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EX-1.2 - FORM OF SELLING DEALER AGREEMENT - ICON Oil & Gas Fund-B L.P.v308383_ex1-2.htm
EX-1.1 - FORM OF DEALER-MANAGER AGREEMENT - ICON Oil & Gas Fund-B L.P.v308383_ex1-1.htm
EX-5.1 - OPINION OF ARENT FOX LLP - ICON Oil & Gas Fund-B L.P.v308383_ex5-1.htm
EX-8.1 - OPINION OF ARENT FOX LLP - TAX - ICON Oil & Gas Fund-B L.P.v308383_ex8-1.htm
EX-10.1 - ESCROW AGREEMENT - ICON Oil & Gas Fund-B L.P.v308383_ex10-1.htm
EX-23.1 - CONSENT OF ERNST & YOUNG LLP - ICON Oil & Gas Fund-B L.P.v308383_ex23-1.htm

As filed with the Securities and Exchange Commission on June 13, 2012

Registration Number 333-177051

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



 

Amendment No. 3
to
FORM S-1
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933



 

ICON OIL & GAS FUND

(Exact name of Registrant as Specified in its Charter)

   
Delaware   1311   Not Applicable
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (IRS Employer
Identification Number)

Philtower Building
427 South Boston Avenue, Suite 703
Tulsa, Oklahoma 74103
(918) 236-4657

(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)



 

Joel S. Kress
Senior Managing Director
ICON Oil & Gas GP, LLC
3 Park Avenue, 36th Floor
New York, New York 10016
(212) 418-4700

(Name, address, including zip code, and telephone number,
including area code, of agent for service)



 

With a Copy to:

Deborah Schwager Froling
Arent Fox LLP
1050 Connecticut Avenue, N.W.
Washington, DC 20036
(202) 857-6075

(Counsel to registrant)



 

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: x

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

     
Large accelerated filer o   Accelerated filer o   Non-accelerated filer x   Smaller Reporting Company o
 

 


 
 

TABLE OF CONTENTS

CALCULATION OF REGISTRATION FEE

       
Title of The Class of Securities to be Registered(4)   Amount to be
Registered
  Proposed Maximum
Offering Price
Per Interest
  Proposed Maximum
Aggregate
Offering Price
  Amount of
Registration Fee
Investor General Partner Interests(1)     16,000     $ 10,000     $ 160,000,000     $ 18,576 (5) 
Converted Limited Partner Interests(2)     16,000     $ 0     $ 0     $ 0  
Limited Partner Interests(3)     4,000     $ 10,000     $ 40,000,000     $ 4,644 (5) 

(1) “Investor General Partner Interests” means up to 16,000 investor general partner interests offered to investors in the fund.
(2) “Converted Limited Partner Interests” means up to 16,000 limited partner interests into which the Investor General Partner Interests automatically will be converted by the Managing GP with no additional price paid by the investor.
(3) “Limited Partner Interests” means up to 4,000 initial limited partner interests offered to investors in the fund.
(4) Each partnership reserves the right to adjust the number of Investor General Partner Interests, Limited Partner Interests and Converted Limited Partner Interests set forth above so long as they do not exceed 20,000 Interests in the aggregate.
(5) Previously paid.


 

The Registrant hereby amends this Registration Statement on such dates as may be necessary to delay its effective date until the Registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.


 
 

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The information in this prospectus is not complete and may be changed. The partnership may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any State where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED JUNE 13, 2012

[GRAPHIC MISSING]

ICON OIL & GAS FUND

an ICON Investments fund

Up to 16,000 Investor General Partner Interests, which will automatically be converted to Limited
Partner Interests after drilling is completed in each respective partnership, and up to
4,000 Limited Partner Interests, at $10,000 per Interest(1)

Minimum Offering 200 Interests ($2,000,000)
Maximum Offering 20,000 Interests ($200,000,000)

Each partnership reserves the right to adjust the number of Investor General Partner Interests,
Limited Partner Interests, and Investor General Partner Interests converted to Limited Partner
Interests set forth above so long as the aggregate number does not exceed 20,000 Interests

 
Offering Price: $10,000 per Interest   Minimum Purchase: $5,000 (½ Interest)

ICON Oil & Gas Fund is an oil and natural gas drilling fund consisting of up to three Delaware limited partnerships. The managing general partner of each of the partnerships is ICON Oil & Gas GP, LLC (the “Managing GP”). Interests in the partnerships will be offered and sold in a series beginning with the offering of interests in the first partnership, ICON Oil & Gas Fund-A L.P. This prospectus relates to the offering of interests in ICON Oil & Gas Fund-A L.P. (the “Interests”) only and all references to the partnership herein will mean ICON Oil & Gas Fund-A L.P. The interests in the other partnerships in ICON Oil & Gas Fund will be offered pursuant to separate prospectuses following the termination of this offering for ICON Oil & Gas Fund-A L.P. on or before December 31, 2012, unless this offering is extended by the Managing GP pursuant to a supplement to this prospectus. If you invest in a partnership, you will not have any interest in any other partnerships unless you also make a separate investment in those other partnerships. The Managing GP intends to use the net proceeds from this offering to invest primarily in oil and liquids-rich natural gas development wells, principally “fluid management” projects, where hydrocarbons are known to be present, located in the Mid-Continent region of the United States, with the potential investment in properties located within other types of projects and/or in other geographic areas that the Managing GP may, from time to time, identify as prospective. The partnership’s primary investment objectives are to (i) generate revenue from the production and sale of oil, natural gas and natural gas liquids, (ii) distribute cash to investors, and (iii) provide investors with tax benefits in the year that the offering commences and in future years.

The partnership is offering up to 20,000 Interests at a public offering price of $10,000.00 per Interest and at a public offering price of $9,300.00 per Interest for Interests sold to the Managing GP, selling dealers or certain of their affiliates, as well as registered investment advisers and their clients. In addition, certain volume discounts may be available for large purchases. These discounted prices reflect certain fees, sales commissions, and reimbursements that will not be paid in connection with these sales. See “Plan of Distribution.” To the extent that Interests are sold at discounted prices, the aggregate amount of subscription proceeds will be reduced, but proceeds received by the partnership will remain unchanged. A minimum investment of one half (½) Interest ($5,000) is required. At any time prior to the two-year anniversary of the date of this prospectus, the Managing GP may increase the offering to a maximum of up to 30,000 Interests; provided, however, that the Managing GP may not extend the offering period in connection with such change.

Investing in Interests is speculative and involves a high degree of risk. You should purchase Interests only if you can afford a complete loss of your investment. See “Risk Factors” beginning on page 14, which include the following:

The partnership’s drilling operations involve the possibility of a total or partial loss of your investment because the partnership may drill (i) wells that are productive, but that do not produce enough revenue to return the investment made, and (ii) from time to time, dry holes.
The partnership’s revenues are directly related to its ability to market the oil and natural gas produced from the wells it drills and oil and natural gas prices, which are volatile and uncertain. If oil and natural gas prices decrease, then the return on your investment will decrease.
If you choose to invest as an Investor General Partner, you will have unlimited joint and several liability for partnership obligations until you are converted to a Limited Partner.
The partnership has a limited prior operating history, no established financing sources and this is the first oil and gas program sponsored by the Managing GP and its affiliates.
Interests are not liquid and your ability to resell your Interests will be limited by the absence of a public trading market and substantial transfer restrictions.
There is no guaranty that cash distributions will be paid from the partnership in any amount or frequency.
The decisions of the Managing GP may be subject to conflicts of interest.
You will have limited voting rights and will be required to rely on the Managing GP to make all investment decisions and achieve the partnership’s investment objectives.
Taxable income may be allocated to you in excess of the cash distributions you receive from the partnership.

Neither the Securities and Exchange Commission nor any State securities commission has approved or disapproved of these securities or determined that this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

       
Offering   Price to Public   Sales Commissions   Dealer-Manager Fee   Proceeds to the Partnership
Per Interest   $ 10,000     $ 700     $ 300     $ 9,000  
Minimum Offering of 200 Interests   $ 2,000,000     $ 140,000     $ 60,000     $ 1,800,000  
Maximum Offering of up to 20,000 Interests   $ 200,000,000     $ 14,000,000     $ 6,000,000     $ 180,000,000  

ICON Securities Corp. (“ICON Securities”), which is an affiliate of the Managing GP, will act as the dealer-manager for this offering of Interests. Broker-dealers selling Interests are not required to sell any specific number of Interests, but will use their “best efforts” to sell Interests. This means that broker-dealers must sell at least 200 Interests and receive subscription proceeds of at least $2,000,000 in order for this offering to close and thereafter use best efforts to sell the remaining unsold Interests. The Managing GP will deposit subscriptions in a bank escrow account with UMB Bank, N.A. until $2,000,000 is received. If the minimum offering is not achieved within twelve months from the date hereof, the escrow agent will send a refund of your investment with any interest earned thereon and without deduction for escrow expenses. Investors (other than Pennsylvania and Tennessee investors who will receive interest on their escrowed funds until subscription proceeds for 1,000 Interests have been received) who invest prior to the minimum offering being achieved will receive interest on their escrowed funds, pro-rated for each day their funds were held in escrow. The last date on which Interests may be sold is December 31, 2012, unless this offering is extended by the Managing GP pursuant to a supplement to this prospectus.

There is no public market for Interests and the Managing GP does not expect one to develop. Interests will not be listed on any national securities exchange.

(1) You may elect to buy either Investor General Partner Interests in the partnership that will be automatically converted to Limited Partner Interests after the partnership’s drilling is completed, or Limited Partner Interests. The type of Interest that you buy will not change your share of the partnership’s costs, revenue or cash distributions; provided, however, that there are material differences in the federal income tax and liability consequences between Investor General Partner Interests and Limited Partner Interests, as discussed in “Summary of the Offering — Description of Interests.”

[GRAPHIC MISSING]

Dealer-Manager
The date of this prospectus is [____].


 
 

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TABLE OF CONTENTS

 
SUITABILITY STANDARDS     v  
FORWARD-LOOKING STATEMENTS     ix  
PROSPECTUS SUMMARY     1  
RISK FACTORS     14  
Risks Related to an Investment in the Partnership     14  
If you choose to invest as an Investor General Partner, you will have unlimited joint and several liability for partnership obligations until you are converted to a limited partner     14  
Interests are not liquid and your ability to resell your Interests will be limited by the absence of a public trading market and substantial transfer restrictions     15  
Compensation and fees to the Managing GP regardless of success of the partnership’s activities will reduce cash distributions     15  
There is no guaranty that cash distributions will be paid by the partnership in any amount or frequency     15  
The Managing GP may not be able to meet its indemnification obligations if its liquid net worth is not sufficient at the time such indemnification is sought     16  
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     16  
Increases in the costs of the wells may adversely affect your return     16  
The partnership does not own any Prospects, the Managing GP has complete discretion to select which prospects are acquired by the partnership, and the possible lack of information about the prospects decreases your ability to evaluate the feasibility of the partnership     17  
Drilling prospects in one area may increase risk     17  
Because of inadequate capital, the partnership may not be able to participate in all wells proposed, which could result in a loss or forfeiture of leasehold interests     18  
The presentment obligation may not be funded and the presentment price may not reflect full value     18  
The lack of an independent dealer-manager may reduce the due diligence investigation of the partnership and the Managing GP     18  
A lengthy offering period may result in delays in the investment of your subscription and any cash distributions from the partnership to you     19  
The partnership is subject to comprehensive federal, state and local laws and regulations that could increase the cost and alter the manner or feasibility of the partnership’s business and operations     19  
Your Interests may be diluted     19  
The partnership’s assets may be plan assets for ERISA purposes, which could subject the Managing GP to additional restrictions on its ability to operate its business with respect to all its partners     20  
An investment in the Interests may not satisfy the requirements of ERISA or other applicable laws     20  
The statements of value that the partnership will include in its Annual Reports on Form 10-K and that the partnership will send to fiduciaries of plans subject to ERISA and to certain other parties are only estimates and may not reflect the actual value of the Interests     20  
Risks Related to the Partnership’s Oil and Gas Operations     20  
The partnership’s drilling operations involve the possibility of a total or partial loss of your investment that may be substantial because the partnership may drill (i) wells that are productive, but that do not produce enough revenue to return the investment made, and (ii) from time to time, dry holes.     20  

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The partnership’s revenues are directly related to its ability to market the oil and natural gas produced from the wells it drills and oil and natural gas prices, which are volatile and uncertain. If oil and natural gas prices decrease, then the returns on your investment will decrease.     21  
Adverse events in marketing the partnership’s natural gas could reduce distributions.     21  
Because some wells may not return their drilling and completion costs, it may take many years to return your investment in cash, if ever     23  
Nonproductive wells may be drilled even though the partnership’s operations are primarily limited to development drilling     23  
The related operator will hold record title on undeveloped leases with respect to each Project for the partnership’s benefit, and the partnership will receive an assignment of an interest in each such lease     23  
The partnership will not acquire title insurance for its leasehold interests, which may be subject to title defects     23  
Participation with third parties in drilling wells may require the partnership to pay additional costs     23  
The partnership’s investments may be concentrated for the most part with one operator, which may have a material adverse effect on the partnership’s performance     24  
The partnership may prepay certain acreage, geological and geophysical costs, and certain drilling and completion costs associated with the wells to be drilled, and as a result the partnership would be a general unsecured creditor of the operator     24  
The partnership may also become an unsecured creditor of the operator or other third parties because the operator and/or such third parties may hold receipts from sales of oil and gas on behalf of the partnership     24  
Initial reserve and revenue estimates have inherent uncertainties and limitations and the Managing GP will not obtain independent reserve evaluations prior to drilling a well     24  
The partnership may secure debt financing, some or all of which may be secured, to pay for costs associated with new drilling, which may affect distributions to investors or otherwise adversely affect an investment in the partnership     25  
Delay in oil or gas production from successful wells, whether from operational or other difficulties or lacking infrastructure, would delay cash distributions and could reduce the partnership’s profitability     25  
The partnership may be required to pay delay rentals to hold properties, and may have to pay increased costs to renew leases, each of which would deplete partnership capital     26  
The partnership may lose oil and gas lease properties due to numerous factors     26  
Environmental hazards involved in drilling oil and natural gas wells may result in substantial liabilities for the partnership     27  
Risks Related to the Partnership’s Organization and Structure     27  
The decisions of the Managing GP may be subject to conflicts of interest     27  
You will have limited voting rights and will be required to rely on the Managing GP to make all investment decisions and achieve the partnership’s investment objectives     28  
The Managing GP’s officers manage other businesses and will not devote their time exclusively to managing the partnership and its business, and the partnership may face additional competition for time and capital because neither the Managing GP nor its affiliates are prohibited from raising money for or managing other entities that pursue the same types of investments that the partnership targets.     28  
The Managing GP may have difficulty managing its growth, which may divert its resources and limit its ability to expand its operations successfully     28  
Operational risks may disrupt the partnership’s business and result in losses     29  
The partnership’s internal controls over financial reporting may not be effective, which could have a significant and adverse effect on our business     29  

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The partnership will be subject to certain reporting requirements and will be required to file certain periodic reports with the Securities and Exchange Commission     29  
Changes in the laws or regulations that affect the terms and conditions set forth in this prospectus and/or the limited partnership agreement could negatively impact the partnership’s and/or your rights and obligations     30  
You are not expected to have any protection under the Investment Company Act     30  
You are not expected to have any protection under the Investment Advisers Act     30  
Risks Related to the Tax Treatment of the Partnership and the Interests     30  
If the IRS classifies the partnership as a corporation rather than a partnership, your distributions would be reduced under current tax law     30  
You may incur tax liability in excess of the cash distributions you receive in a particular year     31  
There are limitations on your ability to deduct the partnership’s losses     31  
This investment may cause you to pay additional taxes     31  
The IRS may allocate more taxable income to you than the Limited Partnership Agreement provides     31  
Some of the distributions paid with respect to the Interests will be a return of capital, in whole or in part, which will complicate your tax reporting and could cause unexpected tax consequences at liquidation     32  
No ruling will be requested from the IRS as to the tax consequences of investing in Interests     32  
The deduction for intangible drilling costs may not be available to you if you do not have passive income     32  
Investment interest deductions that may be available to Investor General Partners may nevertheless be limited     33  
You may not be eligible to claim percentage depletion deductions     33  
The tax benefits that may be available to you from your investment in the partnership are not contractually protected     33  
An IRS audit of the partnership may result in an IRS audit of your personal federal income tax returns     33  
The partnership’s deductions may be challenged by the IRS     33  
Changes in tax laws may reduce the potential tax benefits available from an investment in the partnership     34  
Your deduction for intangible drilling costs may be limited for purposes of the alternative minimum tax     34  
On disposition of property by the partnership or on disposition of Interests by you, certain deductions for intangible drilling costs, depletion, and depreciation must be recaptured as ordinary income     34  
The partnership and its investors may be subject to other taxes besides federal taxes     34  
If you are or invest through a tax-exempt entity or organization, you will have unrelated business taxable income from this investment.     34  
It may be many years before you receive any marginal well production credits, if ever     35  
CONFLICTS OF INTEREST     36  
ACTIONS TO BE TAKEN BY THE MANAGING GP TO REDUCE RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS     44  
SOURCE OF FUNDS AND ESTIMATED USE OF OFFERING PROCEEDS     46  
COMPENSATION     48  
TERMS OF THE OFFERING     57  
PRIOR ACTIVITIES     62  
MANAGEMENT     63  
ALTERNATIVE INVESTMENTS     68  
PROPOSED ACTIVITIES     69  
COMPETITION, MARKETS AND REGULATION     77  

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PARTICIPATION IN COSTS AND REVENUES     81  
FIDUCIARY RESPONSIBILITY OF THE MANAGING GP     86  
FEDERAL INCOME TAX CONSEQUENCES     88  
INVESTMENT BY QUALIFIED PLANS AND IRAS     122  
SUMMARY OF LIMITED PARTNERSHIP AGREEMENT     125  
SUMMARY OF PARTICIPATION AGREEMENT AND OPERATING AGREEMENT     129  
REPORTS TO INVESTORS     130  
PRESENTMENT FEATURE     131  
TRANSFERABILITY OF INTERESTS     133  
PLAN OF DISTRIBUTION     135  
SUBSCRIPTIONS     138  
FURTHER INFORMATION     141  
GLOSSARY     142  
INDEX TO FINANCIAL STATEMENTS     F-1  
FINANCIAL INFORMATION CONCERNING THE MANAGING GP AND THE PARTNERSHIP     F-2  
EXHIBITS:
        
EXHIBIT A — LIMITED PARTNERSHIP AGREEMENT     A-1  
EXHIBIT B — PARTICIPATION AGREEMENT     B-1  
EXHIBIT C — SUBSCRIPTION AGREEMENT     C-1  

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SUITABILITY STANDARDS

In General

An investment in the partnership involves risk and is suitable only for persons who have adequate financial means, desire a relatively long-term investment and who will not need immediate liquidity from their investment. Persons who meet this standard and seek to diversify their personal portfolios with an oil and natural gas-based investment, which among its benefits may provide portfolio diversification, may generate cash distributions, may provide tax benefits, may provide capital growth, and may hedge against inflation, and are able to hold their investment for a time period consistent with the partnership’s liquidity plans, are most likely to benefit from an investment in the partnership. See “Alternative Investments.” On the other hand, an investment in the partnership is not appropriate for persons who require immediate liquidity or guaranteed income, or who seek a short-term investment. Notwithstanding these investor suitability standards, potential investors should consider all of the information contained in this prospectus, including the “Risk Factors” section contained herein, in determining whether an investment in the partnership is appropriate.

The Managing GP will maintain its books and records at its principal office. Such books and records include, among other things, the investor suitability records for a period of six years for any Investor General Partner and/or Limited Partner whose Interests were sold by the Managing GP or any of its affiliates.

It is the obligation of persons selling the Interests to make reasonable efforts to determine that the Interests are suitable for you based on your investment objectives and financial situation, regardless of your income or net worth. However, you should invest in the partnership only if you are willing to assume the risk of a speculative, illiquid, and long-term investment.

The decision to accept or reject your subscription will be made by the Managing GP, in its sole discretion, and is final. The Managing GP will not accept your subscription until it has reviewed your subscription documents, and the records relating to the suitability determination will be maintained for at least six years after acceptance.

Pennsylvania and Tennessee Investors:  Because the minimum closing amount is less than 10% of the maximum closing amount 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. In addition, subscription proceeds received by the partnership from Pennsylvania and Tennessee investors will be placed into a short-term escrow (120 days or less) until subscriptions for at least 5% of the maximum offering proceeds have been received by the partnership, which means that subscriptions for at least $10,000,000 have been received from investors, including Pennsylvania and Tennessee investors. If the appropriate minimum has not been met at the end of the escrow period, the partnership must notify the Pennsylvania investors in writing by certified mail or any other means whereby a receipt of delivery is obtained within 10 calendar days after the end of the escrow period that they have a right to have their investment returned to them. If an investor requests the return of such funds within 10 calendar days after receipt of notification, the partnership must return such funds within 15 calendar days after receipt of the investor’s request.

General Suitability Requirements for Purchasers of Limited Partner Interests

Limited Partner Interests may be sold to you if you meet either of the following requirements:

a net worth of not less than $330,000, exclusive of home, home furnishings, and automobiles; or
a net worth of not less than $85,000, exclusive of home, home furnishings, and automobiles, and had during the last tax year gross income of at least $85,000, without regard to an investment in the partnership.

In addition, if you are a resident of Michigan, Missouri, Oklahoma or Pennsylvania, then you must not make an investment in the partnership that is in excess of 10% of your net worth, exclusive of home, home furnishings and automobiles and if you are a resident of Kentucky or Tennessee, then you must not make an investment in the partnership that is in excess of 10% of your liquid net worth. If you are a resident of Massachusetts, then you must limit your investment in the partnership and other direct participation programs to no more than 10% of your net worth. Further, if you are a resident of Kansas, it is recommended by the

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Office of the Kansas Securities Commissioner that Kansas investors should limit their investment in the partnership and substantially similar programs to no more than 10% of their liquid net worth. Liquid net worth is that portion of your net worth (total assets minus total liabilities) that is comprised of cash, cash equivalents and readily marketable securities. Readily marketable securities may include investments in an IRA or other retirement plan that can be liquidated within a short time, less any income tax penalties that may apply for early distribution. If you are a resident of New Mexico or Oregon, you must not make an investment in the partnership that would, after including your previous investments in any other similar oil and natural gas drilling programs, exceed 10% of your net worth, exclusive of home, home furnishings and automobiles. If you are a resident of Alabama or New Jersey, you must not make an investment in the partnership that would, after including your previous investments in any other similar oil and natural gas drilling programs, exceed 10% of your liquid net worth, exclusive of home, home furnishings and automobiles. Finally, if you are a resident of Ohio, then you must not make an investment in the partnership that would, after including your previous investments, if any, in affiliated programs and other non-traded oil and natural gas programs exceed 10% of your liquid net worth, exclusive of home, home furnishings and automobiles.

General Suitability Requirements for Purchasers of Investor General Partner Interests

If you are a resident of any of the following states or jurisdictions:

   
 1. Alaska,   12. Maryland,   23. South Carolina,
 2. Colorado,   13. Mississippi,   24. South Dakota,
 3. Connecticut,   14. Missouri,   25. Utah,
 4. Delaware,   15. Montana,   26. Vermont,
 5. District of Columbia,   16. Nebraska,   27. Virginia,
 6. Florida,   17. Nevada,   28. West Virginia,
 7. Georgia,   18. New Hampshire,   29. Wisconsin, or
 8. Hawaii,   19. New York,   30. Wyoming,
 9. Idaho,   20. North Dakota,  
10. Illinois,   21. Puerto Rico,     
11. Louisiana,   22. Rhode Island,     

then Investor General Partner Interests may be sold to you if you meet any of the following requirements:

a net worth of not less than $330,000, exclusive of home, home furnishings, and automobiles; or
a net worth in excess of $1,000,000, inclusive of home, home furnishings, and automobiles; or
a net worth of not less than $85,000, exclusive of home, home furnishings, and automobiles, and had during the last tax year gross income of at least $85,000, without regard to an investment in the partnership.

Additionally, if you are a resident of Missouri, then you must not make an investment in the partnership that is in excess of 10% of your net worth, exclusive of home, home furnishings and automobiles.

However, if you are a resident of the states set forth below, then different suitability requirements apply to you if you want to purchase Investor General Partner Interests.

Special Suitability Requirements for Purchasers of Investor General Partner Interests

If you are a resident of any of the following states:

   
1. Alabama,    9. Maine,     
2. Arizona,   10. Massachusetts,   17. Oklahoma,
3. Arkansas,   11. Michigan,   18. Oregon,
4. California,   12. Minnesota,   19. Pennsylvania,
5. Indiana,   13. New Jersey,   20. Tennessee,
6. Iowa,   14. New Mexico   21. Texas, or
7. Kansas,   15. North Carolina,   22. Washington,
8. Kentucky,   16. Ohio,  

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and you subscribe for Investor General Partner Interests, then you must meet one of the following special suitability requirements:

an individual or joint net worth with your spouse of $330,000 or more, without regard to the investment in the partnership, exclusive of home, home furnishings, and automobiles, and a combined gross income of $150,000 or more for the current year and for each of the two previous years; or
an individual or joint net worth with your spouse in excess of $750,000, exclusive of home, home furnishings, and automobiles; or
a net worth in excess of $1,000,000, inclusive of home, home furnishings, and automobiles; or
a combined “gross income” as defined in Section 61 of the Internal Revenue Code (the “Code”) in excess of $200,000 in the current year and the two previous years.

In addition, if you are a resident of Iowa, Michigan, Oklahoma or Pennsylvania, then you must not make an investment in the partnership that is in excess of 10% of your net worth, exclusive of home, home furnishings, and automobiles. If you are a resident of New Mexico or Oregon, then you must not make an investment in the partnership that would, after including your previous investments, if any, and any other similar oil and natural gas drilling programs, exceed 10% of your net worth, exclusive of home, home furnishings and automobiles. Further, if you are a resident of Alabama or New Jersey, then you must not make an investment in the partnership that would, after including your previous investments, if any, and any other similar oil and natural gas drilling programs, exceed 10% of your liquid net worth, exclusive of home, home furnishings and automobiles, and, if you are a resident of Tennessee or Kentucky, then you must not make an investment in the partnership that is in excess of 10% of your liquid net worth. If you are a resident of Massachusetts, then you must limit your investment in the partnership and other direct participation programs to no more than 10% of your net worth. If you are a resident of Ohio, then you must not make an investment in the partnership that would, after including your previous investments, if any, in affiliated programs and other non-traded oil and gas programs, exceed 10% of your liquid net worth. 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 partnership and substantially similar programs to no more than 10% of their liquid net worth. Liquid net worth is that portion of your net worth (total assets minus total liabilities) that is comprised of cash, cash equivalents and readily marketable securities. Readily marketable securities may include investments in an IRA or other retirement plan that can be liquidated within a short time, less any income tax penalties that may apply for early distribution.

Suitability Requirements for Qualified Plans and IRAs

An IRA can purchase the Interests if the IRA owner meets both the basic suitability standard and any standard applicable in the owner’s State of residence. Pension, profit-sharing or stock bonus plans, including Keogh Plans, that meet the requirements of Section 401 of the Code are called qualified plans in this prospectus. Qualified plans that are self-directed may purchase the Interests if the plan participant meets both the basic suitability standard and any standard applicable in the participant’s State of residence. Qualified plans that are not self-directed may purchase the Interests if the plan itself meets both the basic suitability standard and any relevant State standard.

Fiduciary Accounts

If there is a sale of a Interest to a fiduciary account other than an IRA or a qualified plan, such as a trust, both the basic suitability standards and any applicable State suitability standards must be met by the beneficiary, the fiduciary account, or the donor or grantor who directly or indirectly supplies the funds to purchase the Interests if the donor or grantor is the fiduciary.

Generally, you are required to execute your own subscription agreement, and the Managing GP 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.

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Additional Considerations for IRAs, Qualified Plans and Tax-Exempt Organizations

An investment in the Interests will not, in and of itself, create an IRA or qualified plan. To form an IRA or qualified plan, an investor must comply with all applicable provisions of the Code and the Employee Retirement Income Security Act of 1974 (“ERISA”). IRAs, qualified plans and tax-exempt organizations should consider the following when deciding whether or not to invest:

any income or gain realized will be unrelated business taxable income (“UBTI”), which, depending on the amount of such UBTI, may be subject to the unrelated business income tax;
for qualified plans and IRAs, ownership of the Interests may cause a pro rata share of the partnership’s assets to be considered plan assets for the purposes of ERISA and the excise taxes imposed by the Code;
any entity that is exempt from federal income taxation will be unable to take full advantage of any tax benefits generated by the partnership; and
charitable remainder trusts that have any UBTI will be subject to an excise tax equal to 100% of such UBTI.

Although the Interests may represent suitable investments for some IRAs, qualified plans and tax-exempt organizations, the Interests may not be suitable for your plan or organization due to the particular tax rules that apply to your plan or organization. Furthermore, the investor suitability standards represent minimum requirements, and the fact that your plan or organization satisfies them does not mean that an investment would be suitable. You should consult your plan’s tax and financial advisors to determine whether this investment would be advantageous for your particular situation.

If you are a fiduciary or investment manager of a qualified plan or IRA, or if you are a fiduciary of another tax-exempt organization, you should consider all risks and investment concerns, including those related to tax considerations, in deciding whether this investment is appropriate and economically advantageous for your plan or organization. See “Risk Factors,” “Federal Income Tax Consequences” and “Investment by Qualified Plans and IRAs.”

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FORWARD-LOOKING STATEMENTS

Certain statements within this prospectus, including the sections entitled “Prospectus Summary,” “Risk Factors,” “Investment Objectives” and “Proposed Activities,” may constitute forward-looking statements. Forward-looking statements are those that do not relate solely to historical fact. They include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. You can identify these statements by the use of words such as “may,” “will,” “could,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “predict,” “continue,” “further,” “seek,” “plan” or “project” and variations of these words or comparable words or phrases of similar meaning.

These forward-looking statements include such things as:

investment objectives;
references to future success in the partnership’s drilling and marketing activities;
business strategy;
estimated future capital expenditures;
competitive strengths and goals; and
other similar matters.

These forward-looking statements reflect the partnership’s current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside the partnership’s control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under “Risk Factors” and the following:

general economic, market, or business conditions;
changes in laws or regulations;
the risk that the wells are productive, but do not produce enough revenue to return the investment made;
the risk that the wells are dry holes; and
uncertainties concerning the price of natural gas and oil, which may decrease.

Although the partnership believes the expectations reflected in such forward-looking statements are based upon reasonable assumptions, the partnership cannot assure investors that the partnership’s expectations will be attained or that any deviations will not be material. Readers are cautioned that forward-looking statements speak only as of the date they are made and that, except as required by law, the partnership undertakes no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section.

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PROSPECTUS SUMMARY

The following summary highlights material information contained elsewhere in this prospectus. It does not contain all of the information that an investor may consider important in making its investment decision and is qualified in its entirety by the more detailed information and financial statements included elsewhere in this prospectus. Therefore, you should read the entire prospectus, including the section entitled “Risk Factors,” carefully before making an investment decision.

This prospectus relates to the offering of Interests in ICON Oil & Gas Fund-A L.P. only and all references to “the partnership” herein will mean ICON Oil & Gas Fund-A L.P. The interests in the other partnerships in ICON Oil & Gas Fund will be offered pursuant to separate prospectuses. See “Terms of the Offering” for a discussion of the terms and conditions involved in investing in the Interests offered hereby.

The Partnerships and the Managing GP

ICON Oil & Gas Fund is an oil and natural gas drilling fund consisting of up to three Delaware limited partnerships. Interests in the partnerships will be offered and sold in a series beginning with the offering of interests in the first partnership, ICON Oil & Gas Fund-A L.P. Each partnership in ICON Oil & Gas Fund will be a separate and distinct legal entity with its own business purpose. 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 (the “Limited Partnership Agreement”). For a summary of the material provisions of the Limited Partnership Agreement that are not covered elsewhere in this prospectus, see “Summary of Limited Partnership Agreement.” You will be a partner only in the partnership(s) 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 such other partnerships. Thus, your investment return will depend solely on the operations of the partnership(s) in which you invest. Each partnership has a maximum 50-year term, although the Managing GP intends to terminate each partnership when all of the wells invested in by such partnership become uneconomical to continue to operate, which may be approximately seven to 15 years.

ICON Oil & Gas GP, LLC is the managing general partner (the “Managing GP”) of the partnership. The Managing GP is a Delaware limited liability company and is a wholly-owned subsidiary of ICON Investment Group, LLC, a Delaware limited liability company (“ICON Investment Group”). The Managing GP manages and controls the partnership’s business affairs, including, but not limited to, the drilling activity contemplated hereby. Pursuant to the terms of an administration agreement, the Managing GP has engaged an affiliate, ICON Capital Corp. (“ICON Capital”), to, among other things, provide it with facilities, investor relations and administrative support. The address and telephone number of the partnership and the Managing GP are c/o ICON Capital Corp., 3 Park Avenue, 36th Floor, New York, New York 10016, 212-418-4700.

The proceeds from the sale of the Interests will be used to invest primarily in oil and liquids-rich natural gas development wells, principally “fluid management” projects, where hydrocarbons are known to be present, located in the Mid-Continent region of the United States, with the potential investment in properties located within other types of projects and/or in other geographic areas that the Managing GP may, from time to time, identify as prospective (collectively, the “Projects”). See “Proposed Activities.” A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. As of the date of this prospectus, the partnership does not hold any interests in any properties or prospects on which its wells will be drilled.

Investment Objectives

The partnership was formed to enable investors to invest in the Projects, which are presently expected to comprise the partnership’s entire investment portfolio. The primary objectives of the partnership are to:

generate revenue from the production and sale of oil, natural gas and natural gas liquids from the Projects;
distribute cash to its investors; and
provide tax benefits in the year that the offering commences and in future years.

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The partnership will participate in drilling one or more wells in some or all of the Projects. In addition, the Managing GP may add to or substitute wells between these Projects and other projects that are believed to have similar economic and risk profiles.

The Managing GP reserves the right to acquire projects that have existing oil and natural gas production and related infrastructure. In such case, this could result in faster cash flow to the partnership’s investors, but also a reduction in up-front tax deductions. As of the date of this prospectus, no such projects have been identified.

Description of Interests

On subscribing for Interests, you may elect to buy either:

Investor General Partner Interests; or
Limited Partner Interests.

The type of Interest you buy will not affect the allocation of costs, revenues, and cash distributions among the investors in the partnership. There are, however, material differences in the federal income tax consequences and liability associated with each type of Interest. Under the Limited Partnership Agreement, no investor may participate in the management of the partnership or its business. The Managing GP will have exclusive management authority for the partnership.

Investor General Partner Interests

Tax Consequences.  If you invest as an Investor General Partner, then your share of the partnership’s deduction for intangible drilling costs will not be subject to the passive activity limitations on losses. You may claim a deduction in an amount equal to not less than the percentage of your net subscription amount used to pay for intangible drilling costs for all of the wells to be drilled by the partnership in that taxable year. See “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. For example, intangible drilling costs include 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 oil or natural gas. Intangible drilling costs also include the expense of plugging and abandoning any well before a completion attempt, and the costs (other than non-deductible equipment costs and lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.
Unlimited Liability.  If you invest as an Investor General Partner, you will have unlimited liability regarding the partnership’s activities. This means that if (i) the partnership’s insurance proceeds from any source, (ii) the Managing GP’s indemnification of the Investor General Partners, and (iii) the partnership’s assets were, collectively, not sufficient to satisfy a partnership liability for which the Investor General Partners were also liable solely because of your status as general partners of the partnership, then the Managing GP would require the Investor General Partners to make additional capital contributions to the partnership to satisfy the liability. In addition, the Investor General Partners will have joint and several liability, which means, generally, that a person with a claim against the partnership and/or an Investor General Partner may sue all or any one or more of the partnership’s general partners, including you, for the entire amount of the liability.

You will be able to determine if your Interests are subject to assessability based on whether you buy Investor General Partner Interests, which are assessable, or Limited Partner Interests, which are non-assessable.

Your Investor General Partner Interests will be automatically converted by the Managing GP to Limited Partner Interests upon the occurrence of the earlier of (i) the drilling and completion of all of the partnership’s wells, as determined by the Managing GP’s geologists, or (ii) the date that no additional currently deductible

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intangible drilling costs will be realized by the partnership’s Investor General Partners, as determined by the Managing GP. In this regard, a well is deemed to be completed when production equipment is installed on a well, even though the well may not yet be connected to a pipeline for production of oil or natural gas. The timeline for such conversion depends on the timing and amount of the sale of the Interests as well as the availability of appropriate Projects being sourced by the partnership’s operators. The partnership will generally invest in Projects at the time leases are acquired through the completion of the wells. Once all of the wells within all of the partnership’s Projects are completed, the Investor General Partner Interests will then be converted to Limited Partner Interests. If the offering raises the maximum offering amount, the partnership will be able to drill more wells and the larger number of wells would be expected to take longer to drill. If the offering raises less than the maximum offering amount, the number of wells that may be drilled will be less and, therefore, drilling would be expected to be completed sooner. The conversion is not expected to create any tax liability to the investors.

Once your Interests are converted, you will have the limited liability of a limited partner under Delaware law for partnership 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 amount 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 the conversion.

Limited Partner Interests

Tax Consequences.  If you invest as a Limited Partner, then your use of your share of the partnership’s deduction for intangible drilling costs will be limited to offsetting your net passive income from “passive” trade or business activities.
º Passive trade or business activities generally include the partnership and other limited partner investments, but passive income does not include salaries, dividends or 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 net passive income. However, any portion of your share of the partnership’s deduction for intangible drilling costs that you cannot use in the year in which you invest, because you do not have sufficient net passive income in that year, may be carried forward indefinitely until you can use it to offset your net passive income from the partnership or your other passive activities, if any, in subsequent tax years. See “Federal Income Tax Consequences — Limitations on Passive Activity Losses and Credits.”
Limited Liability.  If you invest as a Limited Partner, then you will have limited liability for the partnership’s liabilities and obligations. This means that you will not be liable for any partnership liabilities or obligations beyond the amount of your subscription amount in the partnership and your share of the partnership’s undistributed net profits, subject to certain exceptions set forth in “Summary of Limited Partnership Agreement — Liability of Limited Partners.”

The Managing GP reserves the right to offer new types of Interests, either in addition to or in lieu of Investor General Partner Interests and/or Limited Partner Interests, in the future. Specifically, the Managing GP may, at some point, offer net profits interests, which would generally be treated as a type of royalty interest for federal tax purposes and should qualify as an exempted royalty for unrelated business income tax purposes. Holders of net profits interests will generally be entitled to depletion allowances but will generally not qualify for intangible drilling cost and depreciation deductions.

Risk Factors

This offering involves numerous risks, including risks related to the partnership’s oil and natural gas operations, risks related to an investment in the partnership and tax risks. You should carefully consider a number of significant risk factors inherent in and affecting the business of the partnership and this offering, including the following:

The partnership’s drilling operations involve the possibility of a total or partial loss of your investment because the partnership may drill (i) wells that are productive, but that do not produce enough revenue to return the investment made, and (ii) from time to time, dry holes.

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The partnership’s revenues are directly related to its ability to market the oil and natural gas produced from the wells it drills and oil and natural gas prices, which are volatile and uncertain. If oil and natural gas prices decrease, then the return on your investment will decrease.
If you choose to invest as an Investor General Partner, you will have unlimited joint and several liability for partnership obligations until you are converted to a Limited Partner.
The partnership has a limited operating history, no established financing sources and this is the first oil and gas program sponsored by the Managing GP and its affiliates.
Interests are not liquid and your ability to resell your Interests will be limited by the absence of a public trading market and substantial transfer restrictions.
There is no guaranty that cash distributions will be paid from the partnership in any amount or frequency.
The decisions of the Managing GP may be subject to conflicts of interest.
You will have limited voting rights and will be required to rely on the Managing GP to make all investment decisions and achieve the partnership’s investment objectives.
Taxable income may be allocated to you in excess of the cash distributions you receive from the partnership.

Management

Managing GP

The partnership will be managed by the Managing GP. The Managing GP manages and controls the partnership’s business affairs including, but not limited to, the drilling activity contemplated hereby. Pursuant to the terms of an administration agreement, the Managing GP has engaged ICON Capital to, among other things, provide it with facilities, investor relations and administrative support. The principal office of the Managing GP is located at c/o ICON Capital Corp., 3 Park Avenue, 36th Floor, New York, New York, 10016 and its telephone number is (212) 418-4700. For more information about the Managing GP and ICON Capital, see the “Management” and “Conflicts of Interest” sections of this prospectus.

The Managing GP’s current executive management team, led by Michael A. Reisner, Co-Chairman, Co-Chief Executive Officer and Co-President and Mark Gatto, Co-Chairman, Co-Chief Executive Officer and Co-President, has worked together since 2001. Messrs. Reisner and Gatto would be considered the partnership’s “promoters.” The background and experience of the Managing GP’s management team is described in the “Management” section of this prospectus. Also, in that section, the persons currently employed by or under contract to the Managing GP who have extensive experience in oil and gas drilling are described.

ICON Capital is also the sole stockholder of ICON Securities, the dealer-manager of this offering.

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The following diagram shows the Managing GP’s and certain affiliates’ relationship to the partnerships. The Managing GP and its parent, ICON Investment Group, are affiliates of ICON Capital and ICON Securities under common control.

[GRAPHIC MISSING]

Operators

With respect to each Project, the partnership will partner with one or more oil and gas operators, in each case, subject to a participation agreement (including, in each case, an attached operating agreement) (each, a “Participation Agreement”). Each Participation Agreement generally provides that the related operator will conduct and direct, and have full control of, all operations with respect to specified oil and natural gas prospects within one or more Projects. Each Participation Agreement will continue in force so long as any of the oil and natural gas leases subject to such Participation Agreement remain or are continued in force as to the Project(s), whether by production, extension, renewal or otherwise.

Special Energy Corporation

The partnership anticipates entering into Participation Agreements with Special Energy Corporation (“Special Energy”) with respect to certain prospects in the Hunton limestone formation and other formations similar in profile, as well as conventional oil and liquids-rich natural gas plays, in the Mid-Continent region of the United States. Special Energy is a Stillwater, Oklahoma-based independent oil and gas operating company particularly focused on dewatering as well as conventional oil and liquids-rich natural gas plays in the Mid-Continent Region of the United States. In 2009, the Oklahoma Corporation Commission ranked Special Energy 33rd among the top 100 gas producers and 52nd among the top oil producers in the State of Oklahoma based on gross production.

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Participation in Costs and Revenues

The following table sets forth how the partnership’s costs (in excess of cumulative revenues) and revenues (in excess of cumulative costs) will be charged and credited between the Managing GP and the investors after deducting from the partnership’s gross revenues the landowner royalties and any other lease burdens. The percentages in the table are based on the Managing GP (i) making a capital contribution equal to 1% of total investor capital contributions (net of O&O Costs and the management fee) in the form of payment of a portion of program costs and (ii) not purchasing any Interests.

   
  Managing GP   Interests
Issued by the
Partnership
Partnership Costs
                 
Intangible drilling costs     1 %      99 % 
Well drilling and completion costs(1)     1 %      99 % 
O&O Costs(2)     1 %      99 % 
Lease costs       (3)        (3) 
Administrative costs, direct costs, and all other costs(4)     11 %      89 % 
Partnership Revenues
                 
Interest income(5)     11 %      89 % 
All other revenues, including production revenues(6)     11 %      89 % 

(1) The net offering proceeds will be used to pay up to 99% of the non-deductible equipment costs incurred by the partnership in drilling and completing its wells. If the Managing GP pays for any portion of such non-deductible equipment costs, the Managing GP will receive a share of the partnership’s revenues in the same percentage as such non-deductible equipment costs are paid by the Managing GP.
(2) The gross offering proceeds will be used to pay up to 99% of the “O&O Costs,” which include (i) the dealer-manager fee, (ii) sales commissions and (iii) other costs related to the organization of the partnership and the offering of the Interests.
(3) The net offering proceeds may be used to directly acquire the leases covering a portion of the acreage on which the partnership’s wells will be drilled. If the relevant operator for a Project directly acquires the relevant leases, the net offering proceeds will be used to acquire an assigned interest in such leases.
(4) This table reflects the partnership’s anticipation that its production revenue otherwise allocable between the investors and the Managing GP will be used to pay these costs. If, however, these costs exceed the partnership’s production revenue, then in any given year the investors and the Managing GP may bear a percentage of these costs that differs from their share of the production revenue in that year, which share may vary from year to year under the Limited Partnership Agreement. Other such costs also include the plugging and abandonment costs of the wells after their economic reserves have been produced and depleted. If the Managing GP pays for any portion of any of these costs, the Managing GP will receive a share of the partnership’s revenues in the same percentage as such costs are paid by the Managing GP.
(5) Net offering proceeds will earn interest until they are released from escrow for use in drilling activities, which interest will be credited to your account and paid to you upon admission to the partnership in a special one-time distribution equal to the initial distribution rate, as determined by the Managing GP, pro rated for each day your funds were held in escrow, but without any interest on your escrow funds. Any other interest income will be credited as oil and natural gas production revenues are credited.
(6) The Managing GP and the investors will share in all other revenues in the same percentage as their respective capital contributions bears to total net capital contributions, except that the Managing GP will receive an additional 10% of such revenues.

Distributions

The Managing GP will review the partnership’s account at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. The partnership will distribute funds to investors that the Managing GP does not believe are necessary for the partnership to retain. See “Participation in Costs and Revenues.”

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Insurance

The partnership will obtain various insurance policies and intends to maintain such policies subject to its analysis of the premium costs, coverage and other factors. The partnership will be the beneficiary under its policies and pay the premiums for each of its policies. In the exercise of the Managing GP’s fiduciary duty, it will obtain insurance on behalf of the partnership to provide the partnership with coverage sufficient to protect the Investor General Partners against the foreseeable risks of drilling and production. This coverage may include being named as an additional insured in each Project under the relevant operator’s insurance policies. The Managing GP will review the partnership’s insurance coverage prior to commencing drilling operations and periodically evaluate the sufficiency of insurance. See “Actions to Be Taken by the Managing GP to Reduce Risks of Additional Payments by Investor General Partners.”

Indemnification

The Managing GP will indemnify the Investor General Partners from any liability incurred in connection with the partnership that is in excess of their interest in the partnership’s undistributed net assets and insurance proceeds, if any, from all potential sources.

The Managing GP’s indemnification obligation, however, will not eliminate investors’ potential liability if the Managing GP’s assets are insufficient to satisfy its indemnification obligation. There can be no assurance that the Managing GP’s assets, including its liquid assets, will be sufficient to satisfy its indemnification obligation. See “Actions to be Taken by the Managing GP to Reduce Risks of Additional Payments by Investor General Partners — Indemnification.”

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THE OFFERING

Offering    
    A minimum of 200 Interests and a maximum of up to 20,000 Interests; provided, that, in its sole discretion, the Managing GP may, at any time prior to the two-year anniversary of the date of this prospectus, increase the offering to a maximum of up to 30,000 Interests; provided further, that the Managing GP may not extend the offering period in connection with such change. In the event that the Managing GP increases the size of the offering, the partnership will file a separate registration statement on Form S-1 regarding the additional Interests that it offers.
Offering Period    
   

•  

For the partnership, beginning on the date of this prospectus and expected to end no later than December 31, 2012, unless this offering is extended by the Managing GP pursuant to a supplement to this prospectus.

   

•  

For ICON Oil & Gas Fund, which comprises up to three oil and gas drilling partnerships, the first of which is being offered hereby, beginning on the date of this prospectus and expected to end no later than the two-year anniversary of the date of this prospectus.

    The Managing GP intends to offer interests in the other partnerships sequentially and will not offer interests in more than one partnership at a time. The Managing GP may terminate the offering period for a partnership at any time prior to the scheduled end of such offering period. In certain states in which the partnerships will be registered to offer Interests, such registrations must be updated annually.
Offering Price    
    $10,000 per Interest; $9,300 per Interest for Interests sold to the Managing GP, selling dealers or certain of their affiliates, as well as registered investment advisers and their clients. A minimum subscription in the partnership is one half (½) Interest ($5,000). Fractional subscriptions will be accepted in $1,000 increments, beginning, for example, with $6,000, $7,000, etc. See “Plan of Distribution.”
Escrow(1)    
    For each partnership within ICON Oil & Gas Fund, the Managing GP will deposit and hold an investor’s investment in an interest-bearing escrow account at UMB Bank, N.A. until (i) the minimum offering amount of $2,000,000 has been achieved for such partnership, (ii) the termination of the relevant offering period by the Managing GP, or (iii) the end of the relevant offering period, whichever comes first.
    Investors (other than Pennsylvania and Tennessee investors who will receive a similar one-time distribution upon their admission) who invest prior to the minimum offering size being achieved for a partnership will receive, upon admission into the partnership, a one-time distribution of interest for the period their funds were held in escrow.
    On receipt of the minimum offering proceeds, the Managing GP, on the partnership’s behalf, will break escrow, transfer

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    the escrowed offering proceeds to the partnership’s account, which will be a separate account maintained for the partnership, and begin the partnership’s activities, including drilling. The partnership’s funds will not be commingled with funds of any other entity.
    Any other interest income will be credited as oil and natural gas production revenues are credited. See “Terms of the Offering.”
Estimated Use of Offering Proceeds    
    The partnership must receive minimum offering proceeds of $2,000,000 to break escrow, and the maximum offering proceeds may not exceed $200,000,000. Whether the partnership receives only the minimum or the partnership receives the maximum offering proceeds from the investors, the offering proceeds will be used to pay the following:
   

•  

99% of the intangible drilling costs, as described above in “— Description of Interests,” of drilling and completing the partnership’s wells;

   

•  

up to 99% of the non-deductible equipment costs of drilling and completing the partnership’s wells; and

   

•  

up to 99% of (1) the O&O Costs, which include (i) the dealer-manager fee, (ii) sales commissions and (iii) other costs related to the organization of the partnership and the offering of the Interests, and (2) the management fee, as described below in “— Compensation of the Managing GP, Its Affiliates and Certain Non-Affiliates.” The sum of the O&O Costs and the management fee will equal but not exceed 15% of the gross offering proceeds.

    The offering proceeds may also be used to pay a portion of the partnership’s lease costs, administrative costs and direct costs, as well as other costs incurred by the partnership in drilling and maintaining its wells.
Compensation of the Managing GP, Its Affiliates and Certain Non-Affiliates    
    The Managing GP, its affiliates, including ICON Securities, and certain non-affiliates (namely, selling dealers and operators) will receive fees and compensation from the offering of the Interests, including the following:
   

•  

The Managing GP will receive a share of the partnership’s revenues. The Managing GP’s revenue share will be in the same percentage that its capital contribution bears to the total capital contributions plus an additional 10% of partnership revenues. The Managing GP will make a minimum capital contribution at least equal to 1% of total investor capital contributions (net of O&O Costs and the management fee). All or a portion of the Managing GP’s capital contribution may be in the form of payments for a portion of program costs, including, but not limited to, (i) leases contributed

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    to the partnership (measured at either cost or fair market value if the Managing GP has reason to believe that cost is materially more than fair market value), (ii) payments for a portion of the non-deductible equipment costs of well drilling and completion, and/or (iii) payments for a portion of O&O Costs. The Managing GP will receive a proportionate credit to its capital account in the aggregate amount of any such payments and services as discussed in “Participation in Costs and Revenues.” See “Source of Funds and Estimated Use of Offering Proceeds” and “Federal Income Tax Consequences — Intangible Drilling Costs” for more information.
   

•  

Subject to certain exceptions described in “Plan of Distribution,” as part of the O&O Costs, the partnership will pay (i) to ICON Securities a dealer-manager fee equal to 3% of the gross offering proceeds and (ii) to the selling dealers sales commissions of up to 7% of the gross offering proceeds and bona fide due diligence expense reimbursements, on a fully accountable basis, based upon receipt of a detailed and itemized invoice.

   

•  

The partnership will pay to the Managing GP a management fee equal to 15% of gross offering proceeds less the sum of all O&O Costs.

   

•  

The partnership will reimburse the Managing GP and its affiliates for their (i) administrative costs, subject to applicable caps and on a fully accountable basis, (ii) direct costs, on a fully accountable basis, and (iii) other costs incurred on behalf of the partnership in drilling and maintaining its wells.

   

•  

If the Managing GP or any of its affiliates serves as the operator for any of the partnership’s wells, the Managing GP or such affiliate, as applicable, may charge a Supervisory Fee for operating and maintaining the wells during producing operations. Neither the Managing GP nor any of its affiliates anticipate serving as operator for any of the partnership’s wells. Accordingly, neither the Managing GP nor any of its affiliates anticipate charging a Supervisory Fee for such services. If the Managing GP or any of its affiliates were to serve as operator for any of the partnership’s wells, the Supervisory Fee for such services would be at a rate competitive with rates charged by third-party operators providing similar services, but not based on arm’s-length negotiations. See “Conflicts of Interest — Conflicts Regarding Transactions with the Managing GP and its Affiliates.”

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•  

The unaffiliated operator(s) will receive compensation, at competitive rates, for drilling and completing the partnership’s wells pursuant to the related Participation Agreement(s), as described in “Compensation — Drilling Contracts.”

   

•  

When the partnership’s wells begin producing oil and/or natural gas in commercial quantities, the applicable unaffiliated operator(s) (i) will receive reimbursement at actual cost for all direct expenses incurred by it on behalf of the partnership, and (ii) may receive well supervisory fees, at competitive rates, for maintaining and operating the wells during producing operations.

   

•  

The partnership will pay to the operator or third-party gathering system gathering fees, at competitive rates, for its services in gathering and transporting the partnership’s oil and/or natural gas production.

   

•  

The partnership may pay to the Managing GP gas marketing fees, at competitive rates, but not based on arm’s-length negotiations, for its services, if any, in marketing the natural gas production. The Managing GP does not currently anticipate participating in the marketing of its natural gas production, and thus, does not anticipate charging any gas marketing fees. See “Conflicts of Interest — Conflicts Regarding Transactions with the Managing GP and its Affiliates.”

   

•  

The Managing GP or an affiliate will have the right to charge a rate of interest equal to its cost of funding on any loan it may make to or on behalf of the partnership. If the Managing GP or an affiliate provides equipment, supplies, and other services to the partnership, then it may be compensated for the cost to the Managing GP or such affiliate of such equipment, supplies or other services or at competitive industry rates, but not based on arm’s-length negotiations, whichever is less. See “Conflicts of Interest — Conflicts Regarding Transactions with the Managing GP and its Affiliates.”

    See “Compensation” for more information about the fees the partnership will pay the Managing GP, its affiliates and certain non-affiliates, including the operator(s).
Conflicts of Interest    
    The partnership will be subject to conflicts of interest because of its relationship to the Managing GP and its affiliates. These conflicts may include:
   

•  

the lack of arm’s-length negotiations in determining the Managing GP’s and its affiliates’ compensation;

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•  

the substantial compensation the Managing GP and its affiliates will receive for the management of the partnership’s business;

   

•  

competition with other oil and natural gas drilling partnerships managed and/or sponsored by the Managing GP and its affiliates, including competition for prospects to be drilled; and

   

•  

competition for management services with other funds that the Managing GP and its affiliates sponsor and/or manage.

Limited Partnership Agreement    
    The relationship between investors and the Managing GP is governed by the Limited Partnership Agreement, a copy of which is attached to this prospectus as Exhibit A. Investors should be particularly aware that under the Limited Partnership Agreement:
   

•  

investors will have limited voting rights;

   

•  

the Interests will not be freely transferable; and

   

•  

the fiduciary duty of the Managing GP has been modified because the Managing GP may sponsor and/or manage other similar funds.

Subscriptions    
    Investors must fill out a subscription agreement (Exhibit C to this prospectus) in order to purchase Interests. By signing the subscription agreement, investors will be making the representations and warranties contained in the subscription agreement and will be bound by all of the terms and conditions set forth in the subscription agreement and the Limited Partnership Agreement.
Restrictions on Transfers    
    An investment in Interests is subject to substantial transfer restrictions. See “Transferability of Interests — Restrictions on Transfers.”
Federal Income Tax Consequences    
    This prospectus contains a discussion of the material federal income tax consequences pertinent to investors, including whether the partnership will be taxed as a partnership or as a corporation. The Managing GP has obtained an opinion from its counsel concerning the partnership’s classification for federal income tax purposes as a partnership. In addition, this prospectus contains a discussion of the availability of certain oil and natural gas tax benefits, including the expense deduction for intangible drilling costs and the percentage depletion allowance. See “Federal Income Tax Consequences” for more information.
Plan of Distribution    
    The initial closing of the offering of Interests by the partnership will be held after subscriptions for at least 200 Interests have been received by the escrow agent (excluding subscriptions from residents of Pennsylvania(1) and Tennessee). At that time, subscribers for at least that number of Interests may be admitted as either Investor General Partners or Limited Partners, at the subscriber’s election at the time of subscription. After the initial closing, the

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    partnership intends to hold daily closings until the offering is completed or terminated.

(1) A Pennsylvania resident’s investment is further subject to the conditions that (i) it must be held in escrow until at least $10,000,000 (5.0% of the maximum offering of $200,000,000) has been received; and (ii) investors are offered the opportunity to rescind their investment if $10,000,000 has not been received within 120 days following the date their funds are received by the escrow agent, and every 120 days thereafter, during the offering period in Pennsylvania. In addition, their investment will be held in escrow until the end of the 120-day period following the effective date of the offering during which their money was received. During this period, aggregate subscriptions of $10,000,000 must be received and accepted for Pennsylvania investors to be admitted as either an Investor General Partner or a Limited Partner or investors will have the option to have their investment refunded.

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RISK FACTORS

An investment in the partnership involves a high degree of risk and is suitable only if you have substantial financial means and no need of liquidity in your investment.

Risks Related to an Investment in the Partnership

If you choose to invest as an Investor General Partner, you will have unlimited joint and several liability for partnership obligations until you are converted to a Limited Partner.

If you elect to invest in the partnership as an Investor General Partner for the tax benefits that are not available if you invest as a limited partner, then under Delaware law you will have unlimited liability for the partnership’s activities until your investment is converted to limited partner status, subject to certain exceptions described in “Actions to be Taken by Managing GP to Reduce Risks of Additional Payments by Investor General Partners — Conversion of Investor General Partner Interests to Limited Partner Interests.” 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 Limited Partnership Agreement, if you are an Investor General Partner you agree to pay only your proportionate share, as among all of the partnership’s Investor General Partners, of the partnership’s obligations and liabilities. This agreement, however, does not eliminate your liability to third parties if another Investor General Partner does not pay his proportionate share of the partnership’s obligations and liabilities.

Also, the partnership is expected to own less than 100% of the working interest in most, if not all, 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 the Investor General Partners also would be liable for those costs and liabilities.

As an Investor General Partner you may become subject to the following:

contract liability, which is not covered by insurance;
liability for pollution, abuses of the environment, and other environmental damages as discussed in “Competition, Markets and Regulation — Environmental Regulation,” including, but not limited to, the release of toxic gas, spills or uncontrollable flows of natural gas, oil or well fluids, including underground or surface contamination, against which the Managing GP cannot insure because coverage is not available or against which it may elect not to insure because of high premium costs or other reasons; and
liability for drilling hazards (which include, but are not limited to, well blowouts, fires, craterings and explosions) that result in property damage, personal injury, or death to third-parties in amounts greater than the insurance coverage.

If the partnership’s insurance proceeds and assets, the Managing GP’s indemnification of the Investor General Partners, and the liability coverage provided by major subcontractors (including the operator) were not sufficient to satisfy the liability, then the Managing GP would call for additional funds from the Investor General Partners to satisfy the liability. See “Actions to be Taken by Managing GP to Reduce Risks of Additional Payments by Investor General Partners,” including the Managing GP’s public liability insurance coverage with limits, including umbrella policy limits, of $50 million, which may not be adequate. Additionally, any drilling hazards may result in the loss of the affected well and associated revenues. Finally, an Investor General Partner may have liability if the partnership does not properly plug and abandon a well. See “Participation in Costs and Revenues — Costs — Administrative Costs, Direct Costs and All Other Costs” relating to the costs associated with plugging and abandoning wells.

The partnership has limited prior operating history, no established financing sources and this is the first oil and gas program sponsored by the Managing GP and its affiliates.

The partnership, which was formed in 2011, has a limited operating history, and accordingly, has no direct costs and administrative costs associated with prior operations to disclose, as required by the North American Securities Administrators Association, Inc.’s Guidelines for Registration of Oil and Gas Programs,

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as amended (the “NASAA Guidelines”) in effect as of the date of this prospectus. This is the first oil and gas program sponsored by the Managing GP and its affiliates. You should consider an investment in the partnership in light of the risks, uncertainties and difficulties frequently encountered by companies that are, like the partnership, in their early stage of development. The partnership cannot guarantee that it will succeed in achieving its goals, and its failure to do so could cause you to lose all or a portion of your investment.

Interests are not liquid and your ability to resell your Interests will be limited by the absence of a public trading market and substantial transfer restrictions.

If you invest in the partnership, then you must assume the risks of an illiquid investment. Securities laws, tax laws, and the Limited Partnership Agreement limit the transferability of Interests. The Interests generally cannot be liquidated since there is not a readily available market for the sale of Interests. Further, the partnership does not intend to list Interests on any exchange. See “Transferability of Interests — Restrictions on Transfer Imposed by Securities Laws, Tax Laws and the Limited Partnership Agreement.”

Also, a sale of your Interests could create adverse tax and economic consequences for you. The sale or exchange of all or part of your Interests held for more than 12 months generally will result in recognition of long-term capital gain or loss. However, previous deductions for depreciation, depletion and intangible drilling costs may be recaptured as ordinary income rather than capital gain regardless of how long you have owned your Interests. If you have held your Interests for 12 months or less, then the gain or loss generally will be short-term gain or loss. Also, your pro rata share of the partnership’s liabilities, if any, as of the date of the sale or exchange of your Interests 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 disposition of your Interests, if permitted under the Limited Partnership Agreement. See “Federal Income Tax Consequences — Disposition of Interests” and “Presentment Feature.”

The Managing GP is making only a limited initial cash contribution to the partnership and the partnership will only have an initial capitalization of $1,001 until the minimum offering amount is raised.

In connection with the formation of the partnership, the Managing GP made a cash capital contribution to the partnership of $1.00 and the initial limited partner contributed $1,000. Upon the admission of investors pursuant to this offering, the partnership will promptly refund the $1,000 capital contribution of the initial limited partner, after which it will withdraw as the initial limited partner. Accordingly, the partnership will have an initial capitalization of only $1,001 until the minimum offering amount is raised in this offering.

Compensation and fees paid to the Managing GP regardless of success of the partnership’s activities will reduce cash distributions.

The Managing GP will receive certain 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 investors. The amount of the fees is subject to the complete discretion of the Managing GP, other than the fees must not exceed competitive fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses and the fees must comply with any other restrictions set forth in “Compensation.” With respect to direct costs, the Managing GP has sole discretion on behalf of the partnership to select the provider of the services or goods and the provider’s compensation as discussed in “Compensation.”

There is no guaranty that cash distributions will be paid by the partnership in any amount or frequency.

The timing and amount of distributions will be determined in the sole discretion of the Managing GP and may not be made until the Managing GP determines that such funds are no longer needed for the partnership’s operations. The level of distributions, when made, will primarily be dependent upon the partnership’s levels of revenue, among other factors. Distributions may be reduced or deferred, in the discretion of the Managing GP, to the extent that the partnership’s revenues are used for any of the following:

compensation and fees paid to the Managing GP as described above in “— Compensation and fees paid to the Managing GP regardless of success of the partnership’s activities will reduce cash distributions;”

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repayment of borrowings;
cost overruns;
remedial work to improve a well’s producing capability;
direct costs and general and administrative expenses of the partnership;
reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or
indemnification of the Managing GP and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership’s activities.

Further, because the partnership’s investments will be in depleting assets, partnership revenues and the amount of distributions made to partners will decline with the passage of time. Accordingly, there can be no assurance that the partnership will be able to make regular distributions or that distributions will be made at any consistent rate or frequency. See “Participation in Costs and Revenues — Distributions.”

The Managing GP may not be able to meet its indemnification obligations if its liquid net worth is not sufficient at the time such indemnification is sought.

The Managing GP has made commitments to the investors in the partnership regarding the indemnification of the Investor General Partners for liabilities in excess of their pro rata share of partnership assets and insurance proceeds. A significant financial reversal for the Managing GP could adversely affect its ability to honor these obligations. The Managing GP’s assets may not be sufficient, either currently or in the future, to enable the Managing GP to meet its financial commitments under the Limited Partnership Agreement.

The ability to spread the risks of drilling among a number of wells will be reduced if less than the maximum offering proceeds are received and fewer wells are drilled.

The partnership must receive minimum offering proceeds of $2,000,000 to break escrow, and the partnership’s offering proceeds may not exceed $200,000,000 (or $300,000,000 if the Managing GP increases the size of the offering). There are no other requirements regarding the size of the partnership. Generally, the less offering proceeds received, the fewer wells that will be drilled by the partnership, which would decrease the partnership’s ability to spread the risks of drilling.

To the extent more than the minimum subscription proceeds are received by the partnership and the number of wells drilled increases, the partnership’s overall investment return may decrease if the Managing GP is unable to find enough suitable wells to be drilled. Also, to the extent that the partnership’s subscription proceeds and number of wells it drills increase, greater demands will be placed on the Managing GP’s management capabilities.

In addition, 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 that would shift certain risks of loss from the partnership to the operators of the wells. All of the intangible drilling costs of the partnership’s wells will be charged to the investors in the partnership. If the partnership incurs a cost overrun for the intangible drilling costs of a well or wells, then the Managing GP anticipates that it would use the partnership’s offering proceeds, if available, to pay the cost overrun or advance the necessary funds to the partnership. Using subscription proceeds to pay cost overruns charged to the investors under the Limited Partnership Agreement will result in the partnership drilling fewer wells.

Increases in the costs of the wells may adversely affect your return.

The increase in the price of crude oil over the last several years has increased the demand for drilling rigs and other related equipment, and the costs of drilling and completing oil and natural gas wells also have increased. On the other hand, if the price of oil and natural gas decreases before the partnership’s wells are drilled, the drilling and completion costs of the wells to be drilled by the partnership would, in all likelihood, not be affected since the Managing GP believes that, in the short term, drilling and completion costs are not

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likely to be reduced by a drop in oil and natural gas prices. Also, the reduced availability of drilling rigs and other related equipment may make it more difficult to drill the partnership’s wells in a timely manner or to comply with the prepaid intangible drilling cost rules discussed in “Federal Income Tax Consequences —  Drilling Contracts.”

The partnership does not own any prospects, the Managing GP has complete discretion to select which prospects are acquired by the partnership, and the possible lack of information about the prospects decreases your ability to evaluate the feasibility of the partnership.

The partnership does not currently hold any interests in any prospects on which the wells will be drilled and the Managing GP has absolute discretion in determining the prospects that will be acquired to be drilled. The Managing GP has identified in “Proposed Activities” the areas where the partnership intends to drill its wells.

If there are material adverse events with respect to any of the prospects, the Managing GP will substitute a new prospect. With respect to the prospects to be drilled by the partnership, the Managing GP has the right on behalf of the partnership to:

substitute prospects;
take a lesser working interest in the prospects;
drill in other areas; or
do any combination of the foregoing.

Thus, you will not have any geological or production information to evaluate any additional and/or substituted prospects and wells. Also, if the subscription proceeds received by the partnership are insufficient to drill all of the identified prospects, then the Managing GP will choose those prospects that it believes are most suitable for the partnership. You must rely entirely on the Managing GP to select the prospects and wells for the partnership.

Drilling prospects in one area may increase risk.

If multiple wells are drilled in one area at approximately the same time, which may occur from time to time because of drilling commitments, rig availability or commitments made by the partnership, then there is a greater risk that two or more of the wells will be marginal or nonproductive since the Managing GP 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 contrasted with the situation in which the partnership drills one well in an area and then 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 respect to wells for which the drilling and completing costs are prepaid in one year and the drilling of the wells must begin within the first 90 days of the immediately following year under the tax laws associated with deducting the intangible drilling costs of the prepaid wells in the year in which the prepayment is made, rather than the year in which the wells are drilled. For example, if the partnership prepays in the year you invest the costs of drilling one or more wells to be drilled in the next year, potential bad weather conditions during the first 90 days of that year could delay beginning the drilling of one or more of the prepaid wells beyond the 90 day time limit under the tax laws. This would have a greater adverse effect on the partnership’s deduction for prepaid intangible drilling costs if the Managing GP is required to begin drilling many wells at the same time, rather than only a few wells, and increase the number of wells being drilled in the area at approximately the same time and the associated risk as described above. Also, any “frost laws” in the States in which the partnership drills its wells may prohibit drilling rigs and other heavy equipment from using certain roads during the winter, which may delay beginning the drilling of the prepaid wells within the 90 day time limit in the next tax year under the tax laws. In addition, there could be shortages of drilling rigs, equipment, supplies and personnel during this time period, or unexpected operational events and drilling conditions. See “Federal Income Tax Consequences — Drilling Contracts” regarding prepaid wells and the 90-day time constraint.

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Because of inadequate capital, the partnership may not be able to participate in all wells proposed, which could result in a loss or forfeiture of leasehold interests.

The agreements applicable to the prospects in which the partnership participates may provide that if the partnership elects not to participate in certain drilling, completion or other operations with respect to a well because of inadequate capital or otherwise, the partnership will lose all or a portion of its leasehold interests in such well. In some instances, the loss may be limited to the partnership’s interest in the applicable well or the applicable agreement may provide that after the participating parties recover from production some multiple of their well costs, the partnership will then again participate in the well. However, most frequently where the operation is the drilling of a new well, the applicable agreements may provide that the partnership will permanently forfeit all of its interest in the well, as well as in some defined area surrounding the well. Other penalties include relinquishment of a certain percentage of revenue that the partnership would have received if it had participated in a well.

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 the offering of Interests in the partnership closes, you may present your Interests to the Managing GP for purchase. However, the Managing GP 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 GP may suspend the presentment feature. This risk is increased because the Managing GP has and will incur similar presentment obligations in other partnerships.

Further, the presentment price for your Interests may not reflect the full value of the partnership’s property or your Interests because of the difficulty in accurately estimating oil and natural gas reserves. Reservoir evaluation is a subjective process of estimating underground accumulations of oil and natural gas 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 oil and natural gas prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in these assumptions, including the price of natural gas, could materially affect the estimated quantity of the reserves. As a result, the Managing GP’s estimates are inherently imprecise and may not correspond to realizable value. Thus, the presentment price paid for your Interests and the amount of any partnership distributions received by you before the presentment may be less than the subscription amount you paid for your Interests. However, because the presentment price is a contractual price it is not reduced by discounts for minority interests and lack of marketability that generally are used to value partnership interests for tax and other purposes, but it is subject to discounts for purposes of determining present value and the amount to be paid. See “Presentment Feature.”

Also, a sale of your Interests could create adverse tax and economic consequences for you. The sale or exchange of all or part of your Interests held for more than 12 months generally will result in recognition of long-term capital gain or loss. However, previous deductions for depreciation, depletion and intangible drilling costs may be recaptured as ordinary income rather than capital gain regardless of how long you have owned your Interests. If you have held your Interests for 12 months or less, then the gain or loss generally will be short-term gain or loss. Also, your pro rata share of the partnership’s liabilities, if any, as of the date of the sale or exchange of your Interests 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 disposition of your Interests, if permitted under the Limited Partnership Agreement. See “Federal Income Tax Consequences — Disposition of Interests” and “Presentment Feature.”

The lack of an independent dealer-manager may reduce the due diligence investigation of the partnership and the Managing GP.

There has not been an extensive in-depth “due diligence” investigation of the existing and proposed business activities of the partnership and the Managing GP that might be provided by an independent dealer-manager. While third-party broker-dealers and other third-parties that sell Interests may conduct due diligence on the partnership and the Managing GP and will receive reimbursement for their bona fide due diligence

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expenses, ICON Securities’ due diligence examination concerning the partnership cannot be considered to be independent, nor as comprehensive as an investigation that might have been conducted by an independent dealer-manager. See “Conflicts of Interest.”

A lengthy offering period may result in delays in the investment of your subscription and any cash distributions from the partnership to you.

Because the offering period for the partnership can extend for many months, there may 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 a portion of the partnership’s wells have been drilled, completed and placed on-line for the delivery and sale of natural gas and/or oil and payment has been received from the purchaser of the natural gas and/or oil. Also, distributions of the partnership’s net production revenues will be made only after payment of the Managing GP’s fees and expenses and only if there is sufficient cash available in the Managing GP’s discretion. See “Terms of the Offering” for a discussion of the procedures involved in the offering of the Interests and the formation of the partnership.

The partnership is subject to comprehensive federal, state and local laws and regulations that could increase the cost and alter the manner or feasibility of the partnership’s business and operations.

The partnership’s operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, the partnership could also be liable for personal injuries, property damage and other damages. In addition, failure to comply with these laws and regulations may result in the suspension or termination of the partnership’s operations and subject the partnership to administrative, civil and criminal penalties.

Part of the regulatory environment in which the partnership will operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before beginning drilling and production activities. In addition, the partnership’s activities are subject to regulations regarding conservation practices and protection of correlative rights. Further, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, thus, reduce the partnership’s profitability. Furthermore, the partnership may be put at a competitive disadvantage as compared to larger companies in the oil and gas industry that can spread these additional regulatory compliance costs over a greater number of wells. See “Competition, Markets and Regulation” for a more detailed description of the material laws and regulations that affect the partnership.

Your Interests may be diluted.

The equity interests of the investors in the partnership may be diluted. The investors in the partnership will share in the partnership’s production revenues from all of its wells in proportion to your respective number of Interests, based on $10,000 per Interest, regardless of:

when you subscribe;
which wells are drilled with your subscription proceeds; or
the actual subscription price you paid for your Interests as described below.

Also, some investors, including the Managing GP and its officers and directors and others as described in “Plan of Distribution,” may buy Interests in the partnership at discounted prices because the sales commission will not be paid for those sales. In addition, all of the investors in the partnership will share in the partnership’s production revenues with the Managing GP, based on the number of Interests purchased by each investor, rather than the purchase price paid by the investor for his Interests. Thus, investors who pay discounted prices for their Interests may receive higher returns on their investments in the partnership as compared to investors who pay the entire $10,000 per Interest. This risk is increased if the Managing GP increases the offering to a maximum of 30,000 Interests from the current maximum of 20,000 Interests because some purchasers of the additional Interests may qualify to pay a discounted price, as discusssed above, for a portion of the additional Interests.

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The partnership’s assets may be plan assets for ERISA purposes, which could subject the Managing GP to additional restrictions on its ability to operate its business with respect to all its partners.

ERISA and the Code may apply what is known as the look-through rule to an investment in the Interests. Under that rule, the assets of an entity in which a qualified plan or IRA has made an equity investment may constitute assets of the qualified plan or IRA. If you are a fiduciary of a qualified plan or IRA, you should consult with your advisors and carefully consider the effect of that treatment if the look-through rule is applied. If the look-through rule were to apply, the Managing GP may be viewed as an additional fiduciary with respect to the qualified plan or IRA to the extent of any decisions relating to the undivided interest in the partnership’s assets represented by the Interests held by such qualified plan or IRA. This could result in some restriction on the Managing GP’s willingness to engage in operations that might otherwise be in the best interest of all Interest holders due to the strict rules of ERISA regarding fiduciary actions. See “Investment by Qualified Plans and IRAs.”

An investment in the Interests may not satisfy the requirements of ERISA or other applicable laws.

When considering an investment in the Interests, an individual with investment discretion over assets of any pension plan, profit-sharing plan, retirement plan, IRA or other employee benefit plan covered by ERISA or other applicable laws should consider whether the investment satisfies the requirements of Section 404 of ERISA or other applicable laws. In particular, attention should be paid to the diversification requirements of Section 404(a)(1)(C) of ERISA in light of all the facts and circumstances, including the portion of the plan’s portfolio of which the investment will be a part. All plan investors should also consider whether the investment is prudent and meets plan liquidity requirements, as there are significant restrictions on the ability to sell or otherwise dispose of the Interests, and whether the investment is permissible under the plan’s governing instrument. The partnership has not evaluated, and will not evaluate, whether an investment in the Interests is suitable for any particular plan. Rather, the partnership will accept subscribers as either Investor General Partners or Limited Partners if a subscriber otherwise meets the applicable suitability standards. In addition, the partnership can provide no assurance that any statements of estimated value of the Interests will not be subject to challenge by the Internal Revenue Service if used for any tax (income, estate, gift or otherwise) valuation purposes as an indicator of the fair value of the Interests.

The statements of value that the partnership will include in its Annual Reports on Form 10-K and that the partnership will send to fiduciaries of plans subject to ERISA and to certain other parties are only estimates and may not reflect the actual value of the Interests.

The statements of estimated value are based on the estimated value of each. The Managing GP will rely, in part, upon third party sources and advice in arriving at this estimated value. No independent appraisals on the particular value of the Interests will be obtained and the value will be based upon an estimated fair market value as of the referenced date for such value. Because this is only an estimate, the partnership may subsequently revise any valuation that is provided. The partnership cannot ensure that:

this estimate of value could actually be realized by the partnership or by its partners upon liquidation;
partners could realize this estimate of value if they were to attempt to sell their Interests;
this estimate of value reflects the price or prices that the Interests would or could trade at if they were listed on a national stock exchange or included for quotation on a national market system, because no such market exists or is likely to develop; or
the statement of value, or the method used to establish value, complies with any reporting and disclosure or valuation requirements under ERISA, Code requirements or other applicable law.

Risks Related to the Partnership’s Oil and Gas Operations

The partnership’s drilling operations involve the possibility of a total or partial loss of your investment because the partnership may drill (i) wells that are productive, but that do not produce enough revenue to return the investment made, and (ii) from time to time, dry holes.

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Oil and natural gas exploration is an inherently speculative activity. Before the drilling of a well the Managing GP cannot predict with absolute certainty:

the volume of oil and natural gas recoverable from the well; or
the time it will take to recover the oil and natural gas.

You may not recover any or all of your investment in the partnership, or if you do recover your investment in the partnership you may not receive a rate of return on your investment that is competitive with other types of investment. You will be able to recover your investment only through distributions of the partnership’s net proceeds from the sale of its oil and natural gas from productive wells. The quantity of oil and natural gas in a well, which is referred to as its reserves, decreases over time as the oil and natural gas 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 the partnership, excluding tax benefits, until your total cash distributions from the partnership exceed 100% of your investment.

The partnership’s revenues are directly related to its ability to market the oil and natural gas produced from the wells it drills and oil and natural gas prices, which are volatile and uncertain. If oil and natural gas prices decrease, then the return on your investment will decrease.

The prices at which the partnership’s oil and natural gas will be sold are uncertain. Changes in oil and natural gas prices will have a significant impact on the partnership’s cash flow and the value of its reserves. Lower oil and natural gas prices may not only decrease the partnership’s revenues, but also may reduce the amount of oil and natural gas that the partnership can produce economically.

Historically, oil and natural gas prices have been volatile and it is likely that they will continue to be volatile in the future. Prices for oil and natural gas will depend on supply and demand factors largely beyond the control of the partnership and prices may fluctuate widely in response to:

relatively minor changes in the supply of and demand for natural gas or oil;
market uncertainty; and
a variety of additional factors that are beyond the partnership’s control, as described in “Competition, Markets and Regulations — Competition and Markets.”

These factors make it extremely difficult to predict oil and natural gas price movements with any certainty.

If oil and natural gas prices decrease in the future, then partnership distributions will decrease accordingly. Also, oil and natural gas prices may decrease during the first years of production from the 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. Also, your return level may decrease during the term of the partnership, even if natural gas prices rise, because of declining production volumes from the wells over time.

Any of the partnership’s wells that are marginal wells under the Code would qualify for potentially higher rates of percentage depletion. With respect to those marginal wells, the partnership will be more sensitive to price declines, including reducing the volume of oil and natural gas that the partnership can produce economically (i.e., the volume of oil and natural gas reserves), than if those wells produced at a higher average rate of production that did not qualify for the potentially higher rate of percentage depletion.

Competition from other natural gas producers and marketers in the markets in which the partnership invests, as well as competition from alternative energy sources, may make it more difficult to market the partnership’s natural gas.

There are many companies and individuals engaged in the purchase and sale of producing oil and natural gas properties. Accordingly, the partnership will encounter strong competition from independent operators and major oil companies in marketing the partnership’s natural gas. Many of these companies have financial and technical resources and staffs considerably larger than those available to the partnership. If the partnership is

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not successful in marketing its natural gas, the partnership’s results of operations, financial condition and distributions to investors could be adversely affected.

The Managing GP anticipates that the partnership’s natural gas production initially will be sold to a limited number of purchasers in a defined area. If the partnership loses a natural gas purchaser in the area, the partnership may be unable to locate a new natural gas purchaser in the area that will buy the partnership’s natural gas on as favorable terms as the initial purchaser.

The partnership’s natural gas production will initially be sold to a limited number of purchasers in a defined area. If the partnership loses a natural gas purchaser in the area, the partnership may be unable to locate a new natural gas purchaser in the area that will buy the partnership’s natural gas on as favorable terms as the initial purchaser. The loss of any particular purchaser could have a material adverse impact on the partnership by affecting prices, delaying sales of production or increasing costs.

All natural gas purchase contracts provide that the price paid by the natural gas purchaser may be adjusted upward or downward in accordance with the spot market price and market conditions. Thus, the partnership will not be guaranteed a specific natural gas price, which could reduce the partnership’s revenues and distributions to investors.

The partnership’s natural gas purchase contracts are expected to provide that the price paid by the natural gas purchaser may be adjusted upward or downward in accordance with the spot market price and market conditions, which the partnership cannot control. Therefore, the partnership will not be able to guarantee any specific price for its natural gas, other than through hedging. Depending on the percentage of the partnership’s natural gas production that is hedged, which percentage will be determined by the Managing GP, a substantial or extended decline in natural gas prices could materially and adversely affect the partnership’s results of operations, financial condition and its ability to make distributions to its investors.

All of the natural gas contracts of the partnership are between the natural gas purchaser and the operator, and the related sales proceeds may be subject to the claims of the operator or its affiliates’ creditors.

The operator will receive the sales proceeds from the natural gas purchasers and then distribute the sales proceeds to the partnership based on the volume of natural gas produced by the operator. Until the sales proceeds are distributed to the partnership, they will be subject to the claims of the operator or its affiliates’ creditors. If such proceeds are subjected to claims of the operator’s creditors, it could adversely affect the partnership’s results of operations, financial condition and its ability to make distributions to investors.

The partnership may not be paid, or may experience delays in receiving payment, for its natural gas that has already been delivered to the purchaser.

In accordance with industry practice, an operator 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. In such case, the partnership would be a general unsecured creditor of the natural gas purchaser. This ongoing credit risk also may delay or interrupt the sale of the partnership’s natural gas or the partnership’s negotiation of different terms and arrangements for selling its natural gas to other purchasers.

Increased transportation costs due to longer distances for transporting the partnership’s natural gas could cause the partnership’s net revenues to decrease.

The farther natural gas must be transported before it reaches its market, the higher the transportation costs that the partnership will incur. If the partnership incurs higher costs than anticipated for transporting its natural gas to market, the partnership’s net revenues could decrease, which could adversely affect the partnership’s financial condition and distributions to investors.

Production from wells drilled in certain areas may be delayed until construction of the necessary gathering lines and production facilities is completed, which could reduce the partnership’s net revenues.

If the partnership participates in wells drilled in certain areas not already serviced by existing gathering lines and production facilities, the production from those wells may be delayed until such gathering lines and

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production facilities are built. The additional costs and delays that might be incurred could decrease the partnership’s net revenues from such wells and could adversely affect the partnership’s financial condition and distributions to investors.

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 and produces oil and natural gas in commercial quantities, it may not produce enough oil and natural gas to pay for the costs of drilling and completing the well, even after the tax benefits are considered. Thus, it may take many years to return your investment in cash, if ever. The partnership’s primary drilling area is expected to be located in the Mid-Continent region of the United States. As a result, many of the leases that will be drilled by the partnership are in an area that has already been partially depleted or drained by earlier drilling. This may reduce the partnership’s ability to find economically recoverable quantities of oil and/or natural gas in those areas.

Nonproductive wells may be drilled even though the partnership’s operations are primarily limited to development drilling.

The partnership may drill some development wells that are nonproductive, which 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.

The applicable operator will hold record title on undeveloped leases with respect to each Project for the partnership’s benefit, and the partnership will receive an assignment of an interest in each such lease.

The applicable operator will hold record title for the benefit of the partnership on undeveloped leases with respect to each Project acquired by it as agent for the partnership. Following acquisition of an undeveloped lease by the operator, an interest in such lease will be assigned to the partnership. While the operators hold these undeveloped leases for the benefit of the partnership, creditors of the operators may assert claims that could result in the creation of liens or encumbrances on such undeveloped leases. If the claims of these creditors are not satisfied, this could result in the sale or other loss of these leases to satisfy such claims. As to any third-party claims, until the partnership receives and records an assignment for each lease, the partnership will also remain a general unsecured creditor of the applicable operator.

The partnership will not acquire title insurance for its leasehold interests, which may be subject to title defects.

The partnership must rely on the operator of each Project and the Managing GP to use their best judgment to obtain appropriate title to leases. The partnership’s leasehold interests will not be covered by title insurance. Customarily, oil and gas leasehold interests are not acquired with title insurance. Rather, it is customary in the oil and gas industry to acquire and pay for oil and gas leases based upon a lease broker’s report. However, a lease broker’s report does not provide the same level of assurance of leasehold title as does a title opinion. Therefore, there may be defects in the partnership’s title to its leases. In addition, the partnership may experience losses from title defects that arose during drilling that would have been disclosed by a division order title opinion, such as liens arising during drilling operations or transfers of interests in the leases after drilling begins. Also, the operator and/or the Managing GP, as applicable, may use its own judgment in waiving title requirements for the partnership’s leases and it will not be liable for any failure of title of leases transferred to the partnership. What the operator or the Managing GP determine to be not material at the time of waiving such defects may become material at a later date, which could adversely affect the partnership.

Participation with third parties in drilling wells may require the partnership to pay additional costs.

Third parties will participate with the partnership in drilling some or all of the wells and additional financial risks exist when the costs of drilling, equipping, completing and operating wells are shared by more than one person. If the partnership pays its share of the costs, but another interest owner does not pay its share of the costs, then the partnership may 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, which may, or may not, cover all of the additional costs paid by the partnership.

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In addition, because the Managing GP will not be the actual operator of the well for all of the working interest owners of the well, there is a risk that the Managing GP 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 partnership and the investors:

how the well is operated;
expenditures related to the well; and
possibly the marketing of the oil and natural gas production from the well.

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 partnership’s investments may be concentrated for the most part with one operator, which may have a material adverse effect on the partnership’s performance.

At least initially, the partnership will be investing for the most part in Projects that are operated by one operator. Accordingly, the partnership’s investment will be concentrated and will not be diversified among many industry partners. By concentrating most of the investment in a single operator, a downturn or other event negatively affecting the operator could have a material adverse effect on the partnership’s performance, and consequently, your investment. Further, if the Managing GP raises significantly less than the maximum offering amount, the partnership’s investment may be further concentrated among various Projects with that one operator, thereby increasing the risks associated with such concentration.

The partnership may prepay certain acreage, geological and geophysical costs, and certain drilling and completion costs associated with the wells to be drilled, and as a result the partnership would be a general unsecured creditor of the operator.

Upon execution of a Participation Agreement with the operator, the partnership may prepay to the operator the partnership’s contractual share of acreage, geophysical and geological costs and other up-front expenses, and drilling and completion costs on a well-by-well basis. Once a prepayment is made, the operator is under no requirement to keep such funds segregated from funds received by other working interest owners. As a result of any prepayment, the partnership would become a general unsecured creditor of the operator and, therefore, could suffer the loss of all or part of the amount prepaid in the event that an operator has financial difficulties, liens are placed against the operator’s assets or the operator files for bankruptcy.

The partnership may also become an unsecured creditor of the operator or other third parties because the operator and/or such third parties may hold receipts from sales of oil and gas on behalf of the partnership.

The partnership would be a general unsecured creditor during any time that the operator holds receipts from sales, as there is typically a 30- to 60-day delay for when distributions are made from the operator to the working interest holders. In other cases, the partnership will likely receive revenue from operations directly from the pipeline companies that purchase the gas and oil (typically, separate companies will purchase the oil and gas). During the time between when such companies have purchased the partnership’s oil and gas and when they pay the partnership, the partnership will also remain a general unsecured creditor of the companies purchasing the partnership’s share of oil and gas production.

Initial reserve and revenue estimates have inherent uncertainties and limitations and the Managing GP will not obtain independent reserve evaluations prior to drilling a well.

There are numerous uncertainties inherent in estimating oil and gas reserves and their estimated values, especially prior to production being established, including many factors beyond the control of the producer. Accordingly, the estimates of reserves may prove unreliable. Actual future production, revenue levels, development expenditures, and quantities of recoverable oil and gas reserves may vary substantially from those estimated. Further, the Managing GP will not obtain independent reserve evaluations prior to drilling a well. Therefore, investors may have to rely solely on internal estimates provided by the Managing GP or on estimates provided by the operator of a Project. Estimates provided by an operator who is also a prospect generator on the Project may have inherent conflicts and may prove to be less than reliable.

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The partnership may secure debt financing, some or all of which may be secured, to pay for costs associated with new drilling, which may affect distributions to investors or otherwise adversely affect an investment in the partnership.

The partnership has the ability to secure debt financing from lenders, including the Managing GP and/or institutional oil and gas lenders, to pay for most or all of the costs associated with additional drilling. The loan could be repaid out of net cash flow from existing producing wells, successful new wells and/or the sale of acreage, and would likely be secured by some or all of the partnership’s assets. Cash that would otherwise be available for distribution to the investors would likely have to be paid to the lender(s). Such debt financing could limit the partnership’s ability to use operating cash flow in other areas of the partnership’s business because it would have to dedicate a substantial portion of these funds to make principal and interest payments on the indebtedness. Also, this debt could make the partnership more vulnerable to a downturn in its business, the oil and gas industry or the economy in general, as a substantial portion of the partnership’s operating cash flow will be required to make principal and interest payments on the indebtedness, making it more difficult to react to changes in the partnership’s business and in industry and market conditions. In, addition, certain of partnership’s debt covenants could restrict the partnership’s ability to disburse funds to its investors. These restrictions could delay distributions to investors until the partnership is in compliance with the applicable covenant(s).

If the partnership is unable to generate sufficient cash flow or is otherwise unable to obtain the funds required to make principal and interest payments on its indebtedness, or if the partnership otherwise fails to comply with the various covenants relating to any future indebtedness, the partnership could be in default under the terms of such instruments. In the event of a default, the holders of the partnership’s indebtedness could elect to declare all the funds borrowed under those instruments to be due and payable, together with accrued and unpaid interest, and could foreclose on partnership assets and the partnership could lose its investment its oil and gas properties and other assets. Further, if the partnership is obligated under more than one loan with the partnership’s assets used as collateral, the partnership may be subject to cross collateralization that may subject the entire assets of the partnership to a foreclosure even if a default occurs on just one of the loans made to the partnership. Any of the foregoing consequences could restrict the partnership’s ability to make distributions to its investors and would have a material adverse effect on an investment in the partnership.

Delay in oil or gas production from successful wells, whether from operational or other difficulties or insufficient infrastructure, would delay cash distributions and could reduce the partnership’s profitability.

The partnership’s drilling and producing operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

the high cost, shortages or delivery delays of equipment and services;
unexpected operational events;
adverse weather conditions;
decreases in oil and natural gas prices;
limitations in the market or access to markets for oil and natural gas;
facility or equipment malfunctions;
title disputes;
pipeline ruptures or spills;
collapses of wellbore, casing or other tubulars;
compliance with environmental and other governmental requirements;
unusual or unexpected geological formations;
loss of drilling fluid circulation;
formations with abnormal pressures;

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fires;
earthquakes;
blowouts, craterings and explosions;
changes in below-ground pressure in a formation that cause surface collapse or cratering;
uncontrollable flows of oil, natural gas or well fluids; or
pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion.

The Managing GP also cannot predict the life and production of the initial wells or any additional wells in a Project. The actual lives of these wells could differ from those anticipated. In addition, negative geologic characteristics (i.e., lack of porosity and permeability) of the formation(s) targeted by the partnership’s wells may hinder or restrict production or even make production impractical or impossible. Any one of these events or other events may cause the partnership not to produce sufficient oil or natural gas for investors to receive a profit or to even recover their initial investment.

In addition, drilling wells in areas remote from marketing facilities may delay production from those wells until sufficient reserves are established to justify construction of necessary pipelines and production facilities. While most of the Projects will likely be in areas of current or historical oil and/or natural gas production with existing infrastructure, delays can and do occur. Local conditions including, but not limited to, closing businesses, conservation, shifting population, pipeline maximum operating pressure or capacity constraints, and development of local oversupply or deliverability problems could halt or reduce sales from wells. Any of these delays in the production and sale of the partnership’s oil and gas would delay cash distributions to investors and could reduce the partnership’s profitability.

The partnership may be required to pay delay rentals to hold properties, which would deplete partnership capital.

Oil and natural gas leases generally require that the property must be drilled upon by a certain date or additional funds, known as delay rentals, must be paid to keep the lease in effect. Delay rentals typically must be paid within a year of the entry into the lease if no production or drilling activity has commenced, though certain of the prospect leases will be paid up for a longer period of time. If delay rentals become due on any prospect in which the partnership acquires an interest, the partnership will have to pay its share of such delay rentals or lose its working interest in such prospect. These delay rentals could equal or exceed the cost of the interest. Payment of the delay rentals could seriously deplete the partnership’s capital available to fund drilling activities when they do commence. The risk of incurring delay rentals will be higher in an industry environment when there are shortages of equipment and personnel.

The partnership may be required to pay increased costs to renew leases, which would deplete partnership capital.

Unless drilled upon by a certain date or additional funds, known as delay rentals, are paid to keep a lease in effect, oil and natural gas leases could expire outright and be required to be renewed. In cases where leases in which the partnership holds an interest expire and must be renewed (i.e., there are no delay rentals that can be paid to hold the leases), the partnership could be exposed to increases in the prevailing market prices for leases versus prices when the leases were originally entered into, and such increases could be substantial. Payment of the lease renewals could significantly deplete the partnership’s capital available to fund drilling activities when they commence. The risk of incurring lease renewals and other lease maintenance payments will be higher in an industry environment when there are shortages of equipment and personnel.

The partnership may lose oil and gas lease properties due to numerous factors.

Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and therefore any capital invested in such lease. Delays in drilling due to rig unavailability or the inability to purchase well casing or other needed supplies may cause leases to expire before they are drilled. In addition, weather or other unforeseen events may delay drilling prior to leases expiring. Delays in

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drilling may also occur due to lack of geologic, geophysical or other information. Delays due to the inability of other working interest partners to agree upon and fund specific wells may also delay drilling prior to leases expiring. Leases may also be lost due to legal issues relating to the ownership of leases.

Environmental hazards involved in drilling oil and natural gas wells may result in substantial liabilities for the partnership.

There are numerous natural hazards involved in the drilling of oil and gas wells, including unexpected or unusual formations, high pressures, blowouts which could involve possible damages to property and third parties, including surface damages, bodily injuries or death, damage to and loss of equipment, pipelines, reservoir damage and loss of reserves. Uninsured liabilities would reduce the funds available to the partnership, may result in the loss of the partnership’s wells in a prospect and may create unlimited liability for Investor General Partners. The partnership may be subject to liability for pollution, abuses of the environment and other similar damages. It is possible that insurance coverage and the Managing GP’s assets may be insufficient to protect the partnership and, potentially, the Investor General Partners. In that event, partnership assets would pay personal injury and property damage claims and the costs of controlling blowouts and explosions or replacing destroyed equipment and pipelines rather than drilling activities. These payments would cause the partnership to be less profitable and could result in a complete loss of the investment and possibly expose Investor General Partners to unlimited liability with respect to their personal assets.

If hydraulic fracturing is utilized as part of the drilling operations, the partnership may be subject to costs associated with water disposal requirements and other environmental regulations, as well as potential liability for environmental pollution.

In drilling the partnership’s wells, operators may utilize a process called hydraulic fracturing, which uses a large amount of water and results in water discharge that must be treated and disposed of. There is a risk that hydraulic fracturing operations could result in pollution or contamination to not only the well site, but also adjacent properties and nearby water sources, including wells, streams and rivers. Environmental regulations governing the injection, withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions in or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on drilling operations and financial performance of the partnership.

Risks Related to the Partnership’s Organization and Structure

The decisions of the Managing GP may be subject to conflicts of interest.

There are conflicts of interest between the investors and the Managing GP and its affiliates. These conflicts of interest, which are not otherwise discussed in this “Risk Factors” section, include, but are not limited to, the following:

the Managing GP has determined the compensation and reimbursement that it and its affiliates will receive in connection with the partnership without any unaffiliated third-party dealing at arm’s length on behalf of the investors;
because the Managing GP 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;
the allocation of all intangible drilling costs to the investors and the majority of the equipment costs to the Managing GP may create a conflict of interest concerning whether to complete a well;
if the Managing GP, as tax matters partner, represents the partnership before the IRS, potential conflicts include, for example, 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, if any, to the Managing GP’s capital account for contributing the leases to the partnership;
the Managing GP and its officers, directors, and affiliates may purchase Interests at a reduced price, which would dilute the voting rights of the investors on certain matters; and
the same legal counsel represents the Managing GP and the partnership.

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Other than certain guidelines set forth in “Conflicts of Interest,” the Managing GP has no established procedures to resolve a conflict of interest. Also, the partnership does not have an independent investment committee. Thus, certain matters, including conflicts of interest between the partnership and the Managing GP and its affiliates such as those described above or set forth in “Conflicts of Interest,” may not be resolved as favorably to the investors in the partnership as they would be if there were an independent investment committee.

You will have limited voting rights and will be required to rely on the Managing GP to make all investment decisions and achieve the partnership’s investment objectives.

The Managing GP will make all of the partnership’s investment decisions, including determining the type and location of projects in which the partnership invests, the operators that the partnership partners with, and other investment and operational decisions of the partnership. The partnership’s success will depend on the quality of the decisions that the Managing GP makes, particularly relating to the type and location of the Projects in which the partnership invests. You are not permitted to take part in managing, establishing or changing the partnership’s investment objectives or policies. Accordingly, you should not invest unless you are willing to entrust all aspects of the management of the partnership to the Managing GP.

The Managing GP’s officers manage other businesses and will not devote their time exclusively to managing the partnership and its business, and the partnership may face additional competition for time and capital because neither the Managing GP nor its affiliates are prohibited from raising money for or managing other entities that pursue the same types of investments that the partnership targets.

The partnership will not employ its own full-time officers, managers or employees. Instead, the Managing GP will supervise and control its business affairs. The Managing GP’s officers are also officers and/or employees of affiliates of the Managing GP. In addition to sponsoring and managing the partnership and other oil and natural gas drilling partnerships, certain affiliates of the Managing GP currently sponsor, manage or distribute other investment products, including, but not limited to, seven public equipment funds, one private equipment fund, a business development company and a real estate investment trust. As a result, the time and resources that the Managing GP’s officers devote to the partnership may be diverted, and during times of intense activity in other investment products the Managing GP’s affiliates manage, sponsor or distribute, such officers may devote less time and resources to the partnership’s business than would be the case if the partnership had separate officers and employees. In addition, the partnership may compete with any such investment entities for the same investors and investment opportunities, which could negatively impact the partnership’s operations, business and financial condition. See “Conflicts of Interest — Conflicts Regarding Other Activities of the Managing GP and its Affiliates.”

Also, the Managing GP depends on its affiliate, ICON Capital, for facilities, investor relations and administrative functions as discussed in “Management — Transactions with Management and Affiliates.”

The Managing GP may have difficulty managing its growth, which may divert its resources and limit its ability to expand its operations successfully.

The Managing GP and its affiliates intend to continue to sponsor and manage, as applicable, funds and other investment vehicles similar to and different from the partnership that may be sponsored and managed concurrently with the partnership and they expect to experience further growth in their respective assets under management. The Managing GP’s future success will depend on the ability of its and its affiliates’ officers and key employees to implement and improve their operational, financial and management controls, reporting systems and procedures, and manage a growing number of assets and investment vehicles. However, they may not implement improvements to their management information and control systems in an efficient or timely manner and they may discover deficiencies in their existing systems and controls. Thus, the Managing GP’s anticipated growth may place a strain on its administrative and operations infrastructure, which could increase its costs and reduce its efficiency and could negatively impact the partnership’s operations, business and financial condition.

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Operational risks may disrupt the partnership’s business and result in losses.

The partnership expects to rely heavily on ICON Capital’s financial, accounting, and other software systems. If any of these systems fail to operate properly or become disabled, the partnership could suffer financial loss and a disruption of its business.

In addition, the partnership will be highly dependent on ICON Capital’s information systems and technology. These information systems and technology may not be able to accommodate the partnership’s growth and the cost of maintaining such systems may increase from its current level. A failure to accommodate growth, or an increase in costs related to such information systems, could also negatively affect the partnership’s liquidity and cash flows, and could negatively affect the partnership’s profitability.

Furthermore, the partnership will depend on the headquarters of ICON Capital, which are located in New York City, for the operation of the partnership’s business. A disaster or a disruption in the infrastructure that supports the partnership’s businesses, including a disruption involving electronic communications or other services used by the partnership or third parties with whom the partnership conducts business, or directly affecting the partnership’s headquarters, may have an adverse impact on the partnership’s ability to continue to operate the partnership’s business without interruption, which could have a material adverse effect on us. Any disaster recovery programs may not be sufficient to mitigate the harm that may result from such a disaster or disruption. In addition, insurance and other safeguards might only partially reimburse the partnership for any losses.

Finally, the partnership is likely to rely on third-party service providers for certain aspects of its business, including certain accounting and financial services. Any interruption or deterioration in the performance of these third parties could impair the quality of the partnership’s operations and could adversely affect its business and result in losses.

The partnership’s internal controls over financial reporting may not be effective, which could have a significant and adverse effect on its business.

After the partnership’s first full year of operations, the Managing GP will be required to evaluate the partnership’s internal controls over financial reporting in order to allow management to report on the partnership’s internal controls over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations of the SEC thereunder (“Section 404”). During the course of testing, the Managing GP may identify deficiencies that it may not be able to remediate in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if the partnership fails to achieve and maintain the adequacy of the partnership’s internal controls, as such standards are modified, supplemented or amended from time to time, the partnership may not be able to ensure that it can conclude on an ongoing basis that it has effective internal controls over financial reporting in accordance with Section 404. The partnership cannot be certain as to the timing of completion of its evaluation, testing and any remediation actions or the impact of the same on its operations. If the partnership is not able to implement the requirements of Section 404 in a timely manner or with adequate compliance, it may be subject to sanctions or investigation by regulatory authorities, such as the Securities and Exchange Commission. As a result, it may be required to incur costs in improving its internal control system and the hiring of additional personnel. Any such action could negatively affect its results of operations and the achievement of its investment objectives.

The partnership will be subject to certain reporting requirements and will be required to file certain periodic reports with the Securities and Exchange Commission.

The partnership will be subject to reporting requirements under the Securities Exchange Act of 1934, including the filing of quarterly and annual reports. If the partnership experiences delays in the filing of its reports, its investors may not have access to timely information concerning the partnership, its operations, and its financial results.

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Changes in the laws or regulations that affect the terms and conditions set forth in this prospectus and/or the Limited Partnership Agreement could negatively impact the partnership’s and/or your rights and obligations.

The Managing GP may, without your consent, amend the Limited Partnership Agreement to effect any change necessitated by a change in law or regulation that causes the terms and conditions set forth in this prospectus and/or the Limited Partnership Agreement to be, in the sole discretion of the Managing GP, no longer viable. The changes must be drawn as narrowly as possible so as to effectuate the original intent of this prospectus and the Limited Partnership Agreement. Nevertheless, these changes could negatively impact the partnership’s and/or your rights and obligations.

You are not expected to have any protection under the Investment Company Act.

The partnership will not register and does not expect in the future to be required to register as an investment company under the Investment Company Act of 1940, as amended (the “40 Act”), in reliance upon an exemption therefrom. Among other things, the 40 Act generally requires investment companies to have a minimum of forty percent (40%) independent directors and regulates the relationship between the investment adviser (i.e., the Managing GP) and the investment company (i.e., the partnership), in particular with regard to affiliated transactions. Such protections, and others afforded by the 40 Act, are not expected to be applicable to the partnership. Should the 40 Act become applicable to the partnership, these protections may be implemented in a manner that alters other rights and obligations of the partnership and/or you with respect to other matters. See “— Changes in the laws or regulations that affect the terms and conditions set forth in this prospectus and/or the Limited Partnership Agreement could negatively impact the partnership’s and/or your rights and obligations.”

You are not expected to have any protection under the Investment Advisers Act.

The Managing GP will not register and does not expect in the future to be required to register as an investment adviser under the Investment Advisers Act of 1940, as amended (the “Advisers Act”), because it does not meet the definition of an investment adviser. The Advisers Act contains many provisions designed to protect clients of investment advisers, including, among other things, restrictions on the charging by registered investment advisers of performance-based compensation. Such protections, and others afforded by the Advisers Act, are not expected to be applicable to the Managing GP and to the partnership. Should the Advisers Act become applicable to the Managing GP and to the partnership, these protections may be implemented in a manner that alters other rights and obligations of the partnership and/or you with respect to other matters. See “— Changes in the laws or regulations that affect the terms and conditions set forth in this prospectus and/or the Limited Partnership Agreement could negatively impact the partnership’s and/or your rights and obligations.”

Risks Related to the Tax Treatment of the Partnership and the Interests

If the IRS classifies the partnership as a corporation rather than a partnership, your distributions would be reduced under current tax law.

The partnership will not apply for an IRS ruling that it will be classified as a partnership for federal income tax purposes. Although counsel has rendered an opinion to the partnership that it will be taxed as a partnership and not as a corporation, that opinion is not binding on the IRS and the IRS has not ruled on any federal income tax issue relating to the partnership. If the IRS successfully contends that the partnership should be treated as a corporation for federal income tax purposes rather than as a partnership, then:

the partnership’s realized losses would not be passed through to you;
you would be unable to claim depletion on the partnership's oil and natural gas properties
the partnership’s income would be taxed at tax rates applicable to corporations, thereby reducing cash available to distribute to you; and
your distributions would be taxed as dividend income to the extent of current and accumulated earnings and profits.

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The partnership could be taxed as a corporation if it is treated as a publicly traded partnership by the IRS. To minimize this possibility, our Limited Partnership Agreement places significant restrictions on your ability to transfer the Interests. You and your advisors should not only review the “Federal Income Tax Consequences” section with care, but also carefully review your own individual tax circumstances. See “Federal Income Tax Consequences — Publicly Traded Partnerships.”

You may incur tax liability in excess of the cash distributions you receive in a particular year.

In any particular year, your tax liability from owning the Interests may exceed the cash distributions and any marginal well production credits you receive from this investment. The partnership’s taxable income could exceed the amount of cash distributions you receive in those years the partnership repays its debt (if any) with income or proceeds from asset sales. Additionally, a sale of the partnership’s investments may result in taxes in a given year that are greater than the amount of cash from the sale, resulting in a tax liability in excess of cash distributions. Your tax liability could also exceed the amount of cash distributions you receive due to allocations designed to cause the participants’ capital accounts (as adjusted by certain items) to be equal on a per Interest basis or from the Managing GP’s reinvestment of the partnership’s revenues or the creation of a reserve. Therefore, you may have to pay any excess tax liability with funds from another source, because the distributions the partnership makes may not be sufficient to pay such excess tax liability. Further, due to the operation of the various loss disallowance rules described in this prospectus, in a given tax year you may have taxable income (such as protfolio income) when, on a net basis, the partnership has a loss, or you may recognize a greater amount of taxable income than your share of the partnership’s net income because, due to a loss disallowance, income from some of the partnership’s activities cannot be offset by losses from some of its other activities.

There are limitations on your ability to deduct the partnership’s losses.

Your ability to deduct your share of the partnership’s losses (and depletion from your share of the partnership’s oil and natural gas properties) is limited to the amounts that you have at risk from owning the Interests. This is generally the amount of your investment, plus any profit allocations and minus any loss allocation and distributions. This determination is further limited by a tax rule that applies the at-risk rules on an activity by activity basis, further limiting losses from a specific activity to the amount at risk in that activity.

This investment may cause you to pay additional taxes.

You may be required to pay alternative minimum tax in connection with owning the Interests, since you will be allocated a proportionate share of the partnership’s tax preference items. The Managing GP’s operation of the partnership’s business affairs may lead to other adjustments that could also increase your alternative minimum tax. See “Federal Income Tax Consequences — Alternative Minimum Tax.”

The IRS may allocate more taxable income to you than the Limited Partnership Agreement provides.

The IRS might successfully challenge the partnership’s allocations of taxable income or losses. If so, the IRS would require reallocation of the partnership’s taxable income and loss, resulting in an allocation of more taxable income or less loss to you than the Limited Partnership Agreement allocates. The IRS may also challenge the amount of the partnership’s deductions and the taxable year in which the deductions were claimed, including the deductions for intangible drilling costs and depreciation. For example, depending primarily on when its subscription proceeds are received, it is possible that the partnership may prepay in the year you invest most or all of its intangible drilling costs for wells the drilling of which will not begin until the next year. The timing of these deductions is based on a facts and circumstances test that the IRS could challenge successfully. For example, prepayments the partnership makes where it only owns a portion of the working interests and the other owners do not prepay or prepayments made where the partnership may obtain a credit for any prepayment excess may be easier for the IRS to challenge successfully. See “Federal Income Tax Consequences — Drilling Contracts.”

Any adjustments made by the IRS to the federal information income tax returns of the partnership in which you invest could lead to adjustments on your personal federal income tax returns and could reduce the amount

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of your deductions from the partnership or your depletion deduction with respect to its oil and natural gas properties in the year you invest and subsequent tax years. The IRS also could seek to re-characterize a portion of the 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 “Federal Income Tax Consequences —  Business Expenses,” “— Depreciation and Cost Recovery Deductions,” “— Drilling Contracts,” and “— Allocations of Profits and Losses.”

Some of the distributions paid with respect to the Interests will be a return of capital, in whole or in part, which will complicate your tax reporting and could cause unexpected tax consequences at liquidation.

As you claim depletion deductions for the partnership’s oil and gas properties and the partnership depreciates its capital assets over the term of its existence, it is very likely that a portion of each distribution paid by the partnership will be considered a return of capital, rather than income. Therefore, the dollar amount of each distribution should not be considered as necessarily being all income to you. Since your capital in the Interests will be reduced for tax purposes over the life of your investment, you will not receive a lump sum distribution upon liquidation that equals the purchase price you paid for the Interests, such as you might expect if you had purchased a bond. Also, payments made upon the partnership’s liquidation will be taxable to the extent that such payments are not a return of capital.

As you receive distributions throughout the life of your investment, you will not know at the time of the distribution what portion of the distribution represents a return of capital and what portion represents income. As an administrative convenience to you, the Schedule K-1 statement you receive from the partnership each year will provide information allowing you to determine the amounts allocable to your capital and the partnership’s income from distributions you receive throughout the prior year.

No ruling will be requested from the IRS as to the tax consequences of investing in Interests.

Neither the Managing GP nor the partnership has requested, or will request, a ruling from the IRS regarding the tax consequences of investing in Interests. In addition, the discussion of tax matters set forth in this prospectus was not intended or written to be used, and cannot be used by any prospective investor, for the purpose of avoiding tax-related penalties under federal, state or local tax law. Each prospective investor should seek advice from its independent tax advisor.

The deduction for intangible drilling costs may not be available to you if you do not have passive income.

If you invest in the partnership as a Limited Partner (except as discussed below), your share of the partnership’s deduction for intangible drilling costs in the year you invest will be a passive loss that cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Thus, you may not have enough passive income from the partnership or net passive income from your other passive activities, if any, in the year you invest, to offset a portion or all of your passive deduction for intangible drilling costs in the year you invest. However, any unused passive loss from intangible drilling costs may be carried forward indefinitely by you to offset your passive income in subsequent taxable years. Also, except as described below, the passive activity limitations on your share of the partnership’s deduction for intangible drilling costs in the year you invest do not apply to you if you invest in the partnership as a Limited Partner and you are a C corporation that:

is not a personal service corporation or a closely held corporation;
is a personal service corporation in which employee-owners hold 10% (by value) or less of the stock, but is not a closely held corporation; or
is a closely held corporation (i.e., five or fewer individuals own more than 50% (by value) of the stock), but is not a personal service corporation in which employee-owners own more than 10% (by value) of the stock, in which case you may use your passive losses to offset your net active income (calculated without regard to your passive activity income and losses or portfolio income and losses).

See “Federal Income Tax Consequences — Limitations on Passive Activity Losses and Credits.”

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Investment interest deductions that may be available to Investor General Partners may nevertheless be limited.

If you invest in the partnership as an Investor General Partner, your share of the partnership’s deduction for intangible drilling costs in the year you invest will reduce your investment income and may limit the amount of your deductible investment interest expense, if any.

You may not be eligible to claim percentage depletion deductions.

The availability of percentage depletion will depend in part upon your individual circumstances. Percentage depletion deductions are based upon a percentage of gross income from the property, but are limited to 100% of the total taxable income that an investor receives from the property for each taxable year, may not exceed 65% of the investor’s overall taxable income (with certain adjustments) for the year and, in general, are severely limited or not available to investors that do not qualify as independent producers. Each investor must compute separately its depletion deductions.

The tax benefits that may be available to you from your investment in the partnership are not contractually protected.

An investment in the partnership does not give you any contractual protection against the possibility that part or all of the potential tax benefits that may be available to you from your investment will be disallowed by the IRS. No one provides any insurance, tax indemnity or similar agreement regarding the tax treatment of your investment in the partnership. You have no right to rescind your investment in the 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 the partnership to the Managing GP, its affiliates or independent third parties (including special counsel that issued the tax opinion letter) are refundable or contingent on whether the intended tax consequences of your investment in the partnership are ultimately sustained if challenged by the IRS.

An IRS audit of the partnership may result in an IRS audit of your personal federal income tax returns.

The IRS may audit the partnership’s annual federal information income tax returns. If the partnership is audited, the IRS also may audit your personal federal income tax returns, including prior years’ returns and items that are unrelated to the partnership and may require an adjustment to your tax return. See “Federal Income Tax Consequences.”

The partnership’s deductions may be challenged by the IRS.

If the IRS audits the partnership, it may challenge the amount of the 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 the federal information income tax returns of the partnership could lead to adjustments on your personal federal income tax returns and could reduce the amount of your deductions from the partnership in the year you invest and subsequent tax years. The IRS also could seek to re-characterize a portion of the 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 “Federal Income Tax Consequences —  Business Expenses,” “— Depreciation and Cost Recovery Deductions,” and “— Drilling Contracts.”

In addition, depending primarily on when subscription proceeds are received, it is possible that the partnership may prepay in the year you invest most or all of its intangible drilling costs for wells the drilling of which will not begin until the next year. In that event, you will not receive a deduction in the year you invest for your share of the partnership’s prepaid intangible drilling costs for those wells unless the drilling of the prepaid wells begins on or before the 90th day following the close of the partnership’s taxable year in which the prepayment was made. The drilling of any partnership well may be delayed due to circumstances beyond the control of the Managing GP and/or the operator, without liability to the Managing GP and/or the operator, as applicable. For example, if prepayment of a well is made in the year you invest and for any reason the drilling of the well does not begin within the 90 day time period in the next tax year, your

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deduction for prepaid intangible drilling costs for that well must be claimed for your tax year in which the drilling of the well begins, instead of the tax year you invested. Also, there is a greater risk that the IRS will attempt to defer your share of the partnership’s deduction for intangible drilling costs for drilling and completing any prepaid partnership wells from the tax year in which the prepayment is made by the partnership to the next tax year if there are other additional working interest owners of a prepaid well, because those other working interest owners will not be required to prepay their share of the costs of drilling and completing the wells. See “Federal Income Tax Consequences — Drilling Contracts.”

Changes in tax laws may reduce the potential tax benefits available from an investment in the partnership.

The potential tax benefits from an investment in the partnership may be affected by changes in the tax laws. Lower federal income tax rates will reduce to some degree the amount of taxes you save by virtue of your share of the partnership’s deductions for intangible drilling costs, depletion, and depreciation, and its marginal well production credits, if any. Changes in the tax laws could be made that would reduce your tax benefits from an investment in the partnership. President Obama’s administration has proposed, among other tax law changes, the repeal of certain oil and natural gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs (including your option to amortize intangible drilling costs over a 60 month period), the passive activity exception for working interests and the marginal production tax credit. These proposals may or may not be enacted into law. These proposed tax law changes, if enacted, would result in a substantial decrease in your future tax benefits from an investment in the partnership.

Your deduction for intangible drilling costs may be limited for purposes of the alternative minimum tax.

You will be allocated a share of the partnership’s deduction for intangible drilling costs in the year you invest. Under current tax law, however, your alternative minimum taxable income in the year you invest cannot be reduced by more than 40% by your deduction for intangible drilling costs without creating a tax preference. See “Federal Income Tax Consequences — Alternative Minimum Tax.”

On disposition of property by the partnership or on disposition of Interests by you, certain deductions for intangible drilling costs, depletion, and depreciation must be recaptured as ordinary income.

Each investor must recapture certain deductions for intangible drilling costs, depletion, and depreciation as ordinary income on disposition of property by the partnership or on disposition of Interests by such investor. If the partnership disposes of property or an investor transfers or sells an Interest, investors may recognize ordinary income (instead of capital gain) to the extent such deductions for intangible drilling costs, depletion and depreciation must be recaptured.

The partnership and its investors may be subject to other taxes besides federal taxes.

Taxes may be imposed by an investor’s state of residence, the states in which the partnership’s drilling activities are located and by local authorities. This prospectus does not address the potential impact of these other taxes. Each investor should obtain professional guidance from the investor’s own tax advisor in evaluating the federal, state and local tax risks involved in investing in the partnership and Interests.

If you are or invest through a tax-exempt entity or organization, you will have unrelated business taxable income from this investment.

Tax-exempt entities and organizations are subject to income tax on unrelated business taxable income (“UBTI”). Such entities and organizations are required to file federal income tax returns if they have UBTI from all sources in excess of $1,000 per year. The partnership’s income from its working interests constitutes UBTI. Furthermore, tax-exempt organizations in the form of charitable remainder trusts will be subject to an excise tax equal to 100% of their UBTI. Thus, an investment in the Interests may not be appropriate for a charitable remainder trust and such entities should consult their own tax advisors with respect to an investment in the Interests. See “Federal Income Tax Consequences — Taxation of Tax-Exempt Organizations.”

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It may be many years before you receive any marginal well production credits, if ever.

Depending primarily on the applicable reference prices for natural gas and oil in the preceding year, there is a federal income tax credit for the sale of qualified marginal natural gas and oil production. Qualified marginal natural gas and oil production sold by the partnership may be sold at prices above the applicable reference prices at which the marginal well production credit is reduced to zero, particularly in the early years of the partnership when the production from the partnership’s wells generally is the greatest. Thus, depending primarily on market prices for natural gas and oil, which are volatile, you may not receive any marginal well production credits from the partnership for many years, if ever. Moreover, the Managing GP anticipates that little, if any, of each partnership’s natural gas and oil production will be qualified production for purposes of this tax credit. See “Federal Income Tax Consequences – Marginal Well Production Credits.”

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CONFLICTS OF INTEREST

In General

Your interests and those of the Managing GP and its affiliates may be inconsistent in some respects or in certain instances, and the Managing GP’s actions may not be the most advantageous to you. The following discussion describes possible conflicts of interest that may arise for the Managing GP and its affiliates in the course of the partnership’s drilling activities contemplated in this prospectus. For some of the conflicts of interest, but not all, there are certain limitations on the Managing GP that are designed to reduce, but will not eliminate, the conflicts. Other than these limitations, the Managing GP has no procedures to resolve a conflict of interest and under the terms of the Limited Partnership Agreement, the Managing GP may resolve the conflict of interest in its sole discretion and best interest.

Further, the Managing GP depends on its affiliate, ICON Capital, for facilities, investor relations and administrative functions. Neither the Limited Partnership Agreement nor any other agreement requires that ICON Capital pursue a future business strategy that favors the partnership. The directors and officers of ICON Capital and the Managing GP have a fiduciary duty to make decisions in the best interests of their respective stakeholders. Because the Managing GP is allowed to take into account the interests of parties other than the partnership in resolving partnership conflicts of interest, this has the effect of creating a conflict of interest. However, this conflict of interest is not allowed to limit the Managing GP’s fiduciary duty to the partnership.

The following discussion is materially complete; however, other transactions or dealings may arise in the future that could result in additional conflicts of interest for the Managing GP and its affiliates.

Conflicts Regarding Transactions with the Managing GP and its Affiliates

Although the Managing GP believes that the compensation and reimbursements that it and its affiliates will receive in connection with the partnership are reasonable, the compensation has been determined solely by the Managing GP and did not result from negotiations with any unaffiliated third-party dealing at arm’s length. The Managing GP and its affiliates will receive compensation and reimbursements from the partnership for their services, as described in “Compensation” regardless of the success of the partnership’s wells. The Managing GP and its affiliates providing the services can be expected to profit from the transactions, and it is usually in the Managing GP’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 are comparable.

When the Managing GP or any affiliate provides services to the partnership, the Limited Partnership Agreement provides that their fees must be equal to the costs to the Managing GP or such affiliate of services or competitive with the fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses, whichever is less.

Any services not otherwise described in this prospectus or the Limited Partnership Agreement for which the Managing GP or an affiliate is to be compensated by the partnership must be:

set forth in a written contract that describes the services to be rendered and the compensation to be paid; and
cancelable without penalty on 60 days written notice by investors whose Interests equal a majority of the total Interests.

The compensation paid by the partnership to the Managing GP or its affiliates for additional services to the partnership under these contracts, if any, will be reported to you in the partnership’s annual and semiannual reports, and a copy of the contract will be provided to you on request.

There is also a conflict of interest concerning the purchase price if the Managing GP or an affiliate purchases a property from the 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 GP,” below.

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Conflicts Regarding Sharing of Costs and Revenues

The Managing GP will receive a percentage of partnership revenues that is greater than the percentage of partnership costs that it pays. This sharing arrangement may create a conflict of interest between the Managing GP and the investors in the partnership concerning the determination of which wells will be drilled by the partnership based on the risk and profit potential associated with the wells. The Managing GP 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 GP will serve as the partnership’s tax matters partner and represent the partnership before the IRS. The Managing GP will have broad authority to act on behalf of the 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:

whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, that would decrease:
º the amount of the partnership’s deduction for intangible drilling costs; or
º the amount of the Managing GP’s depreciation deductions, or the credit to its capital account for contributing any leases to the partnership, which would also decrease the Managing GP’s liquidation interest in the partnership; or
the amount charged to the partnership by the Managing GP as reimbursement for expenses incurred by the Managing GP in its role as the tax matters partner.

Conflicts Regarding Other Activities of the Managing GP and Its Affiliates

The Managing GP will be required to devote to the partnership the time and attention that it considers necessary for the proper management of the partnership’s activities. However, the Managing GP may sponsor and manage other oil and natural gas drilling partnerships, which may be concurrent with the partnership, and it may 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 the Managing GP’s other activities. See “Risk Factors — Risks Related to the Partnership’s Organization and Structure — The Managing GP’s officers manage other businesses and will not devote their time exclusively to managing the partnership and its business, and the partnership may face additional competition for time and capital because neither the Managing GP nor its affiliates are prohibited from raising money for or managing other entities that pursue the same types of investments that the partnership targets.”

The Managing GP will determine the allocation of its management time, services and other functions on an as-needed basis consistent with its fiduciary to the partnership and its other activities. However, the Managing GP depends on its affiliate, ICON Capital, for facilities, investor relations and administrative functions. See “Management — Transactions with Management and Affiliates.” Thus, the competition for the time and services of the Managing GP and its affiliates could result in insufficient attention to the management and operation of the partnership.

Subject to its fiduciary duties, the Managing GP and its affiliates will not be restricted from participating in other businesses or activities, even if these other businesses or activities compete with the partnership’s activities and operate in the same areas as the partnership. However, the Managing GP and its affiliates (including other oil and natural gas drilling partnerships for which it serves as the managing general partner) may pursue business opportunities that are consistent with the partnership’s investment objectives for their own account only after they have determined that the opportunity either:

cannot be pursued by the partnership because of insufficient funds; or
it is not appropriate for the partnership under the existing circumstances.

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Conflicts Involving the Acquisition of Leases

The Limited Partnership Agreement gives the Managing GP the authority to cause the partnership to acquire undivided interests in oil and natural gas properties, and to participate with other parties, including other drilling programs previously or subsequently conducted by the Managing GP or its affiliates, in the conduct of its drilling operations on those properties.

In addition, subject to the restrictions set forth below, the Managing GP decides which prospects and what interest in the prospects to transfer to the partnership. This will result in a subsequent partnership sponsored by the Managing GP 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. In this regard, as drilling progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves.

No procedures, other than the guidelines set forth below and in “— Procedures to Reduce Conflicts of Interest,” have been established by the Managing GP to resolve any conflicts that may arise. The Limited Partnership Agreement provides that the Managing GP and its affiliates will abide by the guidelines set forth below. In each case, 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. However, with respect to (2), (3), (4), (5), (7) and (9) below there is an exception in the Limited Partnership Agreement for another program in which the interest of the Managing GP is substantially similar to or less than its interest in the partnership.

(1) Transfers at Cost.  Any leases acquired by the partnership from the Managing GP will be credited as a capital contribution by the Managing GP to the partnership at the cost of the lease, unless the cost is materially more than the fair market value of the property. If the cost is materially more than fair market value, the Managing GP’s credit for the contribution must be at a price not in excess of the fair market value.
(2) Equal Proportionate Interest.  When the Managing GP sells or transfers an oil and natural gas interest to the 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. The term “prospect” generally means an area that is believed to contain commercially productive quantities of oil and/or natural gas; provided, however, that a prospect will be limited to the drilling or spacing unit on which one well will be drilled if the following two conditions are met:
the well is being drilled to a geological feature that contains proved reserves as defined below; and
the drilling or spacing unit protects against drainage.

“Proved reserves,” generally, are the estimated quantities of oil and natural gas that 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 or there is continuity of the reservoir.

(3) Subsequently Enlarging Prospect.  In areas where the prospect is not limited to the drilling or spacing unit and the area constituting the partnership’s prospect is subsequently enlarged based on geological information, which is later acquired, then, if the prospect is enlarged to cover any area where the Managing GP owns a separate property interest and the partnership activities were material in establishing the existence of proved undeveloped reserves that are attributable to the separate property interest, the separate property interest or a portion thereof must be sold to the partnership in accordance with (1), (2) and (4).

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(4) Transfer of Less than the Managing GP’s and its Affiliates’ Entire Interest.  If the Managing GP sells or transfers to the partnership less than all of its ownership in any prospect, then it must comply with the following conditions:
the retained interest must be a proportionate working interest;
the Managing GP’s obligations and the partnership’s obligations must be substantially the same after the sale of the interest by the Managing GP or its affiliates; and
the Managing GP’s revenue interest must not exceed the amount proportionate to its retained working interest.

For example, if the Managing GP transfers 50% of its working interest in a prospect to the partnership and retains a 50% working interest, then the partnership will not pay any of the costs associated with the Managing GP’s retained working interest as a part of the transfer. This limitation does not prevent the Managing GP 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 GP may sell its retained working interest to a third-party for a profit.

(5) Limitations on Activities of the Managing GP and its Affiliates on Leases Acquired by the Partnership.   For a five year period after the final closing of this offering, if the Managing GP proposes to acquire an interest from an unaffiliated person in a prospect in which the partnership owns an interest or in a prospect in which the partnership’s interest has been terminated without compensation within one year before the proposed acquisition, then the following conditions apply:
if the Managing GP does not currently own property in the prospect separately from the partnership, then the Managing GP may not buy an interest in the prospect; and
if the Managing GP 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 GP 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 GP is also prohibited from buying the additional interest.
(6) Limitations on Sale of Undeveloped and Developed Leases to the Managing GP.  The Managing GP and its affiliates, other than an affiliated partnership as set forth in (7) below, may not purchase undeveloped leases or receive a farmout from the partnership other than at the higher of cost or fair market value. Farmouts to the Managing GP and its affiliates also must comply with the conditions set forth in (9) below.

The Managing GP and its affiliates, other than an affiliated income program, may not purchase any producing natural gas or oil property from the partnership, unless the sale is in connection with the liquidation of the partnership. In such a case, the sale must be at fair market value supported by an appraisal of an independent expert selected by the Managing GP. 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 partnership may participate in drilling joint ventures with affiliated drilling limited partnerships. In this regard, the transfer of an undeveloped lease from the partnership to an affiliated drilling limited partnership must be made at fair market value, as supported by an appraisal from an independent expert. The costs of such transfer, including appraisal costs, will be shared equally between the affiliated limited partnerships.

An affiliated income program may purchase a producing oil and natural gas property from the partnership at any time at fair market value, as supported by an appraisal from an independent expert. The costs of such transfer, including appraisal costs, will be shared equally between the affiliated limited partnerships.

However, these prohibitions do not apply to joint ventures or farmouts among affiliated partnerships, provided that the respective obligations and revenue sharing of all parties to the transaction are substantially

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the same and the compensation arrangement or any other interest or right of either the Managing GP or its affiliates is the same in each affiliated partnership, or, if different, the aggregate compensation of the Managing GP or the affiliate is reduced to reflect the lower compensation arrangement.

(8) Leases Will Be Acquired Only for Stated Purpose of the Partnership.  The partnership 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 GP may not assign the working interest in a prospect to the partnership for the purpose of a subsequent farmout, sale or other disposition, nor may the Managing GP enter into a farmout to avoid paying its share of the costs related to drilling a well on an undeveloped lease. However, the Managing GP’s decision with respect to making a farmout and the terms of a farmout from the partnership involve conflicts of interest since (i) the Managing GP may benefit from cost savings and reduction of its risk and (ii) in the event of a farmout to an affiliated public program, the Managing GP will represent both partnerships.

The partnership may farmout an undeveloped lease or well activity to the Managing GP, its affiliates or an unaffiliated third-party only if the Managing GP, exercising the standard of a prudent operator, determines that:

the partnership lacks the funds to complete the oil and gas operations on the lease or well and cannot obtain suitable financing;
drilling on the lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the partnership;
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
the best interests of the partnership would be served.

Conflicts Between Investors and the Managing GP as an Investor

The Managing GP, its officers, directors and affiliates may subscribe for Interests in the partnership and the subscription price of their Interests will be reduced by 7% as described in “Plan of Distribution.” Even though they pay a reduced price for their Interests, these investors generally will:

share in the partnership’s costs, revenues and distributions on the same basis as the other investors as described in “Participation in Costs and Revenues”; and
have the same voting rights, except as discussed below.

Any subscription for Interests by the Managing GP, its officers, directors or affiliates in the partnership will dilute the voting rights of the investors and there may be a conflict with respect to certain matters. The Managing GP and its officers, directors and affiliates, however, are prohibited from voting with respect to certain matters. See “Summary of Limited Partnership Agreement — Voting Rights.”

Lack of Independent Underwriter and Due Diligence Investigation

The terms of this offering and the Limited Partnership Agreement were determined by the Managing GP without arm’s length negotiations. Also, there was not an extensive in-depth “due diligence” investigation of the existing and proposed business activities of the partnership and the Managing GP that would be provided by an independent underwriter. Although ICON Securities, which is affiliated with the Managing GP, serves as dealer-manager of this offering, its due diligence examination concerning this offering cannot be considered to be independent or as comprehensive as a due diligence examination that would have been conducted by an independent underwriter.

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Conflicts Concerning Legal Counsel

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 Limited Partnership Agreement. The Managing GP’s legal counsel will also serve as legal counsel to the partnership and this dual representation will continue in the future. However, if a future dispute arises between the Managing GP and you and the other investors in the partnership, then the Managing GP will cause you and the other investors to retain separate counsel. Also, if counsel advises the Managing GP that counsel reasonably believes its representation of the partnership will be adversely affected by its responsibilities to the Managing GP, then the Managing GP will cause you and the other investors in the partnership to retain separate counsel.

Conflicts Regarding Presentment Feature

You and the other investors in the partnership have the right to present your Interests in the partnership to the Managing GP for purchase beginning with the fifth calendar year after the end of the calendar year in which the partnership’s offering closes. This creates the following conflicts of interest between you and the Managing GP:

The Managing GP 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 GP’s sole discretion.
The Managing GP 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 GP.

Conflicts Regarding Managing GP Withdrawing or Assigning an Interest

A conflict of interest is created with the investors by the Managing GP’s right to do any of the following:

mortgage its Managing GP interest in the partnership;
withdraw an interest in the partnership’s wells equal to or less than its revenue interest to be used as collateral for a loan to the Managing GP; or
assign its Managing GP interest in the partnership to its affiliates which also may mortgage the interests as collateral for their loans, if any.

Procedures to Reduce Conflicts of Interest

In addition to the procedures set forth in “— Conflicts Involving the Acquisition of Leases,” the Managing GP and its affiliates will comply with the following procedures in the Limited Partnership Agreement to reduce some of the conflicts of interest with the investors. The Managing GP does not have any other conflict of interest resolution procedures. Thus, conflicts of interest between the Managing GP and you and the other investors may not necessarily be resolved in your best interests.

(1) Fair and Reasonable.  The Managing GP may not sell, transfer, or convey any property to, or purchase any property from, the partnership except pursuant to transactions that are fair and reasonable; nor take any action with respect to the assets or property of the partnership which does not primarily benefit the partnership.
(2) No Compensating Balances.  The Managing GP may not use the partnership’s funds as a compensating balance on deposit to satisfy the terms of any agreement the Managing GP or any of its affiliates enters into on its own behalf. Thus, the partnership’s funds may not be used to satisfy any deposit requirements imposed by a bank or other financial institution on the Managing GP for its own corporate purposes.
(3) Future Production.  The Managing GP may not commit the future production of a partnership well exclusively for the Managing GP’s own benefit.

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(4) Marketing Arrangements.  All benefits from marketing arrangements or other relationships affecting property of the Managing GP or its affiliates and the partnership will be fairly and equitably apportioned according to the respective interests of each.
(5) Disclosure.  Any agreement or arrangement that binds the partnership must be fully disclosed in this prospectus.
(6) No Loans from the Partnership.  The partnership may not loan money to the Managing GP or any of its affiliates.
(7) No Rebates.  The Managing GP may not participate in any business arrangements which would circumvent these guidelines including receiving rebates or give-ups.
(8) Sale of Assets.  The sale of all or substantially all of the assets of the partnership may only be made with the consent of investors whose Interests equal a majority of the total outstanding Interests.
(9) Participation in Other Partnerships.  If the partnership participates in other partnerships or joint ventures, then the terms of the arrangements must not circumvent any of the requirements contained in the Limited Partnership Agreement, including the following:
there may be no duplication or increase in O&O Costs, the Managing GP’s compensation, partnership expenses, or other fees and costs;
there may be no substantive change in the fiduciary and contractual relationship between the Managing GP and the investors; and
there may be no diminution in your voting rights.
(10) Safekeeping of Funds.  The Managing GP may not employ, or permit another to employ, the funds or assets of the partnership in any manner except for the exclusive benefit of the partnership. The Managing GP has a fiduciary responsibility for the safekeeping and use of all funds and assets of the partnership whether or not in the Managing GP’s possession or control.
(11) Advance Payments.  Advance payments by the partnership to the Managing GP and its affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid intangible drilling costs for a business purpose set forth in the related Participation Agreement.

Policy Regarding Roll-Ups

It is possible at some indeterminate time in the future that the partnership may become involved in a roll-up. In general, a roll-up means a transaction involving the acquisition, merger, conversion or consolidation of the partnership with or into another partnership, corporation or other entity, and the issuance of securities by the roll-up entity to the investors. A roll-up will also include any change in the rights, preferences and privileges of the investors in the partnership. These changes could include the following:

increasing the compensation of the Managing GP;
amending your voting rights;
listing the Interests on a national securities exchange or on NASDAQ;
changing the partnership’s fundamental investment objectives; or
materially altering the partnership’s duration.

If a roll-up should occur in the future, the Limited Partnership Agreement provides various policies which include the following:

an independent expert must appraise all partnership assets as discussed in Section 4.03(d)(16)(a) of the Limited Partnership Agreement, and you must receive a summary of the appraisal in connection with a proposed roll-up;
if you vote “no” on the roll-up proposal, then you will be offered a choice of:
accepting the securities of the roll-up entity; or

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one of the following:
º remaining a partner in the partnership and preserving your Interests 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
the partnership will not participate in a proposed roll-up:
º unless approved by investors whose Interests equal a majority of the total Interests;
º which would result in the diminution 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 Limited 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 Interests equal a majority of the total Interests.

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ACTIONS TO BE TAKEN BY THE MANAGING GP TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS

You may choose to invest in the 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 Investor General Partners could be required to make additional payments to the partnership, the Managing GP will take the actions set forth below.

Insurance.  The Managing GP will obtain and maintain insurance coverage in amounts and for purposes as required by applicable law. Generally, the Managing GP expects to obtain public liability insurance with limits, including umbrella policy limits, of at least $50,000,000. The partnership will be included as an insured under these general, umbrella, and excess liability policies and will pay the premiums for each of the policies obtained on its behalf. The partnership’s insurance coverage may include the partnership being named as an additional insured in each Project under the relevant operator’s insurance policies. In addition, the partnership may require that each of its operators certify that each subcontractor has acceptable insurance coverage for worker’s compensation and general, auto, and excess liability coverage. In the event of a loss caused by a major subcontractor, the partnership may attempt to draw on the insurance policy of the relevant operator before the insurance of the partnership. Also, even if a major subcontractor’s insurance was initially available, the 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 GP will review the partnership’s insurance coverage prior to commencing drilling operations and periodically evaluate the sufficiency of insurance

The insurance will have terms, including exclusions, that are standard for the oil and natural gas industry. If you are an Investor General Partner and there is going to be a material adverse change in the partnership’s insurance coverage, which the Managing GP does not anticipate, then the Managing GP will notify you at least 30 days before the effective date of the change. You will then have the right to convert your Investor General Partner Interests into Limited Partner Interests before the change in insurance coverage is effective by giving written notice to the Managing GP.

Conversion of Investor General Partner Interests to Limited Partner Interests.  Your Investor General Partner Interests will be automatically converted by the Managing GP to Limited Partner Interests upon the occurrence of the earlier of (i) the drilling and completion of all of the partnership's wells, as determined by the Managing GP’s geologists, or (ii) the date that no additional currently deductible intangible drilling costs will be realized by the partnership's Investor General Partners, as determined by the Managing GP. A well is deemed to be completed when production equipment is installed on a well, even though the well may not yet be connected to a pipeline for production of oil and/or natural gas. The timeline of such conversion depends on the timing and amount of the sale of Interests as well as the availability of appropriate Projects being sourced by the partnership’s operators. The partnership will generally invest in Projects at the time leases are acquired through the completion of the wells. Once all of the wells within all of the partnership’s Projects are completed, the Investor General Partner Interests will then be converted to Limited Partner Interests. If the offering raises the maximum offering amount, the partnership will be able to drill more wells and the larger number of wells would be expected to take longer to drill. If the offering raises less than the maximum offering amount, the number of wells that may be drilled will be less and, therefore, drilling would be expected to be completed sooner. The conversion is not expected to create any tax liability to the investors. This would delay conversion of the Investor General Partner Interests to Limited Partner Interests because the Managing GP will not convert the Investor General Partner Interests to Limited Partner Interests in the partnership until after all of the partnership’s wells have been drilled and completed.

Once your Interests are converted, you will have the lesser liability of a limited partner in the 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 amount 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 the conversion.

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Indemnification.  The Managing GP will use its corporate assets, as well as the assets of the principals of its parent company, which assets are held primarily at Warrenton Capital Corp. (“Warrenton”), an affiliate of the Managing GP, to indemnify each Investor General Partner from any partnership-related liability that is in excess of its interest in the partnership’s undistributed net assets and insurance proceeds, if any, from all potential sources. Further, the Managing GP will indemnify each Investor General Partner against any personal liability resulting from the unauthorized acts of another Investor General Partner.

If the Managing GP provides indemnification, then each Investor General Partner that has been indemnified shall transfer and subrogate his rights for contributions from or against any other Investor General Partner to the Managing GP.

The Managing GP’s indemnification obligation, however, will not eliminate investors’ potential liability if the Managing GP’s assets, including a demand promissory note issued by the principals of the parent of the Managing GP and a Note Funding Agreement from Warrenton whereby Warrenton supports the funding obligation under the demand promissory note, are insufficient to satisfy its indemnification obligation. There can be no assurance that the Managing GP’s assets, including its liquid assets, will be sufficient to satisfy its indemnification obligation.

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SOURCE OF FUNDS AND ESTIMATED USE OF OFFERING PROCEEDS

Source of Funds

The partnership must receive minimum offering proceeds of $2,000,000 to break escrow, and the maximum offering proceeds may not exceed $200,000,000. There are no other requirements regarding the size of the partnership.

On completion of the offering of Interests and assuming each Interest is sold for $10,000, the partnership’s source of funds will be as follows:

the gross offering proceeds, which will be $2,000,000 if the minimum number of Interests (200) are sold and $200,000,000 if the maximum number of Interests (20,000) are sold; and
the Managing GP’s capital contribution, which must be at least 1% of all investor capital contributions (net of O&O Costs and the management fee), and may include a credit for (i) contributing certain leases covering a portion of the acreage on which the partnership’s wells will be drilled (the value of such contributed leases to be measured either at cost or fair market value if the Managing GP has reason to believe that the cost is materially more than fair market value), (ii) paying for a portion of equipment costs of well drilling and completion, and/or (iii) paying for a portion of O&O Costs, as discussed in “Participation in Costs and Revenues.” The Managing GP may also satisfy its minimum capital contribution requirement with a direct cash contribution to the partnership.

The net offering proceeds available to the partnership will be not less than approximately $1,717,000 ($1,700,000 plus $17,000 equal to the Managing GP’s 1% capital contribution) if 200 Interests are sold and not less than approximately $171,700,000 ($170,000,000 plus $1,700,000 equal to the Managing GP’s 1% capital contribution) if 20,000 Interests are sold. Such amounts include the gross offering proceeds (net of O&O Costs and the management fee) and a capital contribution by the Managing GP equal to 1% of the offering proceeds (net of O&O Costs and the management fee).

Estimated Use of Offering Proceeds

The gross offering proceeds will be used by the partnership to pay the following:

99% of the intangible drilling costs of drilling and completing the partnership’s wells;
up to 99% of the non-deductible equipment costs of drilling and completing the partnership’s wells: and
(1) up to 99% of O&O Costs and (2) 99% of the Managing GP’s management fee. The sum of the O&O Costs and the management fee will equal but not exceed 15% of the gross offering proceeds.

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. For example, intangible drilling costs include 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 oil or natural gas. Intangible drilling costs also include the expense of plugging and abandoning any well before a completion attempt, and the costs (other than non-deductible equipment costs and lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.

Non-deductible equipment costs, generally, means the costs of drilling and completing a well that are not currently deductible and are not lease costs.

O&O Costs include (i) the dealer-manager fee, (ii) sales commissions and (iii) other costs related to the organization of the partnership and the offering of the Interests and with the management fee are expected to equal 15% of the gross offering proceeds.

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The following table presents information concerning the partnership’s estimated use of the gross proceeds provided by investors. In addition, as discussed above, the Managing GP will make a capital contribution at least equal to 1% of total investor capital contributions (net of O&O Costs and the management fee). All or a portion of the Managing GP’s capital contribution may be in the form of a direct cash contribution to the partnership’s general account, a contribution of leases, and/or a payment of non-deductible equipment costs incurred by the partnership in drilling and completing its wells. If the Managing GP makes a capital contribution, regardless of form, the Managing GP will receive a share of the partnership’s revenues in the same percentage that its capital contribution bears to the total capital contributions to the partnership.

Substantially all of the gross offering proceeds available to the partnership will be expended for the following purposes and in the following manner:

ESTIMATED USE OF OFFERING PROCEEDS

           
  200 INTERESTS SOLD   10,000 INTERESTS SOLD   20,000 INTERESTS SOLD
NATURE OF PAYMENT   $   %(1)   $   %(1)   $   %(1)
O&O Costs and Management Fee(2):
                                                     
Dealer-Manager fee and Sales Commissions.   $ 200,000       10 %    $ 10,000,000       10 %    $ 20,000,000       10 % 
Other costs related to the organization of the partnership and the offering of the Interests; and Managing GP’s management fee   $ 100,000       5 %    $ 5,000,000       5 %    $ 10,000,000       5 % 
Total:   $ 300,000       15 %    $ 15,000,000       15 %    $ 30,000,000       15 % 
Amount of Offering Proceeds Available for Investment:
                                                     
Intangible drilling costs     (3)       (3)       (3)       (3)       (3)       (3)  
Non-deductible equipment costs     (3)       (3)       (3)       (3)       (3)       (3)  
Leases         (4)           (4)           (4)           (4)            (4)            (4)  
Total(5)   $ 1,700,000       85 %    $ 85,000,000       85 %    $ 170,000,000       85 % 

(1) The percentage is based on the gross offering proceeds, and excludes any capital contributions made by the Managing GP.
(2) As discussed in “Participation in Costs and Revenues,” the aggregate of the O&O Costs and the management fee paid to the Managing GP will equal but not exceed 15% of the total gross offering proceeds of the partnership. The O&O Costs consist of the 3% dealer-manager fee, the 7% sales commissions and the other costs related to the organization of the partnership and the offering of the Interests, and the Managing GP’s management fee is equal to the difference between 15% of the gross offering proceeds and the O&O Costs.
(3) The net offering proceeds of investors in the partnership will be used to pay 99% of the intangible drilling costs and up to 99% of the non-deductible equipment costs incurred by the partnership in drilling and completing its wells. The allocation of the partnership’s costs of drilling and completing each well between intangible drilling costs and non-deductible equipment costs will be set forth in the Authority for Expenditure for each well, which will be agreed upon by the Managing GP and the related operator and attached to the related Participation Agreement as an exhibit before each such well is drilled.
(4) A portion of the leases covering the acreage on which the partnership’s wells will be drilled may be contributed to the partnership by the Managing GP. If the Managing GP contributes any such leases, the Managing GP’s capital account will be credited with a capital contribution for each contributed lease valued either at its cost or fair market value if the Managing GP has reason to believe that the cost is materially more than fair market value. The Managing GP is not obligated to directly acquire and contribute any leases.
(5) The partnership is not restricted from financing exploratory wells or purchasing producing properties; though the partnership does not intend to finance exploratory wells and the purchase of producing properties is not expected to comprise a significant portion of its investments.

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COMPENSATION

The following table summarizes the items of compensation to be paid to the Managing GP, its affiliates and each operator from the partnership. The amount of each item of compensation will depend on how many Projects in which the partnership participates, how many wells are drilled within each Project and how much of the working interest in each of the wells is owned by the partnership.

Compensation Related to the Organization of the Partnership and the Offering of Interests

   
Type of Compensation   Method of Compensation   Estimated Dollar Amount
Sales Commissions(1) — 
paid in cash to selling dealers that are not affiliated with the Managing GP.
  Up to $700.00 per Interest from all Interests sold in this offering, or 7.0% of the gross offering proceeds.   Because Sales Commissions are based upon the number of Interests sold, the total amount of Sales Commissions cannot be determined until this offering is complete.
Sales Commissions of up to $140,000 will be paid if the minimum number of 200 Interests is sold in this offering.
          Sales Commissions of up to $14,000,000 will be paid if the maximum number of 20,000 Interests is sold in this offering.
Dealer-Manager Fee — paid in cash to ICON Securities, the dealer-manager and an affiliate of the Managing GP.   $300.00 per Interest on all Interests sold in this offering, or 3.0% of the gross offering proceeds for managing the offering and to reimburse ICON Securities for wholesaling fees and expenses. A portion of the $300.00 per Interest may be re-allowed to selling dealers as a marketing fee for their assistance in marketing this offering and coordinating their sales efforts with those of ICON Securities.
  
Expenses paid from the Dealer-Manager Fee include, but are not limited to: (i) an amount up to $100.00 per Interest that may be re-allowed to selling dealers as a marketing fee for their assistance in this offering; (ii) salaries and commissions of ICON Securities’ employees, including regional vice presidents and regional marketing directors; (iii) and national training and education conferences and seminars.
  Because the Dealer-Manager Fee is based upon the number of Interests sold, the total amount of the Dealer-Manager Fee cannot be determined until this offering is complete.
  
A Dealer-Manager Fee of $60,000 will be paid if the minimum number of 200 Interests is sold in this offering.
  
A Dealer-Manager Fee of $6,000,000 will be paid if the maximum number of 20,000 Interests is sold in this offering.

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Type of Compensation   Method of Compensation   Estimated Dollar Amount
Reimbursement for expenses related to the organization of the partnership and the offering of Interests —  reimbursement to the Managing GP for certain of the partnership’s expenses.   Certain expenses related to the organization of the partnership and the offering of Interests will be reimbursed on an accountable basis, which means that the total amount of such costs that the Managing GP will be reimbursed for will be capped at an amount equal to the difference between (i) 15% of the gross offering proceeds and (ii) the sum of the Dealer-Manager Fee, Sales Commissions and the management fee. Accordingly, the Managing GP and its affiliates ultimately may be reimbursed for less than the actual amount of such costs incurred.   Because such expenses are based upon the number of Interests sold, the total amount of such expenses cannot be determined until this offering is complete.
     The partnership will pay or advance bona fide due diligence fees and expenses of ICON Securities and actual and prospective selling dealers on a fully accountable basis based upon receipt of a detailed and itemized invoice.     
Management Fee — paid to the Managing GP.   The difference between 15% of the gross offering proceeds and the sum of all O&O Costs.(2)
  
In no event will the sum of the Managing GP’s management fee and the O&O Costs exceed 15% of the gross offering proceeds.
  Because the management fee is based upon the number of Interests sold, the total amount of the management fee cannot be determined until this offering is complete.

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Type of Compensation   Method of Compensation   Estimated Dollar Amount
     In conducting its management and supervisory roles for each Project, the Managing GP will perform the following functions: (i) participate in the determination of the AMI and oversee the lease acquisition process to ensure that the lease prices charged to the partnership for leases acquired directly by the operator are reasonable; (ii) oversee infrastructure building by the operator, including the drilling of the saltwater disposal well(s), establishing the power grid, installing the tank battery and installing the gas gathering system; (iii) oversee the drilling of the pilot well(s) to ensure the reasonableness of the costs and techniques used; (iv) evaluate the results of the pilot well(s) and participate in decision-making with the operator regarding whether or not more wells will be drilled within the Project; (v) if more wells are to be drilled within the Project, oversee the infrastructure expansion, if necessary; (vi) oversee the marketing of the hydrocarbons produced from the Project, including direct marketing of the natural gas produced; and (vii) oversee the sale or plugging and abandonment of the wells within the Project.  

(1) The amounts listed above for Sales Commissions do not give effect to the potential reduction of the Sales Commissions in connection with sales for which a volume discount applies and/or the potential waiver of the Sales Commission in connection with sales to the Managing GP, the selling dealers or certain of their affiliates, as well as registered investment advisers and their clients. To the extent Interests are purchased this way, the estimated amount of the expenses of this offering reflected in this chart may be reduced. See “Plan of Distribution.”
(2) O&O Costs include the Dealer-Manager Fee, Sales Commissions and any other costs associated with the organization of the partnership and the offering of Interests.

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Compensation Related to the Operation of the Partnership

   
Type of Compensation   Method of Compensation   Estimated Dollar Amount
Oil and Natural Gas Revenues — a percentage of which will be paid to the Managing GP.   The Managing GP will receive a share of the partnership’s revenues from the production of oil and natural gas. The investors and the Managing GP will share in the partnership’s revenues in the same percentages as their respective capital contributions bear to the total partnership capital contributions, except that the Managing GP will receive an additional 10% of the partnership’s revenues. The Managing GP will make a minimum capital contribution at least equal to 1% of total investor capital contributions (net of O&O Costs and the management fee). A portion of the Managing GP’s capital contribution may be in the form of (i) leases contributed to the partnership, (ii) payments for a portion of non-deductible equipment costs of well drilling and completion, and/or (iii) payments for a portion of O&O Costs. For each contributed lease, the Managing GP will receive a credit to its capital account equal to the cost of such lease, or the fair market value of the lease if the Managing GP has reason to believe that the cost is materially more than the fair market value. The partnership’s credit for its lease and/or other costs incurred for a Project will be proportionate to its working interest in the Project.   The actual amount of production revenue generated cannot be quantified because the volume of oil and natural gas that will be produced from the partnership’s wells cannot be predicted.

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Type of Compensation   Method of Compensation   Estimated Dollar Amount
Supervisory Fee — paid to the Managing GP or its affiliates, as applicable, if the Managing GP or any such affiliate serves as operator.   If the Managing GP or any of its affiliates serves as the operator for any of the partnership’s wells, the Managing GP or such affiliate, as applicable, may charge a Supervisory Fee for operating and maintaining the wells during producing operations. Neither the Managing GP nor any of its affiliates anticipate serving as operator for any of the partnership’s wells. Accordingly, neither the Managing GP nor any of its affiliates anticipate charging a Supervisory Fee for such services. If the Managing GP or any of its affiliates were to serve as operator for any of the partnership’s wells, the Supervisory Fee for such services would be at a rate competitive with rates charged by third-party operators providing similar services, but not based on arm’s-length negotiations. See “Conflicts of Interest — Conflicts Regarding Transactions with the Managing GP and its Affiliates.”   Because the Supervisory Fee would be based upon the characteristics of each Project and the industry rates at the time of such Project, the total amount of the Supervisory Fee for each Project cannot be determined until such Project is identified.
     Notwithstanding anything to the contrary neither the Managing GP nor its affiliates may profit by drilling in contravention of its fiduciary obligation to the investors.     
Gas Marketing Fees — paid to the Managing GP.   The partnership may pay to the Managing GP gas marketing fees, at competitive rates, but not based on arm’s-length negotiations, for its services, if any, in marketing the natural gas production. The Managing GP does not currently anticipate participating in the marketing of its natural gas production, and thus, does not anticipate charging any gas marketing fees. See “Conflicts of Interest — Conflicts Regarding Transactions with the Managing GP and its Affiliates.”   Because any gas marketing fees will be based upon the characteristics of each Project and the industry rates at the time of such Project, the total amount of the gas marketing fees, if any, to be paid to the Managing GP for each Project cannot be determined until such Project is identified.
     If the Managing GP participates in marketing for sale the natural gas produced from its wells, it will market such gas to other gas marketers, interstate and/or intrastate pipeline systems, local distribution companies, local utilities and/or end-users in the area, in each case, under market sensitive contracts in which the price of natural gas sold will vary as a result of market forces.  

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Type of Compensation   Method of Compensation   Estimated Dollar Amount
Interest and Other Compensation —  paid to the Managing GP.   The Managing GP or an affiliate will have the right to charge a rate of interest equal to its cost of funding on any loan it may make to or on behalf of the partnership. If the Managing GP or an affiliate provides equipment, supplies, and other services to the drilling operations, then it may do so for a rate equal to the cost to the Managing GP or such affiliate of such services, equipment or supplies or at competitive industry rates, but not based on arm’s-length negotiations, whichever is less. The Managing GP will determine 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 GP will contact at least two unaffiliated third-parties; provided, however, that the Managing GP will have sole discretion in determining the amount to be charged the partnership. See “Conflicts of Interest — Conflicts Regarding Transactions with the Managing GP and its Affiliates.”
  
For loans made to the partnership by the Managing GP or an affiliate, the Managing GP or an affiliate, as the case may be, may not receive interest in excess of its interest costs, and the Managing GP or an affiliate, as the case may be, will not receive points or other financing charges or fees, regardless of the amount.
  Because any loans, services, equipment and/or supplies provided to the partnership will be based upon the characteristics of each Project and the industry rates at the time of such Project, the total amount of interest and other compensation, if any, associated with such items for each Project cannot be determined until such Project is identified.

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Type of Compensation   Method of Compensation   Estimated Dollar Amount
Reimbursement for Administrative Costs and Direct Costs — paid to the Managing GP.   The Managing GP will receive from the partnership reimbursement for its administrative costs (subject to applicable caps) and its fixed direct costs, in each case, on a fully accountable basis.
  
Direct costs are third-party service provider costs incurred by the partnership, including, among other things, legal fees, accounting fees for audit and tax preparation, and independent engineering analyses and reports. Direct costs will be billed directly to, and paid by, the partnership to the extent practicable. If the Managing GP pays for any direct costs on behalf of the partnership, the Managing GP will receive from the partnership reimbursement for such payments.
  See table below.

The Managing GP estimates that Administrative Costs and Direct Costs allocable to the ICON Oil & Gas Fund for the first twelve months of operation will be approximately $107,000 if the minimum offering proceeds are received (representing approximately 5% of the minimum offering proceeds) and will be approximately $987,000 if the maximum offering proceeds are received (representing approximately 0.5% of the maximum offering proceeds).

The Managing GP estimates that the components of such allocable amounts will be as follows:

   
Administrative Costs   Minimum Offering Proceeds   Maximum Offering Proceeds
Legal   $ 10,000     $ 200,000  
Accounting   $ 10,000     $ 200,000  
Geological/Engineering   $ 10,000     $ 200,000  
Secretarial   $ 0     $ 25,000  
Travel & Entertainment   $ 0     $ 10,000  
Office Rent   $ 15,000     $ 15,000  
Telephone   $ 2,000     $ 2,000  

   
Direct Costs              
External Legal   $ 5,000     $ 50,000  
Audit Fees   $ 15,000     $ 180,000  
Tax   $ 5,000     $ 50,000  
Bookkeeping   $ 10,000     $ 30,000  
Petra Software   $ 25,000     $ 25,000  
TOTAL   $ 107,000     $ 987,000  

The procedures for determining the amounts of Administrative Costs to be allocated to the ICON Oil & Gas Fund are for actual costs to be charged to each partnership based upon the percentage of time the relevant personnel dedicate to such partnership.

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Compensation to Each Operator

   
Type of Compensation   Method of Compensation   Estimated Dollar Amount
Operator Fee and Reimbursement of Direct Costs — paid to each operator.   The partnership will enter into Participation Agreements with unaffiliated operators to drill and complete the partnership’s wells. Pursuant to each such Participation Agreement, the partnership will pay the operator compensation, at competitive rates, to drill and complete the partnership’s wells. In addition, the partnership will reimburse the operators at actual cost, upon presentation of a detailed and itemized invoice, for direct costs incurred by it on behalf of the partnership.   The Operator Fee and reimbursement of the operator’s direct costs will depend on the particular costs of each Project, and, as such, are not determinable until such Project is identified.
     The partnership does not currently have any affiliates that are drilling operators and, accordingly, will enter into Participation Agreements with unaffiliated operators only.     
Well Supervision Fee — paid to each operator.   Under each Participation Agreement, the operator may receive from the partnership, when the wells subject to such Participation Agreement begin producing oil and/or natural gas, well supervision fees at a competitive rate for operating and maintaining the wells during producing operations.   The competitive rate for each well supervision fee will depend on the type and location of each Project in which the partnership participates. The well supervision fee, if any, for each Project will be proportionate to the operator’s working interest in such Project and may be adjusted as such Project progresses to ensure that the fee remains competitive.
     The well supervision fee is intended to cover all normal and regularly recurring operating expenses for the production, delivery, and sale of oil and natural gas, such as: (i) well tending, routine maintenance, and adjustment; reading meters; (ii) recording production, pumping, maintaining appropriate books and records; and (iii) preparing reports to the partnership and to government agencies.
  
The well supervision fees do not include costs and expenses related to: (i) the purchase of equipment, materials, or third-party services; (ii) water hauling; and (iii) rebuilding of access roads.
  
These costs will be charged to the working interest owners at the invoice cost of the materials purchased or the third-party services performed.

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Type of Compensation   Method of Compensation   Estimated Dollar Amount
Gathering Fees — paid to each operator.   Under each Participation Agreement, the operator will be responsible for gathering and transporting, or engaging a third-party gathering system to gather and transport, the natural gas produced by the partnership to interstate/intrastate pipeline systems, local distribution companies, and/or end-users in the area. The partnership will pay a gathering fee directly to each operator or third-party gathering system at competitive rates for the gathering services. The gathering fees paid by the partnership may be increased from time to time but may not be increased beyond competitive rates.   The actual amount of gathering fees to be paid by the partnership to each operator cannot be quantified, because the volume of natural gas that will be produced and transported from the partnership’s wells cannot be predicted.
     In the event an operator uses a third-party gathering system to gather the natural gas produced from the partnership’s wells, that operator will pay all of the gathering fees that it receives from the partnership to such third-party. No operator may retain any excess gathering fees it receives from the partnership over the payments it makes to third-party gas gatherers.     

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TERMS OF THE OFFERING

Subscription to the Partnership

ICON Oil & Gas Fund was formed to offer for sale an aggregate of $200,000,000 of interests in a series of up to three limited partnerships, each of which has been formed under the Delaware Revised Uniform Limited Partnership Act.

Each partnership within ICON Oil & Gas Fund will offer a minimum of 200 Interests, which is $2,000,000, and the partnerships, in the aggregate, will offer a maximum of 20,000 Interests, which is $200,000,000; provided, that, in its sole discretion, the Managing GP may, at any time prior to the two-year anniversary of the date of this prospectus, increase the offering to a maximum of up to 30,000 Interests, which is $300,000,000; provided further, that the Managing GP may not extend the offering period in connection with such change. In the event the Managing GP increases the size of the offering, the partnership will file a separate registration statement on Form S-1 regarding the additional Interests it offers. The maximum subscription for each partnership must be the lesser of:

$200,000,000; or
$200,000,000 less the total offering proceeds received by any prior partnership in the Fund.

Also, set forth below are the targeted ending dates of the offering of interests for each partnership, which are not binding except that the interests in each partnership may not be offered beyond that partnership’s offering termination date as set forth below. The Managing GP may close the offering of interests in a partnership at any time before that partnership’s offering termination date once that partnership is in receipt of the minimum required subscriptions, and the Managing GP may withdraw the offering of interests in a partnership at any time.

     
Partnership Name   Minimum
Offering
Proceeds
  Maximum
Offering
Proceeds
  Offering
Termination
Date(1)
ICON Oil & Gas Fund-A L.P.   $ 2,000,000     $ 200,000,000       December 31, 2012 (2) 
ICON Oil & Gas Fund-B L.P.   $ 2,000,000       (3)       (3)  
ICON Oil & Gas Fund-C L.P.   $ 2,000,000       (3)       (3)  

(1) The partnerships will be offered in a series. Thus, interests in ICON Oil & Gas Fund-B L.P. will not be offered until the offering of interests in ICON Oil & Gas Fund-A L.P. has terminated. Likewise, interests in ICON Oil & Gas Fund-C L.P. will not be offered until the offering of interests in ICON Oil & Gas Fund-B L.P. has terminated.
(2) The offering for ICON Oil and Gas Fund-A L.P. may be extended beyond such date by the Managing GP pursuant to a supplement to this prospectus.
(3) If ICON Oil & Gas Fund-A L.P. receives the maximum offering proceeds set forth above, then interests in ICON Oil & Gas Fund-B L.P. and ICON Oil & Gas Fund-C L.P. will not be offered. Likewise, if, in aggregate, ICON Oil & Gas Fund-A L.P. and ICON Oil & Gas Fund-B L.P. receive the maximum offering proceeds, then interests in ICON Oil & Gas Fund-C L.P. will not be offered.

This prospectus relates to the offering of interests in ICON Oil & Gas Fund-A L.P. (the “Interests”) only and all references to “the partnership” herein means ICON Oil & Gas Fund-A L.P. The interests in the other partnerships in ICON Oil & Gas Fund will be offered pursuant to separate prospectuses following the termination of this offering for ICON Oil & Gas Fund-A L.P. on or before December 31, 2012, unless this offering is extended by the Managing GP pursuant to a supplement to this prospectus. Interests are offered at an offering price of $10,000 per Interest ($9,300 per Interest for Interests sold to the Managing GP, selling dealers or certain of their affiliates, as well as registered investment advisers and their clients) and must be paid 100% in cash at the time of subscribing. The offering price of the Interests has been arbitrarily determined by the Managing GP because the partnership does not have any prior operations, assets, earnings, liabilities or present value. Your minimum subscription is one half (½) Interest ($5,000). Fractional subscriptions will be accepted in $1,000 increments, beginning with $6,000, $7,000, etc.

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You may elect to purchase Interests as either an Investor General Partner or a Limited Partner. However, even though you may elect to subscribe as an Investor General Partner, the Managing GP will have exclusive management authority for the partnership.

Description of Interests

On subscribing for Interests, you may elect to buy either:

Investor General Partner Interests; or
Limited Partner Interests.

The type of Interest you buy will not affect the allocation of costs, revenues, and cash distributions among the investors in the partnership. There are, however, material differences in the federal income tax effects and liability associated with each type of Interest. Under the Limited Partnership Agreement, no investor may participate in the management of the partnership or its business. The Managing General Partner will have exclusive management authority for the partnership.

Investor General Partner Interests

Tax Effect.  If you invest as an Investor General Partner, then your share of the partnership’s deduction for intangible drilling costs will not be subject to the passive activity limitations on losses. You may claim a deduction in an amount equal to not less than the percentage of your subscription amount used to pay for intangible drilling costs for all of the wells to be drilled by the partnership in that taxable year. See “Federal Income Tax Consequences—Limitations on Passive Activity Losses and Credits.”
|sy 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. For example, intangible drilling costs include 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 oil or natural gas. Intangible drilling costs also include the expense of plugging and abandoning any well before a completion attempt, and the costs (other than equipment costs and lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.
Unlimited Liability.  If you invest as an Investor General Partner, you will have unlimited liability regarding the partnership’s activities. This means that if (i) the partnership’s insurance proceeds from any source, (ii) the Managing GP’s indemnification of the Investor General Partners, and (iii) the partnership’s assets were, collectively, not sufficient to satisfy a partnership liability for which the Investor General Partners were also liable solely because of your status as general partners of the partnership, then the Managing GP would require the Investor General Partners to make additional capital contributions to the partnership to satisfy the liability. In addition, the Investor General Partners will have joint and several liability, which means, generally, that a person with a claim against the partnership and/or an Investor General Partner may sue all or any one or more of our general partners, including you, for the entire amount of the liability.

You will be able to determine if your Interests are subject to assessability based on whether you buy Investor General Partner Interests, which are assessable, or Limited Partner Interests, which are not assessable.

Your Investor General Partner Interests will be automatically converted by the Managing GP to Limited Partner Interests upon the occurrence of the earlier of (i) the drilling and completion of all of the partnership’s wells, as determined by the Managing GP’s geologists, or (ii) the date that no additional currently deductible intangible drilling costs will be realized by the partnership’s Investor General Partners, as determined by the Managing GP. In this regard, a well is deemed to be completed when production equipment is installed on a well, even though the well may not yet be connected to a pipeline for production of oil or natural gas. Once all of the wells within all of the partnership’s Projects are completed, the Investor General Partner Interests will then be converted to Limited Partner Interests. If the offering raises the maximum offering amount, the

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partnership will be able to drill more wells and the larger number of wells would be expected to take longer to drill. If the offering raises less than the maximum offering amount, the number of wells that may be drilled will be less and, therefore, drilling would be expected to be completed sooner. The conversion is not expected to create any tax liability to the investors.

Once your Interests are converted, you will have the limited liability of a limited partner under Delaware law for partnership 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 amount 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 the conversion.

Limited Partner Interests

Tax Effect.  If you invest as a Limited Partner, then your use of your share of the partnership’s deduction for intangible drilling costs will be limited to offsetting your net passive income from the partnership’s “passive” trade or business activities.
|sy Passive trade or business activities generally include the partnership and other limited partner investments, but passive income does not include salaries, dividends or 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 net passive income from investments other than the partnership. However, any portion of your share of the partnership’s deduction for intangible drilling costs that you cannot use in the year in which you invest, because you do not have sufficient net passive income in that year, may be carried forward indefinitely until you can use it to offset your net passive income from the partnership or your other passive activities, if any, in subsequent tax years. See “Federal Income Tax Consequences — Limitations on Passive Activity Losses and Credits.”
Limited Liability.  If you invest as a Limited Partner, then you will have limited liability for the partnership’s liabilities and obligations. This means that you will not be liable for any partnership liabilities or obligations beyond the amount of your initial investment in the partnership and your share of our undistributed net profits, subject to certain exceptions set forth in “Summary of Limited Partnership Agreement — Liability of Limited Partners.”

The Managing GP reserves the right to offer new types of Interests, either in addition to or in lieu of Investor General Partner Interests and/or Limited Partner Interests, in the future. Specifically, the Managing GP may, at some point, offer net profits interests, which would generally be treated as a type of royalty interest for federal tax purposes and should qualify as an exempted royalty for unrelated business income tax purposes. Holders of net profits interests will generally be entitled to depletion allowances but will generally not qualify for intangible drilling cost and depreciation deductions.

Partnership Closings and Escrow

You and the other investors should make your checks for Interests payable to “UMB Bank, N.A., Escrow Agent for ICON O&G Fund-A” and give your check to your broker/dealer for submission to the dealer-manager and escrow agent. Offering proceeds for the partnership will be held in a separate interest bearing escrow account at UMB Bank, N.A., 1010 Grand Blvd, 4th Floor, Kansas City, MO 64106, until the partnership has received offering proceeds of at least $2,000,000, excluding the offering price discounts described in “Plan of Distribution.” Investors (other than Pennsylvania and Tennessee investors who will receive a similar one-time distribution upon their admission) who invest prior to the minimum offering size being achieved will receive, upon admission into the partnership, a one-time distribution of interest for the period their funds were held in escrow. During the partnership’s escrow period, its offering 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 they are paid to the Managing GP for 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 GP determines that the partnership may be deemed to be an investment company under the Investment Company Act of 1940, then the investment activity will cease.

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Pennsylvania and Tennessee Investors: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to the 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. In addition, offering proceeds received by the partnership from Pennsylvania and Tennessee investors will be placed into a short-term escrow (120 days or less) until subscriptions for at least 5% of the maximum offering proceeds have been received by the partnership, which for ICON Oil & Gas Fund-A L.P. means that subscriptions for at least $10,000,000 have been received by the partnership from investors, including Pennsylvania and Tennessee investors. If the appropriate minimum has not been met at the end of the 120-day escrow period, the partnership must notify the Pennsylvania investors in writing by certified mail or any other means whereby a receipt of delivery is obtained within 10 calendar days after the end of the escrow period that they have a right to have their investment returned to them. If an investor requests the return of such funds within 10 calendar days after receipt of notification, the partnership must return such funds within 15 calendar days after receipt of the investor’s request.

On receipt of the minimum offering proceeds and written instructions to the escrow agent from the Managing GP and the dealer-manager, the Managing GP, on behalf of the partnership, will break escrow and transfer the escrowed offering proceeds to the partnership account, which will be a separate account maintained for the partnership, and begin drilling operations for the partnership. The partnership’s funds will not be commingled with the funds of any other entity. If the minimum offering proceeds are not received by the offering termination date of the partnership, then the offering proceeds deposited in the escrow account will be promptly returned to you and the other subscribers in the partnership with interest and without deduction for any fees. Although the Managing GP and its affiliates may buy Interests sold in this offering, currently they do not anticipate purchasing any Interests. If they do buy Interests, then those Interests will not be applied towards the minimum offering proceeds required for the partnership to break escrow and begin operations. Also, any Interests purchased by the Managing GP and its affiliates must be purchased for investment purposes only, and not with a view towards redistribution.

The partnership’s funds may not be invested in the securities of another person, except in the following instances:

investments in working interests or undivided lease interests made in the ordinary course of the partnership’s business;
temporary investments made in income-producing short-term, highly liquid investments, where there is appropriate safety of principal, such as U.S. Treasury Bills;
participations in other partnerships or joint ventures;
investments involving less than 5% of partnership capital that are a necessary and incidental part of a property acquisition transaction; and
investments in entities established solely to limit the partnership’s liabilities associated with the ownership or operation of property or equipment, provided, in such instances, duplicative fees and expenses will be prohibited.

Acceptance of Subscriptions

Your execution of the subscription agreement constitutes your offer to buy Interests in the partnership and to hold the offer open until either:

your subscription is accepted or rejected by the Managing GP; or
you withdraw your offer.

To withdraw your subscription agreement, you must give written notice to the Managing GP before your subscription agreement is accepted by the Managing GP.

Also, the Managing GP will:

not complete a sale of Interests to you until at least five business days after the date you receive a final prospectus; and
send you a confirmation of purchase.

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Subject to the foregoing, your subscription agreement will be accepted or rejected by the partnership within 30 days of its receipt. The Managing GP’s acceptance of your subscription is discretionary, and the Managing GP 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 amount and without deduction for any fees.

When you will be admitted to the partnership depends on whether your subscription is accepted before or after the partnership breaks escrow. If your subscription is accepted:

before breaking escrow, then you will be admitted to the partnership not later than 15 days after the release from escrow of the investors’ offering proceeds to the partnership; or
after breaking escrow, then you will be admitted to the partnership not later than the last day of the calendar month in which your subscription was accepted by the partnership.

Your execution of the subscription agreement and the Managing GP’s acceptance also constitutes your:

execution of the Limited Partnership Agreement and agreement to be bound by its terms as a partner; and
grant of a special power of attorney to the Managing GP to file amended certificates of limited partnership and governmental reports, and perform certain other actions on behalf of the investors as partners of the partnership.

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PRIOR ACTIVITIES

Special Energy Corporation

Pursuant to a Project Proposal Agreement, Special Energy Corporation (“Special Energy”) will propose to the Managing GP for investment consideration and approval certain prospects in the Hunton limestone formation and/or other formations similar in profile, as well as conventional oil and liquids-rich natural gas plays in the Mid-Continent region of the United States. Based upon the prior business relations of members of the Managing GP’s management team and Special Energy, the Managing GP anticipates (but does not guarantee) that some or all of such proposals will result in Participation Agreements between the partnership and Special Energy to drill wells within the proposed project areas. Special Energy is a leading independent oil and gas operating company with over 30 years of experience in the oil and gas exploration and production business and with over 13 years of experience as a pioneer in the development of oil and gas dewatering projects. In 2009, the Oklahoma Corporation Commission ranked Special Energy 33rd among the top 100 gas producers and 52nd among the top oil producers in the State of Oklahoma based on gross production.

Since 1998, Special Energy has been the operator of 20 dewatering projects in which a total of $255,069,385 has been invested and has drilled 206 wells on approximately 269,000 acres under lease. Special Energy’s wells have produced over 85,000,000 Mcf of natural gas and over 4,000,000 BBL of crude oil, which generated total net sales revenue of approximately $487,206,738. During its drilling operations, Special Energy has extracted and disposed of over 347,000,000 BBL of saltwater from these wells. In addition, Special Energy was a 65% owner in New Dominion, LLC (“New Dominion”) from 1998 to 2002. During this time, New Dominion was involved in the preliminary development of the Golden Lane Project, one of the largest dewatering plays in Oklahoma, which covers approximately 15 townships. At the time of Special Energy’s withdrawal from New Dominion, New Dominion had leased over 82,000 acres of land and drilled or re-completed 60 wells.

The table below sets forth the prior performance of the projects for which Special Energy is/was the operator. In each case, Special Energy with its affiliates owns/owned the largest working interest percentage of all working interest owners. As of the date of this prospectus, Special Energy with its affiliates is the operator and largest working interest owner in the Master, Iconium and Stonewall Projects. Special Energy with its affiliates was the operator and largest working interest owner in the Greater Mt. Vernon and NW Oklahoma Projects before divesting its interests in such projects in December 2010 for a total of $145,000,000 in gross proceeds from both projects based upon the working interests divested. The allocation of such proceeds between the two projects is reflected in the table below.

SPECIAL ENERGY’S PRIOR PROJECT PERFORMANCE
(All volumes in this table represent gross production and revenue, net of royalties.)

         
  PROJECTS
     Master   Iconium   Stonewall   Greater Mt. Vernon   NW Oklahoma
Time Period
    1998-2010       1999-2010       2002-2010       2004-2009       2005-2009  
Gross Production
                                            
Natural Gas (Mcf)     36,197,533       12,234,011       7,913,940       20,311,519       8,782,211  
Crude Oil (BBL)     3,441,401       79,103       69,772       564,045       159,290  
Water (BBL)     76,715,910       36,397,159       48,360,460       125,566,647       60,322,645  
Total Net Sales   $ 199,115,791     $ 64,006,968     $ 43,886,316     $ 139,002,008     $ 41,195,655  
LOE   $ 38,295,107     $ 15,081,818     $ 17,237,152     $ 39,699,816     $ 27,176,179  
Operating Cash Flow   $ 160,820,684     $ 48,925,150     $ 26,649,164     $ 99,302,192     $ 14,019,476  
Leasehold   $ 2,065,635     $ 1,159,359     $ 1,283,303     $ 8,939,493     $ 16,195,784  
D&C Costs*   $ 40,086,906     $ 12,883,922     $ 23,510,218     $ 85,667,764     $ 63,277,001  
Gross Investment   $ 42,152,541     $ 14,043,281     $ 24,793,521     $ 94,607,257     $ 79,472,785  
Gross Project Divestiture Proceeds                     $ 92,000,000     $ 53,000,000  
Total Project Cash Flow   $ 118,668,143     $ 34,881,869     $ 1,855,643     $ 96,694,935     $ (12,453,309 ) 

* D&C Costs consist of all of the operator’s costs of drilling and completing a well, including intangible drilling costs.

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MANAGEMENT

Managing GP

The partnership will have no officers, directors or employees. Instead, the Managing GP was formed as a Delaware limited liability company on May 9, 2011 to serve as the managing general partner of the partnership. The Managing GP manages and controls the partnership’s business affairs including, but not limited to, the drilling activity contemplated hereby. The sole member of the Managing GP is ICON Investment Group, LLC. Pursuant to the terms of an administration agreement, the Managing GP has engaged ICON Capital to, among other things, provide it with facilities, investor relations and administrative support. See, “— Transactions with Management and Affiliates,” below, regarding the Managing GP’s dependence on ICON Capital for such support. ICON Capital is headquartered at 3 Park Avenue, 36th Floor, New York, New York 10016, which is also the Managing GP’s principal office.

The following diagram shows the Managing GP’s and certain affiliates’ relationship to the partnerships. The Managing GP and its parent, ICON Investment Group, are affiliates of ICON Capital and ICON Securities under common control.

[GRAPHIC MISSING]

Directors, Executive Officers and Key Personnel of the Managing GP

The directors, executive officers and key personnel of the Managing GP as of the date of this prospectus are as follows:

   
Name   Age   Title
Michael A. Reisner   41   Co-Chief Executive Officer, Co-President and Director
Mark Gatto   39   Co-Chief Executive Officer, Co-President and Director
Joel S. Kress   39   Senior Managing Director
Louis Raniero   40   Managing Director
John Y. Koren   59   Managing Director
John Abney   60   Managing Director, Vice President and Senior Geologist
Paul A. Bryden   60   Vice President and Senior Geologist
Steven R. Hash   59   Vice President and Chief Engineer

Biographical information regarding the above directors, executive officers and key personnel of the Managing GP is set forth below.

Michael A. Reisner, Co-Chairman, Co-Chief Executive Officer and Co-President, joined ICON Capital in 2001. Mr. Reisner was formerly Chief Financial Officer of ICON Capital from January 2007 through April 2008. Mr. Reisner was also formerly Executive Vice President — Acquisitions of ICON Capital from February 2006 through January 2007. Mr. Reisner was Senior Vice President and General Counsel of ICON

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Capital from January 2004 through January 2006. Mr. Reisner was Vice President and Associate General Counsel of ICON Capital from March 2001 until December 2003. Previously, from 1996 to 2001, Mr. Reisner was an attorney with Brodsky Altman & McMahon, LLP in New York, concentrating on commercial transactions. Mr. Reisner received a J.D. from New York Law School and a B.A. from the University of Vermont.

Through his extensive experiences as a senior executive, including his time as chief financial officer of ICON Capital, Mr. Reisner brings business expertise, finance and risk assessment skills to the Managing GP and the partnership. Mr. Reisner’s prior position as a corporate attorney allows him to bring to the Managing GP and the partnership the benefit of his experience negotiating and structuring various investment transactions as well as an understanding of the legal, business, compliance and regulatory issues facing publicly registered limited partnerships.

Mark Gatto, Co-Chairman, Co-Chief Executive Officer and Co-President, joined ICON Capital in 1999 and was previously Executive Vice President and Chief Acquisitions Officer from May 2007 to January 2008. Mr. Gatto was formerly Executive Vice President — Business Development of ICON Capital from February 2006 to May 2007 and Associate General Counsel from November 1999 through October 2000. Before serving as Associate General Counsel, Mr. Gatto was an attorney with Cella & Goldstein in New Jersey, concentrating on commercial transactions and general litigation matters. From November 2000 to June 2003, Mr. Gatto was Director of Player Licensing for the Topps Company and, in July 2003, he co-founded ForSport Enterprises, LLC, a specialty business consulting firm in New York City, and served as its managing partner before re-joining ICON Capital in April 2005. Mr. Gatto received an M.B.A. from the W. Paul Stillman School of Business at Seton Hall University, a J.D. from Seton Hall University School of Law, and a B.S. from Montclair State University.

Through his broad experiences in business and corporate development, Mr. Gatto brings to the Managing GP and the partnership a unique business expertise as well as extensive financial and risk assessment abilities. Mr. Gatto’s service with ICON Capital provides him with a specific understanding of the Managing GP and the partnership, their operations, and the business and regulatory issues facing publicly registered limited partnerships.

Joel S. Kress, Senior Managing Director, joined ICON Capital in August 2005 as Vice President and Associate General Counsel. In February 2006, he was promoted to Senior Vice President and General Counsel of ICON Capital, and in May 2007, he was promoted to Executive Vice President — Business and Legal Affairs. Previously, from September 2001 to July 2005, Mr. Kress was an attorney with Fried, Frank, Harris, Shriver & Jacobson LLP in New York and London, England, concentrating on mergers and acquisitions, corporate finance and financing transactions (including debt and equity issuances) and private equity investments. Mr. Kress received a J.D. from Boston University School of Law and a B.A. from Connecticut College.

Louis Raniero, Managing Director, joined ICON Capital in August 2008. From October 2006 to July 2008, Mr. Raniero was a Partner at Ernst & Young in the Banking and Capital Markets group based in Hong Kong where he was responsible for managing tax services provided to global financial services institutions in the Asia-Pacific region. Before his position in Hong Kong, Mr. Raniero was in Ernst & Young’s Latin American Business Center (based in New York and Sao Paulo) where he specialized in advising U.S. multinational companies on cross-border transactions with Latin America. Prior to that, he was in Ernst & Young’s International Tax Group in New York where he advised U.S. multinational companies on global integrated tax solutions. Mr. Raniero received a J.D. from Seton Hall School of Law and a B.S. in Accounting from Rutgers University. Mr. Raniero is a CPA.

John Y. Koren, Managing Director, serves as a special advisor to ICON on its Advisory Board and is a founder and co-managing partner of Hudson Partners Group, an advisor to alternative investment fund managers, which he co-founded in March 2007. From 2000 to March 2007, Mr. Koren was a Senior Managing Director of Bear, Stearns & Co. and co-head of the firm’s Private Funds Group. From 1991 to 1999, he was a partner in the Bear Stearns Fixed Income Sales Group, where he managed the Corporate Coverage department. He also managed the International group, the Emerging Markets group, and became Worldwide Corporate High Grade Product Manager. Previously, Mr. Koren ran the Corporate Coverage department at Morgan Stanley. Mr. Koren started his career on Wall Street with the Bank of Nova Scotia,

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where he rose to become Assistant Agent of their New York Agency. Following a successful tenure representing the Bank of Nova Scotia’s treasury and corporate services, he joined Singer Co. as Director of International Finance. From there, he went on to become the youngest Assistant Treasurer at Uniroyal Corporation. Mr. Koren holds a B.A. and an M.A. in Economics from Manhattanville College, where he has served as a Trustee. Mr. Koren will be dedicating his time, and the resources of his advisory firm, to the Managing GP on an as-needed basis.

John Abney, Managing Director, Vice President and Senior Geologist, joined the Managing GP in November 2011. Mr. Abney has been involved in all aspects of oil and gas project generation and development for the last 33 years. Prior to joining the Managing GP, Mr. Abney was a Senior Geological Consultant to Tangier Ltd., as well as a consulting geologist to various other oil and gas exploration and production companies, from March 2011 to October 2011 and to Millbrae Energy, LLC from its inception in August 2001 to February 2011. Prior to Millbrae, Mr. Abney worked with Surf Energy, Inc. as an independent petroleum geologist/landman from July 1979 to July 1982 and as a consulting petroleum geologist/landman from July 1985 until August 2001. Mr. Abney was also a landman with Energy Exchange Corporation from July 1983 to May 1985 and a landman with Vulcan Energy Corporation from July 1982 to July 1983. Mr. Abney is a certified Petroleum Geologist (AAPG 5657) by the American Association of Petroleum Geologists and an active member of the Tulsa Geological Society, the Oklahoma City Geological Society and the Society of Independent Professional Earth Scientists. Mr. Abney is also a board certified geologist in the State of Texas. Mr. Abney is also a member of the Oklahoma Well Log Library where he has served as a board member for the past 15 years. Mr. Abney received his B.S. in Geology from the University of Tulsa and a B.A. and M.P.A. from the University of Oklahoma. Mr. Abney will devote 90% of his time to the business and affairs of the Managing GP and 10% of his time to independent projects.

Paul A. Bryden, Vice President and Senior Geologist, joined the Managing GP in November 2011. Mr. Bryden has been working as a prospect generator and development geologist in the Mid-Continent region of the United States for the past 34 years. Since May 2010, Mr. Bryden has worked as an independent consulting petroleum geologist through his companies, Dagwood Energy, Inc. and PKB Royalty, LLC. From May 2006 to April 2010, Mr. Bryden was Chief Geologist for North American Petroleum Corp. USA. Mr. Bryden was previously a consulting petroleum geologist for Altex Energy Corporation from February 2003 to May 2006, where he was instrumental in planning and implementing the first horizontal Hunton well drilled in Oklahoma in 2001. Prior to Altex, Mr. Bryden was a consulting petroleum geologist for New Dominion, LLC from March 1997 to February 2003, where he was involved in the earliest stages of the development of the Hunton dewatering play. Mr. Bryden has been involved with the geological planning and implementation of over 70 horizontal Hunton dewatering wells since 2001 and over 100 vertical Hunton wells since 1997. Mr. Bryden is a Certified Petroleum Geologist (AAPG 4224) by the American Association of Petroleum Geologists and is a member of the Tulsa Geological Society, where he has served as a Councilor, Secretary and as Chairman of various committees. Mr. Bryden is also a past board member of the Petroleum Club of Tulsa and a member of the Oklahoma City Geological Society. Mr. Bryden received his B.S. in Geology from the University of Tulsa. Mr. Bryden will be devoting 90% of his time working for the Managing GP, and the other 10% will be devoted to Dagwood Energy, Inc. and PKB Royalty, LLC.

Steven R. Hash, P.E., Vice President and Chief Engineer, joined the Managing GP in November 2011. Mr. Hash is a Licensed Professional Engineer with expertise in well drilling, completion and production operations as well as property evaluation and acquisitions. Since August 1999, Mr. Hash has worked as an independent consulting engineer through his company, EXACT Engineering, Inc. EXACT is a full service, certified, petroleum engineering and consulting firm headquartered in Tulsa, Oklahoma for which Mr. Hash is President. EXACT has served over 200 client companies providing engineering expertise in both vertical and horizontal well construction and development, completion best practices and artificial lift methods. From October 1998 to July 1999, Mr. Hash was a Drilling and Production Manager for Spring Resources, Inc. Prior to that, Mr. Hash was a Drilling and Production Manager for Toklan Oil and Gas Corporation from March 1993 to September 1998 and a Manager of Operations for Geodyne Resources, Inc. from June 1979 to February 1993 in connection with its publicly registered PaineWebber-Geodyne Energy Income Programs. From March 1975 to May 1979, Mr. Hash worked as a Field Petroleum Engineer in Oklahoma and as Division Drilling Engineer for Texaco, Inc. (now owned by Chevron Corporation). Mr. Hash received his B.S.

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in Civil Engineering from Virginia Tech. He is an active member of the Society of Petroleum Engineers, the American Association of Drilling Engineers and the American Association of Petroleum Geologists. Mr. Hash will be dedicating his time, and the resources of his engineering consulting company, to the Managing GP on an as-needed basis.

Committees

Disclosure Committee

The Managing GP has established a disclosure committee to ensure that all disclosures and forward-looking statements made by the partnership to its investors and/or the investment community are accurate and complete, fairly present the partnership’s financial condition and results of operations in all material respects, and are made on a timely basis, as required by applicable laws and regulations. Messrs. Reisner and Kress currently serve on the Disclosure Committee.

Investment Committee

The Managing GP has established an investment committee that has set, and may from time to time revise, standards and procedures for the review and approval of potential investments and for allocating potential investments among the partnerships within ICON Oil & Gas Fund. The investment committee is responsible for supervising and approving all investments. The investment committee will consist of at least two persons designated by the Managing GP. The Managing GP expects that all such persons will be its officers or officers of its affiliates. The investment committee will make decisions by unanimous vote. As of the date of this prospectus, the members of the investment committee are Messrs. Reisner and Gatto.

Transactions with Management and Affiliates

The partnership’s policies and procedures for reviewing, approving or ratifying related party transactions with the Managing GP are set forth in the Limited Partnership Agreement, and the material terms of those policies and procedures are discussed in greater detail in “Conflicts of Interest.” In this regard, the partnership considers related party transactions to be certain transactions between the partnership and the Managing GP or its affiliates as identified in the Limited Partnership Agreement. Section 4.03(d), “Transactions with the Managing General Partner,” of the Limited Partnership Agreement deals with transactions between the partnership and the Managing GP and its affiliates. Those include the following:

the transfer of leases from the Managing GP to the partnership concerning the amount of acreage that must be transferred in the prospect to the partnership, including the transfer of an equal proportionate interest;
the possible subsequent enlargement of the prospect;
the transfer to the partnership of less than the Managing GP’s and its affiliates’ entire interest in the prospect;
the limitations on sale of undeveloped and developed leases by the partnership to the Managing GP;
the limitations on activities of the Managing GP and its affiliates on leases acquired by the partnership;
the transfer of leases between affiliated drilling partnerships;
the sale of all or substantially all of the partnership’s assets in connection with the termination of the partnership;
the provision of services to the partnership by the Managing GP and its affiliates at competitive rates and as described in this prospectus, the Limited Partnership Agreement or in a separate cancellable contract;
loans from the Managing GP or its affiliates to the partnership and the prohibiton on loans from the partnership to the Managing GP or its affiliates;
farmouts to and from the Managing GP and the partnership;
prohibition on the use of the partnership’s funds as compensating balances on deposit to satisfy the terms of any agreement the Managing GP or any of its affiliates enters into on its own behalf;

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commitments of the partnership’s future production;
sharing in gas marketing arrangements among the Managing GP, the partnership and/or their affiliates;
advance payments from the partnership to the Managing GP for payment to an operator to secure tax benefits for a business purpose set forth in a Participation Agreement;
the prohibition on rebates or give-ups to the Managing GP or its affiliates;
the partnership participating in other partnerships;
roll-up limitations (see “Conflicts of Interest” for a more complete discussion);
the requirement that transactions between the partnership and the Managing GP must be fair and reasonable.

The officers of the Managing GP are responsible for applying the partnership’s policies and procedures set forth in the Limited Partnership Agreement with respect to transactions between the partnership and the Managing GP and its affiliates, just as they are responsible for applying all of the other provisions of the Limited Partnership Agreement.

Managing GP Acting on Behalf of the Partnership

The Managing GP will perform the following functions on behalf of the partnership:

investigating, analyzing and proposing possible investment opportunities;
evaluating and recommending hedging strategies and engaging in hedging activities on the partnership’s behalf, consistent with such strategies;
negotiating agreements on the partnership’s behalf;
causing the partnership to qualify to do business in all applicable jurisdictions and to obtain and maintain all appropriate licenses;
assisting the partnership in complying with all regulatory requirements applicable to it with respect to its business activities, including preparing or causing to be prepared all financial statements required under applicable regulations and contractual undertakings, all required tax filings and all reports and documents, if any, required under the applicable securities laws;
handling and resolving all claims, disputes or controversies (including all litigation, arbitration, settlement or other proceedings or negotiations) in which the partnership or its assets may be involved or to which it or its assets may be subject arising out of its day-to-day operations;
obtaining financing for the partnership’s operations;
performing such other services as may be required from time to time for management and other activities relating to the partnership;
obtaining and maintaining, on the partnership’s behalf, insurance coverage for its business and operations, in each case in the types and minimum limits as the Managing GP determines to be appropriate and as is consistent with standard industry practice; and
using commercially reasonable efforts to cause the partnership to comply with all applicable laws.

The Managing GP and its officers, directors and affiliates have in the past invested, and may in the future invest, in partnerships sponsored by the Managing GP. They may also subscribe for Interests in the partnerships as described in “Plan of Distribution.”

The Managing GP depends on its affiliate, ICON Capital, for all facilities, investor relations and administrative functions. An administration agreement between the Managing GP and ICON Capital provides that ICON Capital will provide the Managing GP with all facilities, investor relations and administrative services necessary or appropriate for the conduct of its business, including providing executive, investor relations and administrative personnel, office space and office services.

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ALTERNATIVE INVESTMENTS

Financial planners generally recommend that investors hold a diversified investment portfolio, including traditional investments, such as stocks, bonds and mutual funds, and alternative investments. The objective of this strategy is to reduce the overall portfolio risk and volatility of an investor’s wealth portfolio while achieving acceptable rates of return.

An investment in an oil and natural gas drilling partnership may be regarded as an alternative investment. The appropriate proportion of an investor’s wealth portfolio that should be held in alternative investments will vary from investor to investor. You should consult your financial advisor regarding asset allocation strategies.

As a wealth management strategy, oil and natural gas drilling partnerships may be appropriate for certain investors for reasons that include:

Portfolio diversification.  An investment in an oil and natural gas drilling partnership may provide diversification between alternative and other forms of investments. It may also provide diversification among your alternative investments.
Cash distributions.  Oil and natural gas drilling partnerships may generate cash distributions.
Tax advantages.  Oil and natural gas drilling partnerships may provide tax benefits for some investors. See “Federal Income Tax Consequences.”
Potential for capital growth.  Oil and natural gas drilling partnerships may offer the potential for the growth of invested capital as the result of reinvesting the production proceeds from earlier wells to compound the return achieved from such earlier wells.
Potential inflation hedge.  The price of oil and natural gas will typically rise in conjunction with higher inflation, which can benefit drilling partnerships that have producing wells in place prior to or at the beginning of inflationary periods.

The partnership expects to exhibit some or all of the characteristics described above. Before considering any investment in the Interests, you should first consult with your financial advisor and read and understand this prospectus, including the section entitled “Risk Factors.” You must also meet the general and State specific suitability standards as set out in this prospectus. See “Suitability Standards.”

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PROPOSED ACTIVITIES

Overview

The partnership has been formed to enable investors to own working interests in oil and liquids-rich natural gas development wells. The partnership expects to utilize its specialized processes, including fluid management techniques, to drill development wells in reservoirs where hydrocarbons are known to be present, located in the Mid-Continent region of the United States, with the potential investment in properties located within other types of projects and/or in other geographic areas that the Managing GP may, from time to time, identify as prospective (the “Projects”). The Projects are presently expected to comprise the partnership’s entire portfolio. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. As of the date of this prospectus, the partnership does not hold any interests in any properties or prospects on which its wells will be drilled. The primary objectives of the partnership are to:

generate revenue from the production and sale of oil and natural gas from the Projects;
distribute cash to its investors; and
provide tax benefits in the year that the offering commences and in future years.

The partnership will participate in drilling one or more wells in some or all of the Projects. In addition, the Managing GP may add to or substitute wells between these Projects or other projects that are believed to have similar economic and risk profiles. The type and number of wells in which the partnership will participate will be determined primarily by (i) the amount of offering proceeds raised by the partnership, (ii) the geographic areas in which wells are to be drilled, (iii) the partnership’s percentage of working interest owned in each well and (iv) and the cost of the wells, including any cost overruns for intangible drilling costs and non-deductible equipment costs of the wells, which are charged to investors under the Limited Partnership Agreement.

The Managing GP reserves the right to acquire projects that have existing oil and gas production and related infrastructure. In such case, this could result in faster cash flow to the investors, but also a reduction in up-front tax deductions. As of the date of this prospectus, no such projects had been identified.

Fluid Management

The partnership’s focus, initially, will be on Projects that offer the opportunity to cost-effectively employ specialized processes in which it has particular expertise, such as the utilization of innovations in fluid management technologies. The partnership intends to participate in the cost-effective development and production of high-water-saturation oil and liquids-rich natural gas reservoirs that have been previously bypassed or abandoned as uneconomic. Through advances in fluid management technology and innovative reinterpretation of petroleum reservoir concepts in existing producing formations, the partnership intends to redevelop previously abandoned reservoirs to cost effectively remove and dispose of water potentially yielding substantially more oil and liquids-rich natural gas than previously produced from these same reservoirs.

Initially, the partnership’s Projects will be primarily targeting the Hunton limestone formation in Oklahoma as well as other formations similar in profile in the Mid-Continent region of the United States. Limestone is a soft, porous rock. It is the pores within rocks in which oil, gas and water are trapped. Rocks bearing oil and gas typically have a porosity (the volume of rock that is void-space) of between 5% and 30%. Reservoirs from which oil and gas are recovered through conventional, or primary, methods typically contain rock formations in which the pore spaces contain a high percentage of oil or gas and a relatively low (or no) percentage of water. When the pore spaces within the reservoir rock contain a relatively high percentage of water, the rock is typically considered non-commercial through conventional means of production. Porous formations, like the Hunton, can be attractive for recovering oil and/or gas through dewatering methods.

New dewatering technology enables very large volumes of water, up to 15,000 barrels per day, to be extracted from individual wells. Because the produced waters are salty, the only approved method of disposal is to re-inject them deep into the earth into saltwater disposal wells. With Hunton dewatering plays, saltwater disposal wells are generally drilled into the Arbuckle formation, which is typically hundreds of feet to a few thousand feet deeper than the producing horizon. The Arbuckle is an ideal formation in which to drill disposal

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wells because of its ability to accept hundreds of thousands of barrels of saltwater per day. Fluid management plays in formations other than the Hunton will utilize similar saltwater disposal techniques as those used in the Arbuckle or other similar formations.

The greatest difficulty in achieving economic production in high-water-saturation reservoirs is that water flows through the reservoir much easier than oil and gas. Consequently, initial production in a fluid management play may contain over 99% water with little to no oil and/or gas. Because the hydrocarbons move through the rocks at different rates and because each maintains pressure on the other hydrocarbons as well as the overall formation, there becomes a balancing act of keeping enough pressure within the well to produce the hydrocarbons at the optimum rate. Generally, oil production is very limited initially, but can rise rapidly after several months, eventually reaching a plateau before beginning a gradual decline. Gas is more unpredictable, but generally follows a similar, if less pronounced, pattern as the oil production. A standard production pattern from a hypothetical dewatering well is shown below.

Typical Dewatering Well Production

[GRAPHIC MISSING]

At reservoir depth, there is tremendous heat and pressure creating an environment that locks the oil, gas and water in the rocks. Once the well bore is drilled into that formation, a void is created that relieves the pressure. Oil, gas and water start migrating out of the pores in the rock with gas being able to move more easily through the rock than water, which in turn moves more easily through the rock than oil. If the well is left to run with no controls, the water and gas will be produced too rapidly, which will then relieve the pressure required to simulate the oil flow from the formation. Uncontrolled, the reservoir will not be produced efficiently nor to its maximum capacity. Maximum hydrocarbon production typically occurs when reservoir pressure is reduced to approximately 50% of the original bottomhole pressure. At this point, the high-powered pumps that had been used to pump large volumes of water at a rapid rate are converted to smaller submersible or beam pumps and the reservoir behaves more conventionally.

The amount of time required to adequately dewater a reservoir in order to produce large amounts of oil and gas can vary tremendously from well to well, and some wells may never reach high levels of oil and gas production due to poor reservoir quality (e.g., tight formation rock) or low hydrocarbon saturation. At some point, a decision will be made to rehabilitate or abandon the well. If there are more hydrocarbons to be

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recovered, several different methods may be used to re-stimulate the well’s production or, alternatively, additional lateral legs could be drilled out of the vertical section of the well bore to increase the amount of the reservoir that the well can drain. Regardless of what enhancement techniques are employed, eventually, production from the well will become economically unfeasible and the well will be plugged and abandoned.

Typical Project Process

Working Interest Percentage Ownership

The partnership will own a working interest percentage in each Project, in each case, pursuant to a participation agreement with the relevant operator for such Project, attached to which will be a related operating agreement governing the rights and obligations of the partnership and the related operator with respect to drilling operations (the participation agreement together with the related operating agreement, the “Participation Agreement”). Each Participation Agreement will, among other things, specify the leasehold interests acquired for that Project and create an area of mutual interest (“AMI”) containing those leaseholds. The AMI will define the boundaries of the geographic area in which the partnership will drill for each Project. The AMI for each Project will be of sufficient size to allow for efficient extraction of the subject hydrocarbons, including, in some instances, through the use of fluid management techniques. Within the AMI for a fluid management play, wells will be drilled horizontally on one square mile spacing units, many of which share surface infrastructure (drilling pads, separation facilities and tank batteries).

The Managing GP anticipates that, with respect to each Project, the related operator will own the largest working interest percentage amongst the working interest owners. Unaffiliated third parties may also own working interest percentages in the Projects. Any third party working interest owner will have a separate Participation Agreement with the operator for drilling and operating the wells. Such agreements may contain different terms and conditions from those contained in the partnership’s corresponding Participation Agreements; though, the partnership intends to include in each of its Participation Agreements a most-favored-nation-type clause with respect to material provisions such that no non-operator working interest owner will participate in a Project on any terms more favorable than those contained in the applicable Participation Agreement. For the wells subject to each Participation Agreement, the partnership will pay a proportionate share of total lease, development, and operating costs, and will receive a proportionate share of production subject only to royalties, overriding royalties and similar burdens.

The actual number, identity and percentage of working interests or other interests in Projects will depend on, among other things:

the amount of offering proceeds received by the partnership;
the latest geological and production data;
potential title or spacing problems;
availability and price of drilling services, tubular goods and services;
approvals by federal and state departments or agencies;
agreements with other working interest owners in the Projects;
farmins and farmouts; and
continuing review of other prospects that may be available.

Working interest revenue and production expenses for each Project are allocated to working interest owners based on their percentage interest in such Project. Each working interest owner, including the partnership, will pay or deliver, or cause to be paid or delivered, royalties or other burdens on its share of the production from the Projects. Generally, production revenues from a well drilled by the partnership will be net of the applicable landowner’s royalty interest, which is typically 1/8th (12.5%) to 1/5th (20.0%) 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

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is obtained, and overriding royalty interest generally means an interest that is created in favor of someone other than the landowner; provided, however, that the Managing GP and its affiliates will not receive any such overriding royalty interests on the leasehold interests acquired by the partnership. In either case, the owner of the interest receives a specific percentage of the natural gas and oil production free and clear of all costs of development, operation or maintenance of the well. This is compared with a working interest, which generally means an interest in the lease under which the owner of the interest must pay some portion of the cost of development, operation or maintenance of the well. Also, the leases may be subject to additional terms that favor the landowner-lessor, such as free gas to the landowner-lessor for home heating requirements. The partnership will also pay for its share of expenses for each Project upon receipt of a written statement from the related operator. Each operator will provide this written estimate of current and cumulative costs at reasonable intervals during the conduct of operations on the related Project(s).

The Participation Agreement generally provides that the operator will conduct and direct, and have full control of, all operations on the related Project. The operator generally has no liability to the partnership for losses sustained or liabilities incurred, except as may result from the operator’s gross negligence or willful misconduct with respect to the related Project. Under each Participation Agreement, each of the operator and the partnership will be responsible only for its own working interest percentage of costs of developing and operating on the Project. However, non-operating working interest owners’ participation agreements, including each Participation Agreement, may often provide that the operator can require each non-operator to pay a pro rata share of a defaulting non-operator’s unpaid share of costs. The operator may subcontract responsibilities as operator for wells subject to the Participation Agreement. The operator will retain responsibility for work performed by subcontractors. Where the duties of the operator are subcontracted to an independent third party, the cost of the services performed by such subcontractor will be charged as operating costs.

The operator’s duties include, without limitation, testing formations during drilling and completing the wells by installing surface and well equipment, gathering pipelines, heaters and separators, as are necessary and normal in the area in which the Project is located. The partnership will pay the portion of the drilling and completion costs of the operator as incurred, except that the partnership may prepay its share of certain of the drilling and completion costs of its wells to the operator. If one or more of the 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 Participation Agreement. The Managing GP expects that the operator will begin drilling all of the partnership’s wells no later than the 90th day of the next year following any such prepayments. See “Federal Income Tax Consequences — Drilling Contracts.”. In order to comply with conditions to secure the tax benefits of prepaid drilling costs, the operator, as required under the terms of the Participation Agreements, will not refund any portion of amounts paid in the event actual costs are less than amounts paid, but will apply any amounts solely for payment of additional drilling services to the partnership. If the operator determines that a well is not likely to produce oil and/or gas in commercial quantities, the operator will plug and abandon the well in accordance with applicable regulations. However, in such case, any of the working interest owners, including the partnership, would typically have the right to take over operations in the event they disagreed with the operator’s decision.

The partnership will bear its proportionate share of drilling and completing or drilling and abandoning wells under the terms of the applicable agreements. The partnership will also be subject to industry standard provisions in the Participation Agreements in the event that it does not consent to participate in certain operations, including the drilling of new wells on a Project.

The operator will provide all necessary labor, vehicles, supervision, management, accounting and overhead services for normal production operations, and will deduct from the revenues of all working interest owners, including the partnership, a monthly charge based on competitive industry rates for each producing well for operations and field supervision and a monthly charge per well for accounting, engineering, management, and general and administrative expenses. Non-routine operations will be billed to the working interest owners at their cost, in their pro rata portion. In designating the operator of each Project as its agent to participate in marketing its production, the partnership is authorizing the operator to enter into and bind the partnership in those agreements as it deems in the best interest of the partnership for the sale of its oil and/or gas. See “Proposed Activities — Production Phase.”

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The Participation Agreements will continue in force so long as any of the oil and gas leases subject to the Participation Agreement remain or are continued in force as to the Projects, whether by production, extension, renewal or otherwise.

Prospect Identification, Lease Acquisition and Infrastructure Building

The Managing GP’s highly experienced management team is constantly evaluating opportunities for Projects, including prospects in the market as well as internally generated ideas. The Managing GP’s technical team includes geology and engineering experts who collectively source and identify prospects, evaluate each potential Project and present recommendations to the Managing GP’s investment committee. Once a prospect has been identified and a Project approved, the Managing GP or operator, as applicable, will lease the mineral rights, acquire necessary rights-of-way, and initiate the regulatory procedures that are necessary to drill in the selected sites. If the leases are acquired by the operator, interests in such leases will be assigned to the partnership. Leases may also be acquired directly by the partnership and contributed to the program. The Managing GP may not obtain title to the properties in which the operator(s) will drill. In cases where the operator will hold title to such properties, the partnership will receive only its assigned interest. In such cases, the partnership will endeavor to record such interest. It is not the practice in the oil and natural gas industry to warrant title or obtain title insurance on leases and the Managing GP will provide neither for the leases assigned to the partnership. The Managing GP will take such steps as it deems necessary to assure that title to leases is acceptable for purposes of the partnership. The Managing GP is free, however, to use its judgment in waiving title requirements and will not be liable for any failure of title to leases or other rights assigned to the partnership. As of the date of this prospectus, the Managing GP does not have any rights in an existing inventory of leases. The Managing GP presently intends to obtain assignments of rights in the leaseholds of the operators with whom it will partner for its initial projects.

The leases and other rights assigned to the partnership may include all stratigraphic horizons, or, conversely, may only include rights that are limited to a depth from the surface to the deepest depth of the relevant formation. In the event the Managing GP directly acquires and contributes leases, the amount of the credit the Managing GP receives for such leases will depend on any value allocable to the depth of the drilling rights associated with them. The Managing GP will not receive any royalty or overriding royalty interest on any well.

Once lease rights are acquired and the AMI identified and agreed to in the Participation Agreement, the operator will begin to build the required infrastructure on several selected drilling locations. For example, for a fluid management play, flow lines will be laid, three-phase electrical power, separation systems, and a tank battery will be installed, and a saltwater disposal well will be drilled so that water taken from the reservoir can be pumped back into the ground. Since submersible pumps are utilized to accelerate the reserve recovery, large amounts of three phase power is required for a fluid management play. The operator will typically contract with the local electrical co-op to build sub stations with 5 to 10 megawatt capacity per station. A primary meter will be installed and a private, closed electrical infrastructure will be built.

Drilling and Completion Phase

The operator for each Project will be responsible for drilling the wells on such Project. Generally, once the infrastructure is in place, the operator will drill pilot wells within the AMI. The results from these initial evaluation wells will determine whether or not the operator proceeds to drill additional wells on the Project. All wells will be drilled to a sufficient depth to test thoroughly the objective geological formation unless the working interest owners determine that the well should be completed in a formation uphole from the objective geological formation. The operator may substitute a new well in lieu of any one of the wells, or change the well bore configuration of one or more of the wells, depending on production results obtained during the course of development. This may result in a lower or higher drilling costs than initially estimated. After drilling, the operator will complete each well deemed by it to be capable of production of oil or gas in commercial quantities.

More specifically, during drilling operations, the operator’s duties will include:

making the necessary arrangements for drilling and completing wells and related facilities, such as:

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º determining the exact location where the well bore will be drilled after reviewing geologic information it has compiled;
º selecting the provider of the drilling rig; and
º determining whether to use a pull down drilling rig or a conventional rotary drilling rig;
managing and conducting all field operations in connection with drilling, testing, and equipping the wells, which includes receiving and paying invoices from the subcontractors, reviewing the invoices to confirm that the costs are reasonable, and monitoring compliance by the subcontractor with its contract; and
making the technical decisions required in drilling and completing the wells, such as:
º determining how much casing should be placed in the well, which determination depends primarily on the depth of the well;
º designing the fracturing program, if any, for the well;
º designing the cementing program for the well, including a plan to contain any water that may be encountered in the well bore, such as cementing certain formations in the well; and
º designing the completion program for the well, which includes reviewing and analyzing the wells’ logs, and determining which formations to perforate, and how and where to shoot holes in the formation and, in the case of natural gas wells, generally means treating separately all potentially productive geological formations in an attempt to enhance the natural gas production from the well.

Since the partnership is not acting as operator, the Managing GP will supervise the performance and activities of the operator of each Project, but, with few exceptions, will not have a controlling vote concerning operations on a Project. The Managing GP will represent the partnership with regard to selection of Projects and well locations on those Projects, and will monitor drilling and completion operations, including participation in meetings with the operator and other working interest owners before the wells are drilled, and will typically have its expert consultants on site from time to time during the drilling and completion of a well.

With respect to each Project, additional drilling beyond the initial evaluation wells is contemplated, subject to the success of the initial wells drilled on such Project. If the operator proceeds to drill additional wells, the Managing GP will evaluate each such opportunity and make a determination in its sole discretion as to whether or not the partnership should attempt to participate in such additional drilling on each Project. The partnership will pay its proportionate share, based on its working interest percentage, of the expenses associated with additional drilling. In the event that the partnership does not have sufficient working capital reserves to meet these expenses, the partnership may reinvest cash flow from existing production to fund this additional drilling. The Managing GP may reinvest cash flow from production for: (i) additional wells, whether on Projects or substitute projects, for the purpose of paying the partnership’s share of its working interest; (ii) additional drilling and completion costs on existing wells in excess of funds budgeted; (iii) other costs, such as infrastructure costs and land acquisition costs for the purpose of paying the partnership’s share of such costs; and (iv) partnership expenses, when there is a shortfall of current partnership revenue to cover such expenses, which would reduce or eliminate cash distributions to the investors. While it is the intention of the Managing GP to distribute cash flow from production, in order to protect the partnership’s economic interests in the Projects, it retains the right, in its sole discretion, to exercise this option.

Production Phase

Under the Participation Agreement, the operator will complete each well if there is a reasonable probability of obtaining commercial quantities of natural gas or oil from such well. However, based on its expertise with respect to fluid management projects, the Managing GP anticipates that most of the development wells drilled by the partnerships will have to be completed before the operator can predict the well’s productivity. If the Managing GP and the operator determine that a well should not be completed, then the well will be plugged and abandoned.

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During producing operations, the operator’s duties will include:

managing and conducting all field operations in connection with operating and producing the wells;
making the technical decisions required in operating the wells; and
maintaining the wells, equipment and facilities in good working order during their useful life.

The Managing GP will supervise the production operations and will be reimbursed for its direct expenses. See “Compensation.”

Once a well is completed (i.e., all surface equipment necessary to control the flow of hydrocarbons and produce the well has been installed), and necessary facilities, including the gathering pipeline, have been installed, the production phase will commence. Typically, the operator of a Project will not complete contracts for sale of oil or natural gas on behalf of the partnership until after drilling of the wells.

Sale of Oil and Natural Gas Production

Each operator will be responsible for selling all or a portion of the oil and natural gas produced from the Projects that it operates on a competitive basis at the best available terms and prices. The prices that an operator will be able to negotiate will be based upon a number of factors, including, among other things, the quality of the oil and gas produced, well pressure, estimated reserves, prevailing supply conditions and any applicable price regulations promulgated by the Federal Energy Regulatory Commission (“FERC”).

Natural Gas — Each operator will be responsible for gathering and transporting all or a portion of the natural gas produced from wells in which the partnership participates. Such gas will be sold to gas marketers, interstate and/or intrastate pipeline systems, local distribution companies, local utilities and/or end-users in the area, in each case, under market sensitive contracts in which the price of natural gas sold will vary as a result of market forces. Seasonal factors, such as weather, may impact the sales volumes and prices. Prior to sale, the natural gas will be transported through a gathering system, either operated by the relevant operator or a third-party gas gatherer. In either case, the operator will receive a competitive gathering fee for such gathering services, which fee will be paid by the operator to the third-party gathering system if the operator uses such a third-party system. In addition, the Managing GP may participate in the marketing of the natural gas produced from its wells. In such case, the Managing GP will receive gas marketing fees, at competitive rates, but not based on arm’s-length negotiations, for its services, in marketing the natural gas production. See “Conflicts of Interest — Conflicts Regarding Transactions with the Managing GP and its Affiliates.”

The pricing and delivery arrangements with all of the natural gas purchasers described above are tied to the settlement of the New York Mercantile Exchange (“NYMEX”) monthly futures contracts price, with an additional premium, which is referred to as the basis, paid because of the location of the natural gas in relation to the natural gas market.

Crude Oil — Crude oil produced from the partnership’s wells will flow directly into storage tanks where it will be picked up by oil companies, common carriers or pipeline companies acting for oil companies that are purchasing the crude oil. The operator will sell any oil produced by the wells in which the partnership participates at the prevailing spot market price for West Texas Intermediate crude oil in spot sales.

During the term of the partnership, it is anticipated that the prices of oil and natural gas, respectively, will remain uncertain and volatile.

The partnership’s share of production revenue from a given well will be burdened by and/or subject to royalties and overriding royalties, monthly operating charges, taxes and other operating costs. These items of expenditure involve amounts payable solely out of, or expenses incurred solely by reason of, production operations other than minimal maintenance and administrative expenses. The partnership’s main source of revenues to pay expenses will be from production operations.

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Hedging

Pricing for natural gas and oil has been volatile and uncertain for many years. To limit the partnership’s exposure to decreases in prices, the partnership may enter into financial hedges through contracts such as regulated NYMEX futures and options contracts and over-the-counter swap contracts with qualified counterparties. If financial hedges are instituted, the percentages of oil and/or natural gas production that are hedged through financial hedges may change from time to time in the discretion of the Managing GP, but in no event will the Managing GP hedge more than the amounts of oil and/or natural gas actually produced from its wells. Although hedging provides the partnership some protection against falling prices, these activities also could reduce the potential benefits of price increases and the partnership could incur liability on the financial hedges. For example, the partnership would be exposed to the risk of a financial loss if the counterparties to the hedging contracts fail to perform under the contracts, or there is a sudden, unexpected event materially impacting prices.

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COMPETITION, MARKETS AND REGULATION

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.

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 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 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 that served as wholesalers and 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 that 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 further 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 also has required pipeline companies to develop electronic bulletin boards to provide standardized access to information concerning capacity and prices.

Competition and Markets

The oil and natural gas industry is highly competitive in all phases, and many companies engage in oil and natural gas drilling operations in Oklahoma, where some of the partnership’s wells are expected to be located. In this regard, the partnership will operate in a highly competitive environment for acquiring leases, contracting for drilling equipment, securing trained personnel and marketing oil and natural gas production from its wells. Product availability and price are the principal means of competing in selling oil and natural gas. Many of the partnership’s competitors will have financial resources and staffs larger than those available to the partnership. This may enable them to identify and acquire desirable leases and market their oil and natural gas production more effectively than the Managing GP and the partnership. While it is impossible to accurately determine the partnership’s industry position, the Managing GP does not consider that the partnership’s intended operations will be significant in the overall oil and natural gas industry.

The oil and natural gas industry has from time to time experienced periods of rapid cost increases. The increase in oil and natural gas prices over the last several years also has increased the demand for drilling rigs and other related equipment and the costs of drilling and completing oil and natural gas wells. Additionally, the oil and natural gas industry has experienced an increase in the past few years in the cost of tubular steel used in drilling wells. Also, the reduced availability of drilling rigs and other related equipment may make it more difficult to drill the partnership’s wells in a timely manner or to comply with the prepaid intangible drilling costs rules. See “Federal Income Tax Consequences — Drilling Contracts.” Further, over the term of the partnership there may be fluctuating or increasing costs in doing business that directly affect the operators’ ability to operate the partnership’s wells at acceptable price levels.

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The oil and natural gas produced by the partnership’s wells must be marketed in order for you to receive your portion of production revenues. As set forth above, oil and natural gas prices are not regulated, but instead are subject to factors that are generally beyond the partnership’s and the Managing GP’s control, such as the supply and demand for oil and natural gas. 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 oil and natural gas production, which are also beyond the control of the Managing GP and the partnership and cannot be accurately predicted, are the following:

the cost, proximity, availability, and capacity of pipelines and other transportation facilities;
the price and availability of other energy sources, such as coal, nuclear energy, solar and wind;
the price and availability of alternative fuels, including when large consumers of natural gas are able to convert to alternative fuel use systems;
changes in federal income tax laws affecting the oil and natural gas industry;
local, state, and federal regulations regarding production, conservation, and transportation;
overall domestic and global economic conditions;
the impact of the U.S. dollar exchange rates on oil and natural gas prices;
technological advances affecting energy consumption;
domestic and foreign governmental relations, regulations and taxation;
the impact of energy conservation efforts;
the general level of supply and market demand for oil and natural gas on a regional, national and worldwide basis;
weather conditions and fluctuating seasonal supply and demand for oil and natural gas because of various factors such as home heating requirements in the winter months, although seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation, and certain natural gas users with natural gas storage facilities purchase a portion of the natural gas they anticipate they will need for the winter during the summer, which also can lessen seasonal demand fluctuations;
economic and political instability, including war or terrorist acts in oil and natural gas producing countries, including those of the Middle East, Africa and South America;
the amount of domestic production of oil and natural gas; and
the amount and price of imports of oil and natural gas from foreign sources, including liquid natural gas from Canada and other countries, 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 eliminated trade and investment barriers in the United States, Canada, and Mexico. From time to time since then, there have been increased imports of Canadian natural gas into the United States. 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 partnership’s wells. The Managing GP is unable to predict what effect the various factors set forth above will have on the future price of the oil and natural gas sold from the partnership’s wells.

Notwithstanding, the Managing GP believes that there have been several developments that may increase the demand for natural gas, but may or may not be offset by the current low price for natural gas and increase the supply of natural gas, which the Managing GP is unable to predict. For example, the Clean Air Act Amendments of 1990 contain incentives for the future development of “clean alternative fuel,” which includes natural gas and liquefied petroleum gas for “clean-fuel vehicles.” Also, the accelerating deregulation of electricity transmission has caused a convergence between the natural gas and electric industries.

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According to U.S Energy Information Administration (“EIA”) projections, non-OPEC crude oil and liquid fuels production will grow by 500,000 barrels per day in 2011 and 770,000 barrels per day in 2012 to an average of 53,100,000 barrels per day. The largest sources of expected growth in non-OPEC oil production over the period are Brazil, Canada, China, Columbia and the United States. Additionally, the EIA projects that the majority of growth in natural gas production through 2011 is centered in onshore production in the contiguous United States. According to the EIA’s Short-Term Energy Outlook (September 7, 2011 Release), growing domestic natural gas production has reduced reliance on natural gas imports and contributed to increased exports.

State Regulations

Oil and natural gas operations are regulated in Oklahoma by the Oklahoma Corporation Commission. Any other states in which the partnership’s wells may be situated will likely also impose a comprehensive statutory and regulatory scheme for oil and natural gas 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 state regulations (in Oklahoma and elsewhere) involve:

new well permit and well registration requirements, procedures, and fees;
landowner notification requirements;
certain bonding or other security measures;
minimum well spacing requirements;
restrictions on well locations and underground gas storage;
certain well site restoration, groundwater protection, and safety measures;
discharge permits for drilling operations;
various reporting requirements; and
well plugging standards and procedures.

These state regulatory agencies also have broad regulatory and enforcement powers, including those associated with pollution and environmental control laws, which are discussed below.

Environmental Regulation

The partnership’s drilling and producing operations will be 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 U.S. Environmental Protection Agency and state and local agencies will require the partnership to obtain permits and take other measures with respect to:

the discharge of pollutants into navigable waters;
disposal of wastewater; and
air pollutant emissions.

If these requirements or permits are violated there can be substantial civil and criminal penalties that will increase if there was willful negligence or misconduct. In addition, the partnership 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 partnership’s drilling activities or its wells and its production activities.

The partnership and its Investor General Partners may incur environmental costs and liabilities due to the nature of the partnership’s business and substances from the partnership’s wells. See “Risk Factors —  Environmental hazards involved in drilling oil and natural gas wells may result in substantial liabilities for the partnership.” For example, an accidental release from one of the partnership’s wells could subject the partnership to substantial liabilities arising from environmental cleanup and restoration costs, claims made by

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neighboring landowners and other third-parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted in the future which could significantly increase the partnership’s compliance costs and the cost of any remediation that may become necessary.

Also, the partnership’s liability can extend to pollution costs that occurred on the leases before they were acquired by the partnership. Although the Managing GP will not transfer any lease to the partnership if it has actual knowledge that there is an existing potential environmental liability on the lease, there will not be an independent environmental audit of the leases before they are transferred to the partnership. Thus, there is a risk that the leases will have potential environmental liability even before drilling begins.

The 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 GP is unable to predict the ultimate costs of complying with present and future environmental laws and regulations. Also, the Managing GP is unable to obtain insurance to protect against many environmental claims, including remediation costs.

Proposed Regulation

From time to time there are a number of proposals considered in Congress and in the legislatures and agencies of various states that, if enacted, would significantly and adversely affect the oil and natural gas industry and the partnership’s drilling operations. The proposals typically involve, among other things:

limiting the disposal of waste water from wells or the emission of greenhouse gases, which could substantially increase the partnership’s operating costs and make the partnership’s wells uneconomical to produce;
imposing federal and state laws and regulations on hydraulic fracturing of wells;
changes in the federal income tax benefits for drilling oil and natural gas wells as discussed in “Federal Income Tax Consequences”;
tax credits and other incentives for the creation or expansion of alternative energy sources to oil and natural gas; and
establishing a cap and trade system for carbon emission.

Also, Congress could re-enact price controls or additional taxes on oil and natural gas in the future. However, it is impossible to accurately predict what proposals, if any, will be enacted and their subsequent effect on the partnership’s activities. However, it appears to the Managing GP that the trend is toward increased federal and state regulation of oil and natural gas drilling and production activities, particularly with respect to hydraulic fracturing of wells and emissions of greenhouse gases, which includes the methane component of natural gas, and carbon dioxide, which results when natural gas is burned. More stringent federal or state regulations could increase the partnership’s compliance costs or result in possible restrictions on the partnership’s operations.

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PARTICIPATION IN COSTS AND REVENUES

The Limited Partnership Agreement provides for the sharing of partnership costs and revenues among the Managing GP and the investors. Investors’ investment return will depend solely on the operations and success or lack of success of the partnership. The discussion below assumes that the Managing GP (i) makes a capital contribution equal to 1% of the total investor capital contributions (net of O&O Costs and the management fee) in the form of payment for a portion of program costs and (ii) does not purchase any Interests.

Costs

1.  Intangible Drilling Costs.  The net offering proceeds will be used to pay 99% of the intangible drilling costs incurred by the partnership in drilling and completing its wells, so as to provide investors with the maximum available tax deductions for intangible drilling costs.

Intangible drilling costs, generally, mean 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. For example, intangible drilling costs include 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 oil or natural gas. Intangible drilling costs also include the expense of plugging and abandoning any well before a completion attempt, and the costs (other than non-deductible equipment costs and lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.

Although offering proceeds of the partnership may be used to pay the costs of drilling different wells depending on when the subscriptions are received, the offering proceeds of investors will be used to pay intangible drilling costs regardless of when they subscribe.

2.  Non-deductible equipment costs.  The net offering proceeds will be used to pay up to 99% of the non-deductible equipment costs incurred by the partnership in drilling and completing its wells. Such non-deductible equipment costs are the costs of drilling and completing a well that are not currently deductible and are not lease costs. All such non-deductible equipment costs that exceed the available net offering proceeds will be charged to the working interest owners in the related Project based on each such working interest owner’s working interest ownership percentage. If the Managing GP makes a capital contribution in the form of a payment for any such non-deductible equipment costs, the Managing GP will receive an additional share of the partnership’s revenues in the same percentage as its capital contribution bears to the total capital contributions to the partnership.

The allocation of the partnership’s costs of drilling and completing each well between intangible drilling costs and non-deductible equipment costs will be set forth in the Authority for Expenditure (“AFE”) for each well, which will be agreed upon by the Managing GP and the related operator and attached to the related Participation Agreement as an exhibit before each such well is drilled. However, an AFE is not binding on the IRS should it challenge the partnership’s inclusion of certain costs as IDCs.

The AFE for each well will cover all ordinary deductible and non-deductible costs that may be incurred in drilling and completing (or plugging) each well. Such costs include, without limitation, the costs for site preparation, permits and bonds, roadways, surface damages, power at the site, water, operator’s compensation, 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 each gas well, and geological, geophysical and engineering services.

3.  O&O Costs.  The gross offering proceeds will be used to pay up to 99% of the O&O Costs. All O&O Costs that exceed the available offering proceeds will be charged to the Managing GP. If the Managing GP makes a capital contribution in the form of a payment for any O&O Costs, the Managing GP will receive an additional share of the partnership’s revenues in the same percentage as its capital contribution bears to the total net capital contributions to the partnership.

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O&O Costs include (i) the dealer-manager fee, (ii) sales commissions and (iii) other costs related to the organization of the partnership and the offering of the Interests.

4.  Lease Costs.  A portion of the leases covering the acreage on which the partnership’s wells will be drilled may be contributed to the partnership by the Managing GP. If the Managing GP contributes any such leases, the Managing GP’s capital account will be credited with a capital contribution for each contributed lease valued at either its cost or fair market value if the Managing GP has reason to believe that cost is materially more than fair market value. The Managing GP is not obligated to directly acquire and contribute any leases. All of the leases covering the acreage on which the partnership’s well will be drilled may be acquired by the relevant operator. In such case, such operator will likely hold title to the leases and an interest in such leases will be assigned to the partnership.

5.  Administrative Costs, Direct Costs and All Other Costs.  The net offering proceeds will be used to pay the percentage of the administrative costs, direct costs and all other costs of the partnership that equals the investors’ share of the production revenue for that year, which share may vary from year to year under the Limited Partnership Agreement. The Managing GP will receive from the partnership a fully accountable reimbursement for its administrative costs, as well as a fully accountable reimbursement for its direct costs. The partnership’s administrative costs reimbursements will be capped at the lesser of the actual administrative costs incurred by the Managing GP and the following: (i) in the partnership’s first full year of operations, 1.25% of the partnership’s gross offering proceeds; (ii) in the partnership’s second full year of operations, 1% of the partnership’s gross offering proceeds; (iii) in the partnership’s third full year of operations, 0.75% of the partnership’s gross offering proceeds; and (iv) in the partnership’s fourth full year of operations and thereafter, 0.5% the partnership’s gross offering proceeds. In each case, the above caps are calculated based on gross offering proceeds assuming all 20,000 Interests are sold in this offering. Direct costs are third-party service provider costs incurred by the partnership, including, among other things, legal fees, accounting fees for audit and tax preparation, and independent engineering analyses and reports. Direct costs will be billed directly to and paid by the partnership to the extent practicable. If the Managing GP pays for any direct costs on behalf of the partnership, the Managing GP will receive from the partnership reimbursement for such payments.

Other costs paid by the partnership include the partnership’s portion of the costs of plugging and abandoning a well once it becomes uneconomic to produce. Typically, the working interest owners will share in the proceeds of the salvage value of the equipment for plugged and abandoned wells. The Managing GP will apply the partnership’s portion of such salvage value towards the partnership’s obligation to pay for the costs of plugging and abandoning the well. To cover any shortfall that the partnership might incur between its share of the salvage value of the equipment in a well and its share of the plugging and abandoning costs of the well, the Managing GP has the right, with respect to each of the partnership’s wells, beginning one year after each such well begins producing, to retain up to $200 per month of the partnership’s share of the production revenues in partnership reserves to cover future plugging and abandonment costs of each such well. This $200 also includes the Managing GP’s share of revenues, which will be used exclusively for the Managing GP’s share of the plugging and abandonment costs of the well. To the extent any portion of those reserves ultimately is not required for the plugging and abandonment costs of the well, then it will be returned to the general operating revenues of the partnership.

Revenues

1.  Production Revenues.  The Managing GP and the investors in the partnership will share in all of the partnership’s production revenues in the same percentage as their respective capital contribution bears to the partnership’s total net capital contributions, except that the Managing GP will receive an additional 10% of the production revenues. If the Managing GP makes a capital contribution equal to 1% of the total investor capital contributions (net of O&O Costs and the management fee), which is the Managing GP’s minimum required capital contribution, the Managing GP will receive 11% of production revenues.

2.  Proceeds from the Sale of Wells/Leases.  If a well is sold, the portion of the sales proceeds allocated to the partnership will be allocated among the Managing GP and the investors in accordance with the sharing ratio utilized for the allocation of production revenues, as described above.

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3.  Equipment Proceeds.  Proceeds from the sale or other disposition of equipment used to drill and complete the partnership’s wells will be credited to the Managing GP and the investors in accordance with the sharing ratio utilized for the allocation of production revenues, as described above.

4.  Interest Proceeds.  Interest income earned on offering proceeds until they are released to the Managing GP for use in the drilling activities of the partnership will be credited to each investor’s capital account and paid not later than the partnership’s first cash distribution from operations. Until the partnership’s offering proceeds are invested in such partnership’s operations, any interest income from temporary investments will be allocated pro rata to the investors providing the offering proceeds. All other interest income, including interest earned on the deposit of production revenues, will be credited as provided in “Participation in Costs and Revenues — Revenues — Production Revenues” above.

Table of Participation in Costs and Revenues

The following table sets forth certain partnership costs (in excess of cumulative revenues) and revenues (in excess of cumulative costs) charged and credited between the Managing GP and investors in the partnership, after deducting from the partnership’s gross revenues the landowner royalties and any other lease burdens. The following table assumes that the Managing GP (i) makes a capital contribution equal to 1% of the total investor capital contributions (net of O&O Costs and the management fee) in the form of payment of a portion of program costs and (ii) does not purchase any Interests.

   
  Managing GP   Investors
Partnership Costs
                 
Intangible drilling costs(1)     1 %      99 % 
Non-deductible equipment costs(2)     1 %      99 % 
O&O Costs     1 %      99 % 
Lease costs(3)     1 %      99 % 
Administrative costs, direct costs, and all other costs(4)     11 %      89 % 
Partnership Revenues
                 
Production revenues(5)     11 %      89 % 
Proceeds from the sale of wells/leases     11 %      89 % 
Equipment proceeds     11 %      89 % 
Interest proceeds(6)     11 %      89 % 
Participation in Deductions
                 
Intangible drilling costs     1 %      99 % 
Depreciation     1 %      99 % 
Depletion allowance     (7)       (7)  

(1) The net offering proceeds of investors in the partnership will be used to pay 99% of the intangible drilling costs incurred in drilling and completing the partnership’s wells.
(2) The net offering proceeds of investors in the partnership will be used to pay up to 99% of the non-deductible equipment costs incurred by the partnership in drilling and completing its wells.
(3) Lease costs will likely be borne by the partnership through its acquisition of assigned interests in leases directly acquired and contributed by the operators.
(4) This table reflects the partnership’s anticipation that its production revenue otherwise allocable between the investors and the Managing GP will be used to pay these costs. If, however, these costs exceed the partnership’s production revenue, then in any given year the investors and the Managing GP may bear a percentage of these costs that differs from their share of the production revenue in that year, which share may vary from year to year under the Limited Partnership Agreement. Other such costs also include the plugging and abandonment costs of the wells after their economic reserves have been produced and depleted. If the Managing GP pays for any portion of any of these costs, the Managing GP will receive a share of the partnership’s revenues in the same percentage as such costs are paid by the Managing GP.

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(5) The Managing GP and the investors will share in all of the partnership’s other revenues in the same percentage that their respective capital contributions bear to the partnership’s total net capital contributions, except that the Managing GP will receive an additional 10% of the production revenues.
(6) Interest earned on offering proceeds until they are released to the Managing GP for use in the drilling activities of the partnership will be credited to each investor’s capital account and paid not later than the partnership’s first cash distribution from operations. Until the partnership’s offering proceeds are invested in its operations, any interest income from temporary investments will be allocated pro rata to the investors providing the offering 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.
(7) The greater of the cost depletion allowance and the percentage depletion allowance for each property will be available to investors as a current deduction against their share of the partnership’s gross production revenue in that taxable year, which share may vary from year to year under the Limited Partnership Agreement.

Allocation and Adjustment Among Investors

The investors’ share of the partnership’s revenues, gains, income, certain costs, losses, and other charges and liabilities generally will be charged and credited among investors in the partnership in accordance with the ratio that the respective number of Interests bears to the number of Interests held by all investors as a group in the partnership, based on a subscription price of $10,000 per Interest, regardless of the actual subscription price paid for the Interests. These allocations will take into account any Investor General Partner’s status as a defaulting Investor General Partner.

Distributions

The Managing GP will review the partnership’s accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. The partnership will distribute funds to investors that the Managing GP, 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:

repayment of any partnership borrowings;
cost overruns;
remedial work to improve a well’s producing capability;
compensation and fees to the Managing GP as described in “Risk Factors — Risks Related to an Investment in the Partnership — Compensation and fees to the Managing GP regardless of success of the partnership’s activities will reduce cash distributions”;
direct costs and general and administrative expenses of the partnership;
reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or
indemnification of the Managing GP 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 by the partnership for the purpose of making distributions to the investors if the amount advanced or borrowed would exceed the partnership’s accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. Any cash distributions from the partnership to the Managing GP will be made only in conjunction with distributions to investors in the partnership and only out of funds properly allocated to the Managing GP’s account.

Liquidation

The 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 the partnership terminates on an event that causes a dissolution of the partnership under state law and it is not a final terminating event, then a successor limited partnership

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will automatically be formed. Thus, only on a final terminating event will the partnership be liquidated. A final terminating event is any of the following:

the election by the Managing GP in its discretion to terminate the partnership in the partnership’s best interests, or the affirmative vote of investors whose Interests equal a majority of the total Interests to terminate the partnership;
the termination of the partnership under Section 708(b)(1)(A) of the Code because no part of its business is being carried on; or
the partnership ceases to be a going concern.

On the partnership’s liquidation, investors will receive their interest in the partnership. Generally, an investor’s interest in the partnership means an undivided interest in the partnership’s assets, after payments to the partnership’s creditors, in the ratio that its positive capital account bears to the positive capital accounts of all of the partners in the partnership (including the Managing GP) until all of the capital accounts have been reduced to zero.

Any in-kind property distributions to an investor from the partnership must be made to a liquidating trust or similar entity, unless the investor affirmatively consents to receive an in-kind property distribution after being told the risks associated with the direct ownership of the property, or unless there are alternative arrangements in place that assure that the investor will not be responsible for the operation or disposition of the partnership’s properties. If the Managing GP has not received an investor’s written consent to a proposed in-kind property distribution within 30 days after it is mailed, then it will be presumed that the investor has not consented. The Managing GP 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 GP. Also, if the partnership is liquidated, the Managing GP will be repaid any debts owed to it by the partnership before there are any payments to the investors in that partnership.

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FIDUCIARY RESPONSIBILITY OF THE MANAGING GP

In General

The Managing GP will manage the partnership and its assets. In conducting the partnership’s affairs, the Managing GP is accountable to you as a fiduciary, which under Delaware law generally means that the Managing GP must exercise due care and deal fairly with the investors. Neither the Limited Partnership Agreement nor any other agreement between the Managing GP and the partnership may contractually limit any fiduciary duty owed to the investors by the Managing GP under applicable law. See “Conflicts of Interest — In General” and “Management — Managing GP Acting on Behalf of the Partnership.” regarding the Managing GP’s dependence on its affiliate, ICON Capital, for facilities, investor relations and administrative functions.

In this regard, the Limited Partnership Agreement does permit the Managing GP and its affiliates to:

have business interests or activities that may conflict with the partnership if the Managing GP or its affiliates, as applicable, determine that the business opportunity either:
º cannot be pursued by the partnership because of insufficient funds; or
º is not appropriate for the partnership under the existing circumstances;
devote only so much of their time as is necessary to manage the affairs of the partnership, as determined by the Managing GP, in its sole discretion;
conduct business with the partnership in a capacity other than as Managing GP or sponsor as described in Sections 4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of the Limited Partnership Agreement;
manage multiple drilling programs simultaneously; and
be indemnified and held harmless as described below in “— Limitations on Managing GP’s Liability as Fiduciary.”

The fiduciary duty owed by the Managing GP to the partnership is analogous to the fiduciary duty owed by directors to a corporation and its stockholders, which is commonly referred to as the “business judgment rule.” This rule provides 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.

If the Managing GP 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 the partnership’s behalf to recover damages from a third-party when the Managing GP refuses to institute the action or where an effort to cause the Managing GP 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 GP for violations of its fiduciary duties to the limited partners. This is a rapidly expanding and changing area of the law, and if you have questions concerning the Managing GP’s duties you are urged to consult your own legal counsel.

Limitations on Managing GP’s Liability as Fiduciary

Under the terms of the Limited Partnership Agreement, the Managing GP and its affiliates have limited their liability to the partnership and to the investors for any loss suffered by the partnership or the investors in the partnership that arises out of any action or inaction on their part if:

the Managing GP or its affiliate, as applicable, determined in good faith that the course of conduct was in the best interest of the partnership;
the Managing GP or its affiliate, as applicable, was acting on behalf of, or performing services for, the partnership; and
its course of conduct did not constitute negligence or misconduct.

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In addition, the Limited Partnership Agreement provides for indemnification of the Managing GP and its affiliates by the partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the partnership provided that they meet the standards set forth above. However, there is a more restrictive standard for indemnification for losses arising from or out of an alleged violation of federal or state securities laws.

Payments to the Managing GP or its affiliates arising from the indemnification or agreement to hold harmless provisions of the Limited Partnership Agreement are recoverable only out of the partnership’s tangible net assets, which include its revenues and any insurance proceeds from the types of insurance for which the Managing GP and its affiliates may be indemnified under the Limited Partnership Agreement. Still, the use of partnership funds or assets to indemnify the Managing GP or an affiliate would reduce amounts available for partnership operations or for distribution to the investors.

The partnership may not pay the cost of the portion of any insurance that insures the Managing GP or an affiliate against any liability for which they cannot be indemnified. However, the 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 the following conditions are satisfied:

the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the partnership;
the legal action is initiated by a third-party who is not investor, or the legal action is initiated by an investor and a court of competent jurisdiction specifically approves the advancement; and
the Managing GP or its affiliate, as applicable, undertakes 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 effect of the foregoing provisions and the business judgment rule may be to limit your recourse against the Managing GP.

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FEDERAL INCOME TAX CONSEQUENCES

This section discusses the material federal income tax consequences for an individual investor who is a U.S. citizen or resident. This summary is not exhaustive of all possible tax considerations and is not tax advice. Moreover, this summary does not deal with all aspects that might be relevant to you, as a particular prospective investor, in light of your personal circumstances. The tax consequences of investing in the Interests will not be the same for all investors. A careful analysis of your particular tax situation is required to evaluate this investment properly. Therefore, the Managing GP urges you to consult your own tax advisor.

Tax treatment for other types of investors — such as trusts, corporations, tax-exempt organizations and employee benefit plans, and foreign investors — are likely to differ significantly from the principal tax consequences outlined in this section. See “— Tax Treatment of Certain Trusts and Estates,” “— Taxation of Tax-Exempt Organizations” and “— Corporate Investors.” State and local tax consequences may differ from the federal income tax consequences described below. See “— State and Local Taxes.”

Introduction

The partnership will not request a ruling on any federal tax issue relevant to an investment in the partnership from the IRS. Thus, the IRS could disagree with one or more tax positions the partnership takes. However, the Managing GP has obtained a tax opinion letter from Arent Fox LLP, special counsel for this offering, with respect to its classification as a partnership for federal income tax purposes. Arent Fox LLP also addressed federal income tax issues involving an investment in the partnership by a “typical investor” as that term is defined in “— Managing GP’s Representations.” below. You are urged to read the entire tax opinion letter, which has been filed as an exhibit to the registration statement of which this prospectus is a part. See “Further Information” for information on how to obtain a copy of special counsel’s tax opinion letter.

Although special counsel’s tax opinion and discussion of the issues involving a “typical investor” express what it believes a court would probably conclude if presented with the applicable federal tax issues, special counsel’s tax opinion and analysis 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 opinion or disagree with special counsel’s tax analysis, and the challenge could be sustained in the courts if litigated and cause adverse tax consequences to you and the partnership’s other investors. Special counsel’s tax opinion and analysis are based in part on representations, assumptions regarding a “typical investor,” and statements made by the Managing GP in the tax opinion letter, the representation letter we provided, and in this prospectus, including forward looking statements relating to the partnership and its proposed activities. See “Forward Looking Statements.”

Our special counsel will not prepare or review the partnership’s income tax information returns, which will be prepared on behalf of the Managing GP by an independent registered public accounting firm. The Managing GP will make a number of decisions on such tax matters as the expensing or capitalizing of particular items, the proper period over which capital costs may be depreciated or amortized and many similar matters. Such matters are usually handled by a limited partnership’s general partner, often with the advice of independent accountants, and are usually not reviewed with special counsel.

With regard to the tax consequences to you of an investment in the Interests, your use of the partnership’s special counsel’s tax opinion letter is subject to the limitations of the Code and proposed Treasury Regulations set forth below:

With respect to any material federal tax issue on which the partnership’s special counsel has issued a “more likely than not” or more favorable opinion, its opinion may not be sufficient for you to use for the purpose of avoiding penalties relating to any substantial understatement of income tax under Section 6662(d) of the Code.

Because the partnership has entered into a compensation arrangement with its special counsel to provide certain legal services to us, including its tax opinion letter, the partnership’s special counsel’s tax opinion letter was not written and cannot be used by you for the purpose of avoiding penalties relating to any reportable transaction understatement of income tax under Section 6662A of the Code.

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The limitations set forth above on your use of the partnership’s special counsel’s tax opinion letter apply only for federal tax purposes. They do not apply to your right to rely on the partnership’s special counsel’s tax opinion letter and the discussion in the “Federal Income Tax Consequences” section of this prospectus under the federal securities laws.

Disclosures in Tax Opinion Letter

Similar disclosures to those set forth below are made in special counsel’s tax opinion letter.

The tax opinion letter was written to support the promotion or marketing of Interests to potential investors, and special counsel to the partnership has helped the Managing GP organize and document the offering of Interests.
The tax opinion letter is not confidential. There are no limitations on the disclosure by the Managing GP or any potential investor in the partnership to any other person of the tax treatment or tax structure of the partnership.
Investors in the partnership have no contractual protection against the possibility that a portion or all of their intended tax benefits from an investment in the partnership ultimately are not sustained if challenged by the IRS. See “Risk Factors — Risks Related to the Tax Treatment of the Partnership and the Interests — The tax benefits that may be available to you from your investment in the partnership are not contractually protected.”
The potential investor is urged to seek advice based on his particular circumstances from an independent tax advisor with respect to the federal tax consequences to him of an investment in the partnership.

Special Counsel’s Assumptions

Set forth below is a synopsis of the principal assumptions made by special counsel in giving its federal income tax opinions.

You will not borrow money to buy Interests from the partnership itself, anyone related to the partnership including the Managing GP, and any other investor in the partnership.
You will be personally liable to repay any money you borrow to buy Interests.
You will not protect yourself through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements from losing the money you invest in a partnership.

Managing GP’s Representations

In giving its opinion and analysis, special counsel relied in part on representations from the Managing GP set forth in the tax opinion letter, including the principal representations summarized below.

A “typical investor” in the partnership will be a natural person who purchases Interests in this offering and is a U.S. citizen.
The Investor General Partner Interests will be converted by the Managing GP to Limited Partner Interests after all of the wells in the partnership have been drilled and completed. See “Actions to be Taken by Managing GP to Reduce Risks of Additional Payments by Investor General Partners.”
The partnership and the investor will elect to currently deduct all of the intangible drilling costs of all of the partnership’s wells.
All wells will be located inside the United States (as defined in Section 7701(a)(9) of the Code).
The Managing GP anticipates expending the partnership’s offering proceeds as soon as possible. You will include your share of the partnership’s deduction for intangible drilling costs on your individual federal income tax return for the year in which the partnership properly deducts the intangible drilling costs, subject to your right to elect to capitalize and amortize over a 60-month period a portion or all of your share of the partnership’s deduction for intangible drilling costs.

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The partnership may prepay most, if not all, of its intangible drilling costs for wells the drilling of which will not begin until the next calendar year. To the extent allowable, the partnership will deduct prepaid intangible drilling costs and allocate them to you in accordance with the Partnership Agreement in the year of prepayment.
The partnership will have a calendar year taxable year.
The principal purpose of the partnership is to locate, produce and market oil and natural gas on a profitable basis to its investors, apart from tax benefits, as discussed in this prospectus.
The partnership’s total abandonment losses under Section 165 of the Code, which could include, for example, abandonment losses incurred by the partnership for wells drilled which are nonproductive (i.e., a “dry hole”), and abandonment losses incurred by the partnership for productive wells which have been operated until their commercial oil and natural gas reserves have been depleted, is estimated to be less than $2 million, in the aggregate, in any taxable year of the partnership and less than $4 million, in the aggregate, during the partnership’s first six taxable years. However, as no wells have been drilled the partnership cannot know the actual amount of abandonment losses it will have in any given year.

Additional details, assumptions of special counsel, representations of the Managing GP, and other matters affecting special counsel’s opinions are contained in special counsel’s tax opinion letter. You are urged to read the entire tax opinion letter, which is attached as an exhibit to the registration statement of which this prospectus is a part, to assist your understanding of the federal tax benefits and risks of an investment in the partnership.

Special Counsel’s Opinions

Taxpayers bear the burden of proof to support claimed deductions and tax credits, and special counsel’s tax opinions are not binding on the IRS or the courts. Special counsel’s tax opinions with respect to an investment in the partnership by a typical investor, who is sometimes referred to in special counsel’s opinions as a “Participant,” “Investor General Partner” or “Limited Partner,” are set forth below.

(1) Partnership Classification.  The partnership will be classified as a partnership for federal income tax purposes, and not as a publicly traded partnership or corporation.
(2) Limitations on Passive Activity Losses and Credits.  The passive activity limitations on losses and credits of the partnership under Section 469 of the Code:
will apply to the Limited Partners in the partnership; and
will not apply to the Investor General Partners in the partnership with respect to the partnership’s “working interests” until after their Investor General Partner Interests are converted to Limited Partner Interests, subject to certain recharacterization rules.
(3) Trade or Business Expenses and Other Currently Deductible Items.  You may deduct currently the partnership’s trade or business expense and other currently deductible items subject to the potential limitations below. Items that the Code requires to be capitalized, such as lease acquisition costs, Tangible Costs, and O&O Costs are not deductible currently.

Potential Limitations on Deductions. A Participant’s ability in any taxable year to use his share of these deductions of the partnership on his individual federal income tax returns may be reduced, eliminated or deferred by the following limitations:

the Participant’s personal tax situation, such as the amount of his regular taxable income, alternative minimum taxable income, losses, itemized deductions, personal exemptions, etc., which are not related to his investment in the partnership;
the amount of the Participant’s adjusted basis in his Interests at the end of the partnership’s taxable year;
the amount of the Participant’s “at risk” amount in the partnership at the end of the partnership’s taxable year; and

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the passive activity limitations on losses, and credits, if any, of the partnership in the case of Limited Partners (including Investor General Partners after their Interests are converted to Limited Partner Interests) who are natural persons or are entities that also are subject to the passive activity limitations on losses and credits under Section 469 of the Code.
(4) Intangible Drilling Costs.  Although the partnership will elect to deduct currently all of its Intangible Drilling Costs to the extent allowable, a Participant in the partnership may still elect to capitalize and deduct all or part of his allocable share of the partnership’s Intangible Drilling Costs (which do not include drilling and completion costs of a re-entry well that are not related to deepening the well, if any) ratably over a 60-month period. Subject to the foregoing, Intangible Drilling Costs paid by the partnership under the terms of bona fide drilling contracts for the partnership’s wells will be deductible by Participants in the partnership who elect to currently deduct their share of the 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 in any taxable year to use his share of these partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (3) above.

(5) Prepaid Intangible Drilling Costs.  Subject to the Participant’s election to capitalize and amortize a portion or all of his share of the partnership’s Intangible Drilling Costs as set forth in opinion (4) above, the Participant may deduct the Participant’s allocable share of any Intangible Drilling Cost prepayments by the partnership in the year in which the Participant invests in the partnership for wells the drilling of which will begin within the first 90 days of the next year.

A Participant’s ability in any taxable year to use his share of these partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (3) above.

(6) Depletion Allowance.  The greater of the cost depletion allowance or the percentage depletion allowance for each oil and natural gas property will be available to qualified Participants as a current deduction against their share of the partnership’s gross income from the sale of oil and natural gas production in the taxable year, subject to the following restrictions:
a Participant’s cost depletion allowance cannot exceed his adjusted tax basis in the natural gas or oil property to which it relates; and
a Participant’s percentage depletion allowance:
from each oil and natural gas property may not exceed 100% of his taxable income from such oil and natural gas property before the deduction for depletion; and
is limited to 65% of his taxable income for the year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs and, in the case of a Participant that is a trust, any distributions to its beneficiaries.
(7) MACRS.  The partnership’s reasonable Tangible Costs for equipment placed in its productive wells that cannot be deducted immediately will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System (“MACRS”). The partnership expects that most of its property will be recovered over a seven year “cost recovery period” on a well-by-well basis, beginning in the taxable year the well is drilled, completed and made capable of production, i.e. placed in service. The partnership also may be eligible to use a shorter recovery period under certain circumstances. Also, the Participant will be entitled to bonus depreciation of 100% or 50%, depending on the year, of the related Tangible Costs, which will not be an adjustment for alternative minimum tax for the life of the equipment, provided any equipment the partnership acquires and places in service in 2012 qualifies for such bonus depreciation. In addition, under certain circumstances the Managing GP may determine that claiming bonus depreciation might not be advisable if it reduces the amount of otherwise allowable depletion in excess of basis.

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A Participant’s ability in any taxable year to use his share of these partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (3), above.

(8) Tax Basis of Interests.  The Participant’s initial adjusted tax basis in his Interests will be the amount of money that he paid for his Interests plus his share of the Partnership’s debt, if any.
(9) At Risk Limitation on Losses.  The Participant’s initial “at risk” amount in the partnership in which he invests will be the amount of money that he paid for his Interests.
(10) Allocations.  The allocations in the Partnership Agreement of income, gain, loss, deduction, credit, and distributions, or items thereof, including the allocations of basis and amount realized with respect to the partnership’s oil and natural gas properties, will have substantial economic effect and will govern the Participant’s allocable share of those items.
(11) Subscription.  No gain or loss will be recognized by the Participants on payment of their subscriptions to the partnership.
(12) Profit Motive, IRS Anti-Abuse Rule and Potentially Relevant Judicial Doctrines.  The partnership will possess the requisite profit motive under Section 183 of the Code. Also, Section 7701(o), the partnership anti-abuse rule in Treasury Regulation Section 1.701-2 and potentially relevant judicial doctrines will not have a material adverse effect on the tax consequences of an investment in the partnership by a Participant as described in the partnership’s opinions and analysis.
(13) Reportable Transactions.  Based on its expected operations, the partnership will not engage in any reportable transaction under Section 6707A(c) of the Code. Nevertheless, a reportable transaction may occur if the partnership incurs greater than expected losses.
(14) Overall Conclusion.  The partnership’s overall conclusion is that the federal tax treatment of a typical Participant’s investment in the partnership as set forth in the opinions above more likely than not is the proper federal tax treatment and more likely than not would be upheld on the merits if challenged by the IRS and litigated. The partnership’s evaluation of the federal income tax laws and the expected activities of the partnership as represented to the partnership by the Managing GP in the tax opinion letter and as described in the Prospectus causes the partnership to believe that the deduction by a typical Participant of all, or substantially all, of his allocable share of the partnership’s paid and prepaid Intangible Drilling Costs to the extent allowable for the year he invests, in the year he invests is the principal tax benefit offered by the partnership to its respective Participants (other than the single level of taxation afforded a partnership) and also is the proper federal tax treatment, subject to the Participant’s option to elect to capitalize and amortize a portion or all of his allocable share of the partnership’s deduction for Intangible Drilling Costs.

A Participant’s ability in any taxable year to use his share of these partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (3), above.

The discussion in this prospectus under the caption “Federal Income Tax Consequences,” insofar as it contains statements of federal income tax law, is correct in all material respects.

Discussion of Federal Income Tax Consequences

Introduction

Special counsel’s tax opinions are limited to those set forth above. The following is a discussion of all material federal income tax issues or consequences, and any significant federal tax issues, related to the purchase, ownership and disposition of the partnership’s Interests that may apply to typical investors in the partnership. Except as otherwise noted below, however, different tax consequences from those discussed below may apply to foreign persons, corporations, IRAs and other tax-exempt entities, partnerships, trusts and other prospective investors that are not treated as typical investors for federal income tax purposes. Also, the proper treatment of the partnership’s tax attributes by a typical investor on his individual federal income tax returns may vary from that of another typical investor. This is because the practical utility of the tax aspects of any

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investment depends largely on the investor’s particular income tax position in the year in which items of income, gain, loss, deduction, or credit, if any, are properly taken into account in computing his federal income tax liability. In addition, the IRS may challenge the deductions, and credits, if any, claimed by the partnership or you and the other investors in the partnership, or the taxable year in which the deductions, and credits, if any, are claimed, and it is possible that the challenge would be upheld if litigated. Accordingly, you are urged to seek advice based on your particular circumstances from an independent tax advisor in evaluating the potential tax consequences to you of an investment in the partnership.

Partnership Classification

Multi-owner business organizations generally are treated either as corporations or partnerships for federal income tax purposes. For Federal income tax purposes, unincorporated domestic entities that are not subject to a specific classification provision and that do not elect to be taxed as corporations are treated as partnerships and, thus, pass through entities. Pass through entities are generally tax reporting entities, not taxpaying entities. This means that the individual partners, and not the limited partnership, pay tax on the limited partnership’s income and deduct the limited partnership’s losses. As a limited partner, you will report your share of the partnership’s income, deductions, gains and losses on your federal income tax return. You will also pay taxes on your share of any taxable income or gains earned by us.

One tax advantage of being taxed as a partnership is that the federal government taxes the partnership’s earnings only once. The limited partnership files an informational return with the Internal Revenue Service (“IRS”), but has no federal income tax liability. Because it pays no federal income taxes, the limited partnership has more cash to distribute to its investors. By contrast, the federal government effectively taxes a corporation’s earnings twice. The corporation itself must pay taxes on its taxable income, reducing the amount available to distribute in dividends to its shareholders; and the shareholders are then required to pay income taxes on the dividends they receive. Another tax advantage of partnerships is that, subject to the limitations discussed in this section, investors often can deduct their share of any losses the limited partnership incurs, whereas a corporation does not pass through deductible losses to its investors. Subject to the exceptions set forth below regarding split holding periods, partners are also deemed to own a single partnership interest, regardless of the number of Interests acquired and when acquired.

The partnership believes that your most substantial tax risk from this investment would be for the IRS to treat the partnership as a corporation for tax purposes, by classifying the partnership as a “publicly traded partnership,” without adequate qualifying income, under Code Section 7704(b). Were that to happen, the partnership would have to pay tax on the partnership’s income, reducing the amount of cash available for distribution to you; and you would not be able to deduct your share of any of the partnership’s losses or deduct a depletion allowance on your individual federal income tax return with respect to the partnership’s oil and natural gas properties. Such a classification would adversely affect your after-tax return, especially if the classification were to occur retroactively. Furthermore, a change in the partnership’s tax status would be treated as an exchange by the IRS, which could give rise to additional tax liabilities. See “— Publicly Traded Partnerships.”

Your ability to deduct the partnership’s losses is limited to the amounts that you have at risk in this investment. This is generally the amount of your investment, plus any profit allocations (including depletion deductions taken by you with respect to the partnership’s oil and natural gas properties) and minus any loss allocations and distributions. Additionally, your ability to deduct losses attributable to passive activities is restricted. Because the partnership’s operations predominantly will constitute passive activities to an individual investor who is a limited partner, a limited partner can only use the partnership’s losses (including such limited partner’s allocable share of the partnership’s intangible drilling costs and such limited partner’s depletion deductions) to offset passive income in calculating such limited partner’s tax liability. For example, passive losses may not be used to offset portfolio income. The partnership’s activities are not passive to an Investor General Partner, however. See “— Limitations on Passive Activity Losses and Credits,” “— Tax Basis of Interests,” and “— At Risk Limitation on Losses.”

Publicly Traded Partnerships

The Code classifies some partnerships as publicly traded partnerships for tax purposes, referred to as “PTPs.” If the partnership were to be classified as a PTP and did not qualify for the income exception

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discussed below, the partnership would be taxed as a corporation, the treatment of which the partnership described above. A PTP is a partnership in which interests are traded on an established securities market or are readily tradable on either a secondary market or the substantial equivalent of a secondary market. The Code contains an exception, however, from being taxed as a corporation if the PTP derives 90% or more of its gross income from sources such as certain income from natural resources, interest and dividends, rents from real property and gains from the sale of real property. Although the partnership expects that almost all of its income will be “qualifying income” for PTP purposes, the partnership does not intend to rely on that exception to the general rule regarding the taxation of PTPs and will take steps to limit the market for its Interests.

The legislative history of Code Section 7704 provides that a secondary market for interests in a partnership or the substantial equivalent thereof exists if investors are readily able to buy, sell or exchange their partnership interests in a manner that is comparable, economically, to trading on established securities markets. A secondary market is generally indicated by the existence of a person standing ready to make a market in the interests. The substantial equivalent of a secondary market will be deemed to exist if (i) interests in the partnership are regularly quoted by any person, such as a broker or dealer, making a market in the interests; (ii) any person regularly makes available to the public (including customers and subscribers) bid or offer quotes with respect to interests in the partnership and stands ready to effect buy or sell transactions at the quoted prices for itself or on behalf of others; (iii) the holders of interests in the partnership have a readily available, regular and ongoing opportunity to sell or exchange their interests through a public means of obtaining or providing information of offers to buy, sell, or exchange interests; or (iv) buyers and sellers have the opportunity to buy, sell, or exchange interests in the partnership in a time frame that a market-maker would provide and prospective buyers have similar opportunities to acquire such interests. The legislative history of Section 7704 also indicates that a regular plan of redemptions or repurchases by a partnership may constitute public trading where holders of interests have readily available, regular and ongoing opportunities to dispose of their interests.

The partnership does not intend to list the Interests on any market. The Interests also will not be readily tradable on a secondary market, nor does the partnership expect them to be in the future. Therefore, the partnership will be a PTP only if the Interests become readily tradable on the substantial equivalent of a secondary market. The Interests do not become readily tradable merely because the partnership may provide information to its partners regarding other partners’ desires to buy or sell Interests to each other, or occasionally arrange transfers between partners. Moreover, the Interests do not become readily tradable if the partnership creates a qualified matching program, because transfers made through a qualified matching service are also not counted. A matching service qualifies for this exclusion if it satisfies all seven of the following conditions:

(1) it consists of a system that lists customers’ bid and ask quotes in order to match sellers and buyers;

(2) deals occur either by matching the list of interested buyers to interested sellers or by bidding on listed interests;

(3) sellers cannot enter into a binding agreement to sell their interest until at least 15 days after information regarding their offering is made available to potential buyers;

(4) the closing of the sale does not occur until at least 45 days after information about the offering is made available;

(5) the matching service only displays quotes that express interest in trading but do not represent firm commitments to buy or sell at the quoted price;

(6) the seller’s information is removed from the matching service within 120 days after the posting and, if removed for any reason other than a sale, no offer to sell from that seller is entered into the matching service for at least 60 days; and

(7) the percentage of interests in the capital or profits transferred during the tax year (other than through private transfers) does not exceed 10% of the total interests in partnership capital or profits.

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In the opinion of the partnership’s counsel, the IRS should not treat the partnership as a PTP. This opinion is based in part on the partnership’s representation to counsel that the Interests will not be listed on any securities exchange and that, in accordance with Article VI of the Limited Partnership Agreement, the Managing GP will refuse to recognize or give effect to any assignment of the Interests for any purpose (including recognizing any right of the transferee, such as the right of the transferee to receive directly or indirectly the partnership’s distributions or to acquire an interest in the partnership’s capital or profits) that it knows or has reason to know occurred on an established securities market or a secondary market (or the substantial equivalent thereof), within the meaning of Section 7704 of the Code and the Treasury Regulations and published notices promulgated thereunder, or to permit, recognize or give effect to any assignment of Interests, in any given year, that would result in the transfer of more than the lesser of (X) 2% of the total interests in the partnership’s capital or profits as determined in accordance with Regulations Sections 1.7704-1(j) and 1.7704-1(k) or (Y) the excess of 10% of such Interests over the Interests the transfer of which the Managing General Partner concludes in good faith were described in Treasury Regulation Sections 1.7704-1(f) or 1.7704-1(g) other than those that the Managing GP determines in good faith fall within certain safe harbor provisions under Treasury Regulation Section 1.7704-1 in any given year, such as those pursuant to the Participants’ Presentment right. See “Transfer of the Interests/Withdrawal — Restrictions on the Transfer of the Interests and Withdrawal.” This is pursuant to a “safe harbor” under Treasury Regulation Section 1.7704-1 that provides that a secondary market or its equivalent will not exist if the sum of the interests in partnership capital or profits attributable to those partnership interests that are sold, redeemed, or otherwise disposed of during the partnership’s taxable year and do not fall within other “safe harbor” provisions does not exceed 2%, or such lesser percent as described above, of the total interests in partnership capital or profits. Even if the partnership exceeds the 2% limit due to transfers pursusant to one or more safe harbors, the partnership will not allow transfers that would cause more than 10% of its Interests to be transferred.

While the partnership will use its best efforts to limit the type and number of transfers of Interests to those that will allow the partnership to remain within the 2% safe harbor, the partnership does not warrant that the partnership will satisfy this safe harbor during each of its taxable years. It is conceivable that transfers of Interests could occur that would cause the partnership to fall outside the safe harbor. In this regard, Treasury Regulation Section 1.7704-1(c)(3) states that failure to meet any of the safe harbors will not create a presumption that a secondary market or its equivalent exists for Interests. No assurances can be offered, however, that, if the amount and type of trading in the Interests were to fall outside the safe harbor, the IRS would not assert publicly traded partnership status with respect to us.

If the partnership is classified as a PTP, it would be treated for federal income tax purposes as a corporation unless, as noted above, 90% or more of the partnership’s gross income were to come from certain “qualified sources.” A significant portion of the partnership’s business will be generated from the exploration, development, mining or production of natural resource properties, or the processing, refining, transportation or marketing of natural resources. Income and gains from these sources are “qualified.” Thus, if the partnership were a PTP, the partnership might not be subject to corporate tax treatment due to the sources of the partnership’s gross income. Nevertheless, if the partnership were a PTP and the partnership’s qualifying income was less than 90% of the partnership’s gross income, the major consequences of corporate tax treatment would be that, in addition to being taxed when distributed to you, the partnership’s income would be subject to corporate income tax and the partnership’s losses would not be passed through its partners. If the partnership is taxed as a corporation, and particularly if the PTP classification is made retroactively, corporate taxation would have a substantial adverse effect on your after-tax return on your investment. Furthermore, the IRS would treat a change in tax status from a partnership to a PTP taxable as a corporation as an exchange that could give rise to tax liabilities for the partnership’s partners if the partnership’s debt exceeded the tax basis of the partnership’s assets at the time of the change in tax status — even though partners likely would not receive cash distributions from the partnership to cover such tax liabilities. See “— Opinion of Counsel,” “— Taxation of Limited Partnerships in General” and “— Sale or Other Disposition of Interests.” In addition, the partnership’s distributions would be classified as portfolio income (dividends) rather than passive activity income and thus would not be eligible to be offset by passive activity losses attributable to the partnership or other activities giving rise to passive activity losses. See “— Limitations on Passive Activity Losses and Credits,” “— Tax Basis of Interests,” and “— At Risk Limitation on Losses.”

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Taxation of Current Distributions

As long as the partnership is classified as a partnership under federal tax law, it will not be subject to federal income tax. Rather, you will be required to report on your federal income tax return, and pay taxes with respect to, your share of the partnership’s annual income, gains, losses, deductions and credits. You must pay tax on your distributive share of the partnership’s income regardless of the amount of distributions you receive. The partnership’s tax returns will be prepared using the accrual method of accounting. Under the accrual method, the partnership will recognize as income items such as interest as and when earned by it, even if the proceeds are not received until a subsequent tax year.

The partnership will furnish you with all information about the partnership necessary to prepare your federal income tax return not later than 75 days after the end of each fiscal year. The partnership will also file an annual information return with the IRS and will report its finances on an accrual basis using a December 31 fiscal year. The partnership’s income and loss (as well as tax basis allocable to the partnership’s depletable oil and natural gas properties) for the taxable year will be allocated among its partners to take into account the varying interests of its partners during the year using any method permissible under Code Section 706 that the Managing GP may select. If any partners hold their Interests for less than the entire year, they will be allocated income and loss (as well as tax basis allocable to the partnership’s depletable oil and natural gas properties) using such method as selected by the Managing GP that reflects such part-year ownership as is permissible under Code Section 706. For purposes of allocating income or loss (including depletion taken by participants with respect to the partnership’s oil and natural gas properties) among its partners, the partnership generally will treat its operations as occurring ratably over each fiscal year — in other words, the partnership will assume that income and loss are spread evenly over the fiscal year except for “extraordinary items” as defined in the proposed Treasury Regulations under Section 706. Thus, if some participants are admitted after others, those participants admitted later may receive a smaller portion of each item of the partnership’s net profits and net losses (including depletion taken by participants with respect to the partnership’s oil and natural gas properties) than the participants who were admitted earlier. Nevertheless, those participants still will be obligated to make the same capital contributions to the partnership for their Interests as the participants who were admitted previously. In addition, where a participant transfers Interests during a taxable year, a participant may be allocated net profits for a period for which such participant will not receive a corresponding cash distribution. Moreover, depletion, depreciation or other cost recovery (including depletion taken by participants with respect to the partnerhip’s oil and natural gas properties) with respect to Partnership Assets may create a deferral of tax liability during your ownership of the Interests. Larger cost recovery deductions in the early years may reduce or eliminate the partnership’s taxable income in the initial years of its operations. This deferral, however, will be offset in later years, when smaller depletion, depreciation and cost recovery deductions will offset less of the partnership’s income. In later years, it is possible that taxable income will exceed cash distributions.

With the exception noted below, you will not be required to pay income tax on cash distributions that exceed your share of the partnership’s taxable income (as adjusted for depletion taken by you with respect to the partnership’s oil and natural gas properties); however, the excess will reduce your tax basis for your Interests. Your tax basis will also increase or decrease annually based on your allocable share of the partnership’s income or loss and depletion taken by you with respect to the partnership’s oil and natural gas properties generally to the extent it does not exceed your share of the basis in such properties for the year. Any cash distributions you receive that exceed your tax basis (after adjustment for your allocated share of the partnership’s income or loss and depletion taken by you with respect to the partnership’s oil and natural gas properties) will be taxable to you, generally as capital gains, provided the Interests are held by you as capital assets. Any reduction in your share of non-recourse liabilities (to the extent the partnership incur any), such as might arise as a result of a reduction of your percentage interest in the partnership upon issuance of additional Interests to new or existing partners or a conversion from an IGP interest to a limited partner interest, will be treated as a distribution of cash to you. A portion of any distribution in excess of your tax basis, however, will be recharacterized as ordinary income in the same percentage that ordinary income would be realized upon a sale by the partnership of all the partnership’s assets, for example, because of depreciation or depletion recapture or recapture of the partnership’s intangible drilling costs. In addition, to the extent that a distribution would cause the amount you are considered to have “at risk” with respect to Partnership Assets placed in service in a given year to become negative, you will have to include such amount in your gross income up to

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the amount of losses previously taken with respect to such Partnership Assets. Further, a non-pro rata distribution of money or property, such as might arise as a result of a reduction of your share of the partnership’s liabilities upon the admission of additional partners, may result in ordinary income to you, regardless of your tax basis in your Interests, if the distribution reduces your share of the partnership’s “unrealized receivables,” including depreciation recapture, recapture of the partnership’s intangible drilling costs, or substantially appreciated “inventory items.” These terms are defined in Section 751 of the Code, and are known as “Section 751 assets.” To that extent, you will be treated as having been distributed your proportionate share of the partnership’s Section 751 assets and having exchanged those assets with the partnership in return for the non-pro rata portion of the actual distribution made to you. This last deemed exchange generally will result in your realization of ordinary income under Section 751(b) of the Code. That ordinary income will equal the excess of (i) the non-pro rata portion of that distribution over (ii) your tax basis for your share of Section 751 assets deemed relinquished in the exchange. Similarly, upon the partnership’s redemption of your Interests, it is possible that you could recognize both ordinary income and a capital loss.

Tax Treatment of the Partnership’s Termination Pursuant to the Limited Partnership Agreement

When the partnership terminates pursuant to the Limited Partnership Agreement, the partnership is required to dispose of its assets, apply the proceeds and other funds to repayment of the partnership’s liabilities and distribute any remaining funds to the partnership’s partners in accordance with their “Distribution Interests,” which is equivalent to a distribution to the partners in accordance with their positive capital account balances. Provided that such termination does not occur very early during the partnership’s existence, the partnership expects that the capital accounts of all the partners (except for the Managing GP) will be proportionate based on the number of Interests owned by each partner as of the liquidation date because of the manner in which Profits and Losses are allocated among the partnership’s limited partners during the partnership’s early fiscal years. Sales and other dispositions of the partnership’s assets would have the tax consequences described in “— Sale of the Properties” below. Cash distributions made at liquidation that exceed the tax basis of your interest in the partnership generally would be taxable as capital gain, provided your Interests constitute capital assets in your hands. Cash distributions in amounts less than your basis may result in a loss, generally a capital loss, which would be subject to the general limitations on deductibility of capital losses.

Limitations on Passive Activity Losses and Credits

Under the passive activity rules of Section 469 of the Code, all income of a taxpayer who is subject to the rules is categorized as:

income from passive activities, such as limited partners’ interests in a business;
active income, such as salary, bonuses, etc.; or
portfolio income, such as gain, interest, dividends and royalties unless earned in the ordinary course of a trade or business, and gain not derived in the ordinary course of a trade or business on the sale of property that generates portfolio income or is held for investment.

Losses generated by passive activities can offset only passive income and cannot be applied against active income or portfolio income. Similar rules apply with respect to tax credits. (See “— Marginal Well Production Credits,” below.) Suspended passive losses and passive credits that 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 federal income tax liability (in the case of passive activity credits). Suspended passive activity losses can be used against active or portfolio income upon the taxpayer’s disposition of the passive activity. Passive activity loss limitations apply should you be subject to the AMT.

The passive activity rules apply to:

individuals, estates, and trusts;
closely held C corporations, which under Sections 469(j)(1), 465(a)(1)(B) and 542(a)(2) of the Code are taxed under subchapter C, are corporations with five or fewer individuals who own directly or indirectly more than 50% in value of the outstanding stock at any time during the last half of the

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taxable year (for this purpose, U.S. trusts forming part of a stock bonus, pension or profit-sharing plan of an employer for the exclusive benefit of its employees or their beneficiaries that constitutes a “qualified trust” under Section 401(a) of the Code, trusts forming part of a plan providing for the payment of supplemental employee unemployment compensation benefits that meet the requirements of Section 501(c)(17) of the Code, domestic or foreign “private foundations” described in Section 501(c)(3) of the Code, and a portion of a trust permanently set aside or to be used exclusively for the charitable purposes described in Section 642(c) of the Code or a corresponding provision of a prior income tax law, are considered to be individuals); and
personal service corporations, which under Sections 469(j)(2), 269A(b) and 318(a)(2)(C) of the Code are corporations the principal activity of which is the performance of personal services and those services are substantially performed by employee-owners. For this purpose, the term “employee-owners” includes any employee who owns, on any day during the taxable year, any of the outstanding stock of the personal service corporation, and an employee is considered to own:
the employee’s proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a partnership or estate in which the employee is a partner or beneficiary;
the employee’s proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a trust (other than an employee’s trust that is a qualified pension, profit-sharing, or stock bonus plan and is exempt from tax) if the employee is a beneficiary;
all of the stock of the personal service corporation owned, directly or indirectly, by or for any portion of a trust that the employee is considered to own under the Code; and
if any stock in a corporation is owned, directly or indirectly, for or by the employee, the employee’s proportionate share of the stock of the personal service corporation owned, directly or indirectly, by or for that corporation.

However, a corporation will not be treated as a personal service corporation for purposes of Section 469 of the Code unless more than 10% of the stock (by value) in the corporation is held by employee-owners (as described above).

Also, if a closely held C corporation, other than a personal service corporation in which employee-owners own more than 10% (by value) of the stock, has net active income as defined in Section 469(e)(2)B) for a taxable year, its passive loss for that taxable year can be applied against its net active income for that taxable year. Similar rules apply to its passive credits, if any.

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. Thus, if you are subject to the passive activity rules as described above and you invest in the partnership as a limited partner, your investment in the partnership will be subject to the passive activity limitations on losses and credits. See “Risk Factors — Risks Related to the Tax Treatment of the Partnership and the Interests — The deduction for intangible drilling costs may not be available to you if you do not have passive income.”

Investor General Partners also will not materially participate in the partnership. However, because the partnership intends to own only “working interests,” as defined by the Code, in its wells, and Investor General Partners will not have limited liability under the Delaware Revised Uniform Limited Partnership Act until they are converted to limited partners, their deductions and any credits from the partnership will not be treated as passive deductions or credits under the Code before the conversion, unless they invest in the 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 that limits his personal liability under state law to purchase his Interests, 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 on deductions and credits the same as if he had invested in the partnership as a limited partner. See “— Conversion from Investor General Partner to Limited Partner” and “— Marginal Well Production Credits,” below.

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As compared with limitations on liability under state law as discussed above, contractual limitations on the liability of Investor General Partners under the Partnership Agreement, such as insurance, limited indemnification by the Managing GP, etc. will not cause Investor General Partners to be subject to the passive activity limitations on losses and credits. Investor general partners, however, may be subject to an additional limitation on their deduction of investment interest expense as a result of their non-passive deduction of intangible drilling costs. See “— Limitations on Deduction of Investment Interest,” below.

Suspended passive losses and passive credits that cannot be used by a taxpayer in his current tax year may be carried forward indefinitely, but not back, and can be used to offset passive income in future years or, in the case of passive credits, can be used to offset regular federal income tax liability attributable to passive income in future years. A suspended passive loss, but not a suspended passive credit, is allowed in full when a taxpayer’s entire interest in a passive activity is sold to an unrelated third-party in a fully taxable transaction (including a redemption by the partnership of all your interests), and in part on the taxable disposition of substantially all of a taxpayer’s interest in a passive activity if the suspended passive loss as well as current gross income and deductions of the passive activity can be allocated to the part disposed of with reasonable certainty. In an installment sale of a taxpayer’s entire interest in a passive activity, passive losses become available in the same ratio that gain recognized each year bears to the total gain on the sale. Gain resulting from the disposition of an interest in a passive activity constitutes passive activity income. See “Transferability of Interests — Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”

Any suspended passive losses remaining at a taxpayer’s death are allowed as deductions on the decedent’s final return, but only to the extent the amount of the suspended passive losses is greater than the excess of the basis of the property in the hands of the transferee over the property’s adjusted basis immediately before the decedent’s death. If a taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of the person receiving the gift is increased by any suspended passive losses and no deductions are allowed. If the interest is later sold at a loss, the basis in the property of the person receiving the gift is limited to the fair market value of the property on the date the gift was made.

Passive Activities and Publicly Traded Partnerships

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. As stated above, in special counsel’s opinion the partnership will not be treated as a publicly traded partnership under the Code.

Conversion from Investor General Partner to Limited Partner

If you invest in the partnership as an Investor General Partner, then your share of the partnership’s deduction for intangible drilling costs and other losses in the year you invest will not be subject to the passive activity limitations on losses and credits. This is because the Investor General Partner Interests will not be converted to limited partner Interests under Section 6.01(b)(1) of the Limited Partnership Agreement until after all of the wells in the partnership have been drilled and completed. (See “Actions to be Taken by Managing GP to Reduce Risks of Additional Payments by Investor General Partners,” and “— Drilling Contracts,” below.) After the Investor General Partner Interests have been converted to limited partner Interests, the former Investor General Partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited partnership Act after the date of the conversion.

Concurrently, the former Investor General Partner will become subject to the passive activity limitations on losses and credits as a limited partner. If your Investor General Partner Interest is converted to a Limited Partner Interest during a taxable year, the Treasury Regulations provide that if your interest is coverted before economic performance has occurred with respect to all items of deduction taken into account by the partnership for the taxable year in connection with the drilling or operation of the well, the passive activity rules will apply to that portion of your net loss for the conversion year attributable to deductions for expenses with respect to which economic performance occurred after your conversion.

However, the former Investor General Partner previously will have received a non-passive loss as an Investor General Partner in the year he invested in the partnership as a result of his share of the partnership’s

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deduction for intangible drilling costs and other expenses. 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 that cannot be offset with passive losses. If you are allocated losses (or your depletion deduction from the partnership’s oil and natural gas properties) subsequent to your conversion, you cannot use such losses against your share of the partnership’s income until you dispose of your Interests. For a discussion of the effect of this rule on an Investor General Partner’s tax credits, if any, from the partnership, see “— Marginal Well Production Credits,” below. The conversion of the Investor General Partner Interests into limited partner Interests should not have any other adverse tax consequences on an Investor General Partner unless his share of his partnership liabilities, if any, is reduced as a result of the conversion. See “— Tax Basis of Interests,” below.

Taxable Year

The partnership will have a calendar year taxable year. The taxable year of the partnership is important to you because your share of the partnership’s deductions, tax credits, if any, income and other items of tax significance must be taken into account on your personal federal income tax return for your taxable year within or with which the partnership’s taxable year ends.

Method of Accounting

The partnership will use the accrual method of accounting for federal income tax purposes. Under the accrual method of accounting, income is taken into account for the year in which all events have occurred that fix the right to receive it and the amount is determinable with reasonable accuracy, rather than the time of receipt. Consequently, you and the other investors in the partnership may have income tax liability resulting from the partnership’s accrual of income in one tax year even though it does not receive the income in cash until the next tax year. Expenses are deducted for the year in which all events have occurred that determine the fact of the liability, the amount is determinable with reasonable accuracy and the economic performance test is satisfied. Under Section 461(h) of the Code, if the liability of the taxpayer arises out of the providing of services or property to the taxpayer by another person, economic performance generally occurs as the services or property, respectively, are provided. The Treasury Regulations provide a special rule that deems economic performance to be met when a taxpayer pays the person providing the services or property, but only if the taxpayer can reasonably expect the person to provide the services or property within 3½ months after payment. If the liability of the taxpayer arises out of the use of the property by the taxpayer, economic performance occurs as the property is used.

A special rule in the Code provides that there is economic performance in the current taxable year with respect to amounts paid in that taxable year for costs of drilling and completing a natural gas or oil well so long as the drilling of the well begins before the close of the 90th day after the close of the taxable year in which the payments were made. See “— Drilling Contracts,” below, for a discussion of the federal income tax treatment of any prepaid intangible drilling costs by the partnerships.

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 GP has represented that the amounts payable by the partnership to it and its affiliates under the Partnership Agreement and any other agreements executed in compliance with this prospectus and the Participation Agreement are reasonable and competitive amounts that ordinarily would be paid for similar services in similar transactions between persons having no affiliation and dealing with the other at “arms length” in the proposed areas of the partnership’s operations. See “Compensation” and “— Drilling Contracts,” below. The fees paid to the Managing GP and its affiliates by the partnership will not be currently deductible, however, to the extent it is determined by the IRS or the courts that they are:

in excess of reasonable compensation;
properly characterized as organization or syndication fees or other capital costs, such as lease acquisition costs or equipment costs (i.e., Tangible Costs); or
not “ordinary and necessary” business expenses.

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In the event of an IRS audit of the partnership, payments to the Managing GP and its affiliates by the partnership, if any, would be scrutinized by the IRS to a greater extent than payments to an unrelated party.

Your ability in any taxable year to use your share of these partnership 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 (3) in “— Special Counsel’s Opinions,” above.

Although the partnership will engage in the production of oil and natural gas from wells drilled in the United States, the partnership does not expect to 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 partnership does not expect to have its own employees or pay Form W-2 wages. Instead, the partnership expects to rely on the Managing GP its affiliates, and third parties to manage it and its respective businesses. See “Management.”

Intangible Drilling Costs

You may elect to deduct your share of the partnership’s intangible drilling costs, which include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary to the drilling of a well and preparing it for the production of natural gas or oil, in the taxable year in which the partnership’s wells are drilled and completed. The cost of drilling saltwater disposal wells, however, generally does not constitute deductible intangible drilling costs. For a discussion of the deduction in the year you invest in the partnership of intangible drilling costs that are prepaid by the partnership in the year you invest in the partnership for wells the drilling of which will not begin until the next year, if any, see “— Drilling Contracts,” below.

Your share of the partnership’s gain (if the partnership sells a well at a gain), or your gain (if you sell your Interests 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 (in addition to possible recapture of other depreciation and depletion deductions you have claimed with respect to the partnership’s assets), but not for the deductions for operating expenses, if any. See “— Sale of the Properties” and “— Disposition of Interests,” 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.

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 that may not be currently deductible, such as lease acquisition expenses, equipment costs or syndication fees.

In the case of corporations, other than S corporations, which are “integrated oil companies,” the amount allowable as a deduction for intangible drilling costs in any taxable year is reduced by 30%. Integrated oil companies are:

those taxpayers who directly or through a related person engage in the retail sale of oil and natural gas and whose gross receipts for the taxable year from those activities exceed $5 million; or
those taxpayers and related persons who have average daily refinery runs in excess of 75,000 barrels for the taxable year.

Amounts of an integrated oil company’s intangible drilling costs that are disallowed as a current deduction under Section 291 of the Code are allowable, however, as a deduction ratably over the 60-month period beginning with the month in which the costs are paid or incurred. The partnership does not intend to engage in activity that would cause it to be treated as integrated oil company under the Code.

Your ability in any taxable year to use your share of these partnership 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 (3) 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 your share of the deduction for intangible drilling costs of the partnership.

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Drilling Contracts

Depending primarily on when the offering proceeds are received, the Managing GP anticipates that the partnership may prepay in the year in which its participants invest in the partnership most, if not all, of its intangible drilling costs for wells the drilling of which will begin within the first 90 days of the next tax year. As discussed above, the Code has special rules for determining when a taxpayer may deduct drilling costs and prepaid services. In a transaction that pre-dated the Code and regulations provisions cited above, the Tax Court in Keller v. Commissioner, 79 T.C. 7 (1982), aff’d 725 F.2d 1173 (8th Cir. 1984) (followed by Richard L. Sogg, TC Memo 1986-464; Ronald E. Jolley, TC Memo 1984-70), applied a two-part test for the current deductibility of prepaid intangible drilling and development costs. The test is:

the expenditure must be a payment rather than a refundable deposit; and
the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction.

The drilling partnership in Keller entered into footage and daywork drilling contracts that permitted it to terminate the contracts at any time, without a default by the driller, and receive a return of the prepaid amounts less amounts earned by the driller. The Tax Court found that the right to receive, by unilateral action, a refund of the prepayments on the footage and daywork drilling contracts rendered the prepayments deposits instead of payments. Therefore, the prepayments were held to be nondeductible in the year they were paid to the extent they had not been earned by the driller. The Tax Court further found that the drilling partnership failed to show a convincing business purpose for the prepayments under the footage and daywork drilling contracts.

The drilling partnership in Keller also entered into turnkey drilling contracts that permitted it to stop work under the contract at any time and apply the unearned balance of the prepaid amounts to another well to be drilled on a turnkey basis. The Tax Court found that these prepayments constituted “payments” and not nondeductible deposits, despite the right of substitution. Further, the Tax Court noted that the turnkey drilling contracts obligated “the driller to drill to the contract depth for a stated price regardless of the time, materials or expenses required to drill the well,” thereby locking in prices and shifting the risks of drilling from the drilling partnership to the driller. Because the drilling partnership, a cash basis taxpayer, received the benefit of the turnkey obligation in the year of prepayment, the Tax Court found that the amounts prepaid on turnkey drilling contracts clearly reflected income and were deductible in the year of prepayment.

In Caltex Oil Venture v. Commissioner, 138 TC 2 (2012), the Tax Court held that the term “drilling of the well commences” means that a spudding bit had been raised and released to begin the actual drilling within 90 days. The Tax Court rejected the taxpayer’s position that it was entitled to deduct intangible drilling costs because it performed acts normally required to be done before actual drilling, such as getting drilling permits and preparing the site.

The partnership will attempt to comply with the guidelines set forth in Keller and Caltex with respect to any prepaid intangible drilling costs. In this regard, the drilling and operating agreement will require the partnership to prepay all of the partnership’s share of the estimated intangible drilling equipment costs, for drilling and completing specified wells for the partnership, the drilling of which may begin in the next year. These prepayments of intangible drilling costs should not result in a loss of a current deduction for the intangible drilling costs in the year in which the partnership’s investors invest in the partnership if:

the guidelines set forth in Keller and Caltex are complied with;
there is a legitimate business purpose for the required prepayment;
the drilling of the well for which the partnership pre-paid the intangible drilling costs begins on or before the 90th day of the next year;
the contract is not merely a sham to control the timing of the deduction; and
there is an enforceable contract of economic substance.

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In this regard, the drilling and operating agreement will require the partnership to prepay the Managing GP’s estimate of the intangible drilling and equipment costs to drill and complete the wells specified in the drilling and operating agreement in order to enable the operator to:

begin site preparation for the wells;
obtain suitable subcontractors at the then current prices; and
insure the availability of equipment and materials.

For those contracts not entered into on a “turnkey” basis (contracts which set a price for drilling the well to a specified depth, regardless of the actual amount of time, materials, and expenses required to drill the well), the Managing GP will prepay the intangible drilling costs as estimated in the drilling and operating agreement. If the actual intangible drilling costs incurred are less than the prepaid amounts (excess prepaid intangible drilling costs), such amounts, if any, will not be refundable to the 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. Provided the applicable Code and Regulation sections and the guidelines set forth in Keller are otherwise met, 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 GP anticipates that less than 100% of the working interest will be acquired by the 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 partnership may exist under the facts and circumstances present at the time of prepayment for a specific drilling and operating contract, even though prepayments are not required by the operator with respect to a portion of the working interest in the wells.

Notwithstanding the foregoing, the partnership has not entered into any drilling and operating agreement as of the date of the prospectus. Therefore, special counsel cannot opine as to the deductibility as to any specific prepayment of intangible drilling costs by the partnership. 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. Finally, because the partnership expects to have its independent public accountant prepare its tax returns within 75 days after the end of the partnership’s taxable year, the partnership may not be able to provide you with the exact amount of the partnership’s prepaid intangible drilling costs for any year due to the 90 day time frame provided under the Code. See “— Method of Accounting,” above.

Depletion Allowance

Proceeds from the sale of the partnership’s oil and natural gas production will constitute ordinary income. A portion of that income may be offset by a depletion deduction, which permits a 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 the partnership sells a well at a gain), or your gain (if you sell your Interests at a gain), will be treated as ordinary income rather than capital gain to the extent of your previous deductions for depletion that reduced your adjusted basis in the property or your Interests. See “— Sale of the Properties” and “— Disposition of Interests,” 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. The partnership will allocate to you your share of the partnership’s adjusted tax basis in its properties based on your share of partnership capital on the date the partnership acquires the oil or gas property.The partnership will adjust your share of a property’s tax basis to account for the admission of new partners and the redemption of existing partners.

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Percentage depletion is available to taxpayers other than “integrated oil companies,” as that term is defined in “— Intangible Drilling Costs,” above. The partnership is not expected to be an integrated oil company. Your percentage depletion allowance is based on your share of the partnership’s gross production income (excluding rents or royalties paid) from its oil and natural gas properties. Under Code Section 613A(c), percentage depletion is available with respect to 6,000 cubic feet of average daily production of domestic natural gas multiplied by the number of barrels of your depletable oil quantity that you choose to apply to natural gas or 1,000 barrels of average daily production of domestic crude oil. Taxpayers who have both oil and natural gas production may allocate the production limitation between the types of production.

The rate of percentage depletion is 15%. However, percentage depletion for marginal production increases 1%, up to a maximum increase of 10%, for each whole dollar that the domestic wellhead price of crude oil for the immediately preceding year is less than $20 per barrel without adjustment for inflation. The term “marginal production” includes oil and natural gas produced from a domestic stripper well property, which is defined in Section 613A(c)(6)(E) of the Code as any property that 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. In this regard, the Managing GP has represented that little, if any, of the oil and natural gas production from the partnership’s productive wells will be marginal production under this definition in the Code and will qualify for these potentially higher rates of percentage depletion. The percentage depletion rate for marginal production is 15% in 2011 and the Managing GP anticipates that the rate of percentage depletion for marginal production in 2012 also will be 15%. This rate may fluctuate from year to year for oil and natural gas production from marginal wells, depending on the price of oil, but will not be less than the statutory rate of 15% nor more than 25%. Due to the partnership’s lack of marginal production and current prices, the partnership does not expect that you will receive a benefit from the potentially higher depletion rate.

Also, percentage depletion:

may not exceed 100% of the taxable income from the oil and natural gas property before the deduction for depletion for tax years beginning after December 31, 2011;
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 and, in the case of an investor that is a trust, any distributions to its beneficiaries. Any disallowed percentage depletion deductions under this limitation may be carried forward to the next taxable year; and
can be in excess of your share of the property’s tax basis.

The availability in any taxable year of the percentage depletion allowance must be computed separately by you and not by the partnership or for investors in the partnership as a whole. Nevertheless, as an administrative convenience to its partners, the partnership will compute what it believes to be the most favorable cost and percentage depletion amounts for the typical investor. For example, the partnership will assume that no partner’s depletion should be reduced as a result of the depletable oil quantity limitation described above. Notwithstanding the fact that the partnership will assist the partners in making depletion computations, the partners bear ultimate responsibility for the computation of depletion and the application of partner level limitations, such as the depletable oil quantity limitation and the 65% of net income limitation. Participants are able to obtain detailed information to make their own decision with respect to claiming cost or percentage depletion. You are urged to seek advice based on your particular circumstances from an independent tax advisor with respect to the availability of the percentage depletion allowance to you.

Depreciation and Cost Recovery Deductions

A portion of the offering proceeds from you and the other investors will be used to pay the equipment costs (i.e., “Tangible Costs”). The related depreciation deductions, i.e., cost recovery deductions under the modified accelerated cost recovery system (“MACRS”), will be allocated under the Limited Partnership Agreement among the partners.

The partnership expects that the reasonable Tangible Costs for equipment placed in its wells that cannot be deducted immediately will be recovered through depreciation deductions over a seven year cost recovery period, although different periods may apply based on the facts and circumstances of each piece of equipment acquired. The partnership will use the 200% declining balance method with a switch to straight-line to

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maximize the deduction, beginning in the taxable year in which the well is drilled, completed and made capable of production, (i.e., “placed in service”) by the partnership. In this regard, the Managing GP anticipates that it may take up to 12 months before all of the partnership’s wells are drilled, completed and placed in service for the production of natural gas or oil after the partnership’s final closing. In the case of a short partnership tax year, the MACRS deduction will be prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. Under Code Section 168(d)(1) of the Code, 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 cost of all equipment in a partnership’s wells placed in service during the year is placed in service during the last three months of the year. If that happens, then under Code Section 168(d)(3) the depreciation for the full year will be multiplied by a fraction based on the quarter the equipment 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 partnership and you and the other investors in the partnership are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property by the partnership or your Interests by you. See “— Sale of the Properties” and “— Disposition of Interests,” below. Depreciation for alternative minimum tax purposes, however, is computed using the 150% declining balance method switching to straight-line, for most personal property. This will result in adjustments in computing the alternative minimum taxable income of you and the other investors in the partnership in taxable years in which the partnership claims depreciation deductions, unless the equipment the partnership acquires is “qualified Indian reservation property” as defined in Code Section 168(j). See “— Alternative Minimum Tax,” below.

Also, if any equipment is acquired and placed in service in 2011 or 2012 by the partnership, the Participants in the partnership will be entitled to bonus depreciation of 100% or 50%, depending on the year) of the related Tangible Costs for qualified equipment, which will not be an adjustment for alternative minimum tax for the life of the equipment.

Your ability in any taxable year to use your share of these partnership 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 (3) in “— Special Counsel’s Opinions,” above.

Marginal Well Production Credits.

There is a marginal well production credit of 50¢ per Mcf of qualified natural gas production and $3.00 per barrel of qualified oil production for purposes of the regular federal income tax. A tax credit, unlike a tax deduction, reduces tax liability on a dollar-for-dollar basis. This credit is part of the general business credit under Section 38 of the Code, but under current law this credit cannot be used against the alternative minimum tax. See “— Alternative Minimum Tax,” below. Oil and natural gas production that qualifies as marginal production under the percentage depletion rules of Code Section 613A(c)(6) as discussed above in “— Depletion Allowance,” is also qualified marginal production for purposes of this credit. Also, the credit will be reduced proportionately if the reference prices for the previous calendar year are between $1.67 and $2.00 per Mcf for natural gas and $15.00 and $18.00 per barrel for oil. In this regard, the Managing GP anticipates that few of the partnership’s oil and natural gas properties will be treated as marginal production. Moreover, the partnership believes that none of the partnership’s oil and natural gas production in 2011, if any, will qualify for this credit, because as of the date of this prospectus the prices for oil and natural gas in 2011 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 for oil and natural gas in recent years compared with the prices at which the credit phases out completely, it may appear unlikely that the partnership’s oil and natural gas marginal production will ever qualify for this credit. However, prices for oil and natural gas are volatile and could decrease in the future. See “Risk Factors — Risks Related to the Partnership’s Oil and Gas Operations — The partnership’s revenues are directly related to its ability to market the oil and natural gas produced from the wells it drills and oil and natural gas prices, which are volatile and uncertain. If oil and natural gas prices decrease, then the return on your investment will decrease.” Thus, it is possible that the partnership’s marginal production of natural gas or oil in one or more taxable years after 2011 could qualify for the marginal well production credit, depending primarily on the applicable reference prices for oil and natural gas in the future. However, depending primarily on market prices for oil and natural gas, which are volatile, the partnership’s production of oil and natural gas may not qualify for marginal well production credits for many years, if ever.

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To the extent that your share of the partnership’s marginal well production credits, if any, exceeds your regular federal income tax owed on your share of the partnership’s taxable income, the excess credits, if any, can be used by you to offset any other regular federal income taxes owed by you, on a dollar-for-dollar basis, subject to the passive activity limitations if you invest in the partnership as a limited partner. See “— Limitations on Passive Activity Losses and Credits,” above. Also, if you invest in the partnership as an Investor General Partner, your share of the partnership’s marginal well production credits, if any, will be an active credit that may offset your regular federal income tax liability on any type of income. However, after you are converted to a limited partner in the partnership, your share of the partnership’s marginal well production credits, if any, will be active credits only to the extent of your regular federal income tax liability that is allocable to your share of any net income of the partnership from the sale of its oil and natural gas marginal production, since your share of that net income must continue to be treated by you as non-passive income even after you have been converted to a limited partner. See “— Conversion from Investor General Partner to Limited Partner,” above. Any credits allocable to you as a converted Investor General Partner in excess of that amount, as well as all of the marginal well production credits allocable to those investors who originally invest in the partnership as limited partners, will be passive credits that under current law can reduce only your regular income tax liability attributable to net passive income from the partnership or your other passive activities, if any, other than publicly traded partnership passive activities.

Tax Basis of Interests

Your share of the partnership’s losses is allowable only to the extent of the adjusted basis of your Interests at the end of the partnership’s taxable year. However, for the partnership’s oil and natural gas properties for which you choose to use the percentage depletion method you may claim depletion deductions in excess of your tax basis in the property subject to certain tax basis reduction rules for the “excess percentage depletion” upon an additional capital investment in the property. The adjusted basis of your Interests will be adjusted, but not below zero, for any gain or loss allocated 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:

cash subscription payment;
share of partnership income; and
share, if any, of partnership debt.

The adjusted basis of your Interests will be reduced by your:

share of partnership losses;
share of partnership expenditures that are not deductible in computing its taxable income and are not properly chargeable to capital account;
depletion deductions, but not below zero;
cash distributions from the partnership; and
any reduction in your share of your partnership’s debt, if any.

The reduction in your share of partnership liabilities, if any, is considered a cash distribution to you. Although the partnership does not intend for you to be personally liable on any partnership loans due to (i) the partnership’s intention to not borrow any money for its operations and (ii) the partnership’s intention that any borrowing will be nonrecourse to the partnership and its partners, if you invest in the partnership as an Investor General Partner you will be liable for other obligations of the partnership. See “Risk Factors — Risks Related to an Investment in the Partnership — If you choose to invest as an Investor General Partner, you will have unlimited joint and several liability for partnership obligations until you are converted to a Limited Partner.” Should cash distributions to you from the partnership exceed the tax basis of your Interests immediately before the distributions, taxable gain would result to you to the extent of the excess.

“At Risk” Limitation on Losses

You may use your share of the partnership’s losses to offset income from other sources to the extent that your use of those losses is not limited by the adjusted tax basis of your Interests (subject to any exception for percentage depletion) or the passive activity limitations on losses and credits, but only to the extent of the

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amount you have “at risk” in the partnership under Code Section 465 at the end of a taxable year. See “— Limitations on Passive Activity Losses and Credits” and “— Tax Basis of Interests,” above. “Loss,” for purposes of the “at risk” rules, means the excess of your share of the allocable deductions for a taxable year from the partnership (including your depletion deductions taken outside of the partnership) over the amount of income actually received or accrued by you during the year from the partnership. This “at risk” limitation on your share of the partnership’s losses, however, does not apply to you if you are a corporation that 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 owned more than 50% (in value) of the outstanding stock under Code Section 542(a)(2). See “— Limitations on Passive Activity Losses and Credits,” above, relating to the application of Code Section 469 to closely held C corporations for additional information on the stock ownership requirements under Code Section 542(a)(2).

Your initial “at risk” amount in the partnership will be equal to the amount of money you paid for your Interests. However, any amounts borrowed by you to buy your Interests will not be considered “at risk” if the amounts are borrowed from another investor in the partnership or anyone related to another investor in the partnership. In this regard, the Managing GP has represented that it and its affiliates will not make or arrange financing for you or any other potential investors to use to purchase Interests. Also, the amount you have “at risk” in the partnership will not include the amount of any loss that you are protected against through:

nonrecourse loans;
guarantees;
stop loss agreements; or
other similar arrangements.

The amount of any loss that exceeds your “at risk” amount in the partnership at the end of any taxable year must be carried forward by you to the next taxable year, and will then be available to the extent you are “at risk” in the partnership at the end of that taxable year. Further, your “at risk” amount in subsequent taxable years of the partnership will be reduced by any portion of the partnership loss that is allowable to you as a deduction.

Since income, gains, losses and distributions of the partnership will affect your “at risk” amount in the partnership, the extent to which you are “at risk” in the partnership must be determined annually. Previously allowed losses must be included in your gross income in the year that your “at risk” amount is reduced below zero. The amount included in your income, however, may be deducted in the next taxable year to the extent of any increase in the amount that you have “at risk” in your partnership.

Sale of the Properties

The maximum tax rate on a noncorporate taxpayer’s adjusted net capital gain on the sale of most capital assets held more than a year currently 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, the 5% tax rate on adjusted net capital gain will be reduced to 0%. These capital gain rates also apply for purposes of the alternative minimum tax. See “— Alternative Minimum Tax,” below. However, the former tax rates on adjusted net capital gain of 20% and 10%, respectively, are scheduled to be reinstated for taxable years beginning on or after January 1, 2013.

Gains from the sale by the partnership of an oil and natural gas property held by it for more than 12 months will be treated as long-term capital gain, except to the extent of depreciation recapture on equipment and recapture of intangible drilling costs and depletion deductions as discussed below, while a net loss will be an ordinary deduction. In addition, gain on the sale of the partnership’s oil and natural gas properties may be recaptured as ordinary income to the extent of a taxpayer’s non-recaptured Section 1231 losses (as defined below) for the five most recent preceding taxable years on previous sales, if any, of the taxpayer’s share of the partnership’s oil and natural gas properties or the taxpayer’s other assets. If, for any taxable year, the Section 1231 gains exceed the Section 1231 losses, the gains and losses will be treated as long-term capital gains or long-term capital losses, as the case may be. If the Section 1231 gains do not

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exceed the Section 1231 losses, the gains and losses will not be treated as gains and losses from sales or exchanges of capital assets. For this purpose, the term “Section 1231 gain” means any recognized gain:

on the sale or exchange of a property used in a trade or business; and
from the involuntary conversion into other property or money of:
property used in a trade or business; or
any capital assets that are held for more than one year and are held in connection with a trade or business or a transaction entered into for profit.

The term “Section 1231 loss” means any recognized loss from a sale or exchange or conversion described above.

The term “property used in a trade or business” means depreciable property and real property that are used in a trade or business and are held for more than one year, which are not inventory and are not held primarily for sale to customers in the ordinary course of a trade or business.

Net Section 1231 gain will be treated as ordinary income to the extent the gain does not exceed the non-recaptured net Section 1231 losses. The term “non-recaptured net Section 1231 losses” means the excess of:

the aggregate amount of the net Section 1231 losses for the five most recent taxable years; over
the portion of those losses taken into account to determine whether the net Section 1231 gain for any taxable year should be treated as ordinary income to the extent the gain does not exceed the non-recaptured net Section 1231 losses, as discussed above, for those preceding taxable years.

Other gains and losses on sales of oil and natural gas properties held by the partnership for less than 12 months, if any, will result in ordinary gains or losses.

In addition, as discussed above deductions for intangible drilling costs and depletion allowances that are incurred in connection with a natural gas or oil property may be recaptured as ordinary income when the property is sold or otherwise disposed of in a taxable transaction by the partnership. The amount of gain recaptured as ordinary income is the lesser of:

the aggregate amount of expenditures that have been deducted as intangible drilling costs with respect to the property and which, but for being deducted, would have been included in the adjusted basis of the property, plus deductions for depletion that reduced the adjusted basis of the property; or
the excess of:
the amount realized, in the case of a sale, exchange or involuntary conversion; or
the fair market value of the interest, in the case of any other taxable disposition;

over the adjusted basis of the property. The partnership generally will allocate its taxable income from the sale of its oil and natural gas properties first to those partners who received (or whose predecessors in interest received) allocations of Loss and intangible drilling costs from the property (and depletion taken by the partner outside of the partnership) with any excess gain allocated in accordance with the general allocation rules for Profits. See “— Intangible Drilling Costs” and “— Depletion Allowance,” above.

Also, all gain on the sale or other taxable disposition of equipment by the partnership will be treated as ordinary income to the extent of MACRS deductions previously claimed by the partnership. See “— Depreciation and Cost Recovery Deductions,” above.

Disposition of Interests

The sale or exchange, including a purchase by the Managing GP, of all or some of your Interests, if held by you as a capital asset for more than 12 months, will result in your recognition of long-term capital gain or loss, except for 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

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assets, services rendered or to be rendered, to the extent not previously includable in income under the partnership’s accounting methods, and deductions previously claimed by you for depreciation, depletion and intangible drilling costs with respect to the partnership. “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 Interests. Moreover, due to the operation of Code Section 751, a taxpayer may recognize both ordinary income and a capital loss on the disposition of the same Interest, even if the Interest is disposed at a loss. See “— Sale of the Properties,” above.

If you die, or sell or exchange all of your Interests, the taxable year of the partnership will close with respect to you, but not the remaining investors, on the date of death, sale or exchange, and there will be a proration of partnership items for the partnership’s taxable year. If you sell less than all of your Interests, 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.

If you sell or exchange all or some of your Interests, you are required under Section 6050K of the Code to notify the partnership within 30 days or by January 15 of the following year, if earlier. See “Transferability of Interests — Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Limited Partnership Agreement.” After receiving the notice, the partnership must file a return with the IRS setting forth the name and address of both you, as the transferor, and the transferee, the fair market value of the portion of the partnership’s unrealized receivables and appreciated inventory (i.e., Section 751 assets) allocable to the Interests sold or exchanged by you (which is subject to recapture as ordinary income instead of capital gain as discussed above) and any other information as may be required by the IRS. The partnership also must provide the person whose name is set forth in the return a written statement showing the information set forth on the return.

You are urged to seek advice based on your particular circumstances from an independent tax advisor before any sale or other disposition of your Interests, including any purchase of your Interests by the Managing GP.

Alternative Minimum Tax

With limited exceptions, under Section 55 of the Code you must pay an alternative minimum tax if it exceeds your regular federal income tax for the year. Alternative minimum taxable income (“AMTI”) is regular federal taxable income, plus or minus various adjustments, plus tax preference items. The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married individuals filing separately, of a taxpayer’s AMTI in excess of the applicable exemption amount (as set forth below); and additional AMTI 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. Exemption amounts for alternative minimum tax purposes are different from the regular tax personal exemptions, which are not allowed, and the types and amounts of itemized deductions allowed for minimum tax purposes are more limited than those allowed for regular tax purposes as discussed below.

For tax years beginning in 2011 only, the exemption amounts for individuals are the following amounts:

married individuals filing jointly and surviving spouses, $74,450, less 25% of AMTI exceeding $150,000;
unmarried individuals other than surviving spouses, $48,450, less 25% of AMTI exceeding $112,500; and
married individuals filing separately, $37,225, less 25% of AMTI exceeding $75,000. Also, AMTI of married individuals filing separately is increased by the lesser of $33,125 or 25% of the excess of AMTI (without regard to the exemption reduction) over $207,500.

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Absent future legislation from Congress, the exemption amounts for individuals for alternative minimum tax purposes in 2012 and subsequent years will be reduced substantially from those set forth above.

Code sections suspending losses, such as the rules concerning your “at risk” amount in the partnership, the amount of your passive activity losses from the partnership, and your basis in your Interests, are recomputed for alternative minimum tax purposes, and the amounts of the deductions that are suspended, or capital gains that are recaptured as ordinary income, may differ for regular income tax and alternative minimum tax purposes. Due to the inherently factual nature of these determinations and the investor’s different tax situation, special counsel is unable to express an opinion as to whether any investor will incur, or increase, his alternative minimum tax liability because of an investment in the partnership.

Some of the principal adjustments to taxable income that are used to determine an individual’s AMTI include those summarized below:

Depreciation deductions of the costs of the equipment placed in service in the wells (“Tangible Costs”) may not exceed deductions computed using the 150% declining balance method. These adjustments are discussed in greater detail below. See “— Depreciation and Cost Recovery Deductions,” above.
Miscellaneous itemized deductions are not allowed.
Medical expenses are deductible only to the extent they exceed 10% of adjusted gross income.
State and local income, property and general sales taxes are not deductible unless they are deductible in computing adjusted gross income for regular income tax purposes.
Interest deductions are restricted.
The standard deduction and personal exemptions are not allowed.
Only some types of operating losses are deductible.
Passive activity losses are computed differently.
Earlier recognition of income from incentive stock options may be required.

The principal tax preference items that must be added to taxable income for alternative minimum tax purposes include:

excess intangible drilling costs, as discussed below; and
tax-exempt interest earned on certain 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:

the preference for excess intangible drilling costs; and
the excess percentage depletion preference for oil and natural gas.

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 AMTI computed as if the excess intangible drilling costs preference had not been repealed. Under the prior rules, the amount of intangible drilling costs that is not deductible for alternative minimum tax purposes is the excess of the “excess intangible drilling costs” over 65% of net income from oil and natural gas properties. Net oil and natural gas 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 Code Section 59(e) to capitalize all or part of your share of the partnership’s intangible drilling costs (which as previously discussed do not include your share of the partnership’s

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intangible drilling costs of a re-entry well that are treated under the Code as operating costs, if any) 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:

your regular federal income tax deduction for intangible drilling costs in the year you invest will be reduced because you must spread the deduction for the amount of intangible drilling costs that you elect to capitalize over the 60-month amortization period; and
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, and passive activity losses and credits in the case of limited partners, the principal tax item that may have an impact on your AMTI as a result of investing in the partnership is depreciation of the partnership’s equipment expenses. See “— Limitations on Passive Activity Losses and Credits,” above. As noted in “— Depreciation and Cost Recovery Deductions,” above, the partnership’s cost recovery deductions for regular income tax purposes will be computed differently than for alternative minimum tax purposes. Consequently, in the early years of the cost recovery period of the partnership’s equipment, but not in the later years, 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 could cause you to incur, or may increase, your alternative minimum tax liability in those taxable years. Conversely, this adjustment may decrease your AMTI in the later years of the cost recovery period. Also, under current law, your share of the partnership’s marginal well production credits, if any, may not be used to reduce your alternative minimum tax liability, if any. In addition, the rules relating to the alternative minimum tax for corporations are different from those for individuals that are discussed above.

All prospective investors contemplating purchasing Interests 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 the partnership.

Limitations on Deduction of Investment Interest

Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income for the year, with an indefinite carryforward of disallowed investment interest expense deductions to subsequent taxable years. An Investor General Partner’s share of any interest expense incurred by the partnership before his Investor General Partner Interests are converted to limited partner Interests will be subject to the investment interest limitation. In addition, an Investor General Partner’s share of the partnership’s loss in the year he invests 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 the year he invests, with the disallowed portion to be carried forward to subsequent taxable years. This limitation on the deduction of investment interest expenses, however, will not apply to any income or expenses taken into account by limited partners in computing their income or loss from the partnership as a passive activity under Code Section 469. See “— Limitations on Passive Activity Losses and Credits,” above.

Allocations of Profit and Loss

Your share of any item of the partnership’s income, gain, loss, deduction or credit is determined by the Limited Partnership Agreement. When the partnership begins operations the partnership expects to allocate its profits first to reverse any losses that had been previously allocated to the partners and then to allocate 89% of the partnership’s profits among the Participants, and 11% to the Managing GP. However, the Managing GP’s interest may increase if it contributes additional capital to the partnership as set forth in the Limited Partnership Agreement. The partnership will also allocate profits to reverse prior losses, in reverse order of the losses so allocated. Starting with the partnership’s first fiscal year, profits allocated to Participants will be allocated among them in the first instance so as to cause their capital accounts, as determined on a per Interest basis and adjusted to reflect such items as their share of minimum gain, to be equal and thereafter in proportion to their Interests. Accordingly, during early periods, allocations of taxable income, gain, loss, deduction and credit may differ greatly from Interest to Interest and from the amount of cash distributed.

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If the partnership incurs losses after generating profits, such losses will be allocated 11% to the Managing GP and 89% to the Participants to reverse profits that were allocated in such 11%/89% ratio (or other ratio depending on the amount of the Managing GP’s contributed capital), described above. After reversing prior profits, if any, losses will be allocated between the Managing GP and the participants until the participants’ capital (or, for the Investor General Partners, their capital plus the amount they are obligated to contribute to the partnership) has been extinguished. All excess losses will be allocated to the Managing GP. Non-recourse deductions (deductions generally attributable to the partnership’s debt financed property, to the extent the partnership have any) will be allocated 11% to the Managing GP and 89% among the participants. Among the participants, starting with the partnership’s first fiscal year, losses allocated to the participants will be allocated among them in the first instance so as to cause their capital accounts, determined on a per Interest basis and adjusted to reflect such items as their shares of minimum gain, to be equal and thereafter in proportion to their Interests. Also, the basis of the oil and natural gas properties owned by the partnership for purposes of computing cost depletion and gain or loss on disposition of a property will be allocated and reallocated when necessary in the ratio of the Interests you own to the total Interests in the partnerships.

If the Managing GP or an affiliate makes a nonrecourse loan to the partnership (a “partner nonrecourse liability”), then the partnership’s losses, deductions, or Section 705(a)(2)(B) expenditures attributable to the loan must be allocated to the Managing GP. Also, if there is a net decrease in partner nonrecourse liability minimum gain with respect to the loan, the Managing GP must be allocated income and gain equal to the net decrease. In addition, any marginal well production credits of the partnership will be allocated among the Managing GP and you and the other investors in the partnership in accordance with the partner’s Interests.

The IRS respects a partnership’s allocation of income, gain, loss, deductions or credits if:

(a)  the allocation has economic effect and is substantial, or

(b)  the partners can show that the allocation accords with each partner’s respective interest in us, and

(c)  in the case of either (a) or (b), the allocation complies with special rules requiring that partners receiving allocations of losses or deductions generated by purchasing assets with borrowed money be charged back income and gain as those funds are repaid.

IRS regulations generally provide that, for an allocation to have economic effect, the following conditions must be true:

the allocation must be reflected by an increase or decrease in the relevant partner’s capital account, as those accounts are maintained under the applicable Treasury Regulations;
liquidation proceeds must be distributed in accordance with the partner’s positive capital account balances; and
the partnership agreement must provide that if a partner will have a deficit balance in his or her capital account upon liquidation of the partnership, the partner must be required to restore the deficit amount to the partnership, so that amount may be distributed to other partners with positive capital account balances. However, the Treasury Regulations provide that in the absence of an obligation to restore the deficit, the partnership agreement must contain a qualified income offset provision. A qualified income offset provision mandates that when a partner receives a distribution from the partnership that causes a deficit in the partner’s adjusted capital account (as defined in the Regulations) or increases a preexisting deficit, that partner must be allocated income and gains as quickly as possible to eliminate any deficit balance in his or her adjusted capital account that is greater than any amount that he or she is obligated to restore.

The economic effect of an allocation is substantial if there is a reasonable possibility that it will substantially affect the amount to be received by the partnership’s partners from us, independent of tax consequences. In addition, an economic effect is not substantial if, at the time the allocation becomes part of the Limited Partnership Agreement: (1) at least one partner’s after-tax return may, in present value terms, be enhanced compared to his or her return if the allocation were not contained in the Limited Partnership Agreement; and (2) there is a strong likelihood that no partner’s after-tax return will, in present value terms, be substantially diminished compared to his or her return if the allocation were not contained in the Limited

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Partnership Agreement. The Treasury Regulations on this issue state that, in determining after-tax return, a partner’s entire tax situation, including aspects unrelated to the partnership, will be taken into account.

When determining the after-tax return to a partner that is a “look-through entity” as defined in the Treasury Regulations (generally a partnership, Subchapter S corporation, trust, controlled foreign corporation, or disregarded entity), the partnership must consider the consequences to direct and indirect owners of the look-through entity partners. However, partners (either direct, indirect, or look-through) that own less than a 10% interest in our capital and profits and who are allocated less than 10% of each item of income, gain, loss, deduction and credit are not taken into account when testing substantiality (the “de minimis rule”). The Treasury has proposed regulations removing this de minimis testing rule that are proposed to be effective when final regulations are published in the Federal Register.

The Limited Partnership Agreement contains several provisions designed to ensure that allocations have a substantial economic effect, including:

(1)  It requires that all allocations of income, gains, losses, deductions and distributions are reflected by an increase or decrease in the relevant partners’ capital accounts.

(2)  All partners who are allocated losses and deductions generated by partnership assets acquired with borrowed money will be charged back income and gains generated by those assets.

(3)  While the Investor General Partners and the Managing GP having a deficit balance in his or her capital account after the final liquidating distribution will be required to make a cash contribution to the partnership to eliminate the deficit, for the limited partners and the Investor General Partners after conversion of their interests, the Limited Partnership Agreement contains a provision for a qualified income offset and requires that, upon liquidation, the partnership’s assets will be distributed to the partnership’s partners in accordance with such partners’ positive capital accounts (the Limited Partnership Agreement provides that the partnership’s assets will be distributed in accordance with the partners’ Distribution Interests, which is defined as the ratio of their respective positive capital account balances).

Based on the foregoing, the allocations provided in the Limited Partnership Agreement should be respected for tax purposes. However, depending on when a Participant acquired an Interest and for what price, it is possible that the allocations set forth in the Limited Partnership Agreement have the effect of providing deferral for that partner. If, for example, the participant obtaining deferral is an individual in the highest tax bracket while the participant currently allocated income is tax-exempt, the allocations in the Limited Partnership Agreement could be insubstantial. Nevertheless, because of the large number of expected partners, the partnership does not believe there is a strong likelihood of this occurring. If upon audit the IRS takes the position that any of those allocations should not be recognized, and if the IRS’s position were sustained by the courts, you could be taxed on a portion of the income allocated to the Managing GP or to another participant, and part of the deductions allocated to you could be disallowed or reallocated to another partner or to a different tax year. Also, if the partnership’s allocations fail to have economic effect or are deemed insubstantial, it may also affect the amount of tax basis attributable to the partnership’s oil and natural gas properties allocated to you.

If you sell or transfer your Interest, or on the death of an investor or the admission of an additional partner, the partnership’s income, gain, loss, credits and deductions will be allocated among its partners according to their varying interests in the partnership during the taxable year. Thus, a Participant who enters at the end of the partnership’s tax year generally will be allocated fewer partnership items than a Participant that enters earlier in the year. In addition, the Code may require the partnership’s property to be revalued on the admission of additional partners, if any, if disproportionate distributions are made to the partners, or if there are “built-in” losses in the partnership’s property at the time of the transfer of a partner’s Interests or any distribution of the partnership’s property to its partners. See “— Tax Elections,” below.

It also should be noted that your share of items of income, gain, loss, deduction, and credit, if any, in the partnership 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 the partnership to the repayment of loans, if any, 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

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income from the partnership for a particular year in excess of any cash distributions from the partnership to you with respect to that year. To the extent the partnership has cash available for distribution, however, it is the Managing GP’s policy that partnership cash distributions to you and the other investors in that partnership will not be less than the Managing GP’s estimate of the investors’ income tax liability (as a group) with respect to that partnership’s income.

If any allocation under the Limited Partnership Agreement is not recognized for federal income tax purposes, your share of the items subject to the allocation will be determined under the Code in accordance with your interest in the partnership by considering all of the relevant facts and circumstances. To the extent deductions or credits allocated by the Limited Partnership Agreement exceed deductions or credits that would be allowed under a reallocation of those tax items by the IRS, you may incur a greater tax burden.

Retroactive Allocations

Under Code Section 706(d), “retroactive allocations” — i.e., allocations of items to partners before they become partners — are prohibited. Code Section 706(d) and the Treasury Regulations thereunder effect this prohibition by providing that if there is a change of a partner’s interest in a partnership in any taxable year, each partner’s distributive share of partnership tax items is to be determined by any method prescribed in the Treasury Regulations that takes into account the varying interests of the partners in the partnership during that year. The Treasury has proposed Regulations implementing this provision. The Limited Partnership Agreement provides that the partnership’s items will, to the extent necessary in order to comply with Code Section 706(d), be allocated on a daily, monthly or other basis as determined by the Managing GP using any permissible method under Code Section 706(d) and the Treasury Regulations promulgated thereunder. If, as a result, an amount of profit or loss allocated to a partner is limited compared to what would otherwise have been the case with respect to the general rules regarding the allocation of profits and losses, such excess will be allocated to the other partners in relation to the amounts otherwise allocated to them. As a result, if some participants are admitted after others, they may receive a smaller portion of the partnership’s profits and losses (including its Intangible Drilling Costs and depletion taken outside of the partnership) even though they are required to contribute the same amount as those participants who were admitted earlier. As stated above, some of this disparity results from a timing issue that will resolve itself over the life of the partnership due to the partnership’s allocation provisions beginning in the partnership’s first Fiscal Year. However, a portion of this disparity may result from the receipt of additional cash distributions by those partners who invested earlier.

Estimated Tax Payments

You may be required to make estimated tax payments due to your liability for paying the taxes on your distributive share of the partnership’s taxable income. The partnership does not anticipate withholding or making payments to any taxing authority on behalf of the partnership’s partners. Nevertheless, there may be some circumstances under which the partnership is required to withhold on behalf of a partner. For example, under certain circumstances the partnership is required to withhold a foreign partner’s share of the partnership’s income effectively connected with the conduct of a U.S. trade or business. Some states where the partnership operates may also require the partnership to withhold their state specific income tax from the partnership’s distributions to you. If the partnership does withhold or make a payment to a governmental authority on your behalf, the partnership will treat any excess of that amount over your next entitled distribution as a demand loan carrying an interest rate of 12% per year.

For further information regarding the tax consequences of the partnership’s right or obligation to withhold or make a payment on your behalf, please consult your tax advisor.

Partnership Borrowings

Under the Limited Partnership Agreement, only the Managing GP and its affiliates may make loans to the partnership. The use of partnership revenues taxable to you to repay borrowings by the partnership, if any, 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 by the IRS as capital contributions to the partnership by the Managing GP or its affiliates in light of all of the surrounding facts and circumstances. Also, the “at risk” amounts of you and the other investors in the partnership, which limit the

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amount of partnership losses you and the other investors can claim as discussed in “— ‘At Risk’ Limitation on Losses,” above, will not be increased by the amount of any partnership borrowings from the Managing GP or its affiliates, because you and the other investors will not bear any risk of repaying the borrowings from your non-partnership assets, even if you invest in the partnership as an Investor General Partner.

O&O Costs

Expenses connected with the offer and sale of Interests, such as the dealer-manager fee, sales commissions, and other selling expenses, professional fees, and printing costs, are considered organization and offering costs and are not deductible. Organization expenses as described in Code Section 709 incident to the creation of the partnership will be amortized over a period of not less than 180 months. See —“Tax Elections” below.

Tax Elections

A partnership may elect to adjust the basis of its property (other than cash) on the transfer of a Interest 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 Section 754 election). If the Section 754 election is made, the transferees of the Interests are treated, for purposes of depreciation and gain, in a manner similar to a direct acquisition of 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, due to the complexities and added expense of the tax accounting required to implement a Section 754 election to adjust the basis of the partnership’s property when Interests are sold, taking into account the limitations on the sale of the partnership’s Interests as described in “Transferability of Interests,” the Managing GP anticipates that the partnership will not make the Section 754 election, although it reserves the right to do so. Even if the partnership does not make the Section 754 election, however, the basis adjustment described above is mandatory under the Code, with respect to the transferee partner only, if at the time an Interest 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 Interest. Similarly, a basis adjustment is mandatory under the Code if a partnership distributes cash or 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 Section 7.02 of the Limited Partnership Agreement, the partnership will not distribute its assets in-kind to its investors, except to a liquidating trust or similar entity for the benefit of its investors on the dissolution and termination of the partnership, unless at the time of the distribution its investors have been offered the election of receiving in-kind property distributions, and you or any other investor in the partnership accepts the offer after being advised of the risks associated with direct ownership; or there are alternative arrangements in place that assure you and the other investors in the partnership will not, at any time, be responsible for the operation or disposition of the partnership’s properties.

If the basis of the 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 partnership will not make in-kind property distributions to their respective investors except in the limited circumstances described above, and the Interests will have no readily available market and will be subject to substantial restrictions on their transfer. See “Transferability of Interests — Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Limited Partnership Agreement.” These factors will tend to reduce the likelihood that the partnership will be required to make mandatory basis adjustments to its properties, although a mandatory basis adjustment could occur with respect to the Managing GP due to the operation of the presentment provisions in our Limited Partnership Agreement.

In addition to the Section 754 election, the partnership may make various elections under the Code for federal tax reporting purposes that 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. Also,

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under Section 709 of 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:

paid or incurred in connection with:
investigating the creation or acquisition of an active trade or business;
creating an active trade or business; or
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
that would be allowable 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 the partnership’s expenses constituted start-up expenditures, the partnership’s deductions for those expenses, including your share, if any, of those deductions under the Limited Partnership Agreement would be amortized over the 180-month period.

Tax Returns and IRS Audits

The tax treatment of most partnership items is determined at the partnership, rather than the investor, level. Accordingly, you are required under the Code to treat the tax items of the partnership on your individual federal income tax returns in a manner that is consistent with the treatment of the partnership items on the partnership’s federal information income tax returns, unless you disclose to the IRS, by attaching the required IRS notice to your individual federal income tax return, that your tax treatment of the partnership’s tax items on your personal federal income tax returns is different from the partnership’s tax treatment of those partnership tax items. Treasury Regulations define partnership tax items for this purpose as including distributive share items that must be allocated among the investors, such as partnership liabilities, data pertaining to the computation of the depletion allowance, and guaranteed payments.

In most cases, the IRS must make an administrative determination as to partnership tax items at the partnership level before conducting deficiency proceedings against a partner, and the partners must file a request for an IRS administrative determination with respect to the partnership before filing suit for any credit or refund. Also, the period for assessing tax against you and the other investors because of a partnership tax item may be extended by agreement between the IRS and the Managing GP, which will serve as the partnership’s representative (“Tax Matters Partner”) in all administrative tax proceedings and tax litigation, if any, 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 the 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. Based on its past experience, the Managing GP anticipates that there will be more than 100 investors in the partnership in which Interests are offered for sale. However, by executing the Subscription Agreement you also are executing the Limited Partnership Agreement if your Subscription Agreement is accepted by the Managing GP. Under the Limited Partnership Agreement, you and the other investors in the partnership agree that you will not form or exercise any right as a member of a notice group and will 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.” 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 and the Managing GP does not anticipate that the partnership will make this election, although it reserves the right to do so.

All expenses of any tax proceedings involving the partnership and the Managing GP acting as Tax Matters Partner, which might be substantial, will be paid for by the partnership and not by the Managing GP from its own funds. The Managing GP, however, is not obligated to contest any adjustments made by the IRS to the partnership’s federal information income tax returns, even if the adjustment also would affect the individual federal income tax returns of you and the other investors in that partnership. The Managing GP will

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notify you and the other investors in your partnership of any IRS audits or other tax proceedings involving the partnership, and will provide you and the other investors any other information regarding the proceedings as may be required by the Limited Partnership Agreement or law.

Tax Returns

Your individual income tax returns are your responsibility. The 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

Under Section 183 of the Code, your ability to deduct your share of the partnership’s deductions could be limited or lost if the partnership lacks the appropriate profit motive as determined from an examination of all facts and circumstances at the time. Section 183 of 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 the partnership fails to show a profit in at least three out of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the partnership deductions claimed by 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 a remedy under Treasury Regulation Section 1.701-2. Finally, under Code Section 7701(o), which codified the potentially relevant judicial doctrines such as the step transaction, business purpose, economic substance, substance over form, and sham transaction doctrines, tax deductions and tax credits from a transaction, including the partnership’s deduction for intangible drilling costs in the year its investors invest in the partnership, would be disallowed if the partnership were found by the IRS or the courts, to have no economic substance apart from the tax benefits.

With respect to these issues, special counsel has given its opinion that the partnership will possess the requisite profit motive, and the IRS anti-abuse rule in Treasury Regulation 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 the partnership by a typical investor as described in special counsel’s opinions. The Managing GP’s representations include that the partnership will be operated as described in this prospectus (see “Management” and “Proposed Activities”) and the principal purpose of the partnership is to locate, produce and market oil and natural gas on a profitable basis to its investors, apart from tax benefits, as described in this prospectus. Also, see the information concerning the partnership’s proposed drilling areas in “Proposed Activities.”

Federal Interest and Tax Penalties

Finally, in enacting Code Section 7701(o), codifying the economic substance doctrine, Congress provided for specific penalties if the IRS found a taxpayer liable under the statute. If the partnership engage in a transaction to which the IRS successfully asserts the economic substance doctrine, the IRS will impose a 20% accuracy-related penalty. Additionally, if the partnership fails to disclose the relevant facts of a transaction against which the economic substance doctrine is applied, the transaction is treated as a “nondisclosed economic substance transaction” subject to a 40% accuracy related penalty. The penalties imposed on a transaction that lacks economic substance are subject to strict liability because the general reasonable cause exception for accuracy-related and fraud penalties in Code Section 6664(c) does not apply.

Taxpayers must pay tax and interest on underpayments of federal income taxes and the Code contains various penalties, including penalties for negligence and substantial valuation misstatements with respect to their individual federal income tax returns. In addition, there is a penalty equal to 20% of the amount of a substantial understatement of federal income tax liability. There is a substantial understatement by a noncorporate taxpayer if the correct income tax, as finally determined by the IRS or the courts, exceeds the income tax liability shown on the taxpayer’s federal income tax return by the greater of 10% of the correct tax, or $5,000. In the case of a corporation, other than an S corporation, or a personal holding company as defined in Section 542 of the Code, an understatement is substantial if it exceeds the lesser of: (i) 10% of the

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correct tax (or, if greater, $10,000); or (ii) $10 million). A noncorporate taxpayer may avoid this penalty if the understatement was not attributable to a “tax shelter,” as that term is defined below, and there is or 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 individual federal income tax return or a statement attached to the 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 the of the partnership for this purpose, the penalty may be avoided by a noncorporate taxpayer 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 that caused the understatement, and the taxpayer reasonably believed that his or her treatment of the item on his individual federal income tax return was more likely than not the proper treatment.

For purposes of this penalty, the term “tax shelter” includes a partnership if a significant purpose of the partnership is the avoidance or evasion of federal income tax. Because the IRS has not explained what a “significant” purpose of avoiding or evading federal income taxes means, special counsel cannot give an opinion as to whether the partnership is a “tax shelter” as defined by the Code for purposes of this penalty. However, the legislative history to such provisions as Code Section 7701(o) and other authority provide that it is not an abuse for a taxpayer to engage in an activity based on a tax incentive designed to encourage the taxpayer to engage in such activity.

Also under Section 6662A of the Code, there is a 20% penalty for reportable transaction understatements of federal income taxes on a taxpayer’s individual federal income tax return for any tax year. However, if the disclosure rules for reportable transactions under the Code and the Treasury Regulations are not met by the taxpayer, this penalty is increased from 20% to 30%, and a “reasonable cause” exception to the penalty that is set forth in Section 6664(d) of the Code will not be available to the taxpayer. Under Treasury Regulation Section 1.6011-4, a taxpayer who participates in a reportable transaction in any taxable year must attach to his individual federal income tax return IRS Form 8886 “Reportable Transaction Disclosure Statement,” and file it with the IRS as directed in the Treasury Regulation, in order to comply with the disclosure rules.

A tax item is subject to the reportable transaction rules if the tax item is attributable to:

any listed transaction, which is a transaction that is the same as, or substantially similar to, a transaction that the IRS has publicly pronounced to be a tax avoidance transaction; or
any of four additional types of reportable transactions, if a significant purpose of the transaction is federal income tax avoidance or evasion.

A “loss transaction” is one type of reportable transaction, but only if a “significant” purpose of the transaction is federal income tax avoidance or evasion. As set forth above in discussing the definition of tax shelter, special counsel cannot give an opinion with respect to whether or not the partnership has a “significant” purpose of avoiding federal income taxes, because the IRS has not explained what that phrase means for purposes of this penalty. Subject to the foregoing, under Treasury Regulation Section 1.6011-4(b)(5), there is a loss transaction if the partnership or any of its non-corporate partners claims a loss under Section 165 of the Code of at least $2 million, in the aggregate, in any taxable year of the partnership, or at least $4 million, in the aggregate, over the partnership’s first six years (or any rolling 6 year period). Based on its expected operations, the partnership will not engage in a reportable transaction under Section 6707A(c) of the Code. Nevertheless, a reportable transaction may occur if the partnership incurs greater than expected losses.

For purposes of the “loss transaction” rules, a Section 165 loss includes an amount deductible under a provision of the Code that treats a transaction as a sale or other disposition of property, or otherwise results in a deduction under Code Section 165. A Section 165 loss includes, for example, a loss resulting from a sale or exchange of a partnership interest, such as an investor’s Interests. The amount of a Section 165 loss is adjusted for any salvage value and for any insurance or other compensation received. However, a Section 165 loss for this purpose does not take into account offsetting gains or other income limitations under the Code. In addition, in special counsel’s opinion the partnership’s losses resulting from deductions claimed for intangible

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drilling costs for productive wells properly should be treated as losses under Section 263(c) of the Code and Treasury Regulation Section 1.612-4(a), and should not be treated as Section 165 losses for purposes of the “loss transaction” rules under Treasury Regulation Section 1.6011-4(b)(5). However, the partnership may incur losses under Section 165 of the Code, such as losses for the abandonment by a partnership of:

wells drilled that are nonproductive (i.e., a “dry hole”), if any, in which case the intangible drilling costs, the Tangible Costs, and possibly the lease acquisition costs of the abandoned wells would be deducted as Section 165 losses; and
wells that have been operated until their commercial oil and natural gas reserves have been depleted, in which case the undepreciated Tangible Costs, if any, and possibly the lease acquisition costs, would be deducted as Section 165 losses.

If any of the partnership’s transactions constitute reportable transactions, the partnership will notify you of such transactions. You should consult your own tax advisor as to the reporting on your tax return of any reportable transactions.

State and Local Taxes

The partnership will operate in states and localities that may impose a tax on it, or on you and the partnership’s other investors, based on the partnership’s assets or income or your share of its assets or income. Some states and localities in which the partnership may operate may or currently impose a filing requirement with that state or locality because of the Interests you own. Also, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax on the partnership as an entity, the partnership’s cash available for distribution to you and its other investors would be reduced. The partnership also may be subject to state income tax withholding requirements on its income allocable to you and its other investors, whether or not the revenues that created the income are distributed to you and its other investors.

Deductions and credits, including federal marginal well production credits, if any, which may be available to you for federal income tax purposes, may not be available to you for state or local income tax purposes. If you reside in a state or locality that imposes income taxes on its residents, you likely will be required under those income tax laws to include your share of your partnership’s net income or net loss 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 another 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 the partnership’s operations in a state or 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.

The partnership’s Interests may be sold in all 50 states, the District of Columbia and other jurisdictions, and it is not practical for special counsel to evaluate the many different state and local tax laws that may affect an investment in the partnership. You are urged to seek advice based on your particular circumstances from an independent tax advisor to determine the effect state and local taxes may have on you in connection with an investment in the partnership.

Severance and Ad Valorem (Real Estate) Taxes

The partnership will incur various ad valorem or severance taxes imposed by state or local taxing authorities on its oil and natural gas wells and/or oil and natural gas production from the wells. These taxes will reduce the amount of the partnership’s cash available for distribution to you and its other investors.

Social Security Benefits and Self-Employment Tax

A limited partner’s share of income or loss from the partnership is excluded from the definition of “net earnings from self-employment.” Unless it is considered a guaranteed payment for services actually rendered to or on behalf of the partnership, no increased benefits under the Social Security Act will be earned by limited partners and if any limited partners are currently receiving Social Security benefits, their shares of partnership taxable income will not be taken into account in determining any reduction in benefits because of “excess earnings.”

An Investor General Partner’s share of income or loss from the partnership will constitute “net earnings from self-employment” for these purposes. For self-employment income earned in 2011, the ceiling for social

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security tax of 10.4% is $106,800, which will be adjusted annually for inflation in subsequent years. Unless the law changes, the Social Security tax rate will rise to 12.4% in 2012. 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 the 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 (i.e., anyone other than the partnership) from the farmor (i.e., 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 GP has represented that it will attempt to eliminate or reduce any gain to the partnership from a farmout, if any. However, if the IRS claims that a farmout by the partnership results in taxable income to the partnership and its position is ultimately sustained, you and the other investors in the partnership would be required to include your share of the resulting taxable income on your individual income tax returns, even though the partnership and you and the other investors in the partnership received no cash from the farmout.

Foreign Partners

The partnership generally 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 seek a refund on his individual United States federal income tax return. 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, a foreign partnership, and a foreign trust or estate, unless the investor has certified to the partnership the investor’s status as a U.S. person on Form W-9 or any other form permitted by the IRS for that purpose.

The partnership intends to repurchase the Interests owned by any foreign investor. The partnership may be required to withhold a portion of the foreign investors proceeds on that transaction under Code Section 1445.

Additional Hospital Insurance Tax

For tax years beginning after December 31, 2012, new Code Section 1411 imposes a tax on individuals, estates, and trusts. For individuals, the tax equals 3.8% of the lesser of (a) the individual’s net investment income or (b) the excess of the individual’s modified adjusted gross income (determined in accordance with Code Section 1411) for the year over the threshold amount (generally $250,000 for a taxpayer filing a joint return or a surviving spouse, $125,000 for a married taxpayer filing a separate return, and $200,000 for all other filers). For estates and trusts, the tax imposed equals 3.8% of the lesser of (a) the undistributed net investment income or (b) the excess of the adjusted gross income for the year over the dollar amount at which the highest tax bracket for estates and trusts begins. For Code Section 1411 purposes, net investment income generally includes passive activity income and portfolio income. Thus, for tax years beginning after December 31, 2012, the partnership expects that an individual, estate, or trust limited partner will be required to include his, her or its distributive share of the partnership’s income, gain, loss, and deduction when computing his, her or its net investment income for purposes of Code Section 1411. Although this provision does not apply to the Investor General Partners, such Investor General Partners will be required to include their distributive share of the partnership’s income and loss in the net earnings from self-employment for purposes of calculating their self-employment tax, as described above.

Corporate Investors

The federal income tax consequences to investors that are corporations may differ materially from the tax consequences discussed in this section, particularly as they relate to the alternative minimum tax. Such investors should consult with their tax advisors as to the tax consequences to them of this investment.

Tax Treatment of Certain Trusts and Estates

The tax treatment of trusts and estates can differ from the tax treatment of individuals, investors who are trusts and estates should consult with their tax advisors regarding the applicability of the tax rules discussed in this section.

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Taxation of Tax-Exempt Organizations

Charitable and other tax-exempt organizations, including qualified pension plans and individual retirement accounts, are subject to the unrelated business income tax. Under rules adopted as part of the Tax Relief and Health Care Act of 2006, a charitable remainder trust that has unrelated business taxable income is subject to an excise tax equal to 100% of such income. Tax-exempt investors will be deemed to be engaged in the business carried on by the partnership and will be subject to the unrelated business income tax. Such investors should consult with their tax advisors regarding the tax consequences to them of investing in the partnership’s Interests. In addition, exempt investors that are required to distribute a certain portion of their assets every year, such as IRAs and 401(k) plans subject to the mandatory distribution requirements, should consider the fact that there will not be any market for the Interests when determining their ability to satisfy such mandatory distribution requirements.

Gifts of Interests

Generally, no gain or loss is recognized upon the gift of property. A gift of Interests, however, including a charitable contribution, may be treated partially as a sale, to the extent of your share of the partnership’s non-recourse liabilities. You may be required to recognize gain in an amount equal to the difference between your share of non-recourse indebtedness and, in the case of a charitable contribution, the portion of the basis in the Interests allocable to that deemed sale transaction. In the event of a non-charitable gift, the amount of your share of the non-recourse indebtedness is offset by your entire basis in the Interests. Charitable contribution deductions for the fair market value of the Interests will be reduced by the amounts involved in such a partial sale and, in any event, may be subject to reduction in certain cases by the amount of gain that would be taxed as ordinary income on a sale of your Interests.

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INVESTMENT BY QUALIFIED PLANS AND IRAS

Fiduciaries Under ERISA

Investors that are fiduciaries of qualified plans are subject to certain requirements under the federal law commonly known as ERISA. These requirements include the duty to discharge their responsibilities solely in the interest of, and for the benefit of, the qualified plan’s participants and beneficiaries. A fiduciary must:

perform its duties with the skill, prudence and diligence of a prudent person;
diversify the qualified plan’s investments so as to minimize the risk of large losses; and
act in accordance with the qualified plan’s governing documents.

Fiduciaries of qualified plans include anyone who exercises any authority or control over the management or disposition of the funds or other property of the qualified plan. For example, any person responsible for choosing a qualified plan’s investments, or who is a member of a committee that is responsible for choosing a qualified plan’s investments, is a fiduciary of the qualified plan. Also, an investment professional who renders or who has the authority or responsibility to render investment advice regarding the funds or other property of a qualified plan is a fiduciary of that qualified plan, along with any other person with special influence with respect to a qualified plan’s investment or administrative activities.

IRAs generally are not subject to ERISA’s fiduciary duty rules although they are subject to the rules against engaging in prohibited transactions. In addition, a participant who exercises control over his or her individual account in the qualified plan in a self-directed investment arrangement generally will be held responsible for the consequences of his or her investment decisions.

A person subject to ERISA’s fiduciary rules with respect to a qualified plan should consider those rules in the context of the particular circumstances of the qualified plan before authorizing or making an investment in the Interests with a portion of the qualified plan’s assets.

Prohibited Transactions Under ERISA and the Tax Code

The Code and ERISA prohibit qualified plans and IRAs from engaging in certain transactions involving assets of the qualified plan or IRA with parties that are referred to as disqualified persons or parties in interest. Disqualified persons include fiduciaries of the qualified plan or IRA, officers, directors and certain shareholders and other owners of the company sponsoring the qualified plan, and persons and legal entities sharing certain family or ownership relationships with other disqualified persons. In addition, the beneficiary of an IRA is generally considered to be a disqualified person for purposes of the prohibited transaction rules.

Types of prohibited transactions include:

direct or indirect transfers of a qualified plan’s or IRA’s assets to, or use by or for the benefit of, a disqualified person;
acts by a fiduciary involving the use of a qualified plan’s or IRA’s assets in the fiduciary’s individual interest or for the fiduciary’s own account; and
a fiduciary receiving consideration for his or her own personal account from any party dealing with a qualified plan or IRA in connection with a transaction involving the assets of the qualified plan or IRA.

Under ERISA, a disqualified person that engages in a prohibited transaction will be required to disgorge any profits made from the transaction and will be required to compensate the qualified plan for any losses it sustains. The Code imposes excise taxes on a disqualified person that engages in a prohibited transaction with a qualified plan or IRA. Prohibited transactions subject to these sanctions must generally be unwound to avoid incurring additional penalties. In addition, if you engage in a prohibited transaction with an IRA in which you are a beneficiary, the IRA ceases to be treated as an IRA and, therefore, all of the assets are treated as if they are distributed to you in the year in which such transaction occurred.

In order to avoid the occurrence of a prohibited transaction under the Code or ERISA, Interests may not be purchased by a qualified plan or IRA from assets owned or controlled by the partnership or from assets for which the partnership or any of its affiliates are fiduciaries.

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Plan Assets

If the partnership’s assets are determined under ERISA or the Code to be plan assets of qualified plans and/or IRAs owning the Interests, fiduciaries of such qualified plans and IRAs might be subject to liability for actions that the partnership takes. In addition, some of the activities described in this prospectus in which the partnership might engage might constitute prohibited transactions under the Code and ERISA for qualified plans and IRAs, even if their purchase of the Interests did not originally constitute a prohibited transaction. Moreover, fiduciaries with responsibilities to qualified plans and/or IRAs subject to ERISA’s fiduciary duty rules might be deemed to have improperly delegated their fiduciary responsibilities to the partnership in violation of ERISA.

In some circumstances, ERISA and the Code apply a look-through rule under which the assets of an entity in which a qualified plan or IRA has invested may constitute plan assets and the manager of the entity becomes a fiduciary to the qualified plan or IRA. ERISA and the Code, however, exempt from the look-through principle investments in certain publicly registered securities and in certain operating companies, as well as investments in entities not having significant equity participation by benefit plan investors. Under the Department of Labor’s current regulations, undivided interests in the underlying assets of a collective investment entity such as the partnership will not be treated as plan assets of qualified plan or IRA investors if either:

the Interests are publicly offered;
less than 25% of any class of the Interests are owned by qualified plans, IRAs and certain other employee benefit plans; or
the partnership is an operating company.

To qualify for the publicly-offered exception, the Interests must be freely transferable, owned by at least 100 investors independent of the partnership and of one another, and either (a) be part of a class of securities registered under Section 12(b) or 12(g) of the Securities Exchange Act of 1934 or (b) sold as part of a public offering pursuant to an effective registration statement under the Securities Act of 1933 and registered under the Securities Exchange Act of 1934 within 120 days after the end of the partnership’s fiscal year during which the partnership’s offering occurred. The Interests are being sold as part of an offering registered under the Securities Act of 1933. Accordingly, whether the Interests will qualify for the publicly-offered exception will depend whether they are freely transferable within the meaning of the Department of Labor’s regulations.

Whether the Interests are freely transferable is a factual determination. However, the partnership believes that the limits on assigning the Interests and on substituting partners contained in the Limited Partnership Agreement fall within the scope of certain restrictions that are permitted by the Department of Labor regulations. These regulations will not cause a determination that securities are not freely transferable when the minimum investment is not greater than $10,000.

Whether the partnership’s assets will constitute “plan assets” is a factual issue that may depend in large part on the partnership’s ability throughout its life to satisfy either the publicly-offered shares exception or the 25% ownership exception. Accordingly, the partnership’s counsel is unable to express an opinion on this issue.

Other ERISA Considerations

In addition to the above considerations in connection with the “plan asset” question, a fiduciary’s decision to cause a qualified plan or IRA to acquire the Interests should involve, among other factors, considerations that include whether:

the investment is in accordance with the documents and instruments governing the qualified plan or IRA;
the purchase is prudent in light of the diversification-of-assets requirement for the qualified plan and the potential difficulties that may exist in liquidating the Interests;
the investment will provide sufficient cash distributions in light of the qualified plan’s likely required benefit payments and other needs for liquidity;

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the investment is made solely in the interests of plan participants;
the evaluation of the investment has properly taken into account the potential costs of determining and paying any amounts of federal income tax that will be owed on unrelated business taxable income derived from the partnership’s business affairs; and
the current value of the Interests will be sufficiently ascertainable, and with sufficient frequency, to enable the qualified plan or IRA to value its assets in accordance with the rules and policies applicable to the qualified plan or IRA.

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SUMMARY OF LIMITED PARTNERSHIP AGREEMENT

The partnership will be governed by the Delaware Revised Uniform Limited Partnership Act. The rights and obligations of the Managing GP and the investors in the partnership are governed by the form of Limited Partnership Agreement, a copy of which attached as Exhibit A to this prospectus. You are urged to thoroughly review the Limited Partnership Agreement before you decide to invest in the partnership. The following is a summary of the material provisions in the Limited Partnership Agreement.

Liability of Investors

Investor General Partners

If you invest as an Investor General Partner, you will have joint and several liability to third parties for the obligations of the partnership. The Managing General Partner indemnifies each of the Investor General Partners against all partnership-related liabilities that 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 indemnifies each Investor General Partner against any personal liability as a result of the unauthorized acts of another Investor General Partner.

Limited Partners

If you invest as a Limited Partner, then generally you will not be liable to third-parties for the obligations of the partnership unless you:

also invest as an Investor General Partner;
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
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 from the partnership if you knew at the time the distribution was made that it was improper because it rendered the partnership insolvent.

Amendments

Amendments to the Limited Partnership Agreement may be proposed in writing by:

the Managing GP and adopted with the consent of investors whose Interests equal a majority of the total Interests in the partnership; or
investors whose Interests equal 10% or more of the total Interests in the partnership and adopted by an affirmative vote of investors whose Interests equal a majority of the total Interests in the partnership.

The Limited Partnership Agreement may also be amended by the Managing GP without the consent of the investors for certain limited purposes, including but not limited to:

to add to the representations, duties or obligations of the Managing GP or to surrender any right or power granted to the Managing GP in the Limited Partnership Agreement;
to cure any ambiguity, to correct or supplement any provision in the Limited Partnership Agreement that may be inconsistent with any other provision therein or to add any other provision with respect to matters or questions arising under the Limited Partnership Agreement that will not be inconsistent with its terms;
to preserve the status of the partnership as a “partnership” for federal income tax purposes (or under Delaware law or any comparable law of any other state in which the partnership may be required to be qualified);
to delete or add any provision of or to the Limited Partnership Agreement required to be so deleted or added by the staff of the SEC, by any other federal or state regulatory body or other agency (including, without limitation, any “blue sky” commission) or by any administrator or similar such official;

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to permit the Interests to fall within any exemption from the definition of “plan assets” contained in Section 2510.3-101 of Title 29 of the Code of Federal Regulations;
if the partnership is advised by counsel, by the partnership’s accountants or by the IRS that any allocations of income, gain, loss or deduction provided for in the Limited Partnership Agreement are unlikely to be respected for federal income tax purposes, to amend the allocation provisions thereof, in accordance with the advice of such counsel, such accountants or the IRS, to the minimum extent necessary to effect as nearly as practicable the plan of allocations and distributions provided in the Limited Partnership Agreement;
to effect any change necessitated by a change in law or regulation that causes the terms and conditions set forth in this prospectus and/or the Limited Partnership Agreement to be, in the sole discretion of the Managing GP, no longer viable; provided, that such change shall be drawn as narrowly as possible so as to effectuate the original intent of this prospectus and the Limited Partnership Agreement; and
to change the name of the partnership or the location of its principal office.

However, an amendment that materially and adversely affects the investors may only be made with the consent of the affected investors. For example, an amendment may not do the following without the approval of the investors:

increase the duties or liabilities of the investors;
decrease the duties or liabilities of the Managing GP;
decrease the investors’ profit sharing interest;
increase the investors’ loss sharing interest;
increase the required capital contribution of the investors; or
decrease the required capital contribution of the Managing GP.

Notice

The following provisions apply regarding notices:

when the Managing GP gives the investors notice it begins to run from the date of mailing the notice and is binding even if it is not received;
the notice periods are frequently quite short, a minimum of 22 calendar days, and apply to matters that may seriously affect your rights; and
if you fail to respond in the specified time to the Managing GP’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 Limited Partnership Agreement expressly requires your affirmative approval.

Voting Rights

Other than as set forth below, you generally will not be entitled to vote on any partnership matters at any partnership meeting. At any time, however, investors whose Interests equal 10% or more of the total Interests in the partnership may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of the Managing GP. Such call for a meeting will be deemed to have been made upon receipt by the Managing GP of a written request from holders of the requisite percentage of Interests stating the purposes(s) of the meeting. The Managing GP will deposit in the United States mails within 15 days after receipt of said request, written notice to all investors of the meeting and the purpose of such meeting, which will be held on a date not less than 30 nor more than 60 days after the date of mailing of said notice, at a reasonable time and place; provided however, that the date for notice of such a meeting may be extended for a period of up to 60 days, if, in the opinion of the Managing GP, such additional time is necessary to permit preparation of proxy or information statements or other documents required to be delivered in connection with such meeting by the SEC or other regulatory authorities. Investors will have the right to vote in person or by proxy on any such partnership matters. On the matters being voted on you are

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entitled to one vote per Interest or if you own a fractional Interest that fraction of one vote equal to the fractional interest in the Interest. Investors whose Interests equal a majority of the total Interests in the partnership may vote to:

dissolve the partnership;
remove the Managing GP and elect a new Managing GP;
elect a new Managing GP if the Managing GP elects to withdraw from the partnership;
remove the operator and elect a new operator;
approve or disapprove the sale of all or substantially all of the partnership’s assets;
cancel any contract for services with the Managing GP, an operator, or their affiliates without penalty on 60 days notice; and
amend the Limited Partnership Agreement; provided, however, that no amendment may, without the approval of the affected party, increase the duties or liabilities, or the profits or losses or required capital contribution, of such party.

The Managing GP, its officers, directors, and affiliates may also subscribe for Interests in the partnership on a discounted basis, and they may vote on all matters, including the issues set forth above, other than:

removing the Managing GP and/or an operator; and
any transaction between the Managing GP or its affiliates and the partnership.

Any Interests owned by the Managing GP and its affiliates will not be included in determining the requisite number of Interests necessary to approve any partnership matter on which the Managing GP and its affiliates may not vote or consent.

Access to Records

You will have access to all records of the partnership at any reasonable time on adequate notice. The Managing GP will maintain and preserve during the term of the partnership and for four years thereafter all such records. However, logs, well reports, and other drilling and operating data may be kept confidential for reasonable periods of time. Also, your ability to obtain the list of investors is subject to additional requirements set forth in the Limited Partnership Agreement.

Withdrawal of Managing GP

After 10 years the Managing GP may voluntarily withdraw as Managing GP for any reason by giving 120 days’ prior written notice to the investors. Although the withdrawing Managing GP is not required to provide a substitute Managing GP, a new Managing GP may be substituted by the affirmative vote of investors whose Interests equal a majority of the total Interests in the partnership. If the investors, however, choose not to continue the partnership and do not select a substitute Managing GP, then the partnership would dissolve and terminate, which could result in adverse tax and other consequences to you.

Also, the Managing GP may assign its general partner interest in the partnership to its affiliates, and it 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 at any time if the withdrawal is:

to satisfy the bona fide request of its creditors; or
approved by investors in the partnership whose Interests equal a majority of the total Interests.

In the event of the withdrawal of the Managing GP as Managing GP, the incoming Managing GP and the withdrawing Managing GP will, by mutual agreement, select an independent expert to value the withdrawing Managing GP’s interest in the partnership. In determining the value of the Managing GP’s interest, the independent expert will take into account appropriate discount factors in light of the risk of recovery of oil and gas reserves, and, in any event, will utilize a risk factor discount no less than that utilized in the most recent offer extended relating to cash redemptions, if any. The incoming Managing GP, or the partnership, will have the option to purchase at least 20% of the interests of the withdrawing Managing GP, the value of which

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determined by the expert. The method of payment for such interest must be fair and must protect the solvency and liquidity of the partnership. The method of payment will be deemed presumptively fair where it provides for a non-interest bearing unsecured promissory note with principal payable, if at all, from distributions that the withdrawing Managing GP otherwise would have received under the Limited Partnership Agreement had the Managing GP not withdrawn.

The Managing GP may not voluntarily withdraw prior to the partnership’s completion of its primary drilling and/or acquisition activities, and then only after giving 120 days prior written notice. The Managing GP may not partially withdraw its property interests held by the partnership unless such withdrawal is necessary to satisfy the bona fide request of its creditors or approved by a majority in interest vote of the partners. The Managing GP must fully indemnify the partnership against any additional expenses that may result from a partial withdrawal of property interests and such withdrawal may not result in a greater amount of Direct Costs or Administrative Costs being allocated to the partners. The withdrawing Managing GP will pay all expenses incurred as a result of its withdrawal.

Return of Subscription Proceeds if Partnership Is Not Invested in Twelve Months

Although the Managing GP anticipates that the partnership will spend all of its subscription proceeds soon after the offering of the partnership closes, the partnership will have 12 months in which to use or commit its subscription proceeds to drilling activities. If within the 12-month period, the partnership has not used, or committed for use, all of its subscription proceeds, then the Managing GP will distribute the remaining subscription proceeds to the investors in the partnership in accordance with your respective subscription amounts as a return of capital.

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SUMMARY OF PARTICIPATION AGREEMENT AND OPERATING AGREEMENT

The partnership will enter into a Participation Agreement (including an attached operating agreement) with the operator for each Project in which it participates. A form of Participation Agreement is attached to this prospectus as Exhibit B.

Generally, each Participation Agreement will detail the economic terms of the partnership’s participation in the related Project. In addition, the related operating agreement sets forth the relevant terms that govern the operator’s drilling activities.

Each Participation Agreement will generally include the material provisions set forth below.

The partnership’s working interest ownership percentage.
The operator’s compensation.
The right of the operator to enter into oil and natural gas sales contracts.
The intended net revenue interest for each well subject to the Participation Agreement.
Consequences, if any, of the partnership not participating in all wells within a Project.

Each operating agreement will generally include the material provisions set forth below.

Resignation or replacement of the operator.
The operator’s right to retain funds to cover future plugging and abandonment costs of the wells.
The grant of a first lien and security interest in the wells and related production to secure payment of amounts due to the operator by the partnership.
The prescribed insurance coverage to be maintained by the operator.
Limitations on the operator’s authority to incur extraordinary costs with respect to producing wells.
The ability of the partnership to transfer its interest the wells.
The scope of the operator’s liability to the partnership.
The excuse for nonperformance by the operator due to force majeure, which generally means acts of God, catastrophes and other causes that preclude the operator’s performance and are beyond its control.

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REPORTS TO INVESTORS

Under the Limited Partnership Agreement, you and certain state securities commissions will be provided the reports and information set forth below for the partnership, which the partnership will pay as a direct cost.

Beginning with the calendar year in which the partnership closes this offering, you will be provided an annual report within 120 days after the close of the calendar year, in addition to the partnership’s Annual Report on Form 10-K that will be publicly available with the Securities and Exchange Commission through its website, 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.

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.
A summary of the total fees and compensation paid by the partnership to the Managing GP, the operator(s), and their affiliates. 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 administrative cost allocations was consistent with the method described in Section 4.04(a)(2)(c) of the Limited Partnership Agreement (actual costs charged based upon the percentages of time of the relevant personnel of the Managing GP) and that the total amount of administrative costs allocated did not materially exceed the amounts incurred by the partnership. If the Managing GP subsequently decides to allocate administrative costs in a manner different from that described in Section 4.04(a)(2)(c) of the Limited Partnership Agreement, then the change must be reported to the investors with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.
A description of each Project in which the partnership is participating, including the cost, location, number of acres, and the working interest percentage.
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.
A description of all farmouts, farmins and joint ventures.
A schedule reflecting:
º the total partnership costs;
º the costs paid by the Managing GP and the costs paid by the investors;
º the total partnership revenues; and
º the revenues received or credited to the Managing GP and the revenues received or credited to the investors.

On request, the Managing GP will provide you the information specified by the Quarterly Report on Form 10-Q within 60 days after the close of each quarterly fiscal period, in addition to the partnership’s Quarterly Report on Form 10-Q that will be publicly available with the Securities and Exchange Commission through its website.

By March 15 of each year, the partnership will send you the information that is required for you to file your federal and state income tax returns.

Beginning with the second calendar year after the partnership closes, and every year thereafter, you will receive a computation of the partnership’s total oil and natural gas proved reserves and its dollar value. The reserve computations will be based on engineering reports prepared by the Managing GP and reviewed by an independent expert.

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PRESENTMENT FEATURE

Beginning with the fifth calendar year after the partnership closes this offering, investors in the partnership may present their Interests to the Managing GP to purchase such Interests. However, investors are not required to offer their Interests to the Managing GP, and you may receive a greater return if you retain your Interests. The Managing GP will not purchase less than one Interest, unless the fractional Interest represents your entire interest in the partnership.

The Managing GP has no obligation to purchase any or all such presented Interests, and it has no intention to establish a reserve to satisfy the presentment feature, and it may immediately suspend the presentment obligation by notice to you if the Managing GP determines, in its sole discretion, that it:

does not have the necessary cash flow; or
cannot borrow funds for this purpose on terms the Managing GP deems reasonable.

If fewer than all Interests presented at any time are to be purchased by the Managing GP, then the Interests to be purchased will be selected by lot.

The Managing GP’s right to purchase the Interests presented may be discharged for its benefit by a third-party or an affiliate. If you sell your Interests, they will be transferred to the party who pays for them, and you will be required to deliver an executed assignment of your Interests along with any other documents that the partnership requests. Your presentment of your Interests to the Managing GP for purchase is subject to the following conditions:

your presentment request must be made within 120 days of the partnership reserve report discussed below;
in accordance with Treasury Regulation Section 1.7704-1(f), the Managing GP may not purchase your Interests until at least 60 calendar days after you notify the Managing GP in writing of your intent to present your Interests for purchase; and
the purchase of your Interests will not be considered effective until the presentment price has been paid to you in cash.

The amount of the presentment price for your Interests that is attributable to the partnership’s oil and natural gas reserves, as discussed below, will be determined based on the last reserve report prepared by the partnership and reviewed by an independent expert. Beginning with the second calendar year after the initial closing date for the partnership and every year thereafter, the Managing GP will estimate the present worth of future net revenues attributable to the partnership’s interest in proved reserves. In making this estimate, the Managing GP will use:

a 10% discount rate;
a constant oil price based on then-existing prices; and
base natural gas prices on the existing natural gas contracts or prices at the time of the presentment.

Your presentment price will be based on your share of the partnership’s net assets and liabilities as described below, based on the ratio that your number of Interests bears to the total number of Interests in the partnership. The presentment price will include the sum of the following partnership items:

an amount based on 70% of the present worth of future net revenues from the proved reserves determined as described above;
cash on hand;
prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and
the estimated market value of all assets not separately specified above, determined in accordance with standard industry valuation procedures.

There will be deducted from the foregoing sum the following partnership items:

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an amount equal to all debts, obligations, and other liabilities, including accrued expenses;
an amount allocable to the Managing GP’s interest in the partnership (other than as a holder of Interests); and
any distributions made to you between the date of your presentment request and the date the presentment price is paid to you; provided, however, that if any cash distributed to you by the partnership after your presentment request was derived from the sale of oil, natural gas or a producing property, the amount of those cash 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 for purposes of determining the reduction of the presentment price.

The presentment price may be further adjusted by the Managing GP for estimated changes from the date of the reserve report discussed above to the date of payment of the presentment price to you due to the following:

the production or sales of, or additions to, reserves and lease and well equipment, sale or abandonment of leases, and similar matters occurring before the presentment request; and
any of the following occurring before payment of the presentment price to you:
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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TRANSFERABILITY OF INTERESTS

Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Limited Partnership Agreement

Your ability to sell or otherwise transfer your Interests in the partnership is restricted by federal and State securities laws, federal and State tax laws, and the Limited Partnership Agreement, as described below. Also, the sale or other transfer of your Interests may create negative tax consequences to you. See “Federal Income Tax Consequences — Disposition of Interests.”

First, due to tax laws, the Limited Partnership Agreement provides that you will not be able to sell, assign, exchange, or transfer your Interest if it would, in the opinion of counsel for the partnership, result in the following:

the termination of the partnership for tax purposes; or
the partnership being treated as a “publicly traded” partnership for tax purposes.

Second, under the Limited Partnership Agreement, sales or other transfers of the Interests are subject to the following additional limitations:

except as provided by operation of law, the partnership will recognize the transfer of only one or more whole Interests, unless you own less than a whole Interest, in which case, your entire fractional interest must be transferred;
the costs and expenses associated with the transfer must be paid by the person transferring the Interest;
the form of transfer must be in a form satisfactory to the Managing GP; and
the terms of the transfer must not contravene those of the Limited Partnership Agreement.

Your transfer of an Interest will not:

relieve you of your responsibility for any obligations related to your Interests under the Limited Partnership Agreement;
grant rights under the Limited Partnership Agreement as among your transferees, to more than one party unanimously designated by the transferees to the Managing GP; nor
require an accounting of the partnership by the Managing GP.

If the assignee of the Interest does not become a substituted partner, as described below in “— Conditions to Becoming a Substitute Partner,” the transfer will be effective as of midnight of the last day of the calendar month in which it is made.

Finally, before you are able to sell, assign, pledge, hypothecate, or transfer your Interest, the Managing GP, in its sole discretion, may require that you provide an opinion of counsel acceptable to the Managing GP that the registration and qualification under any applicable Federal or State securities laws are not required.

Conditions to Becoming a Substitute Partner

An assignee of a Interest will not be entitled to any of the rights granted to a partner under the Limited Partnership 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, unless the assignee becomes a substituted partner in accordance with the provisions set forth below. The conditions to become a substitute partner are as follows:

the assignor gives the assignee the right;
the assignee pays all costs and expenses incurred in connection with the substitution; and
the assignee executes and delivers, in a form acceptable to the Managing GP, the instruments necessary to establish that a legal transfer has taken place and to confirm his agreement to be bound by all of the terms and provisions of the Limited Partnership Agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned Interests, including the right to vote. The partnership will amend its records at least once each calendar quarter to effect the substitution of substituted partners.

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Transfer on Death Designation

You have the option of placing a transfer on death, or “TOD,” designation on the Interests that you purchase in this offering. A TOD designation transfers ownership of your Interests to your designated beneficiary or beneficiaries upon your death. This designation may only be made by individuals, not entities, who are the sole or joint owners with right of survivorship of the Interests. However, this option is not available to residents of the States of Louisiana or Texas. If you would like to place a TOD designation on your Interests, you must check the TOD box on the Subscription Agreement and you must complete and return the transfer on death form available upon request to us in order to effect the designation. Designated beneficiaries who desire to make additional investments in the Interests must meet the partnership’s suitability requirements at such time.

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PLAN OF DISTRIBUTION

General

Subject to the conditions set forth in this prospectus and in accordance with the terms and conditions of the Limited Partnership Agreement, the dealer-manager will offer, on a best efforts basis, a maximum of 20,000 Interests in the offering, all of which are priced at $10,000 per Interest, except for Interests that may be purchased by the Managing GP, selling dealers or certain of their affiliates, as well as registered investment advisers and their clients for the net price of $9,300 per Interest, reflecting the elimination of the sales commission. In addition, volume discounts on the sales commissions payable are available for purchases in excess of the thresholds set forth in the table under the heading “— Special Discounts” below. The minimum subscription is one half (½) Interest ($5,000). The only persons affiliated with the Managing GP or its affiliates that may purchase Interests are the executive officers of the Managing GP, who are listed under “Management” in this prospectus. Neither the Managing GP nor its affiliates intends to resell any Interests purchased. In its sole discretion, the Managing GP may, at any time prior to the two-year anniversary of the date the offering commences, increase the offering to a maximum of up to 30,000 Interests; provided, that the Managing GP may not extend the offering period in connection with such change. In the event that the Managing GP increases the size of the offering, the partnership will file a separate registration statement on Form S-1 regarding the additional Interests that the partnership offers. See “Subscriptions — How to Subscribe.”

The offering period for the partnership will begin on the date of this prospectus and will terminate no later than December 31, 2012, unless this offering is extended by the Managing GP pursuant to a supplement to this prospectus. The partnership has a reasonable period of time to conclude the closing after the termination of the offering period. The partnership may terminate the offering period at its option at any time.

Subscribers will generally not have the right to withdraw or receive their funds from the escrow account unless and until the offering is terminated, which may be as late as one year after the effective date of this prospectus.

Interests will be sold primarily through selling dealers and, to a limited extent, by the dealer-manager. The partnership will pay selling dealers or the dealer-manager, as the case may be, a sales commission of up to $700 per Interest sold.

Payments of sales commissions to the selling dealers and dealer-manager fees to the dealer-manager will not exceed 10% of the gross offering proceeds. One of the Managing GP’s affiliates, ICON Securities, is the dealer-manager of this offering and will be receiving non-accountable dealer-manager fees equal to $300 per Interest in the offering. Up to $100 per Interest may be re-allowed to selling dealers as a marketing fee for their assistance in marketing this offering and coordinating their sales efforts with those of the dealer-manager, including providing such selling dealers with, or reimbursing them for, permissible non-cash compensation under FINRA Rule 2310 for national and regional conferences. In addition, the dealer-manager may use a portion of its dealer-manager fee to provide the selling dealers with, or reimburse them for, permissible non-cash compensation under FINRA Rule 2310, such as costs and reimbursement for certain expenses related to other bona fide training and educational meetings.

Additionally, a portion of the gross offering proceeds may be used to pay bona fide due diligence expense reimbursements to the prospective selling dealers on a fully accountable basis. The partnership will require commissions and expenses to be proven by receipt of duly signed subscription documents, detailed and itemized invoices and other evidence satisfactory to it. The sums the partnership may expend in connection with bona fide due diligence activities are included in the O&O Costs the partnership will reimburse the Managing GP or its affiliates for in connection with the organization and this offering. See “Compensation.”

The dealer-manager agreement and the selling dealer agreements contain provisions for the partnership to indemnify the participating selling dealers with respect to some types of liabilities, including liabilities arising under the Securities Act, unless such liability arises from information in this prospectus relating to the dealer-manager and supplied by the dealer-manager.

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Special Discounts

The partnership is offering volume discounts to investors who purchase more than $500,000 worth of Interests through the same selected selling dealer in this offering. The following table shows the discounted price per Interest and the sales commissions payable for volume sales of Interests.

 
Dollar Amount of Interests Purchased   Sales Commission Rate
$1 – $500,000     7%  
$500,001 – $750,000     6%  
$750,001 – $1,000,000     5%  
$1,000,001 – $2,500,000     4%  
$2,500,001 – $5,000,000     3%  
$5,000,001 and up     2%  

The partnership will apply the reduced sales commissions to the incremental Interests within the indicated range only. The application of the reduced sales commissions will be reflected in the issuance of additional Interests rather than as a reduction of the purchase price. Thus, for example, a purchase of $1.25 million would result in the issuance of 126.667 Interests as shown below:

First $500,000 = 50 Interests issued; (7% sales commission + 3% dealer manager fee);
next $250,000 = additional 25.278 Interests issued; (6% sales commission + 3% dealer manager fee);
next $250,000 = additional 25.556 Interests issued; (5% sales commission + 3% dealer manager fee); and
next $250,000 = additional 25.833 Interests issued; (4% sales commission + 3% dealer manager fee).

To qualify for a volume discount as a result of multiple purchases of Interests, you must use the same selected selling dealer and you must mark the “Additional Investment” space on the subscription agreement. The partnership is not responsible for failing to combine purchases if you fail to mark the “Additional Investment” space. Once you qualify for a volume discount, you will be eligible to receive the benefit of such discount for subsequent purchases of Interests in this offering through the same selected selling dealer.

To the extent purchased through the same selected selling dealer, the following persons may combine their purchases as a “single purchaser” for the purpose of qualifying for a volume discount:
º an individual, his or her spouse, their children under the age of 21 and all pension or trust funds established by each such individual;
º a corporation, partnership, association, joint-stock company, trust fund or any organized group of persons, whether incorporated or not;
º an employees’ trust, pension, profit-sharing or other employee benefit plan qualified under Section 401(a) of the Internal Revenue Code; and
º all commingled trust funds maintained by a given bank.

In the event that a person wishes to have his or her order combined with others as a “single purchaser,” that person must request such treatment in writing at the time of subscription setting forth the basis for the discount and identifying the orders to be combined. Any request will be subject to verification that the orders to be combined are made by a single purchaser. If the subscription agreements for the combined orders of a single purchaser are submitted at the same time, then the sales commissions payable and discounted Interest price will be allocated pro rata among the combined orders on the basis of the respective amounts being combined. Otherwise, the volume discount provisions will apply only to the order that qualifies the single purchaser for the volume discount and the subsequent orders of that single purchaser.

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Segregation of Subscription Payments

In compliance with Rule 15c2-4 and Rule 10b-9 under the Securities Exchange Act of 1934, as amended, the partnership will place all offering proceeds in an escrow account at UMB Bank, N.A., a national bank. Such funds will be promptly submitted on the business day following receipt of the investor’s subscription documents and check. In certain circumstances where the suitability review procedures require transmittal to multiple offices of the selling dealers, an investor’s check will be promptly deposited in compliance with Rule 15c2-4. The partnership will do so beginning on the effective date of this prospectus and until the partnership has accepted subscriptions for 200 Interests (or 1,000 Interests in the case of residents of Pennsylvania and Tennessee) and the subscribers have been admitted as limited partners on the initial closing date (or a subsequent closing date in the case of Pennsylvania and Tennessee residents). Investors (other than Pennsylvania and Tennessee investors who will receive a similar one-time distribution upon their admission) who invest prior to the minimum offering size being achieved will receive, upon admission into the partnership, a one-time distribution equal to the initial distribution rate, as determined by the Managing GP, pro-rated for each day their funds were held in escrow, but without any interest on their escrow funds. Thereafter, the partnership will deposit funds received through the termination date in an interest-bearing account pending the next successive closing.

The partnership will promptly accept or reject subscriptions for Interests after the partnership receives a prospective investor’s subscription documents and subscription funds. Broker-dealers have agreed to provide each investor with a final prospectus prior to an investor signing a subscription agreement. Each subscriber has the right to cancel his or her subscription for a period of five business days after receiving a final prospectus. The initial closing date will be not later than 15 days after the partnership receives and accepts subscriptions for 200 Interests excluding, for this purpose, subscriptions from residents of Pennsylvania and Tennessee. Subsequent to the initial closing date, the partnership anticipates holding daily closings, provided the number of subscribed Interests is sufficient to justify the burden and expense of a closing. Once subscriptions total 1,000 Interests, including subscriptions from residents of Pennsylvania and Tennessee, the partnership will release from escrow all subscription payments then remaining in escrow and terminate the escrow agreement. At each closing, the partnership will admit as limited partners, effective as of the same day, all subscribers whose subscriptions have been received and accepted by the partnership and who are then eligible to be admitted.

If 200 Interests have not been subscribed on or before the first anniversary of the date of this prospectus, then the partnership will direct the escrow agent to release the applicable subscription payments from escrow and return them within three business days to subscribers, together with all interest earned on the subscriptions, and the offering will be terminated. For a subscriber from Pennsylvania, this will happen if 1,000 Interests have not been sold within 120 days of the escrow agent’s receipt of his or her subscription, and the subscriber has been offered and has elected to rescind his or her subscription. The partnership will apply the same procedure to return subscription payments that are held in the escrow account for one year from the date of this prospectus.

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SUBSCRIPTIONS

Minimum Investment

The minimum number of Interests you can purchase is one half (½) Interest.

Subscriber Representations and Subscription Procedures

Each potential investor must sign the Subscription Agreement found on pages C-1 to C-8. The partnership will promptly review each subscription and will accept or decline to accept you as either an Investor General Partner or a Limited Partner (as you designate in your Subscription Agreement) in its sole and absolute discretion. If your subscription is accepted, you will be given prompt written confirmation of your admission to the partnership.

By your signature in Section 8 of the Subscription Agreement (on page C-6), you are indicating your desire to become either an Investor General Partner or a Limited Partner (as you designate in your Subscription Agreement) and to be bound by all the terms of the Limited Partnership Agreement. You also appoint the Managing GP to be your true and lawful attorney-in-fact to sign documents, including the Limited Partnership Agreement, which may be required for your admission to the partnership.

Your signature and initials in Section 8 of the Subscription Agreement also serve as your affirmation that the acknowledgments, agreements and representations printed in that section on page C-6 of the Subscription Agreement are true, by which you confirm, among other things, that:

(1) you have received a copy of the prospectus at least five business days before tendering your subscription;
(2) you have read the Important Information for Subscriber(s) on page C-3 of the Subscription Agreement (except for subscribers in the states of Alabama, Arkansas, Kentucky, Maine, Minnesota, Ohio and Texas);
(3) you acknowledge that an investment in the Interests is not a liquid investment;
(4) you affirm that the partnership may rely on the accuracy of the factual data about yourself that you report in the Subscription Agreement, including your representation that:
(a) if you are purchasing Interests for an IRA, qualified plan or other benefit plan, you have accurately identified the subscriber as such;
(b) you have accurately identified yourself, or the investing entity, as a U.S. citizen, resident in the U.S. or Puerto Rico (individuals only) or a U.S. resident alien, having determined such status in the manner described below;
(c) you have accurately reported your social security number or the federal taxpayer identification number of the investing entity;
(d) you are not subject to backup withholding of federal income taxes; and
(e) you agree to redeem all of your Interests if you are no longer a U.S. citizen with a resident address in the United States or Puerto Rico (individuals only) or a resident alien, or if you otherwise are or become a foreign partner for purposes of Section 1446 of the Code at any point while holding Interests;
(5) you meet the minimum income and net worth standards established by us; and
(6) you are purchasing Interests for your own account and not with a view to distribution.

Pursuant to the NASAA Guidelines, a sponsor and each person selling interests in a partnership such as the one described herein shall make every reasonable effort to determine that an investment in such partnership is a suitable and appropriate investment for each investor. In making this determination, the NASAA Guidelines permit each person selling interests in a partnership such as the one described herein to make such determination on behalf of the partnership’s sponsor. The partnership will require that everyone who wishes to purchase the Interests make these representations in order to assist FINRA-registered securities

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sales representatives, selling dealers and the dealer-manager in determining whether this investment is suitable for each subscriber. The partnership will rely upon the accuracy and completeness of your representations in the Subscription Agreement in complying with its obligations under State and federal securities laws.

The Subscription Agreement asks that you acknowledge receipt of this prospectus and of the instruction to rely only on information contained in this prospectus and certain related materials, including supplements to the prospectus and promotional brochures marked as being prepared by the partnership or by the dealer-manager for use in connection with this offering, so that the partnership may make an informed judgment as to whether it should accept your offer to subscribe for the Interests. While the partnership recognizes that in the sales process a potential investor will usually discuss an investment in the Interests with his or her broker, it is possible that you may misunderstand what you are told or that someone might tell you something different from, or contrary to, the information contained in this prospectus. You might also read or hear something that contradicts the information contained in this prospectus.

If you become a limited partner and later make a claim against the partnership, the Managing GP and/or the dealer-manager alleging that you did not receive a prospectus for this offering, or that although you received a prospectus you relied on information that is contradictory to that disclosed in this prospectus, then the partnership and its affiliates anticipate relying on the representations you made in your Subscription Agreement. Your signature on the Subscription Agreement is your acknowledgment that you received this prospectus and the instructions to rely exclusively on the information contained in the prospectus in making your investment decision. Do not sign the Subscription Agreement if you do not understand this section.

Instruction Concerning “Important Information”

The Important Information on page C-3 of the Subscription Agreement asks you to review the disclosures in this prospectus concerning certain conflicts of interest the partnership faces, certain risks involved in this investment, the management of the Managing GP, and possible adverse effects on the federal income tax treatment the partnership expects may occur as a result of your purchase of Interests. These disclosures are found in the sections entitled “Risk Factors,” “Conflicts of Interest,” “Management” and “Federal Income Tax Consequences.”

The Partnership included this instruction because, as this investment involves inherent conflicts of interest and risks, the partnership does not intend to admit you unless it has reason to believe that you are aware of the risks involved in this investment. If you become either an Investor General Partner or a Limited Partner (as you designate in your Subscription Agreement) and later make claims against the partnership, the Managing GP and/or the dealer-manager to the effect that you were not aware that this investment involved the inherent risks described in this prospectus, the partnership, the Managing GP, and the dealer-manager anticipate relying on this instruction as evidence that you were aware of the risks involved in this investment.

Binding Effect of the Limited Partnership Agreement on You

The representation in the Subscription Agreement that you have agreed to all the terms and conditions of the Limited Partnership Agreement is necessary because the Managing GP and every Investor General Partner and Limited Partner are bound by all of the terms and conditions of that agreement, notwithstanding the fact that investors do not actually sign the Limited Partnership Agreement. Though you do not actually sign the Limited Partnership Agreement, your signature on the Subscription Agreement gives the Managing GP the power of attorney pursuant to which it obligates you to be bound by each of the terms and conditions of the Limited Partnership Agreement. If you become either an Investor General Partner or a Limited Partner and later make claims against the partnership, the Managing GP and/or the dealer-manager that you did not agree to be bound by all of the terms of the Limited Partnership Agreement and the Subscription Agreement, the partnership, the Managing GP and/or the dealer-manager anticipate relying on your representation and on the power of attorney as evidence of your agreement to be bound by all of the terms of the Limited Partnership Agreement and the Subscription Agreement.

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Your Citizenship and Residency

All investors will be required to represent and warrant that they are either a United States citizen or a resident alien, each with an address in the United States. The partnership will not admit anyone who is either a United States citizen living outside of the United States or a non-resident of the United States. An investor will be required to tender to the partnership for sale, upon demand, all of its Interests if such investor is no longer a United States citizen, resident in the United States or Puerto Rico (individuals only), or a resident alien or if an investor otherwise is or becomes a foreign partner for purposes of Section 1446 of the Code at any time while it is holding Interests.

Co-Signature By Selling Dealer

Selling dealers must countersign each Subscription Agreement for subscribers solicited by their firm. By this signature, the selling dealer certifies that it has obtained information from the potential investor sufficient to enable the selling dealer to determine that the investment is suitable for the investor based on the investor’s income, net worth and other characteristics. Pursuant to the NASAA Guidelines, a sponsor and each person selling interests in a partnership, such as the partnership, shall make every reasonable effort to determine that an investment in the partnership is a suitable and appropriate investment for each investor. In making this determination, the NASAA Guidelines permit each person selling interests in a partnership such as the partnership, to make such determination on behalf of the partnership’s sponsor. Since the Managing GP and the dealer-manager will not have had the opportunity to obtain financial and other relevant information directly from you, the Managing GP and the dealer-manager will rely on the selling dealer’s representation to determine whether to admit you as either an Investor General Partner or a Limited Partner (as you designate in your Subscription Agreement). If you become either an Investor General Partner or a Limited Partner and later make claims against the partnership, the Managing GP and/or the dealer-manager alleging that the Interests were not a suitable investment because you did not meet the financial requirements contained in the investor suitability standards, the partnership, the Managing GP and the dealer-manager anticipate relying upon the selling dealer’s representation (and your representation) as evidence that you did meet the financial requirements for this investment. FINRA’s Conduct Rules require that any person associated with the dealer-manager or a selling dealer who sells or offers to sell Interests must make every reasonable effort to ensure that a potential subscriber is a suitable investor for this investment in light of such subscriber’s age, education level, knowledge of investments, need for liquidity, net worth and other pertinent factors.

How to Subscribe

If you are an individual investor, you must personally sign the Subscription Agreement and deliver it, together with a check for all subscription monies payable in connection with your subscription, to a selling dealer. In the case of IRA, SEP and Keogh Plans, the trustee or custodian must also sign the Subscription Agreement. In the case of donor trusts or other trusts in which the donor is the fiduciary, the donor must sign the Subscription Agreement. In the case of other fiduciary accounts in which the donor neither exercises control over the account nor is a fiduciary of the account, the plan fiduciary alone may sign the Subscription Agreement.

Until subscriptions for 200 Interests (or 1,000 Interests in the case of residents of Pennsylvania and Tennessee) from the offering are received by the partnership, checks for the purchase of Interests should be made payable to “UMB Bank, N.A., Agent for ICON O&G Fund-A.” After the Initial Closing Date, checks for the purchase of Interests should be made payable to “ICON O&G Fund-A” for deposit into an interest bearing account pending the next closing.

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FURTHER INFORMATION

Sales Material

In addition to this prospectus, the partnership may use sales material in connection with the offering of its Interests. In some jurisdictions, sales material may not be available. This material will include information relating to this offering, the Managing GP and to its affiliates, and may include brochures, articles, presentations for group meetings and publications about the oil and gas industry and oil and gas drilling partnerships. All advertisements of, and oral or written invitations to seminars or other group meetings at which Interests are to be described, offered or sold will clearly indicate that the purpose of such meeting is to offer such Interests, for sale, the minimum purchase price thereof, the suitability standards to be employed, and the name of the person selling the Interests. If required by regulatory agencies, the partnership will use only sales material that they have approved. The offering of the Interests, however, is made only by means of this prospectus. Although the information contained in the sales material does not conflict with any of the information contained in this prospectus, the material does not purport to be complete and should not be considered as a part of this prospectus or the registration statement of which this prospectus is a part, or as incorporated in this prospectus by reference or as forming the basis of this offering of the Interests.

Legal Opinions

Arent Fox LLP of Washington, D.C. has provided us with an opinion on the legality of the Interests offered in this prospectus and the tax matters set forth under “Federal Income Tax Consequences.”

Experts

The audited balance sheet of ICON Oil & Gas Fund-A L.P. as of December 31, 2011 and the audited balance sheet of ICON Oil & Gas GP, LLC as of December 31, 2011 appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon appearing elsewhere herein, and are included in reliance upon such reports given on the authority of such firm as experts in accounting and auditing.

Additional Information

A registration statement under the Securities Act of 1933, as amended, has been filed with the Securities and Exchange Commission, Washington, D.C., with respect to the Interests. This prospectus, which forms a part of the registration statement, contains information concerning the partnership and includes a copy of the Limited Partnership Agreement, but it does not contain all the information set forth in the registration statement and its exhibits. The information omitted may be examined at the public reference room of the Securities and Exchange Commission located at 100 F Street, N.E., Washington, D.C. 20549 (1-800-SEC-3030), without charge, and copies may be obtained from that office upon payment of the fee prescribed by the rules and regulations of the Securities and Exchange Commission. Additionally, it can be viewed via the website of the Securities and Exchange Commission at http://www.sec.gov. The partnership will file periodic reports with the Securities and Exchange Commission, copies of which will be available on ICON Capital’s website at http://www.iconinvestments.com. The information on ICON Capital’s website does not constitute a part of this prospectus.

Litigation

The Managing GP knows of no litigation pending or threatened to which the Managing GP or the partnership are subject or may be a party, and no such proceedings are known by the Managing GP to be contemplated by governmental authorities or other parties.

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GLOSSARY

The following terms used in this prospectus have the meanings set forth below:

AFE” means an Authorization For Expenditure, an itemized list of all costs of drilling and completing each of the partnership’s wells, which list allocates such costs between intangible drilling costs and non-deductible equipment costs.

AMI” means an area of mutual interest containing the leaseholds for a project, as specified in the related Participation Agreement.

Dealer Manager” means ICON Securities Corp., an affiliate of the Managing GP, who will act as the dealer manager of this offering of Interests.

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.

Intangible Drilling Costs” means those costs of drilling and completing a well that are currently deductible, including, without limitation, 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 oil or natural gas.

Interests” means Investor General Partner Interests and Limited Partner Interests.

Investor General Partner Interests” means up to 16,000 investor general partner interests offered to investors in ICON Oil & Gas Fund.

Limited Partner Interests” means up to 4,000 initial limited partner interests offered to investors in ICON Oil & Gas Fund and any “Converted Limited Partner Interests,” which are limited partner interests into which the Investor General Partner Interests automatically will be converted by the Managing GP.

Limited Partnership Agreement” means the limited partnership agreement governing the rights and obligations of the partners in the partnership, a form of which is attached to this prospectus as Exhibit A.

Management Fee” means the fee paid to the Managing GP for managing the partnership and the offering.

Managing GP” means ICON Oil & Gas GP, LLC, a Delaware limited liability company, and its successors and assigns.

Maximum Offering” means the offering of up to 20,000 Interests in the partnership; provided, that, in the sole discretion of the Managing GP, it may, at any time prior to the two-year anniversary of this prospectus, increase the offering to a maximum of up to 30,000 Interests; provided further, that the Managing GP may not extend the offering period in connection with such change.

O&O Costs” means all costs of organizing and offering the Interests, including the dealer-manager fees, sales commissions, due diligence expense reimbursements and other costs related to the organization of the partnership and the offering of the Interests, such as expenses for printing, mailing, transfer agents, registrars, escrow holders, depositaries, engineers and other experts and expenses of the registration and qualification of the sale of securities under federal and state securities law, including taxes and fees and accountant’s fees and attorney’s fees and other front-end fees.

Participation Agreement” means a participation agreement with an operator for a Project which participation agreement will include an attached operating agreement governing the rights and obligations of the partnership and the operator with respect to drilling operations.

Projects” means “fluid management” projects, including dewatering projects, where hydrocarbons are known to be present, located in the Mid-Continent region of the United States, with the potential investment in properties located within other types of projects and/or in other geographic areas that the Managing GP may identify as prospective.

Special Energy” means Special Energy Corporation, a Stillwater, Oklahoma – based independent oil and gas operating company with whom the partnership intends to enter into Participation Agreements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners
ICON Oil & Gas Fund-A L.P.

We have audited the accompanying balance sheet of ICON Oil & Gas Fund-A L.P. (the “Partnership”) as of December 31, 2011. This balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this balance sheet 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 balance sheet is free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of ICON Oil & Gas Fund-A L.P. at December 31, 2011 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

January 26, 2012
Tulsa, Oklahoma

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ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)

BALANCE SHEET
December 31, 2011

Assets

 
Cash   $ 1,001  
Total Assets   $ 1,001  

Partners’ Equity

 
Partners’ Equity:
        
Managing General Partner   $ 1  
Limited Partner     1,000  
Total Partners’ Equity   $ 1,001  

 
 
See Accompanying Notes to Balance Sheet.

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ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
December 31, 2011

(1)  Partnership Organization

ICON Oil & Gas Fund-A L.P. (the “Partnership”) was formed on May 9, 2011 as a Delaware limited partnership. The initial capitalization of the Partnership was $1,001. The Partnership has a maximum 50-year term, although the Partnership intends to terminate when all of the wells invested in by the Partnership become uneconomical to continue to operate, which may be approximately 15 years or longer. The Partnership is offering investor general partner and limited partner interests on a “best efforts” basis with the intention of raising up to $200,000,000 of capital, consisting of 16,000 investor general partner and 4,000 limited partner interests (collectively, the “Interests”). At any time prior to the two-year anniversary of the commencement of the offering, the Partnership may increase the offering to a maximum of up to $300,000,000 of capital from the sale of 30,000 Interests. Upon raising a minimum of $2,000,000, the holders of the Interests will be admitted and the Partnership will commence operations.

The investor general partner interests will be automatically converted by the Partnership to limited partner interests upon the occurrence of the earlier of (i) the drilling and completion of all of the Partnership’s wells or (ii) the date that no additional currently deductible intangible drilling costs will be realized by the Partnership’s investor general partners, as determined by the Managing GP. A well is deemed to be completed when production equipment is installed, even though the well may not yet be connected to a pipeline for production of oil or natural gas.

The Partnership’s primary investment objectives are to (i) generate revenue from the production and sale of oil, natural gas and natural gas liquids, (ii) distribute cash to investors, and (iii) provide investors with tax benefits in the year that the offering commences and in future years. The proceeds from the sale of the Interests will be used to invest primarily in oil and liquids-rich natural gas development wells, principally “fluid management” projects, where hydrocarbons are known to be present, located in the Mid-Continent region of the United States, with the potential investment in properties located within other types of projects and/or in other geographic areas that the Partnership may, from time to time, identify as prospective. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

The managing general partner of the Partnership is ICON Oil & Gas GP, LLC, a Delaware limited liability company (the “Managing GP”), which is a wholly-owned subsidiary of ICON Investment Group, LLC, a Delaware limited liability company. The Managing GP manages and controls the business affairs of the Partnership, including, but not limited to, the drilling activity contemplated in the prospectus. Pursuant to the terms of an administration agreement, the Partnership has engaged an affiliate, ICON Capital Corp., a Delaware corporation (“ICON Capital”), to, among other things, provide the Partnership with facilities, investor relations and administrative support. ICON Securities Corp. d/b/a ICON Investments, which is an affiliate of the Managing GP, will act as the dealer-manager for the offering of the Interests.

Following the commencement of operations, the Partnership will reimburse the Managing GP and its affiliates for certain fees paid on its behalf.

The Partnership’s fiscal year ends on December 31.

(2)  Summary of Significant Accounting Policies

Basis of Presentation

The accompanying balance sheet of the Partnership has been prepared in accordance with U.S. generally accepted accounting principles (“US GAAP”).

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TABLE OF CONTENTS

ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
December 31, 2011

(2)  Summary of Significant Accounting Policies  – (continued)

Cash and Cash Equivalents

The Partnership’s cash is held at one financial institution and at times may exceed insured limits. The Partnership periodically evaluates the creditworthiness of this institution and has not experienced any losses on such deposits. The Partnership did not have any cash equivalents at December 31, 2011.

Deferred Charges

The costs of organizing the Partnership and offering the Interests are capitalized by the Partnership and amortized over the estimated offering period, which period will not exceed two years from the effective date of the offering. Following the effective date of the offering, the unamortized balance of these costs will be reflected in the balance sheet as deferred charges, net. Organizational and offering costs include (i) the dealer-manager fee, (ii) sales commissions and (iii) other costs related to the organization of the Partnership and the offering of the Interests.

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires the Partnership 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 balance sheet. Actual results could differ from those estimates.

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 by the unit-of-production method based on periodic estimates of oil and gas reserves. Undeveloped leaseholds and proved properties will be assessed periodically or whenever events or circumstances indicate that the carrying amount of these assets may not be recoverable. Proved properties will be assessed based on estimates of future cash flows.

Production Revenues

The Managing GP and the investors in the Partnership will share in all of the Partnership’s production revenues in the same percentage as their respective capital contribution bears to the Partnership’s total net capital contributions, except that the Managing GP will receive an additional 10% of the Partnership’s production revenues.

Proceeds from the Sale of Wells/Leases

If a well is sold, the portion of the sales proceeds allocated to the Partnership will be allocated among the Managing GP and the investors in the Partnership in accordance with the sharing ratio utilized for the allocation of production revenues.

Equipment Proceeds

Proceeds from the sale or other disposition of equipment used to drill and complete the Partnership’s wells will be credited to the Managing GP and the investors in the Partnership in accordance with the sharing ratio utilized for the allocation of production revenues.

Income Tax

The Partnership is taxed as a partnership for federal and State income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership's income tax returns will be subject to examination by the federal and State taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

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ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
December 31, 2011

(3)  Participation in Costs and Revenues

The following table sets forth certain Partnership costs (in excess of cumulative revenues) and revenues (in excess of cumulative costs) charged and credited between the Managing GP and investors in the Partnership, after deducting from the Partnership’s gross revenues the landowner royalties and any other lease burdens. The following table assumes that the Managing GP (i) makes a capital contribution equal to 1% of the total investor capital contributions (net of organizational and offering costs and the management fee) in the form of payment of a portion of program costs and (ii) does not purchase any Interests.

   
  Managing GP   Interests Issued by the Partnership
Partnership Costs
   
Intangible drilling costs(1)     1 %      99 % 
Non-deductible equipment costs(2)     1 %      99 % 
Organizational and offering costs     1 %      99 % 
Lease costs(3)     1 %      99 % 
Administrative costs, direct costs, and all other costs(4)     11 %      89 % 
Partnership Revenues
                 
Production revenues(5)     11 %      89 % 
Proceeds from the sale of wells/leases(5)     11 %      89 % 
Equipment proceeds     11 %      89 % 
Interest proceeds(6)     11 %      89 % 
Participation in Deductions
                 
Intangible drilling costs     1 %      99 % 
Depreciation     1 %      99 % 
Depletion allowance     (7)       (7)  

(1) The net offering proceeds of investors in the Partnership will be used to pay 99% of the intangible drilling costs incurred in drilling and completing the Partnership’s wells.
(2) The net offering proceeds of investors in the Partnership will be used to pay up to 99% of the non-deductible equipment costs incurred by the Partnership in drilling and completing its wells.
(3) Lease costs will be borne by the Partnership through its acquisition of assigned interests in leases directly acquired and contributed by the operators.
(4) This table reflects the partnership’s anticipation that its production revenue otherwise allocable between the investors and the Managing GP will be used to pay these costs. If, however, these costs exceed the partnership’s production revenue, then in any given year the investors and the Managing GP may bear a percentage of these costs that differs from their share of the production revenue in that year, which share may vary from year to year under the partnership’s limited partnership agreement. Other such costs also include the plugging and abandonment costs of the wells after their economic reserves have been produced and depleted. If the Managing GP pays for any portion of any of these costs, the Managing GP will receive a share of the partnership’s revenues in the same percentage as such costs are paid by the Managing GP.
(5) The Managing GP and the investors will share in all of the Partnership’s revenues in the same percentage that their respective capital contributions bear to the Partnership’s total net capital contributions, except that the Managing GP will receive an additional 10% of the production revenues.
(6) Interest earned on offering proceeds until they are released to the Managing GP for use in the drilling activities of the Partnership will be credited to each investor’s capital account and paid not later than the Partnership’s first cash distribution from operations. Until the Partnership’s offering proceeds are invested in its operations, any interest income from temporary investments will be

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TABLE OF CONTENTS

ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
December 31, 2011

(3)  Participation in Costs and Revenues  – (continued)

allocated pro rata to the investors providing the offering 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.
(7) The greater of the cost depletion allowance and the percentage depletion allowance for each property will be available to investors as a current deduction against their share of the partnership’s gross production revenue in that taxable year, which share may vary from year to year under the partnership’s limited partnership agreement.

(4)  Capital Contribution

The Managing GP has made an initial capital contribution of $1 to the Partnership. In addition, ICON Investment Group, LLC made an initial capital contribution of $1,000 to the Partnership and was admitted as a limited partner on September 19, 2011.

(5)  Oil and Gas Operations

The Partnership will partner with one or more oil and gas operators, in each case, subject to a participation agreement. Each participation agreement generally provides that the related operator will conduct and direct, and have full control of, all operations with respect to specified oil and natural gas prospects within one or more projects. Each participation agreement will continue in force so long as any of the oil and natural gas leases subject to such participation agreement remain or are continued in force as to the projects, whether by production, extension, renewal or otherwise.

The operators will receive compensation, at competitive rates, for drilling and completing the Partnership’s wells pursuant to the related participation agreement. When the Partnership’s wells begin producing oil and/or natural gas in commercial quantities, the related operators may receive any or all of the following: (i) compensation equal to a percentage of certain costs, (ii) reimbursement at actual cost for all direct expenses incurred by it on behalf of the Partnership, (iii) well supervisory fees, at competitive rates, for maintaining and operating the wells during operations, and (iv) gathering fees, at competitive rates, for its services in gathering and transporting the Partnership’s oil and/or natural gas production.

(6)  Transactions with Related Parties

The Partnership has entered into certain agreements with the Managing GP and ICON Investments, whereby the Partnership pays certain fees and reimbursements to these parties. ICON Investments is entitled to receive a 3% dealer-manager fee from the gross offering proceeds from the sale of the Interests. The selling dealers are entitled to receive a sales commission of up to 7% of the gross offering proceeds. In addition, the Partnership will pay to the Managing GP a management fee equal to 15% of gross offering proceeds less the sum of all organizational and offering costs. The Partnership will reimburse the Managing GP and its affiliates for their (i) administrative costs, (ii) direct costs, and (iii) other costs incurred by the Partnership in drilling and maintaining its wells.

Though the Managing GP does not anticipate charging the Partnership a separate supervisory fee for its supervisory services, such a fee is customary for oil and gas drilling programs of this type and, if charged, would be at a competitive rate, but not based on arm’s-length negotiations, for supervising the operations of the related operator both before and during producing operations. The Partnership may pay to the Managing GP gas marketing fees, at competitive rates, but not based on arm’s-length negotiations, for its services, if any, in marketing the natural gas production. The Managing GP does not currently anticipate participating in the marketing of its natural gas production, and thus, does not anticipate charging any gas marketing fees.

The Managing GP will receive a share of the Partnership’s revenues. The Managing GP’s revenue share will be in the same percentage that its capital contribution bears to the total capital contributions, plus an additional 10% of the Partnership’s revenues. The Managing GP will make a minimum capital contribution at

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ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
December 31, 2011

(6)  Transactions with Related Parties  – (continued)

least equal to 1% of total investor capital contributions (net of organizational and offering costs and the management fee). In addition, the Managing GP and its affiliates will be reimbursed for organizational and offering expenses incurred in connection with the Partnership’s organization and offering of the Interests and administrative expenses incurred in connection with the Partnership’s operations.

Administrative expense reimbursements are costs incurred by the Managing GP or its affiliates that are necessary to the Partnership’s operations. These costs include the Managing GP’s and its affiliates’ legal, accounting, investor relations and operations personnel, as well as professional fees and other costs that are charged to the Partnership based upon the percentage of time such personnel dedicate to the Partnership. Excluded are salaries and related costs, office rent, travel expenses and other administrative costs incurred by individuals with a controlling interest in the Managing GP.

ICON Capital will, among other things, provide the Partnership with facilities, investor relations and administrative support.

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TABLE OF CONTENTS

ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)

BALANCE SHEET
May 31, 2012
(unaudited)

Assets

 
Cash   $ 1,001  
Total Assets   $ 1,001  

Partners’ Equity

 
Partners’ Equity:
        
Managing General Partner   $ 1  
Limited Partner     1,000  
Total Partners’ Equity   $ 1,001  

 
 
See Accompanying Notes to Balance Sheet.

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ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
May 31, 2012

(1)  Partnership Organization

ICON Oil & Gas Fund-A L.P. (the “Partnership”) was formed on May 9, 2011 as a Delaware limited partnership. The initial capitalization of the Partnership was $1,001. The Partnership has a maximum 50-year term, although the Partnership intends to terminate when all of the wells invested in by the Partnership become uneconomical to continue to operate, which may be approximately seven to 15 years or longer. The Partnership is offering investor general partner and limited partner interests on a “best efforts” basis with the intention of raising up to $200,000,000 of capital, consisting of 16,000 investor general partner and 4,000 limited partner interests (collectively, the “Interests”). At any time prior to the two-year anniversary of the commencement of the offering, the Partnership may increase the offering to a maximum of up to $300,000,000 of capital from the sale of 30,000 Interests. Upon raising a minimum of $2,000,000, the holders of the Interests will be admitted and the Partnership will commence operations.

The investor general partner interests will be automatically converted by the Partnership to limited partner interests upon the occurrence of the earlier of (i) the drilling and completion of all of the Partnership’s wells or (ii) the date that no additional currently deductible intangible drilling costs will be realized by the Partnership’s investor general partners, as determined by the managing general partner of the Partnership, ICON Oil & Gas GP, LLC, a Delaware limited liability company (the “Managing GP”). A well is deemed to be completed when production equipment is installed, even though the well may not yet be connected to a pipeline for production of oil or natural gas.

The Partnership’s primary investment objectives are to (i) generate revenue from the production and sale of oil and natural gas, (ii) distribute cash to investors, and (iii) provide investors with tax benefits in the year that the offering commences and in future years. The proceeds from the sale of the Interests will be used to invest primarily in oil and liquids-rich natural gas development wells, principally “fluid management” projects, where hydrocarbons are known to be present, located in the Mid-Continent region of the United States, with the potential investment in properties located within other types of projects and/or in other geographic areas that the Partnership may, from time to time, identify as prospective. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

The Managing GP is a wholly-owned subsidiary of ICON Investment Group, LLC, a Delaware limited liability company. The Managing GP manages and controls the business affairs of the Partnership, including, but not limited to, the drilling activity contemplated in the prospectus. Pursuant to the terms of an administration agreement, the Partnership has engaged an affiliate, ICON Capital Corp., a Delaware corporation (“ICON Capital”), to, among other things, provide the Partnership with facilities, investor relations and administrative support. ICON Securities Corp. (“ICON Securities”), which is an affiliate of the Managing GP, will act as the dealer-manager for the offering of the Interests.

Following the commencement of operations, the Partnership will reimburse the Managing GP and its affiliates for certain fees paid on its behalf.

The Partnership’s fiscal year ends on December 31.

(2)  Summary of Significant Accounting Policies

Basis of Presentation

The accompanying balance sheet of the Partnership has been prepared in accordance with U.S. generally accepted accounting principles (“US GAAP”).

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ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
May 31, 2012

(2)  Summary of Significant Accounting Policies  – (continued)

Cash and Cash Equivalents

The Partnership’s cash is held at one financial institution and at times may exceed insured limits. The Partnership periodically evaluates the creditworthiness of this institution and has not experienced any losses on such deposits. The Partnership did not have any cash equivalents at May 31, 2012.

Deferred Charges

The costs of organizing the Partnership and offering the Interests are capitalized by the Partnership and amortized over the estimated offering period, which period will not exceed two years from the effective date of the offering. Following the effective date of the offering, the unamortized balance of these costs will be reflected in the balance sheet as deferred charges, net. Organizational and offering costs include (i) the dealer-manager fee, (ii) sales commissions and (iii) other costs related to the organization of the Partnership and the offering of the Interests.

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires the Partnership 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 balance sheet. Actual results could differ from those estimates.

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 by the unit-of-production method based on periodic estimates of oil and gas reserves. Undeveloped leaseholds and proved properties will be assessed periodically or whenever events or circumstances indicate that the carrying amount of these assets may not be recoverable. Proved properties will be assessed based on estimates of future cash flows.

Production Revenues

The Managing GP and the investors in the Partnership will share in all of the Partnership’s production revenues in the same percentage as their respective capital contribution bears to the Partnership’s total net capital contributions, except that the Managing GP will receive an additional 10% of the Partnership’s production revenues.

Proceeds from the Sale of Wells/Leases

If a well is sold, the portion of the sales proceeds allocated to the Partnership will be allocated among the Managing GP and the investors in the Partnership in accordance with the sharing ratio utilized for the allocation of production revenues.

Equipment Proceeds

Proceeds from the sale or other disposition of equipment used to drill and complete the Partnership’s wells will be credited to the Managing GP and the investors in the Partnership in accordance with the sharing ratio utilized for the allocation of production revenues.

Income Tax

The Partnership is taxed as a partnership for federal and State income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership's income tax returns will be subject to examination by the federal and State taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

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ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
May 31, 2012

(3)  Participation in Costs and Revenues

The following table sets forth certain Partnership costs (in excess of cumulative revenues) and revenues (in excess of cumulative costs) charged and credited between the Managing GP and investors in the Partnership, after deducting from the Partnership’s gross revenues the landowner royalties and any other lease burdens. The following table assumes that the Managing GP (i) makes a capital contribution equal to 1% of the total investor capital contributions (net of organizational and offering costs and the management fee) in the form of payment of a portion of program costs and (ii) does not purchase any Interests.

   
  Managing GP   Interests Issued by the Partnership
Partnership Costs
   
Intangible drilling costs(1)     1 %      99 % 
Non-deductible equipment costs(2)     1 %      99 % 
Organizational and offering costs     1 %      99 % 
Lease costs(3)     1 %      99 % 
Administrative costs, direct costs, and all other costs(4)     11 %      89 % 
Partnership Revenues
                 
Production revenues(5)     11 %      89 % 
Proceeds from the sale of wells/leases(5)     11 %      89 % 
Equipment proceeds     11 %      89 % 
Interest proceeds(6)     11 %      89 % 
Participation in Deductions
                 
Intangible drilling costs     1 %      99 % 
Depreciation     1 %      99 % 
Depletion allowance     (7)       (7)  

(1) The net offering proceeds of investors in the Partnership will be used to pay 99% of the intangible drilling costs incurred in drilling and completing the Partnership’s wells.
(2) The net offering proceeds of investors in the Partnership will be used to pay up to 99% of the non-deductible equipment costs incurred by the Partnership in drilling and completing its wells.
(3) Lease costs will be borne by the Partnership through its acquisition of assigned interests in leases directly acquired and contributed by the operators.
(4) This table reflects the partnership’s anticipation that its production revenue otherwise allocable between the investors and the Managing GP will be used to pay these costs. If, however, these costs exceed the partnership’s production revenue, then in any given year the investors and the Managing GP may bear a percentage of these costs that differs from their share of the production revenue in that year, which share may vary from year to year under the partnership's limited partnership agreement. Other such costs also include the plugging and abandonment costs of the wells after their economic reserves have been produced and depleted. If the Managing GP pays for any portion of any of these costs, the Managing GP will receive a share of the partnership’s revenues in the same percentage as such costs are paid by the Managing GP.
(5) The Managing GP and the investors will share in all of the Partnership’s revenues in the same percentage that their respective capital contributions bear to the Partnership’s total net capital contributions, except that the Managing GP will receive an additional 10% of the production revenues.
(6) Interest earned on offering proceeds until they are released to the Managing GP for use in the drilling activities of the Partnership will be credited to each investor’s capital account and paid not later than the Partnership’s first cash distribution from operations. Until the Partnership’s offering proceeds are invested in its operations, any interest income from temporary investments will be

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TABLE OF CONTENTS

ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
May 31, 2012

(3)  Participation in Costs and Revenues  – (continued)

allocated pro rata to the investors providing the offering 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.
(7) The greater of the cost depletion allowance and the percentage depletion allowance for each property will be available to investors as a current deduction against their share of the partnership's gross production revenue in that taxable year, which share may vary from year to year under the partnership's limited partnership agreement.

(4)  Capital Contribution

The Managing GP has made an initial capital contribution of $1 to the Partnership. In addition, ICON Investment Group, LLC made an initial capital contribution of $1,000 to the Partnership and was admitted as a limited partner on September 19, 2011.

(5)  Oil and Gas Operations

The Partnership will partner with one or more oil and gas operators, in each case, subject to a participation agreement. Each participation agreement generally provides that the related operator will conduct and direct, and have full control of, all operations with respect to specified oil and natural gas prospects within one or more projects. Each participation agreement will continue in force so long as any of the oil and natural gas leases subject to such participation agreement remain or are continued in force as to the projects, whether by production, extension, renewal or otherwise.

The operators will receive compensation, at competitive rates, for drilling and completing the Partnership’s wells pursuant to the related participation agreement. When the Partnership’s wells begin producing oil and/or natural gas in commercial quantities, the related operators may receive any or all of the following: (i) compensation equal to a percentage of certain costs, (ii) reimbursement at actual cost for all direct expenses incurred by it on behalf of the Partnership, (iii) well supervisory fees, at competitive rates, for maintaining and operating the wells during operations, and (iv) gathering fees, at competitive rates, for its services in gathering and transporting the Partnership’s oil and/or natural gas production.

(6)  Transactions with Related Parties

The Partnership has entered into certain agreements with the Managing GP and ICON Securities, whereby the Partnership pays certain fees and reimbursements to these parties. ICON Securities is entitled to receive a 3% dealer-manager fee from the gross offering proceeds from the sale of the Interests. The selling dealers are entitled to receive a sales commission of up to 7% of the gross offering proceeds, which sales commissions may be subject to reduction for certain large purchases of Interests. In addition, the Partnership will pay to the Managing GP a management fee equal to 15% of gross offering proceeds less the sum of all organizational and offering costs. The Partnership will reimburse the Managing GP and its affiliates for their (i) administrative costs, (ii) direct costs, and (iii) other costs incurred on behalf of the Partnership in drilling and maintaining its wells.

If the Managing GP or any of its affiliates serves as the operator for any of the Partnership’s wells, the Managing GP or such affiliate, as applicable, may charge a separate supervisory fee for operating and maintaining the wells during producing operations. Neither the Managing GP nor any of its affiliates anticipate serving as operator for any of the Partnership’s wells. Accordingly, neither the Managing GP nor any of its affiliates anticipate charging a supervisory fee for such services. If the Managing GP or any of its affiliates were to serve as operator for any of the Partnership’s wells, the supervisory fee for such services would be at a rate competitive with rates charged by third-party operators providing similar services, but not based on arm’s-length negotiations. The Partnership may pay to the Managing GP gas marketing fees, at competitive rates, but not based on arm’s-length negotiations, for its services, if any, in marketing the natural gas

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TABLE OF CONTENTS

ICON Oil & Gas Fund-A L.P.
(A Delaware Limited Partnership)
NOTES TO BALANCE SHEET
May 31, 2012

(6)  Transactions with Related Parties  – (continued)

production. The Managing GP does not currently anticipate participating in the marketing of its natural gas production, and thus, does not anticipate charging any gas marketing fees.

The Managing GP will receive a share of the Partnership’s revenues. The Managing GP’s revenue share will be in the same percentage that its capital contribution bears to the total capital contributions, plus an additional 10% of the Partnership’s revenues. The Managing GP will make a minimum capital contribution at least equal to 1% of total investor capital contributions (net of organizational and offering costs and the management fee). In addition, the Managing GP and its affiliates will be reimbursed for organizational and offering expenses incurred in connection with the Partnership’s organization and offering of the Interests and administrative expenses incurred in connection with the Partnership’s operations.

Administrative expense reimbursements are costs incurred by the Managing GP or its affiliates that are necessary to the Partnership’s operations. These costs include the Managing GP’s and its affiliates’ legal, accounting, investor relations and operations personnel, as well as professional fees and other costs that are charged to the Partnership based upon the percentage of time such personnel dedicate to the Partnership. Excluded are salaries and related costs, office rent, travel expenses and other administrative costs incurred by individuals with a controlling interest in the Managing GP.

ICON Capital will, among other things, provide the Partnership with facilities, investor relations and administrative support.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Member
ICON Oil & Gas GP, LLC

We have audited the accompanying balance sheet of ICON Oil & Gas GP, LLC (the “Company”) as of December 31, 2011. This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet 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 balance sheet is free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of ICON Oil & Gas GP, LLC at December 31, 2011 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

January 26, 2012
Tulsa, Oklahoma

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ICON Oil & Gas GP, LLC
(A Delaware Limited Liability Company)

BALANCE SHEET
December 31, 2011

Assets

 
Investment in limited partnership   $        1  
Total Assets   $ 1  

Member’s Equity

 
Member’s Equity:
        
Member’s Equity   $ 5,000,001  
Less: Note receivable from Member     (5,000,000 ) 
Total Member’s Equity   $ 1  

 
 
See Accompanying Notes to Balance Sheet.

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ICON Oil & Gas GP, LLC
(A Delaware Limited Liability Company)
NOTES TO BALANCE SHEET
December 31, 2011

(1)   Organization

ICON Oil & Gas GP, LLC (the “Company”) is a wholly-owned subsidiary of ICON Investment Group, LLC, a Delaware limited liability company (“ICON Investment Group”). The primary activity of the Company is sponsoring and managing publicly registered oil and gas drilling partnerships in the United States of America.

The Company is the managing general partner of ICON Oil & Gas Fund-A L.P. (the “Managed Fund”).

The Company was formed on May 9, 2011 as a Delaware limited liability company. The Company manages the business affairs of the Managed Fund, including, but not limited to, the investments that the Managed Fund makes, pursuant to the terms of the Managed Fund’s limited partnership agreement. The Managed Fund is a publicly registered oil and gas drilling partnership that was formed to invest primarily in oil and liquids-rich natural gas development wells, principally “fluid management” projects, where hydrocarbons are known to be present, located in the Mid-Continent region of the United States, with the potential investment in properties located within other types of projects and/or in other geographic areas that the Company may, from time to time, identify as prospective. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

The Company will receive a share of the Managed Fund’s revenues from the production of oil and natural gas. The Company’s share of the Managed Fund’s revenues will be in the same percentage that its capital contribution bears to the total capital contributions of the Managed Fund, plus an additional 10% of the Managed Fund’s revenues. The Company will make a minimum capital contribution at least equal to 1% of the Managed Fund’s total investor capital contributions (net of organizational and offering costs and the management fee).

The Company had an initial $1 investment in the Managed Fund, representing its managing general partnership interest. The Company accounts for its investment in the Managed Fund using the equity method of accounting as the sole limited partner has the ability to dissolve the partnership and remove the Company as the Managing General Partner.

On September 19, 2011, the Company received an additional equity contribution of $5,000,000 from ICON Investment Group.

The Company’s fiscal year ends on December 31.

(2)  Summary of Significant Accounting Policies

Basis of Presentation

The accompanying balance sheet of the Company has been prepared in accordance with U.S. generally accepted accounting principles (“US GAAP”). The management of the Company has evaluated all subsequent events through January 26, 2012, the date the balance sheet was issued.

Cash and Cash Equivalents

The Company’s cash is held at one financial institution and at times may exceed insured limits. The Company periodically evaluates the creditworthiness of this institution and has not experienced any losses on such deposits. The Company did not have any cash equivalents at December 31, 2011.

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires the Company 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 balance sheet. Actual results could differ from those estimates.

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ICON Oil & Gas GP, LLC
(A Delaware Limited Liability Company)
NOTES TO BALANCE SHEET
December 31, 2011

(3)  Capital Contribution from Member

On September 19, 2011, ICON Investment Group contributed a $5,000,000 demand promissory note issued by its Members to the Company as a capital contribution. There are no restrictions or covenants associated with this note, which would preclude the Company from receiving the principal or interest amounts due under the terms of the note. The note shall bear interest at an annual fixed rate equal to the then-current annual mid-term Applicable Federal Rate for the month in which the principal amount of the note is drawn. Interest shall be payable on an annual basis following the payment of the aggregate principal amount of the note. The principal amount is due upon demand by the Company. ICON Investment Group is under no obligation to provide additional funding to the Company.

(4)  Transactions with Related Parties

The Company is reimbursed for expenses incurred on behalf of the Managed Fund for the organization and offering of the Managed Fund, is entitled to receive a share of the Managed Fund’s revenues and reimbursement for administrative expenses and direct costs incurred in relation to the Managed Fund’s operations. Operating costs incurred by the Managed Fund include, among other things, legal, accounting, investor relations, operations, and geological and engineering analyses and reports. The Company’s share of the Managed Fund’s revenues will be in the same percentage that its capital contribution bears to the total net capital contributions of the Managed Fund, plus an additional 10% of the Managed Fund’s revenues. The Company will make a minimum capital contribution at least equal to 1% of the Managed Fund’s total investor capital contributions (net of organization and offering costs and the management fee).

Management Fee

The Company will receive a management fee equal to 15% of Managed Fund’s gross offering proceeds less the sum of all organization and offering costs. In no event will the sum of the Company’s management fee and the organization and offering costs exceed 15% of Managed Fund’s gross offering proceeds.

Supervisory Fee

The Company may receive a supervisory fee, at a competitive rate, but not based on arm’s-length negotiations, for each project for supervising the operations of the Managed Fund’s operator both before and during producing operations. The Company does not anticipate charging a separate supervisory fee for its supervisory services.

Gas Marketing Fees

The Company may receive a gas marketing fee, at a competitive rate, but not based on arm’s-length negotiations, for its services, if any, in marketing the Managed Fund’s natural gas production. The Company does not currently anticipate participating in the marketing of its natural gas production, and thus, does not anticipate charging any gas marketing fees.

Capital Contributions

On September 19, 2011, the Company received an additional equity contribution of $5,000,000 from ICON Investment Group (see Note 3).

At December 31, 2011, the Company has a $1 investment in a limited partnership, which represents the managing general partnership interest the Company owns in the Managed Fund (see Note 1).

(5)  Commitments and Contingencies

The Company will indemnify the investor general partners in the Managed Fund against all liabilities that exceed the investor general partners’ interests in the Managed Fund and the Company’s insurance proceeds.

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ICON Oil & Gas GP, LLC
(A Delaware Limited Liability Company)

BALANCE SHEET
May 31, 2012
(unaudited)

Assets

 
Investment in limited partnership   $         1  
Total Assets   $ 1  

Member's Equity

 
Member’s Equity:
        
Member's Equity   $ 5,000,001  
Less: Note receivable from Member     (5,000,000 ) 
Total Member's Equity   $ 1  

 
 
See Accompanying Notes to Balance Sheet.

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ICON Oil & Gas GP, LLC
(A Delaware Limited Liability Company)
NOTES TO BALANCE SHEET
May 31, 2012

(1)  Organization

ICON Oil & Gas GP, LLC (the “Company”) is a wholly-owned subsidiary of ICON Investment Group, LLC, a Delaware limited liability company (“ICON Investment Group”). The primary activity of the Company is sponsoring and managing publicly registered oil and gas drilling partnerships in the United States of America.

The Company is the managing general partner of ICON Oil & Gas Fund-A L.P. (the “Managed Fund”).

The Company was formed on May 9, 2011 as a Delaware limited liability company. The Company manages the business affairs of the Managed Fund, including, but not limited to, the investments that the Managed Fund makes, pursuant to the terms of the Managed Fund’s limited partnership agreement. The Managed Fund is a publicly registered oil and gas drilling partnership that was formed to invest primarily in oil and liquids-rich natural gas development wells, principally “fluid management” projects, where hydrocarbons are known to be present, located in the Mid-Continent region of the United States, with the potential investment in properties located within other types of projects and/or in other geographic areas that the Company may, from time to time, identify as prospective. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

The Company will receive a share of the Managed Fund’s revenues from the production of oil and natural gas. The Company’s share of the Managed Fund’s revenues will be in the same percentage that its capital contribution bears to the total capital contributions of the Managed Fund, plus an additional 10% of the Managed Fund’s revenues. The Company will make a minimum capital contribution at least equal to 1% of the Managed Fund’s total investor capital contributions (net of organizational and offering costs and the management fee).

The Company had an initial $1 investment in the Managed Fund, representing its managing general partnership interest. The Company accounts for its investment in the Managed Fund using the equity method of accounting as the sole limited partner has the ability to dissolve the partnership and remove the Company as the Managing General Partner.

On September 19, 2011, the Company received an additional equity contribution of $5,000,000 from ICON Investment Group.

The Company’s fiscal year ends on December 31.

(2)  Summary of Significant Accounting Policies

Basis of Presentation

The accompanying balance sheet of the Company has been prepared in accordance with U.S. generally accepted accounting principles (“US GAAP”). The management of the Company has evaluated all subsequent events through June 13, 2012, the date the balance sheet was issued.

Cash and Cash Equivalents

The Company’s cash is held at one financial institution and at times may exceed insured limits. The Company periodically evaluates the creditworthiness of this institution and has not experienced any losses on such deposits. The Company did not have any cash equivalents at May 31, 2012.

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires the Company 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 balance sheet. Actual results could differ from those estimates.

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ICON Oil & Gas GP, LLC
(A Delaware Limited Liability Company)
NOTES TO BALANCE SHEET
May 31, 2012

(3)  Capital Contribution from Member

On September 19, 2011, ICON Investment Group contributed a $5,000,000 demand promissory note issued by its Members to the Company as a capital contribution. There are no restrictions or covenants associated with this note, which would preclude the Company from receiving the principal or interest amounts due under the terms of the note. The note shall bear interest at an annual fixed rate equal to the then-current annual mid-term Applicable Federal Rate for the month in which the principal amount of the note is drawn. Interest shall be payable on an annual basis following the payment of the aggregate principal amount of the note. The principal amount is due upon demand by the Company. ICON Investment Group is under no obligation to provide additional funding to the Company.

(4)  Transactions with Related Parties

The Company is reimbursed for expenses incurred on behalf of the Managed Fund for the organization and offering of the Managed Fund, is entitled to receive a share of the Managed Fund’s revenues and reimbursement for administrative expenses and direct costs incurred in relation to the Managed Fund’s operations. Operating costs incurred by the Managed Fund include, among other things, legal, accounting, investor relations, operations, and geological and engineering analyses and reports. The Company’s share of the Managed Fund’s revenues will be in the same percentage that its capital contribution bears to the total net capital contributions of the Managed Fund, plus an additional 10% of the Managed Fund’s revenues. The Company will make a minimum capital contribution at least equal to 1% of the Managed Fund’s total investor capital contributions (net of organization and offering costs and the management fee).

Management Fee

The Company will receive a management fee equal to 15% of the Managed Fund’s gross offering proceeds less the sum of all organization and offering costs. In no event will the sum of the Company’s management fee and the organization and offering costs exceed 15% of the Managed Fund’s gross offering proceeds.

Supervisory Fee

If the Company serves as the operator for any of the Managed Fund’s wells, the Company may charge a separate supervisory fee for operating and maintaining the wells during producing operations. The Company does not anticipate serving as operator for any of the Managed Fund’s wells. Accordingly, the Company does not anticipate charging a supervisory fee for such services. If the Company were to serve as operator for any of the Managed Fund’s wells, the supervisory fee for such services would be at a rate competitive with rates charged by third-party operators providing similar services, but not based on arm’s-length negotiations.

Gas Marketing Fees

The Company may receive a gas marketing fee, at a competitive rate, but not based on arm’s-length negotiations, for its services, if any, in marketing the Managed Fund’s natural gas production. The Company does not currently anticipate participating in the marketing of its natural gas production, and thus, does not anticipate charging any gas marketing fees.

Capital Contributions

On September 19, 2011, the Company received an additional equity contribution of $5,000,000 from ICON Investment Group (see Note 3).

At May 31, 2012, the Company has a $1 investment in a limited partnership, which represents the managing general partnership interest the Company owns in the Managed Fund (see Note 1).

(5)  Commitments and Contingencies

The Company will indemnify the investor general partners in the Managed Fund against all liabilities that exceed the investor general partners’ interests in the Managed Fund and the Company’s insurance proceeds.

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EXHIBIT A

FORM OF LIMITED PARTNERSHIP AGREEMENT OF
ICON OIL & GAS FUND-A L.P.

THIS LIMITED PARTNERSHIP AGREEMENT (this “Agreement”) is made and entered into as of the date set forth below (the “Effective Date”), by and among ICON Oil & Gas GP, LLC (the “Managing General Partner”) and the remaining parties from time to time signing a Subscription Agreement for Limited Partnership Interests, these parties sometimes referred to as “Limited Partners,” or for Investor General Partnership Interests, 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.  Name, Principal Office and Address.  The name of the Partnership is “ICON Oil & Gas Fund-A L.P.” The principal office and place of business of the Partnership shall be located at 3 Park Avenue, 36th Floor, New York, New York 10016 or at such other address as the Managing General Partner may from time to time determine and specify by written notice to the Partners. The Partnership may also maintain such other offices and places of business as the Managing General Partner may deem advisable at any other place or places within the United States and, in connection therewith, the Managing General Partner shall qualify and remain qualified, and shall use its best efforts to qualify and keep the Partnership qualified, to do business under the laws of all such jurisdictions as may be necessary to permit the Partnership legally to conduct its business in such jurisdictions. The registered office of the Partnership shall be at 2711 Centerville Road, Suite 400, Wilmington (New Castle County), Delaware 19808. The name of its registered agent at such address shall be Corporation Service Company. The Managing General Partner may change the registered office and the registered agent of the Partnership, with written notice to the Partners.

1.03.  Address of Partners.  The principal place of business of the Managing General Partner and the places of residence of the other Partners shall be those addresses set forth opposite their respective names in Schedule A to this Agreement (as such may be supplemented or amended from time to time). Any Partner may change his, her or its respective place of residence by giving Notice of such change to the Partnership (and, in the case of the Managing General Partner, by also giving Notice thereof to all of the Partners), which Notice shall become effective five (5) days after receipt.

1.04.  Purpose.  The Partnership shall engage in all phases of the oil and natural gas business. This includes, without limitation, exploration for, development and production of oil and natural gas on the terms and conditions set forth below and any other proper purpose under the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”).

The Managing General Partner may not, without the affirmative vote of Participants whose Interests equal a majority of the total Interests, do the following:

1. change the investment and business purpose of the Partnership; or
2. cause the Partnership to engage in activities outside the stated business purposes of the Partnership through joint ventures with other entities.

ARTICLE II
DEFINITION OF TERMS

2.01.  Definitions.  As used in this Agreement, the following terms shall have the meanings set forth below:

1. “Adjusted Capital Account” means, with respect to any Partner, the balance in such Partner’s Capital Account as of the end of the relevant Allocation Year, after giving effect to the following adjustments:

(i) Credit to such Capital Account any amounts which such Partner is deemed obligated to restore pursuant to the penultimate sentences of Regulations Sections 1.704-2(g)(1) and 1.704-2(i)(5); and

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(ii) Debit to such Capital Account the items described in Regulations Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), and 1.704-1(b)(2)(ii)(d)(6).

The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Regulations Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith.

2. “Adjusted Capital Account Deficit” means, with respect to any Partner, the deficit balance, if any, in such Partner’s Adjusted Capital Account as of the end of the relevant Allocation Year.
3. “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. Specifically, Administrative Costs include (a) all costs of personnel (including officers or employees of the Managing General Partner or its Affiliates other than Controlling Persons) involved in the business of the Partnership, and, with respect to those officers or employees of the Managing General Partner or its Affiliates who provide services not related to the Partnership’s business, such costs shall be allocated to the Partnership pro rata in proportion to the amount of services performed on behalf of the Partnership to the total amount of services performed for the Managing General Partner or its Affiliates, but excluding overhead expenses attributable to such personnel; (b) all costs of borrowed money, taxes and assessments on the Partnership’s assets and other taxes applicable to the Partnership; (c) legal, audit, accounting, brokerage, appraisal and other fees; (d) printing, engraving and other expenses and taxes incurred in connection with the issuance, distribution, transfer, registration and recording of documents evidencing ownership of an interest in the Partnership or in connection with the business of the Partnership; (e) fees and expenses paid to independent contractors, bankers, brokers and services, leasing agents and sales personnel consultants and other management personnel, insurance brokers and other agents (all of which shall only be billed directly by, and be paid directly to, the provider of such services); (f) expenses (including the cost of personnel as described in (a) above) incurred in connection with the Partnership’s business and operations (including the costs and expenses of insurance premiums, etc.); (g) expenses of organizing, revising, amending, converting, modifying or terminating the Partnership; (h) expenses in connection with distributions made by the Partnership to, and communications and bookkeeping and clerical work necessary in maintaining relations with, Participants, including the costs of printing and mailing to such persons evidences of ownership of Interests and reports of meetings of the Partners and of preparation of proxy statements and solicitations of proxies in connection therewith; (i) expenses in connection with preparing and mailing reports required to be furnished to the Participants for investor reporting, tax reporting or other purposes, and reports that the Managing General Partner deems it to be in the best interests of the Partnership to furnish to the Participants and to their sales representatives; (j) any accounting, computer, statistical or bookkeeping costs necessary for the maintenance of the books and records of the Partnership (including an allocable portion of the Partnership’s costs of acquiring and owning computer equipment and software used in connection with the operations and reporting activities of the Partnership and any other investment funds sponsored by the Managing General Partner or any of its Affiliates, the Partnership’s interest in which shall be liquidated in connection with the Partnership’s liquidation); (k) the cost of preparation and dissemination of the informational material and documentation relating to the Partnership’s business and operations; (l) the costs and expenses incurred in qualifying the Partnership to do business in any jurisdiction, including fees and expenses of any resident agent appointed by the Partnership; and (m) the costs incurred in connection with any litigation or regulatory proceedings in which the Partnership is involved.

Administrative Costs shall be limited as follows:

a. no Administrative Costs charged shall be duplicated under any other category of expense or cost; and
b. 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 a 5% or more equity

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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.
4. “Administrator” means the official or agency administering the securities laws of a state.
5. “Affiliate” means with respect to a specific person:
a. 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;
b. 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;
c. any person directly or indirectly controlling, controlled by, or under common control with the specified person;
d. any officer, director, trustee or partner of the specified person; and
e. if the specified person is an officer, director, trustee or partner, any person for which the person acts in any such capacity.
6. “Agreement” means this Limited Partnership Agreement, including all exhibits to this Agreement.
7. “Allocation Year” means (i) the period commencing on the Effective Date and ending on December 31, 2011, (ii) any subsequent twelve (12) month period commencing on January 1 and ending on December 31, or (iii) any portion of the period described in clauses (i) or (ii) for which the Partnership is required to allocate Profit, Loss, and other items of Partnership income, gain, loss or deduction pursuant to Article V.
8. “Assessments” means additional amounts of capital that may be mandatorily required of or paid voluntarily by a Participant beyond his subscription commitment.
9. “Capital Account” or “account” means the account established for each party, maintained as provided in Section 5.01 and its subsections.
10. “Capital Contribution” means the amount agreed to be contributed to the Partnership by a Partner pursuant to Sections 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 and currently in effect.
13. “Controlling Person” means, with respect to the Managing General Partner or any of its Affiliates, any of its chairmen, directors, presidents, vice presidents, corporate secretary, treasurer, any holder of a 5% or larger equity interest in the Managing General Partner or any such Affiliate or any other Person, in each case, having the power to direct or cause the direction of the Managing General Partner or any such Affiliate, whether through the ownership of voting securities, by contract or otherwise. It is not intended that every person who carries a title such as vice president, senior vice president, secretary, controller or treasurer or holds such an equity interest be considered a Controlling Person.
14. “Cost,” when used with respect to the sale or transfer of property to the Partnership by the Managing General Partner, means:
a. the sum of the prices paid by the seller or transferor to an unaffiliated person for the property, including bonuses;
b. title insurance or examination costs, brokers’ commissions, filing fees, recording costs, transfer taxes, if any, and like charges in connection with the acquisition of the property;

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c. a pro rata portion of the seller’s or transferor’s actual necessary and reasonable expenses for seismic and geophysical services; and
d. 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, geophysical, 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.

15. “Dealer-Manager” means ICON Securities Corp., an Affiliate of the Managing General Partner, the broker/dealer that will manage the offering and sale of the Interests.
16. “Depreciation” means, for each Allocation Year, an amount equal to the depreciation, amortization, or other cost recovery deduction (excluding depletion related to the Partnership’s oil and gas properties) allowable with respect to an asset for such Allocation Year for federal income tax purposes, except that with respect to any asset whose Gross Asset Value differs from its adjusted tax basis for federal income tax purposes at the beginning of such Allocation Year, Depreciation shall be an amount that bears the same ratio to such beginning Gross Asset Value as the federal income tax depreciation, amortization, or other cost recovery deduction for such Allocation Year bears to such beginning adjusted tax basis; provided, however, that if the adjusted basis for federal income tax purposes of an asset at the beginning of such Allocation Year is zero, Depreciation shall be determined with reference to such beginning Gross Asset Value using any reasonable method selected by the Managing General Partner.
17. “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.
18. “Direct Costs” means all actual and necessary costs directly incurred for the benefit of the Partnership and generally attributable to the goods and services provided to the Partnership by parties other than the Sponsor or its Affiliates. Direct Costs 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 Section 4.03(d)(7) or pursuant to the Managing General Partner’s role as Tax Matters Partner.
19. “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 Partner’s Capital Account bears to the aggregate positive balance of the Capital Accounts of all of the Partners 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).
20. “Drilling and Operating Agreement” means the proposed Drilling and Operating Agreement or similar agreement between the Operator and the Partnership as Developer, a copy of the proposed form of which is attached to this Agreement as Exhibit (II).

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21. “Exploratory Well” means a well drilled to:
a. find commercially productive hydrocarbons in an unproved area;
b. find a new commercially productive Horizon in a field previously found to be productive of hydrocarbons at another Horizon; or
c. significantly extend a known prospect.
22. “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.
23. “Final Terminating Event” means any one of the following:
a. the expiration of the Partnership’s fixed term;
b. notice to the Participants by the Managing General Partner of its election in its discretion to terminate the Partnership’s affairs in the Partnership’s best interests;
c. notice by the Participants to the Managing General Partner of their similar election through the affirmative vote of Participants whose Interests equal a majority of the total Interests; or
d. the termination of the Partnership under Section 708(b)(1)(A) of the Code or the Partnership ceases to be a going concern.
24. “Gross Asset Value” means with respect to any asset, the asset’s adjusted basis for federal income tax purposes, except as follows:

(i)  The initial Gross Asset Value of any asset contributed by a Partner to the Partnership shall be the gross fair market value of such asset as determined by the Managing General Partner;

(ii)  The Gross Asset Values of all items of Partnership Property shall be adjusted to equal their respective Mark to Market Values (taking Code Section 7701(g) into account) as of the following times: (A) the acquisition of an additional Interest in the Partnership by any new or existing Partner in exchange for more than a de minimis Capital Contribution, (B) the distribution by the Partnership to a Partner of more than a de minimis amount of Partnership Property as consideration for an Interest in the Partnership, and (C) the liquidation of the Partnership within the meaning of Regulations Section 1.704-1(b)(2)(ii)(g); provided that an adjustment described in clause (A) of this paragraph shall be made only if the Managing General Partner reasonably determines that such adjustment is necessary to reflect the relative economic interests of the Partners in the Partnership;

(iii)  The Gross Asset Value of any item of Partnership Property distributed to any Partner (other than as consideration for an Interest in the Partnership as described in clause (B) of subparagraph (ii) above) shall be adjusted to equal the gross fair market value (taking Code Section 7701(g) into account) of such item on the date of distribution; and

(iv)  The Gross Asset Values of each item of Partnership Property shall be increased (or decreased) to reflect any adjustments to the adjusted basis of such assets pursuant to Code Section 734(b) or Code Section 743(b), but only to the extent that such adjustments are taken into account in determining Capital Accounts pursuant to Regulations Section 1.704-1(b)(2)(iv)(m) and subparagraph (vi) of the definition of “Profits” and “Losses” or Section 5.02(c)(1)(vii); provided, however, that Gross Asset Values shall not be adjusted pursuant to this subparagraph (iv) to the extent that an adjustment pursuant to subparagraph (ii) is required in connection with a transaction that would otherwise result in an adjustment pursuant to this subparagraph (iv).

If the Gross Asset Value of an asset has been determined or adjusted pursuant to subparagraph (i), (ii), or (iv), such Gross Asset Value shall thereafter be adjusted by the Simulated Depletion Deductions or Depreciation taken into account with respect to such asset, for purposes of computing Profits and Losses.

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25. “Gross Liability Value” means with respect to any liability of the Partnership described in Regulations Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such liability in an arm's length transaction. The Gross Liability Value of each liability of the Partnership described in Regulations Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Gross Asset Values.
26. “Horizon” means a zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.
27. “ICON Oil & Gas Program” means the series of up to three limited partnerships, of which the Partnership is the first to offer its Interests, formed for the purpose of investing primarily in oil and natural gas development wells.
28. “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 oil and natural gas properties based on the evaluation of all pertinent economic, financial, geologic and engineering information available to the Sponsor or its Affiliates.
29. “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.
30. “Intangible Drilling Costs” or “Non-Capital Expenditures” means those expenditures associated with property acquisition and the drilling and completion of oil and natural gas wells that under the law in effect at the time the expenses are incurred are generally accepted as fully deductible currently for federal income tax purposes. This includes:
a. 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 the taxpayer has the option to currently deduct pursuant to Section 263(c) of the Code and Regulations Section 1.612-4, and are generally termed “intangible drilling and development costs”;
b. the expense of plugging and abandoning any well before a completion attempt; and
c. the costs (other than Tangible Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.

The Partnership intends to expense all Intangible Drilling Costs.

31. “Interests” means up to 4,000 Limited Partnership Interests in the Partnership and up to 16,000 Investor General Partnership Interests in the Partnership, which will be converted to the same number of Limited Partnership Interests as set forth in Section 6.01(b), purchased by Participants in the Partnership under the provisions of Section 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 Interests. The Partnership reserves the right to adjust the number of Investor General Partnership Interests, Limited Partnership Interests and Investor General Partnership Interests converted to Limited Partnership Interests set forth above so long as they do not exceed 20,000 Interests, in the aggregate.
32. “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.
33. “Investor General Partners” means:
a. the Persons signing the Subscription Agreement as Investor General Partners; and
b. the Managing General Partner to the extent of any optional subscription as an Investor General Partner under Section 3.03(b).

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All Investor General Partners shall be of the same class and have the same rights. Each of the Investor General Partners shall be referred to as an Investor General Partner.

34. “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.
35. “Leases” means full or partial interests in oil and natural gas 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.
36. “Limited Partners” means:
a. the Persons signing the Subscription Agreement as Limited Partners;
b. the Managing General Partner to the extent of any optional subscription as a Limited Partner under Section 3.03(b);
c. the Investor General Partners on the conversion of their Investor General Partnership Interests to Limited Partnership Interests pursuant to Section 6.01(b); and
d. any other Persons who are admitted to the Partnership as additional or substituted Limited Partners.

Except as provided in Section 3.05(b), with respect to the required additional Capital Contributions of Investor General Partners, all Limited Partners shall be of the same class and have the same rights. Each of the Limited Partners shall be referred to as a Limited Partner.

37. “Managing General Partner” means:
(ii) ICON Oil & Gas GP, LLC; or
(iii) 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.
38. “Managing General Partner Sharing Ratio” with respect to the Managing General Partner, means the sum of (a) 11% plus (b) the additional percentage of aggregate Capital Contributions of the Participants (other than the Managing General Partner if the Managing General Partner subscribes for Interests pursuant to Section 3.03(b)) (net of the Management Fee set forth in Section 4.04(a)(2)(f)) as of the Offering Termination Date that the Managing General Partner pays in excess of 1%. Under no circumstances shall the Managing General Partner Sharing Ratio with respect to the Managing General Partner be in excess of 50% of the Partnership’s Profits. With respect to the Participants, the Managing General Partner Sharing Ratio equals the difference between 100% and the Managing General Partner Sharing Ratio with respect to the Managing General Partner.
39. “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, that the Partnership’s subscription period is closed and the acceptance of subscriptions ceases, which may be any date up to and including December 31, 2012, unless this offering is extended by the Managing GP pursuant to a supplement to this prospectus.

Notwithstanding the above, the Offering Termination Date may not extend beyond the time that subscriptions for the maximum number of Interests set forth in Section 3.03(c)(1) have been received and accepted by the Managing General Partner.

40. “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 oil and natural gas;

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(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 disposal and injection wells, transporting waste water by pipeline, truck or barge, reworking, workover, subsequent equipping, and similar expenses relating to any well, the Managing General Partner’s well supervision fees, if any, set forth in Section 4.04(a)(2)(D) and the reimbursement of the Managing General Partner’s Administrative Costs set forth in Section 4.04(a)(2)(C); but do not include the costs to re-enter and deepen an existing well, complete the well to deeper formations or reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper formations or reservoirs.

41. “Operator” means any operator of Partnership Wells pursuant to a Participation Agreement and/or Operating Agreement entered into by such Person and the Partnership.
42. “Organization and Offering Costs” means all costs of organizing and selling the offering including, but not limited to:
a. total underwriting and brokerage discounts and commissions, including fees of the underwriters’ attorneys, the Dealer-Manager fee and sales commissions;
b. expenses for printing, mailing, transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts;
c. expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants’ and attorneys’ fees; and
d. other front-end fees.
43. “Overriding Royalty Interest” means an interest in the oil and natural gas 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.
44. “Partially Adjusted Capital Account” means, with respect to any Participant for any Allocation Year, the Capital Account balance of such Participant as of the beginning of such Allocation Year, adjusted as set forth in the definition of Capital Account for all contributions and distributions during such period and all special allocations pursuant to Section 5.02(c)(1) with respect to such Period before giving effect to the allocations pursuant to Sections 5.02(a) or (b), increased by the sum of (a) the Participant’s share of Partnership Minimum Gain (as determined pursuant to Regulations Section 1.704-2(g)), (b) the Participant’s share of Partner Nonrecourse Debt Minimum Gain (as determined pursuant to Regulations Section 1.704-2(i)), and (c) the amount, if any, which such Participant is obligated to contribute to the capital of the Partnership pursuant to this Agreement (but only to the extent that such capital contribution obligation has not been taken into account in determining such Partner’s share of Partner Nonrecourse Debt Minimum Gain).
45. “Participants” means:
a. the Managing General Partner to the extent of its optional subscription under Section 3.03(b);
b. the Limited Partners; and
c. the Investor General Partners.
46. “Partners” means:
a. the Managing General Partner;
b. the Investor General Partners; and
c. the Limited Partners.
47. “Partnership” means ICON Oil & Gas Fund-A L.P.

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48. “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.
49. “Partnership Well” means a well, some portion of the revenues from which is received by the Partnership.
50. “Person” means a natural person, partnership, corporation, association, trust or other legal entity.
51. “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.
52. “Profits” and “Losses” mean, for each Allocation Year, an amount equal to the Partnership’s taxable income or loss for such Allocation Year, determined in accordance with Code Section 703(a) (for this purpose, all items of income, gain, loss, or deduction required to be stated separately pursuant to Code Section 703(a)(1) shall be included in taxable income or loss), with the following adjustments (without duplication):

(i)  Any income of the Partnership that is exempt from federal income tax and not otherwise taken into account in computing Profits or Losses pursuant to this definition of “Profits” and “Losses” shall be added to such taxable income or loss;

(ii)  Any expenditures of the Partnership described in Code Section 705(a)(2)(B) or treated as Code Section 705(a)(2)(B) expenditures pursuant to Regulations Section 1.704-1(b)(2)(iv)(i), and not otherwise taken into account in computing Profits or Losses pursuant to this definition of “Profits” and “Losses” shall be subtracted from such taxable income or loss;

(iii)  In the event the Gross Asset Value of any item of Partnership Property is adjusted pursuant to subparagraphs (ii) or (iii) of the definition of Gross Asset Value, the amount of such adjustment shall be treated as an item of gain (if the adjustment increases the Gross Asset Value of the item of Property) or an item of loss (if the adjustment decreases the Gross Asset Value of the item of Property) from the disposition of such item of Property and shall be taken into account for purposes of computing Profits or Losses;

(iv)  In the event the Gross Liability Value of any liability of the Partnership described in Regulations Section 1.752-7(b)(3)(i) is adjusted as required by this Agreement, the amount of such adjustment shall be treated as an item of loss (if the adjustment increases the Gross Liability Value of such liability of the Company) or an item of gain (if the adjustment decreases the Gross Liability Value of such liability of the Company) and shall be taken into account for purposes of computing Profits or Losses;

(v)  Gain or loss resulting from any disposition of Property with respect to which gain or loss is recognized for federal income tax purposes shall be computed by reference to the Gross Asset Value of the Property disposed of, notwithstanding that the adjusted tax basis of such Property differs from its Gross Asset Value;

(vi)  In lieu of the depreciation, amortization, and other cost recovery deductions taken into account in computing such taxable income or loss, there shall be taken into account Depreciation for such Allocation Year, computed in accordance with the definition of “Depreciation”;

(vii)  To the extent an adjustment to the adjusted tax basis of any item of Partnership Property pursuant to Code Section 734(b) is required, pursuant to Regulations Section 1.704-1(b)(2)(iv)(m)(4), to be taken into account in determining Capital Accounts as a result of a distribution other than in liquidation of a Partner’s Interest, the amount of such adjustment shall be treated as an item of gain (if the adjustment increases the basis of the item of Property) or loss (if

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the adjustment decreases such basis) from the disposition of such item of Property and shall be taken into account for purposes of computing Profits or Losses; and

(viii)  Notwithstanding any other provision of this definition, any items that are specially allocated pursuant to Section 5.02(c) shall not be taken into account in computing Profits or Losses.

The amounts of the items of Company income, gain, loss, or deduction available to be specially allocated pursuant to Section 5.02(c) shall be determined by applying rules analogous to those set forth in subparagraphs (i) through (vii) above.

53. “Program” means one or more limited partnerships or other investment vehicles formed, or to be formed, for the primary purpose of:
a. exploring for natural gas, oil and other hydrocarbon substances; or
b. 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.
54. “Prospect” means an area covering lands that 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 may be different for different Horizons and may be enlarged or contracted from time to time on the basis of subsequently acquired information to define the anticipated limits of the associated hydrocarbon reserves and to include all acreage encompassed therein.

If a 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.

55. “Prospectus” means the Prospectus included in the Registration Statement on Form S-1 relating to the offer and sale of the Interests (the “Registration Statement”), which has been filed with the Securities and Exchange Commission (the “Commission”) under the Securities Act of 1933, as amended (the “Act”). As used in this Agreement, the terms “Prospectus” and “Registration Statement” refer solely to the Prospectus and Registration Statement, as amended, described above, except that:
a. from and after the date on which any post-effective amendment to the Registration Statement is declared effective by the Commission, the term “Registration Statement” shall refer to the Registration Statement as amended by that post-effective amendment, and the term “Prospectus” shall refer to the Prospectus then forming a part of the Registration Statement; and
b. if the Prospectus filed pursuant to Rule 424(b) or (c) promulgated by the Commission under the Act differs from the Prospectus on file with the Commission at the time the Registration Statement or any post-effective amendment thereto shall have become effective, the term “Prospectus” shall refer to the Prospectus filed pursuant thereto from and after the date on which it was filed.
56. “Proved Developed Oil and Gas Reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
57. “Proved Reserves” means the estimated quantities of crude oil, natural gas, and natural gas liquids that 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

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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.
a. 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:
i. that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and
ii. 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.

b. 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.
c. Estimates of proved reserves do not include the following:
i. oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;
ii. 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;
iii. crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
iv. crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
58. “Proved Undeveloped Reserves” means reserves that are expected to be recovered from either:
a. new wells on undrilled acreage; or
b. 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 virtually 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.

59. “Regulations” or “Treasury Regulations,” or “Treas. Reg.” means the Income Tax Regulations, including Temporary Regulations, promulgated under the Code, as such regulations are amended from time to time.
60. “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:
a. 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

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b. a transaction involving the conversion to corporate, trust or association form of only the Partnership if, as a consequence of the transaction, there will be no significant adverse change in any of the following:
i. voting rights;
ii. the Partnership’s term of existence;
iii. the Managing General Partner’s compensation; and
iv. the Partnership’s investment objectives.
61. “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.
62. “Sales Commissions” means all underwriting and brokerage discounts and commissions incurred in the sale of Interests payable in cash to registered broker/dealers, but excluding the 3% Dealer-Manager fee.

All items of compensation to underwriters or dealers, including, but not limited to, sales commissions, expenses, rights of first refusal, consulting fees, finders' fees and all other items of compensation of any kind or description paid by the Partnership, directly or indirectly, shall be taken into consideration in computing the amount of allowable Sales Commissions.

63. “Selling Agents” means the broker/dealers which are selected by the Dealer-Manager to participate in the offer and sale of the Interests.
64. “Simulated Basis” means the Gross Asset Value of any oil and gas property (as defined in Code Section 614).
65. “Simulated Depletion Deductions” means the simulated depletion allowance computed by the Partnership with respect to its oil and gas properties pursuant to Regulations Section 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion, the Partnership will apply the higher of the simulated cost depletion method or the simulated percentage depletion method for each oil and gas property under Regulations Section 1.704-1(b)(2)(iv)(k)(2).
66. “Simulated Gain” or “Simulated Loss” means the simulated gain or simulated loss computed by the Partnership with respect to its oil and gas properties pursuant to Regulations Section 1.704-1(b)(2)(iv)(k)(2).
67. “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:
a. 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
b. 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 Interests.

68. “Subscription Agreement” means an executed Subscription Agreement substantially in the form attached as an exhibit to the Prospectus.
69. “Tangible Costs” or “Capital Expenditures” means those costs associated with property acquisition and drilling and completing oil and natural gas wells which are generally accepted as capital expenditures under the Code. This includes all of the following:
a. costs of equipment, parts and items of hardware used in drilling and completing a well;

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b. the costs (other than Intangible Drilling Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs; and
c. those items necessary to deliver acceptable oil and natural 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.
70. “Tax Matters Partner” means the Managing General Partner.
71. “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.  ICON Oil & Gas GP, LLC shall serve as Managing General Partner of the Partnership. ICON Oil & Gas GP, LLC shall further serve as a Participant to the extent of any subscription made by it pursuant to Section 3.03(b).

Limited Partners and Investor General Partners, including the Managing General Partner and its Affiliates to the extent, if any, they purchase Interests, shall serve as Participants.

3.02.  Participants.

3.02(a).  Limited Partner at Formation.  ICON Investment Group, LLC, as Original Limited Partner, has acquired one Interest and has made a Capital Contribution of $1. 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 Interest. The Original Limited Partner shall then cease to be a Limited Partner in the Partnership with respect to that Interest.

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 Interests sold do not exceed the maximum number of Interests set forth in Section 3.03(c)(1).

3.02(c).  Admission of Participants.  No action or consent by the Participants shall be required for the admission of additional Participants pursuant to this Agreement.

All subscribers’ funds shall be held in an interest bearing account or accounts by an independent escrow holder and shall not be released to the Partnership until the receipt and acceptance of the minimum amount of subscription proceeds set forth in Section 3.03(c)(2). Thereafter, subscriptions may be paid directly to a 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 an Interest shall be $10,000, except as set forth below, and shall be designated on each Participant’s Subscription Agreement and payable as set forth in Section 3.05(b)(1). The minimum subscription per Participant shall be one half (½) Interest ($5,000). Fractional subscriptions shall be accepted in $1,000 increments, beginning with $6,000, $7,000, etc.

Notwithstanding the foregoing, the subscription price for the Managing General Partner, its officers, directors, and Affiliates; Selling Agents and their registered representatives and principals; and registered investment advisers and their clients, shall be reduced by an amount equal to the 7% Sales Commission, which shall not be paid with respect to those sales. In addition, certain volume discounts with respect to Sales Commissions may be available for certain purchases of Interests.

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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).  Managing General Partner’s Optional Subscriptions for Interests.  In addition to the Managing General Partner’s required Capital Contributions under Section 3.04(a), the Managing General Partner may subscribe under the provisions of Section 3.03(a) and its subsections for additional Interests, which amount of Interests shall not be applied towards the minimum number of Interests required to be sold under Section 3.03(c)(2), and, subject to the limitations on voting rights set forth in Section 4.03(c)(3), to that extent of such additional subscriptions, the Managing General Partner shall be deemed to be a Participant in the Partnership for all purposes under this Agreement.

3.03(c).  Maximum and Minimum Number of Interests.

3.03(c)(1).  Maximum Number of Interests.  The maximum number of Interests may not exceed 20,000 Interests, which is $200,000,000 of cash subscription proceeds, excluding the subscription discounts permitted under Section 3.03(a)(1). The Managing General Partner may reduce the maximum number of Interests available based on the participation in other partnerships that are part of the ICON Oil & Gas Program.

3.03(c)(2).  Minimum Number of Interests.  The minimum number of Interests shall equal at least 200 Interests, but in any event not less than the number of Interests that provides the Partnership with cash subscription proceeds of $2,000,000, excluding the subscription discounts permitted under Section 3.03(a)(1).

If subscriptions for the minimum number of Interests have not been received and accepted at the Offering Termination Date, 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, without deduction for any fees.

The Partnership may break escrow and begin its drilling activities, in the Managing General Partner’s sole discretion, on receipt and acceptance 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 Managing General Partner within 30 days of their receipt. If a subscription is rejected, then all of the subscriber’s funds shall be returned to the subscriber promptly, with interest earned and without deduction for any fees.

3.03(d)(3).  Admission to the Partnership.  The Participants shall be admitted to the Partnership as follows:

(i) Once subscriptions for the minimum number of Interests have been received, the Managing General Partner shall set the Initial Closing Date, which shall be no later than 15 days after the release from the escrow account of Participants’ subscription proceeds to the Partnership; or
(ii) if a Participant’s subscription proceeds are received by the Partnership after the Initial Closing Date, the Managing General Partner shall set a Closing Date not later than the last day of the calendar month in which the Managing General Partner accepted the Participant’s Subscription Agreement.

3.04.  Capital Contributions of the Managing General Partner.  

3.04(a).  Managing General Partner’s Required Capital Contributions.  The Managing General Partner is required to pay the costs or make a required Capital Contribution at the Offering Termination Date in an amount equal to not less than 1% of the aggregate Capital Contributions of the Participants (other than the Managing General Partner if the Managing General Partner subscribes for Interests pursuant to Section 3.03(b)) (net of the management fee set forth in Section 4.04(a)(2)(f) and Organization and Offering Costs) as of such date.

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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:

(a) the liquidation of the Partnership; or
(b) the liquidation of the Managing General Partner’s interest in the Partnership.

This shall be determined after taking into account all adjustments and allocations to the Managing General Partner’s Capital Account 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 the liquidation occurs or, if later, within 90 days after the date of the liquidation.

3.04(c).  Managing General Partner’s Partnership Interest for Capital Contributions.  The interest of the Managing General Partner, as Managing General Partner and not as a Participant, in the capital and profits of the Partnership is fully vested and non-forfeitable as of the date of the formation of the Partnership and is in consideration for, and is the only consideration for, its obligations to the Partnership under this Agreement.

3.04(d).  Managing General Partner’s Right to Assign Its Partnership Interest.  The Managing General Partner has the right at any time, in its discretion, without the consent of the Participants, and without affecting the allocation of costs and revenues to the Participants or the Managing General Partner’s voting rights under this Agreement, to sell, contribute, exchange or otherwise transfer all or any portion of its interest as Managing General Partner or as a Participant (if it purchases Interests) in the Partnership, or any interest therein to an Affiliate of the Managing General Partner. In that event, except as otherwise may be permitted under this Agreement, if the Affiliated transferee of the Managing General Partner’s transferred interest in the Partnership does not become a substituted Managing General Partner in the Partnership, the Affiliated transferee, as a partner in the Partnership for tax purposes only, shall have the right to receive the share of the Partnership’s Profits, Losses, income, gains, deductions, credits and depletion allowances, or items thereof, and cash distributions and returns of capital (including, but not limited to, cash distributions and returns of capital on dissolution and liquidation of the Partnership) to which the Managing General Partner would otherwise be entitled under this Agreement with respect to its transferred interest in the Partnership.

Subject to the foregoing, the transfer of the Managing General Partner’s interest in the Partnership to any of its Affiliates may be made on any terms and conditions as the Managing General Partner determines, in its discretion, and the Partnership and the Participants shall have no right to receive or otherwise share in any consideration received by the Managing General Partner from its Affiliates for the transfer of the Managing General Partner’s interest in the Partnership.

No transfer of the Managing General Partner’s interest in the Partnership to its Affiliates under this Section 3.04(d) shall require an accounting by the Managing General Partner or the Partnership to the Participants.

3.05.  Payment of Subscriptions.

3.05(a).  Managing General Partner’s Subscriptions.  The Managing General Partner shall pay any optional subscription under Section 3.03(b) as set forth in Section 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 Amounts.  A Participant shall pay the subscription amount designated on his Subscription Agreement 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 until his subscription proceeds are paid to the Partnership. All interest distributions shall be in the ratio that the number of Interests held by each Participant multiplied by the number of days the Participant’s subscription proceeds were held in the escrow account bears to the sum of that calculation for all Participants whose subscription proceeds were paid to the Managing General Partner at the same time.

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

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Partner, in addition to their subscription amounts, for their pro rata share (determined by the number of Investor General Partner Interests owned to the total number of Investor General Partnership Interests outstanding) of any Partnership obligations and liabilities that are recourse to the Investor General Partners and are represented by their ownership of Interests before the conversion of Investor General Partnership Interests to Limited Partnership Interests under Section 6.01(b).

3.05(b)(3).  Default Provisions.  The failure of an Investor General Partner to timely make a required additional Capital Contribution 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 Interests, must pay the defaulting Investor General Partner’s share of Partnership liabilities and obligations called for by the Managing General Partner. Such contributions shall be treated as though made by the defaulting Investor General Partner. 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 Interests, until the amount in default is recovered in full plus interest at the legal rate; and
(iii) may commence legal action against the defaulting Investor General Partner 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 of the Partnership in any manner except for the exclusive benefit of the Partnership.

Neither this Agreement nor any other agreement between the Managing General Partner and the Partnership shall contractually limit any fiduciary duty owed to the Participants by the Managing General Partner under applicable law.

3.06(b).  Special Account After the Receipt of the Minimum Partnership Subscriptions.  Following the receipt of the minimum number of Interest and breaking escrow, the funds of the Partnership shall be held in a separate 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 shall not be invested in the securities of another person except in the following instances:

(i) investments in Working Interests or undivided Lease interests made in the ordinary course of the Partnership’s business;
(ii) temporary investments made as set forth in Section 3.06(c)(2);
(iii) multi-tier arrangements meeting the requirements of Section 4.03(d)(15);
(iv) investments involving less than 5% of the Partnership’s subscription proceeds that 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. Any interest income from such temporary investments shall be allocated pro rata to the Participants providing such Capital Contributions.

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ARTICLE IV
CONDUCT OF OPERATIONS

4.01.  Acquisition of Leases.

4.01(a).  Assignment to Partnership.

4.01(a)(1).  In General.  The Managing General Partner shall select, acquire and assign or cause to have assigned to the Partnership full or partial interests in Leases, by any method customary in the oil and natural gas industry, subject to the terms and conditions set forth below.

The Partnership and the other partnerships in the 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 and interests in Leases on federal and state lands.

4.01(a)(3).  Managing General Partner’s Discretion as to Terms and Burdens of Acquisition.  Subject to the provisions of Section 4.03(d) and its subsections, the acquisitions of Leases (including interests therein) or other property may be made under any terms and obligations, including any limitations as to the Horizons to be assigned to the Partnership and subject to any burdens as the Managing General Partner deems necessary in its sole discretion.

4.01(a)(4).  Cost of Leases.  The Managing General Partner shall specifically identify all Leases it acquires for the benefit of the Partnership. Any such Leases contributed to the Partnership by the Managing General Partner or its Affiliates shall be credited towards the Managing General Partner’s Capital Contribution set forth in Section 3.04(a) at the Cost of the Lease as described in the Prospectus under “Compensation — Compensation Related to the Operation of the Partnership — Oil and Natural Gas Revenues,” unless the Managing General Partner, in its sole discretion, 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. Additionally, from time to time, the Managing General Partner’s Lease costs on a Prospect may be significantly higher than the fair market value, and in that event the Managing General Partner’s credit to its Capital Contribution to the Partnership and its Capital Account under this Agreement shall be the greater amount; provided, however, that if the sale, transfer or conveyance of a Lease is from an affiliated Program that has held the lease for more than two years and in which Program the interest of the Managing GP or its Affiliates is substantially similar to, or less than, its interest in the Partnership, the sale, transfer or conveyance may be made at fair market value.

A determination of fair market value must be supported by an appraisal from an Independent Expert.

4.01(a)(5).  The Managing General Partner and Its Affiliates’ Rights in the Remainder Interests.  Subject to the provisions of Section 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 and the Participants.

4.01(a)(6).  No Breach of Duty.  Subject to the provisions of Section 4.03 and its subsections, acquisition of Leases from the Managing General Partner or its Affiliates shall not be considered a breach of any obligation owed by them to the Partnership or the Participants.

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4.01(b).  No Overriding Royalty Interests.  Neither the Managing General Partner 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.  To the extent that the Partnership acquires Leases, legal title to such Leases acquired by the Partnership shall be held on a permanent basis in the name of the Partnership. However, legal title to Leases acquired by the Partnership may be held temporarily in the name of, and legal title to other partnership properties, including interests in Leases, may be held 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.

Notwithstanding, legal title to such Leases may be held on a permanent basis in the name of a special nominee entity organized by the Managing GP, provided that the nominee’s sole purpose is the holding of record title for oil and gas properties and it engages in no other business and incurs no other liabilities; and either a ruling from the Internal Revenue Service or an opinion of qualified tax counsel is obtained to the effect that such arrangement will not change the ownership status of the Partnership for federal income tax purposes.

4.01(c)(2).  Managing General Partner’s Discretion.  The Managing General Partner shall take the steps that are necessary in its best judgment to render title to the Leases to be acquired by the Partnership acceptable for the purposes of the Partnership. The Managing General Partner shall be free, however, to use its own best judgment in waiving title requirements.

The Managing General Partner shall not be liable to the Partnership or to the other parties for any mistakes of judgment; nor shall the Managing General Partner be deemed to be making any warranties or representations, express or implied, as to the validity or merchantability of the title to the Leases assigned to the Partnership or the extent of the interest covered thereby except as otherwise provided in the Drilling and Operating Agreement.

4.01(c)(3).  Commencement of Operations.  The Partnership shall not begin operations unless the Managing General Partner is satisfied that necessary title requirements, if any, have been satisfied or waived by the Managing General Partner in its sole discretion.

4.02.  Conduct of Operations.

4.02(a).  In General.  The Managing General Partner shall operate the Partnership and establish a Program in accordance with the Prospectus.

4.02(b).  Management.  Subject to any restrictions contained in this Agreement, the Managing General Partner shall exercise full control over all operations of the Partnership.

4.02(c).  General Powers of the Managing General Partner.

4.02(c)(1).  In General.  Subject to the provisions of Section 4.03 and its subsections, and to any authority that may be granted the Operator under Section 4.02(c)(3)(b), the Managing General Partner shall have full authority to do all things deemed necessary or desirable by it in the conduct of the business of the Partnership. Without limiting the generality of the foregoing, the Managing General Partner is expressly authorized to engage in:

(i) the making of all determinations of which Leases, wells and operations will be participated in by the Partnership, which includes:
(a) which Leases are developed;
(b) which Leases are abandoned; and

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(c) which Leases are sold or assigned to other parties, including other investor ventures organized by the Managing General Partner or any of its 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 the Partnership’s hedging of its oil and natural gas and the pledge of up to 100% of the Partnership’s assets and reserves in connection therewith, and in this regard the Partnership has confirmed its authorization to the Managing General Partner to enter into hedging agreements on its behalf, and has ratified all actions previously taken by the Managing General Partner, or its successors in interest by merger or otherwise, in connection therewith;
(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 (including tax 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 the Partnership’s 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, which insurance coverage will include public liability insurance with limits, including umbrella policy limits, of $50 million. Other insurance policies, such as well control, environmental damage and worker’s compensation, will also be obtained if the Partnership is going to engage directly in operating activities or will otherwise be exposed to potential losses in these areas. The Managing General Partner will notify the Participants 30 days prior to the effective date of any adverse material change in the Partnership's insurance coverage. If the insurance coverage is to be materially reduced, the Participants have a right to convert their Interests from Investor General Partner Interest to Limited Partner Interests prior to such reduction pursuant to Section 6.01(b)(4);
(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 of 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 Section 4.03(d)(6);
(ix) the formation of any further limited or general partnership, tax partnership, joint venture, or other relationship which it deems desirable with any parties who it, in its sole 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 incurring other legal expenses; and

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(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 Affiliated with it, which party shall have the same powers in the conduct of the duties as would the Managing General Partner. The delegation, however, shall not relieve the Managing General Partner of its responsibilities under this Agreement.

4.02(c)(3)(b).  Delegation to Operator.  The Managing General Partner is specifically authorized to delegate any or all of its duties to the Operator by executing the Drilling and Operating Agreement on behalf of the Partnership. This delegation shall not relieve the Managing General Partner of its responsibilities under this Agreement.

4.02(c)(4).  Related Party Transactions.  Subject to the provisions of Section 4.03 and its subsections, any transaction that 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 or any of their Affiliates.

4.02(d).  Additional Powers.  In addition to the powers granted the Managing General Partner under Section 4.02(c) and its subsections or elsewhere in this Agreement, the Managing General Partner, when specified, shall have the following additional express powers.

4.02(d)(1).  Power of Attorney.

4.02(d)(1)(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 are necessary to amend this Agreement as authorized under the terms of this Agreement, or to qualify the Partnership as a limited partnership 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 and any agreements entered into by the Partnership to hedge its oil and natural gas reserves and pledge up to 100% of its assets and oil and natural gas reserves in connection therewith.

4.02(d)(1)(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 the Managing General Partner under this section and its subsections, including amending this Agreement, at any time and from time to time, without the consent of the other Participants, to effect any change in this Agreement for the benefit or protection of the Participants, including but not limited to:

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(i) to add to the representations, duties or obligations of the Managing General Partner or to surrender any right or power granted to the Managing General Partner herein;
(b) 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 with respect to matters or questions arising under this Agreement that will not be inconsistent with the terms of this Agreement;
(ii) to preserve the status of the Partnership as a “partnership” for federal income tax purposes (or under the Delaware Act or any comparable law of any other state in which the Partnership may be required to be qualified);
(iii) to delete or add any provision of or to this Agreement required to be so deleted or added by the staff of the Commission, by any other federal or state regulatory body or other agency (including, without limitation, any “blue sky” commission) or by any administrator or similar such official;
(iv) to permit the Interests to fall within any exemption from the definition of “plan assets” contained in Section 2510.3-101 of Title 29 of the Code of Federal Regulations;
(v) if the Partnership is advised by counsel, by the Partnership’s accountants or by the Internal Revenue Service that any allocations of income, gain, loss or deduction provided for in this Agreement are unlikely to be respected for federal income tax purposes, to amend the allocation provisions of this Agreement, in accordance with the advice of such counsel, such accountants or the IRS, to the minimum extent necessary to effect as nearly as practicable the plan of allocations and distributions provided in this Agreement;
(vi) to effect any change necessitated by a change in law or regulation that causes the terms and conditions set forth in the prospectus and/or this Agreement to be, in the sole discretion of the Managing General Partner, no longer viable; provided, that such change shall be drawn as narrowly as possible so as to effectuate the original intent of the prospectus and this Agreement; and
(vii) to change the name of the Partnership or the location of its principal office.

Each party acknowledges that the power of attorney granted under Section 4.02(d)(2)(a):

(i) is a special power of attorney coupled with an interest and is irrevocable; and
(ii) shall survive the assignment by the Participant of the whole or a portion of his Interests; except when the assignment is of all of the Participant’s Interests and the purchaser, transferee, or assignee of the Interests is admitted as a successor Participant, the power of attorney shall survive the delivery of the assignment for the sole purpose of enabling the attorney-in-fact to execute, acknowledge, and file any agreement, certificate, instrument or document necessary to effect the substitution.

4.02(d)(1)(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 in excess of the amount of 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 the necessary funds to the Partnership under Section 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.  Partnership 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

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(ii) the amount that may be borrowed at any one time may not exceed an amount equal to 10% of the Partnership’s subscription proceeds.

Notwithstanding, the above limitations shall not affect the Partnership’s ability to enter into agreements and financial instruments relating to hedging the Partnership’s oil and natural gas and the pledge of up to 100% of the Partnership’s assets and reserves in connection therewith.

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 and any analogous state or local statute. 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 of the Participants of any administrative or other legal proceedings involving the Partnership and the IRS or any other taxing authority, and thereafter shall furnish all of the 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.

4.03.  No Management Authority of Participants.  Participants, other than the Managing General Partner if it buys Interests, shall have no power over the conduct of the affairs of the Partnership. No Participant, other than the Managing General Partner if it buys Interests, 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 Initial Closing 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:

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(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 an annual 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 the audit was made in accordance with generally accepted auditing standards and that in the auditor’s 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 reimbursements for Administrative Costs and Operating Costs, paid or incurred by, or on behalf of, the Partnership to the Managing General Partner, the Operator, and their Affiliates.

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 of the Partnership’s Administrative Costs was consistent with the method described in §4.04(a)(2)(c) of this Agreement and that the total amount of Administrative Costs allocated did not materially exceed the amounts described in §4.04(a)(2)(c). If the Managing General Partner subsequently decides to allocate Administrative Costs in a manner different from that described in §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:
(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) If assessments have been made during any period covered by the report, then such report shall contain a detailed statement of such assessments and the application of the proceeds derived from such assessments.
(vii) 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.

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Additionally, upon 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 Initial Closing 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 natural 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 based on then-existing prices; and
(c) basing the price of natural gas on the existing natural gas contracts or prices;
(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 such revenues were immediately receivable.

The reserve computations shall be based on engineering reports prepared by the Managing General Partner and reviewed by an Independent Expert.

Also, if any event reduces the Partnership’s Proved Reserves by 10% or more, excluding a reduction of reserves as a result of normal production, sales of reserves, or natural gas or oil price changes, then a computation and estimate of the amount of the reduction in reserves must be sent to each Participant within 90 days after the Managing General Partner determines that such a reduction in reserves has occurred.

4.03(b)(4).  Cost of Reports.  The cost and expenses incurred in the preparation and dissemination of all reports described in this Section 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, provided that access to the list of Participants shall be subject to Section 4.03(b)(7) below. Subject to the foregoing, a Participant may inspect and copy any of the Partnership’s records after giving adequate notice to the Managing General Partner at any reasonable time.

The Managing General Partner shall maintain and preserve during the term of the Partnership and for four years thereafter all accounts, books and other relevant Partnership documents. 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 sources that customarily receive such information in the Partnership’s 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 for six years after each Interest is sold all accounts, books and other relevant documents that include:

(i) investor suitability records for such Interests; and
(ii) any appraisal of the fair market value of the Leases as set forth in Section 4.01(a)(4), along with associated supporting information, or the fair market value of any producing property as set forth in Section 4.03(d)(3).

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4.03(b)(7).  Participant Lists.  The following provisions apply regarding access to the list of Participants:

(i) subject to the other provisions of this Section 4.03(b)(7), an alphabetical list of the names, addresses, and telephone numbers of the Participants along with the number of Interests held by each of them (the “Participant List”) shall 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 during normal business hours upon reasonable advance written notice to the Managing General Partner, which notice shall specify the date and time of the intended visit;
(ii) the Participant List shall be updated quarterly to reflect changes in the information contained in the Participant List;
(iii) subject to the other provisions of this Section 4.03(b)(7), 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) subject to the other provisions of this Section 4.03(b)(7), the purposes for which a Participant may request a copy of the Participant List include matters relating to Participant’s voting rights under this Agreement, if any, and the exercise of Participant’s rights under the federal proxy laws. The requesting Participant must, in its request, certify to the Partnership that such Participant is not requesting the Participant List for the purpose of (i) providing the Participant List (or any information set forth therein) to any third party (other than to the Participant’s designated representative(s)), (ii) selling the Participant List, (iii) using the Participant List for a commercial purpose unrelated to the Interests, or (iv) using the Participant List for an unlawful purpose; and
(v) if the Managing General Partner neglects or refuses to exhibit, produce, or mail a copy of the Participant List as requested, the Managing General Partner shall be liable to any Participant requesting the list for the costs, including attorneys fees, incurred by that Participant for compelling the production of the Participant List, and for actual damages suffered by any Participant by reason of the refusal or neglect. It shall be a defense to such liability that (i) 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 one of the prohibited purposes set forth in Section 4.03(b)(7)(iv), or (ii) the Participant failed to provide the certification required by Section 4.03(b)(7)(iv). 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 Section 4.03(b) with the securities commissions of the states that 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 Interests equal 10% or more of the total Interests for any matters on which Participants may vote.

The call for a meeting by the Participants as described above 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 Interests stating the purpose(s) of the meeting.

4.03(c)(1)(b).  Notice Requirement.  Within 15 days after its receipt of a written request for a meeting from the holders of the requisite percentage of Interests, the Managing General Partner shall provide written notice

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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 Interests equal 10% or more of the total Interests, the Managing General Partner shall call for a vote by Participants. Each Interest is entitled to one vote on all matters, and each fractional Interest is entitled to that fraction of one vote equal to the fractional interest in the Interest. Participants whose Interests equal a majority of the total Interests may, without the concurrence of the Managing General Partner or its Affiliates, vote to:

(i) dissolve the Partnership;
(ii) remove the Managing General Partner and elect a new Managing General Partner;
(iii) elect a new Managing General Partner if the Managing General Partner elects to withdraw from the Partnership;
(iv) approve or disapprove the sale of all or substantially all of the assets of the Partnership; and
(v) amend this Agreement; provided however, that 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, respectively.

4.03(c)(3).  Restrictions on Managing General Partner’s Voting Rights.  With respect to Interests owned by the Managing General Partner or its Affiliates, the Managing General Partner and its Affiliates may vote or consent on all matters other than the following:

(i) the matters set forth in Section 4.03(c)(2)(ii) above; or
(ii) any transaction between the Partnership and the Managing General Partner or its Affiliates.

In determining the requisite percentage in interest of Interests necessary to approve any Partnership matter on which the Managing General Partner and its Affiliates may not vote or consent, any Interests owned by the Managing General Partner and its Affiliates shall not be included.

4.03(c)(4).  Restrictions on Limited Partner Voting Rights.  The exercise by the Limited Partners of the rights granted Participants under Section 4.03(c), except for the special voting rights granted Participants under Section 4.03(c)(2), shall be subject to the prior legal determination that the grant or exercise of the powers will not adversely affect the limited liability of Limited Partners. Notwithstanding the foregoing, if in the opinion of counsel to the Partnership the legal determination is not necessary under the Delaware Act 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 Interests equal a majority of the total Interests 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 Interests necessary to take the action.

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4.03(d).  Transactions with the Managing General Partner.

4.03(d)(1).  Transfer of Equal Proportionate Interest.  When the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) sells, transfers or conveys any 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:

(i) the geological feature to which the well will be drilled contains Proved Reserves; and
(ii) the drilling or spacing unit protects against drainage.

Notwithstanding, a horizontal well may be drilled in one or more directions on the same Prospect on which a vertical well is also drilled. 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 Sections 4.01(a)(4) and 4.03(d)(2).

Notwithstanding the foregoing, Prospects drilled to any 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 Interest 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 Sections 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.

The Managing General Partner and its Affiliates, other than an affiliated income Program, shall not purchase any producing natural gas or oil property from the Partnership unless the sale is in connection with the liquidation of the Partnership, which sale must be at fair market value supported by an appraisal of an Independent Expert selected by the Managing General Partner.

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4.03(d)(4).  Limitations on Activities of the Managing General Partner and its Affiliates on Leases Acquired by the Partnership.  During the period beginning on the Offering Termination Date and ending five years after the Offering Termination Date, 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, that 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 another drilling Program sponsored or managed by the Managing General Partner or its Affiliates must be made at fair market value, as supported by an appraisal from an Independent Expert selected by the Managing General Partner. The costs of such transfer, including appraisal costs, shall be apportioned equally between the Partnership and the affiliated drilling Program.

An affiliated income Program may purchase a producing oil and natural gas property from the Partnership at any time at fair market value, as supported by an appraisal from an independent expert. The costs of such transfer, including appraisal costs, shall be apportioned equally between the Partnership and the affiliated income Program.

However, these prohibitions shall not apply to joint ventures or Farmouts among Affiliated partnerships, provided that:

(i) the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and
(ii) the compensation arrangement or any other interest or right of either the Managing General Partner or its Affiliates is the same in each Affiliated partnership or if different, the aggregate compensation of the Managing General Partner or the Affiliate is reduced to reflect the lower compensation arrangement.

4.03(d)(6).  Sale of All Assets.  The sale of all or substantially all of the assets of the Partnership, including without limitation, Leases, wells, equipment and production therefrom, shall be made only with the consent of Participants whose Interests equal a majority of the total Interests.

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

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substantial extent to other persons in the oil and natural gas industry in addition to the partnerships in which the Managing General Partner or an Affiliate has an interest; and
(ii) the compensation, price, or rental therefor is competitive with the compensation, price, or rental of other persons in the area engaged in the business of rendering comparable services or selling or leasing comparable equipment and supplies which could reasonably be made available to the Partnership.

If the person is not engaged in such a business, then the compensation, price or rental shall be the Cost of the services, equipment or supplies to the person or the competitive rate which could be obtained in the area, whichever is less.

4.03(d)(7)(b).  If Not Disclosed in the Prospectus or this Agreement, then Services by the Managing General Partner Must be Described in a Separate Contract and 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 that precisely describes the services to be rendered and all compensation to be paid and disclosed to the Participants. These contracts shall be cancelable without penalty on 60 days written notice by Participants whose Interests equal a majority of the total Interests.

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 its Affiliates.

4.03(d)(8)(b).  Loans to the Partnership.  Neither the Managing General Partner nor any Affiliate shall loan money to the Partnership if the interest to be charged exceeds the Managing General Partner’s or the Affiliate’s interest cost.

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 by them 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 a well on 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 Section 4.03(d)(3). Notwithstanding, this restriction shall not apply to Farmouts between the Partnership and another partnership managed by the Managing General Partner or its Affiliates, either separately or jointly, provided that the respective obligations and revenue sharing of all parties to the transactions are substantially the same and the compensation arrangement or any other interest or right of the Managing General Partner or its Affiliates is the same in each partnership, or, if different, the aggregate compensation of the Managing General Partner and its Affiliates is reduced to reflect the lower compensation agreement.

The Partnership may Farmout an undeveloped Lease or well activity only if the Managing General Partner, exercising the standard of a prudent operator, determines that:

(i) the Partnership lacks the funds to complete the oil and gas operations on the Lease or well and cannot obtain suitable financing;
(ii) drilling on the Lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the Partnership;
(iii) the Leases or well activity have been downgraded by events occurring after assignment to the Partnership so that development of the Leases or well activity would not be desirable; or
(iv) the best interests of the Partnership would be served.

If the Partnership Farmouts a Lease or well activity, the Managing General Partner must retain on behalf of the Partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices.

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If the Partnership acquires an undeveloped Lease pursuant to a Farmout or joint venture from an Affiliated partnership, the Managing General Partner’s and its Affiliates’ aggregate compensation associated with the property and any direct and indirect ownership interest in the property may not exceed the lower of the compensation and ownership interest in the Managing General Partner and/or its Affiliates could receive if the property were separately owned or retained by either the Partnership or the Affiliated partnership.

4.03(d)(10).  No Compensating Balances.  Neither the Managing General Partner nor any Affiliate shall use the Partnership’s funds as compensating balances on deposit to satisfy the terms of any agreement the Managing General Partner or Affiliate enters into on its own behalf.

4.03(d)(11).  Future Production.  Neither the Managing General Partner nor any Affiliate shall commit the future production of a well developed by the Partnership exclusively for its own benefit.

4.03(d)(12).  Marketing Arrangements.  All benefits from marketing arrangements or other relationships affecting the property of the Managing General Partner or its Affiliates, including its Affiliated partnerships and the Partnership, shall be fairly and equitably apportioned according to the respective interests of each in the property. In this regard, the benefits and liabilities of the hedging agreements shall be equitably allocated by the Managing General Partner to the Partnership and the other partnerships sponsored by the Managing General Partner and its Affiliates pro rata based on actual production, consistent with past practice, and the Partnership and the other partnerships sponsored by the Managing General Partner and its Affiliates shall be severally liable for their respective allocated share thereof, but shall not be jointly and severally liable for the entire amount of the liabilities under the hedging agreements. Additionally, the Managing GP or its successors in interest by merger or otherwise, shall not be liable for any such liabilities, or be entitled to any such benefits, to the extent they are so allocated. The Partnership may enter into agreements and financial instruments relating to hedging its own oil and natural gas and the pledging of up to 100% of the Partnership’s assets and reserves in connection therewith separate from and/or in addition to the hedging agreements described above.

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 to an operator are required to secure the tax benefits of prepaid Intangible Drilling Costs for a business purpose as set forth in the Drilling and Operating Agreement. These payments, if any, shall not include non-refundable payments for completion costs prior to the time that a decision is made that the well(s) warrant a completion attempt.

4.03(d)(14).  No Rebates.  No rebates or give-ups may be received by the Managing General Partner or any Affiliate nor may the Managing General Partner or any Affiliate participate in any reciprocal business arrangements that would circumvent the provisions of this section.

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 Act and comparable provisions under state law for any material misrepresentations or material omissions in the appraisal.

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Partnership assets shall be appraised on a consistent basis. The appraisal shall be based on all relevant information, including current reserve estimates prepared as set forth in Section 4.03(b)(3), 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 Interests 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 Interests.

4.03(d)(16)(c).  No Roll-Up If Diminishment of Voting Rights.  The Partnership shall not participate in any proposed Roll-Up that, if approved, would result in the diminishment of any Participant’s voting rights under the Roll-Up Entity’s chartering agreement. In no event shall the democracy rights of Participants in the Roll-Up Entity be less than those provided for under Sections 4.03(c)(1) and 4.03(c)(2). 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 Equity Securities Would be Impeded.  The Partnership shall not participate in any proposed Roll-Up transaction that includes provisions that would operate to materially impede or frustrate the accumulation of equity securities by any purchaser of the equity 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 that would limit the ability of a Participant to exercise the voting rights of its equity securities of the Roll-Up Entity on the basis of the number of Interests 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 would be less than those provided for under Sections 4.03(b)(5), 4.03(b)(6) and 4.03(b)(7).

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 Interests equal a majority of the total Interests 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 Interests equal a majority of the total Interests.

4.03(d)(17).  Disclosure of Binding Agreements.  Any agreement or arrangement that 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 that does not primarily benefit the Partnership.

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4.04.  Designation, Compensation and Removal of Managing General Partner.

4.04(a).  Managing General Partner.

4.04(a)(1).  Term of Service.  Except as otherwise provided in this Agreement, ICON Oil & Gas GP, LLC shall serve as the Managing General Partner of the Partnership until either it:

(i) is removed pursuant to Section 4.04(a)(3); or
(ii) withdraws pursuant to Section 4.04(a)(3)(f).

4.04(a)(2).  Compensation of Managing General Partner.  In addition to the compensation set forth in Sections 4.01(a)(4) and 3.04(c), the Managing General Partner shall receive the compensation set forth in Sections 4.04(a)(2)(B) through 4.04(a)(2)(G).

4.04(a)(2)(A).  Charges Must Be Necessary and Reasonable.  Charges by the Managing General Partner for goods and services must be fully supportable as to:

(i) the necessity of the goods and services; and
(ii) the reasonableness of the amount charged.

All actual and necessary expenses incurred by the Partnership may be paid out of the Partnership’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 and its Affiliates may be reimbursed for Administrative Costs that are actually incurred by it or them in connection with the performance or arrangement of administrative services reasonably necessary, convenient or advisable, in the discretion of the Managing General Partner, to the prudent operation of the Partnership (based upon the percentage of time the relevant personnel of the Managing General Partner or any Affiliate devote to providing such services); provided, however, that:

(i) the reimbursement shall be limited to the lesser of (A) its or their actual cost of providing the same or (B) the following: (1) in the Partnership’s first full year of operations, 1.25% of the Partnership’s gross offering proceeds; (2) in the Partnership’s second full year of operations, 1% of the Partnership’s gross offering proceeds; (3) in the Partnership’s third full year of operations, 0.75% of the Partnership’s gross offering proceeds; and (4) in the Partnership’s fourth full year of operations and thereafter, 0.5% the Partnership’s gross offering proceeds; provided, that, in each case, the above caps are calculated based on gross offering proceeds assuming the sale of 20,000 Interests;
(ii) no reimbursement is permitted for such services if the Managing General Partner or any Affiliate is entitled to compensation in the form of a separate fee for performing such services pursuant to other provisions of Section 4.04; and
(iii) neither the Managing General Partner nor any of its Affiliates shall be reimbursed by the Partnership for amounts expended by it with respect to (A) salaries, fringe benefits, travel expenses and other administrative items incurred by or allocated to any Controlling Person of the Managing General Partner or of any such Affiliate or (B) expenses for rent, depreciation, utilities, or capital equipment.

4.04(a)(2)(D).  Well Supervision Fee.  With respect to each Partnership Well, the Managing General Partner may receive a Well Supervision Fee, at a rate competitive with the rates charged by third-party operators providing similar services, as determined by the Managing General Partner, if its serves as the operator of such Partnership Well during producing operations. Notwithstanding anything to the contrary, neither the Managing General Partner nor its Affiliates may profit by drilling in contravention of its fiduciary obligation to the Participants.

4.04(a)(2)(E).  Dealer-Manager Fee.  The Dealer-Manager shall receive on each Interest sold to investors a 3% Dealer-Manager fee payable in cash.

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4.04(a)(2)(F).  Management Fee.  The Managing General Partner shall receive a Management Fee equal to the difference between (X) 15% multiplied by the gross offering proceeds less (Y) the sum of all Organization and Offering Costs.

4.04(a)(2)(G).  Other Transactions.  The Managing General Partner and its Affiliates may enter into transactions pursuant to Section 4.03(d)(7) with the Partnership and shall be entitled to compensation 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 Interests equal a majority of the total Interests; provided, however, that upon the bankruptcy or insolvency of the Managing General Partner or ICON Investment Group, LLC or upon the appointment of a receiver for all of the Managing General Partner or ICON Investment Group, LLC’s assets, such 60-day notice requirement shall be waived.

If the Participants vote to remove the Managing General Partner from the Partnership, then Participants must elect by an affirmative vote of Participants whose Interests equal a majority of the total Interests either to:

(i) dissolve, wind-up, and terminate the Partnership; or
(ii) continue as a successor limited partnership under all the terms of this Partnership Agreement as provided in Section 7.01(c).

If the Participants elect to continue as a successor limited partnership, then the Managing General Partner shall not be removed until a substituted Managing General Partner has been selected by an affirmative vote of Participants whose Interests equal a majority of the total Interests 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 as managing general partner 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 or, if they cannot agree, by arbitration in accordance with the then current rules of the American Arbitration Association by two Independent Experts, one selected by the removed Managing General Partner and one by the incoming Managing General Partner. In the event that such two Independent Experts are unable to agree on the value of the removed Managing General Partner’s interest within 90 days, they shall, within 20 days thereafter, jointly appoint a third Independent Expert whose determination shall be final and binding; provided, however, that if the two Independent Experts are unable to agree within such 20 days on a third Independent Expert, the third Independent Expert shall be selected by the American Arbitration Association. The appraisal shall take into account an appropriate discount, to reflect the risk of recovering oil and natural gas reserves, which shall not be less than that used to calculate the presentment price in the most recent presentment offer under Section 6.03, if any.

All costs and expenses related to 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, but not as a Participant, for the value determined pursuant to Section 4.04(a)(3)(B).

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 this Agreement had the Managing General Partner not been terminated; and

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(ii) when the termination is involuntary, the method of payment shall be an interest bearing unsecured promissory note coming due in no less than five years with equal installments each year. The interest rate shall be that charged on comparable loans.

4.04(a)(3)(E).  Termination of Contracts.  At the time of its removal, the removed Managing General Partner shall cause, to the extent it is legally possible to do so, its successor to be transferred or assigned all of 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 all of its rights, obligations and interests as Managing General Partner of the Partnership in any such contract to terminate at the time of its removal.

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, the Managing General Partner may voluntarily withdraw as Managing General Partner after giving 120 days’ prior written notice of withdrawal to the Participants. If the Managing General Partner withdraws, then the following conditions shall apply:

(i) the Managing General Partner’s interest in the Partnership shall be determined as described in Section 4.04(a)(3)(B) above with respect to removal; and
(ii) the interest shall be distributed to the Managing General Partner as described in Section 4.04(a)(3)(D)(i) above.

As set forth in Section 4.04(a)(3)(C) 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).  Right of Managing General Partner to Hypothecate 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 as Managing General Partner in the revenues of the Partnership.

All repayments of these borrowings and costs, interest or other charges related to the borrowings shall be borne and paid separately by the Managing General Partner. In no event shall the repayments, costs, interest, or other charges related to the borrowing be charged to the account of the Participants.

4.04(a)(3)(H).  The Managing General Partner’s Right to Withdraw Property Interest.  The Managing General Partner shall have the right to 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 as Managing General Partner 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 Interests equal a majority of the total Interests.

If the Managing General Partner withdraws a property interest from the Partnership as described above, then the Managing General Partner shall:

(i) pay all of the expenses of withdrawing; and
(ii) fully indemnify the Partnership against any additional expenses which may result from the withdrawal of its property interest, including ensuring that a greater amount of Direct Costs or Administrative Costs is not allocated to the Participants.

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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 and its Affiliates shall not have any liability whatsoever to the Partnership, or to any Participant for any loss suffered by the Partnership or the Participants which arises out of any action or inaction of the Managing General Partner or its Affiliates if:

(i) the Managing General Partner and its Affiliates determined in good faith that the course of conduct was in the best interest of the Partnership;
(ii) the Managing General Partner and its 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 or its Affiliates.

4.05(a)(2).  Standards for Managing General Partner Indemnification.  The Managing General Partner and its 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 and its Affiliates determined in good faith that the course of conduct that caused the loss or liability was in the best interest of the Partnership;
(ii) the Managing General Partner and its 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 or its Affiliates.

Provided, however, payments arising from such indemnification or agreement to hold harmless are recoverable only out of the following:

(a) the Partnership’s tangible net assets, which include its revenues; and
(b) any insurance proceeds from the types of insurance for which the Managing General Partner and its Affiliates may be indemnified under this Agreement.

4.05(a)(3).  Standards for Securities Law Indemnification.  Notwithstanding anything to the contrary contained in this section, the Managing General Partner and its Affiliates and any person acting as a broker/dealer with respect to the offer or sale of the Interests, 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 and any applicable state securities regulatory authority in which plaintiffs claim they were offered or sold Interests 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 or its Affiliates for legal expenses and other costs incurred as a result of any legal action for which indemnification is being sought from the Partnership is permissible only if the Partnership has adequate funds available and the following conditions are satisfied:

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(i) the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the Partnership;
(ii) the legal action is initiated by a third-party who is not a Participant, or the legal action is initiated by a Participant and a court of competent jurisdiction specifically approves the advancement; and
(iii) the Managing General Partner or its Affiliate, as applicable, undertakes 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 that insures the Managing General Partner or its Affiliates for any liability for which they could not be indemnified pursuant to Sections 4.05(a)(1) and 4.05(a)(2).

4.05(b).  Liability of Partners.

4.05(b)(1).  Liability of Investor General Partners and Indemnification by the Managing General Partner.  Under the Delaware 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 Interests.

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 that 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(b)(2).  Limited Liability of Limited Partners.  Limited Partners shall not be bound by the obligations of the Partnership other than as provided under the Delaware Act. Except as otherwise provided under the Delaware Act or applicable law, 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 subscription amount 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 Partnership Interests,

and, in the case of clause (i) and (ii) above, only with respect to such Limited Partner’s interest in the Partnership outside of its Limited Partnership Interests.

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 and the Investor General Partners as provided in Sections 3.05(b)(2) and (3) and 4.05(b).

No Limited Partner shall be required to reimburse the Managing General Partner or its 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 management of the Partnership; or
(ii) from some other breach by the Limited Partner of this Agreement.

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4.05(d).  Authorized Transactions Are Not Deemed to Be a Breach.  No transaction entered into or action taken by the Partnership, or by the Managing General Partner or its Affiliates, which is authorized by this Agreement shall be deemed a breach of any obligation owed by the Managing General Partner or its Affiliates to the Partnership or the Participants.

4.06.  Other Activities.

4.06(a).  The Managing General Partner May Pursue Other Oil and Natural Gas Activities for Its Own Account.  The Managing General Partner and its Affiliates are now engaged, and will engage in the future, for their own account and for the account of others, including other investors, in all aspects of the oil and natural gas 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 to the Partnership as it determines in its sole discretion, but consistent with its fiduciary duties, 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 and its Affiliates may do the following:

(i) continue their activities, or initiate further such activities, individually, jointly with others, or as a part of any other limited or general partnership, tax partnership, joint venture, or other entity or activity to which they are or may become a party, in any locale and in the same fields, areas of operation or prospects in which the Partnership may likewise be active;
(ii) reserve partial interests in Leases being assigned to the Partnership or any other interests not expressly prohibited by this Agreement;
(iii) deal with the Partnership as independent parties or through any other entity in which they may be interested;
(iv) conduct business with the Partnership as set forth in this Agreement; and
(v) participate in such other investor operations, as investors or otherwise.

The Managing General Partner and its Affiliates shall not be required to permit the Partnership or the Participants to participate in or share in any profits or other benefits from any of the other operations in which the Managing General Partner and its Affiliates may be interested as permitted under this section. 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 Programs.  The Managing General Partner or its Affiliates may manage multiple Programs simultaneously.

ARTICLE V
MAINTENANCE OF CAPITAL ACCOUNTS, SHARING OF PROFIT AND LOSS,
DISTRIBUTIONS, AND TAX ELECTIONS

5.01.  Maintenance of Capital Accounts.  The Partnership shall maintain a Capital Account for each Partner in accordance with the following provisions:

5.01(a)  To each Partner’s Capital Account there shall be credited (A) such Partner’s Capital Contributions, (B) such Partner’s distributive share of Profits and any items in the nature of income or gain which are specially allocated to such Partner pursuant to Section 5.02(c), (C) such Partner’s distributive share of Simulated Gain, and (D) the amount of any Partnership liabilities assumed by such Partner or that are secured by any Property distributed to such Partner;

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5.01(b)  To each Partner’s Capital Account there shall be debited (A) the amount of money and the Gross Asset Value of any Property distributed to such Partner pursuant to any provision of this Agreement, (B) such Partner’s distributive share of Loss and any items in the nature of expenses or losses which are specially allocated to such Partner pursuant to Section 5.02(c), (C) such Partner’s distribution share of Simulated Depletion and Simulated Loss, and (D) the amount of any liabilities of such Partner assumed by the Partnership or that are secured by any Property contributed by such Partner to the Partnership;

5.01(c)  In the event an Interest is Transferred in accordance with the terms of this Agreement, the transferee shall succeed to the Capital Account of the transferor to the extent it relates to the Transferred Interest;

5.01(d)  In determining the amount of any liability for purposes of subparagraphs (i) and (ii) above, there shall be taken into account Code Section 752(c) and any other applicable provisions of the Code and Regulations; and

5.01(e)  For purposes of computing the Partners’ Capital Accounts, the Simulated Basis of each oil and gas property of the Partnership will be allocated between the Managing General Partner and the Participants pro rata in accordance with their contributed capital (for this purpose, any capital the Managing General Partner contributes for Interests pursuant to Section 3.03(b) is treated as being contributed by a Participant), and reallocated among the Partners’ as necessary in accordance with the same ratio. For purposes of computing each Participant’s Capital Accounts, the Simulated Basis of each oil and gas property of the Partnership will be allocated to the Participants pro rata by number of Interests held by each Participant, and reallocated among the Participants as necessary in accordance with the same ratio.

The foregoing provisions and the other provisions of this Agreement relating to the maintenance of Capital Accounts are intended to comply with Regulations Section 1.704-1(b), and shall be interpreted and applied in a manner consistent with such Regulations. In the event the Managing General Partner shall determine that it is prudent to modify the manner in which the Capital Accounts, or any debits or credits thereto are computed in order to comply with such Regulations, the Managing General Partner may make such modification. The Managing General Partner also shall (i) make any adjustments that are necessary or appropriate to maintain equality between the Capital Accounts of the Partners and the amount of capital reflected on the Partnership’s balance sheet, as computed for book purposes, in accordance with Regulations Section 1.704-1(b)(2)(iv)(q), and (ii) make any appropriate modifications in the event unanticipated events might otherwise cause this Agreement not to comply with Regulations Section 1.704-1(b). The Managing General Partner shall provide the Participants with written notice of any such adjustments or modifications.

5.02.  Allocations of Profit and Loss.

5.02(a).  Allocations between the Participants and the Managing General Partner

5.02(a)(1).  Profits.  After giving effect to the special allocations set forth in Section 5.02(c)(1) and Section 5.02(c)(2), Profits for any Allocation Year will be allocated as follows:

5.02(a)(1)(A).  One Hundred Percent (100%) to the Managing General Partner until the amount of Profits allocated under this Section 5.02(a)(1)(A) for the current Allocation Year and all prior Allocation Years equals the cumulative amount of Loss allocated to the Managing General Partner under Section 5.02(a)(2)(D).

5.02(a)(1)(B).  One Hundred Percent (100%) to the Investor General Partners pro rata by the amount of Loss allocated to them under Section 5.02(a)(2)(C) until the amount of Profits allocated under this Section 5.02(a)(1)(B) for the current Allocation Year and any prior Allocation Years equals the cumulative amount of Loss allocated to the Investor General Partners under Section 5.02(a)(2)(C).

5.02(a)(1)(C).  One Hundred Percent (100%) to the Partners pro rata by the amount of Loss allocated to them under Section 5.02(a)(2)(B) until the amount of Profits allocated under this Section 5.02(a)(1)(B) for the current Allocation Year and all prior Allocation Years equals the cumulative amount of Loss allocated to the Partners under Section 5.02(a)(2)(B).

5.02(a)(1)(D).  All remaining profits shall be allocated between the Managing General Partner and the Participants in accordance with the Managing General Partner Sharing Ratio.

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5.02(a)(2).  Losses.  After giving effect to the special allocations set forth in Section 5.02(c)(1) and Section 5.02(c)(2), Losses for any Allocation Year will be allocated as follows:

5.02(a)(2)(A).  One Hundred Percent (100%) to the Partners, in proportion to the amount of Profits allocated under Section 5.02(a)(1)(D), until the amount of Losses allocated under this Section 5.02(a)(2)(A) for the current Allocation Year and all prior Allocation Years equals the cumulative amount of Profit allocated to the Partners under Section 5.02(a)(1)(D).

5.02(a)(2)(B).  One Hundred Percent (100%) to the Managing General Partner and the Participants in accordance with their respective Capital Contributions until the aggregate Adjusted Capital Account balance of all the Participants equals zero. For purposes of this allocation provision, the Managing General Partner shall be treated as a limited partner with respect to the Interests that it owns as a Participant.

5.02(a)(2)(C).  One Hundred Percent (100%) to the Investor General Partners until the aggregate Adjusted Capital Account balance of all the Investor General Partners equals the maximum aggregate Adjusted Capital Account Deficit that the Investor General Partners, in the aggregate, are obligated to restore. Allocations among the Investor General Partners shall be made in the same proportion as they would be required to make additional Capital Contributions under Section 3.05(b)(2).

5.02(a)(2)(D).  All remaining Losses shall be allocated One Hundred Percent (100%) to the Managing General Partner.

5.02(b).  Allocations among the Participants.  Profits and Losses allocated to the Participants in the aggregate pursuant to Section 5.02(a) shall be allocated among the Participants as follows: after giving effect to the special allocations provided in Section 5.02(c)(1) and Section 5.02(c)(2), Profits and Losses shall be allocated among the Participants so as to equalize, as soon as practicable, the ratio of each Participant’s Capital Account balance, as increased by the amounts for such Participant described in clauses (a), (b) and (c) of the definition of Partially Adjusted Capital Account, to the number of Interests held by such Participant. If there are not sufficient Profits or Losses so allocated to the Participants for such Fiscal Year to bring such ratios into equality, such Profits and Losses shall be allocated among the Participants in the same proportions as would have been the case had the minimum amount of Profits or Losses, as the case may be, necessary to produce such equality been available for allocation. If the Managing General Partner determines that the Partnership will not have enough Profit or Loss to equalize the ratio of each Participant’s Capital Account balance as increased by the amounts for such Participant described in clauses (a), (b) and (c) of the definition of Partially Adjusted Capital Account to the number of Interests owned by such Participant, the Managing General Partner may allocate items of gross income, gain, loss, or deduction under this provision.

5.02(c)(1).  Special Allocations.  The following special allocations shall be made in the following order:

(i) Minimum Gain Chargeback.  Except as otherwise provided in Regulations Section 1.704-2(f), notwithstanding any other provision of this Article V, if there is a net decrease in Partnership Minimum Gain during any Allocation Year, each Partner shall be specially allocated items of Partnership income and gain for such Allocation Year (and, if necessary, subsequent Allocation Years) in an amount equal to such Partner’s share of the net decrease in Partnership Minimum Gain, determined in accordance with Regulations Section 1.704-2(g). Allocations pursuant to the previous sentence shall be made in proportion to the respective amounts required to be allocated to each Partner pursuant thereto. The items to be so allocated shall be determined in accordance with Regulations Sections 1.704-2(f)(6) and 1.704-2(j)(2). This Section 5.02(c)(1)(i) is intended to comply with the minimum gain chargeback requirement in Regulations Section 1.704-2(f) and shall be interpreted consistently therewith.
(ii) Partner Minimum Gain Chargeback.  Except as otherwise provided in Regulations Section 1.704-2(i)(4), notwithstanding any other provision of this Article V, if there is a net decrease in Partner Nonrecourse Debt Minimum Gain attributable to a Partner Nonrecourse Debt during any Allocation Year, each Partner who has a share of the Partner Nonrecourse Debt Minimum Gain attributable to such Partner Nonrecourse Debt, determined in accordance with Regulations Section 1.704-2(i)(5), shall be specially allocated items of Partnership income and gain for such Allocation Year (and, if necessary, subsequent Allocation Years) in an amount equal to

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such Partner’s share of the net decrease in Partner Nonrecourse Debt Minimum Gain attributable to such Partner Nonrecourse Debt, determined in accordance with Regulations Section 1.704-2(i)(4). Allocations pursuant to the previous sentence shall be made in proportion to the respective amounts required to be allocated to each Partner pursuant thereto. The items to be so allocated shall be determined in accordance with Regulations Sections 1.704-2(i)(4) and 1.704-2(j)(2). This Section 5.02(c)(1)(ii) is intended to comply with the minimum gain chargeback requirement in Regulations Section 1.704-2(i)(4) and shall be interpreted consistently therewith.
(iii) Qualified Income Offset.  In the event that any Partner unexpectedly receives any adjustments, allocations, or distributions described in Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) or 1.704-1(b)(2)(ii)(d)(6) of the Regulations, items of Partnership income and gain shall be allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Regulations, the Adjusted Capital Account Deficit of such Partner as quickly as possible; provided that an allocation pursuant to this Section 5.02(c)(1)(iii) shall be made only if and to the extent that such Partner would have an Adjusted Capital Account Deficit after all other allocations provided for in this Article V have been tentatively made as if this Section 5.03(c)(1)(iii) were not in this Agreement.
(iv) Gross Income Allocation.  In the event that any Partner has an Adjusted Capital Account Deficit at the end of any Allocation Year, each such Partner shall be allocated items of Partnership income and gain in the amount of such deficit as quickly as possible; provided that an allocation pursuant to this Section 5.02(c)(1)(iv) shall be made only if and to the extent that such Partner would have an Adjusted Capital Account Deficit in excess of such sum after all other allocations provided for in this Article V have been tentatively made as if Section 5.02(c)(1)(iii) and this Section 5.02(c)(1)(iv) were not in this Agreement.
(v) Nonrecourse Deductions.  Nonrecourse Deductions for any Allocation Year shall be allocated in accordance with the Managing General Partner Sharing Ratio. For purposes of allocating nonrecourse deductions among the Participants, the Partnership’s nonrecourse deductions (to the extent allocated to the Participants as a group) will be allocated to the Participants pro rata by number of Interests held by each Participant.
(vi) Partner Nonrecourse Deductions.  Any Partner Nonrecourse Deductions for any Allocation Year shall be specially allocated to the Partner who bears the economic risk of loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Regulations Section 1.704-2(i)(1).
(vii) Section 754 Adjustments.  To the extent an adjustment to the adjusted tax basis of any Partnership asset, pursuant to Code Section 734(b) or Code Section 743(b) is required, pursuant to Regulations Section 1.704-1(b)(2)(iv)(m)(2) or 1.704-1(b)(2)(iv)(m)(4), to be taken into account in determining Capital Accounts as the result of a distribution to a Partner in complete liquidation of such Partner’s interest in the Partnership, the amount of such adjustment to Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis) and such gain or loss shall be specially allocated to the Partners in accordance with their interests in the Partnership in the event Regulations Section 1.704-1(b)(2)(iv)(m)(2) applies, or to the Partner to whom such distribution was made in the event Regulations Section 1.704-1(b)(2)(iv)(m)(4) applies.
(viii) Simulated Depletion, Simulated Loss, and Intangible Drilling Costs.  Simulated Depletion, Simulated Loss, and Intangible Drilling Costs with respect to each oil and gas property of the Partnership will be allocated in proportion to the manner in which the Simulated Basis of such property is allocated among the Partners pursuant to subparagraph (e) of the definition of “Capital Account” in Section 5.01.
(ix) Simulated Gains. Simulated Gain with respect to any Partnership oil and gas property will be allocated first to all the Partners, pro rata by the amount of Simulated Depletion, Simulated Loss, and Intangible Drilling Costs allocated to each Partner under Section 5.02(1)(viii) for the current

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and all prior years, until the amount of Simulated Gain allocated to each Partner under this Section equals the amount of Simulated Depletion, Simulated Loss, and Intangible Drilling Cost allocated to each Partner under Section 5.02(1)(viii), and second, in accordance with Section 5.02(a).
(x) Amount Realized on Disposition of Oil and Gas Property.  For purposes of Regulations Sections 1.704-1(b)(2)(iv)(k)(2) and 1.704-1(b)(4)(iii), the amount realized on the disposition of any oil and gas property of the Partnership shall be allocated (i) first to the Partners in an amount equal to the remaining Simulated Basis of such property in the same proportions as the Simulated Basis of such property was allocated to the Partners pursuant to subparagraph (e) of the definition of “Capital Account” in Section 5.01, and (ii) any remaining amount realized shall be allocated to the Partners in the same ratio as Simulated Gain is allocated pursuant to Section 5.02(1)(ix).
(xi) Payments to the Managing General Partner.  In the event, and to the extent, that the Managing General Partner is treated under the Code as having been transferred an interest in the Partnership in connection with the performance of services for the Partnership (whether before or after the formation of the Partnership):
 (A) any resulting compensation income shall be allocated 100% to the Managing General Partner;
 (B) any associated increase in Capital Accounts shall be credited 100% to the Managing General Partner; and,
 (C) any associated deduction to which the Partnership is entitled shall be allocated 100% to the Managing General Partner.
(xii) Syndication Expenses. Syndication Expenses attributable to the Sales Commissions and Underwriting Fees paid on the Partnership’s sale of any Interest shall be specially allocated to the Participant who purchased such Interest; and all other Syndication Expenses shall be allocated to the Participants who are admitted to the Partnership from time to time so that, to the extent possible, the cumulative Syndication Expenses (other than Sales Commissions and Underwriting Fees) allocated with respect to each Interest are the same. If the Managing General Partner determines that such result is not likely to be achieved through future allocation of Syndication Expenses, the Managing General Partner may allocate a portion of Profits or Losses or other items of income, gain, loss, deduction or expense to achieve the same effect on the Capital Accounts of the Participants.
(xiii) Fees and Commissions Paid to the Managing General Partner. It is the intent of the Partnership that any amount paid or deemed paid to the Managing General Partner as a fee or payment described in Section 4.04 shall be treated as a “guaranteed payment” or a payment to a Partner not acting in his capacity as a Partner pursuant to Section 707(c) or (a), respectively, of the Code to the extent possible. If any such fee or payment is deemed to be a distribution to the Managing General Partner and not a guaranteed payment or a payment to a Partner not acting in his capacity as a Partner, the Managing General Partner shall be allocated an amount of Partnership gross ordinary income equal to such payment.
(xiv) Special Allocation of Gross Income with Respect to Section 5.05(a)(2)(ii) Special Distribution. Gross Income shall be specially allocated to those Partners who received a special distribution of interest under Section 5.05(a)(2)(ii) consistent with the allocations of such interest pursuant to Section 3.05(b)(1).
(xv) Solely for purposes of determining the Managing General Partner’s or Participant’s proportionate share of the excess nonrecourse liabilities of the Partnership within the meaning of Regulations Section 1.752-3(a)(3), the Managing General Partner’s interest in Partnership profits is in accordance with its Managing GP Sharing Ratio and the Participants’ interest in Partnership profits equals the difference between 100% and the Managing GP Sharing Ratio.
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Liability or a Partner Nonrecourse Debt only to the extent that such distributions would cause or increase an Adjusted Capital Account Deficit for any Partner that is not a Managing General Partner.
(xvii) Special Allocation of Interest Income with respect to Section 3.06(c)(2). Interest income from temporary investments as described in Section 3.06(c)(2) shall be allocated among the Participants in accordance with that Section.

5.02(c)(2).  Regulatory Allocations.  The allocations set forth in Sections 5.02(c)(1)(i) through (vii) (the “Regulatory Allocations”) are intended to comply with certain requirements of the Regulations. It is the intent of the Partners that, to the extent possible, the Regulatory Allocations shall be offset either with special allocations of other items of Partnership income, gain, loss, or deduction pursuant to this Section 5.02(c)(2). Therefore, notwithstanding any other provision of this Article V (other than the Regulatory Allocations), the Managing General Partner shall make such offsetting special allocations of Partnership income, gain, loss, or deduction in whatever manner it determines appropriate so that, after such offsetting allocations are made, each Partner’s Capital Account balance is, to the extent possible, equal to the Capital Account balance such Partner would have had if the Regulatory Allocations were not part of this Agreement and all Partnership items were allocated pursuant to Section 5.02(a), 5.02(b), and 5.02(c)(1) (other than the Regulatory Allocations). In exercising its discretion under this Section 5.02(c)(2), the Managing General Partner shall take into account future Regulatory Allocations under Sections 5.02(c)(1)(i) and 5.02(c)(1)(ii) that, although not yet made, are likely to offset other Regulatory Allocations previously made under Sections 5.02(c)(1)(v) and 5.02(c)(1)(vi).

5.03.  Other Allocation Rules.

5.03(a).  Profits, Losses, and any other items of income, gain, loss, or deduction will be allocated to the Partners pursuant to this Article V as of the last day of each Allocation Year; provided that Profits, Losses, and such other items shall also be allocated at such times as the Gross Asset Values of Property are adjusted pursuant to subparagraph (ii) of the definition of “Gross Asset Value.”

5.03(b).  For purposes of determining the Profits, Losses, or any other items allocable to any period, Profits, Losses, and any such other items shall be determined on a daily, monthly, or other basis, as determined by the Managing General Partner (except to the extent otherwise provided in Section 6.02(b)(5) using any permissible method under Code Section 706 and the Regulations thereunder.

5.03(c).  The Partners are aware of the income tax consequences of the allocations made by this Article V and hereby agree to be bound by the provisions of this Article V in reporting their shares of Partnership income and loss for income tax purposes, except as otherwise required by law.

5.03(d).  Tax Allocations: Code Section 704(c).  Except as otherwise provided in this Section 5.03(d), each item of income, gain, loss, and deduction of the Partnership for federal income tax purposes shall be allocated among the Partners in the same manner as such items are allocated to each Partner’s Capital Account under this Article V. In accordance with Code Section 704(c) and the Regulations thereunder, income, gain, loss, and deduction with respect to any Property contributed to the capital of the Partnership shall, solely for tax purposes, be allocated among the Partners so as to take account of any variation between the adjusted basis of such Property to the Partnership for federal income tax purposes and its initial Gross Asset Value (computed in accordance with the definition of Gross Asset Value) using the remedial allocation method described in Treasury Regulations Section 1.704-3(b).

In the event the Gross Asset Value of any Partnership asset is adjusted pursuant to subparagraph (ii) of the definition of Gross Asset Value, subsequent allocations of income, gain, loss, and deduction with respect to such asset shall take account of any variation between the adjusted basis of such asset for federal income tax purposes and its Gross Asset Value in the same manner as under Code Section 704(c) and the Regulations thereunder.

Any elections or other decisions relating to such allocations shall be made by the Managing General Partner in any manner that reasonably reflects the purpose and intention of this Agreement. Allocations pursuant to this Section 5.03(d) are solely for purposes of federal, state, and local taxes and shall not affect, or in any way

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be taken into account in computing, any Partner’s Capital Account or share of Profits, Losses, other items, or distributions pursuant to any provision of this Agreement.

5.03(e).  Recapture Items.  In the event that the Partnership has taxable income that is characterized as ordinary income under the recapture provisions of the Code, each Partner’s distributive share of taxable gain or loss from the sale of Partnership assets (to the extent possible) shall include a proportionate share of this recaptured income equal to the Partner’s share of prior cumulative depreciation, depletion, or amortization deductions with respect to the assets that gave rise to the recapture income.

5.03(f).  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, allocating any item of income, gain, loss, deduction or credit pursuant to new laws or new IRS or judicial interpretations of existing law, allocating any other item that is not otherwise specifically allocated in this Agreement or is subsequently determined by the Managing General Partner to be clearly inconsistent with a party’s economic interest in the Partnership allocating any items of Profit or Loss after a redemption of the Partnership’s Interests, or making any other allocations under this Agreement, the Managing General Partner may adopt any method of allocation that it selects, in its sole discretion, after consultation with the Partnership’s legal counsel or accountants. Any new allocation provisions shall be made in a manner that is consistent with the parties’ economic interests in the Partnership and will result in the most favorable aggregate consequences to the Participants that are, as nearly as possible, consistent with the original allocations described in this Agreement.

5.03(g).  Discretion of Managing General Partner in the Method of Maintaining Capital Accounts.  Notwithstanding any other provisions of this Agreement, the method of maintaining Capital Accounts may be changed from time to time, in the discretion of the Managing General Partner, to take into consideration Section 704 and other provisions of the Code and the related rules, regulations and interpretations as may exist from time to time.

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 or any Partner, or any of their Affiliates for the Partnership to be excluded from the application of the partnership provisions of the Code, including Subchapter K of Chapter 1 of Subtitle A of the Code.

5.04(c).  Section 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 Sections 734 and 743 of the Code.

5.04(d).  Special Direction and Consent Regarding Possible Issuance of Final Regulations Affecting Issuance of Partnership Interests for Services.  In the event that proposed regulations under, inter alia, Code Sections 83, 704 and 721 and issued by the Internal Revenue Service on May 24, 2005, under the docket number REG-105346-03, relating to issuance of partnership equity for services become finalized and, as finalized, would apply to the Managing General Partner’s interest in the Partnership upon issuance of Interests in the Partnership, the Partnership is hereby authorized and directed to make the analogue found in such final regulations to the “safe harbor” election presently described in Prop. Treas. Reg. Section 1.83-3(l)(1), whereby such Managing General Partner’s interest would be valued for federal income tax purposes at its so-called “liquidation value,” as such election is further amplified by a Revenue Procedure presently published in draft form as Notice 2005-43. The Partnership and each of its Partners, including the Managing General Partner, agree to comply with all of the requirements of the safe harbor in connection with interests in the Partnership transferred in connection with the performance of services while the election remains effective, to execute such documentation as the Managing General Partner reasonably determines is necessary to comply with such election, and not to take any position for federal income tax purposes inconsistent with such election.

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5.05.  Distributions.

5.05(a).  In General.

5.05(a)(1).  Monthly Review of Accounts.  The Managing General Partner shall review the accounts of the Partnership at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any.

5.05(a)(2).  Distributions to the Participants.  

(i) Except as otherwise provided in this Agreement, the Partnership shall distribute funds to the Participants that the Managing General Partner deems unnecessary for the Partnership to retain.
(ii) Except as provided in Section 5.05(c), below, distributions to the Participants shall be made pro rata in accordance with the number of Interests held by each Participant as of the first day of the month in which such distribution is made.

5.05(a)(3).  Distributions to the Managing General Partner.  Cash distributions from the Partnership to the Managing General Partner shall only be made as follows:

(i) in conjunction with distributions to Participants; and
(ii) as a distribution of Profits (or items of income and gain thereof) allocated to the Managing General Partner’s Capital Account under this Article V.

5.05(a)(4).  No Borrowings.  In no event shall funds be advanced or borrowed by the Partnership for distributions to the Managing General Partner and the Participants 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)(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 net sales proceeds from the sale of the oil and natural gas production from each of its productive wells up to $200 per well 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 to plug and abandon the well.

5.05(b).  Distribution of Uncommitted Subscription Proceeds.  Any 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 amount designated on each Participant’s Subscription Agreement bears to the total subscription amounts designated on all of the Participants’ Subscription Agreements, as a return of capital. The Managing General Partner shall reimburse the Participants for the selling expenses, management fees and 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 ensure 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 Section 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.

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5.05(e).  Partnership Entitled to Withhold.  The Partnership shall, at all times, be entitled to withhold or make payments to any governmental authority with respect to any federal, state, local or foreign tax liability of any Partner arising as a result of such Partner’s participation in the Partnership or the Partner’s sale, exchange, or other disposition of all or part of its interest in the Partnership. Each such amount so withheld or paid shall be deemed to be a distribution for purposes of Sections 5.05(a)(2), 5.05(c), and 7.02, as the case may be, to the extent such Partner is then entitled to a distribution. To the extent that the amount of such withholdings or payments made with respect to any Partner exceeds the amount to which such Partner is then entitled as a distribution, the excess shall be treated as a demand loan, bearing interest at a rate equal to twelve percent (12%) per annum simple interest from the date of such payment or withholding until such excess is repaid to the Partnership (i) by deduction from any distributions subsequently payable to such Partner pursuant to this Agreement or (ii) earlier payment of such excess and interest by such Partner to the Partnership. Such excess and interest shall, in any case, be payable not less than 30 days after demand therefor by the Managing General Partner, which demand shall be made only if the Managing General Partner determines that such Partner is not likely to be entitled to distributions within twelve (12) months from the date of such withholding or payment by the Partnership in an amount sufficient to pay such excess and interest. The withholdings and payments referred to in this Section 5.05(e) shall be made at the maximum applicable statutory rate under the applicable tax law unless the Managing General Partner shall have received an opinion of counsel or other evidence, satisfactory to the Managing General Partner, to the effect that a lower rate is applicable, or that no withholding or payment is required.

ARTICLE VI
TRANSFER OF INTERESTS

6.01.  Transferability of Interests.  A Participant’s transfer of a portion or all his Interests, or any interest in his Interests, is subject to all of the provisions of this Article VI. For purposes of this Article VI, the term “transfer” shall include any sale, exchange, gift, assignment, pledge, mortgage, hypothecation, redemption or other form of transfer of a Interest, or any interest in a Interest, by a Participant (which may include the Managing General Partner or its Affiliates, if they purchase Interests) or by operation of law, including any transfers of Interests which a Participant presents to the Managing General Partner for purchase under Section 6.03.

6.01(a).  Rights of Assignee.  Unless a transferee of a Participant’s Interest becomes a substitute Participant with respect to that Interest in accordance with the provisions of Section 6.02(a)(4)(a), 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, gains, deductions, credits and depletion allowances, or items thereof, and cash distributions or returns of capital to which his transferor would otherwise be entitled under this Agreement.

6.01(b).  Conversion of Investor General Partnership Interests to Limited Partnership Interests.  

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 Partnership Interests to Limited Partnership Interests. In this regard, a well shall be deemed to be completed when production equipment is installed on a well, even though the well may not yet be connected to a pipeline for production of natural gas.

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, subject to the provisions of this Agreement 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 Interests as provided in Section 3.05(b)(2).

6.01(b)(3).  Conversion Shall Not Affect Allocations.  The conversion shall not affect the allocation to any Participant of any item of Partnership income, gain, loss, deduction or credit or other item of special tax significance other than Partnership liabilities, if any. Further, the conversion shall not affect any Participant’s interest in the Partnership’s oil and natural gas properties and unrealized receivables.

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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 material adverse 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 Interests into Limited Partner Interests before the reduction by giving written notice to the Managing General Partner.

6.02.  Special Restrictions on Transfers of Interests by Participants.  

6.02(a).  In General.  Transfers of Interests by Participants are subject to the following general conditions:

(i) except as provided by operation of law only whole Interests may be transferred unless the Participant owns less than a whole Interest, in which case his entire fractional Interest must be transferred; and
(ii) the costs and expenses associated with the transfer must be paid by the assignor Participant;
(iii) the transfer documents must be in a form satisfactory to the Managing General Partner; and
(iv) the terms of the transfer must not contravene those of this Agreement.

Transfers of Interests by Participants are subject to the following additional restrictions set forth in Sections 6.02(a)(1), 6.02(a)(2), and 6.02(a)(2).

6.02(a)(1).  Withdrawal of a Participant.  

(i) A Participant may withdraw from the Partnership only by assigning or having all of his or her Interests redeemed or repurchased in accordance with this Article VI. The withdrawal of a Participant shall not dissolve or terminate the Partnership. In the event of the withdrawal of any such Participant because of death, legal incompetence, dissolution or other termination, the estate, legal representative or successor of such Participant shall be deemed to be the Assignee of the Interests of such Participant and may become a Substitute Participant upon compliance with the provisions of this Agreement.

(ii)  Assignment.

(A)  Subject to the provisions of Sections 6.02(a)(2), 6.02(a)(3), 6.02(a)(4) and this Section 6.02(a)(1), any Participant may Assign all or any portion of the Interests owned by such Participant to any Person (the “Assignee”); provided, that

(1)  such Participant and such assignee shall each execute a written Assignment instrument, which shall:

A.  set forth the terms of such assignment;

B.  evidence the acceptance by the Assignee of all of the terms and provisions of this Agreement;

C.  include a representation by both such Participant and such Assignee that such assignment was made in accordance with all applicable laws and regulations (including, without limitation, such minimum investment and investor suitability requirements as may then be applicable under state securities laws); and

D.  otherwise be satisfactory in form and substance to the Managing General Partner.

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(B)  Notwithstanding the foregoing, unless the Managing General Partner shall specifically consent, no Interests may be Assigned:

(1)  to a minor or incompetent (unless a guardian, custodian or conservator has been appointed to handle the affairs of such Person);

(2)  to any Person if, in the opinion of counsel, such assignment would result in the termination of the Partnership, or its status as a partnership, for federal income tax purposes; provided, however, that the Partnership may permit such assignment to become effective if and when, in the opinion of counsel, such assignment would no longer result in the termination of the Partnership, or its status as a partnership, for federal income tax purposes;

(3)  to any Person if such assignment would affect the Partnership’s existence or qualification as a limited partnership under the Delaware Act or the applicable laws of any other jurisdiction in which the Partnership is then conducting business;

(4)  to any Person not permitted to be an Assignee under applicable law, including, without limitation, applicable federal and state securities laws;

(5)  if such assignment would result in the transfer of less than five (5) Interests (unless such Assignment is of all of the Interests owned by such Partner);

(6)  if such assignment would result in the retention by such Participant of less than five (5) Interests;

(7)  if, in the reasonable belief of the Managing General Partner, such assignment might violate applicable law;

(8)  if, in the determination of the Managing General Partner, such assignment would not be in the best interest of the Partnership and its Partners; or

(9)  if such transfer would cause the Interests to be owned by any person who, if an individual, is not a United States citizen resident in the United States or Puerto Rico, or a resident alien with an address in the United States or who would be a “foreign partner” as that term is used in Code Section 1446.

Any attempt to make any Assignment of Interests in violation of this Section 6.02(a)(1)(ii)(B) shall be null and void ab initio.

(C)  No transfer, assignment or repurchase of Interests shall be made, and the Managing General Partner shall not recognize any such transfer, Assignment or repurchase for any purpose whatsoever, if it would result in the Partnership being treated as an association taxable as a corporation or as a “publicly traded partnership” for federal income tax purposes. In addition, the Managing General Partner shall not recognize for any purpose whatsoever (including recognizing any rights of the transferee, such as the right of the transferee to receive directly or indirectly Partnership distributions or to acquire an interest in the capital or profits of the Partnership), an assignment of Interests (or interest therein) if such assignment occurred on an established securities market or a secondary market (or the substantial equivalent thereof) as defined under the Code and any Treasury Regulations or published notices promulgated thereunder (a “Secondary Market”) or fails to meet one or more of the Secondary Market “safe harbor” provisions of Treas. Reg. Section 1.7704-1 or any substitute safe harbor provisions that subsequently may be established by Treasury Regulations or published notices. The Managing General Partner may, in its sole discretion, decline to recognize, for any purpose whatsoever, a transfer or assignment even if it falls within one or more of the foregoing-referenced Secondary Market “safe harbor” provisions. The Partners agree to provide all information respecting assignments which the Managing General Partner deems necessary in order to determine whether a proposed transfer occurred or will occur on a Secondary Market, and each Partner hereby consents and agrees to any decision made by the Managing General Partner, in good faith, to deny a proposed Assignment of Interests hereunder. In no event shall the Partnership recognize, for any purpose whatsoever, transfers in any taxable year, other than those

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that the Managing General Partner concludes in good faith are described in Treas. Reg. Sections 1.7704-1(e)(1)(i)-(vii), 1.7704-1(e)(1)(ix), 1.7704-1(f), or 1.7704-1(g), to the extent such transfers in the aggregate would exceed the lesser of (X) 2% of the total interests in the Partnership’s capital or profits as determined in accordance with Treas. Reg. Sections 1.7704-1(j) and 1.7704-1(k) or (Y) the excess of 10% of such Interests over the Interests the transfer of which the Managing General Partner concludes in good faith were described in Treas. Reg. Sections 1.7704-1(f) or 1.7704-1(g).

(D)  Assignments made in accordance with this Section 6.02 shall be considered consummated on the last day of the month upon which all of the conditions of this Section 6.02 shall have been satisfied and effective for record purposes and for purposes of Article V as of the first day of the month following the date upon which all of the conditions of this Section 6.02 shall have been satisfied. Distributions to the Assignee shall commence the month following effectiveness of the Assignment.

6.02(a)(2).  Tax Law Restrictions.  Subject to transfers permitted by Section 6.03 and transfers by operation of law, no transfer of a Interest by a Participant 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 Section 708 of the Code; or
(ii) treated as a “publicly-traded” partnership for purposes of Section 469(k) or Section 7704 of the Code.

6.02(a)(3).  Securities Laws Restriction.  Subject to transfers permitted by Section 6.03 and transfers by operation of law, no Interest shall be transferred by a Participant unless there is either:

(i) an effective registration of the Interest under the Securities Act of 1933, as amended, and qualification under applicable state securities laws; or
(ii) an opinion of counsel acceptable to the Managing General Partner that the registration and qualification of the Interest is not required, unless this requirement is waived by the Managing General Partner.

Transfers of Interests by Participants are also subject to any conditions contained in the Subscription Agreement.

6.02(a)(4).  Substitute Participant.

6.02(a)(4)(a).  Procedure to Become Substitute Participant.  Subject to Sections 6.02(a)(1) and 6.02(a)(2), a transferee of a Participant’s Interest shall become a substitute Participant entitled to all the rights of a Participant if, and only if:

(i) the transferor gives the transferee the right;
(ii) the transferee pays to the Partnership all costs and expenses incurred by the Partnership in connection with the substitution; and
(iii) the transferee executes and delivers the instruments necessary to establish that a legal transfer has taken place and to confirm the agreement of the transferee to be bound by all of the terms of this Agreement, in a form acceptable to the Managing General Partner.

6.02(a)(4)(b).  Rights of Substitute Participant.  A substitute Participant shall be entitled to all of the rights attributable to full ownership of the assigned Interests including the right to vote.

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6.02(a)(5).  Repurchase of Interests from Foreign Partners.

(a)  The Partnership shall have the right, but not the obligation, to repurchase, for cash, up to 100% of the Interests of any Partner, at the presentment price calculated under Section 6.03(c), if such Partner becomes a “foreign partner” as that term is used in Code Section 1446 at any time during the Term, provided that the Partnership concludes that such repurchase would not constitute a transaction on an established securities market or a secondary market (or the substantial equivalent thereof) and would not jeopardize the Partnership’s treatment as a partnership for federal income tax purposes, and that sufficient cash flow was available to provide the funds for such repurchase, and provided further that the Partnership shall not, in any calendar year, repurchase Interests pursuant to this Section 6.02(a)(5) that, in the aggregate, along with all Interests otherwise transferred in such calendar year (other than those that the Managing General Partner in good faith concludes are described in Regulations Sections 1.7704-1(e)(i)-(vii), 1.7704-1(e)(ix), 1.7704-1(f), or 1.7704-1(g)), including Interests repurchased pursuant to Section 6.03, would exceed the lesser of (X) 2% of the total interests in the Partnership’s capital or profits as determined in accordance with Regulations Sections 1.7704-1(j) and 1.7704-1(k) or (Y) the excess of 10% of such Interests over the Interests the transfer of which the Managing General Partner concludes in good faith were described in Treas. Reg. Sections 1.7704-1(f) or 1.7704-1(g).

(b)  In the event that all Interests of any Partner are repurchased, such Partner shall be deemed to have withdrawn from the Partnership and shall, from and after the date of the repurchase of all Interests of such Partner, cease to have the rights of a Partner.

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 substitute Participants. Any transfer of an Interest by a Participant that is permitted under this Article VI, when the transferee does not become a substitute Participant, shall be effective not later than midnight of the last day of the calendar month in which it is made.

6.02(b)(2).  A Transfer of Interests Does Not Relieve the Transferor of Certain Costs.  No transfer of a Interest by a Participant, including a transfer of less than all of a Participant’s Interests or the transfer of a Participant’s Interests 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 Interests so transferred, whether arising before or after the transfer.

6.02(b)(3).  A Transfer of Interests Does Not Require a Partnership Accounting.  No transfer of a Interest by a Participant shall require an accounting of the Partnership. Also, no transfer of a Interest shall grant rights under this Agreement, including the exercise of any elections, as between the transferring Participant and the Partnership, the Managing General Partner and the remaining Participants to more than one Person unanimously designated by the transferee(s) of the Interest, and, if he has retained an interest in the transferred Interest, the transferor of the Interest.

6.02(b)(4).  Required Notice to Managing General Partner of Transfer of Interests.  Until the Managing General Partner receives from the transferring Participant a written notice in a form acceptable to the Managing General Partner that designates the transferee(s) of a Interest, the Managing General Partner shall continue to account only to the Person to whom it was furnishing notices pursuant to Section 8.01 and its subsections before the purported transfer of the Interest. This party shall continue to exercise all rights under this Agreement applicable to the Interests owned by the purported transferor of the Interest.

6.02(b)(5).  Distributions and Allocations in Respect of Transferred Partner Interests.  If any Interest is Transferred during any Allocation Year in compliance with the provisions of this Article VI, Profits, Losses, each item thereof, and all other items attributable to the Transferred Interest for such Allocation Year shall be divided and allocated between the transferor and the transferee by taking into account their varying Interests during the Fiscal Year in accordance with Code Section 706(d), using any conventions permitted by law as determined by the Managing General Partner. All distributions on or before the date of such Transfer shall be made to the transferor, and all distributions thereafter shall be made to the transferee. Solely for purposes of making such allocations and distributions, the Partnership shall recognize such Transfer not later than the end of the calendar month during which it is given notice of such Transfer; provided that, if the Company is given

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notice of a Transfer at least ten (10) Business Days prior to the Transfer, the Company shall recognize such Transfer as of the date of such Transfer; and provided further that if the Company does not receive a notice stating the date such Interest was Transferred and such other information as the Managing General Partner may reasonably require within thirty (30) days after the end of the Allocation Year during which the Transfer occurs, then all such items shall be allocated, and all distributions shall be made, to the Person who, according to the books and records of the Partnership, was the owner of the Interest on the last day of such Allocation Year. Neither the Partnership nor the Managing General Partner shall incur any liability for making allocations and distributions in accordance with the provisions of this Section 6.02(b)(5), whether or not the Managing General Partner or the Partnership has knowledge of any Transfer of ownership of any Interest.

6.03.  Presentment.  

6.03(a).  In General.  Participants may present their Interests to the Managing General Partner for purchase by the Managing General Partner (or its Affiliate) subject to the conditions and limitations set forth in Section 6.02 and this Section 6.03. A Participant, however, is not obligated to present his Interests for purchase, and the Managing General Partner is not obligated to purchase any or all of the presented Interests.

The Managing General Partner shall not purchase less than one Interest unless the lesser amount represents the Participant’s entire interest in the Partnership, however, the Managing General Partner may waive this limitation. The provisions of this Section 6.03 are intended to and shall be interpreted and applied so as to comply with the requirements of Treas. Reg. Section 1.7704-1(f).

A Participant may present his Interests 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 request must be made by the Participant within 120 days of the reserve report described in Section 4.03(b)(3);
(ii) in accordance with Regulations Section 1.7704-1(f), the purchase may not be made until at least 60 calendar days after the Participant notifies the Managing General Partner in writing of the Participant’s intention to exercise the presentment right;
(iii) the presentment price shall not be established until at least 60 days after the Participant notifies the Managing General Partner in writng of the Participant’s intention to exercise the presentment right; and
(iv) the purchase shall not be considered effective until the presentment price has been paid to the Participant in cash.

6.03(b).  Independent Expert Review.  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 as described in Section 4.03(b)(3)(ii). The calculation of the presentment price shall be made as set forth in Section 6.03(c).

6.03(c).  Calculation of Presentment Price.  The presentment price shall be based on the Partnership’s net assets and liabilities and shall be allocated pro rata to each Participant in the ratio that his number of Interests bears to the total number of Interests. Subject to the foregoing, the presentment price shall include the sum of the following Partnership items:

(i) an amount based on 70% of the present worth of future net revenues from the Proved Reserves determined as described in Section 6.03(b);
(ii) cash on hand;
(iii) prepaid expenses and accounts receivable less a reasonable amount for doubtful accounts; and
(iv) the estimated market value of all assets that are not separately specified above, determined in accordance with standard industry valuation procedures.

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There shall be deducted from the foregoing sum the following Partnership items:

(i) an amount equal to all debts, obligations, and other liabilities, including accrued expenses;
(ii) an amount allocable to the Managing General Partner’s interest in the Partnership (other than its Interests as a Participant); and
(iii) any distributions made to the Participants between the date of the presentment request and the date the presentment price is paid to the selling Participant. However, if any amount of those cash distributions to the Participant by the Partnership was derived from the sale of natural gas, oil or other mineral production, or of a producing property owned by the Partnership, after the date of the presentment request, for purposes of determining the reduction of the presentment price the amount of those cash distributions shall be discounted using the same rate used to take into account the risk factors employed to determine the present worth of the Partnership’s Proved Reserves.

6.03(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 selling Participant 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 date of the presentment request; and
(ii) any of the following occurring before payment of the presentment price to the selling Participant:
(a) changes in well performance;
(b) increases or decreases in the market price of natural gas, oil or other minerals;
(c) revisions to 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.

6.03(e).  Selection by Lot.  If less than all of the Interests presented at any time are to be purchased, then the Participants whose Interests are to be purchased will be selected by lot.

The Managing General Partner or an Affiliate may purchase Interests presented. The Interests of the selling Participant shall be transferred to the party who pays for it. A selling Participant shall be required to deliver an executed assignment of his Interests, in a form satisfactory to the Managing General Partner, together with any other documentation as the Managing General Partner may reasonably request.

6.03(f).  No Obligation of the Managing General Partner to Establish a Reserve.  Neither the Managing General Partner nor the Partnership shall have any obligation to establish any reserve to satisfy the presentment feature under this section.

6.03(g).  Suspension of Presentment Feature.  The Managing General Partner may suspend this presentment feature by so notifying Participants at any time in its sole discretion that it:

(i) does not have sufficient cash flow; or
(ii) is unable to borrow funds for this purpose on terms it deems reasonable.

In addition, the presentment feature may be conditioned, in the Managing General Partner’s sole discretion, on the Managing General Partner’s receipt of an opinion of counsel that the transfers will not cause the Partnership to be treated as a “publicly traded partnership” under the Code.

The Managing General Partner and/or its Affiliate (to the extent of any Interests it purchases) shall hold the purchased Interests for its own account and not for resale.

6.04.  Redemption of Interests from Non-Citizen Assignees.  If the Partnership, the Managing General Partner or any of its Affiliates become subject to federal, state or local laws or regulations that, in the

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reasonable determination of the Managing General Partner, create a substantial risk of cancellation or forfeiture of any property that they have an interest in because of the nationality, citizenship or other related status of any Participant or assignee of a Participant’s Interests, the Partnership may redeem, on 30 days’ advance notice to the Participant, the Participant’s Interests or the Interests held by the assignee of a Participant, at a reasonable redemption price per Interest as determined by the Managing General Partner in its sole discretion.

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 that causes the dissolution of a limited partnership under the Delaware Act.

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 of 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 partnership and the parties to the successor limited partnership.

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 Section 706(c)(2)(A) of the Code; or
(ii) if later, within 90 days after the date of the liquidation.

Notwithstanding, the following amounts are not required to be distributed within the foregoing time periods so long as the withheld amounts are distributed as soon as practical:

(i) amounts withheld for reserves reasonably required for liabilities of the Partnership; and
(ii) installment obligations owed to the Partnership.

7.02(c).  In-Kind Distributions.  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
(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.

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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 to give 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 the Managing General Partner 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 delivered by an overnight delivery company (although one-day delivery is not required) addressed to the party to receive the notice at the address designated in Section 1.03.

If there is a transfer of Interests under this Agreement, no notice to the transferee shall be required, nor shall the transferee have any rights under this Agreement, until notice of the transfer has been given to the Managing General Partner.

Any transfer of Interests under this Agreement shall not increase the Managing General Partner’s or the Partnership’s duty to give notice. If there is a transfer of Interests under this Agreement to more than one party, then notice to any owner of any interest in the Interests shall be notice to all of the owners of the Interests.

8.01(b).  Change in Address.  The address of any party to this Agreement may be changed by 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 overnight delivery 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 Section 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. Except pursuant to Section 7.02(c), when this Agreement expressly requires affirmative approval of a Participant, the Managing General Partner shall send a first request and the time period for the Participant’s written response shall not be less than 15 business days from the date of mailing of the request. If the Participant does not respond in writing to the first request, then the Managing General Partner shall send a second request. If the Participant

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does not respond in writing to the second request within seven calendar days from the date of mailing the second request, then the Participant shall be conclusively deemed to have approved the action.

8.02.  Applicable Law.  The terms and provisions of this Agreement shall be construed under the laws of the State of Delaware, other than its conflict of law provisions, however, this section shall not be deemed to limit causes of action for alleged 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.

8.03.  Agreement in Counterparts.  This Agreement may be executed in counterpart and shall be binding on all of the parties executing this or similar agreements from and after the date of execution by each party.

8.04.  Amendment.  

8.04(a).  Procedure for Amendment.  Except as provided in Section 8.04(b), 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 Interests equal a majority of the total Interests; or
(ii) proposed in writing by Participants whose Interests equal 10% or more of the total Interests and approved by an affirmative vote of Participants whose Interests equal a majority of the total Interests.

8.04(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 and amend the allocation provisions of this Agreement as provided in Section 5.01(c)(3);
(iii) satisfy any requirements, conditions, guidelines, options, or elections contained in any opinion, directive, order, ruling, or regulation of the Commission, 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;
(iv) cure any ambiguity, correct or supplement any provision of this Agreement that may be inconsistent with any other provision of this Agreement, or add any provision to this Agreement with respect to matters, events or issues arising under this Agreement that is not inconsistent with the other provisions of this Agreement; or
(v) facilitate any agreements entered into by the Partnership to hedge its oil and natural gas reserves and pledge up to 100% of its assets and oil and natural gas reserves in connection therewith.

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 or rights will be so affected.

8.05.  Additional Partners.  Each Participant consents to the admission to the Partnership of additional Participants as the Managing General Partner, in its discretion, chooses to admit.

8.06.  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,” or “parties” shall equally apply to any successor limited partnership, and any heir, devisee, personal representative, successor or assign of a party.

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IN WITNESS WHEREOF, the parties hereto set their hands as of the [___] day of [__________], 2012.

 
  ICON Oil & Gas GP, LLC
Managing General Partner
     By: []

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EXHIBIT B

_______________________ PROJECT
  
PARTICIPATION AGREEMENT

(Various oil and gas leases in __________ County, ______)

This Participation Agreement (hereinafter referred to as the “AGREEMENT”) is entered into this _____ day of ____, but shall be effective as of ___________, ____, by and between _________ (hereinafter referred to as “OPERATOR”) whose address is _______ and __________ (hereinafter referred to as “PARTICIPANT”). This Agreement may be one of several similar agreements that are being entered into between OPERATOR and other industry participants (collectively, with PARTICIPANT, the “PROSPECT PARTICIPANTS”) for the acquisition of the LEASEHOLD (defined below) and the exploration and development of the AMI (defined below). The effectiveness of this AGREEMENT with PARTICIPANT is, however, not conditioned upon OPERATOR entering into other agreements with other PROSPECT PARTICIPANTS.

WHEREAS OPERATOR has defined an area for oil and gas exploitation and development covering approximately _____ acres called the _____________ PROJECT (hereinafter referred to as the “PROJECT”) and outlined on the map attached hereto as Exhibit A as situated in ______.

WHEREAS OPERATOR and PARTICIPANT desire to create an area of mutual interest outlined on the map attached as Exhibit A (the “AMI”). PARTICIPANT and OPERATOR further desire to jointly exploit and/or develop the LEASEHOLD within the AMI under the terms and conditions outlined in this AGREEMENT whereby PARTICIPANT acquires a working interest of _____ percent (___%) (subject to adjustment as provided herein) in and to the LEASEHOLD within the boundaries of this AMI as provided herein.

NOW THEREFORE, in consideration of Ten Dollars and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, OPERATOR and PARTICIPANT do hereby agree as follows:

1.  DEFINITIONS.  The following definitions are used in this Agreement in addition to the terms defined above:

A. “ADMINISTRATIVE FEE” means the payment due OPERATOR in the amount of _____ in addition to the actual COSTS payable as provided in this AGREEMENT.
B. “COSTS” means ____________.
C. “EXISTING BURDENS” means all royalty, overriding royalty, production payments and similar burdens on production constituting a lease burden on the LEASEHOLD of record or, if the context requires, in favor of OPERATOR pursuant to this AGREEMENT.
D. “LEASE” means the oil and gas leases, the oil, gas and mineral leases and other rights to develop the oil and gas mineral estate to the extent the acreage covered thereby is included within the AMI, regardless of how acquired.
E. “LEASEHOLD” means the aggregate of all right, title and interest owned by Operator or Prospect Participants to drill and develop the oil and gas mineral estate to the extent of any acreage in the AMI, whether pursuant to the LEASES, farm-outs, pooling orders or otherwise, all contracts, agreements, leases, licenses, easements, rights under orders of regulatory authorities and other property rights incident to the ownership of the LEASES.
F. “NET REVENUE INTEREST” means the share of production the working interest is entitled after all EXISTING BURDENS have been proportionately taken out.
G. “OPERATING AGREEMENT” means the Joint Operating Agreement entered into pursuant to Paragraph 3.A below.

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H. “PRODUCING WELL” means an oil or gas well capable of producing oil or gas or both and all associated equipment and infrastructure.
I. “THROUGH THE TANKS” shall mean that point in time whereby a well has been fully completed and equipped and to become operational as a WELL, including all the supporting water, salt water or disposal wells, pipeline infra structure and electrical systems in place for that well as designed and implemented by the OPERATOR.
J. “WELL” means an oil or gas well, injection or disposal well and any water or salt water wells, including dry holes.

2.  LEASEHOLD; PARTICIPATION PAYMENTS.

A. Either party may seperately acquire additional LEASES within the AMI, which LEASES shall become subject to this Agreement. The parties shall share in any additional LEASES acquired within the AMI based on the percentage specified for the LEASEHOLD in paragraph 2.B. below.
B. PARTICIPANT agrees to participate in, acquire a working interest of _____ percent (___%) (subject to adjustment as provided herein) in and to the LEASEHOLD within the boundaries of the AMI and pay for its proportionate share of the COSTS. All COSTS incurred to date including any ADMINISTRATIVE FEE, as applicable, shall be due and payable upon execution of this AGREEMENT.
C. OPERATOR and PARTICIPANT further agree that PARTICIPANT shall pay its proportionate share of all COSTS plus an ADMINISTRATIVE FEE equal to _____, for drilling, completing and equipping of each WELL “THROUGH THE TANKS”. COSTS and ADMINISTRATIVE FEES will be determined based on the date of service.
D. Subject to the EXISTING BURDENS and the reservation of overriding royalty interest by OPERATOR and reduction of working interest pursuant to paragraph 2.E below, OPERATOR will execute and deliver an assignment or cause to be assigned to PARTICIPANT its working interest associated with a PRODUCING WELL, upon completion of a division order title opinion, provided, such assignment is being made without warranty of title, either express or implied, except as to claims created or arising by, through or under Operator and not otherwise.
E. PARTICIPANT’S WORKING INTEREST acquired hereunder will be proportionally reduced if OPERATOR is unable to secure LEASEHOLD for 100% of the working interest in each production or proration unit. The LEASEHOLD and working interest acquired by PARTICIPANT is intended to be delivered at an __% NET REVENUE INTEREST. In the event the EXISTING BURDENS on any LEASEHOLD is less than __%, OPERATOR reserves and excepts an overriding royalty interest equal to the difference between ___% and the EXISTING BURDENS. In the event OPERATOR acquires any LEASEHOLD with EXISTING BURDENS greater than __%, OPERATOR will not add any additional leasehold burdens and PARTICIPANT’S NET REVENUE INTEREST in such LEASEHOLD shall be accordingly reduced.

3.  JOINT OPERATING AGREEMENT.

A. PARTICIPANT and OPERATOR agree to conduct all drilling and production operations endeavored as a part of this AGREEMENT in accordance with the terms of the Model Form Operating Agreement attached hereto as Exhibit B. In the event of conflict between the terms of this AGREEMENT and said Model Form Operating Agreement, the terms of this AGREEMENT shall prevail.
B. OPERATOR overhead rates shall be as follows:
$___ Before Casing Point and $___ After Casing Point for all horizontal WELLS.
$____ Before Casing Point and $____ After Casing Point for vertical WELLS.
$___ per month per WELL (excluding dry holes).

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C. PARTICIPANT hereby agrees that OPERATOR shall have the right to enter into and commit all natural gas and natural gas products to gas sales, gathering and processing contracts for the benefit of all parties to this AGREEMENT. PARTICIPANT also agrees that OPERATOR shall have the right to enter into and commit all crude oil and associated products to a crude purchasing contract for the benefit of all parties to this AGREEMENT excluding any hedging strategies or obligations as may be desired or entered into by OPERATOR. All oil and gas sales contracts shall be deemed to have ratified by PARTICIPANT under the terms of this AGREEMENT.

4.  TEST WELL.

Subject to the necessary regulatory approvals and the agreed participation of all PROSPECT PARTICIPANTS, OPERATOR agrees to commence or cause to be commenced operations for the drilling of an initial test well in the AMI to test the __________ formation or to an approximately total depth of _____ feet, whichever is lesser. The initial test well will be drilled and, if applicable, completed in accordance with the terms and conditions of the OPERATING AGREEMENT. PARTICIPANT agrees to bear and pay its share of the costs and expenses (plus ADMINISTRATIVE FEE) of the initial test well in accordance with paragraph 2 above.

5.  NO TAX PARTNERSHIP.

It is further understood that all parties specifically elect to be excluded from the application of Subchapter K of Chapter 1, Subtitle A of the Internal Revenue Code, as may be amended, insofar as said Subchapter or portion thereof which may apply to the parties hereto with respect to the operations covered by this Agreement and their relationship herein. It is not the intention or purpose of this Agreement to create, and nothing herein shall be construed as creating a mining or other partnership or association, or to render any party hereto responsible for any act, whether of omission or commission of the other parties hereto. The obligations of each of the parties hereto shall be several, and each such party shall be responsible only for its share of the costs and obligations relating to this AGREEMENT.

6.  CONFIDENTIALITY.

All information furnished by OPERATOR to PARTICIPANT that is not available in the public domain and inherently of a confidential nature (such as proprietary geological, geophysical or engineering data), shall be kept confidential by PARTICIPANT and OPERATOR for a period of 2 years beyond the expiration of this AGREEMENT as provided under the Operating Agreement attached hereto as Exhibit B. Notwithstanding the above, each party hereto shall have the right to disclose such confidential information to its investors, lenders, attorneys, accountants, consultants and others to the extent such disclosure is necessary to conduct business operations and those other parties shall be notified of this confidentiality and shall be bound to comply.

7.  MISCELLANEOUS.

A. Notice shall be duly noted and given if deposited in the United States Postal Service to the parties named herein and at the address provided in this AGREEMENT. In addition, the parties hereto may utilize facsimile and/or electronic mail accompanied and/or supported by a delivery receipt for such notice.
B. PARTICIPANT and OPERATOR do hereby agree that after execution of this AGREEMENT they will continue to execute any and all curative documents and/or other instruments and take such actions as are necessary to fulfill the rights, duties and obligations provided for under this AGREEMENT.
C. This AGREEMENT shall be binding on and shall inure to the benefit of the parties hereto, their successors, and assigns. In addition, this AGREEMENT shall supersede and replace any and all previous written or oral agreements that might have been in place prior to the execution of this AGREEMENT as they might relate to this PROJECT.
D. PARTICIPANT and OPERATOR agree that the terms of this AGREEMENT and the relationship of the parties hereto shall be governed under the laws of the State of ____ with venue in _____.

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E. This AGREEMENT shall be for the term specified in the Model Form Operating Agreement included in Exhibit B attached hereto as noted on page B-37 under Article XIII, “Term of Agreement” option 2 of said Operating Agreement, limited however, to a term as it relates only to the area outlined in Exhibit A.
F. This AGREEMENT shall be considered a covenant running with the land.
G. This AGREEMENT may be executed in any number of counterparts.

EXECUTED and effective the dates first above written.

 
“PARTICIPANT”   “OPERATOR”
Company Name   Company Name
  
  


Name
Title
 

Name
Title

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EXHIBIT A — Map of Project Area

EXHIBIT B — Operating Agreement

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EXHIBIT A

[MAP OF PROJECT AREA]

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EXHIBIT B

A.A.P.L. FORM 610 — 1989

MODEL FORM OPERATING AGREEMENT

  
  
  
  
  
  

OPERATING AGREEMENT

DATED

_______________ , __________ ,
                year

OPERATOR 

CONTRACT AREA 

  

  

  

  

COUNTY OR PARISH OF ______________________________________ , STATE OF 

  
  
  
  
  
  

COPYRIGHT 1989 — ALL RIGHTS RESERVED AMERICAN ASSOCIATION OF PETROLEUM LANDMEN, 4100 FOSSIL CREEK BLVD.
FORT WORTH, TEXAS, 76137, APPROVED FORM.
  
          A.A.P.L. NO. 610 — 1989

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

TABLE OF CONTENTS

   
Article   Title   Page

I.

DEFINITIONS

    B-10  

II.

EXHIBITS

    B-11  

III.

INTERESTS OF PARTIES

    B-12  

A.

OIL AND GAS INTERESTS:

    B-12  

B.

INTERESTS OF PARTIES IN COSTS AND PRODUCTION:

    B-12  

C.

SUBSEQUENTLY CREATED INTERESTS:

    B-12  

IV.

TITLES

    B-13  

A.

TITLE EXAMINATION:

    B-13  

B.

LOSS OR FAILURE OF TITLE:

    B-14  

1.

Failure of Title

    B-14  

2.

Loss by Non-Payment or Erroneous Payment of Amount Due

    B-14  

3.

Other Losses

    B-15  

4.

Curing Title

    B-15  

V.

OPERATOR

    B-15  

A.

DESIGNATION AND RESPONSIBILITIES OF OPERATOR:

    B-15  

B.

RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR:

    B-16  

1.

Resignation or Removal of Operator

    B-16  

2.

Selection of Successor Operator

    B-16  

3.

Effect of Bankruptcy

    B-16  

C.

EMPLOYEES AND CONTRACTORS:

    B-17  

D.

RIGHTS AND DUTIES OF OPERATOR:

    B-17  

1.

Competitive Rates and Use of Affiliates

    B-17  

2.

Discharge of Joint Account Obligations

    B-17  

3.

Protection from Liens

    B-17  

4.

Custody of Funds

    B-17  

5.

Access to Contract Area and Records

    B-17  

6.

Filing and Furnishing Governmental Reports

    B-18  

7.

Drilling and Testing Operations

    B-18  

8.

Cost Estimates

    B-18  

9.

Insurance

    B-18  

VI.

DRILLING AND DEVELOPMENT

    B-18  

A.

INITIAL WELL:

    B-18  

B.

SUBSEQUENT OPERATIONS:

    B-19  

1.

Proposed Operations

    B-19  

2.

Operations by Less Than All Parties

    B-19  

3.

Stand-By Costs

    B-22  

4.

Deepening

    B-23  

5.

Sidetracking

    B-23  

6.

Order of Preference of Operations

    B-24  

7.

Conformity to Spacing Pattern

    B-24  

8.

Paying Wells

    B-24  

C.

COMPLETION OF WELLS; REWORKING AND PLUGGING BACK:

    B-24  

1.

Completion

    B-24  

2.

Rework, Recomplete or Plug Back

    B-25  

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

   
Article   Title   Page

D.

OTHER OPERATIONS:

    B-25  

E.

ABANDONMENT OF WELLS:

    B-26  

1.

Abandonment of Dry Holes

    B-26  

2.

Abandonment of Wells That Have Produced

    B-26  

3.

Abandonment of Non-Consent Operations

    B-27  

F.

TERMINATION OF OPERATIONS:

    B-27  

G.

TAKING PRODUCTION IN KIND:

    B-27  
(Option 1) Gas Balancing Agreement     B-27  
(Option 2) No Gas Balancing Agreement     B-28  

VII.

EXPENDITURES AND LIABILITY OF PARTIES

    B-29  

A.

LIABILITY OF PARTIES:

    B-29  

B.

LIENS AND SECURITY INTERESTS:

    B-29  

C.

ADVANCES:

    B-30  

D.

DEFAULTS AND REMEDIES:

    B-31  

1.

Suspension of Rights

    B-31  

2.

Suit for Damages

    B-31  

3.

Deemed Non-Consent

    B-31  

4.

Advance Payment

    B-32  

5.

Costs and Attorneys’ Fees

    B-32  

E.

RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES:

    B-32  

F.

TAXES:

    B-32  

VIII.

ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST

    B-33  

A.

SURRENDER OF LEASES:

    B-33  

B.

RENEWAL OR EXTENSION OF LEASES:

    B-33  

C.

ACREAGE OR CASH CONTRIBUTIONS:

    B-34  

D.

ASSIGNMENT; MAINTENANCE OF UNIFORM INTEREST:

    B-34  

E.

WAIVER OF RIGHTS TO PARTITION:

    B-35  

F.

PREFERENTIAL RIGHT TO PURCHASE:

    B-35  

IX.

INTERNAL REVENUE CODE ELECTION

    B-36  

X.

CLAIMS AND LAWSUITS

    B-36  

XI.

FORCE MAJEURE

    B-36  

XII.

NOTICES

    B-37  

XIII.

TERM OF AGREEMENT

    B-37  

XIV.

COMPLIANCE WITH LAWS AND REGULATIONS

    B-38  

A.

LAWS, REGULATIONS AND ORDERS:

    B-38  

B.

GOVERNING LAW:

    B-38  

C.

REGULATORY AGENCIES:

    B-38  

XV.

MISCELLANEOUS

    B-38  

A.

EXECUTION:

    B-38  

B.

SUCCESSORS AND ASSIGNS:

    B-39  

C.

COUNTERPARTS:

    B-39  

D.

SEVERABILITY

    B-39  

XVI.

OTHER PROVISIONS

    B-39  

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

OPERATING AGREEMENT

THIS AGREEMENT, entered into by and between ___________________________________________, hereinafter designated and referred to as “Operator,” and the signatory party or parties other than Operator, sometimes hereinafter referred to individually as “Non-Operator,” and collectively as “Non-Operators.”

WITNESSETH:

WHEREAS, the parties to this agreement are owners of Oil and Gas Leases and/or Oil and Gas Interests in the land identified in Exhibit “A,” and the parties hereto have reached an agreement to explore and develop these Leases and/or Oil and Gas Interests for the production of Oil and Gas to the extent and as hereinafter provided,

NOW, THEREFORE, it is agreed as follows:

ARTICLE I.
DEFINITIONS

As used in this agreement, the following words and terms shall have the meanings here ascribed to them:

A.  The term “AFE” shall mean an Authority for Expenditure prepared by a party to this agreement for the purpose of estimating the costs to be incurred in conducting an operation hereunder.

B.  The term “Completion” or “Complete” shall mean a single operation intended to complete a well as a producer of Oil and Gas in one or more Zones, including, but not limited to, the setting of production casing, perforating, well stimulation and production testing conducted in such operation.

C.  The term “Contract Area” shall mean all of the lands, Oil and Gas Leases and/or Oil and Gas Interests intended to be developed and operated for Oil and Gas purposes under this agreement. Such lands, Oil and Gas Leases and Oil and Gas Interests are described in Exhibit “A.”

D.  The term “Deepen” shall mean a single operation whereby a well is drilled to an objective Zone below the deepest Zone in which the well was previously drilled, or below the Deepest Zone proposed in the associated AFE, whichever is the lesser.

E.  The terms “Drilling Party” and “Consenting Party” shall mean a party who agrees to join in and pay its share of the cost of any operation conducted under the provisions of this agreement.

F.  The term “Drilling Unit” shall mean the area fixed for the drilling of one well by order or rule of any state or federal body having authority. If a Drilling Unit is not fixed by any such rule or order, a Drilling Unit shall be the drilling unit as established by the pattern of drilling in the Contract Area unless fixed by express agreement of the Drilling Parties.

G.  The term “Drillsite” shall mean the Oil and Gas Lease or Oil and Gas Interest on which a proposed well is to be located.

H.  The term “Initial Well” shall mean the well required to be drilled by the parties hereto as provided in Article VI.A.

I.  The term “Non-Consent Well” shall mean a well in which less than all parties have conducted an operation as provided in Article VI.B.2.

J.  The terms “Non-Drilling Party” and “Non-Consenting Party” shall mean a party who elects not to participate in a proposed operation.

K.  The term “Oil and Gas” shall mean oil, gas, casinghead gas, gas condensate, and/or all other liquid or gaseous hydrocarbons and other marketable substances produced therewith, unless an intent to limit the inclusiveness of this term is specifically stated.

L.  The term “Oil and Gas Interests” or “Interests” shall mean unleased fee and mineral interests in Oil and Gas in tracts of land lying within the Contract Area which are owned by parties to this agreement.

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

M.  The terms “Oil and Gas Lease,” “Lease” and “Leasehold” shall mean the oil and gas leases or interests therein covering tracts of land lying within the Contract Area which are owned by the parties to this agreement.

N.  The term “Plug Back” shall mean a single operation whereby a deeper Zone is abandoned in order to attempt a Completion in a shallower Zone.

O.  The term “Recompletion” or “Recomplete” shall mean an operation whereby a Completion in one Zone is abandoned in order to attempt a Completion in a different Zone within the existing wellbore.

P.  The term “Rework” shall mean an operation conducted in the wellbore of a well after it is Completed to secure, restore, or improve production in a Zone which is currently open to production in the wellbore. Such operations include, but are not limited to, well stimulation operations but exclude any routine repair or maintenance work or drilling, Sidetracking, Deepening, Completing, Recompleting, or Plugging Back of a well.

Q.  The term “Sidetrack” shall mean the directional control and intentional deviation of a well from vertical so as to change the bottom hole location unless done to straighten the hole or drill around junk in the hole to overcome other mechanical difficulties.

R.  The term “Zone” shall mean a stratum of earth containing or thought to contain a common accumulation of Oil and Gas separately producible from any other common accumulation of Oil and Gas.

Unless the context otherwise clearly indicates, words used in the singular include the plural, the word “person” includes natural and artificial persons, the plural includes the singular, and any gender includes the masculine, feminine, and neuter.

ARTICLE II.
EXHIBITS

The following exhibits, as indicated below and attached hereto, are incorporated in and made a part hereof:

________  A.  Exhibit “A,” shall include the following information:

  (1)  Description of lands subject to this agreement,

  (2)  Restrictions, if any, as to depths, formations, or substances,

  (3)  Parties to agreement with addresses and telephone numbers for notice purposes,

  (4)  Percentages or fractional interests of parties to this agreement,

  (5)  Oil and Gas Leases and/or Oil and Gas Interests subject to this agreement,

  (6)  Burdens on production.

________  B.  Exhibit “B,” Form of Lease.

________  C.  Exhibit “C,” Accounting Procedure.

________  D.  Exhibit “D,” Insurance.

________  E.  Exhibit “E,” Gas Balancing Agreement.

________  F.  Exhibit “F,” Non-Discrimination and Certification of Non-Segregated Facilities.

________  G.  Exhibit “G,” Tax Partnership.

________  H.  Other: _____________________________________________________

If any provision of any exhibit, except Exhibits “E,” “F” and “G,” is inconsistent with any provision contained in the body of this agreement, the provisions in the body of this agreement shall prevail.

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

ARTICLE III.
INTERESTS OF PARTIES

A.  Oil and Gas Interests:

If any party owns an Oil and Gas Interest in the Contract Area, that Interest shall be treated for all purposes of this agreement and during the term hereof as if it were covered by the form of Oil and Gas Lease attached hereto as Exhibit “B,” and the owner thereof shall be deemed to own both royalty interest in such lease and the interest of the lessee thereunder.

B.  Interests of Parties in Costs and Production:

Unless changed by other provisions, all costs and liabilities incurred in operations under this agreement shall be borne and paid, and all equipment and materials acquired in operations on the Contract Area shall be owned, by the parties as their interests are set forth in Exhibit “A.” In the same manner, the parties shall also own all production of Oil and Gas from the Contract Area subject, however, to the payment of royalties and other burdens on production as described hereafter.

Regardless of which party has contributed any Oil and Gas Lease or Oil and Gas Interest on which royalty or other burdens may be payable and except as otherwise expressly provided in this agreement, each party shall pay or deliver, or cause to be paid or delivered, all burdens on its share of the production from the Contract Area up to, but not in excess of, __________________________________ and shall indemnify, defend and hold the other parties free from any liability therefor. Except as otherwise expressly provided in this agreement, if any party has contributed hereto any Lease or Interest which is burdened with any royalty, overriding royalty, production payment or other burden on production in excess of the amounts stipulated above, such party so burdened shall assume and alone bear all such excess obligations and shall indemnify, defend and hold the other parties hereto harmless from any and all claims attributable to such excess burden. However, so long as the Drilling Unit for the productive Zone(s) is identical with the Contract Area, each party shall pay or deliver, or cause to be paid or delivered, all burdens on production from the Contract Area due under the terms of the Oil and Gas Lease(s) which such party has contributed to this agreement, and shall indemnify, defend and hold the other parties free from any liability therefor.

No party shall ever be responsible, on a price basis higher than the price received by such party, to any other party’s lessor or royalty owner, and if such other party’s lessor or royalty owner should demand and receive settlement on a higher price basis, the party contributing the affected Lease shall bear the additional royalty burden attributable to such higher price.

Nothing contained in this Article III.B. shall be deemed an assignment or cross-assignment of interests covered hereby, and in the event two or more parties contribute to this agreement jointly owned Leases, the parties’ undivided interests in said Leaseholds shall be deemed separate leasehold interests for the purposes of this agreement.

C.  Subsequently Created Interests:

If any party has contributed hereto a Lease or Interest that is burdened with an assignment of production given as security for the payment of money, or if, after the date of this agreement, any party creates an overriding royalty, production payment, net profits interest, assignment of production or other burden payable out of production attributable to its working interest hereunder, such burden shall be deemed a “Subsequently Created Interest.” Further, if any party has contributed hereto a Lease or Interest burdened with an overriding royalty, production payment, net profits interests, or other burden payable out of production created prior to the date of this agreement, and such burden is not shown on Exhibit “A,” such burden also shall be deemed a Subsequently Created Interest to the extent such burden causes the burdens on such party’s Lease or Interest to exceed the amount stipulated in Article III.B. above.

The party whose interest is burdened with the Subsequently Created Interest (the “Burdened Party”) shall assume and alone bear, pay and discharge the Subsequently Created Interest and shall indemnify, defend and hold harmless the other parties from and against any liability therefor. Further, if the Burdened Party fails to pay, when due, its share of expenses chargeable hereunder, all provisions of Article VII.B. shall be

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enforceable against the Subsequently Created Interest in the same manner as they are enforceable against the working interest of the Burdened Party. If the Burdened Party is required under this agreement to assign or relinquish to any other party, or parties, all or a portion of its working interest and/or the production attributable thereto, said other party, or parties, shall receive said assignment and/or production free and clear of said Subsequently Created Interest, and the Burdened Party shall indemnify, defend and hold harmless said other party, or parties, from any and all claims and demands for payment asserted by owners of the Subsequently Created Interest.

ARTICLE IV.
TITLES

A.  Title Examination:

Title examination shall be made on the Drillsite of any proposed well prior to commencement of drilling operations and, if a majority in interest of the Drilling Parties so request or Operator so elects, title examination shall be made on the entire Drilling Unit, or maximum anticipated Drilling Unit, of the well. The opinion will include the ownership of the working interest, minerals, royalty, overriding royalty and production payments under the applicable Leases. Each party contributing Leases and/or Oil and Gas Interests to be included in the Drillsite or Drilling Unit, if appropriate, shall furnish to Operator all abstracts (including federal lease status reports), title opinions, title papers and curative material in its possession free of charge. All such information not in the possession of or made available to Operator by the parties, but necessary for the examination of the title, shall be obtained by Operator. Operator shall cause title to be examined by attorneys on its staff or by outside attorneys. Copies of all title opinions shall be furnished to each Drilling Party. Costs incurred by Operator in procuring abstracts, fees paid outside attorneys for title examination (including preliminary, supplemental, shut-in royalty opinions and division order title opinions) and other direct charges as provided in Exhibit “C” shall be borne by the Drilling Parties in the proportion that the interest of each Drilling Party bears to the total interest of all Drilling Parties as such interests appear in Exhibit “A.” Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions.

Each party shall be responsible for securing curative matter and pooling amendments or agreements required in connection with Leases or Oil and Gas Interests contributed by such party. Operator shall be responsible for the preparation and recording of pooling designations or declarations and communitization agreements as well as the conduct of hearings before governmental agencies for the securing of spacing or pooling orders or any other orders necessary or appropriate to the conduct of operations hereunder. This shall not prevent any party from appearing on its own behalf at such hearings. Costs incurred by Operator, including fees paid to outside attorneys, which are associated with hearings before governmental agencies, and which costs are necessary and proper for the activities contemplated under this agreement, shall be direct charges to the joint account and shall not be covered by the administrative overhead charges as provided in Exhibit “C.”

Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions.

No well shall be drilled on the Contract Area until after (1) the title to the Drillsite or Drilling Unit, if appropriate, has been examined as above provided, and (2) the title has been approved by the examining attorney or title has been accepted by all of the Drilling Parties in such well.

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B.  Loss or Failure of Title:

1.  Failure of Title:  Should any Oil and Gas Interest or Oil and Gas Lease be lost through failure of title, which results in a reduction of interest from that shown on Exhibit “A,” the party credited with contributing the affected Lease or Interest (including, if applicable, a successor in interest to such party) shall have ninety (90) days from final determination of title failure to acquire a new lease or other instrument curing the entirety of the title failure, which acquisition will not be subject to Article VIII.B., and failing to do so, this agreement, nevertheless, shall continue in force as to all remaining Oil and Gas Leases and Interests; and,

(a)  The party credited with contributing the Oil and Gas Lease or Interest affected by the title failure (including, if applicable, a successor in interest to such party) shall bear alone the entire loss and it shall not be entitled to recover from Operator or the other parties any development or operating costs which it may have previously paid or incurred, but there shall be no additional liability on its part to the other parties hereto by reason of such title failure;

(b)  There shall be no retroactive adjustment of expenses incurred or revenues received from the operation of the Lease or Interest which has failed, but the interests of the parties contained on Exhibit “A” shall be revised on an acreage basis, as of the time it is determined finally that title failure has occurred, so that the interest of the party whose Lease or Interest is affected by the title failure will thereafter be reduced in the Contract Area by the amount of the Lease or Interest failed;

(c)  If the proportionate interest of the other parties hereto in any producing well previously drilled on the Contract Area is increased by reason of the title failure, the party who bore the costs incurred in connection with such well attributable to the Lease or Interest which has failed shall receive the proceeds attributable to the increase in such interest (less costs and burdens attributable thereto) until it has been reimbursed for unrecovered costs paid by it in connection with such well attributable to such failed Lease or Interest;

(d)  Should any person not a party to this agreement, who is determined to be the owner of any Lease or Interest which has failed, pay in any manner any part of the cost of operation, development, or equipment, such amount shall be paid to the party or parties who bore the costs which are so refunded;

(e)  Any liability to account to a person not a party to this agreement for prior production of Oil and Gas which arises by reason of title failure shall be borne severally by each party (including a predecessor to a current party) who received production for which such accounting is required based on the amount of such production received, and each such party shall severally indemnify, defend and hold harmless all other parties hereto for any such liability to account;

(f)  No charge shall be made to the joint account for legal expenses, fees or salaries in connection with the defense of the Lease or Interest claimed to have failed, but if the party contributing such Lease or Interest hereto elects to defend its title it shall bear all expenses in connection therewith; and

(g)  If any party is given credit on Exhibit “A” to a Lease or Interest which is limited solely to ownership of an interest in the wellbore of any well or wells and the production therefrom, such party’s absence of interest in the remainder of the Contract Area shall be considered a Failure of Title as to such remaining Contract Area unless that absence of interest is reflected on Exhibit “A.”

2.  Loss by Non-Payment or Erroneous Payment of Amount Due:  If, through mistake or oversight, any rental, shut-in well payment, minimum royalty or royalty payment, or other payment necessary to maintain all or a portion of an Oil and Gas Lease or interest is not paid or is erroneously paid, and as a result a Lease or Interest terminates, there shall be no monetary liability against the party who failed to make such payment. Unless the party who failed to make the required payment secures a new Lease or Interest covering the same interest within ninety (90) days from the discovery of the failure to make proper payment, which acquisition will not be subject to Article VIII.B., the interests of the parties reflected on Exhibit “A” shall be revised on an acreage basis, effective as of the date of termination of the Lease or Interest involved, and the party who failed to make proper payment will no longer be credited with an interest in the Contract Area on account of

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ownership of the Lease or Interest which has terminated. If the party who failed to make the required payment shall not have been fully reimbursed, at the time of the loss, from the proceeds of the sale of Oil and Gas attributable to the lost Lease or Interest, calculated on an acreage basis, for the development and operating costs previously paid on account of such Lease or Interest, it shall be reimbursed for unrecovered actual costs previously paid by it (but not for its share of the cost of any dry hole previously drilled or wells previously abandoned) from so much of the following as is necessary to effect reimbursement:

(a)  Proceeds of Oil and Gas produced prior to termination of the Lease or Interest, less operating expenses and lease burdens chargeable hereunder to the person who failed to make payment, previously accrued to the credit of the lost Lease or Interest, on an acreage basis, up to the amount of unrecovered costs;

(b)  Proceeds of Oil and Gas, less operating expenses and lease burdens chargeable hereunder to the person who failed to make payment, up to the amount of unrecovered costs attributable to that portion of Oil and Gas thereafter produced and marketed (excluding production from any wells thereafter drilled) which, in the absence of such Lease or Interest termination, would be attributable to the lost Lease or Interest on an acreage basis and which as a result of such Lease or Interest termination is credited to other parties, the proceeds of said portion of the Oil and Gas to be contributed by the other parties in proportion to their respective interests reflected on Exhibit “A”; and,

(c)  Any monies, up to the amount of unrecovered costs, that may be paid by any party who is, or becomes, the owner of the Lease or Interest lost, for the privilege of participating in the Contract Area or becoming a party to this agreement.

3.  Other Losses:  All losses of Leases or Interests committed to this agreement, other than those set forth in Articles IV.B.1. and IV.B.2. above, shall be joint losses and shall be borne by all parties in proportion to their interests shown on Exhibit “A.” This shall include but not be limited to the loss of any Lease or Interest through failure to develop or because express or implied covenants have not been performed (other than performance which requires only the payment of money), and the loss of any Lease by expiration at the end of its primary term if it is not renewed or extended. There shall be no readjustment of interests in the remaining portion of the Contract Area on account of any joint loss.

4.  Curing Title:  In the event of a Failure of Title under Article IV.B.1. or a loss of title under Article IV.B.2. above, any Lease or Interest acquired by any party hereto (other than the party whose interest has failed or was lost) during the ninety (90) day period provided by Article IV.B.1. and Article IV.B.2. above covering all or a portion of the interest that has failed or was lost shall be offered at cost to the party whose interest has failed or was lost, and the provisions of Article VIII.B. shall not apply to such acquisition.

ARTICLE V.
OPERATOR

A.  Designation and Responsibilities of Operator:

_______________________________________ shall be the Operator of the Contract Area, and shall conduct and direct and have full control of all operations on the Contract Area as permitted and required by, and within the limits of this agreement. In its performance of services hereunder for the Non-Operators, Operator shall be an independent contractor not subject to the control or direction of the Non-Operators except as to the type of operation to be undertaken in accordance with the election procedures contained in this agreement. Operator shall not be deemed, or hold itself out as, the agent of the Non-Operators with authority to bind them to any obligation or liability assumed or incurred by Operator as to any third party. Operator shall conduct its activities under this agreement as a reasonable prudent operator, in a good and workmanlike manner, with due diligence and dispatch, in accordance with good oilfield practice, and in compliance with applicable law and regulation, but in no event shall it have any liability as Operator to the other parties for losses sustained or liabilities incurred except such as may result from gross negligence or willful misconduct.

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B.  Resignation or Removal of Operator and Selection of Successor:

1.  Resignation or Removal of Operator:  Operator may resign at any time by giving written notice thereof to Non-Operators. If Operator terminates its legal existence, no longer owns an interest hereunder in the Contract Area, or is no longer capable of serving as Operator, Operator shall be deemed to have resigned without any action by Non-Operators, except the selection of a successor. Operator may be removed only for good cause by the affirmative vote of Non-Operators owning a majority interest based on ownership as shown on Exhibit “A” remaining after excluding the voting interest of Operator; such vote shall not be deemed effective until a written notice has been delivered to the Operator by a Non-Operator detailing the alleged default and Operator has failed to cure the default within thirty (30) days from its receipt of the notice or, if the default concerns an operation then being conducted, within forty-eight (48) hours of its receipt of the notice. For purposes hereof, “good cause” shall mean not only gross negligence or willful misconduct but also the material breach of or inability to meet the standards of operation contained in Article V.A. or material failure or inability to perform its obligations under this agreement.

Subject to Article VII.D.1., such resignation or removal shall not become effective until 7:00 o’clock A.M. on the first day of the calendar month following the expiration of ninety (90) days after the giving of notice of resignation by Operator or action by the Non-Operators to remove Operator, unless a successor Operator has been selected and assumes the duties of Operator at an earlier date. Operator, after effective date of resignation or removal, shall be bound by the terms hereof as a Non-Operator. A change of a corporate name or structure of Operator or transfer of Operator’s interest to any single subsidiary, parent or successor corporation shall not be the basis for removal of Operator.

2.  Selection of Successor Operator:  Upon the resignation or removal of Operator under any provision of this agreement, a successor Operator shall be selected by the parties. The successor Operator shall be selected from the parties owning an interest in the Contract Area at the time such successor Operator is selected. The successor Operator shall be selected by the affirmative vote of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit “A”; provided, however, if an Operator which has been removed or is deemed to have resigned fails to vote or votes only to succeed itself, the successor Operator shall be selected by the affirmative vote of the party or parties owning a majority interest based on ownership as shown on Exhibit “A” remaining after excluding the voting interest of the Operator that was removed or resigned. The former Operator shall promptly deliver to the successor Operator all records and data relating to the operations conducted by the former Operator to the extent such records and data are not already in the possession of the successor operator. Any cost of obtaining or copying the former Operator’s records and data shall be charged to the joint account.

3.  Effect of Bankruptcy:  If Operator becomes insolvent, bankrupt or is placed in receivership, it shall be deemed to have resigned without any action by Non-Operators, except the selection of a successor. If a petition for relief under the federal bankruptcy laws is filed by or against Operator, and the removal of Operator is prevented by the federal bankruptcy court, all Non-Operators and Operator shall comprise an interim operating committee to serve until Operator has elected to reject or assume this agreement pursuant to the Bankruptcy Code, and an election to reject this agreement by Operator as a debtor in possession, or by a trustee in bankruptcy, shall be deemed a resignation as Operator without any action by Non-Operators, except the selection of a successor. During the period of time the operating committee controls operations, all actions shall require the approval of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit “A.” In the event there are only two (2) parties to this agreement, during the period of time the operating committee controls operations, a third party acceptable to Operator, Non-Operator and the federal bankruptcy court shall be selected as a member of the operating committee, and all actions shall require the approval of two (2) members of the operating committee without regard for their interest in the Contract Area based on Exhibit “A.”

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C.  Employees and Contractors:

The number of employees or contractors used by Operator in conducting operations hereunder, their selection, and the hours of labor and the compensation for services performed shall be determined by Operator, and all such employees or contractors shall be the employees or contractors of Operator.

D.  Rights and Duties of Operator:

1.  Competitive Rates and Use of Affiliates:  All wells drilled on the Contract Area shall be drilled on a competitive contract basis at the usual rates prevailing in the area. If it so desires, Operator may employ its own tools and equipment in the drilling of wells, but its charges therefor shall not exceed the prevailing rates in the area and the rate of such charges shall be agreed upon by the parties in writing before drilling operations are commenced, and such work shall be performed by Operator under the same terms and conditions as are customary and usual in the area in contracts of independent contractors who are doing work of a similar nature. All work performed or materials supplied by affiliates or related parties of Operator shall be performed or supplied at competitive rates, pursuant to written agreement, and in accordance with customs and standards prevailing in the industry.

2.  Discharge of Joint Account Obligations:  Except as herein otherwise specifically provided, Operator shall promptly pay and discharge expenses incurred in the development and operation of the Contract Area pursuant to this agreement and shall charge each of the parties hereto with their respective proportionate shares upon the expense basis provided in Exhibit “C.” Operator shall keep an accurate record of the joint account hereunder, showing expenses incurred and charges and credits made and received.

3.  Protection from Liens:  Operator shall pay, or cause to be paid, as and when they become due and payable, all accounts of contractors and suppliers and wages and salaries for services rendered or performed, and for materials supplied on, to or in respect of the Contract Area or any operations for the joint account thereof, and shall keep the Contract Area free from liens and encumbrances resulting therefrom except for those resulting from a bona fide dispute as to services rendered or materials supplied.

4.  Custody of Funds:  Operator shall hold for the account of the Non-Operators any funds of the Non-Operators advanced or paid to the Operator, either for the conduct of operations hereunder or as a result of the sale of production from the Contract Area, and such funds shall remain the funds of the Non-Operators on whose account they are advanced or paid until used for their intended purpose or otherwise delivered to the Non-Operators or applied toward the payment of debts as provided in Article VII.B. Nothing in this paragraph shall be construed to establish a fiduciary relationship between Operator and Non-Operators for any purpose other than to account for Non-Operator funds as herein specifically provided. Nothing in this paragraph shall require the maintenance by Operator of separate accounts for the funds of Non-Operators unless the parties otherwise specifically agree.

5.  Access to Contract Area and Records:  Operator shall, except as otherwise provided herein, permit each Non-Operator or its duly authorized representative, at the Non-Operator’s sole risk and cost, full and free access at all reasonable times to all operations of every kind and character being conducted for the joint account on the Contract Area and to the records of operations conducted thereon or production therefrom, including Operator’s books and records relating thereto. Such access rights shall not be exercised in a manner interfering with Operator’s conduct of an operation hereunder and shall not obligate Operator to furnish any geologic or geophysical data of an interpretive nature unless the cost of preparation of such interpretive data was charged to the joint account. Operator will furnish to each Non-Operator upon request copies of any and all reports and information obtained by Operator in connection with production and related items, including, without limitation, meter and chart reports, production purchaser statements, run tickets and monthly gauge reports, but excluding purchase contracts and pricing information to the extent not applicable to the production of the Non-Operator seeking the information. Any audit of Operator’s records relating to amounts expended and the appropriateness of such expenditures shall be conducted in accordance with the audit protocol specified in Exhibit “C.”

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6.  Filing and Furnishing Governmental Reports:  Operator will file, and upon written request promptly furnish copies to each requesting Non-Operator not in default of its payment obligations, all operational notices, reports or applications required to be filed by local, State, Federal or Indian agencies or authorities having jurisdiction over operations hereunder. Each Non-Operator shall provide to Operator on a timely basis all information necessary to Operator to make such filings.

7.  Drilling and Testing Operations:  The following provisions shall apply to each well drilled hereunder, including but not limited to the Initial Well:

(a)  Operator will promptly advise Non-Operators of the date on which the well is spudded, or the date on which drilling operations are commenced.

(b)  Operator will send to Non-Operators such reports, test results and notices regarding the progress of operations on the well as the Non-Operators shall reasonably request, including, but not limited to, daily drilling reports, completion reports, and well logs.

(c)  Operator shall adequately test all Zones encountered which may reasonably be expected to be capable of producing Oil and Gas in paying quantities as a result of examination of the electric log or any other logs or cores or tests conducted hereunder.

8.  Cost Estimates:  Upon request of any Consenting Party, Operator shall furnish estimates of current and cumulative costs incurred for the joint account at reasonable intervals during the conduct of any operation pursuant to this agreement. Operator shall not be held liable for errors in such estimates so long as the estimates are made in good faith.

9.  Insurance:  At all times while operations are conducted hereunder, Operator shall comply with the workers compensation law of the state where the operations are being conducted; provided, however, that Operator may be a self- insurer for liability under said compensation laws in which event the only charge that shall be made to the joint account shall be as provided in Exhibit “C.” Operator shall also carry or provide insurance for the benefit of the joint account of the parties as outlined in Exhibit “D” attached hereto and made a part hereof. Operator shall require all contractors engaged in work on or for the Contract Area to comply with the workers compensation law of the state where the operations are being conducted and to maintain such other insurance as Operator may require.

In the event automobile liability insurance is specified in said Exhibit “D,” or subsequently receives the approval of the parties, no direct charge shall be made by Operator for premiums paid for such insurance for Operator’s automotive equipment.

ARTICLE VI.
DRILLING AND DEVELOPMENT

A.  Initial Well:

On or before the ________ day of ________________________, __________, Operator shall commence the drilling of the Initial Well at the following location:

  
  
  
  

and shall thereafter continue the drilling of the well with due diligence to

  
  
  
  
  
  

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The drilling of the Initial Well and the participation therein by all parties is obligatory, subject to Article VI.C.1. as to participation in Completion operations and Article VI.F. as to termination of operations and Article XI as to occurrence of force majeure.

B.  Subsequent Operations:

1.  Proposed Operations:  If any party hereto should desire to drill any well on the Contract Area other than the Initial Well, or if any party should desire to Rework, Sidetrack, Deepen, Recomplete or Plug Back a dry hole or a well no longer capable of producing in paying quantities in which such party has not otherwise relinquished its interest in the proposed objective Zone under this agreement, the party desiring to drill, Rework, Sidetrack, Deepen, Recomplete or Plug Back such a well shall give written notice of the proposed operation to the parties who have not otherwise relinquished their interest in such objective Zone under this agreement and to all other parties in the case of a proposal for Sidetracking or Deepening, specifying the work to be performed, the location, proposed depth, objective Zone and the estimated cost of the operation. The parties to whom such a notice is delivered shall have thirty (30) days after receipt of the notice within which to notify the party proposing to do the work whether they elect to participate in the cost of the proposed operation. If a drilling rig is on location, notice of a proposal to Rework, Sidetrack, Recomplete, Plug Back or Deepen may be given by telephone and the response period shall be limited to forty-eight (48) hours, exclusive of Saturday, Sunday and legal holidays. Failure of a party to whom such notice is delivered to reply within the period above fixed shall constitute an election by that party not to participate in the cost of the proposed operation. Any proposal by a party to conduct an operation conflicting with the operation initially proposed shall be delivered to all parties within the time and in the manner provided in Article VI.B.6.

If all parties to whom such notice is delivered elect to participate in such a proposed operation, the parties shall be contractually committed to participate therein provided such operations are commenced within the time period hereafter set forth, and Operator shall, no later than ninety (90) days after expiration of the notice period of thirty (30) days (or as promptly as practicable after the expiration of the forty-eight (48) hour period when a drilling rig is on location, as the case may be), actually commence the proposed operation and thereafter complete it with due diligence at the risk and expense of the parties participating therein; provided, however, said commencement date may be extended upon written notice of same by Operator to the other parties, for a period of up to thirty (30) additional days if, in the sole opinion of Operator, such additional time is reasonably necessary to obtain permits from governmental authorities, surface rights (including rights-of-way) or appropriate drilling equipment, or to complete title examination or curative matter required for title approval or acceptance. If the actual operation has not been commenced within the time provided (including any extension thereof as specifically permitted herein or in the force majeure provisions of Article XI) and if any party hereto still desires to conduct said operation, written notice proposing same must be resubmitted to the other parties in accordance herewith as if no prior proposal had been made. Those parties that did not participate in the drilling of a well for which a proposal to Deepen or Sidetrack is made hereunder shall, if such parties desire to participate in the proposed Deepening or Sidetracking operation, reimburse the Drilling Parties in accordance with Article VI.B.4. in the event of a Deepening operation and in accordance with Article VI.B.5. in the event of a Sidetracking operation.

2.  Operations by Less Than All Parties:

(a)  Determination of Participation.  If any party to whom such notice is delivered as provided in Article VI.B.1. or VI.C.1. (Option No. 2) elects not to participate in the proposed operation, then, in order to be entitled to the benefits of this Article, the party or parties giving the notice and such other parties as shall elect to participate in the operation shall, no later than ninety (90) days after the expiration of the notice period of thirty (30) days (or as promptly as practicable after the expiration of the forty-eight (48) hour period when a drilling rig is on location, as the case may be) actually commence the proposed operation and complete it with due diligence. Operator shall perform all work for the account of the Consenting Parties; provided, however, if no drilling rig or other equipment is on location, and if Operator is a Non-Consenting Party, the Consenting Parties shall either: (i) request Operator to perform the work required by such proposed operation for the account of the Consenting

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Parties, or (ii) designate one of the Consenting Parties as Operator to perform such work. The rights and duties granted to and imposed upon the Operator under this agreement are granted to and imposed upon the party designated as Operator for an operation in which the original Operator is a Non-Consenting Party. Consenting Parties, when conducting operations on the Contract Area pursuant to this Article VI.B.2., shall comply with all terms and conditions of this agreement.

If less than all parties approve any proposed operation, the proposing party, immediately after the expiration of the applicable notice period, shall advise all Parties of the total interest of the parties approving such operation and its recommendation as to whether the Consenting Parties should proceed with the operation as proposed. Each Consenting Party, within forty-eight (48) hours (exclusive of Saturday, Sunday, and legal holidays) after delivery of such notice, shall advise the proposing party of its desire to (i) limit participation to such party’s interest as shown on Exhibit “A” or (ii) carry only its proportionate part (determined by dividing such party’s interest in the Contract Area by the interests of all Consenting Parties in the Contract Area) of Non-Consenting Parties’ interests, or (iii) carry its proportionate part (determined as provided in (ii)) of Non-Consenting Parties’ interests together with all or a portion of its proportionate part of any Non-Consenting Parties’ interests that any Consenting Party did not elect to take. Any interest of Non-Consenting Parties that is not carried by a Consenting Party shall be deemed to be carried by the party proposing the operation if such party does not withdraw its proposal. Failure to advise the proposing party within the time required shall be deemed an election under (i). In the event a drilling rig is on location, notice may be given by telephone, and the time permitted for such a response shall not exceed a total of forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays). The proposing party, at its election, may withdraw such proposal if there is less than 100% participation and shall notify all parties of such decision within ten (10) days, or within twenty-four (24) hours if a drilling rig is on location, following expiration of the applicable response period. If 100% subscription to the proposed operation is obtained, the proposing party shall promptly notify the Consenting Parties of their proportionate interests in the operation and the party serving as Operator shall commence such operation within the period provided in Article VI.B.1., subject to the same extension right as provided therein.

(b)  Relinquishment of Interest for Non-Participation.  The entire cost and risk of conducting such operations shall be borne by the Consenting Parties in the proportions they have elected to bear same under the terms of the preceding paragraph. Consenting Parties shall keep the leasehold estates involved in such operations free and clear of all liens and encumbrances of every kind created by or arising from the operations of the Consenting Parties. If such an operation results in a dry hole, then subject to Articles VI.B.6. and VI.E.3., the Consenting Parties shall plug and abandon the well and restore the surface location at their sole cost, risk and expense; provided, however, that those Non-Consenting Parties that participated in the drilling, Deepening or Sidetracking of the well shall remain liable for, and shall pay, their proportionate shares of the cost of plugging and abandoning the well and restoring the surface location insofar only as those costs were not increased by the subsequent operations of the Consenting Parties. If any well drilled, Reworked, Sidetracked, Deepened, Recompleted or Plugged Back under the provisions of this Article results in a well capable of producing Oil and/or Gas in paying quantities, the Consenting Parties shall Complete and equip the well to produce at their sole cost and risk, and the well shall then be turned over to Operator (if the Operator did not conduct the operation) and shall be operated by it at the expense and for the account of the Consenting Parties. Upon commencement of operations for the drilling, Reworking, Sidetracking, Recompleting, Deepening or Plugging Back of any such well by Consenting Parties in accordance with the provisions of this Article, each Non-Consenting Party shall be deemed to have relinquished to Consenting Parties, and the Consenting Parties shall own and be entitled to receive, in proportion to their respective interests, all of such Non-Consenting Party’s interest in the well and share of production therefrom or, in the case of a Reworking, Sidetracking, Deepening, Recompleting or Plugging Back, or a Completion pursuant to Article VI.C.1. Option No. 2, all of such Non-Consenting Party’s interest in the production obtained from the operation in which the Non-Consenting Party did not elect to participate. Such relinquishment shall be effective until the proceeds of the sale of such share, calculated at the well, or market value thereof if

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such share is not sold (after deducting applicable ad valorem, production, severance, and excise taxes, royalty, overriding royalty and other interests not excepted by Article III.C. payable out of or measured by the production from such well accruing with respect to such interest until it reverts), shall equal the total of the following:

(i)  _____________% of each such Non-Consenting Party’s share of the cost of any newly acquired surface equipment beyond the wellhead connections (including but not limited to stock tanks, separators, treaters, pumping equipment and piping), plus 100% of each such Non-Consenting Party’s share of the cost of operation of the well commencing with first production and continuing until each such Non-Consenting Party’s relinquished interest shall revert to it under other provisions of this Article, it being agreed that each Non-Consenting Party’s share of such costs and equipment will be that interest which would have been chargeable to such Non-Consenting Party had it participated in the well from the beginning of the operations; and

(ii)  ____________% of (a) that portion of the costs and expenses of drilling, Reworking, Sidetracking, Deepening, Plugging Back, testing, Completing, and Recompleting, after deducting any cash contributions received under Article VIII.C., and of (b) that portion of the cost of newly acquired equipment in the well (to and including the wellhead connections), which would have been chargeable to such Non-Consenting Party if it had participated therein.

Notwithstanding anything to the contrary in this Article VI.B., if the well does not reach the deepest objective Zone described in the notice proposing the well for reasons other than the encountering of granite or practically impenetrable substance or other condition in the hole rendering further operations impracticable, Operator shall give notice thereof to each Non-Consenting Party who submitted or voted for an alternative proposal under Article VI.B.6. to drill the well to a shallower Zone than the deepest objective Zone proposed in the notice under which the well was drilled, and each such Non-Consenting Party shall have the option to participate in the initial proposed Completion of the well by paying its share of the cost of drilling the well to its actual depth, calculated in the manner provided in Article VI.B.4. (a). If any such Non-Consenting Party does not elect to participate in the first Completion proposed for such well, the relinquishment provisions of this Article VI.B.2. (b) shall apply to such party’s interest.

(c)  Reworking, Recompleting or Plugging Back.  An election not to participate in the drilling, Sidetracking or Deepening of a well shall be deemed an election not to participate in any Reworking or Plugging Back operation proposed in such a well, or portion thereof, to which the initial non-consent election applied that is conducted at any time prior to full recovery by the Consenting Parties of the Non-Consenting Party’s recoupment amount. Similarly, an election not to participate in the Completing or Recompleting of a well shall be deemed an election not to participate in any Reworking operation proposed in such a well, or portion thereof, to which the initial non-consent election applied that is conducted at any time prior to full recovery by the Consenting Parties of the Non-Consenting Party’s recoupment amount. Any such Reworking, Recompleting or Plugging Back operation conducted during the recoupment period shall be deemed part of the cost of operation of said well and there shall be added to the sums to be recouped by the Consenting Parties _______% of that portion of the costs of the Reworking, Recompleting or Plugging Back operation which would have been chargeable to such Non-Consenting Party had it participated therein. If such a Reworking, Recompleting or Plugging Back operation is proposed during such recoupment period, the provisions of this Article VI.B. shall be applicable as between said Consenting Parties in said well.

(d)  Recoupment Matters.  During the period of time Consenting Parties are entitled to receive Non-Consenting Party’s share of production, or the proceeds therefrom, Consenting Parties shall be responsible for the payment of all ad valorem, production, severance, excise, gathering and other taxes, and all royalty, overriding royalty and other burdens applicable to Non-Consenting Party’s share of production not excepted by Article III.C.

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In the case of any Reworking, Sidetracking, Plugging Back, Recompleting or Deepening operation, the Consenting Parties shall be permitted to use, free of cost, all casing, tubing and other equipment in the well, but the ownership of all such equipment shall remain unchanged; and upon abandonment of a well after such Reworking, Sidetracking, Plugging Back, Recompleting or Deepening, the Consenting Parties shall account for all such equipment to the owners thereof, with each party receiving its proportionate part in kind or in value, less cost of salvage.

Within ninety (90) days after the completion of any operation under this Article, the party conducting the operations for the Consenting Parties shall furnish each Non-Consenting Party with an inventory of the equipment in and connected to the well, and an itemized statement of the cost of drilling, Sidetracking, Deepening, Plugging Back, testing, Completing, Recompleting, and equipping the well for production; or, at its option, the operating party, in lieu of an itemized statement of such costs of operation, may submit a detailed statement of monthly billings. Each month thereafter, during the time the Consenting Parties are being reimbursed as provided above, the party conducting the operations for the Consenting Parties shall furnish the Non-Consenting Parties with an itemized statement of all costs and liabilities incurred in the operation of the well, together with a statement of the quantity of Oil and Gas produced from it and the amount of proceeds realized from the sale of the well’s working interest production during the preceding month. In determining the quantity of Oil and Gas produced during any month, Consenting Parties shall use industry accepted methods such as but not limited to metering or periodic well tests. Any amount realized from the sale or other disposition of equipment newly acquired in connection with any such operation which would have been owned by a Non-Consenting Party had it participated therein shall be credited against the total unreturned costs of the work done and of the equipment purchased in determining when the interest of such Non-Consenting Party shall revert to it as above provided; and if there is a credit balance, it shall be paid to such Non-Consenting Party.

If and when the Consenting Parties recover from a Non-Consenting Party’s relinquished interest the amounts provided for above, the relinquished interests of such Non-Consenting Party shall automatically revert to it as of 7:00 a.m. on the day following the day on which such recoupment occurs, and, from and after such reversion, such Non-Consenting Party shall own the same interest in such well, the material and equipment in or pertaining thereto, and the production therefrom as such Non-Consenting Party would have been entitled to had it participated in the drilling, Sidetracking, Reworking, Deepening, Recompleting or Plugging Back of said well. Thereafter, such Non-Consenting Party shall be charged with and shall pay its proportionate part of the further costs of the operation of said well in accordance with the terms of this agreement and Exhibit “C” attached hereto.

3.  Stand-By Costs:  When a well which has been drilled or Deepened has reached its authorized depth and all tests have been completed and the results thereof furnished to the parties, or when operations on the well have been otherwise terminated pursuant to Article VI.F., stand-by costs incurred pending response to a party’s notice proposing a Reworking, Sidetracking, Deepening, Recompleting, Plugging Back or Completing operation in such a well (including the period required under Article VI.B.6. to resolve competing proposals) shall be charged and borne as part of the drilling or Deepening operation just completed. Stand-by costs subsequent to all parties responding, or expiration of the response time permitted, whichever first occurs, and prior to agreement as to the participating interests of all Consenting Parties pursuant to the terms of the second grammatical paragraph of Article VI.B.2. (a), shall be charged to and borne as part of the proposed operation, but if the proposal is subsequently withdrawn because of insufficient participation, such stand-by costs shall be allocated between the Consenting Parties in the proportion each Consenting Party’s interest as shown on Exhibit “A” bears to the total interest as shown on Exhibit “A” of all Consenting Parties.

In the event that notice for a Sidetracking operation is given while the drilling rig to be utilized is on location, any party may request and receive up to five (5) additional days after expiration of the forty-eight hour response period specified in Article VI.B.1. within which to respond by paying for all stand-by costs and other costs incurred during such extended response period; Operator may require such party to pay the estimated stand-by time in advance as a condition to extending the response period. If more than one party elects to take such additional time to respond to the notice, standby costs shall be allocated between the

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parties taking additional time to respond on a day-to-day basis in the proportion each electing party’s interest as shown on Exhibit “A” bears to the total interest as shown on Exhibit “A” of all the electing parties.

4.  Deepening:  If less than all parties elect to participate in a drilling, Sidetracking, or Deepening operation proposed pursuant to Article VI.B.1., the interest relinquished by the Non-Consenting Parties to the Consenting Parties under Article VI.B.2. shall relate only and be limited to the lesser of (i) the total depth actually drilled or (ii) the objective depth or Zone of which the parties were given notice under Article VI.B.1. (“Initial Objective”). Such well shall not be Deepened beyond the Initial Objective without first complying with this Article to afford the Non-Consenting Parties the opportunity to participate in the Deepening operation.

In the event any Consenting Party desires to drill or Deepen a Non-Consent Well to a depth below the Initial Objective, such party shall give notice thereof, complying with the requirements of Article VI.B.1., to all parties (including Non-Consenting Parties). Thereupon, Articles VI.B.1. and 2. shall apply and all parties receiving such notice shall have the right to participate or not participate in the Deepening of such well pursuant to said Articles VI.B.1. and 2. If a Deepening operation is approved pursuant to such provisions, and if any Non-Consenting Party elects to participate in the Deepening operation, such Non-Consenting party shall pay or make reimbursement (as the case may be) of the following costs and expenses.

(a)  If the proposal to Deepen is made prior to the Completion of such well as a well capable of producing in paying quantities, such Non-Consenting Party shall pay (or reimburse Consenting Parties for, as the case may be) that share of costs and expenses incurred in connection with the drilling of said well from the surface to the Initial Objective which Non-Consenting Party would have paid had such Non-Consenting Party agreed to participate therein, plus the Non-Consenting Party’s share of the cost of Deepening and of participating in any further operations on the well in accordance with the other provisions of this Agreement; provided, however, all costs for testing and Completion or attempted Completion of the well incurred by Consenting Parties prior to the point of actual operations to Deepen beyond the Initial Objective shall be for the sole account of Consenting Parties.

(b)  If the proposal is made for a Non-Consent Well that has been previously Completed as a well capable of producing in paying quantities, but is no longer capable of producing in paying quantities, such Non-Consenting Party shall pay (or reimburse Consenting Parties for, as the case may be) its proportionate share of all costs of drilling, Completing, and equipping said well from the surface to the Initial Objective, calculated in the manner provided in paragraph (a) above, less those costs recouped by the Consenting Parties from the sale of production from the well. The Non-Consenting Party shall also pay its proportionate share of all costs of re-entering said well. The Non-Consenting Parties’ proportionate part (based on the percentage of such well Non-Consenting Party would have owned had it previously participated in such Non-Consent Well) of the costs of salvable materials and equipment remaining in the hole and salvable surface equipment used in connection with such well shall be determined in accordance with Exhibit “C.” If the Consenting Parties have recouped the cost of drilling, Completing, and equipping the well at the time such Deepening operation is conducted, then a Non-Consenting Party may participate in the Deepening of the well with no payment for costs incurred prior to re-entering the well for Deepening

The foregoing shall not imply a right of any Consenting Party to propose any Deepening for a Non-Consent Well prior to the drilling of such well to its Initial Objective without the consent of the other Consenting Parties as provided in Article VI.F.

5.  Sidetracking:  Any party having the right to participate in a proposed Sidetracking operation that does not own an interest in the affected wellbore at the time of the notice shall, upon electing to participate, tender to the wellbore owners its proportionate share (equal to its interest in the Sidetracking operation) of the value of that portion of the existing wellbore to be utilized as follows:

(a)  If the proposal is for Sidetracking an existing dry hole, reimbursement shall be on the basis of the actual costs incurred in the initial drilling of the well down to the depth at which the Sidetracking operation is initiated.

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(b)  If the proposal is for Sidetracking a well which has previously produced, reimbursement shall be on the basis of such party’s proportionate share of drilling and equipping costs incurred in the initial drilling of the well down to the depth at which the Sidetracking operation is conducted, calculated in the manner described in Article VI.B.4(b) above. Such party’s proportionate share of the cost of the well’s salvable materials and equipment down to the depth at which the Sidetracking operation is initiated shall be determined in accordance with the provisions of Exhibit “C.”

6.  Order of Preference of Operations.  Except as otherwise specifically provided in this agreement, if any party desires to propose the conduct of an operation that conflicts with a proposal that has been made by a party under this Article VI, such party shall have fifteen (15) days from delivery of the initial proposal, in the case of a proposal to drill a well or to perform an operation on a well where no drilling rig is on location, or twenty-four (24) hours, exclusive of Saturday, Sunday and legal holidays, from delivery of the initial proposal, if a drilling rig is on location for the well on which such operation is to be conducted, to deliver to all parties entitled to participate in the proposed operation such party’s alternative proposal, such alternate proposal to contain the same information required to be included in the initial proposal. Each party receiving such proposals shall elect by delivery of notice to Operator within five (5) days after expiration of the proposal period, or within twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays) if a drilling rig is on location for the well that is the subject of the proposals, to participate in one of the competing proposals. Any party not electing within the time required shall be deemed not to have voted. The proposal receiving the vote of parties owning the largest aggregate percentage interest of the parties voting shall have priority over all other competing proposals; in the case of a tie vote, the initial proposal shall prevail. Operator shall deliver notice of such result to all parties entitled to participate in the operation within five (5) days after expiration of the election period (or within twenty-four (24) hours, exclusive of Saturday, Sunday and legal holidays, if a drilling rig is on location). Each party shall then have two (2) days (or twenty-four (24) hours if a rig is on location) from receipt of such notice to elect by delivery of notice to Operator to participate in such operation or to relinquish interest in the affected well pursuant to the provisions of Article VI.B.2.; failure by a party to deliver notice within such period shall be deemed an election not to participate in the prevailing proposal.

7.  Conformity to Spacing Pattern.  Notwithstanding the provisions of this Article VI.B.2., it is agreed that no wells shall be proposed to be drilled to or Completed in or produced from a Zone from which a well located elsewhere on the Contract Area is producing, unless such well conforms to the then-existing well spacing pattern for such Zone.

8.  Paying Wells.  No party shall conduct any Reworking, Deepening, Plugging Back, Completion, Recompletion, or Sidetracking operation under this agreement with respect to any well then capable of producing in paying quantities except with the consent of all parties that have not relinquished interests in the well at the time of such operation.

C.  Completion of Wells; Reworking and Plugging Back:

1.  Completion:  Without the consent of all parties, no well shall be drilled, Deepened or Sidetracked, except any well drilled, Deepened or Sidetracked pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the drilling, Deepening or Sidetracking shall include:

o Option No. 1:  All necessary expenditures for the drilling, Deepening or Sidetracking, testing, Completing and equipping of the well, including necessary tankage and/or surface facilities.
o Option No. 2:  All necessary expenditures for the drilling, Deepening or Sidetracking and testing of the well. When such well has reached its authorized depth, and all logs, cores and other tests have been completed, and the results thereof furnished to the parties, Operator shall give immediate notice to the Non-Operators having the right to participate in a Completion attempt whether or not Operator recommends attempting to Complete the well, together with Operator’s AFE for Completion costs if not previously provided. The parties receiving such notice shall have forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) in which to elect by delivery of notice to Operator to participate in a recommended Completion attempt or to make a

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Completion proposal with an accompanying AFE. Operator shall deliver any such Completion proposal, or any Completion proposal conflicting with Operator’s proposal, to the other parties entitled to participate in such Completion in accordance with the procedures specified in Article VI.B.6. Election to participate in a Completion attempt shall include consent to all necessary expenditures for the Completing and equipping of such well, including necessary tankage and/or surface facilities but excluding any stimulation operation not contained on the Completion AFE. Failure of any party receiving such notice to reply within the period above fixed shall constitute an election by that party not to participate in the cost of the Completion attempt; provided, that Article VI.B.6. shall control in the case of conflicting Completion proposals. If one or more, but less than all of the parties, elect to attempt a Completion, the provision of Article VI.B.2. hereof (the phrase “Reworking, Sidetracking, Deepening, Recompleting or Plugging Back” as contained in Article VI.B.2. shall be deemed to include “Completing”) shall apply to the operations thereafter conducted by less than all parties; provided, however, that Article VI.B.2. shall apply separately to each separate Completion or Recompletion attempt undertaken hereunder, and an election to become a Non-Consenting Party as to one Completion or Recompletion attempt shall not prevent a party from becoming a Consenting Party in subsequent Completion or Recompletion attempts regardless whether the Consenting Parties as to earlier Completions or Recompletion have recouped their costs pursuant to Article VI.B.2.; provided further, that any recoupment of costs by a Consenting Party shall be made solely from the production attributable to the Zone in which the Completion attempt is made. Election by a previous Non-Consenting party to participate in a subsequent Completion or Recompletion attempt shall require such party to pay its proportionate share of the cost of salvable materials and equipment installed in the well pursuant to the previous Completion or Recompletion attempt, insofar and only insofar as such materials and equipment benefit the Zone in which such party participates in a Completion attempt.

2.  Rework, Recomplete or Plug Back:  No well shall be Reworked, Recompleted or Plugged Back except a well Reworked, Recompleted, or Plugged Back pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the Reworking, Recompleting or Plugging Back of a well shall include all necessary expenditures in conducting such operations and Completing and equipping of said well, including necessary tankage and/or surface facilities.

D.  Other Operations:

Operator shall not undertake any single project reasonably estimated to require an expenditure in excess of ____________________________________________________________________________________ Dollars ($____________) except in connection with the drilling, Sidetracking, Reworking, Deepening, Completing, Recompleting or Plugging Back of a well that has been previously authorized by or pursuant to this agreement; provided, however, that, in case of explosion, fire, flood or other sudden emergency, whether of the same or different nature, Operator may take such steps and incur such expenses as in its opinion are required to deal with the emergency to safeguard life and property but Operator, as promptly as possible, shall report the emergency to the other parties. If Operator prepares an AFE for its own use, Operator shall furnish any Non-Operator so requesting an information copy thereof for any single project costing in excess of _________________________________________________ Dollars ($____________________________). Any party who has not relinquished its interest in a well shall have the right to propose that Operator perform repair work or undertake the installation of artificial lift equipment or ancillary production facilities such as salt water disposal wells or to conduct additional work with respect to a well drilled hereunder or other similar project (but not including the installation of gathering lines or other transportation or marketing facilities, the installation of which shall be governed by separate agreement between the parties) reasonably estimated to require an expenditure in excess of the amount first set forth above in this Article VI.D. (except in connection with an operation required to be proposed under Articles VI.B.1. or VI.C.1. Option No. 2, which shall be governed exclusively be those Articles). Operator shall deliver such proposal to all parties entitled to participate therein. If within thirty (30) days thereof Operator secures the written consent of any party or parties owning at least ________________% of the interests of the parties entitled to participate in such operation, each party having the right to participate in such project shall be bound by the terms of such

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proposal and shall be obligated to pay its proportionate share of the costs of the proposed project as if it had consented to such project pursuant to the terms of the proposal.

E.  Abandonment of Wells:

1.  Abandonment of Dry Holes:  Except for any well drilled or Deepened pursuant to Article VI.B.2., any well which has been drilled or Deepened under the terms of this agreement and is proposed to be completed as a dry hole shall not be plugged and abandoned without the consent of all parties. Should Operator, after diligent effort, be unable to contact any party, or should any party fail to reply within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after delivery of notice of the proposal to plug and abandon such well, such party shall be deemed to have consented to the proposed abandonment. All such wells shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of the parties who participated in the cost of drilling or Deepening such well. Any party who objects to plugging and abandoning such well by notice delivered to Operator within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after delivery of notice of the proposed plugging shall take over the well as of the end of such forty-eight (48) hour notice period and conduct further operations in search of Oil and/or Gas subject to the provisions of Article VI.B.; failure of such party to provide proof reasonably satisfactory to Operator of its financial capability to conduct such operations or to take over the well within such period or thereafter to conduct operations on such well or plug and abandon such well shall entitle Operator to retain or take possession of the well and plug and abandon the well. The party taking over the well shall indemnify Operator (if Operator is an abandoning party) and the other abandoning parties against liability for any further operations conducted on such well except for the costs of plugging and abandoning the well and restoring the surface, for which the abandoning parties shall remain proportionately liable.

2.  Abandonment of Wells That Have Produced:  Except for any well in which a Non-Consent operation has been conducted hereunder for which the Consenting Parties have not been fully reimbursed as herein provided, any well which has been completed as a producer shall not be plugged and abandoned without the consent of all parties. If all parties consent to such abandonment, the well shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of all the parties hereto. Failure of a party to reply within sixty (60) days of delivery of notice of proposed abandonment shall be deemed an election to consent to the proposal. If, within sixty (60) days after delivery of notice of the proposed abandonment of any well, all parties do not agree to the abandonment of such well, those wishing to continue its operation from the Zone then open to production shall be obligated to take over the well as of the expiration of the applicable notice period and shall indemnify Operator (if Operator is an abandoning party) and the other abandoning parties against liability for any further operations on the well conducted by such parties. Failure of such party or parties to provide proof reasonably satisfactory to Operator of their financial capability to conduct such operations or to take over the well within the required period or thereafter to conduct operations on such well shall entitle operator to retain or take possession of such well and plug and abandon the well.

Parties taking over a well as provided herein shall tender to each of the other parties its proportionate share of the value of the well’s salvable material and equipment, determined in accordance with the provisions of Exhibit “C,” less the estimated cost of salvaging and the estimated cost of plugging and abandoning and restoring the surface; provided, however, that in the event the estimated plugging and abandoning and surface restoration costs and the estimated cost of salvaging are higher than the value of the well’s salvable material and equipment, each of the abandoning parties shall tender to the parties continuing operations their proportionate shares of the estimated excess cost. Each abandoning party shall assign to the non-abandoning parties, without warranty, express or implied, as to title or as to quantity, or fitness for use of the equipment and material, all of its interest in the wellbore of the well and related equipment, together with its interest in the Leasehold insofar and only insofar as such Leasehold covers the right to obtain production from that wellbore in the Zone then open to production. If the interest of the abandoning party is or includes and Oil and Gas Interest, such party shall execute and deliver to the non-abandoning party or parties an oil and gas lease, limited to the wellbore and the Zone then open to production, for a term of one (1) year and so long thereafter as Oil and/or Gas is produced from the Zone covered thereby, such lease to be on the form attached

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as Exhibit “B.” The assignments or leases so limited shall encompass the Drilling Unit upon which the well is located. The payments by, and the assignments or leases to, the assignees shall be in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all assignees. There shall be no readjustment of interests in the remaining portions of the Contract Area.

Thereafter, abandoning parties shall have no further responsibility, liability, or interest in the operation of or production from the well in the Zone then open other than the royalties retained in any lease made under the terms of this Article. Upon request, Operator shall continue to operate the assigned well for the account of the non-abandoning parties at the rates and charges contemplated by this agreement, plus any additional cost and charges which may arise as the result of the separate ownership of the assigned well. Upon proposed abandonment of the producing Zone assigned or leased, the assignor or lessor shall then have the option to repurchase its prior interest in the well (using the same valuation formula) and participate in further operations therein subject to the provisions hereof.

3.  Abandonment of Non-Consent Operations:  The provisions of Article VI.E.1. or VI.E.2. above shall be applicable as between Consenting Parties in the event of the proposed abandonment of any well excepted from said Articles; provided, however, no well shall be permanently plugged and abandoned unless and until all parties having the right to conduct further operations therein have been notified of the proposed abandonment and afforded the opportunity to elect to take over the well in accordance with the provisions of this Article VI.E.; and provided further, that Non-Consenting Parties who own an interest in a portion of the well shall pay their proportionate shares of abandonment and surface restoration cost for such well as provided in Article VI.B.2.(b).

F.  Termination of Operations:

Upon the commencement of an operation for the drilling, Reworking, Sidetracking, Plugging Back, Deepening, testing, Completion or plugging of a well, including but not limited to the Initial Well, such operation shall not be terminated without consent of parties bearing _____% of the costs of such operation; provided, however, that in the event granite or other practically impenetrable substance or condition in the hole is encountered which renders further operations impractical, Operator may discontinue operations and give notice of such condition in the manner provided in Article VI.B.1, and the provisions of Article VI.B. or VI.E. shall thereafter apply to such operation, as appropriate.

G.  Taking Production in Kind:

o Option No. 1:  Gas Balancing Agreement Attached

Each party shall take in kind or separately dispose of its proportionate share of all Oil and Gas produced from the Contract Area, exclusive of production which may be used in development and producing operations and in preparing and treating Oil and Gas for marketing purposes and production unavoidably lost. Any extra expenditure incurred in the taking in kind or separate disposition by any party of its proportionate share of the production shall be borne by such party. Any party taking its share of production in kind shall be required to pay for only its proportionate share of such part of Operator’s surface facilities which it uses.

Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in production from the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment directly from the purchaser thereof for its share of all production.

If any party fails to make the arrangements necessary to take in kind or separately dispose of its proportionate share of the Oil produced from the Contract Area, Operator shall have the right, subject to the revocation at will by the party owning it, but not the obligation, to purchase such Oil or sell it to others at any time and from time to time, for the account of the non-taking party. Any such purchase or sale by Operator may be terminated by Operator upon at least ten (10) days written notice to the owner of said production and shall be subject always to the right of the owner of the production upon at least ten (10) days written notice to Operator to exercise at any time its right to

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take in kind, or separately dispose of, its share of all Oil not previously delivered to a purchaser. Any purchase or sale by Operator of any other party’s share of Oil shall be only for such reasonable periods of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (1) year.

Any such sale by Operator shall be in a manner commercially reasonable under the circumstances but Operator shall have no duty to share any existing market or to obtain a price equal to that received under any existing market. The sale or delivery by Operator of a non-taking party’s share of Oil under the terms of any existing contract of Operator shall not give the non-taking party any interest in or make the non-taking party a party to said contract. No purchase shall be made by Operator without first giving the non-taking party at least ten (10) days written notice of such intended purchase and the price to be paid or the pricing basis to be used.

All parties shall give timely written notice to Operator of their Gas marketing arrangements for the following month, excluding price, and shall notify Operator immediately in the event of a change in such arrangements. Operator shall maintain records of all marketing arrangements, and of volumes actually sold or transported, which records shall be made available to Non-Operators upon reasonable request.

In the event one or more parties’ separate disposition of its share of the Gas causes split-stream deliveries to separate pipelines and/or deliveries which on a day-to-day basis for any reason are not exactly equal to a party’s respective proportionate share of total Gas sales to be allocated to it, the balancing or accounting between the parties shall be in accordance with any Gas balancing agreement between the parties hereto, whether such an agreement is attached as Exhibit “E” or is a separate agreement. Operator shall give notice to all parties of the first sales of Gas from any well under this agreement.

o Option No. 2:  No Gas Balancing Agreement:

Each party shall take in kind or separately dispose of its proportionate share of all Oil and Gas produced from the Contract Area, exclusive of production which may be used in development and producing operations and in preparing and treating Oil and Gas for marketing purposes and production unavoidably lost. Any extra expenditures incurred in the taking in kind or separate disposition by any party of its proportionate share of the production shall be borne by such party. Any party taking its share of production in kind shall be required to pay for only its proportionate share of such part of Operator’s surface facilities which it uses.

Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in production from the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment directly from the purchaser thereof for its share of all production.

If any party fails to make the arrangements necessary to take in kind or separately dispose of its proportionate share of the Oil and/or Gas produced from the Contract Area, Operator shall have the right, subject to the revocation at will by the party owning it, but not the obligation, to purchase such Oil and/or Gas or sell it to others at any time and from time to time, for the account of the non-taking party. Any such purchase or sale by Operator may be terminated by Operator upon at least ten (10) days written notice to the owner of said production and shall be subject always to the right of the owner of the production upon at least ten (10) days written notice to Operator to exercise its right to take in kind, or separately dispose of, its share of all Oil and/or Gas not previously delivered to a purchaser; provided, however, that the effective date of any such revocation may be deferred at Operator’s election for a period not to exceed ninety (90) days if Operator has committed such production to a purchase contract having a term extending beyond such ten (10)-day period. Any purchase or sale by Operator of any other party’s share of Oil and/or Gas shall be only for such reasonable periods of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (1) year.

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Any such sale by Operator shall be in a manner commercially reasonable under the circumstances, but Operator shall have no duty to share any existing market or transportation arrangement or to obtain a price or transportation fee equal to that received under any existing market or transportation arrangement. The sale or delivery by Operator of a non-taking party’s share of production under the terms of any existing contract of Operator shall not give the non-taking party any interest in or make the non-taking party a party to said contract. No purchase of Oil and Gas and no sale of Gas shall be made by Operator without first giving the non-taking party ten days written notice of such intended purchase or sale and the price to be paid or the pricing basis to be used. Operator shall give notice to all parties of the first sale of Gas from any well under this Agreement.

All parties shall give timely written notice to Operator of their Gas marketing arrangements for the following month, excluding price, and shall notify Operator immediately in the event of a change in such arrangements. Operator shall maintain records of all marketing arrangements, and of volumes actually sold or transported, which records shall be made available to Non-Operators upon reasonable request.

ARTICLE VII.
EXPENDITURES AND LIABILITY OF PARTIES

A.  Liability of Parties:

The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs of developing and operating the Contract Area. Accordingly, the liens granted among the parties in Article VII.B. are given to secure only the debts of each severally, and no party shall have any liability to third parties hereunder to satisfy the default of any other party in the payment of any expense or obligation hereunder. It is not the intention of the parties to create, nor shall this agreement be construed as creating, a mining or other partnership, joint venture, agency relationship or association, or to render the parties liable as partners, co-venturers, or principals. In their relations with each other under this agreement, the parties shall not be considered fiduciaries or to have established a confidential relationship but rather shall be free to act on an arm’s-length basis in accordance with their own respective self-interest, subject, however, to the obligation of the parties to act in good faith in their dealings with each other with respect to activities hereunder.

B.  Liens and Security Interests:

Each party grants to the other parties hereto a lien upon any interest it now owns or hereafter acquires in Oil and Gas Leases and Oil and Gas Interests in the Contract Area, and a security interest and/or purchase money security interest in any interest it now owns or hereafter acquires in the personal property and fixtures on or used or obtained for use in connection therewith, to secure performance of all of its obligations under this agreement including but not limited to payment of expense, interest and fees, the proper disbursement of all monies paid hereunder, the assignment or relinquishment of interest in Oil and Gas Leases as required hereunder, and the proper performance of operations hereunder. Such lien and security interest granted by each party hereto shall include such party’s leasehold interests, working interests, operating rights, and royalty and overriding royalty interests in the Contract Area now owned or hereafter acquired and in lands pooled or unitized therewith or otherwise becoming subject to this agreement, the Oil and Gas when extracted therefrom and equipment situated thereon or used or obtained for use in connection therewith (including, without limitation, all wells, tools, and tubular goods), and accounts (including, without limitation, accounts arising from gas imbalances or from the sale of Oil and/or Gas at the wellhead), contract rights, inventory and general intangibles relating thereto or arising therefrom, and all proceeds and products of the foregoing.

To perfect the lien and security agreement provided herein, each party hereto shall execute and acknowledge the recording supplement and/or any financing statement prepared and submitted by any party hereto in conjunction herewith or at any time following execution hereof, and Operator is authorized to file this agreement or the recording supplement executed herewith as a lien or mortgage in the applicable real estate records and as a financing statement with the proper officer under the Uniform Commercial Code in the

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state in which the Contract Area is situated and such other states as Operator shall deem appropriate to perfect the security interest granted hereunder. Any party may file this agreement, the recording supplement executed herewith, or such other documents as it deems necessary as a lien or mortgage in the applicable real estate records and/or a financing statement with the proper officer under the Uniform Commercial Code.

Each party represents and warrants to the other parties hereto that the lien and security interest granted by such party to the other parties shall be a first and prior lien, and each party hereby agrees to maintain the priority of said lien and security interest against all persons acquiring an interest in Oil and Gas Leases and Interests covered by this agreement by, through or under such party. All parties acquiring an interest in Oil and Gas Leases and Oil and Gas Interests covered by this agreement, whether by assignment, merger, mortgage, operation of law, or otherwise, shall be deemed to have taken subject to the lien and security interest granted by this Article VII.B. as to all obligations attributable to such interest hereunder whether or not such obligations arise before or after such interest is acquired.

To the extent that parties have a security interest under the Uniform Commercial Code of the state in which the Contract Area is situated, they shall be entitled to exercise the rights and remedies of a secured party under the Code. The bringing of a suit and the obtaining of judgment by a party for the secured indebtedness shall not be deemed an election of remedies or otherwise affect the lien rights or security interest as security for the payment thereof. In addition, upon default by any party in the payment of its share of expenses, interests or fees, or upon the improper use of funds by the Operator, the other parties shall have the right, without prejudice to other rights or remedies, to collect from the purchaser the proceeds from the sale of such defaulting party’s share of Oil and Gas until the amount owed by such party, plus interest as provided in “Exhibit C,” has been received, and shall have the right to offset the amount owed against the proceeds from the sale of such defaulting party’s share of Oil and Gas. All purchasers of production may rely on a notification of default from the non-defaulting party or parties stating the amount due as a result of the default, and all parties waive any recourse available against purchasers for releasing production proceeds as provided in this paragraph.

If any party fails to pay its share of cost within one hundred twenty (120) days after rendition of a statement therefor by Operator, the non-defaulting parties, including Operator, shall upon request by Operator, pay the unpaid amount in the proportion that the interest of each such party bears to the interest of all such parties. The amount paid by each party so paying its share of the unpaid amount shall be secured by the liens and security rights described in Article VII.B., and each paying party may independently pursue any remedy available hereunder or otherwise.

If any party does not perform all of its obligations hereunder, and the failure to perform subjects such party to foreclosure or execution proceedings pursuant to the provisions of this agreement, to the extent allowed by governing law, the defaulting party waives any available right of redemption from and after the date of judgment, any required valuation or appraisement of the mortgaged or secured property prior to sale, any available right to stay execution or to require a marshaling of assets and any required bond in the event a receiver is appointed. In addition, to the extent permitted by applicable law, each party hereby grants to the other parties a power of sale as to any property that is subject to the lien and security rights granted hereunder, such power to be exercised in the manner provided by applicable law or otherwise in a commercially reasonable manner and upon reasonable notice.

Each party agrees that the other parties shall be entitled to utilize the provisions of Oil and Gas lien law or other lien law of any state in which the Contract Area is situated to enforce the obligations of each party hereunder. Without limiting the generality of the foregoing, to the extent permitted by applicable law, Non-Operators agree that Operator may invoke or utilize the mechanics’ or materialmen’s lien law of the state in which the Contract Area is situated in order to secure the payment to Operator of any sum due hereunder for services performed or materials supplied by Operator.

C.  Advances:

Operator, at its election, shall have the right from time to time to demand and receive from one or more of the other parties payment in advance of their respective shares of the estimated amount of the expense to

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be incurred in operations hereunder during the next succeeding month, which right may be exercised only by submission to each such party of an itemized statement of such estimated expense, together with an invoice for its share thereof. Each such statement and invoice for the payment in advance of estimated expense shall be submitted on or before the 20th day of the next preceding month. Each party shall pay to Operator its proportionate share of such estimate within fifteen (15) days after such estimate and invoice is received. If any party fails to pay its share of said estimate within said time, the amount due shall bear interest as provided in Exhibit “C” until paid. Proper adjustment shall be made monthly between advances and actual expense to the end that each party shall bear and pay its proportionate share of actual expenses incurred, and no more.

D.  Defaults and Remedies:

If any party fails to discharge any financial obligation under this agreement, including without limitation the failure to make any advance under the preceding Article VII.C. or any other provision of this agreement, within the period required for such payment hereunder, then in addition to the remedies provided in Article VII.B. or elsewhere in this agreement, the remedies specified below shall be applicable. For purposes of this Article VII.D., all notices and elections shall be delivered only by Operator, except that Operator shall deliver any such notice and election requested by a non-defaulting Non-Operator, and when Operator is the party in default, the applicable notices and elections can be delivered by any Non-Operator. Election of any one or more of the following remedies shall not preclude the subsequent use of any other remedy specified below or otherwise available to a non-defaulting party.

1.  Suspension of Rights:  Any party may deliver to the party in default a Notice of Default, which shall specify the default, specify the action to be taken to cure the default, and specify that failure to take such action will result in the exercise of one or more of the remedies provided in this Article. If the default is not cured within thirty (30) days of the delivery of such Notice of Default, all of the rights of the defaulting party granted by this agreement may upon notice be suspended until the default is cured, without prejudice to the right of the non-defaulting party or parties to continue to enforce the obligations of the defaulting party previously accrued or thereafter accruing under this agreement. If Operator is the party in default, the Non-Operators shall have in addition the right, by vote of Non-Operators owning a majority in interest in the Contract Area after excluding the voting interest of Operator, to appoint a new Operator effective immediately. The rights of a defaulting party that may be suspended hereunder at the election of the non-defaulting parties shall include, without limitation, the right to receive information as to any operation conducted hereunder during the period of such default, the right to elect to participate in an operation proposed under Article VI.B. of this agreement, the right to participate in an operation being conducted under this agreement even if the party has previously elected to participate in such operation, and the right to receive proceeds of production from any well subject to this agreement.

2.  Suit for Damages:  Non-defaulting parties or Operator for the benefit of non-defaulting parties may sue (at joint account expense) to collect the amounts in default, plus interest accruing on the amounts recovered from the date of default until the date of collection at the rate specified in Exhibit “C” attached hereto. Nothing herein shall prevent any party from suing any defaulting party to collect consequential damages accruing to such party as a result of the default.

3.  Deemed Non-Consent:  The non-defaulting party may deliver a written Notice of Non-Consent Election to the defaulting party at any time after the expiration of the thirty-day cure period following delivery of the Notice of Default, in which event if the billing is for the drilling a new well or the Plugging Back, Sidetracking, Reworking or Deepening of a well which is to be or has been plugged as a dry hole, or for the Completion or Recompletion of any well, the defaulting party will be conclusively deemed to have elected not to participate in the operation and to be a Non-Consenting Party with respect thereto under Article VI.B. or VI.C., as the case may be, to the extent of the costs unpaid by such party, notwithstanding any election to participate theretofore made. If election is made to proceed under this provision, then the non-defaulting parties may not elect to sue for the unpaid amount pursuant to Article VII.D.2.

Until the delivery of such Notice of Non-Consent Election to the defaulting party, such party shall have the right to cure its default by paying its unpaid share of costs plus interest at the rate set forth in Exhibit “C,” provided, however, such payment shall not prejudice the rights of the non-defaulting parties to

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pursue remedies for damages incurred by the non-defaulting parties as a result of the default. Any interest relinquished pursuant to this Article VII.D.3. shall be offered to the non-defaulting parties in proportion to their interests, and the non-defaulting parties electing to participate in the ownership of such interest shall be required to contribute their shares of the defaulted amount upon their election to participate therein.

4.  Advance Payment:  If a default is not cured within thirty (30) days of the delivery of a Notice of Default, Operator, or Non-Operators if Operator is the defaulting party, may thereafter require advance payment from the defaulting party of such defaulting party’s anticipated share of any item of expense for which Operator, or Non-Operators, as the case may be, would be entitled to reimbursement under any provision of this agreement, whether or not such expense was the subject of the previous default. Such right includes, but is not limited to, the right to require advance payment for the estimated costs of drilling a well or Completion of a well as to which an election to participate in drilling or Completion has been made. If the defaulting party fails to pay the required advance payment, the non-defaulting parties may pursue any of the remedies provided in the Article VII.D. or any other default remedy provided elsewhere in this agreement. Any excess of funds advanced remaining when the operation is completed and all costs have been paid shall be promptly returned to the advancing party.

5.  Costs and Attorneys’ Fees:  In the event any party is required to bring legal proceedings to enforce any financial obligation of a party hereunder, the prevailing party in such action shall be entitled to recover all court costs, costs of collection, and a reasonable attorney’s fee, which the lien provided for herein shall also secure.

E.  Rentals, Shut-in Well Payments and Minimum Royalties:

Rentals, shut-in well payments and minimum royalties which may be required under the terms of any lease shall be paid by the party or parties who subjected such lease to this agreement at its or their expense. In the event two or more parties own and have contributed interests in the same lease to this agreement, such parties may designate one of such parties to make said payments for and on behalf of all such parties. Any party may request, and shall be entitled to receive, proper evidence of all such payments. In the event of failure to make proper payment of any rental, shut-in well payment or minimum royalty through mistake or oversight where such payment is required to continue the lease in force, any loss which results from such non-payment shall be borne in accordance with the provisions of Article IV.B.2.

Operator shall notify Non-Operators of the anticipated completion of a shut-in well, or the shutting in or return to production of a producing well, at least five (5) days (excluding Saturday, Sunday, and legal holidays) prior to taking such action, or at the earliest opportunity permitted by circumstances, but assumes no liability for failure to do so. In the event of failure by Operator to so notify Non-Operators, the loss of any lease contributed hereto by Non-Operators for failure to make timely payments of any shut-in well payment shall be borne jointly by the parties hereto under the provisions of Article IV.B.3.

F.  Taxes:

Beginning with the first calendar year after the effective date hereof, Operator shall render for ad valorem taxation all property subject to this agreement which by law should be rendered for such taxes, and it shall pay all such taxes assessed thereon before they become delinquent. Prior to the rendition date, each Non-Operator shall furnish Operator information as to burdens (to include, but not be limited to, royalties, overriding royalties and production payments) on Leases and Oil and Gas Interests contributed by such Non-Operator. If the assessed valuation of any Lease is reduced by reason of its being subject to outstanding excess royalties, overriding royalties or production payments, the reduction in ad valorem taxes resulting therefrom shall inure to the benefit of the owner or owners of such Lease, and Operator shall adjust the charge to such owner or owners so as to reflect the benefit of such reduction. If the ad valorem taxes are based in whole or in part upon separate valuations of each party’s working interest, then notwithstanding anything to the contrary herein, charges to the joint account shall be made and paid by the parties hereto in accordance with the tax value generated by each party’s working interest. Operator shall bill the other parties for their proportionate shares of all tax payments in the manner provided in Exhibit “C.”

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If Operator considers any tax assessment improper, Operator may, at its discretion, protest within the time and manner prescribed by law, and prosecute the protest to a final determination, unless all parties agree to abandon the protest prior to final determination. During the pendency of administrative or judicial proceedings, Operator may elect to pay, under protest, all such taxes and any interest and penalty. When any such protested assessment shall have been finally determined, Operator shall pay the tax for the joint account, together with any interest and penalty accrued, and the total cost shall then be assessed against the parties, and be paid by them, as provided in Exhibit “C.”

Each party shall pay or cause to be paid all production, severance, excise, gathering and other taxes imposed upon or with respect to the production or handling of such party’s share of Oil and Gas produced under the terms of this agreement.

ARTICLE VIII.
ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST

A.  Surrender of Leases:

The Leases covered by this agreement, insofar as they embrace acreage in the Contract Area, shall not be surrendered in whole or in part unless all parties consent thereto.

However, should any party desire to surrender its interest in any Lease or in any portion thereof, such party shall give written notice of the proposed surrender to all parties, and the parties to whom such notice is delivered shall have thirty (30) days after delivery of the notice within which to notify the party proposing the surrender whether they elect to consent thereto. Failure of a party to whom such notice is delivered to reply within said 30-day period shall constitute a consent to the surrender of the Leases described in the notice. If all parties do not agree or consent thereto, the party desiring to surrender shall assign, without express or implied warranty of title, all of its interest in such Lease, or portion thereof, and any well, material and equipment which may be located thereon and any rights in production thereafter secured, to the parties not consenting to such surrender. If the interest of the assigning party is or includes an Oil and Gas Interest, the assigning party shall execute and deliver to the party or parties not consenting to such surrender an oil and gas lease covering such Oil and Gas Interest for a term of one (1) year and so long thereafter as Oil and/or Gas is produced from the land covered thereby, such lease to be on the form attached hereto as Exhibit “B.” Upon such assignment or lease, the assigning party shall be relieved from all obligations thereafter accruing, but not theretofore accrued, with respect to the interest assigned or leased and the operation of any well attributable thereto, and the assigning party shall have no further interest in the assigned or leased premises and its equipment and production other than the royalties retained in any lease made under the terms of this Article. The party assignee or lessee shall pay to the party assignor or lessor the reasonable salvage value of the latter’s interest in any well’s salvable materials and equipment attributable to the assigned or leased acreage. The value of all salvable materials and equipment shall be determined in accordance with the provisions of Exhibit “C,” less the estimated cost of salvaging and the estimated cost of plugging and abandoning and restoring the surface. If such value is less than such costs, then the party assignor or lessor shall pay to the party assignee or lessee the amount of such deficit. If the assignment or lease is in favor of more than one party, the interest shall be shared by such parties in the proportions that the interest of each bears to the total interest of all such parties. If the interest of the parties to whom the assignment is to be made varies according to depth, then the interest assigned shall similarly reflect such variances.

Any assignment, lease or surrender made under this provision shall not reduce or change the assignor’s, lessor’s or surrendering party’s interest as it was immediately before the assignment, lease or surrender in the balance of the Contract Area; and the acreage assigned, leased or surrendered, and subsequent operations thereon, shall not thereafter be subject to the terms and provisions of this agreement but shall be deemed subject to an Operating Agreement in the form of this agreement.

B.  Renewal or Extension of Leases:

If any party secures a renewal or replacement of an Oil and Gas Lease or Interest subject to this agreement, then all other parties shall be notified promptly upon such acquisition or, in the case of a replacement Lease taken before expiration of an existing Lease, promptly upon expiration of the existing

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Lease. The parties notified shall have the right for a period of thirty (30) days following delivery of such notice in which to elect to participate in the ownership of the renewal or replacement Lease, insofar as such Lease affects lands within the Contract Area, by paying to the party who acquired it their proportionate shares of the acquisition cost allocated to that part of such Lease within the Contract Area, which shall be in proportion to the interest held at that time by the parties in the Contract Area. Each party who participates in the purchase of a renewal or replacement Lease shall be given an assignment of its proportionate interest therein by the acquiring party.

If some, but less than all, of the parties elect to participate in the purchase of a renewal or replacement Lease, it shall be owned by the parties who elect to participate therein, in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all parties participating in the purchase of such renewal or replacement Lease. The acquisition of a renewal or replacement Lease by any or all of the parties hereto shall not cause a readjustment of the interests of the parties stated in Exhibit “A,” but any renewal or replacement Lease in which less than all parties elect to participate shall not be subject to this agreement but shall be deemed subject to a separate Operating Agreement in the form of this agreement.

If the interests of the parties in the Contract Area vary according to depth, then their right to participate proportionately in renewal or replacement Leases and their right to receive an assignment of interest shall also reflect such depth variances.

The provisions of this Article shall apply to renewal or replacement Leases whether they are for the entire interest covered by the expiring Lease or cover only a portion of its area or an interest therein. Any renewal or replacement Lease taken before the expiration of its predecessor Lease, or taken or contracted for or becoming effective within six (6) months after the expiration of the existing Lease, shall be subject to this provision so long as this agreement is in effect at the time of such acquisition or at the time the renewal or replacement Lease becomes effective; but any Lease taken or contracted for more than six (6) months after the expiration of an existing Lease shall not be deemed a renewal or replacement Lease and shall not be subject to the provisions of this agreement.

The provisions in this Article shall also be applicable to extensions of Oil and Gas Leases.

C.  Acreage or Cash Contributions:

While this agreement is in force, if any party contracts for a contribution of cash towards the drilling of a well or any other operation on the Contract Area, such contribution shall be paid to the party who conducted the drilling or other operation and shall be applied by it against the cost of such drilling or other operation. If the contribution be in the form of acreage, the party to whom the contribution is made shall promptly tender an assignment of the acreage, without warranty of title, to the Drilling Parties in the proportions said Drilling Parties shared the cost of drilling the well. Such acreage shall become a separate Contract Area and, to the extent possible, be governed by provisions identical to this agreement. Each party shall promptly notify all other parties of any acreage or cash contributions it may obtain in support of any well or any other operation on the Contract Area. The above provisions shall also be applicable to optional rights to earn acreage outside the Contract Area which are in support of well drilled inside Contract Area.

If any party contracts for any consideration relating to disposition of such party’s share of substances produced hereunder, such consideration shall not be deemed a contribution as contemplated in this Article VIII.C.

D.  Assignment; Maintenance of Uniform Interest:

For the purpose of maintaining uniformity of ownership in the Contract Area in the Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production covered by this agreement no party shall sell, encumber, transfer or make other disposition of its interest in the Oil and Gas Leases and Oil and Gas Interests embraced within the Contract Area or in wells, equipment and production unless such disposition covers either:

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1.  the entire interest of the party in all Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production; or

2.  an equal undivided percent of the party’s present interest in all Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production in the Contract Area.

Every sale, encumbrance, transfer or other disposition made by any party shall be made expressly subject to this agreement and shall be made without prejudice to the right of the other parties, and any transferee of an ownership interest in any Oil and Gas Lease or Interest shall be deemed a party to this agreement as to the interest conveyed from and after the effective date of the transfer of ownership; provided, however, that the other parties shall not be required to recognize any such sale, encumbrance, transfer or other disposition for any purpose hereunder until thirty (30) days after they have received a copy of the instrument of transfer or other satisfactory evidence thereof in writing from the transferor or transferee. No assignment or other disposition of interest by a party shall relieve such party of obligations previously incurred by such party hereunder with respect to the interest transferred, including without limitation the obligation of a party to pay all costs attributable to an operation conducted hereunder in which such party has agreed to participate prior to making such assignment, and the lien and security interest granted by Article VII.B. shall continue to burden the interest transferred to secure payment of any such obligations.

If, at any time the interest of any party is divided among and owned by four or more co-owners, Operator, at its discretion, may require such co-owners to appoint a single trustee or agent with full authority to receive notices, approve expenditures, receive billings for and approve and pay such party’s share of the joint expenses, and to deal generally with, and with power to bind, the co-owners of such party’s interest within the scope of the operations embraced in this agreement; however, all such co-owners shall have the right to enter into and execute all contracts or agreements for the disposition of their respective shares of the Oil and Gas produced from the Contract Area and they shall have the right to receive, separately, payment of the sale proceeds thereof.

E.  Waiver of Rights to Partition:

If permitted by the laws of the state or states in which the property covered hereby is located, each party hereto owning an undivided interest in the Contract Area waives any and all rights it may have to partition and have set aside to it in severalty its undivided interest therein.

F.  Preferential Right to Purchase:

o (Optional; Check if applicable.)

Should any party desire to sell all or any part of its interests under this agreement, or its rights and interests in the Contract Area, it shall promptly give written notice to the other parties, with full information concerning its proposed disposition, which shall include the name and address of the prospective transferee (who must be ready, willing and able to purchase), the purchase price, a legal description sufficient to identify the property, and all other terms of the offer. The other parties shall then have an optional prior right, for a period of ten (10) days after the notice is delivered, to purchase for the stated consideration on the same terms and conditions the interest which the other party proposes to sell; and, if this optional right is exercised, the purchasing parties shall share the purchased interest in the proportions that the interest of each bears to the total interest of all purchasing parties. However, there shall be no preferential right to purchase in those cases where any party wishes to mortgage its interests, or to transfer title to its interests to its mortgagee in lieu of or pursuant to foreclosure of a mortgage of its interests, or to dispose of its interests by merger, reorganization, consolidation, or by sale of all or substantially all of its Oil and Gas assets to any party, or by transfer of its interests to a subsidiary or parent company or to a subsidiary of a parent company, or to any company in which such party owns a majority of the stock.

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

ARTICLE IX.
INTERNAL REVENUE CODE ELECTION

If, for federal income tax purposes, this agreement and the operations hereunder are regarded as a partnership, and if the parties have not otherwise agreed to form a tax partnership pursuant to Exhibit “G” or other agreement between them, each party thereby affected elects to be excluded from the application of all of the provisions of Subchapter “K,” Chapter 1, Subtitle “A,” of the Internal Revenue Code of 1986, as amended (“Code”), as permitted and authorized by Section 761 of the Code and the regulations promulgated thereunder. Operator is authorized and directed to execute on behalf of each party hereby affected such evidence of this election as may be required by the Secretary of the Treasury of the United States or the Federal Internal Revenue Service, including specifically, but not by way of limitation, all of the returns, statements, and the data required by Treasury Regulation §1.761. Should there be any requirement that each party hereby affected give further evidence of this election, each such party shall execute such documents and furnish such other evidence as may be required by the Federal Internal Revenue Service or as may be necessary to evidence this election. No such party shall give any notices or take any other action inconsistent with the election made hereby. If any present or future income tax laws of the state or states in which the Contract Area is located or any future income tax laws of the United States contain provisions similar to those in Subchapter “K,” Chapter 1, Subtitle “A,” of the Code, under which an election similar to that provided by Section 761 of the Code is permitted, each party hereby affected shall make such election as may be permitted or required by such laws. In making the foregoing election, each such party states that the income derived by such party from operations hereunder can be adequately determined without the computation of partnership taxable income.

ARTICLE X.
CLAIMS AND LAWSUITS

Operator may settle any single uninsured third party damage claim or suit arising from operations hereunder if the expenditure does not exceed _____________________________ Dollars ($____________) and if the payment is in complete settlement of such claim or suit. If the amount required for settlement exceeds the above amount, the parties hereto shall assume and take over the further handling of the claim or suit, unless such authority is delegated to Operator. All costs and expenses of handling settling, or otherwise discharging such claim or suit shall be a the joint expense of the parties participating in the operation from which the claim or suit arises. If a claim is made against any party or if any party is sued on account of any matter arising from operations hereunder over which such individual has no control because of the rights given Operator by this agreement, such party shall immediately notify all other parties, and the claim or suit shall be treated as any other claim or suit involving operations hereunder.

ARTICLE XI.
FORCE MAJEURE

If any party is rendered unable, wholly or in part, by force majeure to carry out its obligations under this agreement, other than the obligation to indemnify or make money payments or furnish security, that party shall give to all other parties prompt written notice of the force majeure with reasonably full particulars concerning it; thereupon, the obligations of the party giving the notice, so far as they are affected by the force majeure, shall be suspended during, but no longer than, the continuance of the force majeure. The term “force majeure,” as here employed, shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade, public riot, lightening, fire, storm, flood or other act of nature, explosion, governmental action, governmental delay, restraint or inaction, unavailability of equipment, and any other cause, whether of the kind specifically enumerated above or otherwise, which is not reasonably within the control of the party claiming suspension.

The affected party shall use all reasonable diligence to remove the force majeure situation as quickly as practicable. 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 by the party involved, contrary to its wishes; how all such difficulties shall be handled shall be entirely within the discretion of the party concerned.

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

ARTICLE XII.
NOTICES

All notices authorized or required between the parties by any of the provisions of this agreement, unless otherwise specifically provided, shall be in writing and delivered in person or by United States mail, courier service, telegram, telex, telecopier or any other form of facsimile, postage or charges prepaid, and addressed to such parties at the addresses listed on Exhibit “A.” All telephone or oral notices permitted by this agreement shall be confirmed immediately thereafter by written notice. The originating notice given under any provision hereof shall be deemed delivered only when received by the party to whom such notice is directed, and the time for such party to deliver any notice in response thereto shall run from the date the originating notice is received. “Receipt” for purposes of this agreement with respect to written notice delivered hereunder shall be actual delivery of the notice to the address of the party to be notified specified in accordance with this agreement, or to the telecopy, facsimile or telex machine of such party. The second or any responsive notice shall be deemed delivered when deposited in the United States mail or at the office of the courier or telegraph service, or upon transmittal by telex, telecopy or facsimile, or when personally delivered to the party to be notified, provided, that when response is required within 24 or 48 hours, such response shall be given orally or by telephone, telex, telecopy or other facsimile within such period. Each party shall have the right to change its address at any time, and from time to time, by giving written notice thereof to all other parties. If a party is not available to receive notice orally or by telephone when a party attempts to deliver a notice required to be delivered within 24 or 48 hours, the notice may be delivered in writing by any other method specified herein and shall be deemed delivered in the same manner provided above for any responsive notice.

ARTICLE XIII.
TERM OF AGREEMENT

This agreement shall remain in full force and effect as to the Oil and Gas Leases and/or Oil and Gas Interests subject hereto for the period of time selected below; provided, however, no party hereto shall ever be construed as having any right, title or interest in or to any Lease or Oil and Gas Interest contributed by any other party beyond the term of this agreement.

o Option No. 1:  So long as any of the Oil and Gas Leases subject to this agreement remain or are continued in force as to any part of the Contract Area, whether by production, extension, renewal or otherwise.
o Option No. 2:  In the event the well described in Article VI.A., or any subsequent well drilled under any provision of this agreement, results in the Completion of a well as a well capable of production of Oil and/or Gas in paying quantities, this agreement shall continue in force so long as any such well is capable of production, and for an additional period of _____ days thereafter; provided, however, if, prior to the expiration of such additional period, one or more of the parties hereto are engaged in drilling, Reworking, Deepening, Sidetracking, Plugging Back, testing or attempting to Complete or Re-complete a well or wells hereunder, this agreement shall continue in force until such operations have been completed and if production results therefrom, this agreement shall continue in force as provided herein. In the event the well described in Article VI.A., or any subsequent well drilled hereunder, results in a dry hole, and no other well is capable of producing Oil and/or Gas from the Contract Area, this agreement shall terminate unless drilling, Deepening, Sidetracking, Completing, Re-completing, Plugging Back or Reworking operations are commenced within ____________________ days from the date of abandonment of said well. “Abandonment” for such purposes shall mean either (i) a decision by all parties not to conduct any further operations on the well or (ii) the elapse of 180 days from the conduct of any operations on the well, whichever first occurs.

The termination of this agreement shall not relieve any party hereto from any expense, liability or other obligation or any remedy therefor which has accrued or attached prior to the date of such termination.

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

Upon termination of this agreement and the satisfaction of all obligations hereunder, in the event a memorandum of this Operating Agreement has been filed of record, Operator is authorized to file of record in all necessary recording offices a notice of termination, and each party hereto agrees to execute such a notice of termination as to Operator’s interest, upon request of Operator, if Operator has satisfied all its financial obligations.

ARTICLE XIV.
COMPLIANCE WITH LAWS AND REGULATIONS

A.  Laws, Regulations and Orders:

This agreement shall be subject to the applicable laws of the state in which the Contract Area is located, to the valid rules, regulations, and orders of any duly constituted regulatory body of said state; and to all other applicable federal, state, and local laws, ordinances, rules, regulations and orders.

B.  Governing Law:

This agreement and all matters pertaining hereto, including but not limited to matters of performance, non-performance, breach, remedies, procedures, rights, duties, and interpretation or construction, shall be governed and determined by the law of the state in which the Contract Area is located. If the Contract Area is in two or more states, the law of the state of ____________ shall govern.

C.  Regulatory Agencies:

Nothing herein contained shall grant, or be construed to grant, Operator the right or authority to waive or release any rights, privileges, or obligations which Non-Operators may have under federal or state laws or under rules, regulations or orders promulgated under such laws in reference to oil, gas and mineral operations, including the location, operation, or production of wells, on tracts offsetting or adjacent to the Contract Area.

With respect to the operations hereunder, Non-Operators agree to release Operator from any and all losses, damages, injuries, claims and causes of action arising out of, incident to or resulting directly or indirectly from Operator’s interpretation or application of rules, rulings, regulations or orders of the Department of Energy or Federal Energy Regulatory Commission or predecessor or successor agencies to the extent such interpretation or application was made in good faith and does not constitute gross negligence. Each Non-Operator further agrees to reimburse Operator for such Non-Operator’s share of production or any refund, fine, levy or other governmental sanction that Operator may be required to pay as a result of such an incorrect interpretation or application, together with interest and penalties thereon owing by Operator as a result of such incorrect interpretation or application.

ARTICLE XV.
MISCELLANEOUS

A.  Execution:

This agreement shall be binding upon each Non-Operator when this agreement or a counterpart thereof has been executed by such Non-Operator and Operator notwithstanding that this agreement is not then or thereafter executed by all of the parties to which it is tendered or which are listed on Exhibit “A” as owning an interest in the Contract Area or which own, in fact, an interest in the Contract Area. Operator may, however, by written notice to all Non-Operators who have become bound by this agreement as aforesaid, given at any time prior to the actual spud date of the Initial Well but in no event later than five days prior to the date specified in Article VI.A. for commencement of the Initial Well, terminate this agreement if Operator in its sole discretion determines that there is insufficient participation to justify commencement of drilling operations. In the event of such a termination by Operator, all further obligations of the parties hereunder shall cease as of such termination. In the event any Non-Operator has advanced or prepaid any share of drilling or other costs hereunder, all sums so advanced shall be returned to such Non-Operator without interest. In the event Operator proceeds with drilling operations for the Initial Well without the execution hereof by all persons listed on Exhibit “A” as having a current working interest in such well, Operator shall indemnify

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

Non-Operators with respect to all costs incurred for the Initial Well which would have been charged to such person under this agreement if such person had executed the same and Operator shall receive all revenues which would have been received by such person under this agreement if such person had executed the same.

B.  Successors and Assigns:

This agreement shall be binding upon and shall inure to the benefit of the parties hereto and their respective heirs, devisees, legal representatives, successors and assigns, and the terms hereof shall be deemed to run with the Leases or Interests included within the Contract Area.

C.  Counterparts:

This instrument may be executed in any number of counterparts, each of which shall be considered an original for all purposes.

D.  Severability:

For the purposes of assuming or rejecting this agreement as an executory contract pursuant to federal bankruptcy laws, this agreement shall not be severable, but rather must be assumed or rejected in its entirety, and the failure of any party to this agreement to comply with all of its financial obligations provided herein shall be a material default.

ARTICLE XVI.
OTHER PROVISIONS

IN WITNESS WHEREOF, this agreement shall be effective as of the ______ day of ___________, _______.
_______________________, who has prepared and circulated this form for execution, represents and warrants that the form was printed from and, with the exception(s) listed below, is identical to the AAPL Form 610-1989 Model Form Operating Agreement, as published in computerized form by Forms On-A-Disk, Inc. No changes, alterations, or modifications, other than those made by strikethrough and/or insertion and that are clearly recognizable as changes in Articles ___________________________, have been made to the form.

 
ATTEST OR WITNESS:   OPERATOR
  
  
    

 


 
 

By

 

 
 

 
 


Type or print name

         Title ___________________________________
         Date ___________________________________
         Tax ID or S.S. No. _______________________

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

 
NON-OPERATORS
  
  
    

 


 
 

By

 

 
 

 
 


Type or print name

         Title ___________________________________
         Date ___________________________________
         Tax ID or S.S. No. _______________________
  
  
    

 


 
 

By

 

 
 

 
 


Type or print name

         Title ___________________________________
         Date ___________________________________
         Tax ID or S.S. No. _______________________
  
  
    

 


 
 

By

 

 
 

 
 


Type or print name

         Title ___________________________________
         Date ___________________________________
         Tax ID or S.S. No. _______________________

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

ACKNOWLEDGMENTS

Note:  The following forms of acknowledgment are the short forms approved by the Uniform Law on Notarial Acts. The validity and effect of these forms in any state will depend upon the statutes of that state.

 
Individual acknowledgment:     
State of _______________)     
                      ) ss.     
County of _____________)     

This instrument was acknowledged before me on

___________________________________________ by ____________________________________________

 
(Seal, if any)   ____________________________________________
     Title (and Rank) ______________________________
     My commission expires: _______________________

 
Acknowledgment in representative capacity:
State of _______________)     
                      ) ss.     
County of _____________)     

This instrument was acknowledged before me on

_________________________________________ by ____________________________________________ as _________________ of ______________________________________________________________________.

 
(Seal, if any)   ____________________________________________
     Title (and Rank) ______________________________
     My commission expires: _______________________

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A.A.P.L. FORM 610 — MODEL FORM OPERATING AGREEMENT — 1989

EXHIBIT C

ICON OIL & GAS FUND
comprised of:
•   ICON Oil & Gas Fund-A L.P.
•   ICON Oil & Gas Fund-B L.P.
•   ICON Oil & Gas Fund-C L.P.

INSTRUCTIONS FOR COMPLETING THIS SUBSCRIPTION AGREEMENT

Consult with your financial advisor regarding suitability requirements and subscriber representations.

1. INVESTMENT    
   

•  

Each Interest costs $10,000.00 (except Interests purchased by the Managing General Partner, the selling dealers or certain of their affiliates).

   

•  

The minimum initial investment is one half (½) Interest ($5,000.00).

2. PARTNERSHIP    
   

•  

Designate the partnership in which you are subscribing.

3. INTERESTS    
   

•  

Designate the type of Interest(s) for which you are subscribing. See page C-5 for the investor suitability requirements for each type of Interest(s).

4. REGISTRATION  INFORMATION    
   

•  

Complete all of the information requested in sections 4(a) and 4(b) on page C-4, including the payment instruction information for distribution payments.

   

•  

Complete section 4(c) on page C-4 only if this investment is for an IRA, Qualified Plan or Trust.

5. FORM OF
 OWNERSHIP
   
   

•  

Mark only one box.

   

•  

Consult your financial advisor with any questions regarding designating the form of ownership.

6. DISTRIBUTION
 ALTERNATIVES
   
   

•  

For non-qualified accounts only, complete this section if you want your distributions sent to you by check instead of direct deposit.

7. POWER OF
 ATTORNEY
   
   

•  

Signature(s) and initials of subscriber(s) are required for all parties in each of the spaces provided. Subscriptions cannot be accepted without signature(s) and initials.

   

•  

Signature of an authorized partner or officer is required for a Partnership or Corporation.

   

•  

Signature of a trustee or custodian is required for a Custodial or Trust account.

8. SIGNATURES
 AND INITIALS
   
   

•  

Signature(s) and initials of subscriber(s) are required for all parties in each of the spaces provided. Subscriptions cannot be accepted without signature(s) and initials.

   

•  

Signature of an authorized partner or officer is required for a Partnership or Corporation.

   

•  

Signature of a trustee is required for a Custodial or Trust account.

9. BROKER/DEALER
 INFORMATION
   
   

•  

The registered representative must complete this section of the Subscription Agreement. An authorized branch manager or registered principal of the broker/dealer firm must sign the Subscription Agreement. Subscriptions cannot be accepted without this broker/dealer authorization.

THIS SUBSCRIPTION AGREEMENT CONTAINS THREE PAGES THAT MUST BE COMPLETED (C-4, C-6 AND C-8) AND DOES NOT CONTAIN CARBONLESS PAGES.

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10. INVESTMENT
  CHECK &
  SUBSCRIPTIONS
   
   

•  

If your registered representative notifies you that the sale of 200 Interests (or 1,000 Interests in the case of residents of Pennsylvania and Tennessee) has not been completed, make checks payable to:

   

º

For ICON Oil & Gas Fund-A L.P.: “UMB Bank, N.A., Escrow Agent for ICON O&G Fund-A”

   

º

For ICON Oil & Gas Fund-B L.P.: “UMB Bank, N.A., Escrow Agent for ICON O&G Fund-B”

   

º

For ICON Oil & Gas Fund-C L.P.: “UMB Bank, N.A., Escrow Agent for ICON O&G Fund-C”

      Otherwise, post-escrow break, make checks payable to:
   

º

For ICON Oil & Gas Fund-A L.P.: “ICON O&G Fund-A”

   

º

For ICON Oil & Gas Fund-B L.P.: “ICON O&G Fund-B”

   

º

For ICON Oil & Gas Fund-C L.P.: “ICON O&G Fund-C”

   

  

Your check should be in the amount of your subscription as shown in Section 1 of the Subscription Agreement.

   

•  

Wiring instructions are available upon request.

    Mailing:
For IRA or Qualified Accounts, mail the subscription document with your check and any transfer instructions to your designated Custodian.
   

•  

For all other accounts, mail the subscription document with your check to ICON Capital Corp., the administrator, at the following address:

   
  Regular Mail
ICON Capital Corp.
c/o DST
P.O. Box 219476
Kansas City, MO 64121-9476
  Overnight
ICON Capital Corp.

c/o DST
430 W. 7th Street
Kansas City, MO 64105
   

•  

Each subscription will be promptly reviewed and the Managing General Partner will accept or decline to accept you as either an Investor General Partner or a Limited Partner, as you designate in Section 3 on page C-4, in its sole and absolute discretion. If your subscription is accepted, either the Managing General Partner or an agent of the Managing General Partner will give you prompt written confirmation of your admission as a either an Investor General Partner or a Limited Partner (as you designate).

NO SUBSCRIPTION AGREEMENT WILL BE PROCESSED UNLESS FULLY COMPLETED AND ACCOMPANIED BY PAYMENT IN FULL. ANY SUBSCRIPTION PAYMENT THAT IS DISHONORED WILL CAUSE THE SUBSCRIPTION TO BE VOID AS OF THE SUBSCRIPTION DATE AND SHALL OBLIGATE THE SUBSCRIBER TO PAY ALL COSTS AND CHARGES ASSOCIATED THEREWITH.

If you have any questions about completing this Subscription Agreement, please call our Subscription Processing Desk at (800) 343-3736.

Important Information About Opening an Account:  In order to assist the government fight against the funding of terrorism and money laundering activities, federal law requires all financial institutions to obtain, verify and record information that identifies each person who opens an account. When opening an account, you will be asked by your Registered Representative for your name, address, date of birth and other information that will be used to identify you, including a driver’s license or other identifying documents.

THIS SUBSCRIPTION AGREEMENT CONTAINS THREE PAGES THAT MUST BE COMPLETED (C-4, C-6 AND C-8) AND DOES NOT CONTAIN CARBONLESS PAGES.

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IMPORTANT INFORMATION FOR SUBSCRIBER(S)

No offer to sell Interests may be made except by means of this Prospectus.
You should not rely upon any oral statements by any person, or upon any written information other than as specifically set forth in this Prospectus and supplements thereto or in promotional brochures clearly marked as being prepared and authorized by the Managing General Partner or by the Dealer-Manager, ICON Securities Corp. (“ICON Securities”), for use in connection with the offering of Interests to the general public by means of this Prospectus.
An investment in Interests involves certain risks, including, without limitation, the matters set forth in the Prospectus under the captions “Risk Factors,” “Conflicts of Interest,” “Management” and “Federal Income Tax Consequences.”
The representations you are making on page C-6 do not constitute a waiver of any of your rights under the Delaware Revised Uniform Limited Partnership Act or applicable federal and State securities laws.
Interests are subject to substantial restrictions on transferability.
There will be no public market for Interests.
It may not be possible for you to readily liquidate your Interests, if at all, even in the event of an emergency.
Any transfer of Interests is subject to our approval and must comply with the terms of Article VI of our Limited Partnership Agreement.
Some states impose more stringent standards than the general requirements described under the “Suitability Standards” section in the Prospectus.
The State of California has additional restrictions on the transfer of Interests, as summarized in the following legend:

“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.”

  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  

THIS SUBSCRIPTION AGREEMENT CONTAINS THREE PAGES THAT MUST BE COMPLETED (C-4, C-6 AND C-8) AND DOES NOT CONTAIN CARBONLESS PAGES.

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INVESTOR SUITABILITY REQUIREMENTS AND SUBSCRIBER REPRESENTATIONS

1. Subscription for Interests
Each Subscriber, by signing his/her name in Section 8 on Page C-6, thereby: (a) subscribes for the number and dollar amount of Interests set forth in Section 1, in the particular partnership indicated in Section 2 and the type of Interests indicated in Section 3 on Page C-4; (b) agrees to become either an Investor General Partner or a Limited Partner (at the Subscriber’s designation in Section 3 on Page C-4) of Fund-A, Fund-B or Fund-C (as applicable) upon acceptance of his/her subscription by the Managing General Partner; and (c) adopts, and agrees to be bound by each and every provision of the relevant Limited Partnership Agreement and this Subscription Agreement.
Each Subscriber is tendering good funds herewith in full payment for the Interests (computed at $10,000 per Interest), subject to waiver of commissions by some brokers (as described in the “Plan of Distribution” section of the Prospectus) and to the minimum investment requirements (as described in the “Subscriptions — Minimum Investment” section of the Prospectus).
2. General Subscriber Representations
Each Subscriber should consult with his/her/its personal tax adviser before subscribing for either Investor General Partner Interests or Limited Partner Interests hereunder. As a condition to Subscriber’s being admitted as either an Investor General Partner or a Limited Partner, as applicable, of Fund-A, Fund-B or Fund-C, as applicable, Subscriber hereby represents that he/she/it:
(a) Investor General Partner — (i) has annual gross income of $150,000 for the current year and the two previous years plus a net worth of $330,000 (exclusive of home, home furnishings and automobiles), or (ii) has a net worth of $750,000 (determined in the same manner), or (iii) has a net worth of $1,000,000 (inclusive of his/her home, home furnishings and automobiles), or (iv) has an annual “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, or (v) meets any higher investor gross income and/or net worth standards applicable to residents of his/her/its State, as set forth in the “Suitability Standards” section of the Prospectus.
(b) Limited Partner — (i) has annual gross income of $85,000 plus a net worth of $85,000 (exclusive of his/her investment in Fund-A, Fund-B or Fund-C, as applicable, home, home furnishings and automobiles) or (ii) a net worth of $330,000 (determined in the same manner), or (iii) meets any higher investor gross income and/or net worth standards applicable to residents of his/her/its State, as set forth in the “Suitability Standards” section of the Prospectus;
(c) If Subscriber is an IRA or a Qualified Plan, it has been accurately identified as such in Sections 4(c) and Section 5 on Page C-4; and
(d) Has accurately identified himself/herself in Section 4(b) on Page C-4 as a U.S. Citizen, resident in the U.S. or Puerto Rico (individuals only) or a U.S. resident alien.
Subscribers who are purchasing Interests for Individual Ownership agree to a redemption, upon demand, of all of their Interests if they are no longer U.S. citizens, residents of the United States or Puerto Rico (individuals only), or resident aliens or if they otherwise are or become foreign partners for purposes of Section 1446 of the Internal Revenue Code of 1986 at any time while holding Interests.
If Subscriber is investing in a fiduciary or representative capacity, such investment is being made for one or more persons, entities or trusts meeting the above requirements.

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3. Additional Fiduciary and Entity Representations.

If the person signing this Subscription Agreement is doing so on behalf of another person or entity who is the Subscriber, including, without limitation, a corporation, a partnership, an IRA, a Qualified Plan, or a trust (other than a Qualified Plan), such signatory, by signing his/her/its name in Section 8 of Page C-6, thereby represents and warrants that:

(a) He or she is duly authorized to (i) execute and deliver this Subscription Agreement, (ii) make the representations contained herein on behalf of Subscriber and (iii) bind Subscriber thereby; and
(b) This investment is an authorized investment for Subscriber under applicable documents and/or agreements (articles of incorporation or corporate by-laws or action, partnership agreement, trust indenture, etc.) and applicable law.
4. Under penalty of perjury, by signing his/her/its name in Section 8 on Page C-6, each Subscriber thereby certifies that:
(a) The Taxpayer Identification Number or Social Security Number listed in Section 4(a) or 4(c) (if applicable) on Page C-4 is correct; and
(b) He/she/it is not subject to backup withholding either because the Internal Revenue Service has (i) not notified such Subscriber that he/she/it is subject to backup withholding as a result of a failure to report all interest or dividends or (ii) has notified such Subscriber that he/she/it is no longer subject to backup withholding. (If a subscriber has been notified that he/she/it is currently subject to backup withholding, strike the language under clause (b) of this paragraph 4 before signing).

UPON THE SUBSCRIBER’S EXECUTION OF THIS SUBSCRIPTION AGREEMENT AND ACCEPTANCE THEREOF BY THE MANAGING GENERAL PARTNER, THIS SUBSCRIPTION AGREEMENT (CONSISTING OF PAGES C-1 THROUGH C-8) WILL BECOME A PART OF THE LIMITED PARTNERSHIP AGREEMENT.

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CONSENT TO ELECTRONIC DELIVERY OF OFFERING MATERIALS

All public drilling partnerships for which ICON Oil & Gas GP, LLC serves as the managing general partner and for which ICON Securities acts as a broker-dealer (collectively, “ICON Funds”) can deliver offering materials to investors electronically. By signing the consent provided below, investors can choose to have ICON Funds electronically deliver offering materials to them, including:

prospectuses;
prospectus supplements;
prospectus amendments;
annual, quarterly and periodic reports;
notices; and
supplemental sales literature (collectively, “Offering Materials”).

ICON Funds may accomplish electronic delivery via:

posting Offering Materials to the ICON Investments Internet Website (http://www.iconinvestments.com), whereby investors will be notified that such materials are available for viewing on the Website by
e-mail, physical mail or telephone;
sending e-mails to investors containing Offering Materials (including portable document format (.pdf) of such material); and
sending CD-ROMs to investors containing Offering Materials (including portable document format (.pdf) of such material).

Investors should note that electronic delivery may impose costs on an investor that he or she would not bear with traditional, physical mailing. Investors may incur Internet online costs for accessing e-mail.

At the same time, investors may need to download a .pdf document viewer, such as Adobe Acrobat®, in order to view Offering Materials sent as a .pdf file. Investors can download the Adobe Acrobat® software free of charge at http://www.adobe.com/products/acrobat/readermain.html.

ICON Securities will try to provide assistance to investors in connection with electronic delivery of Offering Materials free of charge. Investors in need of such assistance should contact ICON Securities toll free at (800) 343-3736.

The undersigned hereby consents to electronic delivery of all Offering Materials by ICON Funds in any or all of the manners described above. Information provided below as to the undersigned’s e-mail address will be used by ICON Funds in lieu of different instructions from the undersigned.

The undersigned understands that he or she may revoke this consent at any time by providing timely notice of revocation to ICON Oil & Gas GP, LLC. Revocation of such consent will act to revoke consent as to all future electronic deliveries of Offering Materials by ICON Funds.

The undersigned also understands that he or she may elect to receive paper copies of Offering Materials at any time upon request, with or without revoking this consent.

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The undersigned also understands that this Consent to Electronic Delivery of Offering Materials is optional, and is not a part of the Subscription Agreement, which must be executed in accordance with the instructions on pages C-1 and C-2.

 
Print Name     
Signature
  Date
E-mail Address (please print, and include domain extension (.com, .net, etc.)     

 
Print Name     
Signature
  Date
E-mail Address (please print, and include domain extension (.com, .net, etc.)     

   
I am an investor in:   ICON Oil & Gas Fund-A L.P.   o
     ICON Oil & Gas Fund-B L.P.   o
     ICON Oil & Gas Fund-C L.P.   o

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You should rely only on the information contained in this prospectus. No dealer, salesperson or other individual has been authorized to give any information or to make any representations that are not contained in this prospectus. If any such information or statements are given or made, you should not rely upon such information or representation. This prospectus does not constitute an offer to sell any securities other than those to which this prospectus relates, or an offer to sell, or a solicitation of an offer to buy, to any person in any jurisdiction where such an offer or solicitation would be unlawful. This prospectus speaks as of the date set forth below. You should not assume that the delivery of this prospectus or that any sale made pursuant to this prospectus implies that the information contained in this prospectus will remain fully accurate and correct as of any time subsequent to the date of this prospectus.

  
  
  

[GRAPHIC MISSING]

  
  
  

Minimum Offering of 200 Interests
Maximum Offering of 20,000 Interests
  

ICON OIL & GAS FUND

  
an ICON Investments fund

  
  
  



 

  
PRELIMINARY PROSPECTUS
  



 

  
  
  
  
  

[•  ], 2012

 

 


 
 

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PART II
  
INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

The estimated expenses of the partnership in connection with the offering (assuming the sale of the maximum of $200,000,000 of Interests) are as follows:

 
Securities and Exchange Commission Registration Fee   $ 23,220  
Financial Industry Regulatory Authority, Inc. Filing Fee   $ 20,500  
Blue Sky Expenses   $ 175,000  
Legal Fees and Expenses   $ 375,000  
Accounting Fees and Expenses   $ 200,000  
Printing   $ 765,000  
Advertising   $ 467,500  
Miscellaneous   $ 1,025,000  
Total   $ 3,051,220  

Item 14. Indemnification of Managing GP

Section 17-108 of the Delaware Revised Uniform Limited Partnership Act states: “Subject to such standards and restrictions, if any, as are set forth in its partnership agreement, a limited partnership may, and shall have the power to, indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever.”

Section 4.05 of the Limited Partnership Agreement, included in the prospectus as Exhibit A, provides for indemnification of the general partner, its affiliates and individual officers under certain circumstances. Reference is made to such section of the Limited Partnership Agreement and to “Summary of the Limited Partnership Agreement” in the prospectus.

The above discussion of the Limited Partnership Agreement is not intended to be exhaustive and is qualified in its entirety by the Limited Partnership Agreement.

Item 15. Recent Sales of Unregistered Securities

On September 20, 2011, the partnership was capitalized with the issuance to (i) ICON Oil & Gas GP, LLC of a general partnership interest of the partnership for a purchase price of $1.00 and (ii) ICON Investment Group, LLC of one (1) limited partnership interest of the partnership for a purchase price of $1,000. These partnership interests in the partnership were purchased for investment and for the purpose of organizing the partnership. The partnership issued the partnership interests in reliance on an exemption from registration under Section 4(2) of the Securities Act.

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Item 16. Exhibits and Financial Statement Schedules

(a)  Exhibits.

 
Exhibit
No.
  Exhibit
 1.1   Form of Dealer-Manager Agreement
 1.2   Form of Selling Dealer Agreement
 3.1   Certificate of Limited Partnership of ICON Oil & Gas Fund-A L.P. filed with the Delaware Secretary of State*
 3.2   Certificate of Limited Partnership of ICON Oil & Gas Fund-B L.P. filed with the Delaware Secretary of State*
 3.3   Certificate of Limited Partnership of ICON Oil & Gas Fund-C L.P. filed with the Delaware Secretary of State*
 4.1   Form of ICON Oil & Gas Fund-A L.P. Limited Partnership Agreement (included as Exhibit A to the prospectus)
 4.2   Subscription Agreement, including the partner signature page and power of attorney (included as Exhibit C to the prospectus)
 5.1   Opinion of Arent Fox LLP
 8.1   Opinion of Arent Fox LLP with respect to certain tax matters
10.1   Escrow Agreement
10.2   Form of Participation Agreement (included as Exhibit B to the prospectus)
23.1   Consent of Ernst & Young LLP
23.2   Consent of Arent Fox LLP (included in Exhibit 5.1)
23.3   Consent of Arent Fox LLP (included in Exhibit 8.1)
24.1   Power of Attorney (included on Signature Page)*
* Previously filed as an exhibit to the Registration Statement filed on September 28, 2011.

(b)  Financial Statement Schedules.

All schedules have been omitted as the requested information is inapplicable or is presented in the prospectus, the balance sheets, financial statements or related notes.

Item 17. Undertakings

(a) Rule 415 Offering.

The partnership hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
(i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after the effective date of this registration statement (or the most recent post-effective amendment thereof), which, individually or in the aggregate, represent a fundamental change in the information set forth in this registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and
(iii) To include any material information with respect to the plan of distribution not previously disclosed in this registration statement or any material change to such information in this registration statement.

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(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
(3) That all post-effective amendments will comply with the applicable forms, rules and regulations of the Securities and Exchange Commission in effect at the time such post-effective amendments are filed.
(4) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
(5) That, for the purpose of determining liability of the partnership under the Securities Act of 1933 to any purchaser in the initial distribution of the securities:

The partnership undertakes that in a primary offering of securities of the partnership pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the partnership will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the partnership relating to the offering required to be filed pursuant to Rule 424;
(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the partnership or used or referred to by the partnership;
(iii) The portion of any other free writing prospectus relating to the offering containing material information about the partnership or its securities provided by or on behalf of the partnership; and
(iv) Any other communication that is an offer in the offering made by the partnership to the purchaser.
(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to the Managing GP of the partnership (or controlling persons of the Managing GP or of the partnership) pursuant to the provisions described under Item 14 or otherwise, the partnership has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the partnership of expenses incurred or paid by the Managing GP or controlling person of the Managing GP or of the partnership in the successful defense of any action, suit or proceeding) is asserted by any such Managing GP or controlling person in connection with the securities being registered, the partnership will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.
(c) The partnership hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreements certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the partnership has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of New York, State of New York, on June 13, 2012.

 
  ICON OIL & GAS FUND
    

By:

ICON Oil & Gas GP, LLC, its agent

    

  

/s/ Michael A. Reisner
Name: Michael A. Reisner
Title: Co-Chief Executive Officer, Co-President and Director

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities indicated on June 13, 2012.

 
Signatures   Title(s)
/s/ Mark Gatto
Mark Gatto
  Co-Chief Executive Officer, Co-President and Director of the Managing GP of the Partnership; Co-Principal Executive Officer
/s/ Michael A. Reisner
Michael A. Reisner
  Co-Chief Executive Officer, Co-President and Director of the Managing GP of the Partnership; Co-Principal Executive Officer
/s/ Nicholas Sinigaglia
Nicholas Sinigaglia
  Managing Director; Principal Accounting and Financial Officer

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EXHIBIT INDEX

 
Exhibit
No.
  Exhibit
 1.1   Form of Dealer-Manager Agreement
 1.2   Form of Selling Dealer Agreement
 3.1   Certificate of Limited Partnership of ICON Oil & Gas Fund-A L.P. filed with the Delaware Secretary of State*
 3.2   Certificate of Limited Partnership of ICON Oil & Gas Fund-B L.P. filed with the Delaware Secretary of State*
 3.3   Certificate of Limited Partnership of ICON Oil & Gas Fund-C L.P. filed with the Delaware Secretary of State*
 4.1   Form of ICON Oil & Gas Fund-A L.P. Limited Partnership Agreement (included as Exhibit A to the prospectus)
 4.2   Subscription Agreement, including the partner signature page and power of attorney (included as Exhibit C to the prospectus)
 5.1   Opinion of Arent Fox LLP
 8.1   Opinion of Arent Fox LLP with respect to certain tax matters
10.1   Escrow Agreement
10.2   Form of Participation Agreement (included as Exhibit B to the prospectus)
23.1   Consent of Ernst & Young LLP
23.2   Consent of Arent Fox LLP (included in Exhibit 5.1)
23.3   Consent of Arent Fox LLP (included in Exhibit 8.1)
24.1   Power of Attorney (included on Signature Page)*
* Previously filed as an exhibit to the Registration Statement filed on September 28, 2011.

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