home Address (Do not use P.O. Box)
sign this Signature Page.)
My Tax I.D. No. (Social Security No.): _________________
_________________________________________________ ___________________________________________________
Print Name
_________________________________________________ ___________________________________________________
Signature
My Tax I.D. No. (Social Security No.): _________________
_________________________________________________ ___________________________________________________
Print Name
My Address for Distributions if Different from Above
_________________________________________________
Signature ___________________________________________________
___________________________________________________
Date: _______________ Account No.: ________________________________________
My Telephone No.: Home ___________________ My Telephone No.: Business ___________________
My E-mail Address: ____________________________________
My Citizenship is: ____________________________________
(CHECK ONE): |_| I am at least twenty-one years of age |_| I am not twenty-one years of age
(CHECK ONE): I am a: |_| Calendar Year Taxpayer |_| Fiscal Year Taxpayer
(CHECK IF APPLICABLE): I am a: |_| Farmer (2/3 or more of my gross income in 2005 or 2004 is from farming)
(CHECK ONE): OWNERSHIP OF THE UNITS- |_| Tenants-in-Common |_| Partnership
|_| Joint Tenancy with Right of Survivorship |_| C Corporation
|_| Individual |_| S Corporation
|_| Trust |_| Community Property
with Survivorship
Rights
|_| Limited Liability Company |_| Other
NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP: NAME ____________________________________________
(ENCLOSE SUPPORTING DOCUMENTS.) IF A PARTNERSHIP, CORPORATION OR TRUST, THEN THE MEMBERS, STOCKHOLDERS OR BENEFICIARIES
THEREOF ARE CITIZENS OF _________________________.
- -----------------------------------------------------------------------------------------------------------------------------
5
TO BE COMPLETED BY REGISTERED REPRESENTATIVE (FOR COMMISSION AND OTHER PURPOSES)
- --------------------------------------------------------------------------------
I hereby represent that I have discharged my affirmative obligations under Rule
2810(b)(2)(B) and (b)(3)(D) of the NASD's Conduct Rules and specifically have
obtained information from the above-named subscriber concerning his/her age, net
worth, annual income, federal income tax bracket, investment objectives,
investment portfolio, and other financial information and have determined that
an investment in the Partnership is suitable for such subscriber, that such
subscriber is or will be in a financial position to realize the benefits of this
investment, and that such subscriber has a fair market net worth sufficient to
sustain the risks for this investment. I have also informed the subscriber of
all pertinent facts relating to the liquidity and marketability of an investment
in the Partnership, of the risks of unlimited liability regarding an investment
as an Investor General Partner, and of the passive loss limitations for tax
purposes of an investment as a Limited Partner.
_________________________________________________ __________________________________________________
Name of Registered Representative and CRD Number Name of Broker/Dealer
_________________________________________________ __________________________________________________
Signature of Registered Representative Broker/Dealer CRD Number
Registered Representative Office Address: Broker/Dealer Facsimile Number: __________________
_________________________________________________ Broker/Dealer E-mail Address:__________________________
_________________________________________________
Phone Number: ___________________________________
Facsimile Number: _______________________________
E-mail Address: _________________________________
_________________________________________________
Company Name (if other than Broker/Dealer Name)
NOTICE TO BROKER-DEALER:
Send SUBSCRIPTION DOCUMENTS completed and signed with CHECK MADE PAYABLE TO:
"ATLAS PUBLIC #14-2005(A) L.P., ESCROW AGENT, NATIONAL CITY BANK OF PA" to:
Mr. Justin Atkinson
Anthem Securities, Inc.
311 Rouser Road
P.O. Box 926
Moon Township, Pennsylvania 15108-0926
(412) 262-1680 (412) 262-7430 (FAX)
- --------------------------------------------------------------------------------
TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
- --------------------------------------------------------------------------------
ACCEPTED THIS ______ day ATLAS RESOURCES, INC.,
of _________________ , 2005 MANAGING GENERAL PARTNER
By: ___________________________
6
EXHIBIT (II)
FORM OF
DRILLING AND OPERATING AGREEMENT
FOR
ATLAS AMERICA PUBLIC #14-2005(A) L.P.
[ATLAS AMERICA PUBLIC #14-2005(B) L.P.]
INDEX
SECTION PAGE
1. Assignment of Well Locations; Representations and Indemnification Associated with the
Assignment of the Lease; Designation of Additional Well Locations;
Outside Activities Are Not Restricted.......................................................................1
2. Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations.................2
3. Operator - Responsibilities in General; Covenants; Term.....................................................3
4. Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination;
Dry Hole Determination; Excess Funds and Cost Overruns - Intangible Drilling Costs; Excess
Funds and Cost Overruns - Tangible Costs....................................................................4
5. Title Examination of Well Locations; Developer's Acceptance and Liability; Additional Well Locations........7
6. Operations Subsequent to Completion of the Wells; Fee Adjustments;
Extraordinary Costs;
Pipelines; Price Determinations; Plugging and Abandonment...................................................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 Oil or Gas Purchaser................................................10
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.............................................................................14
16. Waiver of Default or Breach................................................................................14
17. Notices....................................................................................................15
18. Interpretation.............................................................................................15
19. Counterparts...............................................................................................15
Signature Page.............................................................................................15
Exhibit A Description of Leases and Initial Well Locations
Exhibits A-l through A-___ Maps of Initial Well Locations
Exhibit B Form of Assignment
Exhibit C Form of Addendum
DRILLING AND OPERATING AGREEMENT
THIS AGREEMENT made this ______ day of _______________, 200____, by and between
ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as
"Atlas" or "Operator"),
and
ATLAS AMERICA PUBLIC #14-2005(A) L.P. [Atlas America Public #14-2005(B) L.P.], a
Delaware limited partnership, (hereinafter referred to as the "Developer").
WITNESSETH THAT:
WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the "Leases")
described on Exhibit A attached to and made a part of this Agreement, has
certain rights to develop the ____________ (______) initial well locations (the
"Initial Well Locations") identified on the maps attached to and made a part of
this Agreement as Exhibits A-l through A-______;
WHEREAS, the Developer, subject to the terms and conditions of this Agreement,
desires to acquire certain of the Operator's rights to develop the Initial Well
Locations and to provide for the development on the terms and conditions set
forth in this Agreement of additional well locations ("Additional Well
Locations") which the parties may from time to time designate; and
WHEREAS, the Operator is in the oil and gas exploration and development
business, and the Developer desires that Operator, as its independent
contractor, perform certain services in connection with its efforts to develop
the aforesaid Initial and Additional Well Locations (collectively the "Well
Locations") and to operate the wells completed on the Well Locations, on the
terms and conditions set forth in this Agreement;
NOW THEREFORE, in consideration of the mutual covenants herein contained and
subject to the terms and conditions hereinafter set forth, the parties hereto,
intending to be legally bound, hereby agree as follows:
1. ASSIGNMENT OF WELL LOCATIONS; REPRESENTATIONS AND INDEMNIFICATION
ASSOCIATED WITH THE ASSIGNMENT OF THE LEASE; DESIGNATION OF ADDITIONAL WELL
LOCATIONS; OUTSIDE ACTIVITIES ARE NOT RESTRICTED.
(a) ASSIGNMENT OF WELL LOCATIONS. The Operator shall execute an assignment
of an undivided percentage of Working Interest in the Well Location
acreage for each well to the Developer as shown on Exhibit A attached
hereto, which assignment shall be limited to a depth from the surface
through the completion total depth of the well (in the case of north
central Tennessee the transfer will be an additional 100 feet below
the deepest producing formation in the well) (the "Objective
Formation"). In the event, however, that hydrocarbons are encountered
in quantities that Operator believes to be in paying quantities and
drilling ceases before the Objective 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 AND INDEMNIFICATION ASSOCIATED WITH THE ASSIGNMENT OF
THE LEASE. The Operator represents and warrants to the Developer that:
(i) the Operator is the lawful owner of the Lease and rights and
interest under the Lease and of the personal property on the
Lease or used in connection with the Lease;
(ii) the Operator has good right and authority to sell and convey
the rights, interest, and property;
(iii) the rights, interest, and property are free and clear from all
liens and encumbrances; and
(iv) all rentals and royalties due and payable under the Lease have
been duly paid.
1
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 ____________ (_____)
oil and gas wells on the ____________ (______) Initial Well Locations
in accordance with the terms and conditions of this Agreement.
Developer, as a minimum commitment, agrees to participate in and pay
the Operator's charges for drilling and completing the wells and any
extra costs pursuant to Section 4 in proportion to the share of the
Working Interest owned by the Developer in the wells with respect to
all initial wells. It is understood and agreed that, subject to
sub-section (e) below, Developer does not reserve the right to decline
participation in the drilling of any of the initial wells to be
drilled under this Agreement.
(b) TIMING. Operator shall begin drilling the first well within thirty
(30) days after the date of this Agreement, and shall begin drilling
each of the other initial wells for which payment is made pursuant to
Section 4(b) of this Agreement before the close of the 90th day after
the close of the calendar year in which this Agreement is entered into
by Operator and the Developer. Subject to the foregoing time limits,
Operator shall determine the timing of and the order of drilling the
Initial Well Locations.
(c) DEPTH. All of the wells to be drilled under this Agreement (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.
2
(d) INTEREST OF DEVELOPER. Except as otherwise provided in this Agreement,
all costs, expenses, and liabilities incurred in connection with the
drilling and other operations and activities contemplated by this
Agreement shall be borne and paid, and all wells, gathering lines of
up to approximately 2,500 feet on the Well Location, in connection
with a natural gas well, equipment, materials, and facilities
acquired, constructed or installed under this Agreement shall be
owned, by the Developer in proportion to the share of the Working
Interest owned by the Developer in the wells. Subject to the payment
of lessor's royalties and other royalties and overriding royalties, if
any, production of oil and gas from the wells to be drilled under this
Agreement shall be owned by the Developer in proportion to the share
of the Working Interest owned by the Developer in the wells.
(e) RIGHT TO SUBSTITUTE WELL LOCATIONS. Notwithstanding the provisions of
sub-section (a) above, if the Operator or Developer determines in good
faith, with respect to any Well Location, before operations begin
under this Agreement on the Well Location, that it would not be in the
best interest of the parties to drill a well on the Well Location,
then the party making the determination shall notify the other party
of its determination and its basis for its determination and, unless
otherwise instructed by Developer, the well shall not be drilled. This
determination may be based on:
(i) the production or failure of production of any other wells
which may have been recently drilled in the immediate area of
the Well Location;
(ii) newly discovered title defects; or
(iii) any other evidence with respect to the Well Location as may be
obtained.
If the well is not drilled, then Operator shall promptly propose a new
well location (including all information for the Well Location as
Developer may reasonably request) to be substituted for the original
Well Location. Developer shall then have seven (7) business days to
either reject or accept the proposed new well location. If the new
well location is rejected, then Operator shall promptly propose
another substitute well location pursuant to the provisions of this
sub-section.
Once the Developer accepts a substitute well location or does not
reject it within said seven (7) day period, this Agreement shall
terminate as to the original Well Location and the substitute well
location shall become subject to the terms and conditions of this
Agreement.
3. OPERATOR - RESPONSIBILITIES IN GENERAL; COVENANTS; TERM.
(a) OPERATOR - RESPONSIBILITIES IN GENERAL. Atlas shall be the Operator of
the wells and Well Locations subject to this Agreement and, as the
Developer's independent contractor, shall, in addition to its other
obligations under this Agreement do the following:
(i) arrange for drilling and completing the wells and, if a gas
well, installing the necessary gas gathering line systems and
connection facilities;
(ii) make the technical decisions required in drilling, testing,
completing, and operating the wells;
(iii) manage and conduct all field operations in connection with the
drilling, testing, completing, equipping, operating, and
producing the wells;
(iv) maintain all wells, equipment, gathering lines if a gas well,
and facilities in good working order during their useful
lives; and
(v) perform the necessary administrative and accounting functions.
In performing the work contemplated by this Agreement,
Operator is an independent contractor with authority to
control and direct the performance of the details of the work.
3
(b) COVENANTS. Operator covenants and agrees that under this Agreement:
(i) it shall perform and carry on (or cause to be performed and
carried on) its duties and obligations in a good, prudent,
diligent, and workmanlike manner using technically sound,
acceptable oil and gas field practices then prevailing in the
geographical area of the Well Locations;
(ii) all drilling and other operations conducted by, for and under
the control of Operator shall conform in all respects to
federal, state and local laws, statutes, ordinances,
regulations, and requirements;
(iii) unless otherwise agreed in writing by the Developer, all work
performed pursuant to a written estimate shall conform to the
technical specifications set forth in the written estimate and
all 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 oil and 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. This includes
without limitation, site preparation, permits and bonds, roadways,
surface damages, power at the site, water, Operator's overhead and
profit, rights-of-way, drilling rigs, equipment and materials, costs
of title examinations, logging, cementing, fracturing, casing, meters
(other than utility purchase meters), connection facilities, salt
water collection tanks, separators, siphon string, rabbit, tubing, an
average of 2,500 feet of gathering line per well, in connection with a
gas well, and geological and engineering services.
4
(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 property acquisitions and the drilling and
completion of oil and gas wells which are generally accepted as
capital expenditures pursuant to the provisions of the Code. This
includes 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;
(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.
5
(e) EXCESS FUNDS AND COST OVERRUNS-INTANGIBLE DRILLING COSTS. Any
estimated Intangible Drilling Costs, which are the Intangible Drilling
Costs set forth on the AFE, 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, which are the Intangible Drilling Costs set
forth on the AFE, 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, which are the Tangible Costs set forth on the AFE,
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:
(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,
which are the Tangible Costs set forth on the AFE, 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
6
(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(b).
6. OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS; FEE ADJUSTMENTS;
EXTRAORDINARY COSTS; PIPELINES; PRICE DETERMINATIONS; PLUGGING AND
ABANDONMENT.
(a) OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS. Beginning with the
month in which a well drilled under this Agreement begins to produce,
Operator shall be entitled to an operating fee of $285 per month for
each well being operated under this Agreement, proportionately reduced
to the extent the Developer owns less than 100% of the Working
Interest in the wells. This fee shall be in lieu of any direct charges
by Operator for its services or the provision by Operator of its
equipment for normal superintendence and maintenance of the wells and
related pipelines and facilities.
The operating fees shall cover all normal, regularly recurring
operating expenses for the production, delivery and sale of natural
gas, including without limitation:
(i) well tending, routine maintenance and adjustment;
(ii) reading meters, recording production, pumping, maintaining
appropriate books and records;
(iii) preparing reports to the Developer and government agencies;
and
(iv) collecting and disbursing revenues.
7
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, 2007 with respect to the partnerships designated Atlas
America Public #14-2005(A) L.P., and Atlas America Public #14-2005(B)
L.P. 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, 2004, in the
case of the first adjustment, and since the previous Adjustment Date,
in the case of each subsequent adjustment.
(c) EXTRAORDINARY COSTS. Without the prior written consent of the
Developer, pursuant to a written estimate submitted by Operator,
Operator shall not undertake any single project or incur any
extraordinary cost with respect to any well being produced under this
Agreement reasonably estimated to result in an expenditure of more
than $5,000, unless the project or extraordinary cost is necessary for
the following:
(i) to safeguard persons or property; or
(ii) to protect the well or related facilities in the event of a
sudden emergency.
In no event, however, shall the Developer be required to pay for any
project or extraordinary cost arising from the negligence or
misconduct of Operator, its agents, servants, employees, contractors,
licensees, or invitees.
All extraordinary costs incurred and the cost of projects undertaken
with respect to a well being produced shall be billed at the invoice
cost of third-party services performed or materials purchased together
with a reasonable charge by Operator for services performed directly
by it, in proportion to the share of the Working Interest owned by the
Developer in the wells. Operator shall have the right to require the
Developer to pay in advance of undertaking any project all or a
portion of the estimated costs of the project in proportion to the
share of the Working Interest owned by the Developer in the wells.
(d) PIPELINES. Developer shall have no interest in the pipeline gathering
system, which gathering system shall remain the sole property of
Operator or its Affiliates and shall be maintained at their sole cost
and expense.
(e) PRICE DETERMINATIONS. Notwithstanding anything herein to the contrary,
the Developer shall pay all costs in proportion to the share of the
Working Interest owned by the Developer in the wells with respect to
obtaining price determinations under and otherwise complying with the
Natural Gas Policy Act of 1978 and the implementing state regulations.
This responsibility shall include, without limitation, preparing,
filing, and executing all applications, affidavits, interim collection
notices, reports and other documents necessary or appropriate to
obtain price certification, to effect sales of natural gas, or
otherwise to comply with the Act and the implementing state
regulations.
8
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 Developer's share of the costs of plugging and abandoning
the well.
7. BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS;
DISBURSEMENTS; SEPARATE ACCOUNT FOR SALE PROCEEDS; RECORDS AND REPORTS;
ADDITIONAL INFORMATION.
(a) BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS.
Operator shall promptly and timely pay and discharge on behalf of the
Developer, in proportion to the share of the Working Interest owned by
the Developer in the wells the following:
(i) all expenses and liabilities payable and incurred by reason of
its operation of the wells in accordance with this Agreement ,
such as severance taxes, royalties, overriding royalties,
operating fees, and pipeline gathering charges; and
(ii) any third-party invoices rendered to Operator with respect to
costs and expenses incurred in connection with the operation
of the wells.
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
9
(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.
(e) ADDITIONAL INFORMATION. Operator shall promptly furnish the Developer
with any additional information as it may reasonably request,
including without limitation geological, technical, and financial
information, in the form as may reasonably be requested, pertaining to
any phase of the operations and activities governed by this Agreement.
The Developer and its authorized employees, agents and consultants,
including independent accountants shall, at Developer's sole cost and
expense:
(i) on at least ten (10) days' written notice have access during
normal business hours to all of Operator's records pertaining
to operations, including without limitation, the right to
audit the books of account of Operator relating to all
receipts, costs, charges, expenses and disbursements under
this Agreement, including information regarding the separate
account required under sub-section (c); and
(ii) have access, at its sole risk, to any wells drilled by
Operator under this Agreement at all times to inspect and
observe any machinery, equipment and operations.
8. OPERATOR'S LIEN; RIGHT TO COLLECT FROM OIL OR GAS PURCHASER.
(a) OPERATOR'S LIEN. To secure the payment of all sums due from Developer
to Operator under the provisions of this Agreement the Developer
grants Operator a first and preferred lien on and security interest in
the following:
(i) the Developer's interest in the Leases covered by this
Agreement;
(ii) the Developer's interest in oil and gas produced under this
Agreement and its proceeds from the sale of the oil and gas;
and
10
(iii) the Developer's interest in materials and equipment under this
Agreement.
(b) RIGHT TO COLLECT FROM OIL OR GAS PURCHASER. If the Developer fails to
timely pay any amount owing under this Agreement by it to the
Operator, then Operator, without prejudice to other existing remedies,
may collect and retain from any purchaser or purchasers of oil or gas
the Developer's share of the proceeds from the sale of the oil and gas
until the amount owed by the Developer, plus twelve percent (12%)
interest on a per annum basis, and any additional costs (including
without limitation actual attorneys' fees and costs) resulting from
the delinquency, has been paid. Each purchaser of oil or gas shall be
entitled to rely on Operator's written statement concerning the amount
of any default.
9. SUCCESSORS AND ASSIGNS; TRANSFERS; APPOINTMENT OF AGENT.
(a) SUCCESSORS AND ASSIGNS. This Agreement shall be binding on and inure
to the benefit of the undersigned parties and their respective
successors and permitted assigns. However, without the prior written
consent of the Developer, the Operator may not assign, transfer,
pledge, mortgage, hypothecate, sell or otherwise dispose of any of its
interest in this Agreement, or any of the rights or obligations under
this Agreement. Notwithstanding, this consent shall not be required in
connection with:
(i) the assignment of work to be performed for Operator by
subcontractors, it being understood and agreed, however, that
any assignment to Operator's subcontractors shall not in any
manner relieve or release Operator from any of its obligations
and responsibilities under this Agreement;
(ii) any lien, assignment, security interest, pledge or mortgage
arising under Operator's present or future financing
arrangements; or
(iii) the liquidation, merger, consolidation, or other corporate
reorganization or sale of substantially all of the assets of
Operator.
Further, in order to maintain uniformity of ownership in the wells,
production, equipment, and leasehold interests covered by this
Agreement, and notwithstanding any other provisions to the contrary,
the Developer shall not, without the prior written consent of
Operator, sell, assign, transfer, encumber, mortgage or otherwise
dispose of any of its interest in the wells, production, equipment or
leasehold interests covered by this Agreement unless the disposition
encompasses either:
(i) the entire interest of the Developer in all wells, production,
equipment and leasehold interests subject to this Agreement;
or
(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;
11
(iii) receive billings for and approve and pay all costs, expenses
and liabilities incurred under this Agreement;
(iv) exercise any rights granted to the co-owners under this
Agreement;
(v) grant any approvals or authorizations required or contemplated
by this Agreement;
(vi) sign, execute, certify, acknowledge, file and/or record any
agreements, contracts, instruments, reports, or documents
whatsoever in connection with this Agreement or the activities
contemplated by this Agreement; and
(vii) deal generally with, and with power to bind, the co-owners
with respect to all activities and operations contemplated by
this Agreement.
However, all the co-owners shall continue to have the right to enter
into and execute all contracts or agreements for their respective
shares of the oil and gas produced from the wells drilled under this
Agreement in accordance with sub-section (c) of Section 11.
10. OPERATOR'S INSURANCE; SUBCONTRACTORS' INSURANCE; OPERATOR'S LIABILITY.
(a) OPERATOR'S INSURANCE. Operator shall obtain and maintain at its own
expense so long as it is Operator under this Agreement all required
Workmen's Compensation Insurance and comprehensive general public
liability insurance in amounts and coverage not less than $1,000,000
per person per occurrence for personal injury or death and $1,000,000
for property damage per occurrence, which shall include coverage for
blow-outs and total liability coverage of not less than $10,000,000.
Subject to the above limits, the Operator's general public liability
insurance shall be in all respects comparable to that generally
maintained in the industry with respect to services of the type to be
rendered and activities of the type to be conducted under this
Agreement. Operator's general public liability insurance shall, if
permitted by Operator's insurance carrier:
(i) name the Developer as an additional insured party; and
(ii) provide that at least thirty (30) days' prior notice of
cancellation and any other adverse material change in the
policy shall be given to the Developer.
However, the Developer shall reimburse Operator for the additional
cost, if any, of including it as an additional insured party under the
Operator's insurance.
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
12
(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
(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.
13
12. EFFECT OF FORCE MAJEURE; DEFINITION OF FORCE MAJEURE; LIMITATION.
(a) EFFECT OF FORCE MAJEURE. If Operator is rendered unable, wholly or in
part, by force majeure (as defined below) to carry out any of its
obligations under this Agreement, including but not limited to
beginning the drilling of one or more wells by the applicable times
set forth in Section 2(b), or any Addendum to this Agreement, the
obligations of the Operator, so far as it is affected by the force
majeure, shall be suspended during but no longer than, the continuance
of the force majeure. The Operator shall give to the Developer prompt
written notice of the force majeure with reasonably full particulars
concerning it. Operator shall use all reasonable diligence to remove
the force majeure as quickly as possible to the extent the same is
within reasonable control.
(b) DEFINITION OF FORCE MAJEURE. The term "force majeure" shall mean an
act of God, strike, lockout, or other industrial disturbance, act of
the public enemy, war, blockade, public riot, lightning, fire, storm,
flood, explosion, governmental restraint, unavailability of drilling
rigs, equipment or materials, plant shut-downs, curtailments by
purchasers and any other causes whether of the kind specifically
enumerated above or otherwise, which directly preclude Operator's
performance under this Agreement and is not reasonably within the
control of the Operator including but not limited to, with respect to
the Operator beginning the drilling of the wells subject to this
Agreement by the applicable times set forth in Section 2(b), or any
Addendum to this Agreement, decisions of third-party operators to
delay drilling the wells, poor weather conditions, inability to obtain
drilling permits, access right to the drilling site or title problems.
(c) LIMITATION. The requirement that any force majeure shall be remedied
with all reasonable dispatch shall not require the settlement of
strikes, lockouts, or other labor difficulty affecting the Operator,
contrary to its wishes. The method of handling these difficulties
shall be entirely within the discretion of the Operator.
13. TERM.
This Agreement shall become effective when executed by Operator and the
Developer. Except as provided in sub-section (c) of Section 3, this
Agreement shall continue and remain in full force and effect for the
productive lives of the wells being operated under this Agreement.
14. GOVERNING LAW; INVALIDITY.
(a) GOVERNING LAW. This Agreement shall be governed by, construed and
interpreted in accordance with the laws of the Commonwealth of
Pennsylvania.
(b) INVALIDITY. The invalidity or unenforceability of any particular
provision of this Agreement shall not affect the other provisions of
this Agreement, and this Agreement shall be construed in all respects
as if the invalid or unenforceable provision were omitted.
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.
14
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 #14-2005(A) L.P.
[Atlas America Public #14-2005(B) L.P.]
c/o Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
Notices which are served by registered or certified mail on the parties
in the manner provided in this Section shall be deemed sufficiently
served or given for all purposes under this Agreement at the time the
notice is mailed in any post office or branch post office regularly
maintained by the United States Postal Service or any successor. All
payments shall be hand-delivered or sent by United States mail, postage
prepaid to the addresses set forth above until changed by certified or
registered letter so addressed to the other party.
18. INTERPRETATION.
The titles of the Sections in this Agreement are for convenience of
reference only and shall not control or affect the meaning or
construction of any of the terms and provisions of this Agreement. As
used in this Agreement, the plural shall include the singular and the
singular shall include the plural whenever appropriate.
19. COUNTERPARTS.
The parties may execute this Agreement in any number of separate
counterparts, each of which, when executed and delivered by the
parties, shall have the force and effect of an original; but all such
counterparts shall be deemed to constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have duly executed this
Agreement as of the day and year first above written.
ATLAS RESOURCES, INC.
By:
------------------------------------
(Name and Title)
ATLAS AMERICA PUBLIC #14-2005(A) L.P.
[ATLAS AMERICA PUBLIC #14-2005(B) L.P.]
By its Managing General Partner:
ATLAS RESOURCES, INC.
By:
------------------------------------
(Name and Title)
15
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 ___________________ , 200___
THIS ADDENDUM NO. __________ made and entered into this ______ day of
________________, 200___, by and between ATLAS RESOURCES, INC., a Pennsylvania
corporation (hereinafter referred to as "Operator"),
and
ATLAS AMERICA PUBLIC #14-2005(A) L.P. [ATLAS AMERICA PUBLIC #14-2005(B) L.P.], a
Delaware limited partnership, (hereinafter referred to as the Developer).
WITNESSETH THAT:
WHEREAS, Operator and the Developer have entered into a Drilling and Operating
Agreement dated ___________________, 200___, (the "Agreement"), which relates to
the drilling and operating of ________________ (______)wells on the
________________ (______) Initial Well Locations identified on the maps attached
as Exhibits A-l through A-______ to the Agreement, and provides for the
development on the terms and conditions set forth in the Agreement of Additional
Well Locations as the parties may from time to time designate; and
WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer
presently desire to designate ________________ Additional Well Locations
described below to be developed in accordance with the terms and conditions of
the Agreement.
NOW, THEREFORE, in consideration of the mutual covenants contained in this
Addendum and intending to be legally bound, the parties agree as follows:
1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes
Operator to drill, complete (or plug) and operate, on the terms and conditions
set forth in the Agreement and this Addendum No.__________, ________________
additional wells on the ________________ Additional Well Locations described on
Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits
A-______ through A-______.
2. Operator, as Developer's independent contractor, agrees to drill, complete
(or plug) and operate the additional wells on the Additional Well Locations in
accordance with the terms and conditions of the Agreement and further agrees to
begin drilling the first additional well within thirty (30) days after the date
of this Addendum and to begin drilling all the additional wells on or before
March ___, 2006.
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 #14-2005(A) L.P.
[ATLAS AMERICA PUBLIC #14-2005(B) L.P.]
By its Managing General Partner:
ATLAS RESOURCES, INC.
By
-----------------------------------
Exhibit C
(Page 2)
EXHIBIT (B)
SPECIAL SUITABILITY REQUIREMENTS
AND DISCLOSURES TO INVESTORS
SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS
If you are a resident of one of the following states, then you must meet that
state's qualification and suitability standards as set forth below.
SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING LIMITED PARTNER UNITS IN
CALIFORNIA, MICHIGAN, NEW HAMPSHIRE, NEW JERSEY AND NORTH CAROLINA.
I. If you are a resident of CALIFORNIA or NEW JERSEY and you purchase limited
partners units, then you must meet any one of the following special
suitability requirements:
o a net worth of not less than $250,000, exclusive of home, home
furnishings and automobiles, and expect to have gross income in the
current year of $65,000 or more; or
o a net worth of not less than $500,000, exclusive of home, home
furnishings and automobiles; or
o a net worth of not less than $1 million; or
o expected gross income in the current tax year of not less than
$200,000.
II. If you are a resident of MICHIGAN OR NORTH CAROLINA and you purchase
limited partner units, then you must meet any one of the following special
suitability requirements:
o a net worth of not less than $225,000, exclusive of home, home
furnishings and automobiles; or
o a net worth of not less than $60,000, exclusive of home, home
furnishings and automobiles, and estimated CURRENT year taxable income
as defined in Section 63 of the Internal Revenue Code of $60,000 or
more without regard to an investment in the partnership.
In addition, if you are a resident of MICHIGAN, then you must not make an
investment in the partnership in excess of 10% of your net worth, exclusive of
home, home furnishings and automobiles.
III. If you are a resident of NEW HAMPSHIRE and you purchase limited partner
units, then you must meet any one of the following:
o a net worth of not less than $250,000, exclusive of home, home
furnishings, and automobiles, or
o a net worth of not less than $125,000, exclusive of home, home
furnishings, and automobiles, and $50,000 of taxable income.
SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING INVESTOR GENERAL PARTNER
UNITS IN ALABAMA, ARIZONA, ARKANSAS, CALIFORNIA, INDIANA, IOWA, KANSAS,
KENTUCKY, MAINE, MASSACHUSETTS, MICHIGAN, MINNESOTA, MISSISSIPPI, MISSOURI,
NEW HAMPSHIRE, NEW JERSEY, NEW MEXICO, NORTH CAROLINA, OHIO, OKLAHOMA, OREGON,
PENNSYLVANIA, SOUTH DAKOTA, TENNESSEE, TEXAS, VERMONT, OR WASHINGTON.
I. If you are a resident of CALIFORNIA or NEW JERSEY and you purchase
investor general partner units, then you must meet any one of the
following special suitability requirements:
o a net worth of not less than $250,000, exclusive of home, home
furnishings and automobiles, and expect to have annual gross income in
the current year of $120,000 or more; or
o a net worth of not less than $500,000, exclusive of home, home
furnishings and automobiles; or
o a net worth of not less than $1 million; or
o expected gross income in the current year of not less than $200,000.
II. If you are a resident of any of the following states:
1
o ALABAMA; o MINNESOTA; o PENNSYLVANIA;
o ARKANSAS; o NORTH CAROLINA; o TENNESSEE;
o MAINE; o OHIO; o TEXAS; OR
o MASSACHUSETTS; o OKLAHOMA; o WASHINGTON.
and you purchase investor general partner units, then you must meet any one of
the following special suitability requirements:
o an individual or joint net worth with your spouse of $225,000 or more,
without regard to the investment in the partnership, exclusive of
home, home furnishings and automobiles, and A COMBINED GROSS INCOME OF
$100,000 OR MORE FOR THE CURRENT YEAR AND FOR THE TWO PREVIOUS YEARS;
or
o an individual or joint net worth with your spouse in excess of $1
million, inclusive of home, home furnishings and automobiles; or
o an individual or joint net worth with your spouse in excess of
$500,000, exclusive of home, home furnishings and automobiles; or
o a combined "gross income" as defined in Section 61 of the Internal
Revenue Code of 1986, as amended, in excess of $200,000 in the current
year and the two previous years.
III. If you are a resident of any of the following states:
o ARIZONA; o KENTUCKY; o NEW MEXICO;
o INDIANA; o MICHIGAN; o OREGON;
o IOWA; o MISSISSIPPI; o SOUTH DAKOTA; OR
o KANSAS; o MISSOURI; o VERMONT;
and you purchase investor general partner units, then you must meet any one of
the following special suitability requirements:
o an individual or joint net worth with your spouse of $225,000 or more,
without regard to the investment in the partnership, exclusive of
home, home furnishings and automobiles, AND A COMBINED "TAXABLE
INCOME" OF $60,000 OR MORE FOR THE PREVIOUS YEAR AND EXPECT TO HAVE A
COMBINED "TAXABLE INCOME" OF $60,000 OR MORE FOR THE CURRENT YEAR AND
FOR THE SUCCEEDING YEAR; or
o an individual or joint net worth with your spouse in excess of $1
million, inclusive of home, home furnishings and automobiles; or
o an individual or joint net worth with your spouse in excess of
$500,000, exclusive of home, home furnishings and automobiles; or
o a combined "gross income" as defined in Section 61 of the Internal
Revenue Code of 1986, as amended, in excess of $200,000 in the current
year and the two previous years.
IV. In addition, if you are a resident of any of the following states:
o IOWA; o OHIO; OR
o MICHIGAN; o PENNSYLVANIA;
then you must not make an investment in the partnership in excess of 10% of your
net worth, exclusive of home, furnishings and automobiles.
2
Also, if you are a resident of KANSAS, it is recommended by the Office of the
Kansas Securities Commissioner that you should limit your investment in the
program and substantially similar programs to no more than 10% of your net
worth, excluding home, furnishings and automobiles.
V. If you are a resident of NEW HAMPSHIRE and you purchase investor general
partner units, then you must meet any one of the following special
suitability requirements:
o a net worth of not less than $250,000, exclusive of home, home
furnishings, and automobiles, or
o net worth of not less than $125,000, exclusive of home, home
furnishings, and automobiles, and $50,000 of taxable income.
SPECIAL REPRESENTATIONS FOR SUBSCRIBERS OF
CALIFORNIA, MISSOURI, NORTH CAROLINA AND PENNSYLVANIA.
I. If a resident of CALIFORNIA, I am aware that:
IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR
ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR,
WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS
OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER'S
RULES.
As a condition of qualification of the units for sale in the State of
California, the following rule is hereby delivered to each California purchaser.
CALIFORNIA ADMINISTRATIVE CODE, TITLE 10, CH. 3, RULE 260.141.11. RESTRICTION
ON TRANSFER.
(a) The issuer of any security upon which a restriction on transfer has
been imposed pursuant to Sections 260.102.6, 260.141.10 and 260.534
shall cause a copy of this section to be delivered to each issuee or
transferee of such security at the time the certificate evidencing the
security is delivered to the issuee or transferee.
(b) It is unlawful for the holder of any such security to consummate a
sale or transfer of such security, or any interest therein, without
the prior written consent of the Commissioner (until this condition is
removed pursuant to Section 260.141.12 of these rules), except:
(i) to the issuer;
(ii) pursuant to the order or process of any court;
(iii) to any person described in Subdivision (i) of Section 25102 of
the Code or Section 260.105.14 of these rules;
(iv) to the transferor's ancestors, descendants or spouse, or any
custodian or trustee for the account of the transferor's
ancestors, descendants or spouse, or to a transferee by a
trustee or custodian for the account of the transferee or the
transferee's ancestors, descendants or spouse;
(v) to holders of securities of the same class of the same issuer;
(vi) by way of gift or donation inter vivos or on death;
(vii) by or through a broker-dealer licensed under the Code (either
acting as such or as a finder) to a resident of a foreign
state, territory or country who is neither domiciled in this
state to the knowledge of the broker-dealer, nor actually
present in this state if the sale of such securities is not in
violation of any securities law of the foreign state,
territory or country concerned;
(viii) to a broker-dealer licensed under the Code in a principal
transaction, or as an underwriter or member of an underwriting
syndicate or selling group;
3
(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."
II. 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)).
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 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.
4
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TABLE OF CONTENTS
Page
Summary of the Offering...........................................1
Risk Factors......................................................8
Additional Information...........................................19
Forward Looking Statements and Associated
Risks.........................................................19
Investment Objectives............................................20
Actions to be Taken by Managing General
Partner to Reduce Risks of Additional
Payments by Investor General Partners.........................21
Capitalization and Source of Funds and Use of
Proceeds......................................................23
Compensation.....................................................27
Terms of the Offering............................................33
Prior Activities.................................................41
Management.......................................................51
Management's Discussion and Analysis of Financial Condition,
Results of Operations, Liquidity and Capital
Resources.....................................................57
Proposed Activities..............................................58
Competition, Markets and Regulation..............................74
Participation in Costs and Revenues..............................77
Conflicts of Interest............................................84
Fiduciary Responsibility of the Managing
General Partner...............................................94
Material Federal Income Tax Consequences.........................96
Summary of Partnership Agreement................................125
Summary of Drilling and Operating Agreement.....................127
Reports to Investors............................................128
Presentment Feature.............................................129
Transferability of Units........................................131
Plan of Distribution............................................132
Sales Material..................................................135
Legal Opinions..................................................136
Experts.........................................................136
Litigation......................................................136
Financial Information Concerning the Managing General Partner
and Atlas America Public #14-2005(A) L.P.....................137
EXHIBIT (A) - Form of Amended and Restated Certificate and
Agreement of Limited Partnership for Atlas America
Public #14-2005(A) L.P. [Form of Amended and
Restated Certificate and Agreement of Limited
Partnership for Atlas America Public #14-2005(B)
L.P.]
EXHIBIT (I-A) - Form of Managing General Partner Signature Page
EXHIBIT (I-B) - Form of Subscription Agreement
EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas
America Public #14-2005(A) L.P. [Atlas America
Public #14-2005(B) L.P.]
EXHIBIT (B) - Special Suitability Requirements and Disclosures to
Investors
No one has been authorized to give any information or make any representations
other than those contained in this prospectus in connection with this offering.
If given or made, you should not rely on such information or representations as
having been authorized by the managing general partner. The delivery of this
prospectus does not imply that its information is correct as of any time after
its date. This prospectus is not an offer to sell these securities in any state
to any person where the offer and sale is not permitted.
================================================================================
================================================================================
ATLAS AMERICA
PUBLIC #14-2004 PROGRAM
PROSPECTUS
Until December 31, 2005, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealers' obligation to deliver
a prospectus when acting as underwriters and with respect to their unsold
allotments or subscriptions.
================================================================================