Attached files

file filename
EX-23.1 - EXHIBIT 23.1 - ICON Oil & Gas Fund-B L.P.v245642_ex23-1.htm

As filed with the Securities and Exchange Commission on January 26, 2012

Registration Number 333-177051

 

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



 

Amendment No. 2
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
Executive Vice President
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.


 
 

TABLE OF CONTENTS

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 JANUARY 26, 2012

[GRAPHIC MISSING]

ICON OIL & GAS FUND
an ICON Investment Group 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, which are collectively referred to as “Interests”(1), at $10,000 per Interest

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 [      ]. 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. 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 13, 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. d/b/a ICON Investments (“ICON Investments”), 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 investors who will receive a similar one-time distribution upon their admission) who invest prior to the minimum offering 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. The last date on which Interests may be sold is [_____].

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 [____].


 
 

TABLE OF CONTENTS

TABLE OF CONTENTS

 
SUITABILITY STANDARDS     v  
PROSPECTUS SUMMARY     1  
RISK FACTORS     13  
Risks Related to the Partnership’s Oil and Gas Operations     19  
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.     19  
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.     20  
Adverse events in marketing the partnership’s natural gas could reduce distributions.     20  
Because some wells may not return their drilling and completion costs, it may take many years to return your investment in cash, if ever     22  
Nonproductive wells may be drilled even though the partnership’s operations are primarily limited to development drilling     22  
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     22  
The partnership will not acquire title insurance for its leasehold interests, which may be subject to title defects     22  
Participation with third parties in drilling wells may require the partnership to pay additional costs     22  
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     23  
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     23  
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     23  
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     23  
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     24  
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     24  
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     25  
The partnership may lose oil and gas lease properties due to numerous factors     25  
Environmental hazards involved in drilling oil and natural gas wells may result in substantial liabilities for the partnership     26  
Risks Related to an Investment in the Partnership     13  
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     13  
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     14  

i


 
 

TABLE OF CONTENTS

 
Compensation and fees to the Managing GP regardless of success of the partnership’s activities will reduce cash distributions     14  
There is no guaranty that cash distributions will be paid by the partnership in any amount or frequency     14  
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     15  
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     15  
Increases in the costs of the wells may adversely affect your return     15  
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     16  
Drilling prospects in one area may increase risk     16  
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     17  
The presentment obligation may not be funded and the presentment price may not reflect full value     17  
The lack of an independent dealer-manager may reduce the due diligence investigation of the partnership and the Managing GP     17  
A lengthy offering period may result in delays in the investment of your subscription and any cash distributions from the partnership to you     18  
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     18  
Your Interests may be diluted     18  
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     19  
An investment in the Interests may not satisfy the requirements of ERISA or other applicable laws     19  
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     19  
Risks Related to the Partnership’s Organization and Structure     26  
The decisions of the Managing GP may be subject to conflicts of interest     26  
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     27  
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.     27  
The Managing GP may have difficulty managing its growth, which may divert its resources and limit its ability to expand its operations successfully     27  
Operational risks may disrupt the partnership’s business and result in losses     27  
The partnership’s internal controls over financial reporting may not be effective, which could have a significant and adverse effect on our business     28  
The partnership will be subject to certain reporting requirements and will be required to file certain periodic reports with the Securities and Exchange Commission     28  

ii


 
 

TABLE OF CONTENTS

 
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     28  
You are not expected to have any protection under the Investment Company Act     29  
You are not expected to have any protection under the Investment Advisers Act     29  
Risks Related to the Tax Treatment of the Partnership and the Interests     29  
If the IRS classifies the partnership as a corporation rather than a partnership, your distributions would be reduced under current tax law     29  
You may incur tax liability in excess of the cash distributions you receive in a particular year     29  
There are limitations on your ability to deduct the partnership’s losses     30  
This investment may cause you to pay additional taxes     30  
The IRS may allocate more taxable income to you than the Limited Partnership Agreement provides     30  
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     30  
No ruling will be requested from the IRS as to the tax consequences of investing in Interests     31  
The deduction for intangible drilling costs may not be available to you if you do not have passive income     31  
Investment interest deductions that may be available to Investor General Partners may nevertheless be limited     31  
You may not be eligible to claim percentage depletion deductions     31  
The tax benefits that may be available to you from your investment in the partnership are not contractually protected     32  
An IRS audit of the partnership may result in an IRS audit of your personal federal income tax returns     32  
The partnership’s deductions may be challenged by the IRS     32  
Changes in tax laws may reduce the potential tax benefits available from an investment in the partnership     32  
Your deduction for intangible drilling costs may be limited for purposes of the alternative minimum tax     33  
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     33  
The partnership and its investors may be subject to other taxes besides federal taxes     33  
If you are or invest through a tax-exempt entity or organization, you will have unrelated business taxable income from this investment.     33  
It may be many years before you receive any marginal well production credits, if ever     33  
FORWARD-LOOKING STATEMENTS     34  
ACTIONS TO BE TAKEN BY THE MANAGING GP TO REDUCE RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS     35  
SOURCE OF FUNDS AND ESTIMATED USE OF OFFERING PROCEEDS     37  
COMPENSATION     39  
TERMS OF THE OFFERING     48  
PRIOR ACTIVITIES     53  
MANAGEMENT     54  
ALTERNATIVE INVESTMENTS     59  
PROPOSED ACTIVITIES     60  
COMPETITION, MARKETS AND REGULATION     67  
PARTICIPATION IN COSTS AND REVENUES     71  

iii


 
 

TABLE OF CONTENTS

 
CONFLICTS OF INTEREST     76  
FIDUCIARY RESPONSIBILITY OF THE MANAGING GP     84  
FEDERAL INCOME TAX CONSEQUENCES     86  
INVESTMENT BY QUALIFIED PLANS AND IRAS     120  
SUMMARY OF LIMITED PARTNERSHIP AGREEMENT     123  
SUMMARY OF PARTICIPATION AGREEMENT     127  
REPORTS TO INVESTORS     128  
PRESENTMENT FEATURE     129  
TRANSFERABILITY OF INTERESTS     131  
PLAN OF DISTRIBUTION     133  
SUBSCRIPTIONS     135  
FURTHER INFORMATION     138  
GLOSSARY     139  
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  

iv


 
 

TABLE OF CONTENTS

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 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 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 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 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, then you must not make an investment in the partnership that is in excess of 10% of your liquid net worth. Further, 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

v


 
 

TABLE OF CONTENTS

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 Ohio or Oregon, you must not make an investment in the partnership that would, after including your previous investments in any other similar natural gas and oil drilling programs, exceed 10% of your net worth, exclusive of home, home furnishings and automobiles. Finally, if you are a resident of Alabama, you must not make an investment in the partnership that would, after including your previous investments in any other similar natural gas and oil drilling 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. Louisiana,   23. Rhode Island,
 2. Colorado,   13. Maryland,   24. South Carolina,
 3. Connecticut,   14. Mississippi,   25. South Dakota,
 4. Delaware,   15. Missouri,   26. Utah,
 5. District of Columbia,   16. Montana,   27. Vermont,
 6. Florida,   17. Nebraska,   28. Virginia,
 7. Georgia,   18. Nevada,   29. West Virginia,
 8. Hawaii,   19. New Hampshire,   30. Wisconsin, or
 9. Idaho,   20. New York,   31. Wyoming,
10. Illinois,   21. North Dakota,     
11. Kentucky,   22. Puerto Rico,     

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, and if you are a resident of Kentucky, then you must not make an investment in the partnership that is in excess of 10% of your liquid net worth.

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

vi


 
 

TABLE OF CONTENTS

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 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 Ohio 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 natural gas and oil drilling programs, exceed 10% of your net worth, exclusive of home, home furnishings and automobiles. Further, if you are a resident of Alabama, then you must not make an investment in the partnership that would, after including your previous investments, if any, and any other similar natural gas and oil drilling programs, exceed 10% of your liquid net worth, exclusive of home, home furnishings and automobiles. Finally, if you are a resident of Kansas, it is recommended by the Office of the Kansas Securities Commissioner that Kansas investors should limit their investment in the 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.

vii


 
 

TABLE OF CONTENTS

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.”

viii


 
 

TABLE OF CONTENTS

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 15 years or longer.

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.

1


 
 

TABLE OF CONTENTS

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

2


 
 

TABLE OF CONTENTS

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.

3


 
 

TABLE OF CONTENTS

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 Corp. d/b/a ICON Investments (“ICON Investments”), the dealer-manager of this offering.

4


 
 

TABLE OF CONTENTS

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 Investments 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 will enter 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.

5


 
 

TABLE OF CONTENTS

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.”

6


 
 

TABLE OF CONTENTS

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.”

7


 
 

TABLE OF CONTENTS

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 [__].

   

•  

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 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 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

8


 
 

TABLE OF CONTENTS

    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 Investments, 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 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

9


 
 

TABLE OF CONTENTS

    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 Investments 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, on a fully accountable basis, (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 operator(s) both before and during producing operations. See “Conflicts of Interest — Conflicts Regarding Transactions with the Managing GP and its Affiliates.”

   

•  

The 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 related 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

10


 
 

TABLE OF CONTENTS

    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 competitive rate of interest on any loan it may make to or on behalf of the partnership. If the Managing GP provides equipment, supplies, and other services to the partnership, then it may be compensated at competitive industry rates but not based on arm’s-length negotiations. 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;

   

•  

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

11


 
 

TABLE OF CONTENTS

    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)). 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 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.

12


 
 

TABLE OF CONTENTS

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 current insurance coverage of $[•  ] for pollution liability, 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 NASAA Guidelines. This is the first oil and gas program sponsored by the Managing GP and its affiliates. You should

13


 
 

TABLE OF CONTENTS

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;”
repayment of borrowings;

14


 
 

TABLE OF CONTENTS

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 likely to be reduced by a drop in oil and natural gas prices. Also, the reduced availability of drilling rigs and

15


 
 

TABLE OF CONTENTS

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.

16


 
 

TABLE OF CONTENTS

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 leasehold 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 engineering 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

17


 
 

TABLE OF CONTENTS

expenses, ICON Investments’ 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.

18


 
 

TABLE OF CONTENTS

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.

19


 
 

TABLE OF CONTENTS

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

20


 
 

TABLE OF CONTENTS

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 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 located 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. 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. Finally, this credit risk may reduce the price benefit derived by the partnership from the Managing GP’s natural gas hedging arrangements, since from time to time the Managing GP and its affiliates will implement a portion of their natural gas hedges through the natural gas 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

21


 
 

TABLE OF CONTENTS

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 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.

The related 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 related 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 is 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.

22


 
 

TABLE OF CONTENTS

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. This period in which the partnership is a general unsecured creditor may be even longer because in some situations the partnership may not receive a recorded assignment until up to six months after a well is drilled and completed.

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

23


 
 

TABLE OF CONTENTS

well. Therefore, investors may have to rely solely on estimates provided by the operator of a Project and/or on internal estimates provided by the Managing GP. 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.

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;

24


 
 

TABLE OF CONTENTS

unusual or unexpected geological formations;
loss of drilling fluid circulation;
formations with abnormal pressures;
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, and may have to pay increased costs to renew leases, each of 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. Alternatively, leases could expire outright and be required to be renewed. 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. 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 taken, and such increases could be substantial. Payment of the delay rentals and/or lease renewals could seriously deplete the partnership’s capital available to fund drilling activities when they do commence. The risk of incurring delay rentals, 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 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.

25


 
 

TABLE OF CONTENTS

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.

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

26


 
 

TABLE OF CONTENTS

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, the current business plan of certain affiliates of the Managing GP entails sponsoring, managing and/or distributing other investment products, including, but not limited to, equipment funds, business development companies and real estate investment trusts. 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. 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.

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.

27


 
 

TABLE OF CONTENTS

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.

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

28


 
 

TABLE OF CONTENTS

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.

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

29


 
 

TABLE OF CONTENTS

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 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

30


 
 

TABLE OF CONTENTS

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.”

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,

31


 
 

TABLE OF CONTENTS

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 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

32


 
 

TABLE OF CONTENTS

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.”

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.”

33


 
 

TABLE OF CONTENTS

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.

34


 
 

TABLE OF CONTENTS

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. Generally, major subcontractors are required to carry general and auto liability insurance with a minimum of $[•] combined single limit for bodily injury and property damage in any one occurrence or accident. In the event of a loss caused by a major subcontractor, the 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.

35


 
 

TABLE OF CONTENTS

Indemnification.  The Managing GP will use its corporate assets 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 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.

36


 
 

TABLE OF CONTENTS

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.

37


 
 

TABLE OF CONTENTS

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.

38


 
 

TABLE OF CONTENTS

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 Investments, 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 Investments 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 Investments.
  
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 Investments’ 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.

39


 
 

TABLE OF CONTENTS

   
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 the ICON Investments 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.

(1) The amounts listed above for Sales Commissions do not give effect to the potential reduction of the Sales Commissions that are not payable for Interests purchased by 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.

40


 
 

TABLE OF CONTENTS

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.
Supervisory Fee — paid to the Managing GP.   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 each Project for supervising the operations of the related operator both before and during producing operations. 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.

41


 
 

TABLE OF CONTENTS

   
Type of Compensation   Method of Compensation   Estimated Dollar Amount
     In conducting its supervisory role for each Project, regardless of whether or not it takes a separate Supervisory Fee, 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.
  
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.

42


 
 

TABLE OF CONTENTS

   
Type of Compensation   Method of Compensation   Estimated Dollar Amount
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.”
  
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.
  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.

43


 
 

TABLE OF CONTENTS

   
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 competitive rate of interest, but not based on arm’s-length negotiations, on any loan it may make to or on behalf of the partnership. If the Managing GP provides equipment, supplies, and other services to the drilling operations, then it may do so at competitive industry rates, but not based on arm’s-length negotiations. 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, nor may it receive interest in excess of the amounts that would be charged the partnership (without reference to the Managing GP’s financial abilities or guaranties) by unrelated banks on comparable loans for the same purpose, 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.

44


 
 

TABLE OF CONTENTS

   
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 (i) its administrative costs, on a fully accountable basis, and (ii) its fixed direct costs, on a non-accountable basis. The direct costs reimbursement amount will be determined by the Managing GP, in its sole discretion. Once determined, the Managing GP may not increase this amount during the term of the related Project.
  
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.

45


 
 

TABLE OF CONTENTS

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.

46


 
 

TABLE OF CONTENTS

   
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.     

47


 
 

TABLE OF CONTENTS

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       [•  ]  
ICON Oil & Gas Fund-B L.P.   $ 2,000,000       (2)       [•  ]  
ICON Oil & Gas Fund-C L.P.   $ 2,000,000       (2)       [•  ]  

(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) 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 [      ]. 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.

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.

48


 
 

TABLE OF CONTENTS

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 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.

49


 
 

TABLE OF CONTENTS

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 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.

Pennsylvania 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 investors will be

50


 
 

TABLE OF CONTENTS

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 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.

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

51


 
 

TABLE OF CONTENTS

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.

52


 
 

TABLE OF CONTENTS

PRIOR ACTIVITIES

Special Energy Corporation

The partnership will enter 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 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 $92,000,000 and $53,000,000, respectively, in grossed up proceeds from each project based upon the working interest divested.

SPECIAL ENERGY’S PRIOR PROJECT PERFORMANCE
(All volumes in this table represent gross production and revenue based on gross 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   $ 42,152,540     $ 14,043,281     $ 24,793,521     $ 94,607,258     $ 79,472,785  
Gross Project Divestiture Proceeds                     $ 92,000,000     $ 53,000,000  
Total Project Cash Flow   $ 118,668,143     $ 34,881,870     $ 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.

53


 
 

TABLE OF CONTENTS

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 Investments under common control.

[GRAPHIC MISSING]

Directors and Executive Officers of the Managing GP

The directors and executive officers 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   Executive Vice President and Secretary
Louis Raniero   39   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 and executive officers 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 has been a Director of ICON Capital since May 2007. 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 Capital from January 2004 through

54


 
 

TABLE OF CONTENTS

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.

Mark Gatto, Co-Chairman, Co-Chief Executive Officer and Co-President, has been a Director of ICON Capital since May 2007. Mr. Gatto originally 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.

Joel S. Kress, Executive Vice President and Secretary, 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 his current position with ICON Capital, 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, 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

55


 
 

TABLE OF CONTENTS

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. 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.

56


 
 

TABLE OF CONTENTS

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;
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;
commitments of the partnership’s future production;
sharing in gas marketing arrangements;
advance payments from the partnership to the Managing GP;

57


 
 

TABLE OF CONTENTS

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.

58


 
 

TABLE OF CONTENTS

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.”

59


 
 

TABLE OF CONTENTS

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

60


 
 

TABLE OF CONTENTS

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

61


 
 

TABLE OF CONTENTS

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 is obtained, and overriding royalty interest generally means an interest that is created in favor of someone other than the landowner. In either case, the owner of the interest receives a specific percentage of the natural gas and oil production free and clear of all costs of development, operation or maintenance of the well. This

62


 
 

TABLE OF CONTENTS

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.”

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.

63


 
 

TABLE OF CONTENTS

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:
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;

64


 
 

TABLE OF CONTENTS

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.

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.

65


 
 

TABLE OF CONTENTS

The Managing GP will supervise the production operations and will be reimbursed for its direct expenses and will receive well supervision fees at competitive rates during producing operations. 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.

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 non-regulated over-the-counter futures 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. 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 partnership’s production is substantially less than expected, the counterparties to the futures contracts fail to perform under the contracts, or there is a sudden, unexpected event materially impacting prices.

66


 
 

TABLE OF CONTENTS

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 most or all of the partnership’s wells will 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.

67


 
 

TABLE OF CONTENTS

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.

68


 
 

TABLE OF CONTENTS

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

69


 
 

TABLE OF CONTENTS

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.

70


 
 

TABLE OF CONTENTS

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.

71


 
 

TABLE OF CONTENTS

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 reimbursement for its direct costs. 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