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As filed with the Securities and Exchange Commission on June 8, 2012

Registration Number 333-                    

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

MDS ENERGY PUBLIC 2012 PROGRAM

(Exact name of Registrant as Specified in its Charter)

 

 

Delaware

(State or other jurisdiction of incorporation or organization)

 

 

1311

(Primary Standard Industrial Classification Code Number)

 

 

Not Applicable

(IRS Employer Identification Number)

 

 

409 Butler Road

Suite A

Kittanning, Pennsylvania, 16201

(855) 807-0807

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

 

 

Michael D. Snyder, President

MDS Energy Development, LLC

409 Butler Road

Suite A, Kittanning, Pennsylvania, 16201

(855) 807-0807

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

 

 

With a Copy to:

Wallace W. Kunzman, Jr., Esq.

Gerald A. Bollinger, Esq.

Kunzman & Bollinger, Inc.

5100 N. Brookline

Suite 600

Oklahoma City, Oklahoma 73112

 

 

As soon as practicable after this Registration Statement becomes effective.

(Approximate Date of Commencement of Proposed Sale to the Public)

 

 

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

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

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

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

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		¨		Accelerated filer		¨
Non-accelerated filer		¨		Smaller Reporting Company		x

 

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to be Registered (4)		Unit Amounts to be Registered		Dollar Amounts to be Registered		Proposed Maximum Offering Price per Unit		Proposed Maximum Aggregate Offering Price		Compact New Fees
Investor General Partner Units (1)		29,400		$294,000,000		$10,000		$294,000,000		$33,692.40
Converted Limited Partner Units (2)		29,400		- 0 -		- 0 -		- 0 -		- 0 -
Limited Partner Units (3)		600		$6,000,000		$10,000		$6,000,000		$687.60
TOTAL		30,000		$300,000,000		$10,000		$300,000,000		$34,380

(1)	“Investor General Partner Units” means up to 29,400 investor general partner interests offered to participants in the program.

(2)	“Converted Limited Partner Units” means up to 29,400 limited partner units into which the investor general partner units automatically will be converted by the managing general partner with no additional price paid by the investor.

(3)	“Limited Partner Units” means up to 600 initial limited partner interests offered to participants in the program.

(4)	The partnerships reserve the right to adjust the number of Investor General Partner Units, Limited Partner Units and Investor General Partner Units converted to Limited Partner Units set forth above so long as they do not exceed 30,000 in the aggregate.

 

 

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

 

 

 

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MDS ENERGY PUBLIC 2012 PROGRAM

CROSS REFERENCE SHEET

 

Item of Form S-1				Caption in Prospectus
Item 1.		Forepart of the Registration Statement and Outside Front Cover Page of Prospectus		Front Page of Registration Statement and Outside Front Cover Page of Prospectus
Item 2.		Inside Front and Outside Back Cover Pages of Prospectus		Inside Front and Outside Back Cover Pages of Prospectus
Item 3.		Summary Information, Risk Factors and Ratio of Earnings to Fixed Charges		Summary of the Offering; Risk Factors
Item 4.		Use of Proceeds		Capitalization and Source of Funds and Use of Proceeds
Item 5.		Determination of Offering Price		Terms of the Offering
Item 6.		Dilution		No units will be issued in this offering to the managing general partner and its affiliates except subscriptions described on the Front Cover Page of the Prospectus, which the managing general partner does not anticipate. Discounted units being offered are described in “Plan of Distribution.”
Item 7.		Selling Security Holders		The program does not have any selling security holders.
Item 8.		Plan of Distribution		Plan of Distribution
Item 9.		Description of Securities to be Registered		Summary of the Offering; Terms of the Offering; Summary of Partnership Agreement
Item 10.		Interests of Named Experts and Counsel		Legal Opinions; Experts
Item 11.		Information with respect to the Registrant
		(a)    Description of Business		Proposed Activities; Management
		(b)    Description of Property		Proposed Activities
		(c)    Legal Proceedings		Litigation
		(d)    Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters		The partnerships composing the program have no markets in which their units are being traded and they have not yet paid any dividends.
		(e)    Financial Statements		Financial Information Concerning the Managing General Partner and MDS Energy Public 2012-A LP
		(f)     Selected Financial Data		All of the partnerships composing the program have been formed, but none of the partnerships have yet conducted any activities. Thus, the program does not have this information for the partnerships.

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Item of Form S-1				Caption in Prospectus
		(g)    Supplementary Financial Information		All of the partnerships composing the program have been formed, but none of the partnerships have yet conducted any activities. Thus, the program does not have this information for the partnerships.
		(h)    Management’s Discussion and Analysis of Financial Condition and Results of Operations		Management’s Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources
		(i)     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		There have been no changes in and disagreements with accountants on accounting and financial disclosure.
		(k)    Directors and Executive Officers		Management
		(l)     Executive Compensation		Management
		(m)   Security Ownership of Certain Beneficial Owners and Management		Management
		(n)    Certain Relationships and Related Transactions		Compensation; Management; Conflicts of Interest
Item 12.		Disclosure of Commission Position on Indemnification for Securities Act Liabilities		Fiduciary Responsibilities of the Managing General Partner

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

 

PRELIMINARY PROSPECTUS DATED JUNE 8, 2012

MDS ENERGY PUBLIC 2012 PROGRAM

Up to 29,400 Investor General Partner Units, which will be automatically converted to up to 29,400 Limited Partner Units after drilling is completed in the partnership, and up to 600 Limited Partner Units, which are collectively referred to as the “units,” ⁽¹⁾ at $10,000 per Unit

$2 Million (200 Units) Minimum Aggregate Subscriptions

$300,000,000 (30,000 Units) Maximum Aggregate Subscriptions

The program reserves the right to adjust the number of Investor General Partner Units, Limited Partner Units and Investor General Partner Units converted to Limited Partner Units in each partnership so long as they do not exceed 30,000 units in the aggregate

 

(1)

You may elect to buy either investor general partner units in the partnership then being offered that will be automatically converted to limited partner units after the partnership’s drilling is completed, or limited partner units. The type of unit you buy will not change your share of the partnership’s costs, revenues and cash distributions, however, there are material differences in the federal income tax effects and liability between investor general partner units and limited partner units as discussed in “Summary of the Offering – Description of Units.”

 

 

 

 

These securities are speculative and involve a high degree of risk. You should purchase these securities only if you can afford a complete loss of your investment. See “Risk Factors,” page 14, which includes the following:

 

•

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

 

•

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

 

•

Most, if not all, of the partnership’s wells will be drilled vertically to the Marcellus Shale geological formation in western Pennsylvania, which will provide little or no geological diversification of risk, and will be classified as natural gas wells that may produce some oil or natural gas liquids.

 

•

Your partnership distributions will be a return of capital until you have received 100% of your investment.

 

•

Cash distributions to you from the partnership every month are not guaranteed.

 

•

You will have unlimited joint and several liability for partnership obligations if you choose to invest as an investor general partner until you are converted to a limited partner.

 

•

A lack of liquidity or a public market for the units makes it extremely difficult for you to sell your units.

 

•

There is a lack of conflict of interest resolution procedures between the managing general partner and you and the other investors.

 

•

You must rely totally on the managing general partner and its affiliates to manage the partnership and its business.

 

•

Substantial fees will be paid by the partnership to the managing general partner and its affiliates.

 

•

You and the managing general partner will share in costs disproportionately to your sharing of revenues.

 

•

Proposed changes in the federal income tax laws, if enacted, would reduce your tax benefits from an investment in the partnership.

Neither the SEC nor any state securities commission has approved or disapproved of these securities or determined if this preliminary prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

[MDS Securities, LLC] – Dealer-Manager

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SUITABILITY STANDARDS

In General

It is the obligation of the managing general partner (the “sponsor”) and the persons selling the units to make every reasonable effort to assure that the units are suitable for you based on your investment objectives and financial situation, regardless of your income or net worth. However, you should invest in a partnership only if you are willing to assume the risk of a speculative, illiquid, and long-term investment. Also, subscriptions to a partnership will not be accepted from IRAs, Keogh plans and qualified retirement plans because the partnership’s income would be characterized as unrelated business taxable income, which is subject to federal income tax.

Generally, you are required to execute your own subscription agreement, and the managing general partner will not accept any subscription agreement that has been executed by someone other than you. The only exception is if you have given someone else the legal power of attorney to sign on your behalf and you meet all of the conditions in this prospectus.

The decision to accept or reject your subscription will be made by the managing general partner, in its sole discretion, and is final. The managing general partner will not accept your subscription until it has reviewed your apparent qualifications, and the suitability determination must be maintained by the managing general partner during your partnership’s term and for at least six years thereafter.

Pennsylvania Investors: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to a partnership in this offering, you are cautioned to carefully evaluate the partnership’s ability to fully accomplish its stated objectives and inquire as to the current dollar volume of partnership subscriptions. In addition, subscription proceeds received by a 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 for MDS Energy Public 2012-A LP means that subscriptions for at least $15,000,000 have been received by the partnership from investors, including Pennsylvania investors. If the appropriate minimum has not been met at the end of each 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 each 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 issuer must return such funds within 15 calendar days after receipt of the investor’s request.

General Suitability Requirements for Purchasers of Limited Partner Units

Limited partner units 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 Iowa, Michigan, Missouri, or Pennsylvania, then you must not make an investment in a partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings and automobiles and if you are a resident of Kentucky, then you must not make an investment in a partnership which is in excess of 10% of your liquid net worth. Further, if you are a resident of Ohio or Oregon you must not make an investment in a partnership which would, after including your previous investments in prior MDS Energy Development programs, 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. Also, if you are a resident of Alabama, then you must not make an investment in a partnership which would, after including your previous investments in prior MDS Energy Development’s programs, if any, and any other similar natural gas and oil drilling

 

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programs, exceed 10% of your liquid net worth, exclusive of home, home furnishings and automobiles. Finally, if you are a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Division, respectively, that you should limit your investment in the program and substantially similar programs to no more than 10% of your 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.

General Suitability Requirements for Purchasers of Investor General Partner Units

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 units 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

 

•

an individual net worth or joint net worth with your spouse 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 a partnership which 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 a partnership which 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 purchase investor general partner units.

 

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Special Suitability Requirements for Purchasers of Investor General Partner Units

 

•

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

and you subscribe for investor general partner units, then you must meet any 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 the two previous years; or

 

•

an individual net worth or joint net worth with your spouse in excess of $1,000,000, inclusive of home, home furnishings and automobiles; or

 

•

an individual or joint net worth with your spouse in excess of $750,000, exclusive of home, home furnishings, and automobiles; or

 

•

a combined “gross income” as defined in Internal Revenue Code Section 61 in excess of $200,000 in the current year and the two previous years.

In addition, if you are a resident of Iowa, Michigan or Pennsylvania, then you must not make an investment in a partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings, and automobiles. Further, if you are a resident of Ohio or Oregon, then you must not make an investment in a partnership which would, after including your previous investments in prior MDS Energy Development’s programs, 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. Also, if you are a resident of Alabama, then you must not make an investment in a partnership which would, after including your previous investments in prior MDS Energy Development’s programs, 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 or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Division, respectively, that you should limit your investment in the program and substantially similar programs to no more than 10% of your 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.

Fiduciary Accounts

If there is a sale of a unit to a fiduciary account, then all of the suitability standards set forth above must be met by the beneficiary, the fiduciary account, or the donor or grantor who directly or indirectly supplies the funds to purchase the units if the donor or grantor is the fiduciary.

 

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Restrictions Imposed by the USA Patriot Act and Related Acts

In accordance with the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, as amended (the “USA PATRIOT Act”), the units offered hereby may not be offered, sold, transferred or delivered, directly or indirectly, to any “Prohibited Shareholder,” which means anyone who is:

 

•

a “designated national,” “specially designated national,” “specially designated terrorist,” “specially designated global terrorist,” “foreign terrorist organization,” or “blocked person” within the definitions set forth in the Foreign Assets Control Regulations of the U.S. Treasury Department;

 

•

acting on behalf of, or an entity owned or controlled by, any government against whom the U.S. maintains economic sanctions or embargoes under the Regulations of the U.S. Treasury Department;

 

•

within the scope of Executive Order 13224 – Blocking Property and Prohibiting Transactions with Persons who Commit, Threaten to Commit, or Support Terrorism, effective September 24, 2001;

 

•

subject to additional restrictions imposed by the following statutes or regulations, and executive orders issued thereunder: the Trading with the Enemy Act, the Iraq Sanctions Act, the National Emergencies Act, the Antiterrorism and Effective Death Penalty Act of 1996, the International Emergency Economic Powers Act, the United Nations Participation Act, the International Security and Development Cooperation Act, the Nuclear Proliferation Prevention Act of 1994, the Foreign Narcotics Kingpin Designation Act, the Iran and Libya Sanctions Act of 1996, the Cuban Democracy Act, the Cuban Liberty and Democratic Solidarity Act and the Foreign Operations, Export Financing and Related Programs Appropriation Act or any other law of similar import as to any non-U.S. country, as each such act or law has been or may be amended, adjusted, modified or reviewed from time to time; or

 

•

designated or blocked, associated or involved in terrorism, or subject to restrictions under laws, regulations, or executive orders as may apply in the future similar to those set forth above.

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RISK FACTORS

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

Risks Related To the Partnerships’ Oil and Gas Operations

No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature of Drilling Natural Gas and Oil Wells. Natural gas and oil exploration is an inherently speculative activity. Before the drilling of a well the managing general partner cannot predict with absolute certainty:

 

•

the volume of natural gas and oil recoverable from the well; or

 

•

the time it will take to recover the natural gas and oil.

You may not recover any or all of your investment in your 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 natural gas and oil from productive wells. The quantity of natural gas and oil in a well, which is referred to as its reserves, decreases over time as the natural gas and oil is produced until the well is no longer economical to operate.

Distributions from a Partnership May Be a Return of Capital Rather Than a Return on Your Investment. All of your partnership’s 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. See “Prior Activities.”

Because Some Wells May Not Return Their Drilling and Completion Costs, It May Take Many Years to Return Your Investment in Cash, If Ever. Even if a well is completed by a partnership and produces natural gas and oil in commercial quantities, it may not produce enough natural gas and oil to pay for the costs of drilling and completing the well, even if tax benefits are considered. Thus, it may take many years to return your investment in cash, if ever.

Previous Drilling By Others May Reduce the Partnerships’ Ability to Find Economically Recoverable Quantities of Natural Gas. The partnerships’ Marcellus Shale primary drilling area is located in an area where other oil and gas companies have previously drilled wells and the specific areas where each partnership’s wells will be situated may have already been partially depleted or drained by earlier drilling. This may reduce the partnership’s ability to find economically recoverable quantities of natural gas in those areas.

The Managing General Partner Has Limited Experience in Drilling Vertical Wells in the Marcellus Shale Primary Area. As of January 31, 2012, the managing general partner’s affiliates, including Snyder Brothers, Inc., and the five previous drilling limited partnerships sponsored by the managing general partner’s affiliates, MDS Energy, Ltd. and M/D Gas Inc., had participated in drilling approximately 84 vertical wells in the Marcellus Shale primary area, 70 of which were producing natural gas from the Marcellus Shale geological formation, 11 of which had been drilled but had not yet been placed on line for production of natural gas, and three of which were producing natural gas from shallower geological zones above the Marcellus Shale formation before production from the Marcellus Shale is attempted. Thus, the managing general partner has limited information with respect to the ultimate recoverable reserves and production decline rates of vertical wells drilled in the Marcellus Shale primary area. See “– Risks Related to an Investment in a Partnership – Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of Each Partnership’s Drilling Program” and “Proposed Activities – Primary Area of Operations – Marcellus Shale Geological Formation in Western Pennsylvania.”

 

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Fracturing Each Partnership’s Marcellus Shale Wells Requires Adequate Sources of Water and the Partnership’s Wells Will Produce Water That Must Be Disposed of at a Reasonable Cost and Within Applicable Environmental Rules or the Partnership’s Ability to Produce Natural Gas from a Well Could be Impaired. Each partnership’s natural gas wells in the Marcellus Shale primary area in western Pennsylvania will use a process called hydraulic fracturing, which requires large amounts of water to frack the wells and also results in water discharges that must be treated and disposed of. The use of the water necessary for hydraulic fracturing may increase the partnership’s operating costs and cause delays, interruptions or termination of drilling and operating its wells, the extent of which cannot be predicted, all of which could have an adverse effect on the partnership’s operations and financial performance. The partnership’s ability to transport, treat and dispose of water will affect its production, and the cost of water treatment and disposal may affect its profitability. See “Proposed Activities – Primary Area of Operations – Marcellus Shale Geological Formation in Western Pennsylvania,” and “Competition, Markets and Regulations.”

Each Partnership Will Use Hydraulic Fracturing in Drilling its Marcellus Shale Wells, Which Could Increase the Possibility of Third-Party Claims Against the Partnership Alleging Water Contamination from the Partnership’s Wells. As part of the process of drilling and completing its wells in the Marcellus Shale primary area, each partnership will use hydraulic fracturing, which involves the injection of large amounts of water, sand and small amounts of additives under high pressure into the Marcellus Shale formation in an attempt to increase natural gas production from the wells. See “Proposed Activities – Primary Area of Operations – Marcellus Shale Geological Formation in Western Pennsylvania.” The increased use of hydraulic fracturing has generated national and local publicity over the past few years regarding the possibility that hydraulic fracturing could contaminate nearby water sources, such as lakes, rivers, streams, and drinking water wells or cause minor earthquakes in the area. Also, some lawsuits have been filed against oil and gas operators by third-parties seeking, among other remedies, cash damages for the alleged contamination of their water supplies because hydraulic fracturing was used in drilling nearby wells. Thus, if you are investing in a partnership as an Investor General Partner, your risk may be increased. See “Risk Factors – Risks Related to an Investment in a Partnership – If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner.”

Even though hydraulic fracturing historically has been regulated by the states, the U.S. Environmental Protection Agency (the “EPA”) recently asserted authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act, proposed new regulations governing hydraulic fracking on federal lands, Furthermore, a committee of the U.S. House of Representatives is investigating the possibility of environmental contamination from hydraulic fracturing and legislation has been introduced in Congress to require federal regulation of hydraulic fracturing and disclosure of the chemicals used in the fracturing process. Also, Pennsylvania has adopted a variety of new well construction, set back, and disclosure regulations that limit how fracturing can be performed and require various degrees of disclosure of the chemicals used in the fracking fluid. See “Actions to be Taken By Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners” and “Competition, Markets and Regulations.”

The Partnerships May Drill Horizontal Wells and the Managing General Partner Has No Experience in Drilling Horizontal Wells, if Any, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells. Although the managing general partner anticipates that all of each partnership’s subscription proceeds will be used to drill vertical developmental wells in the Marcellus Shale primary area, the managing general partner, in its discretion, may cause the partnership to use up to approximately 25% of the partnership’s subscription proceeds to drill development wells horizontally in the Marcellus Shale primary area. Also, up to approximately 20% of the partnership’s subscription proceeds may be used to drill vertical or horizontal wells in other areas of the United States. See “Proposed Activities – Secondary Areas of Operations.” Since the managing general partner has no experience in drilling horizontal wells and little or no information with respect to the ultimate recoverable reserves and the production decline rate associated with horizontal wells in any area, the managing general partner anticipates that the partnership will retain third-party experienced geological and/or engineering consultants and drilling contractors as consultants with respect to any horizontal well to be drilled by a partnership. See “– Risks Related to an Investment in a Partnership – Lack of Production

 

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Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of Each Partnership’s Drilling Program” and “Proposed Activities – Primary Area of Operations – Marcellus Shale Geological Formation in Western Pennsylvania.”

Horizontal wells are more expensive to drill and complete than vertical wells, because of increased costs associated with the drilling rigs needed to drill a horizontal well, including multiple fracking of the wells and additional casing for the wells, as discussed in “Compensation – Drilling Contracts.” This increased cost to the partnerships may not result in greater recoverable reserves. In addition, horizontal wells will be more susceptible to mechanical problems associated with completing the wells, such as casing collapse and lost equipment, than vertical wells. Further, fracking the formation in a horizontal well is more complicated than fracking the same geological formation in a vertical well. Thus, there is a greater risk of loss of the well or cost overruns associated with horizontal drilling as compared with vertical drilling.

Federal and State Legislation and Regulations Related to Hydraulic Fracturing Could Result in Increased Costs and Operating Restrictions or Delays. Bills have been introduced in Congress since 2009 that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in drilling operations as well as increased costs to make the wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third-parties to initiate litigation against a partnership in the event of perceived problems with drinking water wells in the vicinity of a partnership well or other alleged environmental problems. In addition, Pennsylvania has adopted a position that will, in effect, require the partnership to truck wastewater from its wells in the Marcellus Shale primary area in western Pennsylvania to Ohio and dispose of the wastewater in injection wells. In this regard, in December 2011, there was an earthquake near Youngstown, Ohio that prompted Ohio officials to at least temporarily shut down a wastewater disposal well in the area to evaluate whether the disposal well may have caused or played a part in precipitating the earthquake. Pennsylvania also has adopted new regulations that impose additional requirements concerning the casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of wells, baseline testing of nearby water wells, and the types of chemicals that may be used in hydraulic fracturing operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive, which would increase the cost of drilling and completing the wells and reduce the amount of partnership distributions to you and the other investors in the partnership.

Recently Adopted EPA Rules Regulating Air Emissions from Natural Gas and Oil Operations Could Cause the Partnerships to Incur Increased Capital Expenditures and Operating Costs. Even though hydraulic fracturing historically has been regulated by the states, the U.S. Environmental Protection Agency (the “EPA”) recently asserted authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act. Also, in April 2012, the EPA issued final rules under the Clean Air Act that establish new air emission controls for natural gas and oil production and natural gas processing operations, some of which, such as the rule requiring reduced emissions controls (“RECs”) on newly fractured wells, do not become effective until January 1, 2015. These rules include new standards to reduce emissions of sulfur dioxide, volatile organic compounds (“VOCs”) and other hazardous air pollutants frequently associated with natural gas and oil production and processing activities, which mandate the use of “green completions” for hydraulic fracturing. A “green completion” captures most of the natural gas that otherwise might escape into the air. Until January 1, 2015, operators generally are allowed under the new rules to vent the natural gas and natural gas liquids that come to the surface during completion of the fracturing process. Although the managing general partner anticipates that all of the partnerships’ wells will be drilled, completed and placed in service before January 1, 2015, the EPA’s new rules may still require a number of modifications to a partnership’s operations, including additional reporting requirements and possibly the installation of additional equipment, which would result in significant costs, including increased capital expenditures and operating costs, and could adversely impact the partnership’s business.

 

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In addition, Congress has considered legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases. The adoption of any legislation or regulation that requires additional reporting of greenhouse gases or further limits emissions of greenhouse gases from a partnership’s equipment and operations that are in addition to the EPA’s new rules under the Clean Air Act discussed above could further increase the partnership’s costs to monitor and report on greenhouse gas emissions or reduce emissions of greenhouse gases associated with its operations, and also could adversely affect demand for the natural gas and oil that the partnership produces. Furthermore, a committee of the U.S. House of Representatives is investigating the possibility of environmental contamination from hydraulic fracturing and legislation has been introduced in Congress to require federal regulation of hydraulic fracturing and disclosure of the chemicals used in the fracturing process. Also, Pennsylvania has adopted a variety of new well construction, set back, and disclosure regulations that limit how fracturing can be performed and require various degrees of disclosure of the chemicals used in the fracking fluid. See “Actions to be Taken By Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners” and “Competition, Markets and Regulations.”

Climate Change Legislation or Regulations Restricting Emissions of Greenhouse Gases (“GHGs”) Could Result in Increased Operating Costs. In response to findings that emissions of carbon dioxide, methane, and other GHGs endanger public health and the environment by contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under the federal Clean Air Act that require entities that produce certain gases to inventory, monitor and report such gases. In November 2010, the EPA published a final GHG emissions reporting rule relating to natural gas processing, transmission, storage, and distribution activities, which requires reporting beginning in 2012 for emissions occurring in 2011. Additionally, in 2010, the EPA issued rules to regulate GHG emissions through traditional major source construction and operating permit programs. These permitting programs require consideration of and, if deemed necessary, implementation of best available control technology to reduce GHG emissions. As a result, the partnerships’ operations could face additional costs for emissions control and higher costs of doing business.

Nonproductive Wells May be Drilled Even Though the Partnerships’ Operations are Primarily Limited to Development Drilling. A partnership may drill some wells that are nonproductive, which is referred to as a “dry hole,” and must be plugged and abandoned. If one or more of the partnership’s wells are nonproductive, then the partnership’s productive wells, if any, may not produce enough revenues to offset the loss of investment in the nonproductive wells. See “Prior Activities.”

Also, drilling for natural gas and oil involves the risk of curtailments, delays or cancellations as a result of factors such as the following:

 

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the prices of natural gas and oil, which are volatile;

 

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unusual geological formations;

 

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higher or unusual pressures in the wellbore, which were not anticipated;

 

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fires;

 

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blowouts;

 

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cave ins;

 

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loss of drilling fluid circulation;

 

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title problems;

 

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facility or equipment malfunctions;

 

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shortages or delivery delays of equipment and services;

 

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adverse weather conditions;

 

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•

subsurface conditions causing a cratering or shifting of the wellbore;

 

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drilling through or encountering an underground mine;

 

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wet formations;

 

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excessive water;

 

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steeply dipping, heaving or faulted formation(s); and

 

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impenetrable zones.

Any of these risks can cause substantial losses, in some cases including personal injury or loss of life, damage to or destruction of property, pollution, environmental contamination or loss of wells and regulatory penalties, and could curtail natural gas or oil production from a well or could require a well to be re-drilled or other remedial action to be taken.

In addition, porosities and permeabilities in the Marcellus Shale are very low, so to unlock the hydrocarbons and make the wells productive frack treatments using large amounts of water must be performed as discussed in “Proposed Activities – Primary Area of Operation – Marcellus Shale Geological Formation in Western Pennsylvania.” Porosity is the percentage of void space between particles that is available for occupancy by either liquids or gases; and permeability is the property of porous rock that allows fluids or gas to flow through it.

Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil. The prices at which the partnerships’ natural gas and oil will be sold are uncertain and as discussed in “– A Partnership May Not Be Able to Replace a Purchaser of its Natural Gas and Oil at the Same or a Better Purchase Price, Which Could Reduce Partnership Distributions,” below, the partnerships are not guaranteed a specific price for the sale of their natural gas and oil production. Changes in natural gas and oil prices will have a significant impact on a partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the partnership’s revenues, but also may reduce the amount of natural gas and oil that the partnership can produce economically as discussed in “– Risks Related to an Investment in a Partnership – A Decrease in Natural Gas Prices and Oil Prices Could Subject the Partnerships’ and the Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles.” As an example of the volatility of natural gas prices, in April 2012 the price of natural gas decreased to a 10-year low of approximately $1.93 per 1,000 cubic feet of natural gas (“mcf”). Historically, natural gas and oil prices have been volatile and it is likely that they will continue to be volatile in the future. Prices for natural gas and oil will depend on supply and demand factors largely beyond the control of the partnership and prices may fluctuate widely in response to:

 

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relatively minor changes in the supply of and demand for natural gas or oil;

 

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market uncertainty; and

 

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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 natural gas and oil price movements with any certainty.

If natural gas and oil prices decrease in the future, then a partnerships’ distributions will decrease accordingly. Also, natural gas and oil prices may decrease during the first years of production from a partnership’s wells, which is when the wells typically achieve their greatest level of production and the managing general partner is subject to its eight-year subordination obligation. See “Participation in Costs and Revenues – Subordination of Portion of Managing General Partner’s Net Revenue Share.” This would have a greater adverse effect on your distributions from the partnership than price decreases in later years when the wells have a lower level of production and the managing general partner’s share of partnership net production revenues may not be subject to its eight-year subordination obligation. Also, your return level will decrease during the term of the partnership,

 

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even if there are rising natural gas prices, because of declining production volumes from the wells over time. Further, as discussed in “Federal Income Tax Consequences – Depletion Allowance,” some of the natural gas and oil production from a partnership’s productive wells may be marginal production under the Internal Revenue Code (the “Code”) and could qualify for potentially higher rates of percentage depletion. In the case of a partnership’s marginal production wells, if any, the partnership will be more sensitive to price declines, which could cause the partnership to plug and abandon the wells, than if the wells produced at a higher average rate of production that did not qualify for the potentially higher rate of percentage depletion.

A Partnership May Not Be Able to Replace a Purchaser of its Natural Gas and Oil at the Same or a Better Purchase Price, Which Could Reduce Partnership Distributions. The managing general partner anticipates that each partnership’s natural gas or oil production initially will be sold to a limited number of purchasers as described in “Proposed Activities – Sale of Natural Gas and Oil Production.” If a partnership loses a natural gas or oil purchaser in a given area, the partnership may be unable to locate a new purchaser in the area that will buy the partnership’s natural gas or oil on as favorable terms as the initial purchaser, which could reduce the partnership’s net production revenues and the partnership’s distributions to you and the other investors.

The Proceeds from the Sale of a Partnership’s Natural Gas and Oil Will Be Subject to Claims of the Managing General Partner’s and its Affiliates’ Creditors Until the Sales Proceeds are Paid to the Partnership. All of the contracts for the sale and purchase of a partnership’s natural gas production may be between the natural gas purchaser and the managing general partner or its affiliates. In that event, the managing general partner anticipates that Snyder Brothers, Inc., an affiliate of the managing general partner, other affiliates of the managing general partner, or the managing general partner as operator under the partnership’s drilling and operating agreement, 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 partnership. Until the sales proceeds are distributed to the partnership, they will be subject to the claims of the managing general partner’s or its affiliates’ creditors.

Also, all of these 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. Natural gas prices remain volatile and could decrease in the future. Thus, the partnerships will not be guaranteed a specific natural gas price under the purchase contracts.

Increased Costs to Transport a Partnership’s Natural Gas to a Pipeline Could Decrease the Partnership’s Net Revenues. A partnership’s net revenues will decrease the farther its natural gas is transported for sale because of increased transportation costs, which may reduce the partnership’s distributions to you and the other investors in the partnership.

Natural Gas Production May Be Delayed Until Construction of the Necessary Gathering Lines and Production Facilities is Completed, Which Could Delay Partnership Distributions. A partnership’s distributions to you and the other investors may be delayed, in the case of a natural gas well, if it is necessary to construct gathering lines for the new productive wells or upgrade or construct production facilities in the area to transport, process or increase natural gas production, which could delay partnership distributions. See “Proposed Activities – Sale of Natural Gas and Oil Production – Gathering of Natural Gas.”

The Managing General Partner May Elect to Curtail a Partnership’s Natural Gas or Oil Production. Natural gas and oil production from a partnership’s wells may be delayed due to low prices, in the managing general partner’s discretion, or until construction of the necessary gathering lines or production facilities for natural gas from the partnership’s productive wells is completed, which may be in the control of a third-party purchaser or owner of the related pipeline. Any curtailments or high pressures on the natural gas gathering system in the future could delay drilling and completing one or more of a partnership’s natural gas wells until the problems are resolved.

 

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The Partnerships May Not Be Paid, or May Experience Delays in Receiving Payment, for Their Natural Gas and Oil That Has Already Been Delivered to the Purchaser. There is a credit risk associated with a purchaser’s ability to pay. In accordance with industry practice, each partnership typically will deliver natural gas and oil 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, or may experience additional delays in receiving payment, for natural gas and oil that already has been delivered if the purchaser, including natural gas or oil sold to Snyder Brothers, Inc., an affiliate of the managing general partner, 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 and oil or the partnership’s negotiation of different terms and arrangements for selling its natural gas and oil to other purchasers. Finally, this credit risk may reduce the price benefit derived by a partnership from its natural gas and oil hedging arrangements as described in “Proposed Activities – Sale of Natural Gas and Oil Production – Natural Gas and Oil Partnership Hedging Activities,” since from time to time it may implement a portion or all of the hedges through the purchasers.

Some or All of a Partnership’s Proposed Wells May Subsequently Be Replaced by the Managing General Partner. Whether a proposed well is drilled by a partnership depends on the managing general partner’s analysis, which may not be accurate, of many factors, including the current spot market price of natural gas and oil, the price of natural gas and oil on the futures market, the anticipated cost to drill the well and the expected volume of production of natural gas or oil from the well. The managing general partner generally places more emphasis on the anticipated future market price of natural gas and oil since significant revenues from the wells that the partnership will drill are not expected to begin until approximately eight months after the offering period for the partnership ends and, although not anticipated by the managing general partner, it may take up to 12 months or longer before all the wells in the partnership have been drilled and completed and are online for the sale of their production. If the price of natural gas and oil on the futures market declines over a partnership’s scheduled drilling period, then some or all of the wells selected to be drilled by the partnership may become uneconomical to drill, in which case the managing general partner may replace and not drill the first well.

Possible Leasehold Defects Arising During Drilling Operations Could Result in Unanticipated Losses. There may be defects in a partnership’s title to its leases. Although the managing general partner or an affiliate will obtain a favorable formal title opinion for the leases before each well is drilled, no division order title opinion will be obtained after the well is completed. Thus, a partnership may experience losses from title defects which arose during drilling that would have been disclosed by a division order title opinion, such as liens arising during drilling operations. Also, the managing general partner may use its own judgment in waiving title requirements for a partnership’s leases and it will not be liable for any failure of title of leases transferred to the partnership. See “Proposed Activities – Title to Properties.”

A horizontal well drilled by a partnership, if any, may encroach on acreage that has been assigned to prior drilling partnerships sponsored by the managing general partner or its affiliates. In this event, the encroachment will be waived and allowed by the prior partnership without restriction or charge to the partnership in this program unless the managing general partner determines, in its discretion, that the encroachment results in drainage from one or more of the prior partnership’s wells. In that event, the partnership in this program would compensate the prior partnership for the drainage, either by a cash payment or an overriding royalty interest or portion of the working interest owned by the partnership in the partnership’s well that encroaches on the prior partnership’s acreage, as determined by the managing general partner in its discretion, consistent with its fiduciary duties to both of the partnerships. The foregoing may also apply to the partnerships in this program and their wells with respect to horizontal drilling conducted by other drilling partnerships sponsored by the managing general partners in the future.

The Leases and Wells May Be Subject to Claims of the Managing General Partner’s Creditors Because the Leases Will Not Be Transferred Until the Wells are Completed. Because the leases will not be transferred from the managing general partner to a partnership until after the wells are drilled and completed, the transfer could be set aside by a creditor of the managing general partner, or the trustee in the event of the voluntary or involuntary bankruptcy of the managing general partner, if it were determined that the managing general partner received less

 

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than a reasonably equivalent value for the leases. In this event, the leases and the wells would revert to the creditors or trustee, and the partnership would recover either nothing or only the amount it paid for the leases and the cost of drilling the wells. See “Proposed Activities – Title to Properties.” Assigning the leases to a partnership after its wells are drilled and completed, however, will not affect the availability of the tax deductions for intangible drilling costs since the partnership will have an economic interest in the wells under the drilling and operating agreement before the wells are drilled. See “Federal Income Tax Consequences – Drilling Contracts.”

Participation with Third-Parties in Drilling Wells May Require a Partnership to Pay Additional Costs. The managing general partner, its affiliates or third-parties may participate with a partnership in drilling one or more of the partnership’s wells. In this regard, additional financial risks exist when the costs of drilling, equipping, completing, and operating wells are shared by more than one person. If the partnership pays its share of the costs, but another interest owner does not pay its share of the costs, then the partnership would have to pay the costs of the defaulting party. In this event, the partnership would receive the defaulting party’s revenues from the well, if any, under penalty arrangements set forth in the operating agreement, which may, or may not, cover all of the additional costs paid by the partnership.

If the managing general partner is not the actual operator of the well for all of the working interest owners of the well, then there is a risk that the managing general partner cannot supervise the third-party operator closely enough. For example, decisions related to the following would be made by the third-party operator and may not be in the best interests of the partnership and you and the other investors in the partnership:

 

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how the well is operated;

 

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expenditures related to the well; and

 

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possibly the marketing of the natural gas and oil 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 material’s and workmen’s liens. In this regard, the managing general partner may not be the operator of a well for all of the working interest owners of the well if the partnership owns less than a 50% working interest in the well or if the managing general partner acquired the working interest in the well from a third-party under arrangements that required the third-party to be named operator as one of the terms of the acquisition.

Also, if there is a third-party operator of a partnership well, which is not anticipated by the managing general partner in the case of vertical wells to be drilled in the Marcellus Shale primary area in western Pennsylvania, each partnership’s share of revenues, if any, from the sale of natural gas and oil produced by the well to be drilled may first be temporarily held in a separate bank account by the third-party operator to allow it to pay each working interest co-owner’s (including the partnership’s) respective share of the operating costs of the wells and landowner royalties, overriding royalty interests and any other burdens on the leases covering the wells, before it distributes the partnership’s share of the net proceeds to the partnership. This creates a risk that the partnership’s production revenues from a well operated by a third-party, if any, will be subject to claims by the third-party’s creditors before they are paid to the partnership.

Risks Related to an Investment in a Partnership

If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner. If you elect to invest in a partnership as an investor general partner for the tax benefits instead of as a limited partner, then under Delaware law you will have unlimited liability for the partnership’s activities until you are converted to limited partner status, subject to certain exceptions described in “Actions To Be Taken by Managing General Partner To Reduce Risks of Additional Payments By Investor General Partners – Conversion of Investor General Partner Units to Limited Partner Units.” This could result in you being required to make payments, in addition to your original investment, in amounts that are impossible to predict because of their uncertain nature. Under the

 

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terms of the 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, a partnership may own less than 100% of the working interest in one or more of its wells. If a court holds the partnership and the other third-party working interest owners of the well liable for the development and operation of a well and the third-party working interest owners do not pay their proportionate share of the costs and liabilities associated with the well, then the partnership and you and the other investor general partners also would be liable for those costs and liabilities.

As an investor general partner you may become subject to the following:

 

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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 improper disposal of water from the partnership’s wells, 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 general partner cannot insure because coverage is not available or against which it may elect not to insure because of high premium costs or other reasons; and

 

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liability for drilling hazards that result in property damage, personal injury, or death to third-parties in amounts greater than the insurance coverage. The drilling hazards include, but are not limited to, well blowouts, fires, craterings and explosions.

See “Proposed Activities – Insurance Claims.”

If the partnership’s insurance proceeds and assets, the managing general partner’s indemnification of you and the other investor general partners, and the liability coverage provided by subcontractors were not sufficient to satisfy the liability, then the managing general partner would call for additional funds from you and the other investor general partners to satisfy the liability. See “Actions to Be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners.” Additionally, any of the drilling hazards may result in the loss of the well and the associated revenues. Finally, an investor general partner may have liability if the partnership does not properly plug and abandon a well.

The Managing General Partner May Not Meet Its Capital Contributions, Indemnification and Purchase Obligations If Its Liquid Net Worth Is Not Sufficient. The managing general partner has made commitments to you and the other investors in your partnership regarding the following:

 

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contributing the leases for the partnership’s wells and paying the partnership’s organization and offering costs;

 

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indemnification of the investor general partners for liabilities in excess of their pro rata share of partnership assets and insurance proceeds; and

 

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purchasing units presented by an investor, although this feature may be suspended by the managing general partner if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds or arrange other consideration for this purpose on reasonable terms.

However, a significant financial reversal for the managing general partner could adversely affect its ability to honor these obligations as discussed below. Also, see “Management’s Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources” for a discussion of the credit facility obtained by MDS Associated Companies, Inc., which is the managing general partner’s parent company.

 

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The managing general partner’s net worth is based primarily on the estimated value of its producing natural gas properties and is not available in cash without borrowings or a sale of the properties. If natural gas prices decrease, then the estimated value of the properties and the managing general partner’s net worth will be reduced since the majority of the managing general partner’s proved reserves are currently natural gas reserves, and the managing general partner’s net worth is more susceptible to movements in natural gas prices than in oil prices. Further, price decreases will reduce the managing general partner’s revenues, and may make some oil and gas reserves uneconomic to produce. This would reduce the managing general partner’s reserves and cash flow.

The managing general partner’s net worth may not be sufficient, either currently or in the future, to meet its financial commitments under the partnership agreement. These risks are increased because the managing general partner intends to make similar financial commitments in partnerships it sponsors in the future. In addition, because of the current credit crisis in the United States, there is a risk that the managing general partner’s ability to borrow funds could be adversely affected. See “Financial Information Concerning the Managing General Partner and MDS Energy Public 2012-A LP.”

An Investment in a Partnership Must be for the Long-Term Because the Units Are Illiquid and Not Readily Transferable. If you invest in a partnership, then you must assume the risks of an illiquid investment. The transferability of the units is limited by the securities laws, the tax laws, and the partnership agreement. The units generally cannot be liquidated since there is no readily available market for the sale of the units. Further, the partnership does not intend to list its units on any exchange. See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”

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

Each Partnership Must Receive Offering Proceeds of At Least $2 Million from You and Its Other Investors Before It Can Begin Drilling Activities. When each partnership was formed under the Uniform Revised Limited Partnership Act of Delaware, the partnership received only a nominal amount of initial capital from the managing general partner and its affiliates. See “Financial Information Concerning the Managing General Partner and MDS Energy Public 2012-A LP.” Thus, each partnership must receive at least $2 million of offering proceeds from its investors before it can have its initial closing and begin drilling activities. In addition, the number of wells drilled by each partnership will depend primarily on the amount of offering proceeds it receives in this offering. See “– 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,” below.

A Partnership’s Wells May Not be Diversified Over Different Drilling Areas or Different Geological Formations. The managing general partner anticipates that all of each partnership’s wells will be drilled vertically to the Marcellus Shale geological formation in western Pennsylvania as discussed in “Proposed Activities,” In that event, the partnership’s drilling risks would not be diversified by drilling wells in different areas or to different geological formations, which increases the risk that you and the other investors in the partnership will not receive a return of your subscription proceeds or a return on your investment in the partnership. Notwithstanding, up to 25% of a partnership’s subscription proceeds may be used to drill horizontal wells in the Marcellus Shale primary area and up to 20% of a partnership’s subscription proceeds may be used to drill either vertical or horizontal wells in other areas of the United States, in the managing general partner’s discretion. See “– No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature of Drilling Natural Gas and Oil Wells,” above.

 

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Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled. Each partnership must receive minimum subscription proceeds of $2 million to close the offering, and the subscription proceeds of all three partnerships, in the aggregate, may not exceed $300 million. There are no other requirements regarding the size of a partnership and the subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of another partnership. A partnership with a smaller amount of subscription proceeds will drill fewer wells, which would decrease the partnership’s ability to spread the risks of drilling. For example, the managing general partner anticipates that the partnership will drill approximately 1.64 net vertical development wells, which is not less than two gross development wells, if the minimum subscriptions are received, which is compared with approximately 246.2 net vertical development wells, which is not less than 247 gross development wells, if the maximum subscription proceeds of $300 million are received and all of the wells are vertical wells drilled in the Marcellus Shale primary area. See “Compensation – Drilling Contracts,” however, for a discussion of the estimated average well cost of drilling and completing both vertical and horizontal wells in the Marcellus Shale primary area. A gross well is a well in which the partnership owns a working interest. This is compared with a net well, which is the sum of the fractional working interests owned in the gross wells. For example, a 50% working interest owned in three wells is three gross wells, but 1.5 net wells.

On the other hand, to the extent more than the minimum subscription proceeds are received by a partnership and the number of wells drilled increases, the partnership’s overall investment return may decrease if the managing general partner is unable to find enough suitable wells to be drilled. See “Proposed Activities – Acquisition of Leases.” Also, to the extent the partnership’s subscription proceeds and number of wells it drills increase, greater demands will be placed on the managing general partner’s management capabilities.

Increases in the Costs of the Wells or Cost Overruns May Adversely Affect Your Return. Increases in natural gas and oil prices over the last several years (excluding the recent decrease in natural gas prices) have also increased the demand for drilling rigs and other related equipment and the costs of drilling and completing natural gas and oil wells. Because the partnership’s wells will be drilled on a modified cost plus basis as described in “Capitalization and Source of Funds and Use of Proceeds,” the costs to drill and complete the partnership’s wells could be greater than those estimated by the managing general partner in “Compensation – Drilling Contracts.” This means that if an increase in natural gas and oil prices occurs before the partnership drills its wells and causes the drilling costs for the partnership’s wells to increase, which may happen since the prices are volatile, then fewer wells may be drilled by the partnership than it would have drilled if the drilling and completion costs of the wells had not increased.

On the other hand, if the price of natural gas and oil 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 general partner believes that, in the short term, drilling and completion costs are not likely to be reduced by a drop in natural gas and oil prices. Also, a reduced availability of drilling rigs and other related equipment may make it more difficult to drill the partnership’s wells in a timely manner to comply with the prepaid intangible drilling costs rules discussed in “Federal Income Tax Consequences – Drilling Contracts.”

In addition, the cost of drilling and completing wells is uncertain and there may be cost overruns in drilling and completing the wells since the wells will not be drilled and completed on a turnkey basis for a fixed price that would shift certain risks of cost overruns from the partnership to the managing general partner as drilling contractor. In this regard, all of the intangible drilling costs and equipment costs of your partnership’s wells will be charged to you and the other investors in the partnership. If the partnership incurs a cost overrun in drilling or completing a well or wells, then the managing general partner anticipates that it would use the partnership’s subscription proceeds, if available, to pay the cost overrun, advance the necessary funds itself to the partnership, or cause the partnership to borrow the necessary funds from third-party lenders, if available. Using subscription proceeds to pay cost overruns may result in the partnership drilling fewer wells. See “Compensation – Drilling Contracts.”

 

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The Partnerships Do Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects Are Acquired By a Partnership, and the Lack of Information for Any Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership. The partnerships do not currently hold any interests in any prospects on which the wells will be drilled, and the managing general partner has absolute discretion in determining which prospects will be acquired to be drilled. If there are material adverse events with respect to any of the currently proposed prospects in Appendix A for MDS Energy Public 2012-A LP, the managing general partner will substitute a new prospect. With respect to the identified prospects to be drilled by the partnership, the managing general partner has the right on behalf of the partnership to:

 

•

substitute other prospects;

 

•

take a lesser working interest in the prospects; 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 general partner will choose those prospects which it believes are most suitable for the partnership. You must rely entirely on the managing general partner to select the prospects and wells for the partnership.

In addition, the partnerships do not have the right of first refusal in the selection of prospects from the inventory of the managing general partner and its affiliates, and they may sell their prospects to other partnerships, companies, joint ventures, or other persons at any time. Also, the managing general partner and its affiliates may elect to drill a well for their own account because of the prospective economic benefits. For example, because the partnership agreement limits the amount of revenue that may be received by the managing general partner and its affiliates from the partnerships, it may be more advantageous for the managing general partner and its affiliates to drill the well for their own account. See “Proposed Activities” and “Conflicts of Interest.”

Drilling Multiple Wells Only in One Area and At the Same Time May Increase the Risk of Drilling Marginal or Nonproductive Wells. The managing general partner intends that multiple wells will be drilled by each partnership in the Marcellus Shale primary area at approximately the same time. Thus, there is a greater risk that two or more of the wells will be marginal or nonproductive since the managing general partner will not be using the drilling results of one or more of those wells to decide whether or not to continue drilling prospects in that area or to substitute other prospects in other areas. This is 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 any 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, even though your partnership may prepay 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 the next 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 increase the risk as described above if the managing general partner is required to begin drilling many wells at the same time, rather than only a few wells. Also, “frost laws” 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, which could delay the partnership’s drilling activities. See “Federal Income Tax Consequences – Drilling Contracts” regarding prepaid wells and the 90 day time constraint, and “– Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership” regarding the proposed repeal of the election to currently expense intangible drilling costs paid or incurred after December 31, 2012.

 

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Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of Each Partnership’s Drilling Program. Production information from wells previously drilled to the same geological formation in the area surrounding the location where a new well is proposed to be drilled is an important indicator in evaluating the economic potential of the well proposed to be drilled. However, generally there will be little or no production information from surrounding wells for the majority of the wells to be drilled by a partnership, which results in greater uncertainty to you and the other investors. This lack of production information sometimes results from the managing general partner, as operator, proposing wells to be drilled by the partnership that are adjacent to or relatively close to wells that have previously been drilled to the geological formation, but have not yet been completed, have not yet been put on-line to sell production, or have been producing for only a short period of time so there is little or no production information available.

Also, if the managing general partner was not the operator of a previously drilled well then the production information may not be available from the third-party operator or state records filed by the third-party operator if the well was drilled within the last five years in Pennsylvania since in the past the Pennsylvania Department of Environmental Resources (the “Department”) has kept production data confidential for the first five years from the time a well starts producing, although the Department currently appears to be making production data for Marcellus Shale wells available to the public as it receives the information.

The Partnerships in This Program and Other Partnerships Sponsored by the Managing General Partner and its Affiliates May Compete With Each Other for Prospects, Equipment, Subcontractors, and Personnel. The managing general partner anticipates that the partnerships in this program and other partnerships sponsored by the managing general partner or its affiliates, including other Regulation D offerings that are currently being offered by the managing general partner and M/D Gas, Inc., or joint ventures in which the managing general partner and its affiliates participate, will have unexpended capital funds at the same time. Thus, these partnerships or joint ventures will compete for suitable prospects, equipment, subcontractors, and the services of the managing general partner’s and its affiliates’ personnel. In addition to the other current partnership offerings, for example, a partnership organized by the managing general partner or M/D Gas, Inc. in the future may be acquiring prospects to drill in the same areas at the same time a partnership in this program is attempting to acquire its prospects. This may make it more difficult for the partnership in this program to complete its prospect acquisition and drilling activities and may make the partnership less profitable. Also, the managing general partner and its affiliates may choose to drill certain wells for their own account at any time.

Managing General Partner’s Subordination is Not a Guarantee of the Return of Any of Your Investment. If your cumulative cash distributions from your partnership are less than the amounts described in “Participation in Costs and Revenues – Subordination of Portion of Managing General Partner’s Net Revenue Share” during the partnership’s eight 12-month subordination periods, then the managing general partner has agreed to subordinate a portion of its share of the partnership’s net production revenues. However, if the wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination you may not receive the intended return of capital during the partnership’s 96-month aggregate subordination period, or a return of all of your capital during the term of the partnership. Also, at any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cumulative cash distributions from the partnership would exceed the intended return of capital.

Borrowings by the Managing General Partner Could Reduce Funds Available for Its Subordination Obligation. Subject to its subordination obligation and a required 1% minimum participation interest in each partnership, unless there is a substituted managing general partner, the managing general partner may pledge either its partnership interest and/or an undivided interest in the partnership’s assets equal to or less than its revenue interest in the partnership, which depends on the amount of its capital contribution to the partnership and is not yet known, to secure borrowings for its and its affiliates’ general purposes. See “Conflicts of Interest – Conflicts Regarding Managing General Partner Withdrawing or Assigning an Interest.” Under agreements previously entered into, as described in “Management’s Discussion and Analysis of Financial Condition, Results

 

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of Operations, Liquidity and Capital Resources,” MDS Associated Companies, Inc.’s lenders have required a first lien on its assets, including the managing general partner’s interest in the natural gas and oil properties and other assets of each partnership, which will not include the interests of you and the other investors in the partnership, and the lenders will have priority over the managing general partner’s subordination obligation under the partnership agreement. If there was a default by MDS Associated Companies, Inc. or an affiliate to the lenders under this pledge arrangement, the amount of the partnership’s net production revenues available to the managing general partner for its subordination obligation to you and the other investors would be reduced or eliminated. Also, under certain circumstances, if the managing general partner made a subordination distribution to you and the other investors after a default by MDS Associated Companies, Inc. or an affiliate to its lenders, then the lenders may be able to recoup that subordination distribution from you and the other investors. In addition, there is a risk that the current credit crisis in the United States could adversely affect MDS Associated Companies, Inc.’s ability to borrow funds under its credit facility.

Compensation and Fees to the Managing General Partner Regardless of Success of a Partnership’s Activities Will Reduce Cash Distributions. The managing general partner and its affiliates will profit from their services in drilling, completing, and operating each partnership’s wells, and will receive the other fees and reimbursement of direct costs described in “Compensation,” regardless of the success of the partnership’s wells. These fees and direct costs paid by your partnership will reduce the amount of cash distributions to you and the other investors. The amount of the fees is subject to the complete discretion of the managing general partner, other than the fees must not exceed competitive fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses and there must be compliance with any other restrictions set forth in “Compensation.” With respect to direct costs, the managing general partner has sole discretion on behalf of the partnerships to select the provider of the services or goods and the provider’s compensation as discussed in “Compensation.”

The Intended Monthly Distributions to Investors May be Reduced or Delayed. Cash distributions to you and the other investors may not be paid by your partnership each month. Distributions may be reduced or deferred, for example, in the discretion of the managing general partner, to the extent a partnership’s revenues are used for any of the following:

 

•

compensation and fees to the managing general partner and its affiliates as described in “Compensation”;

 

•

repayment of partnership borrowings, if any;

 

•

any cost overruns in drilling and completing wells;

 

•

remedial work to improve a well’s producing capability, including additional fracks for wells and drilling through the frack plugs previously set in a well;

 

•

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 general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership’s activities.

See “Participation in Costs and Revenues – Distributions.”

Conflicts of Interest Between the Managing General Partner and the Investors May Not Necessarily Be Resolved in Favor of the Investors. There are conflicts of interest between you and the other investors in your partnership and the managing general partner and its affiliates. These conflicts of interest, which are not otherwise discussed in this “Risk Factors” section, include the following:

 

•

the managing general partner 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 arms’ length on behalf of you and the other investors;

 

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•

the managing general partner must monitor and enforce, on behalf of the partnership, its compliance with the drilling and operating agreement and the partnership agreement and its affiliates’ compliance with their gas gathering, marketing, hedging, and other service agreements;

 

•

the managing general partner anticipates that most, if not all, of the partnership’s natural gas will be transported through pipelines owned by Snyder Brothers, Inc., an affiliate of the managing general partner, at competitive rates and sold to Snyder Brothers, Inc. or other affiliates of the managing general partner at competitive prices in the area;

 

•

because the managing general partner will receive a percentage of revenues greater than the percentage of its capital contribution to the partnership, there may be a conflict of interest concerning which wells will be drilled based on each well’s risk and profit potential;

 

•

the allocation of all intangible drilling costs and equipment costs to you and the other investors may create a conflict of interest concerning whether to drill or complete a well;

 

•

if the managing general partner, 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 deductions for intangible drilling costs or depreciation of equipment costs, or the managing general partner’s credit to its capital account for contributing the leases to the partnership;

 

•

which wells will be drilled by the managing general partner’s and its affiliates’ for their own account or other affiliated partnerships, third-party programs or joint ventures with third-parties, in which they serve as driller/operator, and which wells will be drilled by the partnership, and the terms on which the partnership’s leases will be acquired;

 

•

the managing general partner’s policies and procedures for hedging the partnership’s natural gas production are not set forth in any written agreements and as the managing general partner continues to sponsor natural gas and oil drilling partnerships in the future, any future interests of its existing partnerships, including this partnership, in the risks and benefits of hedging agreements entered into on behalf of both a partnership in this offering and one or more other partnership’s sponsored by the managing general partner or its affiliates may be diluted unless the managing general partner or its affiliates continue their hedging activities as the new partnerships produce additional natural gas reserves;

 

•

although not anticipated by the managing general partner, subject to certain limitations described in “Conflicts of Interest – Conflicts Involving the Acquisition of Leases,” the managing general partner will have complete discretion in determining the terms on which it or its affiliated limited partnerships may purchase producing wells from the partnership;

 

•

the managing general partner and its officers, directors, and affiliates may purchase units in the partnership at a reduced price, which would dilute the voting rights of you and the other investors on certain matters; and

 

•

the same legal counsel represents the managing general partner and the partnership.

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

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 units in a partnership

 

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closes you may present your units to the managing general partner for purchase. The amount of your presentment price for your units will be determined by the two methods set forth below and you will receive the greater amount for your units:

 

•

three times the amount of the partnership’s total distributions to you during the previous twelve months; or

 

•

the amount that is generally attributable to your share of the partnership’s natural gas and oil reserves, as discussed below.

However, the managing general partner may determine, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds for this purpose on reasonable terms. In either event the managing general partner may suspend the presentment feature. This risk is increased because the managing general partner expects to incur similar presentment obligations in other partnerships it sponsors in the future.

The presentment price based on three times the amount of your distributions from the partnership during the previous 12 months may not reflect the full value of your units. See “– The Intended Monthly Distributions to Investors May be Reduced or Delayed,” above. For example, if all or a portion of partnership revenues during the 12 months preceding the calculation of your presentment price were used to pay the costs of plugging and abandoning a partnership well, instead of paying distributions to you and the other investors, then your presentment price for your units based on three times the partnership distributions during that 12-month period also would be reduced and could be less than your presentment price would have been if you had held your units and presented them for purchase at a later time when partnership distributions were not being used during the preceding 12 month period to pay plugging and abandonments costs, and instead were distributed to you and the other investors. Thus, the presentment price paid for your units that is based on three times the amount of the partnership distributions received by you during the 12 months before the presentment plus the amount of any partnership distributions received by you before the presentment may be less than the subscription amount you paid for your units.

Also, the presentment price for your units that is based primarily on your share of the partnership’s natural gas and oil reserves may not reflect the full value of the partnership’s property or your units because of the difficulty in accurately estimating natural gas and oil reserves. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way, and the accuracy of the reserve estimate is a function of the quality of the available data and of engineering and geological interpretation and judgment. Also, the reserves and future net revenues are based on various assumptions as to natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in these assumptions, including the price of natural gas and oil, could materially affect the estimated quantity of the reserves. As a result, the managing general partner’s reserve estimates are inherently imprecise and may not correspond to realizable value. Thus, the presentment price for your units based primarily on the partnership’s natural gas and oil reserves plus the amount of any partnership distributions received by you before the presentment may be less than the subscription amount you paid for your units. Since the presentment price that is based primarily on the partnership’s natural gas and oil reserves is a contractual price under the partnership agreement, 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 of the partnership’s estimated net cash flow and the presentment amount to be paid. See “Presentment Feature.” Also, see “– An Investment in the Partnership Must be for the Long-Term Because the Units Are Illiquid and Not Readily Transferable,” above, concerning the tax effects on you of presenting your units for purchase.

The Managing General Partner May Not Devote the Necessary Time to the Partnerships Because Its Management Obligations Are Not Exclusive. The partnerships do not have any employees and they must rely on the managing general partner and its affiliates for the management of them and their respective businesses, and the managing general partner and its affiliates may not devote the necessary time to the partnerships, which is in

 

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the managing general partner’s discretion. In this regard, the managing general partner depends on its affiliates, primarily MDS Energy, Ltd. and First Class Energy, LLC, for management and administrative functions as discussed in “Management.”

Also, the managing general partner and its affiliates, including Snyder Brothers, Inc., will be engaged in other oil and gas activities, such as other affiliated partnerships, joint ventures and unrelated business ventures for their own account or for the account of others, during the term of each partnership. Thus, the competition for time and services of the managing general partner and its affiliates could result in insufficient attention to the management and operation of a partnership.

Prepaying Subscription Proceeds to the Managing General Partner May Expose the Subscription Proceeds to Claims of the Managing General Partner’s Creditors. Under the drilling and operating agreement, each partnership will be required to immediately pay the managing general partner, acting as general drilling contractor, the entire estimated price for drilling and completing the partnership’s wells. Thus, these funds could be subject to claims of the managing general partner’s creditors. See “Financial Information Concerning the Managing General Partner and MDS Energy Public 2012-A LP.”

A Lengthy Offering Period May Result in Delays in the Investment of Your Subscription and Any Cash Distributions From Your Partnership to You. Because the offering period for a partnership can extend for many months, there may be a delay in the investment of your subscription proceeds. This may create a delay in your 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 oil, and payment has been received from the purchaser of the production. Also, distributions of the partnership’s net production revenues will be made only after payment of the managing general partner’s fees and expenses and only if there is sufficient cash available, which is in the managing general partner’s discretion. See “Terms of the Offering” for a discussion of the procedures involved in the offering of the units and the formation of the partnerships.

The Partnerships Are Subject to Comprehensive Federal, State and Local Laws and Regulations That Could Increase the Cost and Alter the Manner or Feasibility of the Partnerships Doing Business. Each 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 natural gas and oil wells. For example, environmental violations could include the discharge of water, silt-laden runoff and any resulting erosion from a well site, the discharge of residual and industrial waste such as diesel fuel and production fluids from a well site, and failing to restore a well site to its previous condition within the time frame required by Pennsylvania. See “Competition, Markets and Regulation – Environmental Regulation” for a more detailed discussion.

Under these laws and regulations, a partnership and its investor general partners could also be liable for personal injuries, property damage and other damages. In addition, failure to comply with existing or future 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 partnerships will operate may include legal requirements for obtaining environmental assessments, water disposal plans, environmental impact studies and/or plans of development before beginning drilling and production activities. Further, the natural gas and oil 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 partnerships’ profitability, including the possibility of future regulations imposing additional requirements on the treatment and disposal of water and waste produced from the wells. In this regard, the partnerships may be 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 laws and regulations that affect the partnerships.

 

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Future Hedging Activities May Adversely Affect a Partnership’s Financial Condition and Results of Operations. All of the purchase contracts under which each partnership will sell its natural gas and oil will provide that the price paid by the purchaser may be adjusted upward or downward in accordance with the spot market price and market conditions and natural gas and oil prices are volatile and could decrease in the future. To limit exposure to changing natural gas and oil prices, the partnerships may enter into hedging arrangements through Snyder Brothers, Inc., an affiliate of the managing general partner, and any other natural gas and oil purchasers, for up to 50% of their respective natural gas and oil production. In this regard, the percentages of a partnership’s natural gas and oil production that are hedged through financial hedges, physical hedges, or not hedged at all, will change from time to time, in the discretion of the managing general partner, but will not exceed 50%. Also, the partnerships will not participate in the hedging pool operated by Snyder Brothers, Inc., an affiliate of the managing general partner, which may or may not provide better results to a partnership’s participants than the partnership’s own hedging arrangements.

By using hedging arrangements, a partnership will reduce, but not eliminate, the potential effects of changing natural gas and oil prices on a portion, which may be substantial, of the cash flow from the partnership for the periods covered by the hedges. Furthermore, while intended to help reduce the effects of volatile natural gas and oil prices, such transactions, depending on the hedging instrument used, may limit the potential gains for the partnership if natural gas and oil prices were to rise substantially over the price established by the hedge. Also, the partnership could incur liability on the financial hedges. For example, a partnership would be exposed to the risk of a financial loss if any of the following occur:

 

•

the partnership’s production is substantially less than expected;

 

•

the counterparties to the futures contracts fail to perform under the contracts, the risk of which is increased because of the current credit crisis in the United States; or

 

•

there is a sudden, unexpected event materially impacting natural gas and oil prices.

See “Proposed Activities – Sale of Natural Gas and Oil Production – Natural Gas Contracts” for a more detailed discussion.

Your Interests May Be Diluted Because Units May Be Sold At Discounted Prices to Certain Classes of Investors. The equity interests of you and the other investors in your partnership may be diluted. You and the other investors will share in the partnership’s production revenues from all of its wells in proportion to your respective number of units, based on $10,000 per unit, regardless of:

 

•

when you subscribe;

 

•

which wells are drilled with your subscription proceeds; or

 

•

the actual subscription price you paid for your units as described below.

Thus, investors who pay discounted prices for their units will receive higher returns on their investments in the partnership as compared to investors who pay the entire $10,000 per unit. In this regard, some investors, including the managing general partner and its officers as described in “Plan of Distribution,” may buy units in the partnership at discounted prices because certain dealer-manager fees and sales commissions will not be paid for those sales.

Resignation or Removal of Managing General Partner, or Loss of Key Management Personnel from the Partnerships’ Managing General Partner, Could Adversely Affect the Partnerships’ Ability to Conduct Their Business. Each partnership’s future success depends to a significant degree on the continued service of its managing general partner and its management team and, in particular, Mr. Michael D. Snyder, the managing general partner’s Chief Executive Officer and President. The managing general partner has not entered into any employment agreement with Mr. Snyder or its other officers and it and its affiliates may be unable to retain employees or attract and retain new employees, either of which could materially and adversely affect a partnership’s ability to conduct its business. The partnerships and the managing general partner do not maintain key man life insurance with respect to Mr. Snyder.

 

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Due to the Accounting Treatment of the Partnerships’ Derivative Contracts, Increases in Prices for Natural Gas and Oil Could Result in Non-Cash Balance Sheet Reductions. The managing general partner, its affiliates, its affiliated partnerships, and the partnerships will enter into natural gas and oil derivative contracts and account for the derivative contracts by applying the provisions of Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Due to the mark-to-market accounting treatment for these contracts, the managing general partner, its affiliates and a partnership could recognize incremental hedge liabilities between reporting periods resulting from increases in reference prices for natural gas and oil, which could result in the managing general partner, its affiliates and the partnership recognizing a non-cash loss in their accumulated other comprehensive income (loss) and a consequent non-cash decrease in their members’ equity between reporting periods. Any such decrease could be substantial.

A Decrease in Natural Gas and Oil Prices Could Subject the Partnerships’ and the Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles. Generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. The managing general partner and each partnership assess their producing natural gas properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the managing general partner reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of natural gas and oil. Certain events, including but not limited to, downward revisions in estimates to their reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore, a possible impairment of the managing general partner’s and a partnership’s proved natural gas and oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs, and is measured by the amount by which the net capitalized costs exceed their fair value. Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows are determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas reserves. Due to the availability of new reserve information, the managing general partner and the partnerships intend to review their respective proved natural gas properties for impairment at December 31, 2012. Future declines in the price of natural gas and oil may cause the carrying value of the partnerships’ or the managing general partner’s respective oil and gas properties to exceed the expected future cash flows, and require an impairment loss to be recognized.

Federal Income Tax Risks

Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership. Your tax benefits from an investment in your partnership may be affected by changes in the tax laws. For example, President Obama’s administration has proposed, beginning January 1, 2013, among other tax changes, the repeal of certain oil and 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 credit. These proposals may or may not be enacted into law. Also, other changes in the tax laws could be made that would reduce your tax benefits from an investment in a partnership. See “Federal Income Tax Consequences.”

Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum Tax. Under current tax law, your alternative minimum taxable income in the year in which you invest in a partnership cannot be reduced by more than 40% by your share of the partnership’s deduction for intangible drilling costs. See “Federal Income Tax Consequences – Alternative Minimum Tax.”

Limited Partners Need Passive Income to Use Their Partnership Deductions. If you invest in a partnership as a limited partner (except as discussed below), your share of the partnership’s deductions for intangible drilling

 

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costs and depreciation, if any, 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 deductions from your partnership in the year you invest. However, any unused passive loss from the deduction for intangible drilling costs and depreciation deductions, if any, 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 deductions 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 which:

 

•

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.”

You May Owe Taxes in Excess of Your Cash Distributions from Your Partnership. You may become subject to income tax liability for your share of your partnership’s income in any taxable year in an amount that is greater than the cash you receive from the partnership in that taxable year. For example:

 

•

if the partnership borrows money, your share of partnership revenues used to pay principal on the loan will be included in your income from the partnership and will not be deductible;

 

•

income from sales of natural gas and oil may be included in your income from the partnership in one tax year, even though payment is not actually received by the partnership and, thus, cannot be distributed to you, until the next tax year;

 

•

if there is a deficit in your capital account, the partnership may allocate income or gain to you even though you do not receive a corresponding distribution of partnership revenues;

 

•

the partnership’s revenues may be expended by the managing general partner for nondeductible costs or retained in the partnership to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning the wells, which will reduce your cash distributions from the partnership without a corresponding tax deduction; and

 

•

the taxable disposition of the partnership’s property or your units may result in income tax liability to you in excess of the cash you receive from the transaction.

Investment Interest Deductions of Investor General Partners May Be Limited. If you invest in a partnership as an investor general partner, your share of the partnership’s deduction for intangible drilling costs in the year you invest will reduce your investment income and may limit the amount of your deductible investment interest expense, if any.

Your Tax Benefits from an Investment in a Partnership Are Not Contractually Protected. An investment in a partnership does not give you any contractual protection against the possibility that part or all of the intended tax benefits of your investment will be disallowed by the IRS. No one provides any insurance, tax indemnity or similar agreement for the tax treatment of your investment in 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 is ultimately disallowed by the IRS or the courts. Also, none of the fees paid by the partnership to the managing general partner, its affiliates or

 

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independent third-parties (including special counsel which issued the tax opinion letter) are refundable or contingent on whether the intended tax consequences of your investment in the partnership are ultimately sustained if challenged by the IRS.

Your Partnership’s Deductions May be Challenged by the IRS. If the IRS audits your 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, if any. 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, and could lead to an audit of your personal federal income tax returns, including prior years’ returns and items that are unrelated to the partnership. The IRS also could seek to recharacterize 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 could 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.” This risk may be increased to the extent the partnership prepays intangible drilling costs in 2012 for wells the drilling of which will not begin until 2013. See “– Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership”, above, and “Federal Income Tax Consequences – Drilling Contracts.”

It May Be Many Years Before You Receive Any Marginal Well Production Credits, If Ever. Currently there is a federal income tax credit for the sale of qualified marginal natural gas and oil production, which President Obama’s administration has proposed to repeal as discussed in “– Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership,” above. The managing general partner anticipates that some of each partnership’s natural gas and oil production may be qualified marginal production for purposes of this tax credit. However, it is anticipated that in the early years of the partnership, when the production from the partnership’s wells generally is the greatest, natural gas and oil prices will remain above the applicable reference prices under the Internal Revenue Code at which the marginal well production credit is reduced to zero. Thus, you may not receive any marginal well production credits from your partnership for many years, if ever. See “Federal Income Tax Consequences – Marginal Well Production Credits.”

 

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ADDITIONAL INFORMATION

The program and the partnerships composing the program currently are not required to file reports with the SEC. However, a registration statement on Form S-1 has been filed on behalf of the program with the SEC. Certain portions of the registration statement have been deleted from this prospectus under SEC rules and regulations. You are urged to refer to the registration statement, as amended, including its post-effective amendments, for further information concerning the provisions of certain documents referred to in this prospectus.

You may read and copy any materials filed as a part of the registration statement, including the tax opinion included as Exhibit 8.1, at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Also, the SEC maintains an internet website that contains registration statements, reports, proxy statements, and other information about issuers who file electronically with the SEC, including the partnerships composing the program. The address of that site is http://www.sec.gov. Additionally, you may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Finally, a copy of the tax opinion may be obtained by you or your advisors from the managing general partner at no cost. The delivery of this prospectus does not imply that its information is correct as of any time after its date.

 

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FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS

Statements, other than statements of historical facts, included in this prospectus and its exhibits address activities, events or developments that the managing general partner and the partnerships anticipate will or may occur in the future. For example, the words “believes,” “anticipates,” “will” and “expects” are intended to identify forward-looking statements. These forward-looking statements include such things as:

 

•

investment objectives;

 

•

references to future success in the partnerships’ drilling and marketing activities;

 

•

business strategy;

 

•

estimated future capital expenditures;

 

•

competitive strengths and goals; and

 

•

other similar matters.

These statements are based on certain assumptions and analyses made by the partnerships and the managing general partner in light of their experience and their perception of historical trends, current conditions, and expected future developments. However, whether actual results will conform with these expectations is subject to a number of risks and uncertainties, many of which are beyond the control of the partnerships and the managing general partner, including, but not limited to:

 

•

general economic, market, or business conditions;

 

•

changes in laws or regulations, including the federal income tax laws;

 

•

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

 

•

the risk that the price of natural gas and oil may decrease.

Thus, all of the forward-looking statements made in this prospectus and its exhibits are qualified by these cautionary statements. There can be no assurance that actual results will conform with the managing general partner’s and the partnerships’ expectations.

 

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INVESTMENT OBJECTIVES

Each partnership’s principal investment objectives are to invest its subscription proceeds in drilling, completing and operating natural gas and oil development wells which will:

 

•

Provide monthly cash distributions to you, in the managing general partner’s discretion, until the wells are depleted, with a minimum subordinated cumulative return of capital of 10% during each of its first five 12-month subordination periods and 7.5% during each of its next three 12-month subordination periods. The first 12-month subordination period will begin on the earlier of when your partnership begins receiving revenues from all of its productive wells, if any, or 12 months after the partnership’s final closing. The subordination is based on $10,000 per unit for all units sold regardless of the actual subscription price you paid for your units. These distributions during the partnership’s 96-month aggregate subordination period are not guaranteed, but are subject to the managing general partner’s subordination obligation as described in “Participation in Costs and Revenues – Subordination of Portion of Managing General Partner’s Net Revenue Share.”

 

•

Obtain tax deductions from your partnership in the year that you invest from intangible drilling costs to offset a portion of your taxable income from sources other than the partnership, subject to the passive activity limitations on losses if you invest as a limited partner. For example, if you pay $10,000 for a unit then the managing general partner anticipates that you may claim an income tax deduction for intangible drilling costs of up to $8,160 per unit, 81.6%, in the year you invest against:

 

•

ordinary income, or capital gain in some situations, if you invest as an investor general partner in the partnership; or

 

•

net passive income from your other passive activity investments, if any, and passive income from the partnership in the year you invest, if any, if you invest as a limited partner in the partnership.

In the above example, if you are in either the 35% or 33% tax bracket and you claimed an intangible drilling costs deduction in the amount of $8,160 in 2012, you would save approximately $2,856 or $2,693, respectively, per $10,000 unit, in federal income taxes. Most states also allow this type of deduction. Beginning in 2013, however, the top four federal brackets for individual taxpayers under prior law are scheduled under the Code to be restored to 38.6%, 35%, 30% and 27%.

 

•

Obtain tax deductions in 2012 of the remaining approximately 18.4% of your investment over a seven-year cost recovery period beginning in the taxable year your partnership drills, completes and places into service each of its wells. Also, if you invest in MDS Energy Public 2012-A LP, there is a first-year bonus depreciation allowance in 2012 only that is equal to 50% of the qualified equipment costs for wells placed in service in 2012 for the production of natural gas or oil, which may include one or more of MDS Energy Public 2012-A LP’s wells. This 50% bonus depreciation allowance is scheduled to expire under current law on January 1, 2013, and will not be available for the other partnerships in this program.

 

•

Offset a portion of any gross production income generated by the partnership with tax deductions from the 15% percentage depletion allowance, although gross production income from “marginal wells,” as defined in the Code, is eligible for potentially higher rates of percentage depletion. In this regard, the managing general partner anticipates that some of the natural gas and oil production from a partnership’s productive wells may be classified as marginal production for federal tax purposes. The applicable percentage depletion rate for gross income from marginal production is 15% in 2012. During the lifetime of a partnership’s marginal wells, however, the applicable percentage depletion rate may fluctuate from year to year, depending on the price of oil, but under current tax law it will not be less than the statutory rate of 15% nor more than 25%.

 

•

If you are self-employed and invest in the partnership as an investor general partner, then you may use your share of the partnership’s net deductions to offset a portion of your net earnings from self-employment in the year you invest.

 

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Attainment of these investment objectives by the partnerships will depend on many factors, including the ability of the managing general partner to select suitable wells that will be productive and produce enough revenue to return the investment made. The success of each partnership depends largely on future economic conditions, especially the future price of natural gas, which is volatile and may decrease.

Also, the extent to which your partnership attains the foregoing investment objectives will be different as compared with the other partnerships in the program, because each partnership is a separate business entity which:

 

•

generally will drill different wells;

 

•

may receive a different amount of subscription proceeds, which generally will be the primary factor in determining the number of wells that can be drilled by a partnership; and

 

•

may drill wells situated in different geographical areas with different formations, reservoirs or depths, which will affect the cost of the wells and, thus, will also affect the number of wells that can be drilled by a partnership.

There can be no guarantee that the foregoing objectives will be attained.

 

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

You may choose to invest in a partnership as an investor general partner so that you can claim an immediate federal income tax deduction for your share of the partnership’s intangible drilling costs, which can be used against any type of income. To help reduce the risk that you and other investor general partners could be required to make additional payments to the partnership, the managing general partner will take the actions set forth below.

Insurance. The managing general partner or its affiliates will obtain and maintain insurance coverage for the benefit of the partnerships in amounts and for purposes that would be carried by a reasonable, prudent general contractor and operator in accordance with industry standards, taking into account each partnership’s intended drilling operations, including hydraulic fracking of the wells in the Marcellus Shale primary area. See “Risk Factors – Risks Related to The Partnerships’ Oil and Gas Operations” and “Proposed Activities.” The partnerships will be included as insures under these general and umbrella liability policies. In the Marcellus Shale primary area, there will be limited liability coverage for personal injury and property damage if there is pollution from a partnership well arising from a sudden and accidental event that is discovered within 30 days and reported to the insurer within 90 days, subject to policy limits, deductions, exclusions and other terms and conditions. For example, the pollution liability coverage does not include coverage for governmental fines or penalties and there is no well control or blowout insurance coverage.

The managing general partner’s current insurance coverage satisfies the following specifications:

 

•

worker’s compensation insurance in full compliance with the laws of the Commonwealth of Pennsylvania and any other applicable state laws where the wells will be drilled;

 

•

commercial general liability insurance covering bodily injury and products/completed operations, including certain pollution clean-up costs, subject to certain discovery and reporting requirements as discussed above, with limits of $1,000,000 per occurrence and $2,000,000 in the aggregate;

 

•

automobile liability insurance with a $1,000,000 combined single limit for bodily injury and property damage, including hired and non-owned vehicles; and

 

•

umbrella liability with an annual aggregate limit of $50 million, except that the limit for pollution, is $25 million.

The annual insurance limits available to the partnership could be substantially less if insurance claims are made by the managing general partner’s other affiliates, including the previous partnerships sponsored by MDS Energy, Ltd. and M/D Gas, Inc. As of the date of this prospectus, however, no material insurance claims, lawsuits or regulatory fines or penalties regarding pollution of the environment or other matters involving the previous partnerships’ drilling of approximately 51 vertical wells in the Marcellus Shale have been made.

Because the managing general partner is the driller and operator of wells for other partnerships, in addition to the partnerships in this program, the insurance available to each partnership could be substantially less if insurance claims are made in the other partnerships.

This insurance has deductibles, which would first have to be paid by a partnership, per occurrence for bodily injury and property damage, and other terms, including exclusions, that are standard for the natural gas and oil industry. On request the managing general partner will provide you or your representative a copy of the insurance policies. The managing general partner will use its best efforts to maintain insurance coverage that meets its current coverage, but it may be unsuccessful if the coverage becomes unavailable or too expensive.

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 general partner does not anticipate, then the

 

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managing general partner will notify you at least 30 days before the effective date of the change. You will then have the right to convert your units into limited partner units before the change in insurance coverage by giving written notice to the managing general partner.

 

•

Conversion of Investor General Partner Units to Limited Partner Units. Your investor general partner units will be automatically converted by the managing general partner to limited partner units after all of the wells in your partnership have been drilled and completed. In this regard, a well is deemed to be completed when production equipment is installed on the well, even though the well may not yet be connected to a pipeline for production of natural gas in the case of natural gas wells. The managing general partner anticipates that all of your partnership’s wells will be drilled and completed no later than 12 months after the offering of your partnership closes, and the conversion will occur before the end of the succeeding tax year. However, if all or a majority of the maximum subscription proceeds are received by MDS Energy Public 2012-A LP, then it may take longer for all of its wells to be drilled and completed than if fewer units were sold in that partnership and there were fewer wells to be drilled and completed, which could delay the conversion of the investor general partner units to limited partner units.

Once your units are converted, which generally is a nontaxable event, you will have the lesser 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.

 

•

Nonrecourse Debt. The managing general partner does not anticipate that the partnerships will borrow funds. However, if borrowings are required, then each partnership will be permitted to borrow funds from the managing general partner and its affiliates or third-party lenders that are without recourse against your non-partnership assets. Thus, if there is a default by your partnership under a loan arrangement you cannot be required to contribute funds to the partnership. Any borrowings by a partnership will be repaid from that partnership’s revenues and assets.

The amount that may be borrowed at any one time by each partnership may not exceed an amount equal to 5% of the investors’ subscription proceeds in that partnership. However, because you do not bear the risk of repaying your partnership’s borrowings with non-partnership assets, the borrowings will not increase the extent to which you are allowed to deduct your individual share of partnership losses. See “Federal Income Tax Consequences – Tax Basis of Units” and “- ‘At Risk’ Limitation on Losses.” Notwithstanding, this 5% limitation on partnership borrowings does not apply to each partnership’s ability to enter into agreements and financial instruments relating to hedging up to 50% of the partnership’s natural gas and oil and pledging up to 100% of the partnership’s assets and reserves in connection therewith.

 

•

Indemnification. The managing general partner will indemnify you from any liability incurred in connection with your partnership that is in excess of your interest in the partnership’s:

 

•

undistributed net assets; and

 

•

insurance proceeds, if any, from all potential sources.

The managing general partner’s indemnification obligation, however, will not eliminate your potential liability if the managing general partner’s assets are insufficient to satisfy its indemnification obligation. There can be no assurance that the managing general partner’s assets, including its liquid assets, will be sufficient to satisfy its indemnification obligation. See “Financial Information Concerning The Managing General Partner and MDS Energy Public 2012-A LP.”

 

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CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS

Source of Funds

Each partnership must receive minimum subscription proceeds of $2 million to close, and the subscription proceeds of the partnerships, in the aggregate, may not exceed $300 million. There are no other requirements regarding the size of a partnership, and the subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of another partnership. Although the targeted maximum subscription amounts for each partnership are set forth in “Terms of the Offering – Subscription to a Partnership,” they are not binding on the managing general partner. For example, the managing general partner has the discretion to accept subscriptions for any amount up to and including the entire amount of the program in MDS Energy Public 2012-A LP and not offer and sell any units in the other partnerships. See “Terms of the Offering – Subscription to a Partnership.”

On completion of the offering of units in a partnership, the partnership’s source of funds will be as follows assuming each unit is sold for $10,000:

 

•

the subscription proceeds of you and the other investors, which will be:

 

•

$2 million if 200 units are sold; and

 

•

$300 million if 30,000 units are sold; and

 

•

the managing general partner’s capital contribution, which must be at least 15% of all capital contributions to each partnership and includes its credit for contributing the leases to each partnership and paying 100% of each partnership’s organization and offering costs as follows:

 

•

approximately $352,941 if 200 units are sold; and

 

•

approximately $52,941,177 if 30,000 units are sold.

Thus, the total amount available to a partnership will be not less than approximately $2,352,941 if 200 units are sold ranging to not less than approximately $352,941,177 if 30,000 units are sold.

Use of Proceeds

The subscription proceeds received from you and the other investors will be used by your partnership to pay 100% of the:

 

•

intangible drilling costs of drilling and completing the partnership’s wells; and

 

•

equipment costs of drilling and completing the partnership’s wells.

The managing general partner considers a proposed drilling area to be a primary area if it expects to use 10% or more of the partnership’s subscription proceeds to drill wells in the area. In this regard, the managing general partner anticipates that all of the maximum subscription proceeds of each partnership will be allocated to drilling vertical wells in the Marcellus Shale primary area in western Pennsylvania, although up to approximately 25% of a partnership’s subscription proceeds may be allocated to drilling horizontal wells in the Marcellus Shale primary area and up to approximately 20% of the subscription proceeds may be allocated to drilling vertical and/or horizontal wells in other areas of the United States, including, for example, the Mid-Continent region and the Utica Shale geological formation in Ohio, in the managing general partner’s discretion. See “Proposed Activities – Secondary Areas of Operations.” The percentages set forth above, however, are estimates and may change materially depending on actual drilling results. See “Proposed Activities.”

The managing general partner also will be charged with 100% of the organization and offering costs for the partnerships and it will contribute all of the leases to the partnerships. A portion of these contributions to each partnership will be in the form of payments to itself, its affiliates and third-parties and the remainder will be in

 

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the form of services related to organizing this offering. The managing general partner will receive a credit towards its required capital contribution to each partnership for these payments and services as discussed in “Compensation.”

The following table presents information concerning a partnership’s use of the proceeds provided by you and the other investors. The table is presented based on:

 

•

the sale of 200 units ($2 million), which is the minimum number of units for each partnership; and

 

•

the sale of 30,000 units ($300 million), which is the maximum number of units for all of the partnerships in the program.

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

INVESTOR CAPITAL

 

NATURE OF PAYMENT		200 UNITS SOLD				%				30,000 UNITS SOLD				%
Organization and Offering Expenses
Dealer-manager fee and sales commissions (1)			- 0 -				0%				- 0 -				0%
Organization costs (2)			- 0 -				0%				- 0 -				0%
Amount Available for Investment:
Intangible drilling costs (3)		$	1,621,960				81.1%			$	243,294,079				81.1%
Equipment costs (3)		$	378,040				18.9%			$	56,705,921				18.9%
Leases (4)			- 0 -				- 0 -				- 0 -				- 0 -
Total Investor Capital		$	2,000,000				100%			$	300,000,000				100%

 

(1)

All of these costs will be charged to the managing general partner. MDS Securities, an affiliate of the managing general partner, will be the dealer-manager of the offering and it will receive the dealer-manager fee and the sales commissions. A portion of the dealer-manager fee and generally all of the sales commissions will be reallowed by the dealer-manager to the broker/dealers, which are referred to as selling dealers, as discussed in “Plan of Distribution.”

(2)	All of these costs will be charged to the managing general partner.

(3)

The subscription proceeds provided by you and the other investors to a partnership will be used to pay 100% of the partnership’s intangible drilling costs and equipment costs to drill and complete its wells. These costs will vary depending on the actual intangible drilling costs and equipment costs of drilling and completing the wells. For purposes of this table, the managing general partner estimated the allocation of a partnership’s subscription proceeds between intangible drilling costs and equipment costs based on its estimated average cost to drill one net vertical well in the Marcellus Shale primary area as discussed in greater detail in “Compensation – Drilling Contracts.”

(4)	As part of its required capital contribution to each partnership, the managing general partner will contribute all of the partnership’s leases. See “Compensation – Lease Costs” and “Participation in Costs and Revenues.”

 

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COMPENSATION

The items of compensation to be paid to the managing general partner and its affiliates from each partnership are discussed below. Also, a tabular presentation of all items of compensation follows the narrative discussion. The amount of most of these items of compensation depends on the amount of subscription proceeds received by the partnership, how many wells the partnership drills and how much of the working interest in each of the wells is owned by the partnership. In this regard, the managing general partner estimates that approximately 1.59 net vertical wells, which is not less than two gross wells, will be drilled by a partnership if the minimum required subscription proceeds are received by the partnership, and approximately 238.6 net vertical wells, which is not less than 239 gross wells, will be drilled if the maximum subscription proceeds of $300 million are received by a partnership or the partnerships and assuming 100% of the maximum subscription proceeds is used to drill vertical wells in the Marcellus Shale primary area. A gross well is a well in which the partnership owns a working interest. This is compared with a net well, which is the sum of the fractional working interests owned in the gross wells. For example, a 50% working interest owned in three wells is three gross wells, but 1.5 net wells.

Based on the partnerships’ maximum subscription proceeds of $300 million, the managing general partner has provided its estimate of:

 

•

the partnerships’ average cost to drill and complete a partnership well; and

 

•

the managing general partner’s estimated compensation from the partnerships for its services as general drilling contractor and operator during the drilling and completion operations for all of the estimated number of wells to be drilled and completed by the program. See “- Drilling Contracts,” below.

However, these estimates by the managing general partner are based on certain assumptions including, but not limited to, the following:

 

•

the number of vertical and horizontal wells that will be drilled and completed by the partnerships;

 

•

how deep the wells will be drilled by the partnerships;

 

•

the amount of subscription proceeds received by the partnerships;

 

•

the cost of equipment and services to be provided by both third-party and affiliated subcontractors; and

 

•

each partnerships’ percentage of the working interest in its wells and prospects.

The actual results of each partnership’s drilling activities will be different from the managing general partner’s assumptions and estimates for various reasons, including those set forth in “Risk Factors – Risks Related to an Investment in a Partnership – The Partnerships Do Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects Are Acquired By a Partnership, and the Lack of Information for Any Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership.” Thus, the actual results of the drilling and completion operations of a partnership, including the amount of the managing general partner’s compensation from the partnership for serving as general drilling contractor and operator during its drilling and completion operations, will vary from the managing general partner’s assumptions and estimated well costs, and the variations could be material.

Organization and Offering Costs

The managing general partner will receive a credit towards its required capital contribution and revenue share to each partnership for paying all of the partnership’s organization and offering costs. However, if organization and offerings costs exceed 15% of a partnership’s subscription proceeds, then the managing general partner will not receive any credit towards its required capital contribution or its revenue share for the organization and offering costs it pays in excess of 15% of the partnership’s subscription proceeds. Organization and offering costs generally means all costs of organizing and selling the offering and includes the dealer-manager fees, sales commissions, non-cash compensation, nonaccountable marketing fees, and reimbursements for bona fide due

 

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diligence expenses. Subject to certain exceptions described in “Plan of Distribution,” MDS Securities, which is the dealer-manager of this offering and an affiliate of the managing general partner, will receive on each unit sold to an investor:

 

•

a 3% dealer-manager fee; and

 

•

a 7% sales commission.

Assuming the above amounts are paid for all units sold, the dealer-manager will receive:

 

•

$200,000 if subscription proceeds of $2 million are received by a partnership; and

 

•

$30,000,000 if subscription proceeds of $300,000,000 are received by one or more of the partnerships.

Generally all of the sales commissions will be reallowed by the dealer-manager to the selling dealers. See “Plan of Distribution” regarding the reimbursement of the selling dealers’ bona fide due diligence expenses. A portion of the 3% dealer-manager fee will be reallowed to the wholesalers licensed with FINRA through the dealer-manager and employed as officers by the managing general partner. Also, a portion of the dealer-manager fee will be reallowed to the selling dealers as described in “Plan of Distribution.” The dealer-manager will retain any of the compensation that is not reallowed. See “Management” for the ownership of MDS Securities.

A portion of the organization costs charged to the partnership will include services provided by the managing general partner and its affiliates to organize this offering. The amount of the managing general partner’s charges for its services for organization costs will be determined based on generally accepted accounting principles. The complete definition of organization and offering costs is set forth in the partnership agreement.

The managing general partner’s aggregate maximum credit of 15% of the partnerships’ subscription proceeds for organization and offering costs will be:

 

•

$300,000 if the minimum subscription proceeds are received; and

 

•

$45,000,000 if the maximum subscription proceeds are received, which is composed of offering costs of 10% ($30,000,000) and organization costs of 5% ($15,000,000).

Natural Gas and Oil Revenues

Subject to the managing general partner’s subordination obligation, the investors and the managing general partner will share in each partnership’s revenues in the same percentages as their respective capital contributions bear to the partnership’s total capital contributions, except that the managing general partner will receive an additional 8% of the partnership’s revenues.

 

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For example, if the managing general partner contributes the required minimum of 15% of a partnership’s total capital contributions and the investors contribute 85% of the partnership’s total capital contributions, then the managing general partner will receive 23% of the partnership’s revenues and the investors will receive 77% of the partnership’s revenues as shown in the bar chart set forth below.

 

As noted above, up to 60% of the managing general partner’s share of partnership net production revenues is subject to its subordination obligation as described in “Participation in Costs and Revenues – Subordination of Portion of Managing General Partner’s Net Revenue Share.” For example, if the managing general partner’s revenue share is 23% of a partnership’s revenues, then up to 13.8% of its partnership net production revenues could be used for its subordination obligation.

Lease Costs

Under the partnership agreement the managing general partner or its affiliates will contribute to each partnership all of the undeveloped leases necessary to drill the partnership’s wells and it generally will receive a credit towards its required capital contributions to the partnership in an amount equal to the cost of the leases contributed to the partnership, or the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than fair market value, except that the managing general partner’s credit for leases in the Marcellus Shale primary area that are acquired from Snyder Brothers, Inc. or another affiliate of the managing general partner, and then contributed to a partnership, will be an amount equal to the fair market value of the leases, as determined by an appraisal of the fair market value of the leases by an independent expert selected by the managing general partner, but not to exceed the price actually paid by the managing general partner to its affiliates for the leases.

In this regard, the cost of the leases generally includes:

 

•

the sum of the prices paid by the seller or transferor to an unaffiliated person for the property, including bonuses;

 

•

title insurance or examination costs, brokers’ commissions, filing fees, recording costs, transfer taxes, if any, and like charges in connection with its acquisition of the property;

 

•

rentals and ad valorem taxes paid by the seller or the transferor for the property to the date of transfer to the partnership, and interest and points actually incurred on funds used to acquire or maintain the property; and

 

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•

a portion of the seller’s or transferor’s necessary and reasonable expenses for seismic, geological, geophysical, engineering, drafting, accounting, legal and other like services allocated to the leases in conformity with generally accepted accounting principles and industry standards.

See the full definition of “Cost” in the partnership agreement.

Also, the leases contributed to the partnership to drill a vertical well generally will include the wellbore and a 330 foot radius around the wellbore, which would cover approximately 7.85 acres, but may be less than a 330 foot radius and cover much less than 7.85 acres in a prospect depending primarily on the location of the drill site, the number of acres in the prospect leased by the managing general partner, and after any adjustments for lease boundaries. In this regard, however, the managing general partner and its affiliates, including their affiliated partnerships, will not drill another vertical well to the Marcellus Shale formation within 330 feet of an existing partnership wellbore. Also, the managing general partner and its affiliates, including their affiliated partnerships, may drill a horizontal well to the Marcellus Shale on the same well pad used by a partnership well or on a different well pad located anywhere else within the 330 feet circle around the wellbore of the partnership well, and they may drill the horizontal well laterally through all or any portion of the 330 feet circle around the existing wellbore of the partnership well, but they may not frack or complete the horizontal well or any of its laterals within 330 feet of the wellbore of the partnership well.

The managing general partner’s credit for the leases for a prospect will be proportionally reduced to the extent the partnership acquires less than 100% of the working interest in the prospect. A working interest generally means an interest in the lease under which the owner of the working interest must pay some portion of the cost of development, operation, or maintenance of the well. The actual amount of the managing general partner’s credit for its contribution of leases to each partnership cannot be quantified at this time.

Drilling the partnership’s wells also may provide the managing general partner with offset prospects to be drilled by it and its affiliates, including affiliated partnerships and future partnerships sponsored by it or its affiliates, by allowing them to determine, at the partnership’s expense, the value of adjacent acreage in which the partnership would not have any interest. Further, the managing general partner may cause the partnership to drill wells on leases that are scheduled to expire soon in order to prevent the expiration of the lease.

Drilling Contracts

The partnership will enter into the drilling and operating agreement with the managing general partner, acting as a third-party general drilling contractor and operator, to drill and complete the partnership’s wells for an amount equal to the sum of the following items: (i) the cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by affiliates of the managing general partner, then those items will be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the managing general partner’s affiliates, which will be charged at competitive rates; (iv) an administration and supervision fee at a competitive rate, which is $60,000 per vertical well and $250,000 per horizontal well, if any, in the Marcellus Shale (Pennsylvania) primary area, which will be charged to you and the other investors as part of each well’s intangible drilling costs and equipment costs; and (v) a mark-up in an amount equal to 15% of the sum of (i), (ii), and (iii), but not (iv), above, for the managing general partner’s services as general drilling contractor. Notwithstanding, if the managing general partner drills a well for the partnership that it determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completing the well or as otherwise determined by the managing general partner, the administration and supervision fee for the well described above may be increased to a competitive rate as determined by the managing general partner. In this regard, the managing general partner has determined that the cost of drilling and completing the partnership’s wells as set forth above is a competitive rate based on information it has concerning drilling rates of third-party operators in the general area where the partnerships’ wells will be drilled and its affiliates’ past experience in drilling vertical wells to the Marcellus Shale geological formation in the same general area.

 

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If the cost of drilling and completing a partnership’s wells as set forth above subsequently exceeds competitive rates available from non-affiliated persons in the area engaged in the business of rendering or providing comparable services or equipment, then the rate will be adjusted to the competitive rate. Additionally, the 15% mark-up will not be increased by the managing general partner for any wells drilled by the partnership.

During drilling operations, the managing general partner’s duties as operator and general drilling contractor will include:

 

•

making the necessary arrangements for drilling and completing the wells and related facilities for which it has responsibility under the drilling and operating agreement;

 

•

managing and conducting all field operations in connection with drilling, testing, and equipping the wells;

 

•

purchasing and installing meters to measure production from the wells, which will be owned by Snyder Brothers, Inc. or other affiliates of the managing general partner if they are the purchasers of the natural gas; and

 

•

making the technical decisions required in drilling and completing the wells.

See “Proposed Activities – Drilling and Completion Activities; Operation of Producing Wells” for a more detailed discussion of the services to be provided to the partnerships by the managing general partner as general drilling contractor. The managing general partner expects to subcontract some of the actual drilling and completion of each partnership’s wells to third-parties selected by it as well as to its affiliates. The managing general partner may not benefit by interpositioning itself between the partnership and the actual provider of drilling contractor services, and may not profit by drilling in contravention of its fiduciary obligations to the partnership. However, the managing general partner’s affiliates may charge a competitive rate for their services if they meet the requirements described in “Conflicts of Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.” For example, First Class Energy, an affiliate of the managing general partner, currently leases nine drilling rigs, two service rigs, one oil tubing rig and over 50 excavators and bulldozers, plus other ancillary equipment from MDS Energy, Ltd., an affiliate of the managing general partner, which First Class Energy may use to provide subcontractor drilling and fracking services to the partnerships.

The cost of each partnership well includes all of the ordinary costs of drilling, testing and completing the well. This includes, but is not limited to, the cost of the following items with respect to each vertical natural gas well, which will be the classification of all the wells in the Marcellus Shale primary area:

 

•

multiple fracks and completions, which generally means treating separately all potentially productive geological formations in an attempt to enhance the natural gas production from the well;

 

•

installing the necessary flow lines to connect the well’s natural gas production to a pipeline or gathering system; and

 

•

the necessary surface facilities for producing natural gas from the well.

The amount paid to the managing general partner for drilling and completing a partnership well will be proportionately reduced to the extent the partnership acquires less than 100% of the working interest in the prospect. In addition, the amount of compensation that the managing general partner could earn as a result of these arrangements depends on many other factors as well, including the following:

 

•

the specific locations where the wells are drilled and their depths;

 

•

whether the well is a vertical development well or a horizontal development well;

 

•

the methods used to complete the wells; and

 

•

the number of wells drilled.

 

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An example of the managing general partner’s estimated average cost for a partnership to drill and complete one net vertical well in the Marcellus Shale primary area, which does not include lease acquisition costs or organization and offering costs, is set forth in the table below:

 

Example		Administration and Supervision Fee				Total Estimated Average Cost Per Net Well, Excluding  Lease Interests, But Including 15% Mark-Up and Administration and Supervision Fee				Estimated % of Intangible Costs of Well				Estimated % of Tangible Costs of Well
Vertical Marcellus Shale Well (1)(2)		$	60,000			$	1,257,150	(3)			81.6	%			18.4	%

 

(1)

The partnership’s cost of drilling and completing any given well in the area described above, excluding lease interests, may be considerably more or less than the amounts estimated by the managing general partner as described above, depending primarily on where the well is situated in the area, the depth of the well, and unanticipated cost overruns.

(2)

The managing general partner anticipates that each partnership’s targeted maximum subscription proceeds of $100 million will be expended 100% on drilling approximately 79.6 net vertical wells, which is at least 80 gross wells, per partnership in the Marcellus Shale primary area, assuming the partnership owns 100% of the working interest in the wells. If only the minimum subscription proceeds are received by a partnership, the managing general partner anticipates that the partnership will drill only approximately 1.69 net vertical wells, which is at least two gross wells, in the Marcellus Shale primary area in western Pennsylvania.

(3)

The managing general partner anticipates that the average cost for the partnership to drill a vertical development well in the Marcellus Shale primary area will be approximately $1,257,150 per net vertical well, assuming the partnership owns 100% of the working interest in the well and the administrative and supervision fee is $60,000 per vertical well. This estimate also was based on the managing general partner’s estimate of how deep the wells will be drilled by the partnership.

Notwithstanding, in the managing general partner’s discretion up to approximately 25% ($25 million) of each partnership’s targeted maximum subscription proceeds may be expended on drilling horizontal wells in the Marcellus Shale primary area. In this event, the managing general partner estimates that the total average cost per net horizontal well in the Marcellus Shale primary area, including its administration and supervision fee of $250,000 per horizontal well, but excluding lease costs, would be approximately $7,438,059 per well, assuming the partnership owned 100% of the working interest in the well, which would be allocated approximately 86% to intangible drilling costs and 14% to equipment costs (i.e., “Tangible Costs”). To the extent the partnership drills horizontal wells, if any, the number of wells that is drilled with the same amount of subscription proceeds may be substantially reduced, depending primarily on how much of the working interest in the wells is owned by the partnership, because the cost of drilling a horizontal well is so much greater than the cost of drilling a vertical well as shown in the table above. Also, up to approximately 20% ($20 million) of each partnership’s subscription proceeds may be used to drill vertical and/or horizontal wells in other areas of the United States.

The actual compensation received by the managing general partner as a result of each partnership’s drilling operations will vary from these estimates, and the managing general partner anticipates that each partnership will acquire less than 100% of the working interest in one or more of its prospects.

Additionally, affiliates of the managing general partner will provide subcontracting services, equipment and materials in drilling, completing or operating each partnership’s wells for which they will receive competitive rates, including First Class Energy as described above, because they meet the requirements described in “Conflicts of Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.” Thus, the total compensation paid to the managing general partner and its affiliates per net partnership well will be greater than the estimated amount to be paid to the managing general partner for the partnership’s wells as described above to the extent compensation is paid by the partnership to the managing general partner’s affiliates for services, equipment or supplies they provide to the partnership.

 

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Per Well Charges

Under the drilling and operating agreement the managing general partner, as operator of the wells, will receive the following compensation from each partnership when the wells begin producing natural gas or oil:

 

•

well supervision fees at a competitive rate for operating and maintaining the wells during producing operations; and

 

•

reimbursement at actual cost for all direct expenses incurred on behalf of the partnership.

Currently the managing general partner has determined that the competitive rate for well supervision fees is $800 per vertical well per month and $2,000 per horizontal well per month, if any, in the Marcellus Shale (Pennsylvania) primary area. Direct expenses include third-party expenses, such as water hauling and chart calibration.

The well supervision fees described above will be proportionately reduced to the extent a partnership acquires less than 100% of the working interest in the well. Also, the managing general partner’s well supervision fees may be adjusted annually beginning in 2013 for inflation since January 1, 2012. If the managing general partner’s well supervision fee would exceed a competitive rate in the area where the well is situated, then the rate will be adjusted to the competitive rate. Conversely, if in the future the managing general partner’s well supervision fee set forth above would be less than a competitive rate in an area where a well is situated, then regardless of the inflation adjustment, the rate may be increased automatically to the competitive rate from time to time by the managing general partner, as operator, as determined in its sole discretion. Also, the managing general partner may not benefit by interpositioning itself between a partnership and the actual provider of operator services. In no event will any consideration received by the managing general partner for operator services under the drilling and operating agreement be duplicative of any consideration or reimbursement received by the managing general partner under the partnership agreement.

The well supervision fee covers all normal and regularly recurring operating expenses for the production, delivery, and sale of natural gas and oil, such as:

 

•

well tending, routine maintenance, and adjustment;

 

•

reading meters, recording production, pumping, maintaining appropriate books and records; and

 

•

preparing reports to the partnership and to government agencies.

The well supervision fees do not include costs and expenses related to:

 

•

the purchase of equipment and materials, or services provided by third-parties or affiliates of the managing general partner at competitive rates in the area;

 

•

water hauling or disposal; and

 

•

rebuilding of access roads.

These costs will be charged to the partnership at the invoice cost of the materials purchased or the services provided by third-parties or affiliates of the managing general partner at competitive rates in the area.

As discussed above, affiliates of the managing general partner will provide subcontracting services, equipment and materials in drilling, completing or operating the partnerships’ wells for which they will receive competitive rates, including First Class Energy as described in “– Drilling Contracts,” above, because they meet the requirements described in “Conflicts of Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.” Thus, the total compensation paid to the managing general partner and its affiliates per net partnership well will be greater than the estimated amount to be paid to the managing general partner for drilling and completing the partnerships’ wells as described in the table set forth in “– Drilling Contracts,” above, to the extent compensation is paid by the partnerships to the managing general partner’s affiliates for services, equipment or supplies they provide to the partnerships.

 

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Gathering Fees

Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnerships to interstate pipeline systems, local distribution companies, and/or end-users in the area (the “gathering services”). In providing the gathering services, the managing general partner will use gathering systems owned by independent third-parties and/or its affiliates in the Marcellus Shale primary area. Each partnership will pay a gathering fee to the managing general partner or directly to its affiliates at competitive rates for any gathering services they provide to the partnership. The gathering fees paid by the partnership to the managing general partner or its affiliates may be increased from time-to-time by the managing general partner, in its sole discretion, but may not be increased beyond competitive rates as determined by the managing general partner. Currently, the managing general partner has determined that the competitive rates in the Marcellus Shale primary area are as set forth below:

 

•

if transported through a pipeline owned by Snyder Brothers, Inc. or MDS Energy, Ltd., which are affiliates of the managing general partner, 10% of the sales price a partnership receives for its natural gas, plus processing, compression, dehydration and any other operating costs related to the partnership’s natural gas transported, but not less than $0.50 per 1,000 cubic feet (“mcf”) of natural gas transported; and

 

•

if transported through pipelines owned by Furnace Run Pipeline, L.P. or Mushroom Farm Pipeline, L.P., which are affiliates of the managing general partner, $0.60 per mcf transported, plus 4% for processing, compression, dehydration and any other operating costs related to the partnership’s natural gas transported.

The payment of a competitive fee to the managing general partner or its affiliates for their gathering services, which excludes processing, compression and other operating expenses related to the partnership’s natural gas transported, will be subject to the following conditions:

 

•

If a gas gathering system owned or operated by an affiliate of the managing general partner is used by the partnership, the gathering fee may not exceed a competitive rate for similar services in the area.

 

•

If a third-party gathering system is used by the partnership, then the gathering fee paid by the partnership will be the actual fee charged by the third-party.

 

•

If both a third-party gathering system and a gas gathering system owned or operated by an affiliate of the managing general partner are used by the partnership, then the partnership will pay a competitive fee as described above for the natural gas transported by the segment of the gathering system provided by the managing general partner’s affiliate, plus the actual amount charged by the third-party for the natural gas transported by the segment of the gathering system provided by the third-party.

The actual amount of gathering, processing and compression fees and expenses to be paid by a partnership to the managing general partner or its affiliates cannot be quantified, because the sales price that will be received by the partnership and the volume of natural gas that will be produced, transported and sold from the partnership’s wells cannot be predicted.

The managing general partner also anticipates that a portion or all of each partnership’s natural gas production in the Marcellus Shale primary area will be sold to Snyder Brothers, Inc. or other affiliates of the managing general partner at competitive sales prices, which will be determined by the managing general partner, in its discretion, based on sales prices paid by the managing general partner’s affiliate to independent third-parties for comparable gas in the area. In this regard, the affiliated purchaser can be expected to profit, in an amount which cannot currently be quantified, when the affiliate resells the natural gas to third-party end-users or other purchasers of the natural gas.

 

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Interest and Other Compensation

The managing general partner or an affiliate will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of a partnership, which are not anticipated by the managing general partner. If the managing general partner or an affiliate provides equipment, supplies, and other services to a partnership, then it may do so at competitive industry rates.

Set forth below is a tabular presentation of the narrative discussion of the compensation set forth above and the managing general partner’s estimate of the direct and administrative costs that will be incurred by each partnership during its first full 12 months of operations. In all cases, the tabular presentation is subject to the discussion set forth above.

Offering Stage

 

Entity receiving compensation		Organization and Offering Costs
MDS Securities		Dealer-Manager Fees. Subject to certain exceptions described in “Plan of Distribution,” MDS Securities, the dealer-manager and an affiliate of the managing general partner, will receive on each unit sold to an investor:   •   a 3% dealer-manager fee; and   •   a 7% sales commission.		Estimated Amount Assuming the dealer-manager will receive the dealer-manager fee and the sales commissions on all units sold, these amounts will be:   •   $200,000 if the minimum subscription proceeds are received; and   •   $30,000,000 if the maximum subscription proceeds are received.
Drilling Stage
Entity receiving compensation		Type and method of compensation
Managing general partner and its affiliates		Lease Costs. The managing general partner will receive a credit to its capital account in an amount equal to:   •   the cost of the leases or the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than fair market value; or		Estimated Amount The actual amount of the managing general partner’s credit for its contribution of the leases to each partnership cannot be quantified at this time.
		•   for leases in the Marcellus Shale primary area that the managing general partner acquires from Snyder Brothers, Inc. or another affiliate of the managing general partner, the fair market value of the leases pursuant to an appraisal of the leases by an independent expert selected by the managing general partner, but not to exceed the price actually paid to the affiliate by the managing general partner.

 

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Entity receiving compensation		Type and method of compensation
Managing general partner and its affiliates		Drilling Contracts. Each partnership will enter into the drilling and operating agreement with the managing general partner, acting as a third-party general drilling contractor and operator, to drill and complete each partnership’s wells for an amount equal to the sum of the following items: (i) the cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by affiliates of the managing general partner, then those items will be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the managing general partner’s affiliates, which will be charged at competitive rates; (iv) an administration and supervision fee at a competitive rate, which is $60,000 per vertical well and $250,000 per horizontal well, if any, in the Marcellus Shale primary area, which will be charged to you and the other investors as part of each well’s intangible drilling costs and equipment costs; and (v) a mark-up in an amount equal to 15% of the sum of (i), (ii), and (iii), but not (iv), above, for the managing general partner’s services as general drilling contractor. Additionally, if the managing general partner drills a well for a partnership that it determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completing the well or as otherwise determined by the managing general partner, the administration and supervision fee for the well described above may be increased to a competitive rate as determined by the managing general partner.		Estimated Amount Based on the assumptions and the estimated average costs to drill vertical wells in the Marcellus Shale primary area as set forth in “– Drilling Contracts” above, the managing general partner estimates that its average administration and oversight fee and its 15% mark-up paid by you and the other investors will be approximately:   •   $250,800 if the minimum subscription proceeds are received; and   •   $43,432,434 if the maximum subscription proceeds of $300 million are received.   Additionally, affiliates of the managing general partner, including First Class Energy, will provide subcontracting services, equipment and materials in drilling, completing or operating the partnership’s wells for which they will receive competitive rates, because they meet the requirements described in “Conflicts of Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.” Thus, the total compensation paid to the managing general partner and its affiliates per net well will be greater than the estimated amount to be paid to the managing general partner as described above.

 

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Operational Stage
Entity receiving compensation		Type and method of compensation		Estimated amount
Managing general partner and its affiliates		Natural Gas and Oil Revenues. Subject to the managing general partner’s subordination obligation, the investors and the managing general partner will share in each partnership’s revenues in the same percentages as their respective capital contributions bear to the total capital contributions to the partnership, except that the managing general partner will receive an additional 8% of the partnership’s revenues.		For example, subject to the managing general partner’s subordination obligation and assuming the managing general partner contributes 15% of a partnership’s total capital contributions and you and the other investors contribute 85% of the partnership’s total capital contributions, then you and the other investors would receive 77% of the partnership’s net production proceeds and the managing general partner would receive 23% of the partnership’s net production proceeds.
Managing general partner and its affiliates		Per Well Charges. Under the drilling and operating agreement the managing general partner, as operator of the wells, will receive from each partnership reimbursement at actual cost for all direct expenses incurred on behalf of the partnership and well supervision fees at a competitive rate for operating and maintaining the wells during producing operations when the wells begin producing natural gas or oil.		Based on the assumptions and the estimated well supervision fees described in “– Per Well Charges,” above, the managing general partner estimates that it will receive well supervision fees for each partnership’s first 12 months of operation after all of the wells have been placed in production of:   •   $15,360 if the minimum subscription proceeds are received; and   •   $1,232,400 if the maximum subscription proceeds are received.
Managing general partner and its affiliates		Gathering Fees. Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnerships to interstate pipeline systems, local distribution companies, and/or end-users in the area (the “gathering services”). Each partnership will pay a gathering fee to the managing general partner or directly to its affiliates at competitive rates for the gathering services. The gathering fees paid by the partnership to the managing general partner or its affiliates may be increased from time-to-time by the managing general partner, in its sole discretion, but may not be increased beyond competitive rates as determined by the managing		Estimated amount The actual amount of gathering and processing fees to be paid by a partnership to the managing general partner cannot be quantified, because the volume of natural gas that will be produced, transported and processed from the partnership’s wells cannot be predicted.

 

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Entity receiving compensation		Type and method of compensation		Estimated amount
		general partner. Currently, the managing general partner has determined that the competitive rates in the Marcellus Shale primary area where each partnership will drill its wells as described in “Proposed Activities” are as follows:   •   if transported through a pipeline owned by Snyder Brothers, Inc. or MDS Energy, Ltd., which are affiliates of the managing general partner, 10% of the sales price the partnership receives for its natural gas, plus processing, compression and any other operating costs related to the partnership’s natural gas transported, but not less than $0.50 per mcf transported; and   •   if transported through pipelines owned by Furnace Run Pipeline, L.P. or Mushroom Farm Pipeline, L.P., which are affiliates of the managing general partner, $0.60 per mcf transported, plus 4% for compression, dehydration and any other operating costs related to the partnership’s natural gas transported.   The payment of a competitive gathering fee to the managing general partner or its affiliates for their transportation services will be subject to the conditions described in “– Gathering Fees,” above.
Managing general partner and its affiliates		Interest and Other Compensation. The managing general partner or an affiliate will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of a partnership. If the managing general partner or an affiliate provides equipment, supplies, and other services to the partnership, then it may do so at competitive industry rates.		The actual amount of interest and other compensation is not determinable at this time.

 

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Entity receiving compensation		Type and method of compensation
Managing general partner and its affiliates		Costs of Water Disposal. Compensation at a competitive rate for any services provided to a partnership relating to disposal or injection wells and the transportation and treatment or recycling of wastewater from the partnership’s wells.		Estimated amount The actual amount of compensation is not determinable at this time.
Managing general partner and its affiliates		Administrative Costs and Direct Costs. The managing general partner estimates that administrative costs and direct costs allocable to each of the partnerships for the first twelve months after all of its wells have been placed into operation will be approximately $157,000 if the minimum subscription proceeds are received by a partnership and approximately $1,297,000 if the maximum subscription proceeds of $300 million are received by a partnership.		Estimated amount See table below.

The managing general partner further estimates that the amounts of administrative costs and direct costs discussed above will be allocated as follows:

 

Administrative Costs		Minimum Offering Proceeds				Maximum Offering Proceeds
Legal		$	10,000			$	250,000
Accounting		$	10,000			$	250,000
Geological/Engineering		$	10,000			$	250,000
Secretarial		$	35,000			$	35,000
Travel & Entertainment		$	10,000			$	75,000
Office Rent		$	15,000			$	15,000
Telephone		$	2,000			$	2,000
Direct Costs
External Legal		$	10,000			$	75,000
Audit Fees		$	15,000			$	200,000
Tax		$	5,000			$	75,000
Bookkeeping		$	10,000			$	45,000
Sales Logic and other software		$	25,000			$	25,000
TOTAL		$	157,000			$	1,297,000

The method used to determine the amount of administrative costs to be allocated to a partnership will be based on actual costs and the percentage of time the relevant personnel of the managing general partner and its affiliates devoted to the business of the partnership.

 

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TERMS OF THE OFFERING

Subscription to a Partnership

The MDS Energy Public 2012 Program offers for sale up to an aggregate of $300,000,000 of units 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 will offer a minimum of 200 units, which is $2 million, and the partnerships, in the aggregate, will offer a maximum of 30,000 units which is $300 million. The maximum subscription for each partnership must be the lesser of:

 

•

$300 million; or

 

•

$300 million less the total subscription proceeds received by any prior partnerships in the program.

Also, set forth below are the targeted ending dates of the offering of units for each partnership, which are not binding except that the units in each partnership may not be offered beyond that partnership’s offering termination date as set forth below. The managing general partner may close the offering of units in a partnership at any time before that partnership’s offering termination date once the partnership is in receipt of the minimum required subscriptions, and the managing general partner may withdraw the offering of units in any partnership at any time. For example, if MDS Energy Public 2012-A LP and MDS Energy Public 2013-A LP receive the maximum subscription proceeds of $300 million, in the aggregate, then units in MDS Energy Public 2013-B LP will not be offered in 2013.

 

Partnership Name

Required Minimum Subscription

Nonbinding Targeted Subscription Proceeds (1)

Nonbinding Targeted Ending Date (1)

Offering Termination Date (1)

MDS Energy Public 2012-A LP

$

2 million

$

100 million

12/31/12

12/31/12

MDS Energy Public 2013-A LP

$

2 million

$

100 million

07/31/13

12/31/13

MDS Energy Public 2013-B LP

$

2 million

$

100 million

12/31/13

12/31/13

 

(1)

The partnerships will be offered in a series. Thus, units in MDS Energy Public 2013-A LP will not be offered until the offering of units in MDS Energy Public 2012-A LP has terminated. Likewise, units in MDS Energy Public 2013-B LP will not be offered until the offering of units in MDS Energy Public 2013-A LP has terminated.

Units are offered at a subscription price of $10,000 per unit, subject to certain exceptions described in “Plan of Distribution,” and must be paid 100% in cash at the time of subscribing. The subscription price of the units has been arbitrarily determined by the managing general partner because the partnership does not have any prior operations, assets, earnings, liabilities or present value. Your minimum subscription is one unit ($10,000), however, the managing general partner may accept subscriptions for less than one unit in its sole discretion. Also, larger subscriptions will be accepted in $1,000 increments, beginning with $11,000, $12,000, etc.

You may elect to purchase units in a partnership 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 general partner will have exclusive management authority for the partnership.

Each partnership will be a separate business entity from the other partnerships in the program. Thus, as an investor, you will be a partner only in the partnership in which you invest. You will have no interest in the business, distributions, assets or tax benefits of the other partnerships unless you also invested in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership or partnerships in which you invest.

 

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Partnership Closings and Escrow

You and the other investors should make your checks for units payable to “Citizens Bank of Pennsylvania, N.A., Escrow Agent, MDS Energy Public 2012-A LP,” which is the first partnership to be offered, and give your check to your broker/dealer for submission to the dealer-manager and escrow agent. Subscription proceeds for the partnership will be held in a separate interest bearing escrow account at Citizens Bank of Pennsylvania, c/o Institutional Services Group, 870 Westminster Street, RWR 110, Providence, Rhode Island 02903, until the partnership has received subscription proceeds of at least $2 million, excluding the subscription price discounts described in “Plan of Distribution” and excluding any subscriptions by the managing general partner or its affiliates. However, on receipt of the minimum subscription proceeds the managing general partner will break escrow and transfer the escrowed subscription proceeds to a partnership account, enter into the drilling and operating agreement with itself or an affiliate as general drilling contractor and operator, and begin drilling operations for the partnership.

If the minimum subscription proceeds for MDS Public 2012-A LP are not received by the partnership by December 31, 2012, then the subscription proceeds deposited in the escrow account will be promptly returned to you and the other subscribers with interest and without deduction for any fees. See “Risk Factors – Risks Related to an Investment in a Partnership – A Lengthy Offering Period May Result in Delays in the Investment of Your Subscription and Any Cash Distributions From a Partnership to You.” Although the managing general partner and its affiliates may buy up to 5% of the total units sold in the partnership, currently they do not anticipate purchasing any units. If they do buy units, then those units will not be applied towards the minimum subscription proceeds required for the partnership to break escrow and begin operations. Also, any units purchased by the managing general partner and its affiliates must be purchased for investment purposes only, and not with a view toward redistribution.

You will receive interest on your subscription proceeds from the time they are deposited in the escrow account, or a partnership account if you subscribe after the minimum subscription proceeds have been received and escrow has been broken, until they are paid to the managing general partner for use in the partnership’s drilling activities. All interest distributions will be made in the ratio that the product of multiplying the amount of the subscription proceeds of each investor by the number of days the investor’s subscription proceeds were held in the escrow account, or a partnership account after the minimum number of units have been received, bears to the sum of that calculation for all investors whose subscription proceeds are paid to the managing general partner at the same time. Also, interest distributions will be made no later than the partnership’s first cash distribution from the sale of its natural gas and oil. The amount of interest earned on subscription proceeds is expected by the managing general partner to be nominal because subscription proceeds are expected to be quickly paid to the managing general partner for use in the partnership’s operations and the current interest rate on the subscriptions is relatively low.

During each partnership’s escrow period its subscription proceeds will be invested only in short-term securities issued or guaranteed by the United States government. After the funds are transferred to a partnership account and before they are paid to the managing general partner 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 general partner 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. Subscription proceeds will not be commingled with the funds of the managing general partner or its affiliates, nor will subscription proceeds be subject to their creditors’ claims, before they are paid to the managing general partner under the drilling and operating agreement.

Pennsylvania Investors: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to a partnership in this offering, you are cautioned to carefully evaluate the partnership’s ability to fully accomplish its stated objectives and inquire as to the current dollar volume of partnership subscriptions. In addition, subscription proceeds received by a partnership from Pennsylvania investors will be placed into a

 

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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 MDS Energy Public 2012-A LP means that subscriptions for at least $15,000,000 have been received by the partnership from investors, including Pennsylvania investors. If the appropriate minimum has not been met at the end of each 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 each 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 issuer must return such funds within 15 calendar days after receipt of the investor’s request.

Acceptance of Subscriptions

Your execution of the subscription agreement constitutes your offer to buy units in the partnership then being offered and to hold the offer open until your subscription is either accepted or rejected by the managing general partner or you withdraw your offer. To withdraw your subscription agreement, you must give written notice to the managing general partner before your subscription agreement is accepted by the managing general partner. Also, a partnership may not complete a sale of units to you until at least five business days after the date you receive a final prospectus and you will be sent 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 general partner’s acceptance of your subscription is discretionary, and the managing general partner may reject your subscription for any reason without incurring any liability to you for this decision. If your subscription is rejected, then all of your funds will be promptly returned to you together with any interest earned on your subscription proceeds 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’ subscription 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 general partner’s acceptance also constitutes your:

 

•

execution of the partnership agreement and agreement to accept its terms and conditions as a partner; and

 

•

grant of a special power of attorney to the managing general partner to file amended certificates of limited partnership and governmental reports, and perform certain other actions on behalf of you and the other investors as partners of the partnership.

 

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PRIOR ACTIVITIES

Since the managing general partner was recently formed and this is the first public limited partnership it has sponsored, the following tables reflect certain historical data as of February 29, 2012 with respect to previous private development well drilling partnerships sponsored by MDS Energy, Ltd. and M/D Gas, Inc., affiliates of the managing general partner. The tables do not include information concerning any private offering currently being conducted under Regulation D by the managing general partner or M/D Gas, Inc., nor wells acquired by the managing general partner and its affiliates through merger or other form of acquisition, although this information will be provided to you to the extent it is then available on written request to the managing general partner.

Although past performance is no guarantee of future results, the investors in the managing general partner’s, MDS Energy, Ltd.’s and M/D Gas, Inc.’s prior partnerships have not had to make additional capital contributions to their partnerships because of their status as general partners.

The managing general partner and its affiliates sponsored each of their drilling partnerships with the intention to produce natural gas or oil from the partnership’s wells until such time as it became no longer economical for the partnership to continue to operate the wells, rather than selling the partnership’s productive wells during the term of the partnership. The managing general partner anticipates that when each partnership’s wells become depleted, which means generally that the wells cannot produce enough natural gas and oil at the then current prices to economically justify the continued operation of the partnership and its wells, its wells will be sold, plugged and abandoned or otherwise disposed of, and the partnership will be liquidated.

As disclosed in their respective offering documents, each of the managing general partner’s prior partnerships has a maximum term before it is to be liquidated under its partnership agreement as set forth below:

 

Program		Maximum Term of Program
(1)    MDS Wells 2006 LP		December 31, 2035
(2)    MDS Wells 2007 LP		December 31, 2037
(3)    MDS Wells 2008 LP		December 31, 2038
(4)    MDS Wells 2009 LP		December 31, 2039
(5)    MDS Wells 2010 LP		December 31, 2040
(6)    MDS Wells 2011 LP		December 31, 2062

No other date or time period at which any of the managing general partner’s prior partnerships might be liquidated was disclosed in their respective offering documents.

As of the date of the followings tables, none of the managing general partner’s prior partnerships had been liquidated or reached its maximum term under its partnership agreement and each partnership continued to produce natural gas or oil from its wells.

It should not be assumed that you and the other investors in your partnership will experience returns, if any, comparable to those experienced by investors in the prior drilling partnerships sponsored by MDS Energy, Ltd. and M/D Gas, Inc. for several reasons, including, but not limited to, differences in:

 

•

partnership terms;

 

•

property locations and objective formations;

 

•

partnership size; and

 

•

economic considerations.

The results of the prior drilling partnerships should be viewed only as a measure of the level of activity and experience of the principals of MDS Energy, Inc. and M/D Gas, Inc., affiliates of the managing general partner, with respect to drilling partnerships.

 

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M/D GAS, INC. – PRIOR ACTIVITY TABLES

Table 1 sets forth certain sales information of previous development drilling partnerships sponsored by M/D Gas, Inc., an affiliate of the managing general partner.

Table 1

Experience in Raising Funds

as of February 29, 2012

 

Partnership				Number of Original Investors				Investor Capital				M/D Gas, Inc. Capital				Total Capital				Date Operations Began				Date of First Distributions				Years Wells in Production
1. MDS Wells 2008 LP					47			$	6,930,000			$	70,000			$	7,000,000				3/14/2008				September, 2008				3.69
2. MDS Wells 2009 LP					51				8,415,000				85,000				8,500,000				3/10/2009				August, 2009	(2)			2.78
3. MDS Wells 2010 LP					48				10,405,000				105,000				10,510,000				3/2/2010				January, 2011	(2)			1.67
4. MDS Wells 2011 LP (1)					27				7,261,650				73,350				7,335,000				10/27/2011				January, 2012				0.28

 

(1)	This partnership closed December 31, 2011.

(2)	This partnership agreed to a delayed fracking schedule in order to obtain more favorable fracking prices for its wells, which also delayed the date the partnership began making distributions.

Table 2 reflects the drilling activity of previous development drilling partnerships sponsored by the M/D Gas, Inc., an affiliate of managing general partner and its affiliates. All of the wells were development wells. You should not assume that the past performance of the prior partnerships is indicative of the future results of the partnerships in this program.

Table 2

Well Statistics – Development Wells

as of February 29, 2012

 

Partnership		Gross Wells (1)												Net Wells (2)
		Oil				Gas				Dry (3)				Oil				Gas				Dry (3)
1. MDS Wells 2008 LP			0				28				0				0				27.50				0
2. MDS Wells 2009 LP			0				33				0				0				28.10				0
3. MDS Wells 2010 LP			0				23				0				0				15.95				0
4. MDS Wells 2011 LP (4)			0				7				0				0				4.90				0
Total			0				91				0				0				76.45				0

 

(1)	A “gross well” is one which an interest is owned.

(2)	A “net well” equals the actual interest owned in one gross well divided by 100. For example, a 50% interest in a well is one gross well but only a .50 net well.

(3)	For the purposes of this table only, a “Dry Hole” means a well which is plugged and abandoned with or without a completion attempt because the operator has determined that it will not be productive of gas and/or oil in commercial quantities.

(4)	This partnership was still in the process of drilling and completing its wells as of the date of the table. Accordingly, 7 gross and 4.9 net wells have been drilled with 5 gross wells and 4.15 net wells producing as of the date of the table.

 

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M/D GAS, INC. – PRIOR ACTIVITY TABLES

 

Table 3 provides information concerning the operating results of previous development drilling partnerships sponsored by M/D Gas, Inc., an affiliate of the managing general partner. You should not assume that the past performance of the prior partnerships is indicative of the future results of the partnerships in this program.

Table 3

Investor Operating Results – Including Expenses

as of February 29, 2012

 

						TOTAL COSTS												Cash Distributions (4)				Cash Return (5)				Latest Monthly Cash Distribution As of Date of Table (6)
Partnership		Investor Capital				Direct (1)				Admin (2)				Operating (3)
1. MDS Wells 2008 LP		$	6,930,000			$	62,382			$	22,652			$	181,220			$	2,853,790				41	%		$	40,717
2. MDS Wells 2009 LP			8,415,000				67,328				13,865				113,524				2,141,479				25	%(8)		$	86,328
3. MDS Wells 2010 LP			10,405,000				37,791				4,477				37,940				1,144,291				11	%(8)		$	148,931
4.MDS Wells 2011 LP (7)			7,261,650				—				208				2,000				75,942				1	%		$	11,943

 

(1)	Direct costs are costs for maintaining the wells that are not included in the monthly well maintenance or administration charge.

(2)	Administrative charges are $25 per well per month for shallow wells and $50 per well per month for vertical Marcellus Shale wells. For the 2011 program, administrative charges on all wells are $50.

(3)

Operating costs are the monthly well maintenance charges of $200 per well per month for shallow wells and $450 per well per month for vertical Marcellus Shale wells. In the 2011 Program, shallow well maintenance charges are $225 per well per month and vertical Marcellus Shale wells are $500 per well per month.

(4)	This column reflects total cash distributions beginning with the first production from the program and includes the return of the investors’ capital.

(5)	This column reflects total cash distributions beginning with the first production from the program as a percentage of the total amount invested in the program and includes the return of the investors’ capital.

(6)	Net cash was distributed in February 2012 from December 2011 production.

(7)	This partnership closed December 31, 2011.

(8)	This partnership agreed to a delayed fracking schedule in order to obtain more favorable fracking prices for its wells, which also delayed the date the partnership began making distributions.

Table 3A proves information concerning the operating results of previous development drilling partnerships sponsored by M/D Gas, Inc., an affiliate of the managing general partner.

Table 3A

M/D Gas, Inc. Operating Results – Including Expenses

as of February 29, 2012

 

Partnership		MGP Capital				TOTAL COSTS												Cash Distributions (4)				Cash Return (5)				Latest Monthly Cash Distribution As of Date of Table (6)
						Direct (1)				Admin (2)				Operating (3)
1. MDS Wells 2008 LP		$	70,000			$	630			$	229			$	1,831			$	28,827				41	%		$	411
2. MDS Wells 2009 LP			85,000				680				140				1,147				21,630				25	%(8)		$	872
3. MDS Wells 2010 LP			105,000				381				45				383				11,547				11	%(8)		$	1,503
4. MDS Wells 2011 LP (7)			73,350				—				2				20				767				1	%		$	121

 

(1)	Direct costs are costs for maintaining the wells that are not included in the monthly well maintenance or administration charge.

(2)	This column is the administrative charge of $25 per well per month for shallow wells and $50 per well per month for vertical Marcellus Shale wells.

(3)	Operating costs are the monthly well maintenance charges of $200 per well per month for shallow wells and $450 per well per month for vertical Marcellus Shale wells.

(4)	This column reflects total cash distributions beginning with the first production from the program and includes the return of the M/D Gas, Inc.’s capital.

(5)	This column reflects total cash distributions beginning with the first production from the program as a percentage of the total amount invested by M/D Gas, Inc. in the program and includes the return of M/D Gas, Inc.’s capital.

 

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(6)	Net cash was distributed in February 2012 from December 2011 production.

(7)	This partnership closed December 31, 2011.

(8)	This partnership agreed to a delayed fracking schedule in order to obtain more favorable fracking prices for its wells, which also delayed the date the partnership began making distributions.

Table 4 sets forth the managing general partner’s estimate of the federal tax savings to investors in the prior development drilling partnerships sponsored by M/D Gas, Inc., an affilate of the managing general partner, based on the maximum marginal federal tax rate in each year, the share of tax deductions as a percentage of their subscriptions and aggregate cash distributions. You are urged to consult with your own tax advisors concerning your specific tax situation and should not assume that the past performance of M/D Gas, Inc.’s prior partnerships is indicative of the future results of the partnerships in this program.

Table 4

Summary of Investor Tax Benefits and Cash Distribution Returns

As of February 29, 2012

 

Partnership		Investor Capital				1st Year Tax Deduct.  (2)				Eff. Tax Rate				Estimated Federal Tax Savings From (1):												Total				Cash Distribution As of Date of Table (4)				Total Cash Dist. And Tax Savings (5)				Cumulative Percent of Cash Dist. And Tax Savings to Date (5)
														1st Year I.D.C. Deduct. (3)				Depletion Allowance (3)				Depreciation (3)
1.MDS Wells 2008 LP		$	6,930,000				69.9	%			35	%			1,694,683				163,803				558,389			$	2,416,875				2,853,790			$	5,270,665				76	%
2.MDS Wells 2009 LP			8,415,000				72.6	%			35	%			2,138,936				122,651				583,401			$	2,844,988				2,141,479				4,986,467				59	%(8)
3.MDS Wells 2010 LP			10,405,000				72.6	%			35	%			2,643,405				64,285				98,151			$	2,805,841				1,144,291				3,950,132				38	%(8)
4.MDS Wells 2011 LP (7)			7,261,650				75.0	%			35	%			1,906,185				4,103				9,104			$	1,919,392				75,942				1,995,334				27	%

 

(1)	These columns reflect the possible savings in taxes which would have been paid by an investor, assuming full use of deductions available to the investor.

(2)	Actual first year Intangible Drilling Costs (“IDC”) deduction as reported on the partnerships’ federal tax returns.

(3)	The IDC Deductions, Depletion Allowance and Depreciation deductions have been reduced to credit equivalents.

(4)	This column reflects total cash distributions beginning with the first production from the program and includes the return of the investors’ capital.

(5)	This column reflects total cash distributions beginning with the first production from the program and tax savings and includes the return of the investors’ capital.

(6)	These percentages are calculated by dividing the entry for each partnership in the “Total Cash Dist. And Tax Savings” column by that partnership’s entry in the investor capital column.

(7)	This partnership closed December 31, 2011.

(8)	This partnership agreed to a delayed fracking schedule in order to obtain more favorable fracking prices for its wells, which also delayed the date the partnership began making distributions.

Table 5 sets forth payments made to M/D Gas, Inc., an affilate of the managing general partner, from the previous partnerships it sponsored.

Table 5

Summary of Payments to M/D Gas, Inc. and Affiliates

From Prior Partnerships

As of February 29, 2012

 

Partnership		Investor Capital				Leasehold, Drilling and Completion Costs (1)				Cumulative Operator’s Charges				Cumulative Reimbursement of General & Administrative Overhead
1. MDS Wells 2008 LP		$	6,930,000			$	6,930,000			$	183,051			$	22,881
2. MDS Wells 2009 LP			8,415,000				8,415,000			$	114,671			$	14,005
3. MDS Wells 2010 LP			10,405,000				10,405,000			$	38,323			$	4,522
4. MDS Wells 2011 LP (2)			7,261,650				7,261,650			$	2,020			$	210

 

(1)	Excluding M/D Gas, Inc.’s capital and its affiliates’ contributions.

(2)	This partnership closed December 31, 2011.

 

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MDS ENERGY, LTD. – PRIOR ACTIVITY TABLES

 

Table 1 sets forth certain sales information of previous development drilling partnerships sponsored by MDS Energy, Ltd., an affiliate of the managing general partner.

Table 1

Experience in Raising Funds

as of February 29, 2011

 

Partnership		Number of Original Investors				Investor Capital				MDS Energy, Ltd. Capital				Total Capital				Date Operations Began				Date of First Distributions				Years Wells in Production
1. MDS Wells 2006 LP			15			$	2,475,000			$	25,000			$	2,500,000				1/16/2007				May, 2007				5.04
2. MDS Wells 2007 LP			26				3,960,000				40,000				4,000,000				2/19/2007				October, 2007				4.70

Table 2 reflects the drilling activity of previous development drilling partnerships sponsored by MDS Energy, Ltd., an affiliate of managing general partner. All of the wells were development wells. You should not assume that the past performance of the prior partnerships is indicative of the future results of the partnerships in this program.

Table 2

Well Statistics – Development Wells

as of February 29, 2011

 

		Gross Wells (1)												Net Wells (2)
Partnership		Oil				Gas				Dry (3)				Oil				Gas				Dry (3)
1. MDS Wells 2006 LP			0				14				0				0				14				0
2. MDS Wells 2007 LP			0				20				0				0				17.9				0
Total			0				33				0				0				31.9				0

 

(1)	A “gross well” is one which an interest is owned.

(2)	A “net well” equals the actual interest owned in one gross well divided by 100. For example, a 50% interest in a well is one gross well but only a .50 net well.

(3)	For the purposes of this table only, a “Dry Hole” means a well which is plugged and abandoned with or without a completion attempt because the operator has determined that it will not be productive of gas and/or oil in commercial quantities.

Table 3 provides information concerning the operating results of previous development drilling partnerships sponsored by MDS Energy, Ltd., an affiliate of the managing general partner. You should not assume that the past performance of the prior partnerships is indicative of the future results of the partnership in this program.

Table 3

Investor Operating Results – Including Expenses

as of February 29, 2012

 

						TOTAL COSTS												Cash Distributions (4)				Cash Return (5)				Latest Monthly Cash Distribution As of Date of Table (6)
Partnership		Investor Capital				Direct (1)				Admin (2)				Operating (3)
1. MDS Wells 2006 LP		$	2,475,000			$	80,655			$	17,820			$	142,758			$	2,260,288				91	%		$	14,964
2. MDS Wells 2007 LP			3,960,000				92,201				18,430				147,104				2,471,688				62	%		$	23,959

 

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MDS ENERGY, LTD. – PRIOR ACTIVITY TABLES

 

 

(1)	Direct costs are costs for maintaining the wells that are not included in the monthly well maintenance or administration charge.

(2)	Administrative charges are $25 per well per month for shallow wells and $50 per well per month for vertical Marcellus Shale wells.

(3)	Operating costs are the monthly well maintenance charges of $200 per well per month for shallow wells and $450 per well per month for vertical Marcellus Shale wells.

(4)	This column reflects total cash distributions beginning with the first production from the program as a percentage of the total amount invested in the program and includes the return of the investors’ capital.

(5)	This column reflects total cash distributions beginning with the first production from the program as a percentage of the total amount invested in the program and includes the return of the investors’ capital.

(6)	The last cash distribution included in this table was net cash that was distributed in February 2012 from December 2011 production.

Table 3A provides information concerning the operating results of previous development drilling partnerships sponsored by MDS Energy, Ltd., an affiliate of the managing general partner.

Table 3A

MDS Energy, Ltd. Operating Results – Including Expenses

as of February 29, 2012

 

						TOTAL COSTS
Partnership		Investor Capital				Direct (1)				Admin (2)				Operating (3)				Cash Distributions (4)				Cash Return (5)				Latest Monthly Cash Distribution As of Date of Table (6)
1. MDS Wells 2006 LP		$	25,000			$	815			$	180			$	1,442			$	22,831				91	%		$	151
2. MDS Wells 2007 LP			40,000				931			$	186			$	1,486				24,967				62	%		$	242

 

(1)	Direct costs are costs for maintaining the wells that are not included in the monthly well maintenance or administration charge.

(2)	This column is the administrative charge of $25 per well per month for shallow wells and $50 per well per month for vertical Marcellus Shale wells.

(3)	Operating costs are the monthly well maintenance charges of $200 per well per month for shallow wells and $450 per well per month for vertical Marcellus Shale wells.

(4)	This column reflects total cash distributions beginning with the first production from the program and includes the return of MDS Energy, Ltd.’s capital.

(5)	This column reflects total cash distributions beginning with the first production from the program as a percentage of the total amount invested by MDS Energy, Ltd. in the program and includes the return of MDS Energy, Ltd.’s capital.

(6)	The last cash distribution included in this table was net cash that was distributed in February 2012 from December 2011 production.

 

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MDS ENERGY, LTD. – PRIOR ACTIVITY TABLES

 

Table 4 sets forth the managing general partner’s estimate of the federal tax savings to investors in the prior development drilling partnerships sponsored by MDS Energy, Ltd., an affilate of the managing general partner, based on the maximum marginal federal tax rate in each year, the share of tax deductions as a percentage of their subscriptions and aggregate cash distributions. You are urged to consult with your own tax advisors concerning your specific tax situation and should not assume that the past performance of MDS Energy, Ltd.’s prior partnerships is indicative of the future results of the partnerships in this program.

Table 4

Summary of Investor Tax Benefits and Cash Distribution Returns

As of February 29, 2012

 

Partnership		Investor Capital				1st Year Tax Deduct. (2)				Eff. Tax Rate				Estimated Federal Tax Savings From (1):												Total				Cash Distributions As of Date of Table (4)				Total Cash Dist. And Tax Savings (5)				Cumulative Percent of Cash Dist. And Tax Savings to Date (6)
														1st Year I.D.C. Deduct. (3)				Depletion Allowance (3)				Depreciation (3)
1. MDS Wells 2006 LP		$	2,475,000				69.8	%			35	%		$	604,920			$	131,329			$	181,748			$	917,997			$	2,260,288			$	3,178,285				128	%
2. MDS Wells 2007 LP		$	3,960,000				69.7	%			35	%		$	966,151			$	148,815			$	276,936			$	1,391,902			$	2,471,688				3,863,590				98	%

 

(1)	These columns reflect the possible savings in taxes which would have been paid by an investor, assuming full use of deductions available to the investor.

(2)	Actual first year Intangible Drilling Costs (“IDC”) percentage as reported on the partnerships’ federal tax returns.

(3)	The IDC Deductions, Depletion Allowance and Depreciation deductions have been reduced to credit equivalents.

(4)	This column reflects total cash distributions beginning with the first production from the program and includes the return of the investors’ capital.

(5)	This column reflects total cash distributions beginning with the first production from the program and tax savings and includes the return of the investors’ capital.

(6)	These percentages are calculated by dividing the entry for each partnership in the “Total Cash Dist. And Tax Savings” column by that partnership’s entry in the investor capital column.

Table 5 sets forth payments made to MDS Energy, Ltd., an affilate of the managing general partner, from the previous partnerships it sponsored.

Table 5

Summary of Payments to MDS Energy, Ltd. and Affiliates

From Prior Partnerships

As of February 29, 2012

 

Partnership		Investor Capital				Leasehold, Drilling and Completion Costs (1)				Cumulative Operator’s Charges				Cumulative Reimbursement of General & Administrative Overhead
1. MDS Wells 2006 LP		$	2,475,000			$	2,475,000			$	144,200			$	18,000
2. MDS Wells 2007 LP			3,960,000				3,960,000			$	148,590			$	18,616

 

(1)	Excluding MDS Energy, Ltd.’s capital and its affiliates’ contributions.

 

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MANAGEMENT

Managing General Partner

The partnerships will have no officers, directors or employees. Instead, MDS Energy Development, LLC, a Pennsylvania limited liability company, will serve as the managing general partner of each partnership. However, see “– Transactions with Management and Affiliates,” below, regarding the managing general partner’s dependence on its affiliates, primarily MDS Energy, Ltd. and First Class Energy, LLC (“First Class Energy”), for facilities, management and administrative functions. MDS Energy, Ltd. and First Class Energy together currently employ more than 100 employees. See “– Organizational Diagram and Security Ownership of Beneficial Owners,” below. The managing general partner and its affiliates are headquartered at 409 Butler Road, Suite A, Kittanning, Pennsylvania 16201, which is also the primary office of the partnerships.

Officers of Managing General Partner

Since the managing general partner is a limited liability company, and not a corporation, it has no directors. The officers of the managing general partner will serve until their successors are elected. The executive officers of the managing general partner are as follows:

 

NAME		POSITION OR OFFICE
Michael D. Snyder		Chief Executive Officer and President
Russell D. Hogue		Chief Financial Officer
Randall L. Morris, Jr.		Vice President and Chief Engineer
Brannon P. McPherson		Managing Executive Vice President of Partnership Administration
Gregory R. Hill		Executive Vice President of Partnership Administration

With respect to the biographical information set forth below, the approximate amount of an individual’s professional time devoted to the business and affairs of the managing general partner and its affiliates, including MDS Energy, Ltd., M/D Gas, Inc., and First Class Energy, have been aggregated.

Michael D. Snyder, age 27, has been the Chief Executive Officer and President of the managing general partner since its formation in February 2011. Mr. Snyder has over seven years of experience in all phases of natural gas and oil exploration and development in western Pennsylvania. He also serves as the Chief Executive Officer and President of M/D Gas, Inc. since March 2008 and as the sole Director of M/D Gas, Inc. since January 2011. Mr. Snyder previously served as Vice President of M/D Gas, Inc. from its formation in May 2006 until March 2008 and as a director of M/D Gas, Inc. from May 2006 to January 2011. He further serves as President and Chief Executive Officer of First Class Energy since its formation in December 2007, and President of MDS Associated Companies, Inc. since its formation in January 2008 and sole Director of MDS Associated Companies, Inc. since January 2011. Previously, Mr. Snyder served as a director of MDS Associated Companies, Inc. from January 2008 to January 2011. Mr. Snyder will devote approximately 100% of his professional time to the business and affairs of the managing general partner, MDS Energy, Ltd., M/D Gas, Inc., and First Class Energy. Mr. Snyder is a son of David E. Snyder, the Chairman, Chief Executive Officer and President of Snyder Brothers, Inc., the brother of Bryan K. Snyder, a Vice President of Snyder Brothers, Inc., a nephew of Mark A. Snyder, the corporate Secretary of Snyder Brothers, Inc., and a cousin of Benjamin T. Snyder, the Vice President of Marketing of Snyder Brothers, Inc. Mr. Michael Snyder is also an indirect minority shareholder of Snyder Brothers, Inc. Mr. Snyder devotes approximately 95% of his professional time to the business and affairs of the managing general partner and its affiliates.

Russell D. Hogue, age 47, has been the Chief Financial Officer of the managing general partner since its formation in February 2011. Mr. Hogue also serves as Chief Financial Officer of MDS Associated Companies, Inc., M/D Gas, Inc. and First Class Energy since February 2010. Mr. Hogue further serves as the President of Hogue Accounting & Business Services P. C. Previously, he served as the Chief Financial Officer of Creekside Mushroom, an affiliate of Snyder Brothers, Inc. and an agriculture business, from 1994 until he joined MDS

 

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Energy, Ltd. in February 2010, Mr. Hogue is a Certified Public Accountant and he received his Bachelor of Science degree in Accounting from Slippery Rock University in 1987. Mr. Hogue devotes approximately 100% of his professional time to the business and affairs of the managing general partner and its affiliates.

Randall L. Morris, Jr., age 28, has served as the Vice President and Chief Engineer of the managing general partner since February 2011. Mr. Morris also serves as the Vice President and Chief Engineer of M/D Gas, Inc. and MDS Associated Companies, Inc. since July 2008. Before that he was an Engineer for General Electric from May 2005 until April 2007 and he was a Field Engineer Specialist for Northrop Grumman from July 2004 until May 2005. Mr. Morris received a Bachelor of Science degree in Mechanical Engineering from The Pennsylvania State University in 2004. Mr. Morris devotes approximately 100% of his professional time to the business and affairs of the managing general partner and its affiliates.

Brannon P. McPherson, age 40, has served as the Managing Executive Vice President of Partnership Administration of the managing general partnership since December 2011. From March 2007 until joining the managing general partner in December 2011. Mr. McPherson was employed as a Regional Marketing Director by Atlas Energy, L.P. He worked as a retirement sales consultant and in institutional sales and marketing for the Teachers Insurance Annuity Association – College Retirement Equities Fund from January 1995 until March 2007. Mr. McPherson has been licensed as an associated person with ARI since December 2011. Mr. McPherson received a B.A. degree in Writing from Regis College in 1994 and a M.B.A. degree from Regis University in 1998, and he is a registered representative with the dealer-manager. Mr. McPherson devotes approximately 100% of his professional time to the business and affairs of the managing general partner and its affiliates, including MDS Securities.

Gregory R. Hill, age 59, has been the Executive Vice President of Partnership Administration of the managing general partner since November 2011. Prior to forming and then operating Elliot Management Corporation, an investment consulting firm, from September 2005 to September 2008, Mr. Hill served as Director of Investment Capital for the Eastern Region at Cole Capital Corporation from July 2003 to August 2005, Senior Vice President Eastern Markets at NNN Capital from January 2000 to June 2003, and Senior VP-Eastern US for Inland Capital Corporation from August 1985 to January 2000. Most recently he served as Regional Vice President for Mid-Atlantic Sales of American Realty Capital from October 2008 to November 2011. Mr. Hill has been licensed as an associated person with ARI since November 2011. Mr. Hill received his A.B. degree in American Civilization from Brown University in 1975 and is a registered representative with the dealer-manager. Mr. Hill devotes approximately 100% of his professional time to the business and affairs of the managing general partner and its affiliates, including MDS Securities.

Organizational Diagram and Security Ownership of Beneficial Owners

Set forth below is a current organizational chart of MDS Associated Companies, Inc. and its subsidiaries. Except as shown otherwise in the chart, MDS Associated Companies, Inc. owns, directly or indirectly, 100% of the equity interests in the companies shown in the chart. Also, the sole shareholder of MDS Associated Companies, Inc. is Mr. Michael D. Snyder.

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ORGANIZATIONAL DIAGRAM

 

 

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MDS Energy, Ltd., a Pennsylvania Limited Partnership

MDS Energy, Ltd. is a majority-owned subsidiary of MDS Associated Companies, Inc. See “– Organizational Diagram and Security Ownership of Beneficial Owners,” above. The managing general partner depends primarily on MDS Energy, Ltd. and First Class Energy to provide all corporate staff and support services. See “– Transactions with Management and Affiliates,” below. Since MDS Energy, Ltd. is a limited partnership, and not a corporation, it has no officers or directors. The general partner of MDS Energy, Ltd. is M/D Gas, Inc., which is discussed below.

Other Key Personnel.

Adam W. Zellman has been the Production Manager for MDS Energy, Ltd. since October 2007. Mr. Zellman supervises and coordinates the maintenance and production of natural gas from vertical Marcellus Shale wells, in addition to shallower wells drilled to other zones or formations in the Appalachian Basin. He also coordinates survey work, water testing, access roads and site preparation. Mr. Zellman received a Bachelor of Science degree in Environmental Geography from Indiana University of Pennsylvania in 2005.

Sean M. Baker joined MDS Energy, Ltd., in June 2011. Mr. Baker’s duties include participating in drilling engineering, well testing and production design. He received a Bachelor of Science degree in Petroleum and Natural Gas Engineering from The Pennsylvania State University in May 2011.

First Class Energy, LLC (“First Class Energy”), a Pennsylvania Limited Liability Company

First Class Energy is a wholly-owned subsidiary of MDS Associated Companies, Inc. See “– Organizational Diagram and Security Ownership of Beneficial Owners,” above. The managing general partner depends primarily on MDS Energy, Ltd. and First Class Energy to provide all corporate staff and support services. See “– Transactions with Management and Affiliates,” below. Since First Class Energy is a limited liability company, and not a corporation, it has no directors. The executive officers of First Class Energy are as follows:

 

NAME		POSITION
Michael D. Snyder		Chief Executive Officer and President
Russell D. Hogue		Chief Financial Officer

See “– Officers of Managing General Partner” above, for biographical information on Messrs. Snyder and Hogue.

Other Key Personnel.

Paul B. Murray has been the Superintendent of drilling operations for First Class Energy since its formation in 2007. Mr. Murray supervises the day-to-day drilling operations of First Class Energy, including its fracking operations using a coil tubing rig for vertical Marcellus Shale wells. Mr. Murray has over 13 years of experience in natural gas and oil drilling operations, primarily in the Appalachian Basin.

M/D Gas, Inc., a Pennsylvania Corporation

M/D Gas, Inc. is a wholly-owned subsidiary of MDS Associated Companies, Inc. See “– Organizational Diagram and Security Ownership of Beneficial Owners,” above. M/D Gas, Inc. is the general partner of MDS Energy, Ltd., and the executive officers and directors of M/D Gas, Inc. are as follows:

 

NAME		POSITION
Michael D. Snyder		Chief Executive Officer, President and Director
Russell D. Hogue		Chief Financial Officer
Randall L. Morris, Jr.		Vice President and Chief Engineer

 

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See “– Officers of Managing General Partner,” above, for biographical information on Messrs. Snyder, Hogue and Morris.

Remuneration of Officers and Directors

No officer of the managing general partner will receive any remuneration or other compensation from the partnerships. These persons will receive compensation solely from affiliated companies of the managing general partner.

Code of Business Conduct and Ethics

Because the partnerships do not employ any persons, the managing general partner has determined that the partnerships will rely on a Code of Business Conduct and Ethics adopted by MDS Energy Development, LLC that applies to the executive officers, employees and other persons performing services for the managing general partner generally. You may obtain a copy of this Code of Business Conduct and Ethics by a request to the managing general partner at MDS Energy Development, LLC, 409 Butler Road, Suite A, Kittanning, Pennsylvania, 16201.

Transactions with Management and Affiliates

The managing general partner does not directly employ any of the persons responsible for its management or operation. Rather, the personnel of MDS Energy, Ltd. and First Class Energy manage and operate the managing general partner’s business, and they will also spend a substantial amount of time managing their own business and affairs as well as the business and affairs of the managing general partner’s other affiliates, which creates a conflict regarding the allocation of their time between the managing general partner’s business and affairs and their other business interests. In this regard, each partnership’s policies and procedures for reviewing, approving or ratifying related party transactions with the managing general partner are set forth in the partnership agreement, and the material terms of those policies and procedures are discussed in greater detail in “Conflicts of Interest.” In this regard, the managing general partner considers related party transactions to be certain transactions between a partnership and the managing general partner or its affiliates as identified in the partnership agreement. Section 4.03(d) “Transactions with the Managing General Partner” of the partnership agreement provides that transactions between a partnership and the managing general partner and its affiliates that are authorized by the partnership agreement, such as those set forth below, are deemed not to be breaches of the partnership agreement:

 

•

the transfer of leases from the managing general partner to the partnership concerning the amount of acreage that must be transferred in the prospect to the partnership;

 

•

the possible subsequent enlargement of the prospect;

 

•

the limitations on activities of the managing general partner and its affiliates on leases acquired by the partnership;

 

•

the transfer to the partnership of less than the managing general partner’s and its affiliates’ entire interest in the prospect;

 

•

the limitations on the sale of undeveloped and developed leases by the partnership to the managing general partner;

 

•

the requirement that property transactions between the partnership and the managing general partner must be fair and reasonable;

 

•

the transfer of leases between affiliated limited partnerships;

 

•

the sale of all or substantially all of the partnership’s assets;

 

•

the providing of services to the partnership by the managing general partner and its affiliates at competitive rates;

 

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•

loans from the managing general partner to the partnership and no loans from the partnership to the managing general partner or its affiliates;

 

•

farmouts to and from the managing general partner and the partnership;

 

•

commitments of the partnership’s future production;

 

•

sharing in gas marketing arrangements;

 

•

the requirement that transactions between the partnership and the managing general partner must be fair and reasonable;

 

•

advance payments from the partnership to the managing general partner;

 

•

the partnership participating in other partnerships; and

 

•

roll-up limitations, see “Conflicts of Interest” for a more complete discussion; as well as

the compensation and reimbursement of expenses to be paid by the partnerships to the managing general partner and its affiliates under Section 4.04 of the partnership agreement and the potential purchase of units by the managing general partner and its affiliates from you and the other investors pursuant to the partnership’s presentment feature under Section 6.03 of the partnership agreement. See “Presentment Feature.”

The officers of the managing general partner are responsible for applying the partnership’s policies and procedures set forth in the partnership agreement with respect to transactions between the partnerships and the managing general partner and its affiliates, just as they are responsible for applying all of the other provisions of the partnership agreement.

The managing general partner and its officers and affiliates have in the past invested, and may in the future invest, in partnerships sponsored by M/D Gas, Inc. They may also subscribe for units in the partnerships in this program as described in “Plan of Distribution.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION, RESULTS OF OPERATIONS,

LIQUIDITY AND CAPITAL RESOURCES

The partnerships have been formed as limited partnerships under the Delaware Revised Uniform Limited Partnership Act. However, they have not included any historical information in this prospectus since they have no net worth, do not own any properties on which wells will be drilled, have no third-party investors, and have not conducted any operations. See “Capitalization and Source of Funds and Use of Proceeds,” “Proposed Activities,” “Competition, Markets and Regulation,” and “Financial Information Concerning the Managing General Partner and MDS Energy Public 2012-A LP.”

Each partnership will depend on the proceeds of this offering and the managing general partner’s capital contribution to carry out its proposed activities. Each partnership intends to use its subscription proceeds to pay the following:

 

•

the intangible drilling costs of the partnership’s wells; and

 

•

the equipment costs of the partnership’s wells.

The managing general partner will pay all of the partnership’s organization and offering costs and it may pay or contribute all or a portion of the lease acquisition costs, in its discretion, for each well to be drilled by the partnership. See “Capitalization and Source of Funds and Use of Proceeds” and “Compensation – Organization and Offering Costs” and “– Lease Costs.”

The managing general partner believes that each partnership’s liquidity requirements will be satisfied from the following:

 

•

subscription proceeds of this offering;

 

•

the managing general partner’s capital contributions;

 

•

cash flow from future operations; and

 

•

partnership borrowings, if necessary.

The managing general partner also anticipates that no additional funds will be required for operating costs before a partnership begins receiving production revenues from its wells.

All, or substantially all, of the subscription proceeds of you and the other investors in a partnership will be committed or expended within 12 months after the offering of the partnership closes. If a partnership requires additional funds for cost overruns or additional development or remedial work after a well begins producing, then these funds may be provided by:

 

•

subscription proceeds, if available, which will result in the partnership either drilling fewer wells or acquiring a lesser working interest in one or more wells;

 

•

borrowings from the managing general partner, its affiliates, or third-parties if available on terms deemed reasonable by the managing general partner; or

 

•

retaining partnership revenues.

The amount that may be borrowed by a partnership from the managing general partner, its affiliates and third-parties may not at any time exceed 5% of the partnership’s subscription proceeds from you and the other investors and must be without recourse to you and the other investors. Notwithstanding, this limitation will not affect a partnership’s ability to enter into agreements and financial instruments relating to hedging up to 50% of the partnership’s natural gas and oil production and pledging up to 100% of the partnership’s assets and reserves in connection therewith. The partnership’s repayment of any borrowings would be from its production revenues and would reduce or delay your cash distributions.

 

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If the managing general partner loans money to a partnership, which it is not required to do, then:

 

•

the interest charged to the partnership must not exceed the managing general partner’s interest cost or the interest that would be charged to the partnership, without reference to the managing general partner’s financial abilities or guarantees by unrelated lenders, on comparable loans for the same purpose; and

 

•

the managing general partner may not receive points or other financing charges or fees, although the actual amount of the charges incurred from third-party lenders may be reimbursed to the managing general partner.

In June 2011, the managing general partner obtained a $1 million line of credit from Gateway Bank at prime minus .5%, with an initial variable interest rate of 2.750%, which was amended in March 2012 to extend the maturity date to December 31, 2012. The line of credit is secured by a deposit account pledged by an affiliate of the managing general partner. As of March 14, 2012, $353,000 was outstanding under the line of credit. The managing general partner and its affiliates own less than 5% of the total outstanding shares of Gateway Bank.

If the managing general partner were to default under its line of credit, the lender could proceed against the collateral granted to it to secure that indebtedness and if it accelerated the repayment of the borrowing, the managing general partner might not have sufficient assets to repay the line of credit and the managing general partner’s other obligations. Also, any borrowings under the managing general partner’s line of credit will be at variable rates of interest and expose it to interest rate risk. If interest rates increase, the managing general partner’s debt service obligations on the variable rate indebtedness would increase, but not above 18%, even though the amount borrowed remained the same, and its net income would decrease, which could adversely affect its ability to meet its financial obligations to the partnership. See “Risk Factors – Risks Related to an Investment in a Partnership – The Managing General Partner May Not Meet Its Capital Contributions, Indemnification and Purchase Obligations If Its Liquid Net Worth is Not Sufficient.”

 

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PROPOSED ACTIVITIES

Overview of Drilling Activities

The managing general partner anticipates that the subscription proceeds of each partnership will be used to drill primarily vertical development wells in the Marcellus Shale primary area. A development well means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. See “Appendix A” for information concerning the vertical wells in the Marcellus Shale primary area currently proposed by the managing general partner to be drilled by MDS Energy Public 2012-A LP. Stratigraphic means a layer of rock which has characteristics that differentiate it from the rocks above and below it. Stratigraphic horizon generally means that part of a formation or layer of rock with sufficient porosity and permeability to form a petroleum reservoir. However, in the managing general partner’s discretion, up to approximately 25% of the subscription proceeds may be used to drill horizontal development wells in the Marcellus Shale primary area, and up to approximately 20% of the subscription proceeds may be used to drill vertical and/or horizontal development wells in other areas of the United States, including, for example, drilling development wells in the Mid-Continent region of the United States or the Utica Shale geological formation in Ohio. See “ – Secondary Areas of Operations,” below. In this regard, the managing general partner considers a proposed drilling area to be a primary area if it expects to use 10% or more of a partnership’s subscription proceeds to drill wells in the area. The percentages set forth above, however, are estimates and may change materially depending on actual drilling results. See “Capitalization and Source of Funds and Use of Proceeds” and “– Primary Area of Operations – Marcellus Shale Geological Formation in Western Pennsylvania,” below, for a more detailed discussion.

Most, if not all, of the wells expected by the managing general partner to be drilled by each partnership will be classified as natural gas wells, which may produce a small amount of oil. As discussed above, however, the managing general partner may select developmental prospects in a secondary area that may be classified as oil wells, which may also produce natural gas and natural gas liquids, such as ethane, (i.e., “wet gas”), as compared with the natural gas produced from the Marcellus Shale primary area, which is “dry gas” that does not generally include oil or natural gas liquids. Currently, the partnerships do not own any interests in any properties or prospects on which the wells will be drilled.

Each partnership will be a separate business entity from the other partnerships in the program, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invested in the other partnership or partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership or partnerships in which you invest.

Each partnership in the program generally will drill different wells, but they may own working interests and participate in drilling and completing one or more of the same wells. The number of wells to be drilled by a partnership cannot be determined precisely before the funding of the partnership and is determined primarily by:

 

•

the amount of subscription proceeds raised by the partnership (for example, the managing general partner has the sole discretion to sell up to all of the units in MDS Energy Public 2012-A LP and not offer and sell any units in the other partnerships);

 

•

the geographical areas in which wells are drilled by the partnership;

 

•

the partnership’s percentage of working interest owned in the wells, which could range from 1% to 100%;

 

•

the cost of the partnership’s wells, including any cost overruns for intangible drilling costs and equipment costs of the wells which are charged to you and the other investors under the partnership agreement; and

 

•

whether any horizontal wells, which are much more expensive to drill and complete than vertical wells, are drilled.

 

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For the estimated number of wells to be drilled at the minimum subscription proceeds and the maximum subscription proceeds for a partnership, see “Risk Factors – Risks Related to an Investment in the Partnerships – 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,” “Capitalization and Source of Funds and Use of Proceeds – Use of Proceeds,” and “Terms of the Offering.”

Before the managing general partner selects a prospect on which a well will be drilled by a partnership, it will review all available geologic and production data for wells located in the vicinity of the proposed well including, but not limited to:

 

•

various well logs;

 

•

completion reports;

 

•

plugging reports; and

 

•

production reports.

In selecting prospects for drilling, the managing general partner will use information from adjacent prospects or in the immediate area to the extent available to it, such as production information, zone or formation thickness, porosities and water saturations which lead the managing general partner to believe that a proposed well location will be productive. For example, production information from surrounding wells in the area is an important indicator in evaluating the economic potential of a proposed well to be drilled. The managing general partner believes that natural gas production from wells drilled to the Marcellus Shale geological formation is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells located on contiguous prospects. Generally, however, the managing general partner anticipates that there will be little or no production information from surrounding wells for the majority of the wells to be drilled by the partnership, which results in greater uncertainty to you and the other investors. This lack of production information often results from the managing general partner, as operator, proposing a development well to be drilled by the partnership that are adjacent to wells its affiliates or third-parties have previously drilled in prior partnerships or for their own account that have not yet been completed or put on-line to sell production, or have been producing for only a short period of time so there is little or no production information available.

Production information is only one factor, and the managing general partner may propose a well to be drilled by a partnership because geologic trends in the immediate area, such as shale thickness, porosities and water saturations lead the managing general partner to believe that the proposed well location will be productive. A prospect must be classified as proved undeveloped before the managing general partner will drill the well, which generally means that the well is being drilled to a geologic feature that contains proved reserves and is adjacent to a prospect that has or had a productive well. See the partnership agreement for the complete definitions of a “prospect,” “proved reserves” and “undeveloped reserves.”

The managing general partner will not make a final decision on all of the specific wells to be drilled by a partnership until the offering of units in that partnership has ended. The managing general partner, however, will substitute a new prospect if, before drilling begins, there are material adverse events with respect to a prospect. For example, the managing general partner will substitute a prospect if:

 

•

the latest geological and production data in the area from new wells being drilled indicates that the well may be non-productive or less productive than anticipated;

 

•

there are potential title problems;

 

•

drilling rigs, tubular goods and services in the area will not be available;

 

•

approvals by federal and state departments or agencies cannot be obtained; or

 

•

other properties are available that appear to be of a higher quality.

 

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By waiting as long as possible before selecting all of the prospects to be drilled by a partnership, the managing general partner may acquire additional information to help it select better prospects for the partnership, and it may be able to include prospects that were not available when this prospectus was written or even when the offering of units in the partnership is closed.

Primary Area of Operations – Marcellus Shale Geological Formation in Western Pennsylvania

The Marcellus Shale geological formation in western Pennsylvania is situated in a mature producing region in the United States that has well known geologic characteristics as described below, although its geological aspects are continually being evaluated by the managing general partner.

Generally, the Marcellus Shale primary area has the following characteristics:

 

•

geological features such as structure and faulting generally are not factors used to find commercial natural gas production from a well drilled to this formation;.

 

•

the governing factors for commercial production of natural gas appear to be shale quality in terms of net pay zone thickness, porosity, the effectiveness of hydraulic fracturing to stimulate productive capacity in the well, and encountering natural fractures can enhance the productivity of the well;

 

•

natural gas from a well drilled to this formation is produced at rates which decline rapidly during the first few years of operations and, although the well can produce for many years, a proportionately larger amount of the well’s production can be expected within the first several years; and

 

•

it has been the managing general partner’s experience that natural gas production from wells drilled to this formation is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells on contiguous prospects. Thus, as drilling progresses, reserves from newly completed wells are reclassified to the proved developed category and additional adjacent locations are added to proved undeveloped reserves.

See “Risk Factors” and “Prior Activities.” Also, see “Compensation – Drilling Contracts” for the managing general partner’s estimated average cost per vertical well and per horizontal well in the Marcellus Shale primary area.

With respect to horizontal wells that are drilled in this area, if any, there are increased risks and expenses associated with drilling the wells as described in “Risk Factors – Risks Related to the Partnerships’ Oil and Gas Operations – The Managing General Partner Has No Experience in Drilling Horizontal Wells, if Any,” and “– Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells.”

The Marcellus Shale is a highly organic, black shale found throughout the Appalachian Basin and is encountered at depths ranging from approximately 3,000 to 9,000 feet in western Pennsylvania. Prior drilling activities throughout the western portion of Pennsylvania, primarily from deeper Oriskany tests, have proven that the Marcellus Shale is a blanket formation varying in thickness from approximately 95 feet to 140 feet in the intended drilling areas. Porosities and permeabilities in this shale are very low, so to unlock the hydrocarbons and make the well productive a hydraulic fracturing treatment using large amounts of water must be performed. Porosity is the percentage of void space between particles that is available for occupancy by either liquids or gases; and permeability is the property of porous rock that allows fluids or gas to flow through it. Before the large amounts of water used in hydraulic fracturing the wells in the Marcellus Shale can be disposed of, water disposal plans approved by the Pennsylvania Department of Environmental Resources must be obtained, which may delay drilling the wells and could increase the costs of disposing of the wastewater from the well. For example, the managing general partner anticipates that the partnerships will use a typical nitrogen hydraulic fracturing treatment for all of the wells it drills to the Marcellus Shale in western Pennsylvania. A typical nitrogen hydraulic fracturing treatment for a vertical well would consist of approximately 700,000 pounds of sand, 180,000 gallons of water and a small amount of additives in addition to the nitrogen, which would displace

 

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approximately 600,000 gallons of water that would typically be used in a slick water frack of these types of wells. A typical slick water hydraulic fracturing treatment for a horizontal well with a 3,000 foot lateral wellbore would consist of approximately four million pounds of sand, five million gallons of water and a small amount of additives. In the case of horizontal wells, in particular, the managing general partner anticipates that each lateral will be fractured multiple times approximately 350 feet apart to stimulate natural gas flows to the lateral wellbore. In this regard, hydraulic fracturing has been used in drilling hundreds of thousands of wells since 1947 in many areas of the United States including, for example, the Marcellus Shale formation in Pennsylvania, West Virginia and other areas of the Appalachian Basin, the Barnett Shale formation in Texas, and the Bakken Shale formation, which is primarily in North Dakota.

The managing general partner and its affiliates, including its affiliated drilling partnerships, also will drill wells to the Marcellus Shale geological formation in the same areas and during the same time frame as the partnerships in this program, which will create conflicts of interest concerning which wells will be drilled for their own account or for their other partnerships and which wells will be drilled for the partnerships. See “Conflicts of Interest – Conflicts Regarding Other Activities of the Managing General Partner, the Operator and their Affiliates” and “– Conflicts Involving the Acquisition of Leases.”

Subject to certain limitations as described in “– Acquisition of Leases” and “– Drilling Rights Retained by Managing General Partner,” below, the wells drilled by the partnerships to the Marcellus Shale geological formation will be subject to the following:

 

•

for vertical wells a prospect will be limited to not more than approximately 7.85 acres consisting of a circle with a radius of 330 feet from the wellbore and extending in depth from the bottom of the Tully Limestone formation to the top of the Onondaga Limestone formation, subject to minimum spacing limitations under Pennsylvania law and as adjusted to take into account lease boundaries;

 

•

for a horizontal well, if any, which may include horizontal drilling in one or more laterals in different directions through one or more vertical wellbores drilled on the same well pad, the prospect will be limited to the wellbore plus up to approximately 125 feet on all sides of the center line of each lateral in the well, and extending from the beginning of the first perforation to the end of the last perforation and will be further limited to a depth from the bottom of the Tully Limestone formation to the top of the Onondaga Limestone formation and as adjusted to take into account lease boundaries;

 

•

the wells will be drilled vertically to approximately 6,500 to 8,000 feet or more in depth and each lateral in a horizontal well, if any, is expected by the managing general partner to extend up to approximately 4,000 feet;

 

•

water, sand, and chemicals used in the hydraulic fracturing process for each well will be transported by truck to each drilling location and wastewater from the wells will first be placed in holding pits on the well location and then trucked to wastewater disposal wells or treatment facilities, which may be situated in eastern Ohio; and

 

•

classified as natural gas wells that may produce a small amount of oil.

Also, a vertical well may be drilled on the same well pad as a horizontal well, if any, and one or more laterals may be drilled horizontally on the same prospect. Accordingly, the number of prospects that the managing general partner will assign to a partnership is not expected by the managing general partner to be the same as the number of wells that the partnership drills, assuming each lateral in a horizontal well, if any, is deemed a separate well.

Secondary Areas of Operations

The managing general partner has the right to use up to approximately 20% of the subscription proceeds of each partnership to drill vertical and/or horizontal development wells in other areas of the United States where the managing general partner and its affiliates have no drilling experience. In this event, the managing general

 

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partner anticipates that the partnership would either participate with, or employ, an experienced independent third-party operator in the area in drilling the well. See “Risk Factors” and “Compensation.” The conditions that will prompt the managing general partner to select developmental properties in secondary areas are access to prospects that generally meet the same criteria as the Marcellus Shale primary area or that the managing general partner anticipates would more likely to be classified primarily as developmental oil wells, or natural gas wells that will also produce natural gas liquids and/or oil, rather than dry natural gas, such as that the managing general partner anticipates will be produced from natural gas wells drilled in the partnerships’ Marcellus Shale primary area in western Pennsylvania.

Acquisition of Leases

The managing general partner will have the right, in its sole discretion, to select the prospects which each partnership will drill as described in “Compensation – Lease Costs” and the leases for each partnership well to be drilled will be contributed to the partnership by the managing general partner or its affiliates and credited to the managing general partner as a part of its required capital contribution to the partnership. Also, the leases assigned to the partnership will be limited as described in “– Drilling Rights Retained by the Managing General Partner,” below, and “Conflicts of Interests – Conflicts Involving the Acquisition of Leases.” Neither the managing general partner nor its affiliates will receive any royalty or overriding royalty interest on any well.

The managing general partner anticipates that it will select the prospects in the Marcellus Shale primary area for each partnership, including any additional and/or substituted prospects, from the following:

 

•

leases in its and its affiliates’ existing leasehold inventory;

 

•

leases that are subsequently acquired by it or its affiliates; or

 

•

leases owned by independent third-parties that may participate with the partnership in drilling wells.

The managing general partner anticipates that the partnerships will not farmout any operation associated with their respective wells. However, the need for a farmout might arise, for example, if a vertical well is drilled and during drilling or subsequently the managing general partner determines that the partnership does not have the funds to complete the well or there might be a productive horizon in the wellbore situated above (i.e. uphole) the target horizon, but the partnership does not have the funds to complete the well in the shallower horizon or the completion of the shallower horizon would be inconsistent with the partnership’s objectives. In this event, the managing general partner might decide to farmout the completion of the well. Generally, a farmout in the case of a partnership is an agreement in which the partnership, as the owner of the existing well, agrees to assign a portion of its interest in the existing well to an assignee subject to the assignee completing or recompleting the existing well. The partnership would retain the remaining ownership interest in the existing well. See “Conflicts of Interest – Conflicts Involving the Acquisition of Leases” for the procedure for a farmout, and “Federal Income Tax Consequences – Farmouts.”

Drilling Rights Retained by Managing General Partner in the Marcellus Shale Primary Area. The partnerships’ leases covering vertical wells in the Marcellus Shale primary area generally will be limited to the wellbore and the acreage within a circle having a radius of 330 feet from the wellbore and will further be limited to only the Marcellus Shale geological formation. The managing general partner will retain all other lease interests, including the shallower, deeper and contiguous geological formations and zones, and other drilling rights, which includes ownership of any coal bed methane production that might be obtained from zones or formations in a well that were not transferred to the partnership. However, the managing general partner and its affiliates, including their affiliated partnerships, will not drill another vertical well to the Marcellus Shale geological formation within 330 feet of the wellbore of a productive vertical well previously drilled by a partnership, nor will they complete a horizontal well or any of its laterals within 330 feet of the wellbore of any producing partnership well in the Marcellus Shale primary area. See “– Primary Area of Operations – Marcellus Shale Geological Formation in Western Pennsylvania,” above, “– Acquisition of Leases,” above, and “Compensation – Lease Costs,” for a more detailed description of the leases and drilling rights to be assigned to the partnerships.

 

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The amount of the credit the managing general partner receives for the leases it contributes to a partnership will not include any value allocable to the drilling rights in a lease retained by it. If, in the future, the managing general partner undertakes any activities with respect to zones or formations covered by the leases that were not assigned to the partnership, subject to certain limitations described in “Conflicts of Interest – Conflicts Involving the Acquisition of Leases,” then the partnership would not share in the profits from these activities, nor would the partnership pay any of the associated costs.

Interests of Parties

Generally, production and revenues from a well drilled by a partnership will be net of the applicable landowner’s royalty interest, which is typically 1/8th (12.5%) of gross production, and any interest in favor of third-parties such as an overriding royalty interest. Landowner’s royalty interest generally means an interest that is created in favor of the landowner when an oil and gas lease is obtained; and overriding royalty interest generally means an interest that is created in favor of someone other than the landowner such as a third-party operator. In either case, the owner of the interest receives a specific percentage of the natural gas and oil production free and clear of all costs of development, operation, or maintenance of the well. This is compared with a working interest, which is the type of interest each partnership will own in all its wells and 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. No royalty interests in a partnership’s leases, however, will be owned by the managing general partner or its affiliates. Also, the leases will be subject to terms that are customary in the industry such as free gas to the landowner-lessor for home heating requirements, etc.

The following charts express the managing general partner’s estimate of the percentage of production revenues that the managing general partner, the landowner, other third-parties, and you and the other investors in each partnership will share in from the wells drilled to the Marcellus Shale formation. The charts assume that the partnership owns 100% of the working interest in the well. Net revenue interest generally means the percentage of revenues the owner of an interest in a well is entitled to receive under the lease. If a partnership acquires a lesser percentage working interest in a well, then the partnership’s net revenue interest in that well will decrease proportionately.

The actual number, identity and percentage of working interests or other interests in prospects to be acquired by the partnerships will depend on, among other things:

 

•

the amount of subscription proceeds received by each 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 prospects;

 

•

farmins and farmouts; and

 

•

continuing review of other prospects that may be available.

 

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Table of Partnership’s Net Revenue Interest Anticipated by the Managing General Partner in Vertical Wells in the Marcellus Shale Primary Area (1)

 

Entity		Partnership Interest		Third Party Royalty Interest		86.43% Partnership Net Revenue Interest (3)
Managing General Partner		23% partnership interest (3)					19.88	%
Investors		77% partnership interest (3)					66.55	%
Third-Party				13.57% Landowner Royalty Interest (2)			13.57	%
							100.00	%

 

(1)

These percentages are for illustration purposes only, and assume that a partnership has a 100% working interest and the managing general partner makes a 15% required capital contribution to the partnership and the capital contributions from you and the other investors total 85%. The actual percentages are likely to be different because they will be based on the actual capital contributions to the partnership of the managing general partner and you and the other investors. See “Compensation – Natural Gas and Oil Revenues.”

(2)	Landowner royalty interests are negotiated and may vary.

(3)

Interests in favor of independent third-parties that are not currently known by the managing general partner, such as overriding royalty interests, net profits interests, carried interests, production payments, reversionary interests pursuant to farmouts or non-consent elections under joint operating agreements, or other retained or carried interests may exist, which would reduce a partnership’s net revenue interest.

Secondary Areas

Although the managing general partner anticipates that each partnership will have a net revenue interest ranging from 69.5% to 87.5% in its leases in any secondary areas, assuming the partnership owns 100% of the working interest, there is no minimum net revenue interest that a partnership is required to own in any vertical or horizontal well to be drilled in any secondary area in other areas of the United States, including, for example, the Mid-Continent region of the United States or the Utica Shale geological formation in Ohio. The leases in these areas may be subject to interests in favor of independent third-parties that are not currently known by the managing general partner, such as overriding royalty interests, net profits interests, carried interests, production payments, reversionary interests pursuant to farmouts or non-consent elections under joint operating agreements, or other retained or carried interests.

Title to Properties

Title to all leases acquired by a partnership ultimately will be held in the name of the partnership. However, to facilitate the partnership’s acquisition of the leases title to the leases may initially be held in the name of the managing general partner, the operator, their affiliates, or any nominee designated by the managing general partner, which may included a third-party operator. Title to the leases covering the partnership’s productive wells will be transferred to the partnership and filed for record from time to time after the wells are drilled and completed.

The managing general partner will take the steps it deems necessary to assure that each partnership has acceptable title for its purposes. However, it is not the practice in the natural gas and oil industry to warrant title or obtain title insurance on leases and the managing general partner will provide neither for the leases it assigns to the partnerships. The managing general partner will obtain a favorable formal title opinion for the leases before each well is drilled, but will not obtain a division order title opinion after the well is completed. The managing general partner may use its own judgment in waiving title requirements and will not be liable for any failure of title of the leases transferred to a partnership. Also, a partnership may experience losses from title defects excluded from, or not disclosed by, the formal title opinion that is provided to the managing general partner or its affiliate before a well is drilled or that would have been disclosed by a division order title opinion

 

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after the well is drilled, if the partnership obtained division order title opinions, which it will not do. Although past performance is no guarantee of future results, the managing general partner’s affiliates, MDS Energy, Ltd. and M/D Gas, Inc., and their prior partnerships, have participated in drilling approximately 150 wells in the Appalachian Basin since 2007 and none of the wells have been lost because of title failure.

Drilling and Completion Activities; Operation of Producing Wells

On receipt of a partnership’s minimum subscription proceeds, the managing general partner on behalf of the partnership will do the following:

 

•

release the funds from the escrow account;

 

•

transfer the escrowed funds to a partnership account;

 

•

enter into the drilling and operating agreement, which is attached to the partnership agreement as Exhibit II, with itself or an affiliate of the managing general partner as operator; and

 

•

begin drilling the partnership’s wells.

Under the drilling and operating agreement, the responsibility for drilling and either completing or plugging partnership wells will be on the managing general partner or an affiliate of the managing general partner as the operator and the general drilling contractor. Under the drilling and operating agreement, the partnership is required to prepay the drilling and completion costs of its wells to the managing general partner, as the general drilling contractor and operator. If one or more of the partnership’s wells will be drilled within the first 90 days in the calendar year after the year in which the advance payment is made, then under the current tax law the required advance payment allows the partnership to secure tax benefits of prepaid intangible drilling costs provided that there is a substantial business purpose for the advance payment under the drilling and operating agreement. The managing general partner, as operator and general drilling contractor, expects that it will begin drilling all of each partnership’s wells no later than the 90^th day of the next year immediately following the year in which the offering of units in that partnership closes. See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership” and “Federal Income Tax Consequences – Drilling Contracts.”

During drilling operations the managing general partner’s duties as operator and general drilling contractor will include:

 

•

making the necessary arrangements for drilling and completing partnership wells and related facilities for which it has responsibility under the drilling and operating agreement, such as:

 

•

determining the exact location where the wellbore will be drilled after reviewing geologic information it has compiled;

 

•

selecting the provider of the drilling rig;

 

•

determining whether to use a pull down drilling rig or a conventional rotary drilling rig or a rig for horizontal drilling; and

 

•

scheduling the drilling rig;

 

•

managing and conducting all field operations in connection with drilling, testing, and equipping the wells, which includes receiving and paying invoices from the subcontractors, reviewing that the invoices are reasonable, and monitoring compliance by each subcontractor with its contract; and

 

•

making the technical decisions required in drilling and completing the wells, such as:

 

•

determining how much casing should be placed in the well, which depends primarily on the depth of the well and whether or not the well will be drilled horizontally;

 

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•

designing the fracturing program for the well, which includes how much water and how much and what kind of fluid or gel to pump into the wellbore, whether sand or foam should be pumped into the wellbore and, if so, how much, and whether or not nitrogen should be pumped into the wellbore;

 

•

designing the cementing program for the well, including a plan to contain any water that may be encountered in the wellbore, such as cementing certain formations in the well;

 

•

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;

 

•

designing water disposal plans and obtaining required state permits; and

 

•

in the case of horizontal wells, if any, determining the number of laterals, the length of each lateral and the fracturing and completion program for each lateral, which may include, for example, up to approximately 11 hydraulic fracturing treatments.

All partnership wells will be drilled to a sufficient depth to test thoroughly the objective geological formation unless the managing general partner determines in its sole discretion that the well should be completed in a formation uphole from the objective geological formation. With respect to the horizontal wells, there are increased risks associated with drilling the wells as described in “Risk Factors – Risks Related to the Partnerships’ Oil and Gas Operations – The Managing General Partner Has No Experience in Drilling Horizontal Wells, if Any, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells.” In the case of horizontal wells, if any, the managing general partner will select drilling companies or consultants that are experienced in drilling horizontal wells to serve as subcontractors.

Under the drilling and operating agreement the managing general partner, as operator and general drilling contractor, will complete each well if there is a reasonable probability of obtaining commercial quantities of natural gas or oil. If the managing general partner, as operator and general drilling contractor, determines that a well should not be completed, then the well will be plugged and abandoned.

During producing operations the managing general partner’s duties, as operator, will include:

 

•

managing and conducting all field operations in connection with operating and producing the wells;

 

•

making the technical decisions required in operating the wells;

 

•

maintaining the wells, equipment, and facilities in good working order during their useful life; and

 

•

transporting wastewater for treatment, recycling or disposal.

The managing general partner, as operator, will be reimbursed for its direct expenses and will receive well supervision fees at competitive rates for operating and maintaining the wells during producing operations. In the event a partnership acquires less than 100% of the working interest in a well, then the managing general partner may not serve as the actual operator of the well, or the lease acquisition agreement may require that an independent third-party serve as operator of the well. In those cases, the managing general partner will still supervise the performance and activities of the third-party operator of the well on behalf of the partnership as a co-owner of the working interest in the well and the managing general partner will monitor the drilling and completion operations and supervise the production operations of the well. For performing these duties, the managing general partner will be reimbursed by the partnership for its direct expenses and will receive well supervision fees at competitive rates for supervising the third-party operator on behalf of the partnership as discussed in “Compensation.” In this regard, the managing general partner anticipates that it will serve as the actual operator of each partnership’s wells to be drilled in the Marcellus Shale primary area. As discussed in

 

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“Summary of Drilling and Operating Agreement,” the drilling and operating agreement contains a number of other material provisions which you are urged to review. The managing general partner expects that it will subcontract the actual drilling and day-to-day operation of the partnership’s wells, subject to its supervision, to its affiliates or third-parties.

Also, one or more wells may be drilled by a partnership with third-parties owning a portion of the working interest in the wells. Any other working interest owner in a well will have a separate participation agreement with the managing general partner for drilling and operating the well, which will contain different terms and conditions from those contained in the partnership’s drilling and operating agreement. See “Federal Income Tax Consequences – Drilling Contracts.”

Sale of Natural Gas and Oil Production

For natural gas sold during their previous three fiscal years in the Marcellus Shale primary area, the managing general partner’s affiliates received an average selling price after the effects of hedging arrangements, but before deducting all expenses, including transportation expenses, of approximately:

 

•

$6.49 per 1,000 cubic feet of natural gas (“mcf”) in 2009;

 

•

$5.63 per mcf in 2010; and

 

•

$4.86 per mcf in 2011.

Notwithstanding, natural gas prices are volatile and could decrease in the future.

Crude oil produced from a partnership’s wells will flow directly into storage tanks where it will be picked up by the oil company, a common carrier, or pipeline companies acting for the oil company which is purchasing the crude oil. Unlike natural gas, crude oil does not present any transportation problem. The managing general partner anticipates selling any oil produced by the wells to regional oil refining companies at the prevailing spot market price in the area. In this regard, the managing general partner and the prior investment drilling partnerships sponsored by its affiliates have not drilled any oil wells. However, Snyder Brothers, Inc., an affiliate of the managing general partner, and its affiliates received an average selling price for oil during their previous three fiscal years of approximately $69.33 per barrel in 2009, $84.40 per barrel in 2010 and $86.35 per barrel in 2011. During the term of the partnership it is anticipated that the price of oil will be uncertain and volatile.

Policy of Treating All Wells Equitably in a Geographic Area. Under the partnership agreement, all benefits and liabilities from marketing arrangements or other relationships affecting the property of the managing general partner or its affiliates and the partnerships must be fairly and equitably apportioned according to the respective interests of each party in the property. For example, if a portion or all of the natural gas produced by a partnership in an area must be shut-in, in the managing general partner’s discretion, because of limited gathering line or pipeline capacity, or limited demand and resulting low prices for the natural gas, which increases pipeline pressure, then the production that is sold, if any, will be from those wells that have the greatest well pressure and are able to feed into the pipeline, and the proceeds from these natural gas sales will be credited only to the wells that produced the natural gas sold.

Gathering of Natural Gas. Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area. Under the drilling and operating agreement, the partnership must, at its own cost, construct flowlines as necessary to connect its wells to a pipeline or gathering system. In the partnership’s Marcellus Shale primary area, which the managing general partner anticipates will account for most, if not all, of each partnership’s natural gas production, the managing general partner anticipates that the partnership will use gathering systems and pipelines owned by Snyder Brothers, Inc., MDS Energy, Ltd., and other affiliates of the managing general partner, or those owned by independent third-parties. See “Compensation – Gathering Fees.”

 

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Natural Gas Contracts. As of the date of this prospectus, there are no natural gas supply contracts or other arrangements to which a partnership is a party or that are otherwise binding on the partnerships for the commitment of any portion of a partnership’s natural gas and oil production and the managing general partner is free to use its discretion in locating purchasers for the partnerships’ natural gas and oil production. In this regard, the managing general partner anticipates that most, if not all, of the natural gas produced by the partnerships from the Marcellus Shale primary area will be sold to Snyder Brothers, Inc., an affiliate of the managing general partner, at a competitive price based on prices paid by Snyder Brothers, Inc. to other natural gas producers in the area for similar natural gas. See “Conflicts of Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.” The pricing and delivery arrangements with Snyder Brothers, Inc., and the vast majority of any other natural gas purchasers, generally are tied to the settlement of the New York Mercantile Exchange Commission (“NYMEX”) monthly futures contracts price, which is reported daily in the Wall Street Journal and includes a premium in the Marcellus Shale primary area due to the proximity of the natural gas to the Eastern markets. In this regard, Snyder Brothers, Inc., or any other gas purchaser, will receive the sales proceeds and then distribute each partnership’s share of the sales proceeds to the partnership, less any fees owed by the partnership, such as transportation fees and processing and compression expenses, based on the volume of natural gas produced and sold by the partnership. Until the sales proceeds are distributed to the partnership, they will be subject to the claims of the gas purchaser’s creditors.

Hedging Activities. To limit the partnerships’ exposure to decreases in natural gas and oil prices, each partnership expects to use hedges for up to 50% of its natural gas and oil production, as determined by the managing general partner in its discretion, and the partnership may pledge up to 100% of its assets and reserves in connection therewith. In this regard, the partnership may use financial hedges through contracts such as regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties, as well as physical hedges through its natural gas and oil purchasers as discussed below. The managing general partner does not intend to contract for positions that it cannot offset with actual production. Any physical hedges require firm delivery of natural gas or oil and, therefore, are considered normal sales, rather than hedges, for accounting purposes. The percentages of natural gas and oil that are hedged by each partnership through either financial hedges or physical hedges, or are not hedged at all, will change from time to time in the discretion of the managing general partner, but will not exceed 50% of the partnership’s natural gas and oil production. In this regard, the managing general partner will ensure that the partnerships’ hedging contracts are used solely for hedging price risks and not for speculative purposes. The partnerships’ natural gas and oil production that is not hedged generally will be sold at contract prices in the month produced or at spot market prices.

Although hedging provides a 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 hedges. For example, the partnership would be exposed to the risk of a financial loss if any of the following occur:

 

•

the partnership’s production is substantially less than expected;

 

•

the counterparties to the hedging contracts fail to perform under the contracts, the risk of which is increased because of the current tight credit market in the United States; or

 

•

there is a sudden, unexpected event materially impacting natural gas and/or oil prices.

Subject to the managing general partner’s and its affiliates’ interest in their natural gas contracts or pipelines and gathering systems, all benefits and liabilities from marketing and hedging or other relationships affecting the property of the managing general partner, its affiliates or the partnerships must be fairly and equitably apportioned according to the interests of each in the property based on each partnership’s respective current actual monthly production, consistent with past practice.

The partnerships will not participate in a hedging pool that is operated by Snyder Gas Marketing, a division of Snyder Brothers, Inc., primarily for Snyder Brothers, Inc.’s own account and the account of certain affiliates of Snyder Brothers, Inc., because the managing general partner has determined that the hedging risks of that

 

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hedging pool would not be appropriate for the partnerships. Instead, the managing general partner anticipates that, among other possible hedging arrangements, it will instruct Snyder Gas Marketing, which has years of hedging experience, or a partnership’s other natural gas and oil purchasers, to arrange hedging contracts on terms determined by the managing general partner for that partnership’s sole benefit, in the managing general partner’s discretion. Thus, there will be no need to allocate hedging arrangements, including natural gas and oil production, between the partnership and Snyder Brothers, Inc. and other affiliates of the managing general partner, including the investment drilling partnerships sponsored by MDS Energy, Ltd. and M/D Gas, Inc.

Marketing of Natural Gas and Oil Production from Wells in Secondary Drilling Areas of the United States

The managing general partner expects that any natural gas and oil produced by a partnership from wells in a secondary drilling area, if any, will be primarily tied to the spot market price and supplied to natural gas and oil marketers, local distribution companies, industrial or other end-users, and/or companies generating electricity.

Insurance Claims

Since 2007 MDS Energy, Ltd. and M/D Gas, Inc., affiliates of the managing general partner, and the previous drilling partnerships they have sponsored have been involved in drilling more than 100 developmental wells in Pennsylvania, including approximately 51 vertical Marcellus Shale wells in western Pennsylvania, and they have not yet made any material insurance claims with respect to those drilling activities. For this purpose, the managing general partner defines a material insurance claim as being any claim with respect to which its insurer has paid, or has established a reserve to possibly pay, in excess of $50,000.

Use of Consultants and Subcontractors

The partnerships may use the services of independent outside consultants and subcontractors, which will normally be paid on a per diem or other cash fee basis by the partnership on whose behalf the costs were incurred as either a direct cost or as a direct expense under either the partnership agreement or the drilling and operating agreement. For example, because the managing general partner has no experience in drilling horizontal wells and little or no information with respect to the ultimate recoverable reserves and the production decline rate associated with horizontal wells in any area, the managing general partner anticipates that the partnerships will retain third-party experienced geological engineering consultants and drilling contractors as consultants with respect to any horizontal well to be drilled by a partnership. These charges will be in addition to the costs of subcontractor services provided by the managing general partner’s affiliates, which will be charged at competitive rates, the administration and supervision fee that will be paid to the managing general partner during drilling operations, and the well supervision fees that will be paid to the managing general partner as operator as discussed in “Compensation.”

 

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COMPETITION, MARKETS AND REGULATION

Natural Gas Regulation

Governmental agencies regulate the production and transportation of natural gas. Generally, the regulatory agency in the state where a producing natural gas well is located supervises production activities and the transportation of natural gas sold into intrastate markets, and the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation of natural gas.

Natural gas prices have not been regulated since 1993, and the price of natural gas is subject to the supply and demand for 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. FERC Order 636 was 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.

Crude Oil Regulation

Oil prices are not regulated, and the price is subject to the supply and demand for oil, along with qualitative factors such as the gravity of the crude oil and sulfur content differentials.

Competition and Markets

The partnerships will operate in a highly competitive environment for acquiring leases, contracting for drilling equipment and hydraulic fracturing services, securing trained personnel, and marketing natural gas and oil production from their respective wells. Product availability and price are the principal means of competing in selling natural gas and oil. Many companies engage in natural gas and oil drilling operations and most of the partnerships’ competitors in the areas where the partnerships will drill their wells will have financial resources and staffs larger than those available to the partnerships. This may enable them to identify and acquire desirable leases and market their natural gas and oil production more effectively than the partnerships. Also, the natural gas and oil industry has from time to time experienced periods of rapid cost increases.

Natural gas and oil prices are volatile and may decrease in the future. As an example of volatility of natural gas prices, a ten-year low in natural gas prices of approximately $2.09 per mcf was reached in March 2012, as compared to a natural gas futures price of almost $15 per mcf in 2005. Oil prices over the past 10 years have also experienced volatility. The current relatively low price for natural gas has recently led some companies to curtail a significant portion of their natural gas production until natural gas prices increase at sometime in the future, which cannot be predicted accurately. Also, some natural gas and oil companies have begun drilling wells that they expect will produce oil and/or “wet gas,” from which petroleum liquids can be extracted and sold currently at higher prices, rather than wells that produce mostly “dry gas,” such as the natural gas generally produced from the Marcellus Shale primary area.

 

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Also, the demand for drilling rigs and other related equipment and the costs of drilling and completing natural gas and oil wells have increased over the past few years. As of the date of this prospectus, however, the managing general partner does not expect a problem in obtaining drilling equipment, nor does it anticipate any unreasonable delays in obtaining fracking services for the partnerships’ wells. Because the partnerships’ wells will be drilled on a modified cost plus basis as described in “Compensation – Drilling Contracts,” any increased costs will increase the partnerships’ costs to drill and complete their respective wells and may reduce the number of wells a partnership can drill. Also, any reduced availability of drilling rigs or equipment may make it more difficult to drill the partnerships’ wells in a timely manner or to comply with the prepaid intangible drilling costs rules discussed in “Federal Income Tax Consequences – Drilling Contracts.” Further, over the term of a partnership there may be fluctuating or increasing costs in doing business, such as those associated with disposing of the fluid used to hydraulically frack the partnership’s wells, or dispose of wastewater from the wells, which would directly affect the managing general partner’s ability to operate the partnership’s wells at acceptable cost levels.

The natural gas and oil produced by your partnership’s wells must be marketed in order for you to receive cash distributions from your partnership. Reduced natural gas demand, high inventories of natural gas, and/or excess natural gas supplies have resulted in part from higher natural gas production from drilling activities in unconventional shale formations, including the Marcellus Shale formation in western Pennsylvania, that previously were not economic, but can now be drilled economically by using modern hydraulic fracturing and horizontal drilling technologies. Although the managing general partner and its affiliates have not experienced any problems in selling natural gas and oil in recent years, the prices have varied significantly from time to time. See “Proposed Activities – Sale of Natural Gas and Oil Production.” As set forth above, natural gas and oil prices are not regulated, but instead are subject to factors that are generally beyond a partnership’s and the managing general partner’s control and cannot be accurately predicted such as:

 

•

the cost, proximity, availability, and capacity of pipelines for natural gas and other transportation facilities, the cost to inject hydraulic fracturing fluid in unconventional natural gas geological formations, including the Marcellus Shale primary area in western Pennsylvania, and the cost to transport wastewater from the wells to disposal wells and/or treatment and dewatering 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 gas industry;

 

•

local, state, and federal regulations regarding production, conservation, water disposal and transportation;

 

•

overall domestic and global economic conditions;

 

•

the impact of the U.S. dollar exchange rates on natural gas and oil prices;

 

•

technological advances affecting energy consumption;

 

•

domestic and foreign governmental relations, regulations and taxation;

 

•

the impact of government subsidies of alternative fuels and other energy conservation efforts;

 

•

the general level of supply and market demand for natural gas and oil on a regional, national and worldwide basis;

 

•

weather conditions and fluctuating seasonal supply and demand for natural gas and oil 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 next winter during the summer, which also can lessen seasonal demand fluctuations;

 

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•

economic and political instability, including war or terrorist acts in natural gas and oil producing countries, including those of the Middle East and South America;

 

•

the amount of domestic production of natural gas and oil; and

 

•

the amount and price of imports of natural gas and oil from foreign sources, including imports of natural gas and liquid natural gas from Canada and other countries, and the actions of the members of the Organization of Petroleum Exporting Countries (“OPEC”), which include imposing production quotas for petroleum products from time to time with the intent of increasing, maintaining, or decreasing price levels.

For example, the North American Free Trade Agreement (“NAFTA”) eliminated trade and investment barriers in the United States, Canada, and Mexico. From time to time since then there have been increased imports 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 partnerships’ wells. On the other hand, in January 2012 President Obama rejected the immediate construction of the proposed Keystone XL pipeline, which would have transported oil from Canada to refineries in the Houston, Texas area. Also, a pipeline has been built to help extend the supply of Rocky Mountain Basin natural gas to major markets in the upper Midwest and the eastern United States, which may have the effect of placing downward pressure on Appalachian Basin natural gas pricing, including natural gas produced in the Marcellus Shale primary area. The managing general partner is unable to predict what effect the various factors set forth above will have on the future price of the natural gas and oil sold from the partnership’s wells.

State Regulations

Natural gas and oil operations are regulated by the states where the wells are situated, which includes the Department of Environmental Resources for wells to be drilled in Pennsylvania. In this regard, the states impose a comprehensive statutory and regulatory scheme for natural gas and oil operations, including supervising the production activities and the transportation of natural gas sold in intrastate markets, which creates additional financial and operational burdens. Among other things, these regulations involve:

 

•

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;

 

•

restrictions on hydraulic fracturing, including bans on using hydraulic fracturing, which have been imposed previously, for example, by New York and New Jersey;

 

•

certain well site restoration, groundwater protection, including water disposal plans, and other safety measures;

 

•

discharge permits for drilling operations;

 

•

various reporting requirements; and

 

•

well plugging standards and procedures.

The states also have broad regulatory and enforcement powers including those associated with pollution and the environment as discussed below.

Environmental Regulation

Each 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

 

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environment. The United States Environmental Protection Agency (the “EPA”) and state and local agencies will require the partnerships to obtain permits and take other measures with respect to:

 

•

the discharge of pollutants into navigable waters;

 

•

the disposal, recycling or treatment 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 negligence or misconduct by a partnership. In addition, the partnerships may be subject to fines, penalties and unlimited liability for cleanup costs under various federal laws such as the Federal Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 for oil and/or hazardous substance contamination or other pollution caused by a partnership’s drilling activities or its wells and its production activities. These risks may be increased because of the large amounts of water that will be used by the partnerships to hydraulically frackture their respective wells in the Marcellus Shale primary area as described in “Proposed Activities – Primary Area of Operations – Marcellus Shale Geological Formation in Western Pennsylvania.”

A 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 as described “Risk Factors.” For example, an accidental release of natural gas, oil, hydraulic fracturing fluid or wastewater from one of the partnership’s wells could subject the partnership to substantial liabilities arising from environmental cleanup and restoration costs, claims made by 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 partnerships’ compliance costs and the cost of any remediation that may become necessary. See “– Proposed Regulation,” below.

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

The partnerships’ required compliance with these environmental laws and regulations may cause delays or increase the cost of a partnership’s drilling and producing activities. Because these laws and regulations are frequently changed, the managing general partner is unable to predict the ultimate costs of complying with present and future environmental laws and regulations.

Proposed Regulation

From time to time there are a number of proposals considered by Congress, the EPA and state legislatures and agencies that if enacted would significantly and adversely affect the natural gas and oil industry and the partnerships. The proposals involve, among other things:

 

•

further limiting the disposal of wastewater from wells or the emission of greenhouse gases, such as carbon dioxide, which could substantially increase a partnership’s operating costs and make the partnership’s wells uneconomical to produce;

 

•

imposing additional federal laws and regulations on hydraulic fracturing of wells;

 

•

repealing federal income tax benefits for drilling natural gas and oil wells as discussed in “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership”;

 

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•

new or increased federal and/or state fees for wells;

 

•

new or expanded tax credits and other incentives for the creation or expansion of alternative energy sources to natural gas and oil; and

 

•

establishing a cap and trade system for carbon emissions as part of the effort to combat global warming and reduce reliance on oil, natural gas and coal.

Also, Congress could re-enact price controls on natural gas and oil and additional federal, state and local taxes on natural gas and oil could be imposed. It is impossible to accurately predict what proposals, if any, will be enacted and their subsequent effect on the partnerships’ activities. However, it appears to the managing general partner that the trend is toward increased federal and state regulation of natural gas and oil 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, and the disposal of wastewater from wells. More stringent federal or state regulations could increase the partnerships’ compliance costs or result in possible restrictions on the partnerships’ operations.

 

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PARTICIPATION IN COSTS AND REVENUES

The Managing General Partner’s Required Capital Contribution. The managing general partner’s aggregate capital contributions to each partnership must not be less than 15% of all capital contributions to the partnership. This includes such items as the managing general partner’s:

 

•

credit for the leases it contributes in-kind to the partnership; and

 

•

credit for the partnership’s organization and offering costs paid or incurred by the managing general partner, including the costs of services contributed by the managing general partner to the partnership as organization costs.

The managing general partner’s capital contributions must be paid or made at the time the costs are required to be paid by the partnership, but in any event not later than the end of the year immediately following the year in which the partnership had its final closing.

The partnership agreement provides for the sharing of partnership costs and revenues among the managing general partner and you and the other investors. A tabular summary of the following discussion appears below. Each partnership will be a separate business entity from the other partnerships in the program, and you will be a partner only in the partnership or partnerships in which you invest. You will have no interest in the business, assets, or tax benefits of another partnership or partnerships unless you also made an investment in the other partnership or partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership or partnerships in which you invest.

Costs

 

1.	Organization and Offering Costs. Organization and offering costs will be charged 100% to the managing general partner.

 

•

Organization and offering costs generally means all costs of organizing and selling the offering and includes, but is not limited to, dealer-manager fees, sales commissions, nonaccountable marketing fees, non-cash compensation, and reimbursements for bona fide due diligence expenses. See “Plan of Distribution.”

The managing general partner will pay a portion of each partnership’s organization and offering costs to itself, its affiliates and independent third-parties and it will contribute the remainder to the partnership in the form of services related to organizing this offering. The managing general partner will receive a credit for these payments and services towards its required capital contribution in the partnership. The managing general partner’s credit for its contribution of services for organization costs will be determined based on generally accepted accounting principles. However, the managing general partner will not receive any credit towards its required capital contribution or its revenue share for any organization and offering costs charged to it in excess of 15% of the partnerships’ subscription proceeds. The complete definition of organization and offering costs is set forth in the partnership agreement.

 

2.

Lease Costs. The leases covering a partnership’s wells will be contributed to the partnership in-kind by the managing general partner. The managing general partner’s capital account will be credited with a capital contribution for each contributed lease valued generally at either its cost or fair market value if the managing general partner has reason to believe that cost is materially more than fair market value, except that with respect to leases acquired by the managing general partner in the Marcellus Shale primary area from Snyder Brothers, Inc. or another affiliate, and then contributed to a partnership, the managing general partner’s credit will equal the fair market value of the leases as determined by an appraisal of an independent expert selected by the managing general partner, but not to exceed the price actually paid by the managing general partner for the leases. See “Compensation – Lease Costs.”

 

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In this regard, the “cost” of the leases includes a portion of the managing general partner’s reasonable, necessary and actual expenses for geological, geophysical, engineering, drafting, accounting, legal and other like services allocated to the leases in conformity with generally accepted accounting principles and industry standards. The complete definition of “Cost” is set forth in the partnership agreement.

 

3.	Intangible Drilling Costs. The subscription proceeds of you and the other investors in each partnership will be used to pay 100% of the intangible drilling costs incurred by the partnership in drilling and completing its wells.

 

•

Intangible drilling costs generally means those costs of drilling and completing a well that are currently deductible, as compared with lease costs, which must be recovered through the depletion allowance, and equipment costs, which must be recovered through depreciation deductions. 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 natural gas or oil, as well as the expense of plugging and abandoning any well before a completion attempt.

Although the subscription proceeds of a partnership may be used to pay the costs of drilling different wells depending on when the subscriptions are received, the subscription proceeds of you and the other investors will be used to pay 100% of the intangible drilling costs regardless of when you subscribe. Also, after all of a partnership’s wells have been drilled and completed, which may be eight to twelve months or longer, the managing general partner has the right to revise the allocation of a well’s costs between intangible drilling costs and equipment costs (i.e., “tangible costs”) based on the actual costs of drilling and completing the well, rather than the initial estimate of those costs by the managing general partner before the wells were drilled. However, your share of your partnership’s intangible drilling costs will not be less than approximately 81.6% of your subscription amount for your units.

In addition, even if the IRS successfully challenged the managing general partner’s characterization of a portion of these costs as deductible intangible drilling costs, and instead recharacterized the costs as some other item that may not be currently deductible, such as equipment costs and/or lease acquisition costs, this recharacterization by the IRS would have no effect on the allocation and payment of 100% of the costs by you and the other investors as intangible drilling costs under the partnership agreement. The allocation of each partnership’s costs of drilling and completing its wells between intangible drilling costs, as defined in the partnership agreement, and equipment costs, as defined as “tangible costs” in the partnership agreement, will be made by the managing general partner, in its sole discretion.

 

4.	Equipment Costs. The subscription proceeds of you and the other investors in each partnership will be used to pay 100% of the equipment costs incurred by the partnership in drilling and completing its wells.

 

•

Equipment costs generally means the costs of drilling and completing a well that are not currently deductible and are not lease acquisition costs, although a potential 50% first-year bonus depreciation allowance is available for wells drilled by MDS Energy Public 2012-A LP and placed in service in 2012, if any. See “Federal Income Tax Consequences – Depreciation and Cost Recovery Deductions.”

 

5.

Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating costs, direct costs, administrative costs, and all other partnership costs of each partnership not specifically charged under the partnership agreement will be charged between the managing general partner and you and the other investors in the partnership in the same ratio as the related production revenues are being credited.

 

•

These costs generally include all costs of partnership administration and producing and maintaining the partnership’s wells.

Each well in a partnership will have a different productive life and when a well becomes uneconomic to produce, it will be plugged and abandoned. The costs of plugging and abandoning a well (other than those incurred in connection with drilling a nonproductive well) are shared between the managing general partner and you and the other investors in the same percentage as the related production revenues are being shared.

 

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Typically, the managing general partner will apply the salvage value of the equipment towards this obligation. Since you and the other investors will have paid all of the partnership’s equipment costs, all of the salvage value of the partnership’s equipment will be allocated to you and the other investors. See the “Investor Capital” table in “Capitalization and Source of Funds and Use of Proceeds” for the estimated equipment costs if the minimum or maximum subscription proceeds are received by the partnerships. Also, when a well is plugged and abandoned the partnership’s lease rights may be assigned by the partnership to the managing general partner in return for a cash payment, farmout, overriding royalty interest or other interest in the prospect as determined by the managing general partner, in its discretion, consistent with its fiduciary duty to the partnership.

To cover any potential shortfall in a partnership’s funds for the plugging and abandoning costs of a well, the managing general partner has the right, beginning one year after each partnership well begins producing, to retain up to $200 per month of partnership revenues to cover future plugging and abandonment costs of the well. This $200 also includes the managing general partner’s share of revenues. The managing general partner’s retained revenues will be used exclusively for its share of the plugging and abandonment costs of the well. To the extent any portion of this reserve account ultimately is not required for the plugging and abandonment costs of the well, it will be returned to the general operating revenues of the partnership.

Revenues

Each partnership’s production revenues from all of its wells will be commingled. Thus, regardless of when you subscribe to the partnership you will share in the production revenues from all of the wells in your partnership on the same basis as the other investors in the partnership in proportion to your number of units.

 

1.

Proceeds from the Sale of Leases. If a partnership well is sold, a portion of the sales proceeds will be allocated to the partners in the same proportion as their share of the adjusted tax basis of the property. In addition, proceeds will be allocated to the managing general partner to the extent of any pre-contribution appreciation in value of the property if it contributed the property to the partnership. See “Compensation – Lease Costs.” Any excess will be credited as provided in 4, below.

 

2.

Interest Proceeds. Interest income earned on your subscription proceeds while held in the escrow account will be credited to your account and paid to you no later than the partnership’s first cash distribution from operations. Until your partnership’s subscription proceeds are invested in your partnership’s operations, any interest income from temporary investments will be allocated pro rata to you and the other investors providing the subscription proceeds. All other interest income, including interest earned on the deposit of production revenues, will be credited as provided in 4, below.

 

3.	Equipment Proceeds. Proceeds from the sale or other disposition of equipment will be credited 100% to you and the other investors.

 

4.

Production Revenues. Subject to the managing general partner’s subordination obligation as described below, the managing general partner and you and the other investors in the partnership will share in all of the partnership’s other revenues, including production revenues, in the same percentage as their respective capital contribution bears to the partnership’s total capital contributions, except that the managing general partner will receive an additional 8% of the partnership’s revenues. For example, assuming the managing general partner contributes 15% of your partnership’s total capital contributions and you and the other investors contribute 85% of the partnership’s total capital contributions, then the managing general partner will receive 23% of the partnership revenues and you and the other investors will receive 77% of the partnership revenues. See “Compensation – Natural Gas and Oil Revenues” for a graphic presentation of this amount.

 

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Subordination of Portion of Managing General Partner’s Net Revenue Share

Each partnership is structured to provide you and the other investors with cumulative cash distributions, including all distributions from operations to you and the other investors before the first 12-month subordination period begins, based on a subscription price of $10,000 per unit regardless of the actual subscription price you paid for your units, equal to at least:

 

•

10% of capital (which is $1,000 per $10,000 unit) in each of the first five consecutive 12-month subordination periods; and

 

•

7.5% of capital (which is $750 per $10,000 unit) in each of the next three consecutive 12-month subordination periods.

Each partnership’s first 12-month subordination period will begin on the earlier of when the partnership begins receiving revenues from all of its productive wells, if any, or 12 months after the partnership’s final closing. To help achieve this investment feature, the managing general partner will subordinate up to 60% of its share, as managing general partner, of partnership net production revenues, which will depend on the amount of its capital contributions, during the 96-month, in the aggregate, subordination period. The partnership may begin monthly cash distributions to you and the other investors at any time, in the managing general partner’s discretion.

 

•

Partnership net production revenues means gross revenues after deduction of the related operating costs, direct costs, administrative costs, and all other costs not specifically allocated.

Subordination distributions will be determined by debiting or crediting current period partnership revenues to the managing general partner as may be necessary to provide the distributions to you and the other investors. At any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cumulative cash distributions from your partnership would exceed the intended return of capital described above. The specific formula for determining subordination distributions is set forth in Section 5.01(b)(4)(a) of the partnership agreement.

The managing general partner anticipates that you will benefit from the subordination if the price of natural gas and oil received by your partnership and/or the volume of natural gas and oil produced from the partnership’s wells are unable to provide the intended return of capital. However, if the wells produce small natural gas and oil volumes or natural gas and oil prices decrease, then even with subordination your cash flow may be very small and you may not receive the return of capital described above during the partnership’s 96-month aggregate subordination period.

Example of Net Revenue Sharing During a Subordination Period.

 

Entity		Percentage of Partnership Capital Contributions (1)				Percentage of Partnership Net Revenues Without Subordination (1)				Maximum Amount of Managing General Partner’s Share of Partnership Net Revenues Available for Subordination (1)				Net Revenues to Managing General Partner and Investors  if Maximum Amount of Managing General Partner’s Share of Partnership Net Revenues is Subordinated (1)
Managing General Partner			15	%			23	%			13.8	%			9.2	%
Investors			85	%			77	%							90.8	%

 

(1)

These percentages are for illustration purposes only and assume the managing general partner made a capital contribution of 15% to the partnership and there were capital contributions of 85% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. See “Compensation – Natural Gas and Oil Revenues.”

 

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Table of Participation in Costs and Revenues

The following table sets forth how your partnership’s costs and revenues will be charged and credited between the managing general partner and you and the other investors in the partnership, after deducting from the partnership’s gross revenues the landowner royalties and any other lease burdens. Some of the line items in the table do not have percentages stated, because the percentages will be determined either by the actual costs incurred by the partnership to drill and complete its wells or by the final amount of the managing general partner’s capital contribution to the partnership, which will not be known until after all of the partnership’s wells have been drilled and completed.

 

		Managing General Partner				Investors
Partnership Costs
Organization and offering costs			100	%			0	%
Lease costs			100	%			0	%
Intangible drilling costs (1)			0	%			100	%
Equipment costs (2)			0	%			100	%
Operating costs, administrative costs, direct costs, and all other costs			(3	)			(3	)
Partnership Revenues
Interest income on subscription proceeds (4)			0	%			100	%
Equipment proceeds (2)			0	%			100	%
All other revenues including production revenues and other interest income			(4)(5)(6	)			(4)(5)(6	)
Participation in Deductions and Credits
Intangible drilling costs			0	%			100	%
Depreciation (2)			0	%			100	%
Percentage depletion allowance			(7	)			(7	)

 

(1)	The subscription proceeds of you and the other investors in the partnership will be used to pay 100% of the intangible drilling costs incurred by the partnership in drilling and completing its wells.

(2)

The subscription proceeds of you and the other investors in the partnership will be used to pay 100% of the equipment costs incurred by the partnership in drilling and completing its wells. Equipment proceeds, if any, and depreciation also will be allocated 100% to you and the other investors in the partnership.

(3)	These costs, which also include plugging and abandonment costs of the wells after the wells have been drilled, produced, and depleted, will be charged to the parties in the same ratio as the related production revenues are being credited.

(4)

Your subscription proceeds will earn interest while held in the escrow account, or a partnership account after the escrow account is broken, until they are paid to the managing general partner for use in the partnership’s drilling operations. This interest will be credited to your account and paid to you no later than the partnership’s first cash distribution from operations. All other interest income, including interest earned on the deposit of operating revenues, will be credited as natural gas and oil production revenues are credited.

(5)

The managing general partner and you and the other investors will share in all of the partnership’s other revenues in the same percentage that their respective capital contributions bear to the partnership’s total capital contributions, except that the managing general partner will receive an additional 8% of the partnership’s revenues.

(6)	If a portion of the managing general partner’s partnership net production revenues is subordinated, then the actual allocation of partnership net production revenues between the managing general partner and you and the other investors will vary from the allocation described in (5) above.

(7)	The percentage depletion allowance will be credited between the managing general partner and you and the other investors in the same percentages as the production revenues are being credited.

 

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Allocation and Adjustment Among Investors

The investors’ share as a group of a partnership’s revenues, gains, income, costs, expenses, losses, and other charges and liabilities generally will be charged and credited among you and the other investors in the partnership in accordance with the ratio that your respective number of units bears to the number of units held by all investors as a group in the partnership, based on a subscription price of $10,000 per unit regardless of the actual subscription price you paid for your units. These allocations will take into account any investor general partner’s status as a defaulting investor general partner. Certain investors, however, will pay a discounted subscription price for their units as described in “Plan of Distribution.” Thus, the intangible drilling costs and equipment costs of drilling and completing the partnership’s wells will be charged among you and the other investors in the partnership as set forth above, except that these allocations (i.e., intangible drilling costs and equipment costs) will be based on the respective actual subscription amount paid by you and the other investors for your respective units as set forth on the respective subscription agreements, rather than a deemed subscription price of $10,000 per unit for all of the units.

Distributions

You will be able to recover your investment only through distributions of your partnership’s net proceeds from the sale of its natural gas and oil from productive wells. The managing general partner will review the partnership’s accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any, taking into account its subordination obligation discussed above in “– Subordination of Portion of Managing General Partner’s Net Revenue Share.” Except in the managing general partner’s sole discretion, the partnership will distribute funds to you and the other investors by direct deposit and provide you password-protected access to your check stubs on the Internet, rather than mailing paper checks, in amounts that the managing general partner, in its sole discretion, does not believe are necessary for the partnership to retain. Distributions may be reduced or deferred to the extent partnership revenues are used for any of the following:

 

•

repayment of partnership borrowings;

 

•

cost overruns in drilling or completing one or more wells;

 

•

remedial work to improve a well’s producing capability;

 

•

compensation and fees to the managing general partner as described in “Risk Factors – Risks Related to an Investment in a Partnership – Compensation and Fees to the Managing General Partner Regardless of Success of the Partnership’s Activities Will Reduce Cash Distributions”;

 

•

direct costs and general and administrative expenses of the partnership;

 

•

reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

 

•

indemnification of the managing general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership’s activities.

Also, funds will not be advanced or borrowed by your partnership for the purpose of making distributions to you and the other investors if the amount advanced or borrowed would exceed the partnership’s accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. Any cash distributions from the partnership to the managing general partner will be made only in conjunction with distributions to you and the other investors in the partnership and only out of funds properly allocated to the managing general partner’s account. The partnership may begin monthly cash distributions to you and the other investors at any time, in the managing general partner’s discretion.

Liquidation

Each partnership will continue for 50 years unless it is terminated earlier by a final terminating event as described below, or an event which causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if a partnership terminates on an event which causes a dissolution of

 

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the partnership under state law and it is not a final terminating event, then a successor limited partnership will automatically be formed. Thus, only on a final terminating event will the partnership be liquidated. A final terminating event is any of the following:

 

•

the election to terminate the partnership by the managing general partner or the affirmative vote of investors whose units equal a majority of the total units;

 

•

the termination of the partnership under Section 708(b)(1)(A) of the Internal Revenue Code because no part of its business is being carried on; or

 

•

the partnership ceases to be a going concern.

On your partnership’s liquidation you will receive your interest in the partnership. Generally, your interest in the partnership means an undivided interest in the partnership’s assets, after payments to the partnership’s creditors, in the ratio that your positive capital account bears to the positive capital accounts of all of the partners in the partnership (including the managing general partner) until all of the capital accounts have been reduced to zero. Thereafter, your interest in any remaining partnership assets will equal your interest in the related partnership revenues.

Any in-kind property distributions to you from your partnership must be made to a liquidating trust or similar entity, unless you affirmatively consent to receive an in-kind property distribution after being told the risks associated with the direct ownership of the property or unless there are alternative arrangements in place which assure that you will not be responsible for the operation or disposition of the partnership’s properties. If the managing general partner has not received your written consent to a proposed in-kind property distribution within 30 days after it is mailed, then it will be presumed that you have not consented. The managing general partner may then sell the asset at the best price reasonably obtainable from an independent third-party, or to itself or its affiliates at fair market value as determined by an independent expert. Also, if your partnership is liquidated the managing general partner will be repaid any debts owed to it by the partnership before there are any payments to you and the other investors in the partnership.

 

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CONFLICTS OF INTEREST

In General

Conflicts of interest are inherent in natural gas and oil partnerships involving non-industry investors because the transactions are entered into without arms’ length negotiation. Your interests and those of the managing general partner and its affiliates may be inconsistent in some respects, and the managing general partner’s actions may not be the most advantageous to you. The managing general partner believes that the following discussion describes the material conflicts of interest that may arise for the managing general partner and its affiliates in the course of each partnership, however, other transactions or dealings may arise in the future that could result in conflicts of interest for the managing general partner and its affiliates. For some of the conflicts of interest, but not all, there are certain limitations on the managing general partner that are designed to reduce, but will not eliminate, the conflicts. Other than these limitations the managing general partner has no procedures to resolve a conflict of interest and under the terms of the partnership agreement the managing general partner may resolve the conflict of interest in its sole discretion and best interest.

Further, the managing general partner depends on its affiliates, primarily MDS Energy, Ltd. and First Class Energy, for management and administrative functions. Neither the partnership agreement nor any other agreement requires MDS Energy, Ltd. or First Class Energy to pursue a future business strategy that favors a partnership. The principals of MDS Energy, Ltd. and First Class Energy have a fiduciary duty to make decisions in the best interests of their respective equity owners. Because the managing general partner is allowed to take into account the interests of parties other than the partnerships, such as MDS Energy, Ltd. and First Class Energy, in resolving partnership conflicts of interest, this has the effect of creating a conflict of interest. However, this conflict of interest cannot limit the managing general partner’s fiduciary duty to the partnerships.

Conflicts Regarding Transactions with the Managing General Partner and its Affiliates

When the managing general partner or any affiliate provides services or equipment to a partnership the partnership agreement provides that their fees must be competitive with the fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. Although the managing general partner believes that the compensation that it and its affiliates will receive in connection with the partnerships are reasonable, the compensation has been determined solely by the managing general partner and did not result from negotiations with any unaffiliated third-party dealing at arms’ length. The managing general partner and its affiliates will receive compensation from each partnership for their services in drilling, completing, and operating the partnership’s wells under the drilling and operating agreement and will receive the other fees described in “Compensation” regardless of the success of the partnerships’ wells. The managing general partner and its affiliates providing the services or equipment can be expected to profit from the transactions, and it is usually in the managing general partner’s best interest to enter into contracts with itself and its affiliates, rather than unaffiliated third-parties, even if the contract terms, skill, and experience offered by the unaffiliated third-parties are comparable.

The managing general partner anticipates that most, if not all, of each partnership’s natural gas production will be transported at a competitive rate through pipelines owned by Snyder Brothers, Inc., an affiliate of the managing general partner, and then sold to Snyder Brothers, Inc. at a competitive price based on the price that Snyder Brothers, Inc. pays to other natural gas producers in the area for similar natural gas. This creates a conflict of interest, since it is in Snyder Brothers, Inc.’s best interest to pay the lowest price possible. However, the managing general partner has the right to sell a partnership’s natural gas to other purchasers if it can obtain a higher price, which is not guaranteed.

There is also a conflict of interest concerning the purchase price if the managing general partner or an affiliate purchases a property from a partnership, which they may do in certain limited circumstances as described in “– Conflicts Involving the Acquisition of Leases – (2) Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner,” below.

 

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Conflict Regarding the Partnership Agreement, the Drilling and Operating Agreement and Other Agreements

The managing general partner anticipates that all of the wells to be drilled by each partnership will be drilled and operated under the drilling and operating agreement attached as Exhibit (II) to the partnership agreement. This creates a continuing conflict of interest because the managing general partner must monitor and enforce, on behalf of the partnership, its own compliance as managing general partner with the partnership agreement, as operator with the drilling and operating agreement, and the compliance of its affiliates with any gas gathering, marketing and purchase agreements they have an interest in.

Conflicts Regarding Sharing of Costs and Revenues

The managing general partner will receive a percentage of partnership revenues that is greater than the percentage of partnership costs that it pays. This sharing arrangement may create a conflict of interest between the managing general partner and you and the other investors in your partnership concerning the determination of which wells will be drilled by the partnership based on the risk and profit potential associated with the wells.

Conflicts Regarding Tax Matters Partner

The managing general partner will serve as each partnership’s tax matters partner and will have broad authority to act on behalf of you and the other investors in your partnership in any administrative or judicial proceeding involving the IRS or other tax authorities, and this authority may involve conflicts of interest. For example, potential conflicts include:

 

•

whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, that would decrease:

 

•

the amount of the partnership’s deduction for intangible drilling costs, which is allocated 100% to you and the other investors in the partnership;

 

•

the amount of the partnership’s depreciation deductions, which are allocated 100% to you and the other investors in the partnership; or

 

•

the credit to the managing general partner’s capital account for contributing the leases to the partnership, which would also decrease the managing general partner’s capital contribution to the partnership, its share of partnership revenues, and its liquidation interest in the partnership; and

 

•

the amount charged to the partnership by the managing general partner as reimbursement for expenses incurred by the managing general partner in its role as the tax matters partner.

Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates

The managing general partner will be required to devote to the partnerships the time and attention that it considers necessary for the proper management of each partnership’s activities. However, the managing general partner’s affiliates, MDS Energy, Ltd. and M/D Gas, Inc., have sponsored and continue to manage other natural gas and oil drilling partnerships as set forth in “Prior Activities,” and the managing general partner and M/D Gas, Inc. and their affiliates continue to offer additional private natural gas and oil drilling partnership offerings. The managing general partner also intends to sponsor and manage additional natural gas and oil drilling partnerships, which may be concurrent with this offering or in the future, and it and its affiliates will engage in other oil and gas activities, including drilling either for their own account or on behalf of other partnerships, joint ventures, corporations, or other entities in which they have an interest. This creates a continuing conflict of interest in allocating management time, services, and other activities among the partnerships in this program and the managing general partner’s other activities. See “Management.”

The managing general partner will determine the allocation of its management time, services, and other functions on an as-needed basis consistent with its fiduciary duties among the partnerships in this program and its other partnerships, affiliates and activities. However, the managing general partner depends on its affiliates, primarily

 

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MDS Energy, Ltd. and First Class Energy, for management, facilities and administrative functions as described in “Management – Transactions with Management and Affiliates.” Thus, the competition for the time and services of the managing general partner and its affiliates could result in insufficient attention to the management and operation of the partnerships in this program.

Subject to its fiduciary duties, the managing general partner will not be restricted from participating in other businesses or activities, even if these other businesses or activities compete with a partnership’s activities and operate in the same area as the partnerships in this program. However, the managing general partner and its affiliates may pursue business opportunities for their own account that are consistent with the investment objectives of the partnerships in this program only after they have determined that the opportunity either:

 

•

cannot be pursued by the partnership because of insufficient funds; or

 

•

it is not appropriate for the partnership under the existing circumstances.

Conflicts Involving the Acquisition of Leases

The managing general partner will select, in its sole discretion, the wells to be drilled by each partnership. Conflicts of interest may arise concerning which wells will be drilled by a partnership and which wells will be drilled by the managing general partner and its affiliates for their own account or for other affiliated partnerships, third-party programs or joint ventures in which they serve as driller/operator. It may be in the managing general partner’s or its affiliates’ advantage to have the partnership bear the costs and risks of drilling a particular well rather than another affiliate or itself. Conversely, the managing general partner and its affiliates may elect to drill a well for their own account because of the prospective economic benefits. For example, because the partnership agreement limits the amount of partnership revenues that may be received by the managing general partner and its affiliates, it may be more advantageous for the managing general partner and its affiliates to drill the well for their own account, so that their revenues from the well will not be subject to the partnership’s limitations on the managing general partner’s revenues from partnership wells. See “– Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates,” above. Some of these potential conflicts of interest will be increased if the managing general partner allocates wells to one or more of the partnerships in this program and itself or its affiliates for their own account, or to another affiliated partnership, at the same time. Also, the managing general partner may cause the partnerships to drill wells on leases that are scheduled to expire in order to prevent the expiration of the lease, and a conflict of interest is created with you and the other investors by the managing general partner’s right to cause the partnerships to enter into a farmout with the managing general partner or its affiliates.

The leases assigned by the managing general partner or its affiliates to a partnership for each prospect to be drilled by a partnership will be limited and the managing general partner or its affiliates will retain all lease acreage and drilling rights surrounding the prospects as discussed in “Compensation – Lease Costs,” and “Proposed Activities – Primary Area of Operations – Acquisition of Leases” and “– Drilling Rights Retained by the Managing General Partner.” Also, see the partnership agreement for the complete definition of a “Prospect.”

The managing general partner anticipates that the wells drilled by each partnership will provide the managing general partner and its affiliates with offset sites by allowing it to determine, at the partnership’s expense, the value of adjacent acreage and other geological formations, zones, areas, reservoirs, etc. in which the partnership will not have any interest. In this regard, the managing general partner and its affiliates own acreage throughout the Marcellus Shale primary area where the partnership’s wells will be drilled. As drilling progresses, reserves from newly completed wells will be reclassified to the proved developed category and additional adjacent locations will be added to proved undeveloped reserves. To lessen this conflict of interest, the managing general partner and its affiliates, including their affiliated partnerships, will not drill another vertical well to the Marcellus Shale formation for their own account within 330 feet of an existing partnership vertical well. However, the managing general partner and its affiliates, including their affiliated partnerships, may drill a horizontal well to the Marcellus Shale formation for their own account on the same well pad used by a partnership well or on a different well pad located anywhere else within the 330 feet circle around the wellbore of

 

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the partnership well or on a well pad located more than 330 feet away from the wellbore of the partnership well, and they may drill the horizontal well laterally through all or any portion of the 330 feet circle around the wellbore of the partnership well, without paying any compensation to the partnership, but they may not complete the horizontal well or any of its laterals within 330 feet of the wellbore of the partnership well.

When the managing general partner and its affiliates must provide prospects to two or more partnerships at the same time, the managing general partner will attempt to ensure that each partnership is treated fairly on a basis consistent with:

 

•

the funds available to the partnerships; and

 

•

the time limitations on the investment of funds for the partnerships.

The partnership agreement gives the managing general partner the authority to cause each partnership in this program to acquire less than 100% of the ownership interests in natural gas and oil properties, and to participate with other parties, including other drilling programs previously or subsequently sponsored by the managing general partner or its affiliates, in the conduct of the partnership’s drilling operations on those properties. If conflicts of interest between the partnership and the managing general partner and its affiliates arise, then the managing general partner may be unable to resolve those conflicts to the maximum advantage of the partnership, because the managing general partner and its affiliates must deal fairly with the investors in all of their drilling partnerships, in addition to the equity owners in itself and its affiliates.

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

 

(1)	Transfers of Leases. A portion or all of the leases will be acquired by each partnership, in kind or in cash, from the managing general partner and credited towards the managing general partner’s required minimum capital contribution to the partnership at:

 

•

the cost of the lease, unless the managing general partner has a reason to believe that cost is materially more than the fair market value of the property in which case the managing general partner’s credit for the contribution must be at a price not in excess of the fair market value; except that

 

•

the managing general partner’s credit for leases in the Marcellus Shale primary area it acquires from Snyder Brothers, Inc. or another affiliate, and then contributes to the partnership, if any, will be the fair market value of the leases as set forth in an appraisal of the leases by an independent expert selected by the managing general partner, but not to exceed the actual price paid by the managing general partner. See “Compensation – Lease Costs.”

 

•

A determination of fair market value must be supported by an appraisal from an independent expert and maintained in the partnership’s records for at least six years.

 

(2)	Equal Proportionate Interest. When the managing general partner sells or transfers an oil and gas interest to a partnership, it must, at the same time, sell or transfer to the partnership an equal proportionate interest in all of its other property in the same prospect.

 

•

The term “prospect” generally means an area which is believed to contain commercially productive quantities of natural gas or oil.

However, a prospect will be limited to the minimum area permitted by state law or local practice, whichever is applicable, if the following two conditions are met:

 

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the well is being drilled to a geological feature which contains proved reserves as defined below; and

 

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the limitation protects the well against drainage.

 

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•

Proved reserves, generally, are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. See the partnership agreement for the complete definition of “Proved Reserves.”

Subject to the foregoing, a “Prospect” for wells drilled by the partnerships to the Marcellus Shale geological formation in western Pennsylvania will be deemed:

 

•

for vertical wells in the Marcellus Shale primary area a prospect will be limited to not more than approximately 7.85 acres consisting of the wellbore and the acreage within a circle having a radius of 330 feet from the wellbore and extending in depth from the bottom of the Tully Limestone formation to the top of the Onondaga Limestone formation, subject to minimum spacing limitations under Pennsylvania law and as adjusted to take into account lease boundaries; and

 

•

for horizontal wells in the Marcellus Shale primary area, if any, a prospect will be composed of the wellbore plus 125 feet on all sides of the center line of each lateral in the well, and extending from the beginning of the first perforation to the end of the last perforation and will further be limited to a depth from the bottom of the Tully Limestone formation to the top of the Onondaga Limestone formation, subject to minimum spacing limitations under Pennsylvania law and as adjusted to take into account lease boundaries.

The managing general partner believes that none of the prospects transferred to a partnership will result in drainage from the surrounding wells.

 

(3)	Subsequently Enlarging Prospect. In areas where the prospect is not limited as provided in (2) and the area constituting a partnership’s prospect is subsequently enlarged based on geological information which is later acquired, there is the following special provision:

 

•

if the prospect is enlarged to cover any area where the managing general partner owns a separate property interest and the partnership activities were material in establishing the existence of proved undeveloped reserves which are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold to the partnership in accordance with (1), (2) and (4).

 

(4)	Transfer of Less than the Managing General Partner’s and its Affiliates’ Entire Interest. If the managing general partner sells or transfers to a partnership less than all of its ownership in any prospect, then it must comply with the following conditions:

 

•

the retained interest must be a proportionate working interest;

 

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the managing general partner’s obligations and the partnership’s obligations must be substantially the same after the sale of the interest by the managing general partner or its affiliates; and

 

•

the managing general partner’s revenue interest must not exceed the amount proportionate to its retained working interest.

For example, if the managing general partner transfers 50% of its working interest in a prospect to a partnership and retains a 50% working interest, then the partnership will not pay any of the costs associated with the managing general partner’s retained working interest as a part of the transfer. This limitation does not prevent the managing general partner and its affiliates from subsequently dealing with their retained working interest as they may choose with unaffiliated parties or affiliated partnerships. For example, the managing general partner may sell its retained working interest to a third-party for a profit.

 

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(5)

Limitations on Activities of the Managing General Partner and its Affiliates on Leases Acquired by the Partnership. For a five year period after the final closing of a partnership, if the managing general partner proposes to acquire an interest from an unaffiliated person in a prospect in which the partnership owns an interest or in a prospect in which the partnership’s interest has been terminated without compensation within one year before the proposed acquisition, then the following conditions apply:

 

•

if the managing general partner does not currently own property in the prospect separately from the partnership, then the managing general partner may not buy an interest in the prospect; and

 

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if the managing general partner currently owns a proportionate interest in the prospect separately from the partnership, then the interest to be acquired must be divided in the same proportion between the managing general partner and the partnership as the other property in the prospect. However, if the partnership does not have the cash or financing to buy the additional interest, then the managing general partner is also prohibited from buying the additional interest.

 

(6)

Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner. The managing general partner and its affiliates, other than an affiliated partnership as set forth in (7) below, may not purchase undeveloped leases or receive a farmout from a partnership other than at the higher of cost or fair market value. However, when a well is plugged and abandoned the partnership’s lease rights may be assigned by the partnership to the managing general partner in return for a cash payment, farmout, overriding royalty interest or other interest in the prospect as determined by the managing general partner, in its discretion, consistent with its fiduciary duty to the partnership. Farmouts to the managing general partner and its affiliates also must comply with the conditions set forth in (9) below.

The managing general partner and its affiliates, other than an affiliated income program, may not purchase any producing natural gas or oil property from a partnership unless:

 

•

the sale is in connection with the liquidation of the partnership; or

 

•

the managing general partner’s well supervision fees under the drilling and operating agreement for the well have exceeded the net revenues of the well, determined without regard to the managing general partner’s well supervision fees for the well, for a period of at least three consecutive months.

In both cases, the sale must be at fair market value supported by an appraisal of an independent expert selected by the managing general partner. The appraisal of the property must be maintained in the partnership’s records for at least six years.

 

(7)

Transfer of Leases Between Affiliated Limited Partnerships. Each partnership may joint venture in the drilling of wells with affiliated drilling limited partnerships. In this regard, the transfer of an undeveloped lease from a partnership to an affiliated drilling limited partnership must be made at fair market value if the undeveloped lease has been held by the partnership for more than two years. Otherwise, the transfer may be made at cost if the managing general partner deems it to be in the best interest of the partnership.

An affiliated income program may purchase a producing natural gas and oil property from a partnership at any time at:

 

•

fair market value as supported by an appraisal from an independent expert if the property has been held by the partnership for more than six months or there have been significant expenditures made in connection with the property; or

 

•

cost as adjusted for intervening operations if the managing general partner deems it to be in the best interest of the partnership.

 

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However, these prohibitions do not apply to joint ventures or farmouts among affiliated partnerships, provided that:

 

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the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and

 

•

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

 

(8)

Leases Will Be Acquired Only for Stated Purpose of the Partnerships. Each partnership must acquire only leases that are reasonably expected to meet the stated purposes of the partnership. Also, no leases may be acquired for the purpose of a subsequent sale, farmout or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the partnership’s best interest.

 

(9)

Farmout. The managing general partner may not assign the working interest in a prospect to a partnership for the purpose of a subsequent farmout, sale or other disposition, nor may the managing general partner enter into a farmout to avoid paying its share of the costs related to drilling a well on an undeveloped lease, if any. However, the managing general partner’s decision with respect to making a farmout and the terms of a farmout from a partnership involve conflicts of interest since the managing general partner may benefit from cost savings and reduction of its risk.

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

 

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the partnership lacks the funds to complete the oil and gas operations on the lease or well and cannot obtain suitable financing;

 

•

drilling on the lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the partnership;

 

•

the leases or well activity have been downgraded by events occurring after assignment to the partnership so that development of the leases or well activity would not be desirable; or

 

•

the best interests of the partnership would be served.

If a partnership farmouts a lease or well activity, the managing general partner must retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices.

However, if the farmout is made to the managing general partner or its affiliates there is a conflict of interest since the managing general partner will represent both the partnership and itself or an affiliate. For example, if the managing general partner or an affiliate drills a productive well on a prospect on which a productive partnership well is already located (the “initial well”) pursuant to the terms of a farmout with a partnership because the managing general partner, in its discretion, initially determines that there will not be any communication of natural gas or oil reserves between the new well and the partnership’s initial well on the prospect, but the managing general partner subsequently determines, in its discretion, that the new well drains a portion of the natural gas or oil production from the partnership’s initial well on the prospect, then the managing general partner in its discretion may cause itself or its affiliate, as the farmee, to pay a cash amount or assign an overriding royalty interest or other interest in the new well to the partnership as consideration for the partnership’s decrease in production from its initial well, consistent with the managing general partner’s fiduciary duties. Although the conflict of interest may be resolved to the managing general partner’s benefit, the managing general partner must still retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices.

 

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Conflicts Regarding Selection of Prospects

There are conflicts between you and the managing general partner and its affiliates, because the managing general partner may choose well locations for each partnership that are situated near the gathering systems owned by its affiliates in the Marcellus Shale primary area, which would benefit the managing general partner’s affiliates by providing more gathering fees, even if there are other suitable well locations available in the same area or other areas which may offer the partnership a greater potential return.

Conflicts Between Investors and the Managing General Partner as an Investor

The managing general partner, its officers, and its affiliates may subscribe for units in each partnership and the subscription price of their units will be reduced as described in “Plan of Distribution.” Even though they pay a reduced price for their units, these investors generally will:

 

•

share in the partnership’s costs, revenues, and distributions on the same basis as the other investors as described in “Participation in Costs and Revenues”; and

 

•

have the same voting rights, except as discussed below.

Any subscription for units by the managing general partner, its officers, or its affiliates in a partnership will dilute the voting rights of you and the other investors and there may be a conflict with respect to certain matters. The managing general partner and its officers, and its affiliates, however, are prohibited from voting with respect to certain matters as described in “Summary of Partnership Agreement – Voting Rights.”

Lack of Independent Underwriter and Due Diligence Investigation

The terms of this offering, the partnership agreement, and the drilling and operating agreement were determined by the managing general partner without arms’ length negotiations. You and the other investors have not been separately represented by legal counsel, who might have negotiated more favorable terms in this offering and the agreements for you and the other investors.

Also, there was not an extensive in-depth “due diligence” investigation of the existing and proposed business activities of the partnerships and the managing general partner that would be provided by independent underwriters. Although MDS Securities, which is affiliated with the managing general partner, serves as dealer-manager of this offering, its due diligence examination concerning this offering cannot be considered to be independent or as comprehensive as a due diligence examination that would have been conducted by an independent underwriter.

Conflicts Concerning Legal Counsel

The managing general partner anticipates that its legal counsel will also serve as legal counsel to each partnership and that this dual representation will continue in the future. However, if a future dispute arises between the managing general partner and you and the other investors in a partnership, then the managing general partner will cause you and the other investors to retain separate counsel. Also, if counsel advises the managing general partner that it reasonably believes its representation of a partnership will be adversely affected by its responsibilities to the managing general partner, then the managing general partner will cause you and the other investors in the partnership to retain separate counsel.

 

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Conflicts Regarding Presentment Feature

You and the other investors in a partnership have the right to present your units in the partnership to the managing general partner for purchase beginning with the fifth calendar year after the end of the calendar year in which the offering of units in your partnership closes. This creates the following conflicts of interest between you and the managing general partner.

 

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The managing general partner may suspend the presentment feature if it does not have the necessary cash flow or it cannot borrow funds for this purpose on terms which it deems reasonable. Both of these determinations are subjective and will be made in the managing general partner’s sole discretion.

 

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The managing general partner will also determine the presentment price based on the greater of:

 

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three times the amount of the partnership’s total distributions to you during the past 12 months; or

 

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the amount that is generally attributable to your share of your partnership’s natural gas and oil reserves as discussed in “Presentment Feature.” The formula for arriving at the purchase price based on a reserve report has many subjective determinations that are within the discretion of the managing general partner.

Conflicts Regarding Managing General Partner Withdrawing or Assigning an Interest

A conflict of interest is created with you and the other investors by the managing general partner’s right to mortgage its managing general partner interest in the partnership, and by its right to do either or both of the following, subject to its subordination obligation and, unless there is a substituted managing general partner, a required 1% participation interest in the partnership:

 

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withdraw an interest in the partnership’s wells equal to or less than its revenue interest to be used as collateral for a loan to the managing general partner; or

 

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assign its managing general partner interest in the partnership to its affiliates which also may mortgage the interest as collateral for their loans, if any.

If the managing general partner takes any of the actions described above:

 

•

the amount of partnership net production revenues available to the managing general partner or the affiliated assignee for their respective subordination obligations to you and the other investors could be reduced or eliminated if there was a default under a loan to the managing general partner or the affiliated assignee; and

 

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under certain circumstances, if the managing general partner or an affiliated assignee made a subordination distribution to you and the other investors after a default to its lenders, the lenders may be able to recoup that subordination distribution from you and the other investors.

Procedures to Reduce Conflicts of Interest

In addition to the procedures set forth in “– Conflicts Involving the Acquisition of Leases,” the managing general partner and its affiliates will comply with the following procedures in the partnership agreement to reduce some of the conflicts of interest with you and the other investors. The managing general partner does not have any other conflict of interest resolution procedures. Thus, conflicts of interest between the managing general partner and you and the other investors may not necessarily be resolved in your best interests. However, the managing general partner believes that its significant capital contribution to each partnership will reduce the conflicts of interest.

 

(1)

Fair and Reasonable. The managing general partner may not sell, transfer, or convey any property to, or purchase any property from, a partnership except pursuant to transactions that are fair and reasonable; nor take any action with respect to the assets or property of a partnership which does not primarily benefit the partnership.

 

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(2)

No Compensating Balances. The managing general partner may not use a partnership’s funds as a compensating balance for its own benefit. Thus, a partnership’s funds may not be used to satisfy any deposit requirements imposed by a bank or other financial institution on the managing general partner for its own corporate purposes.

 

(3)	Future Production. The managing general partner may not commit the future production of a partnership well exclusively for the managing general partner’s own benefit.

 

(4)	Disclosure. Any agreement or arrangement that binds a partnership must be fully disclosed in this prospectus.

 

(5)	No Loans from the Partnership. A partnership may not loan money to the managing general partner or any of its affiliates.

 

(6)	No Rebates. The managing general partner may not participate in any business arrangements which would circumvent these guidelines including receiving rebates or give-ups.

 

(7)	Sale of Assets. The sale of all or substantially all of the assets of a partnership may only be made with the consent of investors whose units equal a majority of the total units.

 

(8)	Participation in Other Partnerships. If a partnership participates in other partnerships or joint ventures, then the terms of the arrangements must not circumvent any of the requirements contained in the partnership agreement, including the following:

 

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there may be no duplication or increase in organization and offering expenses, the managing general partner’s compensation, partnership expenses, or other fees and costs;

 

•

there may be no substantive change in the fiduciary and contractual relationship between the managing general partner and you and the other investors; and

 

•

there may be no diminishment in your voting rights.

 

(9)	Investments. A partnership’s funds may not be invested in the securities of another person except in the following instances:

 

•

investments in working interests made in the ordinary course of the partnership’s business;

 

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temporary investments in income producing short-term highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills;

 

•

multi-tier arrangements meeting the requirements of (8) above;

 

•

investments involving less than 5% of the total subscription proceeds of the partnership 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 that duplicative fees and expenses are prohibited.

 

(10)

Safekeeping of Funds. Each partnership’s funds may not be commingled with the funds of any other entity and the managing general partner may not employ, or permit another to employ, the funds or assets of a partnership in any manner except for the exclusive benefit of the partnership. The managing general partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of each partnership whether or not in the managing general partner’s possession or control.

 

(11)	Advance Payments. Advance payments by each partnership to the managing general partner and its affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid intangible drilling costs and for a business purpose.

 

(12)

Policy of Treating All Wells Equitably in a Geographic Area. Under the partnership agreement, all benefits and liabilities from marketing and hedging arrangements or other relationships affecting the property of the managing general partner or its affiliates and the partnership must be fairly and equitably apportioned according to the respective interests of each party in the property.

 

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Policy Regarding Roll-Ups

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

 

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increasing the compensation of the managing general partner;

 

•

amending your voting rights;

 

•

listing the units on a national securities exchange or on NASDAQ;

 

•

changing the partnership’s fundamental investment objectives; or

 

•

materially altering the partnership’s duration.

If a roll-up should occur in the future, the partnership agreement provides various policies which include the following:

 

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an independent expert must appraise all partnership assets as discussed in Section 4.03(d)(16)(a) of the partnership agreement, and you must receive a summary of the appraisal in connection with a proposed roll-up;

 

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if you vote “no” on the roll-up proposal, then you will be offered a choice of:

 

•

accepting the securities of the roll-up entity; or

 

•

one of the following:

 

•

remaining a partner in the partnership and preserving your units in the partnership on the same terms and conditions as existed previously; or

 

•

receiving cash in an amount equal to your pro-rata share of the appraised value of the partnership’s net assets; and

 

•

the partnership will not participate in a proposed roll-up:

 

•

unless approved by investors whose units equal a majority of the total units;

 

•

which would result in the diminishment of your voting rights under the roll-up entity’s chartering agreement;

 

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which includes provisions which would operate to materially impede or frustrate the accumulation of shares by you of the securities of the roll-up entity;

 

•

in which your right of access to the records of the roll-up entity would be less than those provided by the partnership agreement; or

 

•

in which any of the transaction costs would be borne by the partnership if the proposed roll-up is not approved by investors whose units equal a majority of the total units.

 

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FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER

In General

The managing general partner will manage each partnership and its assets. In conducting your partnership’s affairs the managing general partner is accountable to you as a fiduciary, which under Delaware law generally means that the managing general partner must exercise due care and deal fairly with you and the other investors. Neither the partnership agreement nor any other agreement between the managing general partner and a partnership may contractually limit any fiduciary duty owed to you and the other investors by the managing general partner under applicable law. See “Conflicts of Interest – In General.” In this regard, the partnership agreement permits the managing general partner and its affiliates to:

 

•

have business interests or activities that may conflict with the partnerships if they determine that the business opportunity either:

 

•

cannot be pursued by a partnership because of insufficient funds; or

 

•

it is not appropriate for the partnership under the existing circumstances;

 

•

devote only so much of their time as is necessary to manage the affairs of each partnership, as determined by the managing general partner in its sole discretion;

 

•

conduct business with the partnerships in a capacity other than as managing general partner or sponsor as described in Sections 4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of the partnership agreement;

 

•

manage multiple programs simultaneously; and

 

•

be indemnified and held harmless as described below in “- Limitations on Managing General Partner Liability as Fiduciary.”

The fiduciary duty owed by the managing general partner to each partnership is analogous to the fiduciary duty owed by directors to a corporation and its stockholders, which is commonly referred to as the “business judgment rule.” This rule provides that directors are not liable for mistakes made in the good faith exercise of honest business judgment or for losses incurred in the good faith performance of their duties when performed with such care as an ordinarily prudent person would use.

If the managing general partner breaches its fiduciary responsibilities, then you are entitled to an accounting and the recovery of any economic loss caused by the breach. The Delaware Revised Uniform Limited Partnership Act provides that a limited partner may institute legal action (a “derivative” action) on the partnership’s behalf to recover damages from a third-party when the managing general partner refuses to institute the action or where an effort to cause the managing general partner to do so is not likely to succeed. In addition, the statutory or case law may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners (a “class action”) to recover damages from the managing general partner for violations of its fiduciary duties to the limited partners. This is a rapidly expanding and changing area of the law, and if you have questions concerning the managing general partner’s duties you are urged to consult your own counsel.

Limitations on Managing General Partner Liability as Fiduciary

Under the terms of the partnership agreement the managing general partner, the operator, and their affiliates have limited their liability to the partnerships and to you and the other investors for any loss suffered by your partnership or you and the other investors in the partnership which arises out of any action or inaction on their part if:

 

•

they determined in good faith that the course of conduct was in the best interest of the partnership;

 

•

they were acting on behalf of, or performing services for, the partnership; and

 

•

their course of conduct did not constitute negligence or misconduct.

 

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In addition, the partnership agreement provides for indemnification of the managing general partner, the operator, and their affiliates by each partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the partnership provided that they meet the standards set forth above. However, there is a more restrictive standard for indemnification for losses arising from or out of an alleged violation of federal or state securities laws. Also, to the extent that any indemnification provision in the partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, you should be aware that in the SEC’s opinion this indemnification provision would be contrary to public policy and therefore unenforceable.

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

The partnership may not pay the cost of the portion of any insurance that insures the managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified. However, the partnership’s funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if the partnership has adequate funds available and the following conditions in the partnership agreement are met:

 

(i)

the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the partnership;

 

(ii)

the legal action is initiated by a third-party who is not an investor, or the legal action is initiated by an investor and a court of competent jurisdiction specifically approves the advancement; and

 

(iii)

the managing general partner or its affiliates undertake to repay the advanced funds to the partnership, together with the applicable legal rate of interest thereon, in cases in which such party is found not to be entitled to indemnification.

The effect of the foregoing provisions and the business judgment rule may be to limit your recourse against the managing general partner.

 

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FEDERAL INCOME TAX CONSEQUENCES

Introduction

No advance ruling on any federal tax issue of an investment in a partnership will be requested from the IRS. Thus, the IRS could disagree with one or more tax positions taken by the partnerships. However, the managing general partner has obtained a tax opinion letter from Kunzman & Bollinger, Inc., Oklahoma City, Oklahoma, special counsel for this offering, with respect to the material and any significant federal income tax issues involving an investment in the partnership by a “typical investor,” which is as defined by the managing general partner for this purpose as a natural person who purchases units in this offering and is a U.S. citizen. You are urged to read the entire tax opinion letter, which has been filed with the SEC as Exhibit 8.1 to the registration statement of which this prospectus is a part. See “Additional Information” for information on how to obtain a copy of special counsel’s tax opinion letter.

Although special counsel’s tax opinions express what it believes a court would probably conclude if presented with the applicable federal tax issues, special counsel’s tax opinions are only predictions, and are not guarantees, of the outcome of the particular tax issues being addressed. The IRS could challenge special counsel’s tax opinions, and the challenge could be sustained in the courts if litigated and cause adverse tax consequences to you and your partnership’s other investors. Special counsel’s tax opinions are based on current law and in part on representations made by the managing general partner to special counsel as set forth in the tax opinion letter and this prospectus, including forward looking statements relating to the partnerships and their proposed activities. See “Forward Looking Statements and Associated Risks.”

In this regard, President Obama’s administration has proposed, beginning January 1, 2013, among other tax changes, the repeal of certain oil and 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. Also, other changes in the tax laws could be made that would reduce your tax benefits from an investment in the partnership.

Disclosures in Tax Opinion Letter

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

 

•

The tax opinion letter was written to support the promotion or marketing of units in the partnerships to potential investors, and special counsel to the partnerships has helped the managing general partner organize and document the offering of units in the partnerships.

 

•

The tax opinion letter is not confidential. There are no limitations on the disclosure by the managing general partner or any potential investor in a partnership to any other person of the tax treatment or tax structure of the partnerships.

 

•

Investors in a partnership have no contractual protection against the possibility that a portion or all of their intended tax benefits from an investment in the partnership ultimately are not sustained if challenged by the IRS. See “Risk Factors – Federal Income Tax Risks – Your Tax Benefits from an Investment in a Partnership Are Not Contractually Protected.”

 

•

Each potential investor is urged to seek advice based on his particular circumstances from an independent tax advisor with respect to the federal tax consequences to him of an investment in a partnership.

 

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Special Counsel’s Assumptions

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

 

•

You will not borrow money to buy units in a partnership from any other investor in the partnership.

 

•

You will be personally liable to repay any money you borrow to buy units in a partnership.

 

•

You will not protect yourself through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements from losing the money you invest in a partnership.

Managing General Partner’s Representations

In giving its opinions for each partnership offered in this program, special counsel relied in part on representations from the managing general partner, which are set forth in the tax opinion letter, including the principal representations summarized below.

 

•

A “typical investor” in each partnership will be a natural person who purchases units in this offering and is a U.S. citizen.

 

•

The investor general partner units in each partnership will be converted by the managing general partner to limited partner units after all of the wells in the partnership have been drilled and completed. See “Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners.”

 

•

Each partnership will elect to currently deduct all of the intangible drilling costs of all of its wells.

 

•

The managing general partner anticipates that each partnership’s entire subscription proceeds will be expended in the year in which its investors invest in the partnership, and you will include your share of your partnership’s deduction for intangible drilling costs on your individual federal income tax return for the year in which you invest in the partnership, subject to your right to elect to capitalize and amortize over a 96-month period a portion or all of your share of your partnership’s deduction for intangible drilling costs.

 

•

Each partnership may have its final closing as late in the year as December 31 of the year in which its investors invest in the partnership. Thus, depending primarily on when its subscription proceeds are received, each partnership may prepay in the year in which the partnership’s investors invest in the partnership most, if not all, of its intangible drilling costs for wells the drilling of which will not begin until the next year.

 

•

Each partnership will have a calendar year taxable year.

 

•

The principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis to its investors, apart from tax benefits, as discussed in this prospectus.

 

•

The managing general partner anticipates that each partnership’s total abandonment losses for wells drilled that are nonproductive (i.e. a “dry hole”), if any, and productive wells which have been operated until their commercial natural gas and oil reserves have been depleted will be less than $2 million, in the aggregate, in any taxable year of the partnership and less than $4 million, in the aggregate, during the partnership’s first six taxable years.

Additional details, assumptions of special counsel, representations of the managing general partner, and other matters affecting special counsel’s opinions are contained in special counsel’s tax opinion letter. You are urged to read the entire tax opinion letter, which is attached as Exhibit 8.1 to the Registration Statement of which this prospectus is a part, to assist your understanding of the federal tax benefits and risks of an investment in a partnership.

 

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Special Counsel’s Opinions

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

 

(1)

Partnership Classification. Each Partnership will be classified as a partnership for federal income tax purposes, and not as a corporation.

 

(2)

Limitations on Passive Activity Losses and Credits. The passive activity limitations on losses and credits under §469 of the Code:

 

•

will apply to the initial Limited Partners in a Partnership; and

 

•

will not apply to the Investor General Partners in a Partnership until after their Investor General Partner Units are converted to Limited Partner Units.

 

(3)

Not a Publicly Traded Partnership. The Partnerships will not be treated as publicly traded partnerships under the Code.

 

(4)

Business Expenses. Business expenses, including payments for personal services actually rendered in the taxable year in which accrued by a Partnership, which are reasonable, ordinary and necessary and do not include amounts for items such as Lease acquisition costs, Tangible Costs, Organization and Offering Costs and other items that are required to be capitalized under the Code, are currently deductible.

 

•

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

 

•

the Participant’s personal tax situation, such as the amount of his regular taxable income, alternative minimum taxable income, losses, itemized deductions, personal exemptions, etc., which are not related to his investment in a Partnership;

 

•

the amount of the Participant’s adjusted basis in his Units at the end of the Partnership’s taxable year;

 

•

the amount the Participant is “at risk” in the Partnership at the end of the Partnership’s taxable year; and

 

•

the passive activity limitations on Partnership losses and credits in the case of Limited Partners (including Investor General Partners after their Investor General Partner Units are converted to Limited Partner Units) who are subject to §469 of the Code.

 

(5)

Intangible Drilling Costs. Although each Partnership will elect to deduct currently all of its Intangible Drilling Costs, each Participant in a Partnership may still elect to capitalize and deduct all or part of his share of the Partnership’s Intangible Drilling Costs ratably over a 60-month period. Subject to the foregoing, Intangible Drilling Costs paid by a Partnership under the terms of bona fide drilling contracts for the Partnership’s wells will be deductible by Participants in that Partnership who elect to currently deduct their share of their Partnership’s Intangible Drilling Costs in the taxable year in which the payments are made and the drilling services are rendered.

 

A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4) above.

 

(6)

Prepaid Intangible Drilling Costs. Subject to each Participant’s election to capitalize and amortize a portion or all of his share of his Partnership’s Intangible Drilling Costs as set forth in opinion

 

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(5) above, any prepayments of Intangible Drilling Costs by a Partnership in the year in which the Participant invests in the Partnership for wells the drilling of which begins within the first 90 days of the next year will be deductible by the Participant in the year in which he invests.

 

A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4) above.

 

(7)

Depletion Allowance. The greater of the cost depletion allowance or the percentage depletion allowance will be available to qualified Participants as a current deduction against their share of their Partnership’s gross income from the sale of natural gas and oil production in each taxable year.

 

A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4), above.

 

(8)

MACRS. Each Partnership’s reasonable Tangible Costs for equipment placed in its productive wells that cannot be deducted immediately will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System (“MACRS”) over a seven year “cost recovery period” on a well-by-well basis, beginning in the taxable year each well is drilled, completed and made capable of production, i.e. placed in service.

 

A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4), above.

 

(9)

Tax Basis of Units. Each Participant’s initial adjusted tax basis in his Units will be the amount of money that he paid for his Units.

 

(10)

At Risk Limitation on Losses. Each Participant’s initial “at risk” amount in the Partnership in which he invests will be the amount of money that he paid for his Units.

 

(11)

Allocations. The allocations in the Partnership Agreement of income, gain, loss, deduction, credit, and distributions, or items thereof, for each Partnership, including the allocations of basis and amount realized with respect to a Partnership’s natural gas and oil properties, will govern each Participant’s allocable share of those items to the extent the allocations do not cause or increase a deficit balance in his Capital Account in the Partnership in which he invests.

 

(12)

Subscription. No gain or loss will be recognized by the Participants on payment of their subscriptions to the Partnership in which they invest.

 

(13)

Profit Motive, IRS Anti-Abuse Rule and Potentially Relevant Judicial Doctrines. The Partnerships will possess the requisite profit motive under §183 of the Code. Also, the IRS anti-abuse rule in Treas. Reg. §1.701-2 and potentially relevant judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a Partnership by a Participant as described in our opinions.

 

(14)

Reportable Transactions. The Partnerships are not, and should not be in the future, reportable transactions under §6707A(c) of the Code.

 

(15)

Overall Conclusion. Our overall conclusion is that the federal tax treatment of a typical Participant’s investment in a Partnership as set forth in our opinions above is the proper federal tax treatment and will be upheld on the merits if challenged by the IRS and litigated. Our evaluation of the federal income tax laws and the expected activities of the Partnerships as represented to us by the Managing General Partner in this tax opinion letter and as described in the Prospectus causes us to believe that the deduction by a typical Participant of all, or substantially all, of his allocable share of his Partnership’s Intangible Drilling Costs in the year he invests (even if the drilling of most or all of his Partnership’s wells begins within the first 90 days of the next year), is the principal tax benefit

 

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offered by each Partnership to its respective Participants and also is the proper federal tax treatment, subject to each Participant’s option to elect to capitalize and amortize a portion or all of his share of his Partnership’s deduction for Intangible Drilling Costs.

 

A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4), above.

 

The discussion in the Prospectus under the caption “FEDERAL INCOME TAX CONSEQUENCES,” insofar as it contains statements of federal income tax law, is correct in all material respects.

Discussion of Federal Income Tax Consequences

Special counsel’s tax opinions are limited to those set forth above. Subject to the foregoing, the following discussion relates to the purchase, ownership and disposition of each partnership’s units by typical investors in a partnership. Except as otherwise noted below, however, different tax consequences from those discussed below may apply to foreign persons, corporations, partnerships, trusts and other prospective investors that are not treated as typical investors for federal income tax purposes. Also, the proper treatment of a partnership’s tax attributes by a typical investor on his individual federal income tax returns may vary from that of another typical investor. This is because the practical utility of the tax aspects of any investment depends largely on each investor’s particular income tax position in the year in which items of income, gain, loss, deduction, or credit, if any, are properly taken into account in computing his federal income tax liability. In addition, the IRS may challenge the deductions, and credits, if any, claimed by your partnership or you and the other investors in your partnership, or the taxable year in which the deductions, and credits, if any, are claimed, and it is possible that the challenge would be upheld if litigated. Accordingly, you are urged to seek advice based on your particular circumstances from an independent tax advisor in evaluating the potential tax consequences to you of an investment in a partnership.

Partnership Classification

For federal income tax purposes a partnership is not a taxable entity. Thus, the partners, rather than the partnership, receive and report any deductions and tax credits, if any, as well as the income, from the partnership’s operations. Each partnership has been formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act and the partnerships will each be classified automatically as a partnership for federal tax purposes since the managing general partner has represented that the partnerships will not elect to be taxed as corporations. Treas. Reg. §301.7701-2.

Limitations on Passive Activity Losses and Credits

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

 

•

income from passive activities, such as limited partners’ interests in a business;

 

•

active income, such as salary, bonuses, etc.; or

 

•

portfolio income, such as gain, interest, dividends and royalties unless earned in the ordinary course of a trade or business, and gain not derived in the ordinary course of a trade or business on the sale of property that generates portfolio income or is held for investment.

Losses generated by passive activities can offset only passive income and cannot be applied against active income or portfolio income. Similar rules apply with respect to tax credits. See “– Marginal Well Production Credits,” below.

 

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The passive activity rules apply to:

 

•

individuals, estates, and trusts;

 

•

closely held C corporations, which under §§469(j)(1), 465(a)(1)(B) and 542(a)(2) of the Code are regular corporations with five or fewer individuals who own directly or indirectly more than 50% in value of the outstanding stock at any time during the last half of the taxable year (for this purpose, U.S. trusts forming part of a stock bonus, pension or profit-sharing plan of an employer for the exclusive benefit of its employees or their beneficiaries that constitutes a “qualified trust” under §401(a) of the Code, trusts forming part of a plan providing for the payment of supplemental employee unemployment compensation benefits that meet the requirements of §501(c)(17) of the Code, domestic or foreign “private foundations” described in §501(c)(3) of the Code, and a portion of a trust permanently set aside or to be used exclusively for the charitable purposes described in §642(c) of the Code or a corresponding provision of a prior income tax law, are considered to be individuals); and

 

•

personal service corporations, which under §§469(j)(2), 269A(b) and 318(a)(2)(C) of the Code are corporations the principal activity of which is the performance of personal services and those services are substantially performed by employee-owners. For this purpose, the term “employee-owners” includes any employee who owns, on any day during the taxable year, any of the outstanding stock of the personal service corporation, and an employee is considered to own:

 

•

the employee’s proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a partnership or estate in which the employee is a partner or beneficiary;

 

•

the employee’s proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a trust (other than an employee’s trust that is a qualified pension, profit-sharing, or stock bonus plan and is exempt from tax) if the employee is a beneficiary;

 

•

all of the stock of the personal service corporation owned, directly or indirectly, by or for any portion of a trust that the employee is considered to own under the Code; and

 

•

if any stock in a corporation is owned, directly or indirectly, for or by the employee, the employee’s proportionate share of the stock of the personal service corporation owned, directly or indirectly, by or for that corporation.

However, a corporation will not be treated as a personal service corporation for purposes of §469 of the Code unless more than 10% of the stock (by value) in the corporation is held by employee-owners (as described above). I.R.C. §469(j)(2)(B).

Also, if a closely held C corporation, other than a personal service corporation in which employee-owners own more than 10% (by value) of the stock, has net active income (i.e., taxable income determined without regard to any income or loss from a passive activity and without regard to any item of portfolio income, expense (including interest expense), or gain or loss) for a taxable year, its passive loss for that taxable year can be applied against its net active income for that taxable year. Similar rules apply to its passive credits, if any. I.R.C. §469(e)(2).

Passive activities include any trade or business in which the taxpayer does not materially participate on a regular, continuous, and substantial basis. Under the partnership agreement, limited partners will not have material participation in the partnership in which they invest. Thus, if you are subject to the passive activity rules as described above and you invest in a partnership as a limited partner, your investment in the partnership will be subject to the passive activity limitations on losses and credits. See “Risk Factors – Federal Income Tax Risks – Limited Partners Need Passive Income to Use Their Partnership Deductions .”

Investor general partners also will not materially participate in the partnership in which they invest. However, under what we refer to as the “passive loss exception for working interests,” because each partnership will own only “working interests,” as defined by the Code, in its wells, and investor general partners will not have limited

 

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liability for partnership liabilities and obligations under the Delaware Revised Uniform Limited Partnership Act until they are converted to limited partners, their deductions and any credits from their partnership will not be treated as passive deductions or credits under the Code before the conversion unless they invest in the partnership through an entity which limits their liability. See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership.” For example, if an individual invests in a partnership indirectly as an investor general partner by using an entity that limits his personal liability under state law to purchase his units, such as a limited partnership in which he is not a general partner, a limited liability company or an S corporation, then he will not be eligible for the passive loss exception for working interests. Instead, he will be subject to the passive activity limitations on deductions and credits the same as if he had invested directly in the partnership as a limited partner. See “– Conversion from Investor General Partner to Limited Partner” and “– Marginal Well Production Credits,” below.

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

President Obama’s administration, however, has proposed repealing the passive loss exception for working interests for taxable years beginning after December 31, 2012. See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership,” and “– Drilling Contracts,” below.

A limited partner’s “at risk” amount is reduced by losses allowed under §465 of the Code even if the losses are suspended by the passive activity limitations. See “– ‘At Risk’ Limitation on Losses,” below. Similarly, a limited partner’s basis is reduced by deductions even if the deductions are suspended under the passive activity limitations. See “– Tax Basis of Units,” below.

Suspended passive losses and passive credits that cannot be used by a taxpayer in his current tax year may be carried forward indefinitely, but not back, and can be used to offset passive income in future years or, in the case of passive credits, can be used to offset regular federal income tax liability attributable to passive income in future years. I.R.C. §469(b). A suspended passive loss, but not a suspended passive credit, is allowed in full when a taxpayer’s entire interest in a passive activity is sold to an unrelated third-party in a fully taxable transaction, and in part on the taxable disposition of substantially all of a taxpayer’s interest in a passive activity if the suspended passive loss as well as current gross income and deductions of the passive activity can be allocated to the part disposed of with reasonable certainty. I.R.C. §469(g)(1). In an installment sale of a taxpayer’s entire interest in a passive activity, passive losses become available in the same ratio that gain recognized each year bears to the total gain on the sale. I.R.C. §469(g)(3). See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”

Any suspended passive losses remaining at a taxpayer’s death are allowed as deductions on the decedent’s final return, subject to a reduction to the extent the amount of the suspended passive losses is greater than the excess of the basis of the property in the hands of the transferee over the property’s adjusted basis immediately before the decedent’s death. I.R.C. §469(g)(2). If a taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of the person receiving the gift is increased by any suspended passive losses and no deductions are allowed. I.R.C. §469(j)(6). If the interest is later sold at a loss, the basis in the property of the person receiving the gift is limited to the fair market value of the property on the date the gift was made. I.R.C. §469(j)(6).

 

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Publicly Traded Partnership Rules

Net losses and most net credits of a partner from a publicly traded partnership are suspended and carried forward to be netted against income or regular federal income tax liability, respectively, from that publicly traded partnership only. In addition, net losses from other passive activities may not be used to offset net passive income from a publicly traded partnership. I.R.C. §§469(k)(2) and 7704. A publicly traded partnership is a partnership in which interests in the partnership are traded on an established securities market or are readily tradable on either a secondary market or the substantial equivalent of a secondary market. However, in special counsel’s opinion the partnerships will not be treated as publicly traded partnerships under the Code. This opinion is based primarily on the substantial restrictions in the partnership agreement on the ability of you and the other investors to transfer your units in your partnership. See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.” Also, the managing general partner has represented that the units in each partnership will be not traded on an established securities market.

Conversion from Investor General Partner to Limited Partner

If you invest in a partnership as an investor general partner, then under current law your share of the partnership’s deduction for intangible drilling costs in the year in which you invest will not be subject to the passive activity limitations on losses and credits. This is because the investor general partner units in the partnership will not be converted to limited partner units under §6.01(b)(1) of the partnership agreement until after all of the wells in the partnership have been drilled and completed. See “Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners,” and “– Drilling Contracts,” below. After the investor general partner units have been converted to limited partner units, each former investor general partner will have limited liability with respect to the partnership’s activities after the conversion.

Concurrently, the former investor general partner will become subject to the passive activity limitations on losses and credits as a limited partner. However, the former investor general partner previously will have received a non-passive loss as an investor general partner in the year in which he invested in a partnership as a result of his share of the partnership’s deduction for intangible drilling costs. Therefore, the Code requires that his net income from the partnership’s wells after his conversion to a limited partner must continue to be characterized as non-passive income that cannot be offset with passive losses. The conversion of the investor general partner units into limited partner units should not have any other adverse tax consequences on an investor general partner unless his share of partnership liabilities, if any, is reduced as a result of the conversion. See “– Tax Basis of Units,” below.

Taxable Year

Each partnership will have a calendar year taxable year. I.R.C. §§706(a) and (b). The taxable year of your partnership is important to you because your share of the partnership’s deductions, tax credits, if any, income and other items of tax significance must be taken into account on your personal federal income tax return for your taxable year within or with which the partnership’s taxable year ends.

Method of Accounting

Each partnership will use the accrual method of accounting for federal income tax purposes. I.R.C. §448(a). Under the accrual method of accounting, income is taken into account for the year in which all events have occurred that fix the right to receive it and the amount is determinable with reasonable accuracy, rather than the time of receipt. Consequently, you and the other investors in your partnership may have income tax liability resulting from the partnership’s accrual of income in one tax year even though it does not receive the income in cash until the next tax year. Expenses are deducted for the year in which all events have occurred that determine the fact of the liability, the amount is determinable with reasonable accuracy and the economic performance test

 

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is satisfied. Under §461(h) of the Code, if the liability of the taxpayer arises out of the providing of services or property to the taxpayer by another person, economic performance occurs as the services or property, respectively, are provided. If the liability of the taxpayer arises out of the use of the property by the taxpayer, economic performance occurs as the property is used.

A special rule in the Code, however, provides that there is economic performance in the current taxable year with respect to amounts paid in that taxable year for intangible drilling costs of drilling and completing a natural gas or oil well so long as the drilling of the well begins before the close of the 90^th day after the close of the taxable year in which the payments were made. I.R.C. §461(i). See “– Drilling Contracts,” below, for a discussion of the federal income tax treatment of any intangible drilling costs that are prepaid by the partnerships and “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership.”

Business Expenses

Ordinary and necessary business expenses, including reasonable compensation for personal services actually rendered, are deductible in the year incurred. In this regard, the managing general partner has represented that the amounts payable by each partnership to it and its affiliates under the drilling and operating agreement to drill, frack and complete the partnership’s wells are reasonable and competitive amounts that ordinarily would be paid for similar services in similar transactions between persons having no affiliation and dealing with each other at “arm’s length” in the proposed area of the partnership’s operations. See Treas. Reg. §1.162-7(b)(3), “Compensation” and “– Drilling Contracts,” below. The fees paid to the managing general partner and its affiliates by the partnership will not be currently deductible, however, to the extent it is determined by the IRS or the courts that they are:

 

•

in excess of reasonable compensation;

 

•

properly characterized as organization or syndication fees or other capital costs, such as lease acquisition costs or equipment costs (i.e., “Tangible Costs”); or

 

•

not “ordinary and necessary” business expenses.

In the event of an IRS audit of a partnership, payments to the managing general partner and its affiliates by the partnership would be scrutinized by the IRS to a greater extent than payments to an unrelated party.

Your ability in any taxable year to use your share of these partnership deductions on your personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in special counsel’s opinion (4) in “– Special Counsel’s Opinions,” above.

Although the partnerships will engage in the production of natural gas and oil from wells drilled in the United States, the partnerships will not qualify for the “U.S. production activities deduction.” This is because the deduction cannot exceed 50% of the IRS Form W-2 wages paid by a taxpayer for a tax year, and the partnerships will not pay any Form W-2 wages since they will not have any employees. Instead, the partnerships will rely on the managing general partner and its affiliates to manage them and their respective businesses.

Intangible Drilling Costs

You may elect to deduct your share of your partnership’s intangible drilling costs, which include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary to the drilling of a well and preparing it for the production of natural gas or oil, in the taxable year in which the partnership’s wells are drilled and completed. I.R.C. §263(c), Treas. Reg. §1.612-4(a). In this regard, President Obama’s administration has proposed the repeal of a taxpayer’s election to expense its intangible drilling costs, beginning January 1, 2013, which Congress may or may not do. This proposal, however, is not expected by the managing general partner to adversely affect your ability to elect to deduct or amortize (as discussed below) your share of your partnership’s

 

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intangible drilling costs in 2012 for wells that are drilled in 2012. See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership.” Also, for a discussion of the deduction for intangible drilling costs that are prepaid by your partnership in the year in which you invest in the partnership for wells the drilling of which will not begin until the next year, if any, see “– Drilling Contracts,” below.

Your share of your partnership’s gain (if the partnership sells a well at a gain), or your gain (if you sell your units in the partnership at a gain), will be treated as ordinary income, rather than capital gain, to the extent of the previous deductions for intangible drilling costs you have claimed. See “– Sale of the Properties” and “– Disposition of Units,” below. Also, productive-well intangible drilling costs may subject you to an alternative minimum tax in excess of regular tax unless you elect to deduct all or part of these costs ratably over a 60-month period. See “– Alternative Minimum Tax,” below.

Under the partnership agreement, the subscription proceeds received by your partnership from you and the other investors will be used to pay 100% of the partnership’s intangible drilling costs of drilling and completing its wells. See “Capitalization and Source of Funds and Use of Proceeds” and “Participation in Costs and Revenues.” The IRS could challenge the characterization of some of these costs as currently deductible intangible drilling costs and recharacterize the costs as some other item that may not be currently deductible, such as lease acquisition expenses, equipment costs or syndication fees. However, this would have no effect on the allocation and payment of the intangible drilling costs by you and the other investors under the partnership agreement.

In the case of corporations, other than S corporations, which are “integrated oil companies,” the amount allowable as a deduction for intangible drilling costs in any taxable year is reduced by 30%. I.R.C. §291(b)(1). Integrated oil companies are:

 

•

those taxpayers who directly or through a related person engage in the retail sale of natural gas and oil and whose gross receipts for the taxable year from those activities exceed $5 million; or

 

•

those taxpayers and related persons who have average daily refinery runs in excess of 75,000 barrels for the taxable year. I.R.C. §291(b)(4).

Amounts of an integrated oil company’s intangible drilling costs that are disallowed as a current deduction under §291 of the Code are allowable, however, as a deduction ratably over the 60-month period beginning with the month in which the costs are paid or incurred. The partnerships, however, will not be treated as integrated oil companies under the Code.

Your ability in any taxable year to use your share of these partnership deductions on your personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in special counsel’s opinion (4) in “– Special Counsel’s Opinions,” above.

You are urged to seek advice based on your particular circumstances from an independent tax advisor concerning the tax benefits to you of your share of the deduction for intangible drilling costs of the partnership.

Drilling Contracts

Each partnership will enter into the drilling and operating agreement with the managing general partner to drill and complete the partnership’s wells on a modified cost plus basis for the compensation described in “Compensation – Drilling Contracts.” The actual cost of drilling and completing the wells, however, including the managing general partner’s 15% mark-up, may be more or less than the dollar amounts estimated by the managing general partner in “Compensation – Drilling Contracts,” due primarily to the uncertain nature of drilling operations. The managing general partner believes that the compensation payable to it and its affiliates under the drilling and operating agreement is competitive in the proposed area of operations. Nevertheless, a portion or all of the amount of fees and profit realized by the managing general partner under the drilling and operating agreement could be challenged by the IRS as being unreasonable and disallowed as a deductible intangible drilling cost.

 

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Depending primarily on when their respective subscription proceeds are received, the managing general partner anticipates that each partnership may prepay in the year in which its investors invest in the partnership most, if not all, of its intangible drilling costs for wells the drilling of which will begin within the first 90 days of the next year. In Keller v. Commissioner, 79 T.C. 7 (1982), aff’d 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current deductibility of prepaid intangible drilling and development costs. The test is:

 

•

the expenditure must be a payment rather than a refundable deposit; and

 

•

the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction.

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

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

In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine separate turnkey contracts with a general contractor, the parent corporation of the drilling program’s corporate general partner, to drill nine program wells. Each contract identified the prospect to be drilled, stated the turnkey price, and required the full price to be paid in 1974. The program paid the full turnkey price to the general contractor on December 31, 1974; the receipt of which was found by the court to be significant in the general contractor’s financial planning. The program had no right to receive a refund of any of the payments. The actual drilling of the nine wells was subcontracted by the general contractor to independent contractors who were paid by the general contractor in accordance with their individual contracts. The drilling of all of the wells began in 1975 and all of the wells were completed in 1975. The amount paid by the general contractor to the independent driller for its work on the nine wells was approximately $365,000 less than the amount prepaid by the program to the general contractor. The program claimed a deduction for intangible drilling and development costs in 1974. The IRS challenged the timing of the deduction, contending that there was no business purpose for the payments in 1974, that the turnkey arrangements were merely “contracts of convenience” designed to create a tax deduction in 1974, and that the turnkey contracts constituted assets having a life beyond the taxable year and that to allow a deduction for their entire costs in 1974 distorted income. The Tax Court, relying on Keller, held that the program could deduct the full amount of the payments in 1974. The court found that the program entered into turnkey contracts, paid a premium to secure the turnkey obligations, and thereby locked in the drilling price and shifted the risks of drilling to the general contractor. Further, the court found that by signing and paying the turnkey obligation, the program got its bargained-for benefit in 1974, therefore the deduction of the payments in 1974 clearly reflected income.

Each partnership will attempt to comply with the guidelines set forth in Keller with respect to any prepaid intangible drilling costs. In this regard, the drilling and operating agreement will require each partnership to prepay in the year in which the partnership’s investors invest in the partnership all of the partnership’s share of the estimated intangible drilling costs, and all of the investors’ share of the partnership’s share of the estimated

 

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equipment costs, for drilling and completing specified wells for the partnership, the drilling of which may begin in the next year. These prepayments of intangible drilling costs should not result in a loss of a current deduction for the intangible drilling costs in the year in which the partnership’s investors invest in the partnership if:

 

•

the guidelines set forth in Keller are complied with;

 

•

there is a legitimate business purpose for the required prepayment;

 

•

the drilling of the prepaid wells begins on or before the first 90 days of the next taxable year;

 

•

the contract is not merely a sham to control the timing of the deduction; and

 

•

there is an enforceable contract of economic substance.

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

 

•

begin site preparation for the wells;

 

•

obtain suitable subcontractors at the then current prices; and

 

•

insure the availability of equipment and materials.

Under the drilling and operating agreement excess prepaid intangible drilling costs, if any, will not be refundable to a partnership, but instead will be applied only to intangible drilling cost overruns, if any, on the other specified wells being drilled or completed by the partnership or to intangible drilling costs to be incurred by the partnership in drilling and completing substitute wells. Under Keller, a provision for substitute wells should not result in the prepayments being characterized as refundable deposits.

The likelihood that prepayments of intangible drilling costs will be challenged by the IRS on the grounds that there is no business purpose for the prepayments is increased if prepayments are not required with respect to 100% of the working interest in the well. In this regard, the managing general partner anticipates that less than 100% of the working interest may be acquired by a partnership in one or more of its wells, especially in any wells situated in a secondary drilling area, and prepayments of intangible drilling costs will not be required of the other owners of working interests in those wells. In the view of special counsel, however, a legitimate business purpose for the required prepayments of intangible drilling costs by the partnership may exist under the guidelines set forth in Keller, even though prepayments are not required by the drilling contractor with respect to a portion of the working interest in some of the wells.

In addition, a current deduction for prepaid intangible drilling costs is available only if the drilling of the wells begins before the close of the 90^th day after the close of the taxable year in which the prepayment was made. See the discussion of §461(i) of the Code in “– Method of Accounting,” above. Therefore, under the drilling and operating agreement the managing general partner, serving as operator and general drilling contractor, is required to begin drilling the wells that are prepaid by a partnership, if any, no later than the close of the 90^th day of the year immediately following the year in which the partnership made the prepayment. However, the drilling of any partnership well may be delayed due to circumstances beyond the control of the managing general partner and the drilling subcontractors. These circumstances include, for example:

 

•

the unavailability of drilling rigs at the scheduled times;

 

•

decisions of third-party operators to delay drilling the wells;

 

•

poor weather conditions;

 

•

inability to obtain drilling permits or access right to the drilling site; or

 

•

title problems;

 

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and the managing general partner will have no liability under the partnership agreement or the drilling and operating agreement to the partnerships or their respective investors if these types of events (i.e., “force majeure”) delay beginning the drilling of any partnership prepaid well beyond the 90 day limit imposed by §461(i) of the Code.

If the drilling of a prepaid partnership well does not begin within the 90 day time constraint imposed by §461(i) of the Code, deductions claimed by you and the other investors in the partnership for prepaid intangible drilling costs for the well in the year you invest in the partnership would not be lost under current law, but the Code would require that those deductions be deferred to the following year when the well is actually drilled. For example, any wells prepaid in 2012 by MDS Energy Public 2012-A LP must be spudded by March 31, 2013 or the deduction for that well’s intangible drilling costs would not be available for the 2012 tax year, but instead, would have to be claimed for the 2013 tax year, which would be the tax year in which the well was actually drilled. In that event, you may not be able to deduct, or elect to amortize over a 60-month period, any of your deferred intangible drilling costs in 2013 for any prepaid partnership wells the drilling of which did not begin within the 90 day time constraint if President Obama’s proposal to repeal the election to expense intangible drilling costs incurred or paid after December 31, 2012 is enacted into law. See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership.”

Depletion Allowance

Proceeds from the sale of a partnership’s natural gas and oil production will constitute ordinary income. A portion of that income will not be taxable under the depletion allowance, which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion allowance, whichever is greater. I.R.C. §§611, 613 and 613A. The rate of percentage depletion under the Code is 15%. Your share of your partnership’s gain (if your partnership sells a well at a gain), or your gain (if you sell your units at a gain), will be treated as ordinary income rather than capital gain to the extent of your previous deductions for depletion that reduced your adjusted basis in the property or your units. See “– Sale of the Properties” and “– Disposition of Units,” below.

Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates.

Percentage depletion is available to taxpayers other than “integrated oil companies,” as that term is defined in “– Intangible Drilling Costs,” above, which does not include the partnerships. Your percentage depletion allowance is based on your share of your partnership’s gross production income (excluding rents or royalties paid) from its natural gas and oil properties. Under §613A(c) of the Code, percentage depletion is available with respect to 6 million cubic feet of average daily production of domestic natural gas or 1,000 barrels of average daily production of domestic crude oil. However, taxpayers who have both natural gas and oil production may allocate the production limitation between the production.

In this regard, percentage depletion for marginal production increases 1%, up to a maximum increase of 10%, for each whole dollar that the domestic wellhead price of crude oil for the immediately preceding year is less than $20 per barrel without adjustment for inflation. I.R.C. §613A(c)(6). Also, the term “marginal production” includes natural gas and oil produced from a domestic stripper well property, which is defined in §613A(c)(6)(E) of the Code as any property that produces a daily average of 15 or less equivalent barrels of oil, which is equivalent to 90 mcf of natural gas, per producing well on the property in the calendar year. In this regard, some wells that initially do not qualify as marginal wells may subsequently become marginal wells as the wells age and their natural gas and oil production declines. Accordingly, some of the natural gas and oil production from each partnership’s productive wells may, from time to time, be classified as marginal production under this definition in the Code and may qualify for the potentially higher rates of percentage depletion as discussed

 

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above. In this regard, the percentage depletion rate for marginal production is 15% in 2012. This rate may fluctuate from year to year in the future for natural gas and oil production from marginal wells, as discussed above, but will not be less than the statutory rate of 15% nor more than 25%.

Also, percentage depletion:

 

•

may not exceed 100% of the taxable income from each natural gas and oil property before the deduction for depletion, although this limitation has been suspended by Congress in past years with respect to natural gas and oil production from marginal properties, there is no assurance that Congress will suspend this limitation for marginal production in the future for 2012 or subsequent years; and

 

•

is limited to 65% of the taxpayer’s taxable income for the year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs and, in the case of an investor that is a trust, any distributions to its beneficiaries. Any disallowed percentage depletion deductions under this limitation may be carried forward to the next taxable year.

The availability in any taxable year of the percentage depletion allowance must be computed separately by you and not by your partnership or for investors in your partnership as a whole. You are urged to seek advice based on your particular circumstances from an independent tax advisor with respect to the availability of the percentage depletion allowance to you.

If President Obama’s proposal to repeal the percentage depletion allowance for taxable years beginning after December 31, 2012, is enacted into law, which Congress may or may not do, your future depletion deductions from your investment in a partnership would be reduced. See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership.”

Depreciation and Cost Recovery Deductions

A portion of the subscription proceeds from you and the other investors in your partnership will be used to pay all of the equipment costs (i.e.; “Tangible Costs”) of drilling and completing the partnership’s wells as discussed in “Participation in Costs and Revenues,” and the related depreciation deductions, i.e.; cost recovery deductions under the modified accelerated cost recovery system (“MACRS”), will be allocated under the partnership agreement 100% to you and the other investors in the partnership.

Some of the wells drilled by MDS Energy Public 2012-A LP may qualify for a first-year bonus depreciation allowance in an amount equal to 50% of the partnership’s unadjusted depreciable basis in the equipment without any dollar limitation, for qualified equipment in the wells, provided that the wells are drilled, completed, and made capable of production (i.e., “placed in service”) by the partnership in 2012 , which depends primarily on when the partnership’s subscription proceeds are received. In the case of wells placed in service in 2012 by MDS Energy Public 2012-A LP, if any, the partnership’s basis in the equipment must be reduced by the 50% first-year bonus depreciation allowance for purposes of calculating the MACRS depreciation allowances for the remaining 50% of basis in the equipment over a seven-year cost recovery period beginning in 2012. There would not be any alternative minimum tax adjustment with respect to MDS Energy Public 2012-A LP’s first-year bonus depreciation allowances discussed above, if any, nor any of the other depreciation deductions allowable in 2012 or later years for the partnership’s costs of qualified equipment for any wells it places in service in 2012. I.R.C.§168(k)(2)(G).

Subject to the above, each partnership’s reasonable Tangible Costs for equipment placed in its wells that cannot be deducted immediately will be recovered through depreciation deductions over a seven year cost recovery period, using the 200% declining balance method with a switch to straight-line to maximize the deduction, beginning in the taxable year in which each well is drilled, completed and made capable of production, (i.e., “placed in service”) by the partnership. In this regard, the managing general partner anticipates that it may take up to 12 months after a partnership’s final closing before all of the partnership’s wells are drilled, completed and placed in service for the production of natural gas or oil. I.R.C. §168(c). In the case of a short partnership tax

 

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year, the MACRS deduction will be prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. Under §168(d)(1) of the Code, all property assigned to the 7-year class is treated as placed in service, or disposed of, in the middle of the year, unless more than 40% of the total cost of all equipment in the partnership’s wells placed in service during the year is placed in service during the last three months of the year. If that happens, then under §168(d)(3) of the Code the depreciation for the full year will be multiplied by a fraction based on the quarter the equipment is placed in service: 87.5% for the first quarter, 62.5% for the second, 37.5% for the third, and 12.5% for the fourth. All of these cost recovery deductions claimed by the partnership and you and the other investors in the partnership are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property by the partnership or your units by you. See “– Sale of the Properties” and “– Disposition of Units,” below. Depreciation for alternative minimum tax purposes, however, is computed using the 150% declining balance method switching to straight-line, for most personal property, which will result in adjustments in computing the alternative minimum taxable income of you and the other investors except as discussed above in the case of the 50% bonus depreciation allowance for wells place in service in 2012, if any. See “– Alternative Minimum Tax,” below.

Marginal Well Production Credits Under current law, depending on natural gas and oil prices, there is a marginal well production credit of 50¢ per mcf of qualified natural gas production and $3 per barrel of qualified oil production for purposes of the regular federal income tax, but not the alternative minimum tax. See “– Alternative Minimum Tax,” below. However, President Obama’s administration has proposed repealing this credit, beginning January 1, 2013, which Congress may or may not do. See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership.” A tax credit, unlike a tax deduction, reduces tax liability on a dollar-for-dollar basis. A partnership’s natural gas and oil production that qualifies as marginal production under the percentage depletion rules of §613A(c)(6) of the Code as discussed above in “– Depletion Allowance,” if any, also will qualify as marginal production for purposes of this credit. However, the credit will be reduced proportionately if the reference prices for the previous calendar year are between $1.67 and $2.00 per mcf for natural gas and $15 and $18 per barrel for oil, adjusted in both cases for inflation. In this regard, the managing general partner anticipates that none of MDS Energy Public 2012-A LP’s natural gas and oil production in 2012, if any, will qualify for this credit, because the prices for natural gas and oil in 2011 were substantially above the prices where the credit phases out completely. Based on the prices for natural gas and oil in recent years compared with the prices at which the credit phases out completely, it may appear unlikely that a partnership’s natural gas and oil marginal production if any, would ever qualify for this credit. However, prices for natural gas and oil are volatile and could decrease in the future. See “Risk Factors – Risks Related To The Partnerships’ Oil and Gas Operations – Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil.” Depending primarily on the applicable reference prices for natural gas and oil in the future, it is possible that the partnerships’ marginal production of natural gas or oil in one or more taxable years after 2012, if any, could qualify for the marginal well production credit, however, each partnership’s production of natural gas and oil may not qualify for marginal well production credits for many years, if ever.

Lease Acquisition Costs and Abandonment

Lease acquisition costs, together with the related cost depletion deduction, any amortization deductions for geological and geophysical expenses incurred after August 8, 2005 with respect to a partnership’s prospects, and any abandonment loss deduction for lease acquisition costs, are allocated under the partnership agreement 100% to the managing general partner, which will contribute the leases to the partnerships as part of its required minimum capital contribution to each partnership.

 

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Tax Basis of Units

Your share of your partnership’s losses is allowable only to the extent of the adjusted basis of your units at the end of the partnership’s taxable year. I.R.C. §704(d). The adjusted basis of your units will be adjusted, but not below zero, for any gain or loss to you from a sale or other taxable disposition by the partnership of a natural gas or oil property, and will be increased by your:

 

•

cash subscription payment;

 

•

share of partnership income; and

 

•

share, if any, of partnership debt.

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

 

•

share of partnership losses;

 

•

share of partnership expenditures that are not deductible in computing its taxable income and are not properly chargeable to capital account;

 

•

depletion deductions, but not below zero;

 

•

cash distributions from the partnership; and

 

•

any reduction in your share of the partnership’s debt, if any. I.R.C. §§705, 722 and 742.

The reduction in your share of partnership liabilities, if any, is considered a cash distribution to you. Although you will not be personally liable on any partnership loans, if you invest in a partnership as an investor general partner you will be liable as a general partner for all other obligations of the partnership. See “Risk Factors – Risks Related to an Investment In the Partnership – If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner.” Should cash distributions to you from your partnership exceed the tax basis of your units immediately before the distributions, taxable gain would result to you to the extent of the excess. See “– Distributions From a Partnership,” below.

“At Risk” Limitation on Losses

You may use your share of your partnership’s losses to offset income from other sources to the extent that your use of those losses is not limited by the adjusted tax basis of your units or the passive activity limitations on losses and credits, but only to the extent of the amount you have “at risk” in the partnership under §465 of the Code at the end of a taxable year. See “– Limitations on Passive Activity Losses and Credits” and “– Tax Basis of Units,” above. “Loss,” for purposes of the “at risk” rules, means the excess of your share of the allocable deductions for a taxable year from the partnership over the amount of income actually received or accrued by you during the year from the partnership. This “at risk” limitation on your share of the partnership’s losses, however, does not apply to you if you are a corporation that is neither an S corporation nor a corporation in which at any time during the last half of the taxable year five or fewer individuals owned more than 50% (in value) of the outstanding stock under §542(a)(2) of the Code.

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

 

•

nonrecourse loans;

 

•

guarantees;

 

•

stop loss agreements; or

 

•

other similar arrangements.

 

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

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

Distributions From a Partnership

A cash distribution from your partnership to you in excess of the adjusted basis of your units immediately before the distribution is treated as gain to you from the sale or exchange of your units to the extent of the excess. I.R.C. §731(a)(1). Different rules apply, however, to payments by the partnership to a deceased investor’s successor in interest and to payments for an investor’s share of the partnership’s unrealized receivables and inventory items as those terms are defined in §751 of the Code. Under §731(a)(2) of the Code, no loss can be recognized by you on these types of distributions unless the distribution is made to liquidate your units in the partnership, and then only to the extent of the excess, if any, of your adjusted basis in your units over the sum of the amount of money distributed to you plus your share of the basis (as determined under §732 of the Code) of any unrealized receivables and inventory items of the partnership. See “– Disposition of Units,” below, for a discussion of the partnership’s unrealized receivables and inventory items under §751 of the Code.

No gain or loss will be recognized by your partnership on cash distributions to you and its other investors. I.R.C. §731(b). If property is distributed by the partnership to the managing general partner and you and the other investors in the partnership, basis adjustments to the partnership’s properties may be made by the partnership, and adjustments to the basis in their respective interests in the partnership may be made by the managing general partner and you and the other investors. I.R.C. §§732, 733, 734, and 754. See Section 5.04(c) of the partnership agreement and “– Tax Elections,” below. Other distributions of cash, disproportionate distributions of property, if any, and liquidating distributions of your partnership may result in taxable gain or loss to you and the other investors.

Sale of the Properties

The maximum tax rate on a noncorporate taxpayer’s long-term capital gain on the sale of most capital assets held more than a year is 15%, or 0% to the extent the gain would have been taxed at a rate below 25% if it had been ordinary income. In addition, the former maximum tax rates of 20% and 10%, respectively, on qualified five-year gain have been eliminated. These capital gain rates also apply for purposes of the alternative minimum tax. See “– Alternative Minimum Tax,” below. However, the former tax rates on long-term capital gains are scheduled to be reinstated on January 1, 2013. If this happens, long-term capital gains of a noncorporate taxpayer that are now taxed at a rate of 0% will be taxed at a rate of 10% (8% for assets held over five years), and long-term capital gains now taxed at a rate of 15% will be taxed at a rate of 20% (18% for assets held over five years).

Under §1(h)(3) of the Code, “adjusted net capital gain” means net capital gain determined without taking qualified dividend income into account:

 

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reduced (but not below zero) by:

 

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any amount of qualified dividend income taken into account as investment income under §163(d)(4)(B)(iii) of the Code;

 

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net capital gain that is taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of qualified small business stock qualified under §1202 of the Code); and

 

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net capital gain that is taxed at a maximum rate of 25% (gain attributable to real estate depreciation); and

 

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increased by the amount of qualified dividend income.

“Net capital gain” means the excess of net long-term gain (the excess of long-term gains over long-term losses) over net short-term loss (the excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. I.R.C. §1211(b)

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

 

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on the sale or exchange of a property used in a trade or business; and

 

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from the involuntary conversion into other property or money of:

 

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property used in a trade or business; or

 

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any capital assets that are held for more than one year and are held in connection with a trade or business or a transaction entered into for profit.

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

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

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

 

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the aggregate amount of the net §1231 losses for the five most recent taxable years; over

 

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

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

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

 

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the aggregate amount of expenditures that have been deducted as intangible drilling costs with respect to the property and which, but for being deducted, would have been included in the adjusted basis of the property, plus deductions for depletion that reduced the adjusted basis of the property; or

 

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the excess of:

 

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the amount realized, in the case of a sale, exchange or involuntary conversion; or

 

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the fair market value of the property, in the case of any other taxable disposition;

over the adjusted basis of the property. I.R.C. §1254(a).

See “– Intangible Drilling Costs” and “– Depletion Allowance,” above.

Also, all gain on the sale or other taxable disposition of equipment by a partnership will be treated as ordinary income to the extent of MACRS deductions previously claimed by the partnership. I.R.C. §1254(a). See “– Depreciation and Cost Recovery Deductions,” above.

Disposition of Units

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

The sale or exchange, including a purchase by the managing general partner, of all or some of your units, if held by you as a capital asset for more than 12 months, will result in your recognition of long-term capital gain or loss, except for your share of your partnership’s “§751 assets” (i.e. inventory items and unrealized receivables). “Unrealized receivables” generally includes any right to payment for goods delivered, or to be delivered, to the extent the proceeds would be treated as amounts received from the sale or exchange of non-capital assets, services rendered or to be rendered, to the extent not previously includable in income under your partnership’s accounting methods, and deductions previously claimed by you for depreciation, depletion and intangible drilling costs with respect to the partnership. “Inventory items” includes property properly included inventory, property held primarily for sale to customers in the ordinary course of business and any other property that would produce ordinary income if sold, including accounts receivable for goods and services. These tax items are sometimes referred to in this discussion as “§751 assets.” All of these tax items may be recaptured as ordinary income rather than capital gain regardless of how long you have owned your units. See “ – Sale of the Properties,” above.

If your units are held for 12 months or less, your gain or loss will be short-term gain or loss. Also, your pro rata share of the partnership’s liabilities, if any, as of the date of the sale or exchange, must be included in the amount realized by you. Thus, the gain recognized by you may result in a tax liability to you greater than the cash proceeds, if any, received by you from the disposition of your units. In addition to characterization of any gain as gain from a passive activity, a portion of any gain recognized by a limited partner on the sale or other taxable disposition of his units will be characterized as portfolio income under the passive activity loss rules to the extent the gain is attributable to portfolio income, e.g. interest income on investments of working capital. Treas. Reg. §1.469-2T(e)(3). See “– Limitations on Passive Activity Losses and Credits,” above.

A gift of your units may result in federal and/or state income tax and gift tax liability to you. Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. I.R.C. §1031(a)(2)(D). Other types of dispositions of your units may or may not result in recognition of taxable gain. However, no gain should be recognized by an investor general partner on the conversion of his investor general partner units to limited partner units so long as there is no change in his share of his partnership’s liabilities, if any, or §751 assets as a result of the conversion. Revenue Ruling 84-52, 1984-1 C.B. 157.

 

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If you die, or sell or exchange all of your units, the taxable year of your partnership will close with respect to you, but not the remaining investors, on the date of death, sale or exchange, and there will be a proration of partnership items for the partnership’s taxable year. If you sell less than all of your units, the partnership’s taxable year will not terminate with respect to you, but your proportionate share of the partnership’s items of income, gain, loss, deduction and credit will be determined by taking into account your varying interests in the partnership during the taxable year.

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

Alternative Minimum Tax

With limited exceptions, under §55 of the Code you must pay an alternative minimum tax if it exceeds your regular federal income tax for the year. Alternative minimum taxable income (“AMTI”) is regular federal taxable income, plus or minus various adjustments, plus tax preference items. The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married individuals filing separately, of a taxpayer’s AMTI in excess of the applicable exemption amount (as set forth below); and additional AMTI is taxed at 28%. However, the regular tax rates on capital gains also will apply for purposes of the alternative minimum tax. See “– Sale of the Properties,” above. Exemption amounts for alternative minimum tax purposes are different from the regular tax personal exemptions, which are not allowed, and the types and amounts of itemized deductions allowed for minimum tax purposes are more limited than those allowed for regular tax purposes as discussed below. For example, in 2011 only, the alternative minimum tax exemption amounts for individuals were as follows:

 

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married individuals filing jointly and surviving spouses, $74,450, less 25% of AMTI exceeding $150,000 (zero exemption when AMTI is $447,800);

 

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unmarried individuals other than surviving spouses, $48,450, less 25% of AMTI exceeding $112,500 (zero exemption when AMTI is $306,300); and

 

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married individuals filing separately, $37,225, less 25% of AMTI exceeding $75,000 (zero exemption when AMTI is $223,900). Also, AMTI of married individuals filing separately is increased by the lesser of $37,225 or 25% of the excess of AMTI (without regard to the exemption reduction) over $223,900.

The managing general partner anticipates that the President and Congress will enact similar exemptions from the alternative minimum tax for 2012. Absent a future change in the Code, however, the exemption amounts for individuals for alternative minimum tax purposes in 2012 and subsequent years will be reduced substantially from those set forth above for 2011.

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

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

 

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Depreciation deductions of the cost of the equipment placed in service in the wells (except equipment, if any, that qualifies for the 2012 50% bonus depreciation allowance for MDS Energy Public 2012-A LP ) generally may not exceed deductions computed using the 150% declining balance method. See “– Depreciation and Cost Recovery Deductions,” above.

 

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Miscellaneous itemized deductions are not allowed.

 

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Medical expenses are deductible only to the extent they exceed 10% of adjusted gross income.

 

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State and local income taxes, and general sales and use taxes generally are not deductible unless they are deductible in computing adjusted gross income for regular income tax purposes. Absent future legislation from Congress, which may or may not be retroactive to January 1, 2012, your election to deduct general sales and use taxes in lieu of state and local income taxes that was available for 2011 will not be available for 2012.

 

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Interest deductions are restricted.

 

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The standard deduction and personal exemptions are not allowed.

 

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Only some types of operating losses are deductible.

 

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Passive activity losses are computed differently.

 

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Earlier recognition of income from incentive stock options may be required.

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

 

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excess intangible drilling costs, as discussed below; and

 

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tax-exempt interest earned on certain private activity bonds.

For taxpayers other than “integrated oil companies” as that term is defined in “– Intangible Drilling Costs,” above, which does not include the partnership, the 1992 National Energy Bill repealed:

 

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the preference for excess intangible drilling costs; and

 

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the excess percentage depletion preference for natural gas and oil.

The repeal of the excess intangible drilling costs preference, however, under current law may not result in more than a 40% reduction in the amount of the taxpayer’s AMTI computed as if the excess intangible drilling costs preference had not been repealed. I.R.C. §57(a)(2)(E). Under the prior rules, the amount of intangible drilling costs that is not deductible for alternative minimum tax purposes is the excess of the “excess intangible drilling costs” over 65% of net income from natural gas and oil properties. Net natural gas and oil income is determined for this purpose without subtracting excess intangible drilling costs. Excess intangible drilling costs is the regular intangible drilling costs deduction minus the amount that would have been deducted under 120-month straight-line amortization, or, at the taxpayer’s election, under the cost depletion method. There is no preference item for costs of nonproductive wells. Also, you may elect under §59(e) of the Code to capitalize all or part of your share of your partnership’s intangible drilling costs and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred by the partnership. This election also applies for regular tax purposes and can be revoked only with the IRS’ consent. Making this election, therefore, will include the following principal consequences to you:

 

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your regular federal income tax deduction for intangible drilling costs in the year you invest in a partnership will be reduced, because you must spread the deduction for the amount of intangible drilling costs that you elect to capitalize over the 60-month amortization period; and

 

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the capitalized intangible drilling costs will not be treated as a preference that is included in your alternative minimum taxable income.

See “– Drilling Contracts,” above.

Other than intangible drilling costs as discussed above, and passive activity losses and credits in the case of limited partners, the principal tax item that may have an impact on your AMTI as a result of investing in a partnership is depreciation of the partnership’s equipment expenses. See “– Limitations on Passive Activity

 

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Losses and Credits,” above. As noted in “– Depreciation and Cost Recovery Deductions,” above, subject to the exception for the 50% bonus depreciation allowance for any wells placed in service in 2012 by MDS Energy Public 2012-A LP, each partnership’s cost recovery deductions will be computed differently for regular income tax purposes than for alternative minimum tax purposes. Consequently, if MDS Energy Public 2012-A LP places any wells in service in 2013, or if you invest in another partnership in this program in 2013, then in the early years of the cost recovery period for your partnership’s equipment, but not in the later years, your depreciation deductions from the partnership generally will be smaller for alternative minimum tax purposes than your depreciation deductions for regular income tax purposes on the same equipment. This could cause you to incur, or may increase your, alternative minimum tax liability in those taxable years. Also, under current law, your share of your partnership’s marginal well production credits, if any, may not be used to reduce your alternative minimum tax liability, if any. In addition, the rules relating to the alternative minimum tax for corporations are different from those for individuals that are discussed above.

All prospective investors contemplating purchasing units in a partnership are urged to seek advice based on their particular circumstances from an independent tax advisor as to the likelihood of them incurring or increasing any alternative minimum tax liability as a result of an investment in a partnership.

Limitations on Deduction of Investment Interest

Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed investment interest expense deductions to subsequent taxable years. I.R.C. §163(d). An investor general partner’s share of any interest expense incurred by his partnership before his investor general partner units are converted to limited partner units will be subject to the investment interest limitation. I.R.C. §163(d)(5)(A)(ii). In addition, the deduction for intangible drilling costs included in an investor general partner’s share of the partnership’s loss in the year he invests will reduce his net investment income and may reduce or eliminate the deductibility of his investment interest expenses, if any, in that year, with the disallowed portion to be carried forward to subsequent taxable years. This limitation on the deduction of investment interest expenses, however, will not apply to any income or expenses taken into account by limited partners in computing their income or loss from the partnership as a passive activity under §469 of the Code. I.R.C. §163(d)(4)(D). See “– Limitations on Passive Activity Losses and Credits,” above.

Allocations

The partnership agreement allocates to you your share of your partnership’s income, gains, losses, deductions, and credits, if any, including the deductions for intangible drilling costs and depreciation. Your capital account in the partnership will be adjusted to reflect your share of these allocations, and your capital account, as adjusted, will be given effect by the partnership in making distributions to you on liquidation of the partnership or your units. Also, the basis of the natural gas and oil properties owned by the partnership for purposes of computing cost depletion and gain or loss on disposition of a property will be allocated and reallocated when necessary in the ratio in which the expenditure giving rise to the tax basis of each property was charged as of the end of the year. See Section 5.03(b) of the partnership agreement.

Your capital account in your partnership will be:

 

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increased by the amount of money you contribute to the partnership and allocations of partnership income and gain to you; and

 

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decreased by the value of property or cash distributed to you by the partnership and allocations of partnership losses and deductions to you.

Allocations under the partnership agreement of some tax items are made in ratios that are different from allocations of other tax items (i.e., “special allocations”). These special allocations generally will not be given effect under the Code unless they have “substantial economic effect” and any partner with a deficit balance in his capital account following the liquidation of his interest in the partnership is required to restore the amount of the

 

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deficit to the partnership. Economic effect means that if there is an economic benefit or burden that corresponds to an allocation, the partner to whom the allocation is made must receive the economic benefit or bear the economic burden. The economic effect of an allocation is substantial if there is a reasonable possibility that the allocation will affect substantially the dollar amounts to be received by the partners from the partnership, independent of tax consequences and taking into account the partners’ tax attributes that are unrelated to the partnership.

Also, even though you and the other investors are not required under the partnership agreement to restore any deficit balance in your capital accounts by making additional capital contributions to your partnership, an allocation that is not attributable to nonrecourse debt or tax credits will still be considered to have economic effect to the extent it does not cause or increase a deficit balance in your capital account if throughout the term of the partnership:

 

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the partners’ capital accounts are increased and decreased as described above;

 

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the partnership’s liquidation proceeds are distributed in accordance with the partners’ capital accounts; and

 

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the partnership agreement provides that if you unexpectedly incur a deficit balance in your capital account because of certain adjustments, allocations, or distributions of the partnership, then you will be allocated an additional amount of partnership income and gain that is sufficient to eliminate the deficit balance as quickly as possible.

Treas. Reg. §1.704-1(b)(2)(ii)(d). These provisions are included in the partnership agreement. See Sections 5.02, 5.03(h), and 7.02(a) of the partnership agreement.

Special provisions of the Treasury Regulations apply to deductions that are related to nonrecourse debt and tax credits, since allocations of those tax items cannot have substantial economic effect under the Treasury Regulations. If the managing general partner or an affiliate makes a nonrecourse loan to your partnership (a “partner nonrecourse liability”), then the partnership’s losses, deductions, or §705(a)(2)(B) expenditures attributable to the loan must be allocated to the managing general partner. Also, if there is a net decrease in partner nonrecourse liability minimum gain with respect to the loan, the managing general partner must be allocated income and gain equal to the net decrease. See Sections 5.03(a)(1) and 5.03(i) of the partnership agreement. In addition, any marginal well production credits of the partnership will be allocated among the managing general partner and you and the other investors in your partnership in accordance with each partner’s respective interest in the partnership’s production revenues from the sale of its natural gas and oil marginal production. See Section 5.03(g) of the partnership agreement, “Participation in Costs and Revenues,” and “– Marginal Well Production Credits,” above.

If you sell or transfer your unit in your partnership, or on the death of an investor or the admission of an additional partner, the partnership’s income, gain, loss, credits and deductions will be allocated among its partners according to their varying interests in the partnership during the taxable year. In addition, the Code may require the partnership’s property to be revalued on the admission of additional partners, if any, if disproportionate distributions are made to the partners, or if there are “built-in” losses on the transfer of a partner’s units or any distribution of the partnership’s property to its partners. See “– Tax Elections,” below.

It should be noted that your share of items of income, gain, loss, deduction, and credit, if any, in your partnership must be taken into account by you whether or not you receive any cash distributions from the partnership. For example, your share of partnership revenues applied by the partnership to the repayment of loans, if any, or the reserve for plugging wells, will be included in your gross income in a manner analogous to an actual distribution of the revenues (and income) to you. Thus, you may have tax liability on taxable income from the partnership for a particular year in excess of any cash distributions from the partnership to you with respect to that year. To the extent your partnership has cash available for distribution, however, it is the managing general partner’s policy

 

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that partnership cash distributions to you and the other investors in the partnership will not be less than the managing general partner’s estimate of the investors’ average federal income tax liability with respect to the partnership’s income.

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

Partnership Borrowings

The use of partnership revenues taxable to you to repay borrowings by your partnership, if any, could create income tax liability for you in excess of your cash distributions from the partnership, since repayments of principal are not deductible for federal income tax purposes. In addition, interest on loans from the managing general partner or its affiliates will not be deductible unless the loans are bona fide loans that will not be treated by the IRS as capital contributions to the partnership by the managing general partner or its affiliates in light of all of the surrounding facts and circumstances. Also, the “at risk” amounts of you and the other investors in the partnership, which limit the amount of partnership losses you and the other investors can claim as discussed in “– ‘At Risk’ Limitation on Losses,” above, will not be increased by the amount of any partnership nonrecourse borrowings, because you and the other investors will not bear any risk of repaying the borrowings from your non-partnership assets, even if you invest in the partnership as an investor general partner.

Partnership Organization and Offering Costs

Expenses connected with the offer and sale of units in the partnership, such as the dealer-manager fee, sales commissions and other selling expenses, professional fees, and printing costs, which are charged 100% to the managing general partner as organization and offering costs, are not deductible. Although expenses incident to the creation of the partnership may be amortized over a period of not less than 180 months, these expenses also will be paid by the managing general partner as part of the partnership’s organization costs. Thus, any related deductions, which are not expected by the managing general partner to be a material amount as compared to the total amount of a partnership’s subscription proceeds, also will be allocated under the partnership’s agreement to the managing general partner.

Tax Elections

Each partnership may elect to adjust the basis of its property (other than cash) on the transfer of a unit in the partnership by sale or exchange or on the death of an investor, and on the distribution of property (other than money) by the partnership to an investor (the §754 election). Any election, once made, may not be revoked without the consent of the IRS. In this regard, due to the tax complexities and added expense of the tax accounting required to implement a §754 election to adjust the basis of a partnership’s property when units are sold, taking into account the limitations on the sale of the partnership’s units as described in “Transferability of Units,” the managing general partner anticipates that the partnerships will not make the §754 election, although each partnership reserves the right to do so. Even if a partnership does not make the §754 election, however, the basis adjustment described above is mandatory under the Code with respect to the transferee partner only, if at the time a unit is transferred by sale or exchange, or on the death of an investor, the partnership’s adjusted basis in its property exceeds the fair market value of the property by more than $250,000 immediately after the transfer of the unit. Similarly, a basis adjustment is mandatory under the Code if a partnership distributes property in-kind to a partner and the sum of the partner’s loss on the distribution and the basis increase to the distributed property is more than $250,000. I.R.C. §§734 and 743. In this regard, under Section 7.02 of the partnership agreement, a partnership will not distribute its assets in-kind to its investors, except to a liquidating trust or similar entity for the benefit of its investors on the dissolution and termination of the partnership, unless at the time of the

 

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distribution its investors have been offered the election of receiving in-kind property distributions, and you or any other investor in the partnership accepts the offer after being advised of the risks associated with direct ownership; or there are alternative arrangements in place that assure that you and the other investors in the partnership will not, at any time, be responsible for the operation or disposition of the partnership’s properties.

If the basis of your partnership’s assets must be adjusted as discussed above, the primary effect on the partnership, other than the federal income tax consequences discussed above, would be an increase in its administrative and accounting expenses to make the required basis adjustments to its properties and separately account for those adjustments after they are made. In this regard, the partnerships will not make in-kind property distributions to their respective investors except in the limited circumstances described above, and the units will have no readily available market and will be subject to substantial restrictions on their transfer. See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.” These factors will tend to reduce the likelihood that a partnership will be required to make mandatory basis adjustments to its properties.

In addition to the §754 election, each partnership may make various elections under the Code for federal tax reporting purposes that could result in the deductions of intangible drilling costs, depreciation and the depletion allowance being treated differently for tax purposes than for accounting purposes. Also, under §195 of the Code “start-up expenditures” may be capitalized and amortized over a 180-month period. The term “start-up expenditure” for this purpose includes any amount:

 

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paid or incurred in connection with:

 

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investigating the creation or acquisition of an active trade or business;

 

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creating an active trade or business; or

 

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any activity engaged in for profit and for the production of income before the day on which the active trade or business begins, in anticipation of that activity becoming an active trade or business; and

 

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that would be allowable as a deduction if paid or incurred in connection with the expansion of an existing business.

If it is ultimately determined by the IRS or the courts that any of a partnership’s expenses constituted start-up expenditures, the partnership’s deductions for those expenses, including your share, if any, of those deductions under the partnership agreement, would be amortized over the 180-month period.

Tax Returns and IRS Audits

The tax treatment of most partnership items is determined at the partnership, rather than the partner, level. Accordingly, you are required under the Code to treat the tax items of the partnership in which you invest on your individual federal income tax returns in a manner that is consistent with the treatment of the partnership items on the partnership’s federal information income tax returns, unless you disclose to the IRS, by attaching the required IRS notice to your individual federal income tax return, that your tax treatment of the partnership’s tax items on your personal federal income tax returns is different from the partnership’s tax treatment of those partnership tax items. I.R.C. §§6221 and 6222. Treasury Regulations define partnership tax items for this purpose as including distributive share items that must be allocated among the partners, such as partnership liabilities, data pertaining to the computation of the depletion allowance, and guaranteed payments. Treas. Reg. §301.6231(a)(3)-1.

In most cases, the IRS must make an administrative determination as to partnership tax items at the partnership level before conducting deficiency proceedings against a partner, and the partners must file a request for an IRS administrative determination with respect to the partnership before filing suit for any credit or refund. Also, the period for assessing tax against you and the other investors because of the partnership tax item may be extended

 

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by agreement between the IRS and the managing general partner, which will serve as each partnership’s representative (“Tax Matters Partner”) in all administrative tax proceedings and tax litigation, if any, conducted at the partnership level.

The Tax Matters Partner may enter into a settlement on behalf of, and binding on, any investor owning less than a 1% profits interest in a partnership if there are more than 100 partners in the partnership unless that investor timely files a statement with the Secretary of the Treasury providing that the Tax Matters Partner does not have authority to enter into a settlement agreement on behalf of that investor. However, by executing the Subscription Agreement you also are executing the partnership agreement if your Subscription Agreement is accepted by the managing general partner. Under the partnership agreement, you and the other investors in your partnership agree that you will not form or exercise any right as a member of a notice group and will not file a statement notifying the IRS that the Tax Matters Partner does not have binding settlement authority. In addition, a partnership with at least 100 partners may elect to be governed under simplified tax reporting and audit rules as an “electing large partnership.” However, most limitations affecting the calculation of the taxable income and tax credits of an electing large partnership are applied at the partnership level and not the partner level. Thus, the managing general partner does not anticipate that the partnerships will make this election if there are more than 100 partners in the partnership, although they reserve the right to do so.

All expenses of any tax proceedings involving a partnership and the managing general partner acting as Tax Matters Partner, which might be substantial, will be paid for by the partnership and not by the managing general partner from its own funds. The managing general partner, however, is not obligated to contest any adjustments made by the IRS to a partnership’s federal information income tax returns, even if the adjustment also would affect the individual federal income tax returns of you and the other investors in the partnership. The managing general partner will notify you and the other investors in your partnership of any material IRS audits or other tax proceedings involving the partnership, and will provide you and the other investors any other information regarding the proceedings as may be required by the partnership agreement or law.

Tax Returns

Your individual income tax returns are your responsibility. Each partnership will provide its investors with the tax information applicable to their investment in the partnership necessary to prepare their tax returns.

Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations on Deductions

Under §183 of the Code, your ability to deduct your share of your partnership’s deductions could be limited or lost if the partnership lacks the appropriate profit motive as determined from an examination of all facts and circumstances at the time. Section 183 of the Code creates a presumption that an activity is engaged in for profit if, in any three of five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if the partnership fails to show a profit in at least three out of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the partnership deductions claimed by you would be substantially increased. The fact that the possibility of ultimately obtaining profits is uncertain, standing alone, does not appear under the Treasury Regulations to be sufficient grounds for the denial of losses. Also, if a principal purpose of the partnership is to reduce substantially the partners’ federal income tax liability in a manner that is inconsistent with the intent of the partnership rules of the Code, based on all the facts and circumstances, the IRS is authorized under Treasury Regulation §1.701-2 to remedy the abuse. Finally, under potentially relevant judicial doctrines such as the step transaction, business purpose, economic substance, substance over form, and sham transaction doctrines, tax deductions and tax credits from a transaction, including the partnership’s deduction for intangible drilling costs in the year its investors invest in the partnership, would be disallowed if the partnership were found by the IRS or the courts to have no economic substance apart from the tax benefits.

With respect to these issues, special counsel has given its opinions under current law that each partnership will possess the requisite profit motive and the IRS anti-abuse rule in Treas. Reg. §1.701-2 and the potentially relevant judicial doctrines listed above will not have a material adverse effect on the tax consequences of an

 

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investment in a partnership by a typical investor as described in special counsel’s opinions. These opinions are based in part on the results of the previous natural gas and oil drilling partnerships sponsored by the managing general partner’s affiliates, MDS Energy, Ltd. and M/D Gas, Inc., as set forth in “Prior Activities,” and the managing general partner’s representations that are set forth in the tax opinion letter and this prospectus. The managing general partner’s representations include that each partnership will be operated as described in this prospectus (see “Management” and “Proposed Activities”) and the principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis to its investors, apart from tax benefits, as described in this prospectus.

Federal Interest and Tax Penalties

Taxpayers must pay tax and interest on underpayments of federal income taxes, and the Code contains various penalties, including penalties for negligence and substantial valuation misstatements with respect to a taxpayer’s individual federal income tax returns. For example, there is a penalty equal to 20% of the amount of a substantial understatement of federal income tax liability. There is a substantial understatement by a noncorporate taxpayer if the correct income tax, as finally determined by the IRS or the courts, exceeds the income tax liability shown on the taxpayer’s federal income tax return by the greater of 10% of the correct tax, or $5,000. In the case of a corporation, other than an S corporation or a personal holding company as defined in §542 of the Code, an understatement is substantial if it exceeds the lesser of: (i) 10% of the correct tax (or, if greater, $10,000); or (ii) $10 million. I.R.C. §6662. A noncorporate taxpayer may avoid this penalty if the understatement was not attributable to a “tax shelter,” as that term is defined below, and there is or was substantial authority for the taxpayer’s tax treatment of the item that caused the understatement, or if the relevant facts were adequately disclosed on the taxpayer’s individual federal income tax return and the taxpayer had a reasonable basis for the tax treatment of that item. In the case of an understatement that is attributable to a “tax shelter,” however, which may include the partnerships for this purpose, the penalty may be avoided by a noncorporate taxpayer only if there was reasonable cause for the underpayment and the taxpayer acted in good faith, or there is or was substantial authority for the taxpayer’s treatment of the item that caused the understatement and the taxpayer reasonably believed that his treatment of the item on his individual federal income tax return was more likely than not the proper treatment. For purposes of this penalty, the term “tax shelter” includes a partnership if a significant purpose of the partnership is the avoidance or evasion of federal income tax.

Also, under §6662A of the Code there is a 20% penalty for reportable transaction understatements of federal income taxes on a taxpayer’s individual federal income tax return for any tax year. However, if the disclosure rules for reportable transactions under the Code and the Treasury Regulations are not met by the taxpayer, this penalty is increased from 20% to 30%, and a “reasonable cause” exception to the penalty that is set forth in §6664(d) of the Code will not be available to the taxpayer. Under Treasury Regulation §1.6011-4, a taxpayer, which may include you and the other investors as discussed below, must report participation in a reportable transaction in any taxable year to the IRS, as directed in the Treasury Regulation, in order to avoid a penalty under § 6707A of the Code ranging from $5,000 to $10,000 if the taxpayer is a natural person, or from $10,000 to $50,000 for taxpayers that are not natural persons.

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

 

•

any listed transaction, which is a transaction that is the same as, or substantially similar to, a transaction that the IRS has publicly pronounced to be a tax avoidance transaction; or

 

•

other types of reportable transactions, where a significant purpose of the transaction is federal income tax avoidance or evasion.

For example, there would be a reportable transaction if a partnership or any of its noncorporate partners claims certain types of losses under §165 of the Code in amounts equal to at least $2 million, in the aggregate, in any taxable year of the partnership, or at least $4 million, in the aggregate, over the partnership’s first six years, and a significant purpose of the transaction was federal income tax avoidance or evasion. In this regard, deductions claimed for intangible drilling costs for productive wells should be treated as losses under §263(c) of the Code

 

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and Treas. Reg. §1.612-4(a), and should not be treated as §165 losses. However, a partnership may incur abandonment losses under §165 for wells drilled that are nonproductive (i.e. a “dry hole”), if any, and wells that have been operated until their commercial natural gas and oil reserves have been depleted. If a partnership’s abandonment losses under §165 are more than $2 million, in the aggregate, in any taxable year of the partnership, or more than $4 million, in the aggregate, during the partnership’s first six taxable years, then the managing general partner may determine that the partnership was engaged in a loss transaction type of “reportable transaction” that should be reported to the IRS as discussed above.

State and Local Taxes

Each partnership will operate in Pennsylvania and possibly other states and localities that may impose a tax on it, or on you and your partnership’s other investors, based on the partnership’s assets or income or your share of its assets or income. Also, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If your partnership becomes subject to state or local taxes as an entity, its cash available for distribution to you and its other investors will be reduced. Each partnership also may be subject to state income tax withholding requirements on its income allocable to you and its other investors, whether or not the revenues that created the income are distributed to you and its other investors. For example, if you are not a resident of Pennsylvania your partnership expects to withhold Pennsylvania income taxes at a rate of 3.07% on your share of its income from its wells situated in Pennsylvania.

If you are an individual, and not a corporation, and you are also not a resident of Pennsylvania, then unless you affirmatively elect in your Subscription Agreement to be included in your partnership’s consolidated state or local income tax returns, which will include your share of the partnership’s income and deductions (including the intangible drilling costs deduction, which the managing general partner anticipates will be amortized over an eight-year period for the partnership’s Pennsylvania income tax purposes only), you likely will be required to file your own tax returns for Pennsylvania and likely any other states where your partnership’s wells are situated. Also, a partnership may elect to file consolidated partnership tax returns in any other state where its wells may be situated if the election is available under the particular state’s laws. For partnership purposes, any payments to state or local tax authorities on your behalf by your partnership will be treated by the partnership as if those payments had actually been distributed to you and then you paid the taxes yourself.

Partnership deductions and credits, including marginal well production credits, if any, which may be available to you for federal income tax purposes, may not be available to you for state or local income tax purposes. If you reside in a state or locality that imposes income taxes on its residents, you likely will be required under those income tax laws to include your share of your partnership’s net income or net loss in determining your reportable income for state or local tax purposes in the jurisdiction in which you reside. To the extent that you pay tax to another state because of partnership operations within that state, you may be entitled to a deduction or credit against tax owed to your state of residence with respect to the same income. Also, due to a partnership’s operations in a state or local jurisdiction, state or local estate or inheritance taxes may be payable on the death of an investor in addition to estate or inheritance taxes imposed by his own domicile.

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

Severance and Ad Valorem (Real Estate) Taxes

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

 

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investors. In this regard, Pennsylvania recently enacted an impact fee generally ranging from a minimum of $190,000 to a maximum of $350,000 on each horizontal well, and from $38,000 to up to $70,000 per well for vertical wells, drilled in Pennsylvania to the Marcellus Shale geological formation, which is payable over a 15-year period for horizontal wells and a 10-year period for vertical wells, and will be adjusted for the price of natural gas and inflation in the future. Also, other fees or taxes on natural gas and oil production or wells may be enacted or increased in the future in Pennsylvania and any other states where a partnership drills its wells.

Social Security Benefits and Self-Employment Tax

A limited partner’s share of income or loss from a partnership is excluded from the definition of “net earnings from self-employment.” No increased benefits under the Social Security Act will be earned by limited partners and if any limited partners are currently receiving Social Security benefits, their shares of partnership taxable income will not be taken into account in determining any reduction in benefits because of “excess earnings.”

An investor general partner’s share of income or loss from a partnership, however, will constitute “net earnings from self-employment” for these purposes. The ceiling for social security tax in 2012 is $110,100, which will adjusted annually for inflation in subsequent years. Also, during 2012 only, the social security tax is 10.4%, instead of the usual 12.4% tax. Although the employer’s share of this tax continues at 6.2%, the employee’s share is reduced for 2012 only to 4.2% from the usual 6.2%. There is no ceiling for Medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax.

Farmouts

Under a farmout by a partnership, if a property interest, other than an interest in the prospect assigned to the partnership well in question, is earned by the farmee (i.e., anyone other than the partnership) from the farmor (i.e., the partnership) as a result of the farmee drilling or completing the well, then under the Code the farmee must recognize income equal to the fair market value of the outside interest earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between the fair market value of the outside interest and the farmor’s tax basis in the outside interest. Neither the farmor nor the farmee would have received any cash to pay the tax. The managing general partner has represented that it will attempt to eliminate or reduce any gain to a partnership from a farmout or farmin, if any. However, if the IRS claims that a farmout or farmin by a partnership, if any, results in taxable income to the partnership and its position is ultimately sustained, you and the other investors in the partnership would be required to include your share of the resulting taxable income on your individual income tax returns, even though the partnership and you and the other investors in the partnership received no cash from the transaction.

Foreign Partners

Each partnership generally will be required to withhold and pay income tax to the IRS at the highest rate under the Code applicable to partnership income allocable to its foreign investors, if any, even if no cash distributions are made to them. In the event of overwithholding, a foreign investor must seek a refund on his individual United States federal income tax return. For withholding purposes, a foreign investor means an investor who is not a United States person and includes a nonresident alien individual, a foreign corporation, a foreign partnership, and a foreign trust or estate, unless the investor has certified to his partnership the investor’s status as a U.S. person on Form W-9 or any other form permitted or required by the IRS for that purpose. Foreign investors are urged to seek advice based on their particular circumstances from an independent tax advisor regarding the applicability of these rules and the other tax consequences of an investment in a partnership to them.

You are urged to seek advice based on your particular circumstances from an independent tax advisor with respect to the impact of recent federal tax legislation on an investment in a partnership and the status of federal and state legislative, regulatory or administrative tax developments and tax proposals and their potential effect on the tax consequences to you of an investment in a partnership.

 

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SUMMARY OF PARTNERSHIP AGREEMENT

The rights and obligations of the managing general partner and you and the other investors in a partnership are governed by the form of partnership agreement attached as Exhibit (A) to this prospectus. You are urged to thoroughly review the partnership agreement before you decide to invest in a partnership. The following is a summary of material provisions in the partnership agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the partnership agreement.

Liability of Limited Partners

Each partnership will be governed by the Delaware Revised Uniform Limited Partnership Act. If you invest as a limited partner, then generally you will not be liable to third-parties for the obligations of the partnership unless you:

 

•

also invest as an investor general partner;

 

•

take part in the control of the partnership’s business in addition to the exercise of your rights and powers as a limited partner; or

 

•

fail to make a required capital contribution to the full extent of the required capital contribution.

In addition, you may be required to return any distribution you receive from your partnership if you knew at the time the distribution was made that it was improper because it rendered the partnership insolvent.

Amendments

Amendments to the partnership agreement of a partnership may be proposed in writing by:

 

•

the managing general partner and adopted with the consent of investors whose units equal a majority of the total units in the partnership; or

 

•

investors whose units equal 10% or more of the total units in the partnership and adopted by an affirmative vote of investors whose units equal a majority of the total units in the partnership.

The partnership agreement of each partnership may also be amended by the managing general partner without the consent of the investors for certain limited purposes. However, an amendment that materially and adversely affects the investors can only be made with the consent of the affected investors. For example, an amendment may not do the following without the approval of the investors:

 

•

increase the duties or liabilities of the investors;

 

•

decrease the duties or liabilities of the managing general partner;

 

•

decrease the investors’ profit sharing interest;

 

•

increase the investors’ loss sharing interest;

 

•

increase the required capital contribution of the investors; or

 

•

decrease the required capital contribution of the managing general partner.

Notice

The following provisions apply regarding notices:

 

•

when the managing general partner gives you and other investors notice it begins to run from the date of mailing the notice and is binding even if it is not received;

 

•

the notice periods are frequently quite short, a minimum of 22 calendar days, and apply to matters that may seriously affect your rights; and

 

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•

if you fail to respond in the specified time to the managing general partner’s second request for approval of or concurrence in a proposed action, then you will conclusively be deemed to have approved the action unless the partnership agreement expressly requires your affirmative approval.

Voting Rights

Other than as set forth below, you generally will not be entitled to vote on any partnership matters at any partnership meeting. At any time, however, investors whose units equal 10% or more of the total units in a partnership may call a for all investors to vote at a meeting, or vote without a meeting, on the matters set forth below without the concurrence of the managing general partner. On the matters being voted on you are entitled to one vote per unit or if you own a fractional unit that fraction of one vote equal to the fractional interest in the unit, regardless of the subscription price you paid for your units. Investors whose units equal a majority of the total units in the partnership may vote to:

 

•

dissolve the partnership;

 

•

remove the managing general partner and elect a new managing general partner;

 

•

elect a new managing general partner if the managing general partner elects to withdraw from the partnership;

 

•

remove the operator and elect a new operator;

 

•

approve or disapprove the sale of all or substantially all of the partnership’s assets;

 

•

cancel any contract for services with the managing general partner, the operator, or their affiliates without penalty on 60 days notice; and

 

•

amend the partnership agreement, however, any amendment may not:

 

•

without the approval of investors whose units equal a majority of the total units in the partnership or the managing general partner increase the duties or liabilities of you and the other investors or the managing general partner, respectively, or increase or decrease the profits or losses or required capital contribution of you and the other investors or the managing general partner, respectively; or

 

•

without the unanimous approval of the investors, affect the classification of partnership income and loss for federal income tax purposes.

The managing general partner, its officers, directors, and affiliates may also subscribe for units in the partnership on a discounted basis, and they may vote on all matters, including the issues set forth above, other than:

 

•

removing the managing general partner and operator; and

 

•

any transaction between the managing general partner or its affiliates of the partnership.

Any units owned by the managing general partner and its affiliates will not be included in determining the requisite number of units necessary to approve any partnership matter on which the managing general partner and its affiliates may not vote or consent.

Access to Records

You will have access to all records of your partnership at any reasonable time on adequate notice. However, logs, well reports, and other drilling and operating data may be kept confidential for reasonable periods of time. Also, your ability to obtain the list of investors is subject to additional requirements set forth in the partnership agreement.

 

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Withdrawal of Managing General Partner

After 10 years, which will not be earlier than eight years after all of the wells in your partnership have been drilled, the managing general partner may voluntarily withdraw as managing general partner of the partnership for any reason by giving 120 days’ written notice to you and the other investors in the partnership. Although the withdrawing managing general partner is not required to provide a substitute managing general partner, a new managing general partner may be substituted by the affirmative vote of investors whose units equal a majority of the total units in the partnership. If the investors, however, choose not to continue the partnership and do not select a substitute managing general partner, then the partnership would dissolve and terminate, which could result in adverse tax and other consequences to you.

Also, subject to retaining not less than a 1% interest in the partnership and its subordination obligations, unless there is a substituted managing general partner, the managing general partner may assign its general partner interest in the partnership to its affiliates and it may withdraw a property interest in the form of a working interest in your partnership’s wells equal to or less than its revenue interest at any time if the withdrawal is:

 

•

to satisfy the bona fide request of its creditors; or

 

•

approved by investors in the partnership whose units equal a majority of the total units.

See “Conflicts of Interest – Conflicts Regarding the Managing General Partner Withdrawing or Assigning an Interest.”

Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months

Although the managing general partner anticipates that your partnership will spend all of its subscription proceeds soon after the offering of the partnership closes, the partnership will have 12 months in which to use or commit its subscription proceeds to drilling activities. If within the 12-month period the partnership has not used, or committed for use, all of its subscription proceeds, however, then the managing general partner will distribute the remaining subscription proceeds to you and the other investors in the partnership in accordance with your respective subscription amounts as a return of capital.

 

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SUMMARY OF DRILLING AND OPERATING AGREEMENT

The managing general partner will serve as the operator under the drilling and operating agreement, Exhibit (II) to the partnership agreement. The operator may be replaced at any time on 60 days’ advance written notice by the managing general partner acting on behalf of your partnership on the affirmative vote of investors whose units equal a majority of the total units in the partnership. You are urged to thoroughly review the drilling and operating agreement before you decide to invest in a partnership. The following is a summary of the material provisions of the drilling and operating agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the drilling and operating agreement.

 

•

The operator’s right to resign after five years.

 

•

The operator’s right beginning one year after each partnership well drilled and completed by your partnership begins producing to retain $200 per month to cover future plugging and abandonment costs of the well.

 

•

The grant of a first lien and security interest in the wells and related production to secure payment of amounts due to the operator by your partnership.

 

•

The prescribed insurance coverage to be maintained by the operator.

 

•

Limitations on the operator’s authority to incur extraordinary costs with respect to producing wells in excess of $15,000 per well.

 

•

Restrictions on the partnership’s ability to transfer its interest in fewer than all wells unless the transfer is of an equal undivided interest in all of the wells.

 

•

The limitation of the operator’s liability to your partnership to claims and liabilities relating to, caused by or arising out of the operator’s:

 

(i)

violations of law;

 

(ii)

negligence or misconduct by it, its employees, dealers or subcontractors; or

 

(iii)

breach of the drilling and operating agreement;

except that under Section 4.05 of the partnership agreement the operator will not have any liability for any loss suffered by your partnership or you and the other investors which arises out of any action or inaction of the operator if the operator determined in good faith that the course of conduct was in the best interest of the partnership, the operator was performing services for the partnership and the operator’s course of conduct did not constitute negligence or misconduct.

 

•

The excuse for nonperformance by the operator of its obligations to your partnership due to force majeure, which generally means acts of God, catastrophes and other causes which preclude the operator’s performance and are beyond its control.

 

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REPORTS TO INVESTORS

Under the partnership agreement you and certain state securities commissions will be provided the reports and information set forth below, which your partnership will pay as a direct cost:

 

•

Beginning with the calendar year in which your partnership closes, you will be provided an annual report within 120 days after the close of the calendar year containing audited financial statements of the partnership prepared in accordance with generally accepted accounting principles with a reconciliation for information furnished for income tax purposes, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year containing at least the following information.

 

•

Beginning with the calendar year in which your partnership closes, you will be provided an annual report within 120 days after the close of the calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing at least the following information.

 

•

Audited financial statements of the partnership prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation for information furnished for income tax purposes. Independent certified public accountants will audit the financial statements to be included in the annual report, but semiannual reports will not be audited.

 

•

A summary of the total fees and compensation paid by the partnership to the managing general partner, the operator, and their affiliates. In this regard, the independent certified public accountant will provide written attestation annually, which will be included in the annual report, that the method used to make allocations was consistent with the method described in Section 4.04(a)(2)(c) of the partnership agreement (actual costs charged based upon the percentages of time of the relevant personnel of the managing general partner) and that the total amount of costs allocated did not materially exceed the amounts described in Section 4.04(a)(2)(c) of the partnership agreement.

If the managing general partner subsequently decides to allocate expenses in a manner different from that described in Section 4.04(a)(2)(c) of the partnership agreement, then the change must be reported to you and the other investors with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.

 

•

A description of each prospect owned by the partnership, including the cost, location, number of acres, and the interest.

 

•

A list of the wells drilled or abandoned by the partnership indicating:

 

•

whether each of the wells has or has not been completed; and

 

•

a statement of the cost of each well completed or abandoned.

 

•

A description of all farmouts, farmins, and joint ventures.

 

•

A schedule reflecting:

 

•

the total partnership costs;

 

•

the costs paid by the managing general partner and the costs paid by the investors;

 

•

the total partnership revenues; and

 

•

the revenues received or credited to the managing general partner and the revenues received or credited to you and the other investors.

 

•

On request the managing general partner will provide you the information specified by Form 10-Q (if that report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period. Also, this information is available at the SEC website www.sec.gov.

 

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•

By March 15 of each year you will receive the information that is required for you to file your federal and state income tax returns.

 

•

If the partnership sells units to 2,000 or more investors and receives and accepts $10 million or more in subscription proceeds, it must register the units with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). In that event, the partnership’s compliance with the reporting requirements of the Exchange Act would require timely filing of quarterly reports on Form 10-Q, annual reports on Form 10-K and current reports on Form 8-K, among other actions, including compliance with corporate governance and disclosure requirements under the Sarbanes-Oxley Act of 2002. This would increase the partnership’s administrative costs and direct costs, including legal and accounting fees, the majority of which would be charged to you and the other investors as set forth in “Participation in Costs and Revenues.”

 

•

By March 15 of each year you will receive the information that is required for you to file your federal and state income tax returns.

 

•

Beginning with the second calendar year after the partnership closes, and every year thereafter, you will receive a computation of the partnership’s total natural gas and oil proved reserves and its dollar value. The reserve computations will either be prepared by an independent expert selected by the managing general partner or be based on engineering reports prepared by the managing general partner and reviewed by an independent expert selected by the managing general partner.

 

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PRESENTMENT FEATURE

Beginning with the fifth calendar year after the offering of your partnership closes, you and the other investors in the partnership may present your units to the managing general partner to purchase your units. However, you are not required to offer your units to the managing general partner, and you may receive a greater return on your investment in the partnership if you retain your units. The managing general partner will not purchase less than one unit unless the fractional unit represents your entire interest in the partnership.

The managing general partner has no obligation or intention to establish a reserve to satisfy the presentment feature and it may immediately suspend the presentment obligation by notice to you if it determines, in its sole discretion, that it:

 

•

does not have the necessary cash flow; or

 

•

cannot borrow funds for this purpose on terms it deems reasonable.

If fewer than all units presented at any time are to be purchased by the managing general partner, then the units to be purchased will be selected by lot.

The managing general partner’s obligation to purchase the units presented may be discharged for its benefit by a third-party or an affiliate. If you sell your unit it will be transferred to the party who pays for it, and you will be required to deliver an executed assignment of your unit along with any other documents that the managing general partner requests. Your presentment of your units to the managing general partner for purchase is subject to the following conditions:

 

•

the managing general partner will not purchase more than 5% of the total outstanding units in the partnership in any calendar year, and this 5% limit may not be waived;

 

•

your presentment request must be made within 120 days of the partnership reserve report discussed below;

 

•

in accordance with Treas. Reg. §1.7704-1(f) the managing general partner may not purchase your units until at least 60 calendar days after you notify the partnership in writing of your intent to present your units for purchase; and

 

•

the purchase of your units will not be considered effective until the presentment price has been paid to you in cash.

The amount of your presentment price for your units will be based on the ratio that your number of units bears to the total number of units in the partnership and you will receive the greater of the following amounts for your units, subject to the managing general partner’s right to suspend the presentment feature and the other limitations regarding the presentment feature discussed above:

 

•

three times the amount of the partnership’s total distributions to you during the previous twelve months; or

 

•

the amount that is generally attributable to your share of your partnership’s natural gas and oil reserves, as discussed below.

Any distributions made to you between the date of your presentment request and the date the presentment price is paid to you will reduce the amount of your presentment price. However, if any of those cash distributions to you by your partnership was derived from the sale of oil, natural gas, or a producing property after the date of your presentment request, the amount of those cash distributions will be discounted at the same rate used to take into account the risk factors employed to determine the present worth of the partnership’s proved reserves for purposes of determining the presentment price. Also, there will be deducted from the foregoing sum an amount equal to all of your partnership’s debts, obligations, and other liabilities, including accrued expenses.

 

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The amount of the presentment price for your units that is attributable to the partnership’s natural gas and oil reserves, as discussed below, will be determined based on the last reserve report prepared by either the managing general partner and reviewed by an independent expert or prepared by an independent expert selected by the managing general partner, in the managing general partner’s sole discretion. Beginning with the second calendar year after the offering of units in your partnership closes and every year thereafter, the managing general partner or an independent expert, in the managing general partner’s sole discretion, will estimate the present worth of future net revenues attributable to the partnership’s interest in proved reserves based on:

 

•

a 10% discount rate;

 

•

a constant oil price; and

 

•

natural gas prices on the existing natural gas contracts or prices at the time of the presentment.

Your presentment price that is generally based on your partnership’s natural oil and gas reserves, as described below will be allocated pro rata to you, based on the ratio that your number of units bears to the total number of units in your partnership. The presentment price will include the sum of the following partnership items:

 

•

an amount based on 70% of the present worth of future net revenues from the proved reserves determined as described above;

 

•

cash on hand;

 

•

prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and

 

•

the estimated market value of all assets not separately specified above, determined in accordance with standard industry valuation procedures.

The presentment price that is generally based on the partnership’s natural gas and oil reserves, as discussed above, may be further adjusted by the managing general partner for estimated changes from the date of the reserve report discussed above to the date of payment of the presentment price to you due to the following:

 

•

the production or sales of, or additions to, reserves and lease and well equipment, sale or abandonment of leases, and similar matters occurring before the presentment request; and

 

•

any of the following occurring before payment of the presentment price to you;

 

•

changes in well performance;

 

•

increases or decreases in the market price of oil, natural gas, or other minerals;

 

•

revision of regulations relating to the importing of hydrocarbons;

 

•

changes in income, ad valorem, and other tax laws, such as material variations in the provisions for depletion; and

 

•

similar matters.

 

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TRANSFERABILITY OF UNITS

Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement

Your ability to sell or otherwise transfer your units in your partnership is restricted by the securities laws, the tax laws, and the partnership agreement as described below. Also, the sale or other transfer of your units may create negative tax consequences to you as described in “Federal Income Tax Consequences – Disposition of Units.”

Also, under the partnership agreement sales or other transfers of the units are subject to the following additional limitations:

 

•

except as provided by operation of law, the partnership will recognize the transfer of only one or more whole units unless you own less than a whole unit, in which case your entire fractional interest must be transferred;

 

•

the costs and expenses associated with the transfer must be paid by you;

 

•

the transfer documents must be in a form satisfactory to the managing general partner; and

 

•

the terms of the transfer must not contravene those of the partnership agreement.

Your transfer of a unit will not:

 

•

relieve you of your responsibility for any obligations related to your units under the partnership agreement;

 

•

grant rights under the partnership agreement, as among your transferees, to more than one party unanimously designated by the transferees to the managing general partner; nor

 

•

require an accounting of the partnership by the managing general partner.

If the assignee of the unit does not become a substituted partner as described below in “- Conditions to Becoming a Substitute Partner,” the transfer will be effective as of midnight of the last day of the calendar month in which it is made.

Conditions to Becoming a Substitute Partner

An assignee of a unit will not be entitled to any of the rights granted to a partner under the partnership agreement, other than the right to receive all or part of the share of the profits, losses, income, gain, credits and cash distributions or returns of capital to which his assignor would otherwise be entitled, unless the assignee becomes a substituted partner in accordance with the provisions set forth below. The conditions to become a substitute partner are as follows:

 

•

the assignor gives the assignee the right;

 

•

the assignee pays all costs and expenses incurred in connection with the substitution; and

 

•

the assignee executes and delivers, in a form acceptable to the managing general partner, the instruments necessary to establish that a legal transfer has taken place and to confirm his agreement to be bound by all of the terms and provisions of the partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned units. The partnership will amend its records at least once each calendar quarter to effect the substitution of substituted partners.

 

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PLAN OF DISTRIBUTION

Commissions

The units in your partnership will be offered on a “best efforts” basis by MDS Securities, LLC (“MDS Securities”), an affiliate of the managing general partner, acting as dealer-manager, and other broker/dealers that are selected by the dealer-manager and are members of the Financial Industry Regulatory Authority, Inc. (“FINRA”), acting as selling dealers. Best efforts generally means that the dealer-manager and the selling dealers will not guarantee that a certain number of units will be sold. MDS Securities was formed for the purpose of serving as dealer-manager of partnership offerings sponsored by the managing general partner. MDS Securities will become a FINRA member firm before the effective date of the Registration Statement of which this prospectus is a part, or this prospectus will be amended to remove MDS Securities as the dealer-manager of this offering.

Units may also be sold by the officers and directors of the managing general partner, other than those individuals who are associated persons of MDS Securities, in those states where they are licensed to do so or are exempt from licensing. All offers and sales of units by the managing general partner’s officers and directors who are not associated persons of MDS Securities will be made under the SEC safe harbor from broker/dealer registration provided by Rule 3a4-1. In this regard, none of the officers and directors of the managing general partner who may offer and sell units:

 

•

is subject to a statutory disqualification, as that term is defined in Section 3(a)(39) of the Act, at the time of his participation;

 

•

is compensated in connection with his participation by the payment of commissions or other remuneration based either directly or indirectly on transactions in securities; and

 

•

is at the time of his participation an associated person of a broker or dealer.

Also, each of the officers and directors who may offer and sell units:

 

•

performs, or is intended primarily to perform at the end of the offering, substantial duties for or on behalf of the managing general partner otherwise than in connection with transactions in securities;

 

•

was not a broker or dealer, or an associated person of a broker or dealer, within the preceding 12 months; and

 

•

will not participate in selling an offering of securities for any issuer more than once every 12 months, with the understanding that for securities issued pursuant to Rule 415 under Securities Act of 1933, the 12 month period begins with the last sale of any security included within one Rule 415 registration.

Except as provided below, MDS Securities will receive sales commissions of 7.0% of the gross offering proceeds for units sold in this offering and, as the dealer-manager, it will receive 3.0% of the gross offering proceeds as compensation for acting as the dealer-manager. Reduced sales commissions will be paid with respect to certain volume discount sales as discussed below, and the partnerships will not pay any sales commissions or dealer-manager fees for units sold under their friends and family program described below. Except as provided below, the dealer-manager will re-allow all of its 7.0% sales commissions attributable to a selling dealer.

The partnerships may also sell units at a discount to the offering price of $10,000 per unit through the following distribution channels in the event that the investor:

 

•

pays a broker a single fee, e.g., a percentage of assets under management, for investment advisory and broker services, which is frequently referred to as a “wrap fee”;

 

•

engages the services of a registered investment advisor with whom the investor has agreed to pay compensation for investment advisory or other financial services, other than a registered investment advisor that is also registered as a broker dealer who does not have a wrap fee or similar arrangement with the investor; or

 

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•

invests through a bank acting as trustee or fiduciary.

If you purchase units through one of the distribution channels described above, the units will be sold at a 7.0% discount, or at $9,300 per unit, reflecting that sales commissions are not being paid in connection with your purchase. The net proceeds to the partnerships will not be affected by that reduction in sales commissions. Neither the dealer-manager nor its affiliates will compensate any person engaged as an investment advisor by any potential investor as an inducement for such investment advisor to advise favorably for an investment in a partnership.

The dealer-manager will also reallow to the selling dealers from its 3.0% dealer-manager fee an additional .5% sales commission on the first 100 units in each partnership sold by the selling dealers. The dealer-manager may also re-allow a .5% nonaccountable marketing fee from its dealer-manager fee to a selling dealer, which may be reduced for the dealer-manager’s or managing general partner’s costs to participate in the selling dealer’s national or regional conferences, based on such factors as:

 

•

the volume of sales estimated to be made by the selling dealer; or

 

•

the selling dealer’s agreement to provide one or more of the following services:

 

•

providing internal marketing support personnel and marketing communications vehicles to assist the dealer-manager in promoting the sale of the units;

 

•

responding to investors’ inquiries concerning monthly statements, valuations, distribution rates, tax information, annual reports, repurchase rights and procedures, a partnership’s financial status and the wells it has drilled;

 

•

assisting investors with repurchases of their units; or

 

•

providing other services requested by investors from time to time and maintaining the technology necessary to adequately service investors.

In addition, MDS Securities may reimburse certain of the selling dealers for:

 

•

technology costs; and

 

•

other costs and expenses associated with this offering, the facilitation of the marketing of the units and the ownership of the units by the selling dealers’ customers.

These costs will be paid out of the dealer-manager fee. There is a possibility that these reimbursements may cause the aggregate compensation paid to a particular selling dealer to exceed 10% of its sales. For a more complete discussion of all compensation and fees paid in connection with this offering, see “Compensation.”

MDS Securities, as dealer-manager, will provide services to the partnerships, which will include conducting broker-dealer seminars, holding informational meetings and providing information and answering any questions concerning this offering. The partnerships pay MDS Securities a dealer-manager fee of 3.0% of the gross offering proceeds. In addition to re-allowing a portion of the dealer-manager fee as a marketing fee to certain selling dealers, the dealer-manager fee will also be used for certain costs that are viewed by FINRA as included in the 10% underwriting compensation limit discussed below, such as the cost of the following activities:

 

•

travel and entertainment expenses;

 

•

compensation of the managing general partner’s employees who are also licensed registered representatives of MDS Securities in connection with wholesaling activities;

 

•

expenses incurred in coordinating broker-dealer seminars and meetings;

 

•

wholesaling expense reimbursements paid by MDS Securities or its affiliates to other entities;

 

•

the national and regional sales conferences of the selling dealers;

 

•

training and education meetings for registered representatives of the selling dealers; and

 

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•

permissible forms of non-cash compensation to registered representatives of the selling dealers, such as logo apparel items and gifts that do not exceed an aggregate value of $100 per annum per registered representative and that are not pre-conditioned on achievement of a sales target. These gifts would include, but not be limited to, seasonal gifts.

The maximum amount of all items of compensation the partnerships may pay to MDS Securities and the selling dealers is set forth in the table below. This table assumes that all units are sold through distribution channels associated with the highest possible sales commissions and dealer-manager fees.

Dealer-Manager and Selling Dealer Compensation

 

		Maximum Aggregate
Sales Commissions (maximum)		$	21,000,000
Dealer-manager fees (maximum)			9,000,000
Total		$	30,000,000

The partnerships will also reimburse the dealer-manager for payments it may make to broker-dealers for reasonable bona fide due diligence expenses incurred which are supported by a detailed and itemized invoice. These reimbursements are subject to the limitations on organization and offering expenses described below.

The offering will be made in compliance with FINRA Rule 2310 and all compensation, including non-cash compensation, to broker/dealers and wholesalers, regardless of the source, will not exceed 10% of the gross proceeds of the offering. MDS Securities and the partnerships will monitor the payment of all fees and expense reimbursements to assure that this 10% underwriting compensation limit is not exceeded. The dealer-manager will reimburse the partnerships for any underwriting compensation in excess of FINRA’s 10% underwriting compensation limit in the event this offering is abruptly terminated before reaching the maximum offering amount. Also, this offering will be made in compliance with FINRA Rule 2310(b)(2)(C) and the broker/dealers and wholesalers will not execute a transaction for the purchase of units in a discretionary account without the prior written approval of the transaction by the customer. Finally, the offering will be conducted in compliance with SEC Rule 15c2-4.

In addition to the 10% underwriting compensation limit, FINRA and many states also limit the total organizational and offering expenses, including sales commissions and the dealer-manager fee, that the partnerships may incur to 15% of their gross offering proceeds. Under the partnership agreement, all organizational and offering expenses, including sales commissions and the dealer-manager fee, will be charged to the managing general partner, which will not receive any credit towards its required capital contribution or revenue interest in the partnerships for any organization and offering costs it pays in excess of 15% of the partnerships’ gross offering proceeds.

Certain of the selling dealers and their affiliates may have from time to time provided, and may in the future provide, general financing, banking and advisory services to the managing general partner and its affiliates for customary fees. In addition, certain of the selling dealers and their affiliates may also provide general financing and banking services to the partnerships for customary fees.

 

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Each partnership will offer a reduced unit purchase price in the offering to single purchasers on orders of more than $500,000 made through the same selling dealer, which are referred to in this prospectus as “volume discounts.” Sales commissions paid to MDS Securities and the selling dealers will be reduced by the amount of the discount. The unit purchase price will be reduced for each incremental unit purchased in the total volume ranges set forth in the table below.

 

Dollar Volume of Units Purchased For A “Single” Purchaser		Selling Commission For Incremental Unit in Volume Discount Range				Purchase Price Per Unit to Investors
$1,000 – $500,000			7.0	%		$	10,000
500,001 – 1,000,000			6.0	%			9,900
1,000,001 – 2,000,000			5.0	%			9,800
2,000,001 – 3,000,000			4.0	%			9,700
3,000,001 – 5,000,000			3.0	%			9,600

Sales commissions for purchases of more than $5 million are negotiable. Sales commissions paid will in all cases be the same for the same level of sales and once a price is negotiated with the initial purchaser this will be the price for all purchases at that volume. In the event of a sale of more than $5 million, this prospectus will be supplemented to include:

 

•

the aggregate amount of the sale;

 

•

the price per unit paid by the purchaser; and

 

•

a statement that other similar investors wishing to purchase at that volume of securities will pay the same price for that volume of securities.

For example, a single purchaser would receive 55.051 units rather than 55 units for an investment of $550,000 and the selling commission would be $38,030. The discount would be calculated as follows: On the first $500,000 of the investment there would be no discount and the purchaser would receive 50 units at $10,000 per unit. On the remaining $50,000, the per unit price would be $9,900 and the purchaser would receive 5.051 units.

For purposes of determining investors eligible for volume discounts, investments made by accounts with the same primary account holder, as determined by the account tax identification number, may be combined. This includes individual accounts and joint accounts that have the same primary holder as any individual account.

An investor may request a volume discount by checking the appropriate box and providing therequired information in his or her subscription agreement. To the extent an investor qualified for a volume discount on a particular purchase, any subsequent purchase, regardless of the number of units subscribed for in that purchase, will also qualify for that volume discount or, to the extent the subsequent purchase when aggregated with the prior purchase(s) qualifies for a greater volume discount, the greater discount. For example, if an initial purchase is for $450,000, and a second purchase is for $80,000, then the first $50,000 of the second purchase will be priced at $10,000 per unit and the remaining $30,000 of the second purchase will be priced at $9,900 per unit. Any request to treat a subsequent purchase cumulatively for purposes of the volume discount must be made in writing and will be subject to verification by the partnership or the dealer-manager that all of the orders were made by a single purchaser.

In the event orders are combined, the commission payable with respect to the subsequent purchase of units will equal the commission per unit that would have been payable in accordance with the commission schedule set forth above if all purchases had been made simultaneously. Any reduction of the 7.0% selling commission otherwise payable to MDS Securities or a selling dealer if the full purchase price of $10,000 per unit was paid will be credited to the purchaser as additional full or fractional units. Unless investors indicate that orders are to be combined and provide all other requested information, a partnership cannot be held responsible for failing to combine orders properly.

 

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The volume discount will be prorated among the separate accounts considered to be a single purchaser. The amount of total commissions thus computed will be apportioned pro rata among the individual orders on the basis of the respective amounts of the orders being combined.

For purposes of distributions, all investors will be deemed to have contributed the same amount per unit to their partnership whether or not the investor receives a discount. Accordingly, investors who pay reduced sales commissions will receive higher returns on their investments in a partnership as compared to investors who do not pay reduced sales commissions.

California residents should be aware that volume discounts will not be available in connection with the sale of units to California residents to the extent the discounts do not comply with the provisions of Rule 260.140.51 adopted pursuant to the California Corporate Securities Law of 1968. Pursuant to this rule, volume discounts can be made available to California residents only in accordance with the following conditions:

 

•

there can be no variance in the net proceeds to a partnership from the sale of the units to different purchasers of the same offering;

 

•

all purchasers of the units must be informed of the availability of quantity discounts;

 

•

the same volume discounts must be allowed to all purchasers of units which are part of the offering;

 

•

the minimum amount of units as to which volume discounts are allowed cannot be less than $10,000;

 

•

the variance in the price of the units must result solely from a different range of commissions, and all discounts must be based on a uniform scale of commissions; and

 

•

no discounts are allowed to any group of purchasers.

Accordingly, volume discounts for California residents will be available in accordance with the foregoing table of uniform discount levels based on dollar volume of units purchased, but no discounts are allowed to any group of purchasers, and no subscriptions may be aggregated as part of a combined order for purposes of determining the number of units purchased.

Units may also be sold directly from the partnerships at the following discounts:

 

•

to selling dealers, their representatives and employees, and registered investment advisors and their representatives, at a purchase price of $9,300 per unit, which is net of the sales commissions; and

 

•

to the managing general partner and its affiliates and their officers, directors and family members, as defined below, at a purchase price of $9,000 per unit, which is net of all sales commissions and the dealer-manager fee. For purposes of this discount, the partnerships consider a family member to be a spouse, parent, child, sibling, cousin, mother- or father-in-law, son- or daughter-in-law or brother- or sister-in-law.

No more than 5% of each partnership’s outstanding units, in the aggregate, may be sold at the discounted prices discussed above, but there is no limitation on the number of units that may be sold at the volume discounts discussed above. Additionally, all purchasers of units at a discounted price will be expected to hold the units they purchase for investment and not with a view towards distribution. The net offering proceeds a partnership receives will not be affected by the reduced sales price of discounted units.

The managing general partner is also using the services of wholesalers who are employed by the managing general partner and are licensed with FINRA through MDS Securities. In addition to the wholesalers’ salaries and expense reimbursements as discussed above, 1% of the 3% dealer-manager fee will be reallowed by the dealer-manager to the affiliated wholesalers on all units sold in this offering and on which the dealer-manager fee is paid. The dealer-manager will retain the remainder of the dealer-manager fee not reallowed to the wholesalers or the selling dealers as described above.

 

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After the minimum subscription proceeds are received by the partnership and the checks have cleared the banking system, the dealer-manager fees and sales commissions may be paid to the dealer-manager and the selling dealers approximately every two weeks until the offering closes.

Indemnification

The dealer-manager is an underwriter as that term is defined in the 1933 Act and the sales commissions and dealer-manager fees will be deemed underwriting compensation. The managing general partner and the dealer-manager have agreed to indemnify each other, and it is anticipated that the dealer-manager and each selling dealer will agree to indemnify each other against certain liabilities, including liabilities under the Securities Act of 1933.

 

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SALES MATERIAL

In addition to the prospectus, the managing general partner intends to use the following sales material with the offering of the units:

 

•

a brochure entitled “MDS Energy Public 2012 Program”;

 

•

a term sheet entitled “MDS Energy Public 2012 Program;

 

•

a brochure entitled “MDS Energy Public 2012 Program – Tax Tips”;

 

•

a powerpoint presentation entitled “MDS Energy Public 2012 Program”; and

 

•

possibly other supplementary materials.

The managing general partner has not authorized the use of other sales material and the offering of units is made only by means of this prospectus. The sales material is subject to the following considerations:

 

•

it must be preceded or accompanied by this prospectus;

 

•

it is not complete;

 

•

it does not contain any information which is inconsistent with this prospectus; and

 

•

it should not be considered a part of or incorporated into this prospectus or the registration statement of which this prospectus is a part.

In addition, supplementary materials, including prepared presentations for group meetings, must be submitted to the state administrators before they are used and their use must either be preceded by or accompanied by a prospectus. Also, all advertisements of, and oral or written invitations to, “seminars” or other group meetings at which the units are to be described, offered, or sold will clearly indicate the following:

 

•

that the purpose of the meeting is to offer the units for sale;

 

•

the minimum purchase price of the units;

 

•

the suitability standards to be employed; and

 

•

the name of the person selling the units.

Also, no cash, merchandise, or other items of value may be offered as an inducement to you or any other prospective investor to attend the meeting. All written or prepared audiovisual presentations, including scripts prepared in advance for oral presentations to be made at the meetings, must be submitted to the state administrators within a prescribed review period. These provisions, however, will not apply to meetings consisting only of the registered representatives of the selling agents.

You should rely only on the information contained in this prospectus in making your investment decision. No one is authorized to provide you with information that is different.

 

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LEGAL OPINIONS

Kunzman & Bollinger, Inc. has issued its opinion on the material and any significant federal tax issues involving individual typical investors in the partnerships. However, the factual statements in this prospectus are those of the partnerships or the managing general partner, and counsel has not given any opinions with respect to any of the tax or other legal aspects of this offering except as expressly set forth above.

EXPERTS

The consolidated financial statements for MDS Energy Development, LLC, the managing general partner, and the balance sheet for MDS Energy Public 2012-A LP have been included in this registration statement and related prospectus in reliance upon the reports of Schneider Downs & Co., Inc., registered independent public accountants, given on their authority as experts in accounting and auditing.

LITIGATION

The managing general partner knows of no litigation pending or threatened to which it or the partnerships are subject or may be a party that it believes would have a material adverse effect on the partnerships or their business, and no such proceedings are known to be contemplated by governmental authorities or other parties.

 

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FINANCIAL INFORMATION CONCERNING THE MANAGING

GENERAL PARTNER AND MDS ENERGY PUBLIC 2012-A LP

Financial information concerning the managing general partner and MDS Energy Public 2012-A LP is reflected in the following financial statements.

The securities offered by this prospectus are not securities of, nor are you acquiring an interest in the managing general partner, its affiliates, or any other entity other than MDS Energy Public 2012-A LP or any other partnership.

INDEX TO FINANCIAL STATEMENTS

 

MDS ENERGY PUBLIC 2012-A LP FINANCIAL STATEMENTS
Independent Auditors’ Report			F-1
Balance Sheet as of May 18, 2012			F-2
Notes to Balance Sheet dated May 18, 2012			F-3
MDS ENERGY DEVELOPMENT, LLC FINANCIAL STATEMENTS (AUDITED)
Independent Auditors’ Report			F-7
Consolidated Balance Sheets as of December 31, 2011 and May 31, 2011 (As Restated)			F-8
Consolidated Statement of Operations for the Period June 1, 2011 to December 31, 2011			F-9
Consolidated Statement of Member’s Equity for the Period June 1, 2011 to December 31, 2011			F-10
Consolidated Statement of Cash Flows for the Period June 1, 2011 to December 31, 2011			F-11
Notes to Consolidated Balance Sheet dated December 31, 2011 and May 31, 2011			F-12

 

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MDS ENERGY PUBLIC 2012-A LP

FINANCIAL STATEMENTS

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners

MDS Energy Public 2012-A LP

Kittanning, Pennsylvania

We have audited the accompanying balance sheet of MDS Energy Public 2012-A LP (Partnership) as of May 18, 2012. This balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform our audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of MDS Energy Public 2012-A LP as of May 18, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ SCHNEIDER DOWNS & CO., INC.

Pittsburgh, Pennsylvania

May 25, 2012

 

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MDS ENERGY PUBLIC 2012-A LP

BALANCE SHEET

MAY 18, 2012

 

ASSETS
CASH AND CASH EQUIVALENTS		$	100
PARTNERS’ EQUITY
PARTNERS’ EQUITY		$	100

See notes to balance sheet.

 

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MDS ENERGY PUBLIC 2012-A LP

NOTES TO BALANCE SHEET

MAY 18, 2012

NOTE 1 - ORGANIZATION AND NATURE OF OPERATIONS

On May 1, 2012 (date of inception), MDS Energy Public 2012-A LP (Partnership), a Delaware limited partnership, was formed for the purpose of drilling developmental natural gas and oil wells. The Partnership has a maximum 50-year term, although the Partnership intends to terminate when all of the wells invested in by the Partnership become uneconomical to continue to operate, which may be approximately 15 years or longer. The Partnership was formed by MDS Energy Development, LLC (MDS), a related party, as the managing general partner and M/D Gas, Inc (M/D), a related party, as the sole limited partner. In accordance with the terms of the limited partnership agreement, the managing general partner is authorized to manage all activities of the Partnership and initiates and completes substantially all transactions.

The Partnership intends to solicit potential investors with a registration statement (offering) on a “best efforts” basis. The Partnership intends to sell between 200 and 30,000 general and/or limited partner units at a price of $10,000 per unit. The proceeds from the offering will be used to cover intangible drilling costs and equipment associated with the drilling of developmental natural gas and oil wells in the Marcellus Shale formation in Pennsylvania. Upon raising a minimum of $2,000,000, the holders of the units will be admitted and the Partnership will commence operations.

General partner units will be automatically converted by the Partnership to limited partner units upon the drilling and completion of all of the Partnership’s wells. A well is deemed to be completed when production equipment is installed, even though the well may not yet be connected to a pipeline for production of oil or natural gas.

The Partnership’s fiscal year ends on December 31.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of significant accounting policies consistently applied by management in the preparation of the accompanying balance sheet follows:

Use of Estimates - The preparation of the balance sheet in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the balance sheet and accompanying notes. Actual results could differ from those estimates. Estimates that are particularly significant to the balance sheet include estimates of natural gas and oil revenue, natural gas and oil reserves and future cash flows from natural gas and oil properties.

Cash and Cash Equivalents - The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Partnership maintains substantially all of its cash and cash equivalents in one bank account at one financial institution, which at times may exceed insured limits. The Partnership has not experienced losses in any such accounts to date and limits the Partnership’s exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.

Deferred Charges - The costs of organizing the Partnership and offering the units are capitalized by the Partnership and amortized over the estimated offering period, which period will not exceed two years from the effective date of the offering. Following the effective date of the offering, the unamortized balance of these costs will be reflected in the balance sheet as deferred charges, net. Organizational and offering costs include (i) the dealer manager fee, (ii) sales commissions and (iii) other costs related to the organization of the Partnership and the offering of the Units.

 

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MDS ENERGY PUBLIC 2012-A LP

NOTES TO BALANCE SHEET

MAY 18, 2012

 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Oil and Gas Properties - The Partnership will use the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip wells will be capitalized. Depreciation and depletion will be computed on a field-by-field basis by the unit-of-production method based on periodic estimates of oil and gas reserves. Undeveloped leaseholds and proved properties will be assessed periodically or whenever events or circumstances indicate that the carrying amount of these assets may not be recoverable. Proved properties will be assessed based on estimates of future cash flows.

Production Revenues - The managing general partner and the investors in the Partnership will share in all of the Partnership’s production revenues in the same percentage as their respective capital contribution bears to the Partnership’s total net capital contributions, except that the managing general partner will receive an additional 8% of the Partnership’s production revenues.

Proceeds from the Sale of Wells/Leases - If a well is sold, the portion of the sales proceeds allocated to the Partnership will be allocated among the managing general partner and the investors in the Partnership generally in accordance with the sharing ratio utilized for the allocation of production revenues.

Equipment Proceeds - Proceeds from the sale or other disposition of equipment used to drill and complete the Partnership’s wells will be credited to the managing general partner and the investors in the Partnership in accordance with the sharing ratio utilized for the allocation of production revenues.

Income Taxes - Since the taxable income or loss of the Partnership is reported in the separate tax returns of the individual partners, no provision has been made for income taxes by the Partnership.

Accounting for uncertainty in income taxes requires financial statement recognition, measurement and disclosure of uncertain tax positions recognized in an enterprise’s financial statements. Under this guidance, income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the standard. The Partnership did not have any unrecognized tax benefits and there was no effect on its financial condition or results of operations as a result of implementing this standard. When necessary, the Partnership would accrue penalties and interest related to unrecognized tax benefits as a component of income tax expense. The Partnership will file a U.S. federal income tax return, but income will be passed through to the partners.

Subsequent Events - Subsequent events are defined as events or transactions that occur after the balance sheet date, but before the balance sheet is issued or is available to be issued. Management has evaluated subsequent events through May 25, 2012, the date on which the balance sheet was available to be issued.

 

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MDS ENERGY PUBLIC 2012-A LP

NOTES TO BALANCE SHEET

MAY 18, 2012

 

NOTE 3 - PARTICIPATION IN COSTS AND REVENUES

The following table sets forth how the Partnership’s costs and revenues will be charged and credited between the managing general partner and investors in the Partnership, after deducting from the Partnership’s gross revenues the landowner royalties and any other lease burdens. Some of the line items in the table do not have percentages stated, because the percentages will be determined either by the actual costs incurred by the Partnership to drill and complete its wells or by the final amount of the managing general partner’s capital contribution to the Partnership, which will not be known until after all of the Partnership’s wells have been drilled and completed.

 

		Managing General Partner				Units issued by the Partnership
Partnership Costs
Organizational and offering costs			100	%			0	%
Lease costs			100	%			0	%
Intangible drilling costs (1)			0	%			100	%
Equipment costs (2)			0	%			100	%
Operating, administrative, direct and all other costs				(3)				(3)
Partnership Revenues
Interest income on subscription proceeds (4)			0	%			100	%
Equipment proceeds (2)			0	%			100	%
All other revenues including production revenues and other interest income				(4)(5)(6)				(4)(5)(6)

 

(1)	The subscription proceeds of investors in the Partnership will be used to pay 100% of the intangible drilling costs incurred by the Partnership in drilling and completing its wells.

(2)	The subscription proceeds of investors in the Partnership will be used to pay 100% of the equipment costs incurred by the Partnership in drilling and completing its wells. Equipment proceeds, if any, and depreciation will also be allocated 100% to investors in the Partnership.

(3)	These costs, which will also include plugging and abandonment costs of the wells after the wells have been drilled, produced and depleted, will be charged to the parties in the same ratio as the related production revenues being credited.

(4)

The subscription proceeds will earn interest until the escrow account is broken and they are paid to the Partnership. This interest will be credited to the investors’ account and paid no later than the Partnership’s first cash distribution from operations. All other interest income, including interest earned on the deposit of operating revenues, will be credited as natural gas and oil production revenues are credited.

(5)

The managing general partner and the investors will share in all of the Partnership’s other revenues in the same percentage that their respective capital contributions bear to the Partnership’s total capital contributions, except that the managing general partner will receive an additional 8% of the Partnership’s revenues.

(6)	If a portion of the managing general partner’s Partnership net production revenue is subordinated, then the actual allocation of Partnership net production revenues between the managing general partner and the investors will vary from the allocation described in (5) above.

 

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MDS ENERGY PUBLIC 2012-A LP

NOTES TO BALANCE SHEET

MAY 18, 2012

 

NOTE 4 - PARTNERS’ EQUITY

M/D made an initial contribution of $100 and was admitted as a limited partner.

A unit in the Partnership represents the individual interest of an investor partner in the Partnership. Transfers and assignments of units are restricted. Furthermore, beginning five years after the offering terminates, investor partners may request that the managing general partner repurchase units provided certain conditions are met.

The managing general partner and other partners share in partnership revenues in the same percentage as capital contributions except that the managing general partner is entitled to receive an additional 8% of partnership revenues.

The partnership agreement provides that the managing general partner shall review the accounts of the partnership at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any.

The partnership agreement provides for the enhancement of investor cash distributions if the Partnership does not meet a performance standard defined in the agreement during the first 8 years of operations beginning the earlier of the first full year of operation after all wells begin production or twelve months after the final closing of the Partnership. In general, if the cumulative distributions to the investors is less than 10% of their subscriptions for years 1 through 5; and 7.5% of their subscriptions for years 6 through 8, the managing general partner will subordinate up to 60% of its share, as managing general partner, of partnership net production revenues.

The managing general partner is responsible for lease costs and 100% of the organization and offering costs and will not receive a credit to its capital account for any organizational and offering costs incurred in excess of 15% of the subscription proceeds.

NOTE 5 - RELATED-PARTY ACTIVITIES

The managing general partner will also receive a fully-accountable, reimbursement for actual administrative costs. In its capacity as operator of the wells, the managing general partner will also receive reimbursement for direct costs, well supervision fees and fees for gas gathering services and any other services it provides, at competitive rates.

MDS, through entities under common ownership, will perform drilling, administrative, gathering, transportation, well services and gas marketing for the Partnership and will be paid at competitive rates for these services.

 

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MDS ENERGY DEVELOPMENT, LLC

FINANCIAL STATEMENTS

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Table of Contents

[The Independent Registered Public Accounting Firm Report will be provided in a subsequent amendment.]

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

 

		December 31, 2011				May 31, 2011 (As Restated)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	20,540			$	100,200
Accounts receivable			52,758				—
Prepaid expenses			68,298				—
Total Current Assets			141,596				100,200
NATURAL GAS PROPERTIES, successful efforts method, at cost			476,269				476,269
Less: Accumulated depreciation, depletion and amortization			(149,958	)			(115,190	)
			326,311				361,079
OTHER ASSETS
Partnership interests			2,630,405				2,783,076
Investment towards partnership interest			465,000				—
			3,095,405				2,783,076
		$	3,563,312			$	3,244,355
LIABILITIES
CURRENT LIABILITIES
Line of Credit		$	150,000				—
Accounts payable			47,778			$	138,280
Accrued expenses			232,978				—
Total Current Liabilities			430,756				138,280
ASSET RETIREMENT OBLIGATIONS			145,768				143,540
MEMBER’S EQUITY
MEMBER’S EQUITY			2,986,788				2,962,435
NON-CONTROLLING INTEREST			—				100
			2,986,788				2,962,535
		$	3,563,312			$	3,244,355

See notes to consolidated financial statements.

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE PERIOD JUNE 1, 2011 TO DECEMBER 31, 2011

 

Natural Gas Sales		$	128,658
Operating Costs and Expenses
Natural gas production costs			8,281
Depreciation, depletion and amortization			34,768
Accretion of asset retirement obligations			2,228
General and administrative			7,070
			52,347
Income from Operations			76,311
Loss from Partnership Interests			(41,958	)
Net Income		$	34,353

See notes to consolidated financial statements.

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

CONSOLIDATED STATEMENT OF MEMBER’S EQUITY

FOR THE PERIOD JUNE 1, 2011 TO DECEMBER 31, 2011

 

		Member’s Equity				Non-Controlling Equity				Total
Member’s Equity May 31, 2011, as restated		$	2,962,435			$	100			$	2,962,535
Dissolution of subsidiary (see Note 1)			—				(100	)			(100	)
Net income			34,353				—				34,353
Distributions			(10,000	)			—				(10,000	)
Member’s Equity December 31, 2011		$	2,986,788				—			$	2,986,788

See notes to consolidated financial statements.

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE PERIOD JUNE 1, 2011 TO DECEMBER 31, 2011

 

CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	34,353
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			36,996
Loss from partnership interests			41,958
Changes in assets and liabilities:
Accounts receivable			(52,758	)
Prepaid expenses			(68,298	)
Accounts payable			(90,502	)
Accrued expenses			232,978
Net Cash Provided By Operating Activities			134,727
CASH FLOWS FROM INVESTING ACTIVITIES
Distributions from equity interests			110,713
Investment towards partnership interest			(465,000	)
Net Cash (Used In) Investing Activities			(354,287	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from line of credit			150,000
Distributions			(10,000	)
Dissolution of subsidiary			(100	)
Net Cash Provided By Financing Activities			139,900
Net Decrease In Cash And Cash Equivalents			(79,660	)
CASH AND CASH EQUIVALENTS
Beginning of period			100,200
End of period		$	20,540

See notes to consolidated financial statements.

 

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011 AND MAY 31, 2011

NOTE 1 – ORGANIZATION AND NATURE OF OPERATIONS

On February 3, 2011 (date of inception), MDS Energy Development, LLC (MDS) was formed for the purpose of the exploration and production of natural gas and oil primarily in Pennsylvania through its own natural gas and oil assets as well as investment as a general partner in other entities. MDS is organized under the Pennsylvania Limited Liability Company Act and shall continue in existence indefinitely, unless dissolved or terminated by statute or by any provision of its operating agreement. On May 31, 2011, the sole member of MDS, MDS Associated Companies, Inc. (MDS Associated Companies) contributed cash, royalty interests, overriding royalty interests, working natural gas wells and interests in four natural gas exploration and production partnerships. Effective June 1, 2011, MDS began to recognize revenues and costs associated with these assets.

In 2011, MDS was the managing general partner of a limited partnership, MDS Well Development 2011, LP (MDS 2011), that was formed for the purpose of drilling developmental natural gas wells. However, this limited partnership had no activity beyond the $100 capital contributions and was dissolved in December 2011.

In January 2012, MDS 2012 – Marcellus Shale Development, LP (MDS Marcellus) was formed as a Delaware limited liability partnership, for the prpose of drilling natural gas and oil wells. MDS Marcellus was formed with MDS as the managing general partner and M/D Gas, Inc. (M/D) as the limited partner. MDS Marcellus intends to solicit potential investors with private placement memorandum (PPM). The proceeds from the PPM will be used to cover intangible drilling costs and equipment associated with the drilling of developmental natural gas and oil wells in the Marcellus Shale formation in Pennsylvania and, in the managing general partner’s discretion, developmental oil wells in the Upper Devonian Sands in Pennsylvania. MDS may be removed as the managing general partner at any time by the affirmative vote of holders of a majority of the units in MDS Marcellus.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of significant accounting policies consistently applied by management in the preparation of the accompanying consolidated financial statements follows:

Principles of Consolidation – The accompanying consolidated financial statements include the accounts of MDS Energy Development, LLC and MDS 2011 (collectively the Company). However, MDS 2011’s sole activity during the period from June 1, 2011 through December 31, 2011 was its dissolution. All intercompany transactions and account balances have been eliminated in consolidation.

Use of Estimates – The preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates that are particularly significant to the consolidated financial statements include estimates of natural gas and oil revenue, natural gas and oil reserves and future cash flows from natural gas and oil properties.

Cash and Cash Equivalents – The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains substantially all of its cash and cash equivalents in two bank accounts at one financial institution, which at times may exceed insured limits. The Company has not experienced losses in any such accounts to date and limits the Company’s exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011 AND MAY 31, 2011

 

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Accounts Receivable and Allowance for Doubtful Accounts – The Company recognizes revenue and accounts receivable from purchasers of natural gas. The Company sells substantially all of its natural gas to a related party that manages production and market fluctuations in prices for other related producers and third parties. As of December 31, 2011, MDS did not record an allowance for doubtful accounts. In making the estimate for receivables that are uncollectible, MDS considers, among other things, historical write-offs and overall creditworthiness of customers. It is reasonably possible that the MDS’s estimate of uncollectible receivables will change periodically. MDS did not incur any losses on accounts receivable for the period from June 1, 2011 through December 31, 2011.

Natural Gas Properties – The Company accounts for its natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. The Company calculates deprecation, depletion and amortization (DD&A) expense by using as the denominator the Company’s estimated period-end reserves adjusted to add-back current period production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. The Company does not maintain an inventory of undrilled leases.

Proved Reserves – Company estimates of proved reserves are based on those quantities of natural gas by analysis of geosciences and engineering data that are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Company engages independent petroleum engineers to prepare a reserve and economic evaluation of the properties on a field by field basis. Additionally, the Company adjusts reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property can also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Company’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Company’s depreciation, depletion and amortization expense, a change in the Company’s estimated reserves could have an effect on the Company’s net income and natural gas properties.

Proved Property Impairment – The Company assesses its producing natural gas properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Company reasonably estimates the commodities to be sold. The estimates of future prices might differ from current market prices of natural gas. Certain events, including, but not limited to, downward revisions in estimates to the Company’s reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Company’s proved natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011 AND MAY 31, 2011

 

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

or inputs, and is measured by the amount by which the net capitalized costs exceed their fair value. Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows are determined utilizing a risk-adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas reserves. The Company reviewed its proved natural gas properties for impairment at December 31, 2011 and concluded that no impairments existed.

Partnership Interests – Partnership companies that are not consolidated, but over which the Company exercises significant influence, are accounted for under the equity method of accounting. Whether or not the Company exercises significant influence with respect to an investee depends on an evaluation of several factors, including, among others, representation on the investee company’s board of directors and ownership level, which is generally a 20% to 50% interest in the voting securities of the investee company. Under the equity method of accounting, an investee company’s accounts are not reflected within the Company’s consolidated financial statements; however, the Company’s share of the earnings or losses of the investee company is reflected in the caption “Loss from partnership interests” in the consolidated statement of operations. The Company’s carrying value in an equity method investee company is reflected in the caption “Partnership Interests” in the Company’s consolidated balance sheets.

MDS capitalizes organization and offering costs incurred in its role as managing general partner when those costs will be converted to partnership interests in a subsequent period upon finalization of the corresponding partnership. These costs are reflected in the caption “Investment towards Partnership Interests” in the Company’s consolidated balance sheets.

Production Tax Liability – Production tax liabilities represents estimated taxes, primarily ad valorem and property, to be paid to the states and counties in which the Company produces natural gas and crude oil. The Company’s share of these taxes will be expensed and included in natural gas production costs on the Company’s consolidated statements of operations. The Company’s production taxes payable will be included in the caption accounts payable on the Company’s consolidated balance sheets.

Income Taxes – The taxable income or loss of the Company will be reported on a consolidated tax return with its parent and therefore, no provision has been made for income taxes by the Company.

Accounting for uncertainty in income taxes requires financial statement recognition, measurement and disclosure of uncertain tax positions recognized in an enterprise’s financial statements. Under this guidance, income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the standard. The Company did not have any unrecognized tax benefits and there was no effect on its financial condition or results of operations as a result of implementing this standard. When necessary, the Company would accrue penalties and interest related to unrecognized tax benefits as a component of income tax expense.

Asset Retirement Obligations – The Company accounts for asset retirement obligations by recording the fair value of Company well plugging and abandonment obligations when incurred, which is at the time the well is spudded. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011 AND MAY 31, 2011

 

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

recorded to both the asset retirement obligation and the long-lived asset cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling retirement obligations.

Revenue Recognition – Natural gas, royalty and overriding royalty revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. The Company uses the “net-back” method of accounting for transportation arrangements of the Company’s natural gas sales. The Company sells its natural gas at the sales metering station where the Company’s flowline connects to a third-party’s or affiliate’s gathering or transmission pipeline system and recognizes revenues based on the sales price less certain gathering, compression, processing and other operating costs charged by the third-party or affiliate that transports the Company’s natural gas. Virtually all of the Company’s contract pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions.

Subsequent Events – Subsequent events are defined as events or transactions that occur after the financial statement date, but before the consolidated financial statements are issued or are available to be issued. Management has evaluated subsequent events through April 6, 2012, the date on which the consolidated financial statements are available to be issued.

NOTE 3 – COMMITMENTS AND CONTINGENCIES

Due to the nature of the natural gas and oil industry, the Company is exposed to environmental risks. The Company has various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. The Company conducts periodic reviews to identify changes in its environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. The Company is not aware of any environmental claims existing as of December 31, 2011. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Company’s properties.

NOTE 4 – LINE OF CREDIT

On June 6, 2011, MDS entered into a $1,000,000 line-of-credit agreement with a bank that matures December 31, 2012. The line requires interest at the Prime lending rate less 0.50% but at no time will go below 2.75% or above 18%. The line is secured by a one-year certificate of deposit held by the bank and pledged by a related party. At December 31, 2011, there was an outstanding balance of $150,000 on the line.

NOTE 5 – ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with MDS’s working interest in natural gas and crude oil properties.

 

Balance at May 31, 2011		$	143,540
Revisions in estimated cash flows			—
Accretion expense			2,228
Balance at December 31, 2011		$	145,768

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011 AND MAY 31, 2011

 

NOTE 5 – ASSET RETIREMENT OBLIGATIONS (Continued)

 

If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.

NOTE 6 – MEMBER’S EQUITY

On May 31, 2011, MDS Associated Companies, the sole member of MDS, contributed cash, royalty interests, overriding royalty interests, working natural gas wells and interests in four natural gas exploration and production partnerships. The assets were contributed at the sole member’s net book value. At May 31, 2011, a summary of the contributed assets consisted of the following:

 

Cash		$	100,100
Royalty and overriding royalty interest			—
Working natural gas wells, net			361,079
Partnership interests			2,783,076
Asset retirement obligations			(143,540	)
		$	3,100,715

Royalty interests contributed to MDS consists of eight well leases, seven of which began in 2007 and one of which began in 2009 with a 12.5% royalty. Overriding royalty interests contributed to MDS consists of 92 well leases that began on various dates from 2007 through 2010 with royalty rates that range from 1.125% to 4.25%. The Company began recognizing royalty revenue June 1, 2011 and is included with natural gas sales on the consolidated statement of operations.

Working natural gas wells contributed to MDS consists of eight wells with original cost of $476,269, accumulated DD&A of $115,190 and asset retirement obligations of $143,540. The Company began recognizing revenue from these natural gas wells June 1, 2011.

Partnership interests contributed to MDS consists of ownership percentages ranging from 14.07% to 21% in four drilling programs, MDS Wells 2006 LP, MDS Wells 2007 LP, MDS Wells 2008 LP and MDS Wells 2009 LP. The 2006 program consists of 14 wells, the 2007 program consists of 21 wells, the 2008 program consists of 28 wells and the 2009 program consists of 34 wells. The combined financial position of the Company’s equity basis investment in four exploration and production partnerships at December 31, 2011, is summarized below:

 

		December 31, 2011				May 31, 2011
Cash		$	336,000			$	39,000
Accounts receivable			690,000				412,000
Natural gas properties, net			16,574,000				17,953,000
Total Assets		$	17,600,000			$	18,404,000
Accounts payable and accrued expenses		$	192,000			$	115,000
Asset retirement obligations			1,700,000				1,663,000
Partnership equity			15,708,000				16,626,000
Total Liabilities And Partnership Equity		$	17,600,000			$	18,404,000
MDS’s Combined Partnership Interests		$	2,630,405			$	2,783,076

 

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MDS ENERGY DEVELOPMENT, LLC AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2011 AND MAY 31, 2011

 

NOTE 7 – RELATED-PARTY ACTIVITIES

MDS Associated Companies, the sole member of MDS, owns several natural gas and oil companies that consist of other exploration and production companies and a drilling and service company. In addition, there are other related parties through common ownership that will provide various administrative, maintenance, transportation and services to the Company. These services will be provided at competitive prices. There were no related-party services charged to the Company during the period from June 1, 2011 to December 31, 2011.

With regards to MDS Marcellus, MDS receives a credit to its capital account for organization and offering costs up to 15% of subscription proceeds, is entitled to receive a share of its revenues and reimbursement for administrative expenses and direct costs incurred in relation to its operations. Operating costs incurred by the MDS Marcellus include, among other things, legal, accounting, investor relations, operations, and geological and engineering analyses and reports. MDS’s share of MDS Marcellus’s revenues will be in the same percentage that its capital contribution bears to the total net capital contributions, plus an additional 8%. During the period June 1, 2011 through December 31, 2011, MDS capitalized its investment of $465,000 towards offering costs associated with MDS Marcellus.

The MDS Marcellus partnership agreement provides for the enhancement of investor cash distributions if the its does not meet a performance standard defined in the agreement during the first 8 years of operations beginning the earlier of the first full year of operation after all wells begin production or twelve months after the final closing of MDS Marcellus. In general, if the cumulative distributions to the investors is less than 10% of their subscriptions for years 1 through 5; and 7.5% of their subscriptions for years 6 through 8, then MDS will subordinate up to 60% of its share, as managing general partner, of MDS Marcellus’s net production revenues.

MDS will receive reimbursement for administrative costs. In its capacity as drilling contractor and operator of the wells, MDS and its affiliates will also receive reimbursement for direct costs, well supervision fees and fees gas gathering services and any other services it provides, at a competitive rate.

NOTE 8 – RESTATEMENT

Member’s equity and partnership interests as of May 31, 2011 has been increased by $457,133 to reflect the finalization of the accounting for contributions made to MDS upon its formation. This adjustment had no effect on operations for the period from June 1, 2011 through December 31, 2011. Member’s equity prior to this adjustment amounted to $2,513,984.

 

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APPENDIX A

INFORMATION REGARDING

CURRENTLY PROPOSED PROSPECTS

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INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS

The partnership does not currently hold any interests in any prospects on which the wells will be drilled, and the managing general partner has absolute discretion in determining which prospects will be acquired to be drilled. However, set forth below is information relating to certain proposed prospects in the partnership’s Marcellus Shale primary area and the wells which are currently proposed to be drilled on the prospects by MDS Energy Public 2012-A, LP. The managing general partner anticipates that one vertical well will be drilled on each development prospect, which, for purposes of this discussion, are referred to together as the “well.” Also, one or more horizontal wells, if any, may be drilled on the same well pad on which a vertical well is drilled. The managing general partner does not anticipate that the wells will be selected in the order in which they are set forth below. Also, the wells currently proposed to be drilled by the partnership when its subscription proceeds are released from escrow, and from time to time thereafter, are subject to the managing general partner’s right to:

 

•

withdraw the wells and to substitute other wells;

 

•

take a lesser working interest in the wells;

 

•

add other wells; or

 

•

any combination of the foregoing.

Any additional or substituted well may be situated in the Marcellus Shale primary area or in another area of the United States and may be either a vertical or a horizontal well, in the managing general partner’s discretion. See “Proposed Activities.”

If its targeted maximum subscription proceeds of $100 million are raised by the partnership and it takes the working interests in the wells that are set forth below in the “Lease Information,” then the managing general partner anticipates that approximately [—]% ($[—] million) of the subscription proceeds will be expended by the partnership on drilling the currently proposed wells to the Marcellus Shale.

See “Compensation – Drilling Contracts” for the partnership’s estimated average costs to drill and complete a vertical well in the Marcellus Shale primary area. The managing general partner has not proposed any other wells if:

 

•

a lesser working interest in the wells is acquired; or

 

•

other wells are substituted for the proposed wells for any of the reasons set forth below.

The managing general partner has not authorized any person to make any representations to you concerning the possible inclusion of any other wells which will be drilled by the partnership, and you should rely only on the information in this prospectus. The currently proposed wells in the partnership’s primary area will be assigned to the partnership unless there are circumstances which, in the managing general partner’s opinion, lessen the relative suitability of the wells. These considerations include:

 

•

the amount of the subscription proceeds received by the partnership;

 

•

the latest geological and production data available;

 

•

potential title or spacing problems;

 

•

the expiration dates of oil and gas leases covering the prospect on which the well is situated;

 

•

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 wells;

 

•

farmins; and

 

•

continuing review of other properties which may be available.

 

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Any substituted and/or additional wells will meet the same general criteria that the managing general partner used in selecting the currently proposed wells, and generally will be located in areas where the managing general partner or its affiliates have previously conducted drilling operations. You, however, will not have the opportunity to evaluate for yourself the relevant production and geological information for the substituted and/or additional wells.

The information regarding the currently proposed wells is intended to help you evaluate the economic potential and risks of drilling the proposed wells. This includes production information for wells in the same general area as the proposed wells, which the managing general partner believes is an important indicator in evaluating the economic potential of any well to be drilled. However, generally there is little or no production information from surrounding wells for the majority of the wells to be drilled by the partnership, which results in greater uncertainty to you and the other investors. This lack of production information may result because the managing general partner, as operator, is proposing wells to be drilled in the partnership that are adjacent to wells its affiliates have previously drilled for their own account or as operator in prior partnerships that have not yet been completed, have not yet been put on-line to sell production, or have been producing for only a short period of time so there is little or no production information available. Also, if the managing general partner was not the operator of a previously drilled well in Pennsylvania, then the production information may not be available if the well was drilled within the last five years in Pennsylvania since the Pennsylvania Department of Environmental Resources in the past has kept production data confidential for the first five years from the time a well starts producing. See “Risk Factors – Risks Related to an Investment In the Partnership – Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of the Partnership’s Drilling Program.” Additionally, wells may be proposed by the managing general partner to be drilled by the partnership for which there is no production data for other wells in the immediate area if geologic trends in the immediate area, such as sand thickness, porosities and water saturations lead the managing general partner to believe that the proposed wells also will be productive. See the production data set forth below for the Marcellus Shale primary area.

When reviewing production information, if any, for each well offsetting or in the general area of a proposed well to be drilled, you should consider the factors set forth below.

 

•

The length of time that the well has been on-line, and the time period for which production information is shown. Generally, the shorter the period for which production information is shown the less reliable the information is in predicting the ultimate recovery of reserves from a well.

 

•

Production from a well declines throughout the life of the well. The rate of decline, the “decline curve,” varies based on which geological formation is producing, and may be affected by the operation of the well. For example, each well in the Marcellus Shale geological formation will have a different rate of decline.

 

•

The greatest volume of production (“flush production”) from a well usually occurs in the early period of well operations and may indicate a greater reserve volume (generally, the ultimate amount of natural gas and oil recoverable from a well) than the well actually will produce. This period of flush production can vary depending on how the well is operated and the location of the well.

 

•

Production information for wells located close to a proposed well tends to be more relevant than production information for wells located farther away, although performance and volume of production from wells located on contiguous prospects can be much different since the geological conditions in these areas can change in a short distance.

 

•

Consistency in production among wells tends to confirm the reliability and predictability of the production information.

 

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The information set forth below is included to help you become familiar with the proposed wells.

 

•

Marcellus Shale Primary Area

 

•     Lease information				[—]
•     Location and Production Maps				[—]
•     Production data				[—]
•     Schlumberger’s geological assessment for the currently proposed wells				[—]

[The rest of this page is intentionally left blank]

 

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LEASE INFORMATION

FOR THE

MARCELLUS SHALE PRIMARY AREA

 

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LOCATION AND PRODUCTION MAPS

FOR THE

MARCELLUS SHALE PRIMARY AREA

 

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PRODUCTION TABLE OF THE GEOLOGIC EVALUATION

FOR THE

MARCELLUS SHALE PRIMARY AREA

 

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EXHIBIT (A)

FORM OF

LIMITED PARTNERSHIP AGREEMENT

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FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP FOR MDS ENERGY PUBLIC 2012-A LP

[MDS ENERGY PUBLIC 2013-A, LP]

[MDS ENERGY PUBLIC 2013-B, LP]

THIS AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP (“AGREEMENT”), amending and restating the original Certificate of Limited Partnership, is made and entered into as of the date set forth below, by and among MDS Energy Development, LLC, referred to as “MDS Energy Development” or the “Managing General Partner,” and the remaining parties from time to time signing a Subscription Agreement for Limited Partner Units, these parties sometimes referred to as “Limited Partners,” or for Investor General Partner Units, these parties sometimes referred to as “Investor General Partners.”

ARTICLE I

FORMATION

1.01. Formation. The parties have formed a limited partnership under the Delaware Revised Uniform Limited Partnership Act on the terms and conditions set forth in this Agreement.

1.02. Certificate of Limited Partnership. This document is not only an agreement among the parties, but also is the Amended and Restated Certificate and Agreement of Limited Partnership of the Partnership. This document shall be filed or recorded in the public offices required under applicable law or deemed advisable in the discretion of the Managing General Partner. Amendments to the certificate of limited partnership shall be filed or recorded in the public offices required under applicable law or deemed advisable in the discretion of the Managing General Partner.

1.03. Name, Principal Office and Residence.

1.03(a). Name. The name of the Partnership is MDS Energy Public 2012-A LP [ MDS Energy Public 2013-A LP] [ MDS Energy Public 2013-B LP]

1.03(b). Residence. The residence of the Managing General Partner is its principal place of business at 409 Butler Road, Suite A, Kittanning, Pennsylvania, 16201, which shall also serve as the principal place of business of the Partnership.

The residence of each Participant shall be as set forth on the Subscription Agreement executed by the Participant.

All addresses shall be subject to change on notice to the parties.

1.03(c). Agent for Service of Process. The name and address of the agent for service of process shall be Registered Agents Legal Services, LLC, 1220 North Market Street, Suite 806, Wilmington, Delaware 19801.

1.04. Purpose. The Partnership shall engage in all phases of the natural gas and oil business. This includes, without limitation, exploration for, development and production of natural gas and oil on the terms and conditions set forth below and any other proper purpose under the Delaware Revised Uniform Limited Partnership Act.

The Managing General Partner may not, without the affirmative vote of Participants whose Units equal a majority of the total Units, do the following:

 

(i)

change the investment and business purpose of the Partnership; or

 

(ii)

cause the Partnership to engage in activities outside the stated business purposes of the Partnership through joint ventures with other entities.

 

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ARTICLE II

DEFINITION OF TERMS

2.01. Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:

 

1.

“Administrative Costs” means all customary and routine expenses incurred by the Sponsor for the conduct of Partnership administration, including: in-house legal, finance, in-house accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature. Administrative Costs shall be limited as follows:

 

(i)

no Administrative Costs charged shall be duplicated under any other category of expense or cost; and

 

(ii)

no portion of the salaries, benefits, compensation or remuneration of controlling persons of the Managing General Partner shall be reimbursed by the Partnership as Administrative Costs. Controlling persons include directors, executive officers and those holding a 5% or more equity interest in the Managing General Partner or a person having power to direct or cause the direction of the Managing General Partner, whether through the ownership of voting securities, by contract, or otherwise.

 

2.	“Administrator” means the official or agency administering the securities laws of a state.

 

3.	“Affiliate” means with respect to a specific person:

 

(i)

any person directly or indirectly owning, controlling, or holding with power to vote 10% or more of the outstanding voting securities of the specified person;

 

(ii)

any person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by the specified person;

 

(iii)

any person directly or indirectly controlling, controlled by, or under common control with the specified person;

 

(iv)

any officer, director, trustee or partner of the specified person; and

 

(v)

if the specified person is an officer, director, trustee or partner, any person for which the person acts in any such capacity.

 

4.	“Agreement” means this Amended and Restated Certificate and Agreement of Limited Partnership, including all exhibits to this Agreement.

 

5.	“Assessments” means additional amounts of capital which may be mandatorily required of or paid voluntarily by a Participant beyond his subscription commitment.

 

6.	“Capital Account” or “account” means the account established for each party, maintained as provided in §5.02 and its subsections.

 

7.	“Capital Contribution” means the amount agreed to be contributed to the Partnership by a Partner pursuant to §§3.04 and 3.05 and their subsections.

 

8.	“Carried Interest” means an equity interest in the Partnership issued to a Person without consideration, in the form of cash or tangible property, in an amount proportionately equivalent to that received from the Participants.

 

9.	“Code” means the Internal Revenue Code of 1986, as amended.

 

10.	“Cost,” when used with respect to the sale or transfer of property to the Partnership, means:

 

(i)

the sum of the prices paid by the seller or transferor to an unaffiliated person for the property, including bonuses;

 

(ii)

title insurance or examination costs, brokers’ commissions, filing fees, recording costs, transfer taxes, if any, and like charges in connection with the acquisition of the property;

 

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(iii)

a pro rata portion of the seller’s or transferor’s actual necessary and reasonable expenses for seismic and geophysical services; and

 

(iv)

rentals and ad valorem taxes paid by the seller or transferor for the property to the date of its transfer to the buyer, interest and points actually incurred on funds used to acquire or maintain the property, and the portion of the seller’s or transferor’s reasonable, necessary and actual expenses for geological, geophysical, engineering, drafting, accounting, legal and other like services allocated to the property cost in conformity with generally accepted accounting principles and industry standards, except for expenses in connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the expenses enumerated in this subsection (iv) shall have been incurred not more than 36 months before the sale or transfer to the Partnership.

“Cost,” when used with respect to services, means the reasonable, necessary and actual expense incurred by the seller on behalf of the Partnership in providing the services, determined in accordance with generally accepted accounting principles.

As used elsewhere, “Cost” means the price paid by the seller in an arm’s-length transaction.

 

11.	“Dealer-Manager” means MDS Securities, LLC, an Affiliate of the Managing General Partner, and the broker/dealer which will manage the offering and sale of the Units.

 

12.

“Developed Reserves” means reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. To see other SEC definitions of terms relating to oil and gas reserves, visit http://www.sec.gov/divisions/ corpfin/ecfrlinks.shtml, click on “Regulation S-X,” and then scroll down and click the link in the “Section Contents” to §210.4-10 and then read §210.4-10 (a) Definitions.

 

13.	“Development Well” means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic Horizon known to be productive.

 

14.

“Direct Costs” means all actual and necessary costs directly incurred for the benefit of the Partnership and generally attributable to the goods and services provided to the Partnership by parties other than the Sponsor or its Affiliates. Direct Costs may not include any cost otherwise classified as Organization and Offering Costs, Administrative Costs, Intangible Drilling Costs, Tangible Costs, Operating Costs or costs related to the Leases, but may include the cost of services provided by the Sponsor or its Affiliates if the services are provided pursuant to written contracts and in compliance with §4.03(d)(7) or pursuant to the Managing General Partner’s role as Tax Matters Partner.

 

15.

“Distribution Interest” means an undivided interest in the Partnership’s assets after payments to the Partnership’s creditors or the creation of a reasonable reserve therefor, in the ratio the positive balance of a party’s Capital Account bears to the aggregate positive balance of the Capital Accounts of all of the parties determined after taking into account all Capital Account adjustments for the taxable year during which liquidation occurs (other than those made pursuant to liquidating distributions or restoration of deficit Capital Account balances). Provided, however, after the Capital Accounts of all of the parties have been reduced to zero, the interest in any remaining Partnership assets shall equal a party’s interest in the related Partnership revenues as set forth in §5.01 and its subsections.

 

16.	“Drilling and Operating Agreement” means the proposed Drilling and Operating Agreement between the Managing General Partner or an Affiliate as Operator, and the Partnership as Developer, a copy of the proposed form of which is attached to this Agreement as Exhibit (II).

 

17.

“Exploratory Well” means a well drilled to find and produce oil or gas in an unproved area, find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. Generally, an exploratory well is any well that is not a developmental well, a service well, or a stratigraphic test well as those items are defined by the SEC.

 

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18.

“Farmout” means an agreement by the owner of the leasehold or Working Interest to assign his interest in certain acreage or well to the assignees, retaining some interest such as an Overriding Royalty Interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment.

 

19.	“Final Terminating Event” means any one of the following:

 

(i)

the expiration of the Partnership’s fixed term;

 

(ii)

notice to the Participants by the Managing General Partner of its election to terminate the Partnership’s affairs;

 

(iii)

notice by the Participants to the Managing General Partner of their similar election through the affirmative vote of Participants whose Units equal a majority of the total Units; or

 

(iv)

the termination of the Partnership under §708(b)(1)(A) of the Code or the Partnership ceases to be a going concern.

 

20.	“Horizon” means a zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

 

21.

“Independent Expert” means a person with no material relationship to the Sponsor or its Affiliates who is qualified and in the business of rendering opinions regarding the value of natural gas and oil properties based on the evaluation of all pertinent economic, financial, geologic and engineering information available to the Sponsor or its Affiliates.

 

22.	“Initial Closing Date” means the date after the minimum amount of subscription proceeds has been received when subscription proceeds are first withdrawn from the escrow account.

 

23.

“Intangible Drilling Costs” or “Non-Capital Expenditures” means those expenditures associated with property acquisition and the drilling and completion of natural gas and oil wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes:

 

(i)

all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil, that are currently deductible pursuant to Section 263(c) of the Code and Treasury Reg. Section 1.612-4, and are generally termed “intangible drilling and development costs”;

 

(ii)

the expense of plugging and abandoning any well before a completion attempt; and

 

(iii)

the costs (other than Tangible Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.

 

24.	“Interim Closing Date” means those date(s) after the Initial Closing Date, but before the Offering Termination Date, that the Managing General Partner, in its sole discretion, applies additional subscription proceeds to additional Partnership activities, including drilling activities.

 

25.	“Investor General Partners” means:

 

(i)

the Persons signing the Subscription Agreement as Investor General Partners; and

 

(ii)

the Managing General Partner to the extent of any optional subscription as an Investor General Partner under §3.03(b)(1).

All Investor General Partners shall be of the same class and have the same rights.

 

26.	“Landowner’s Royalty Interest” means an interest in production, or its proceeds, to be received free and clear of all costs of development, operation, or maintenance, reserved by a landowner on the creation of a Lease.

 

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27.

“Leases” means full or partial interests in natural gas and oil leases, oil and natural gas mineral rights, fee rights, licenses, concessions, or other rights under which the holder is entitled to explore for and produce oil and/or natural gas, and includes any contractual rights to acquire any such interest.

 

28.	“Limited Partners” means:

 

(i)

the Persons signing the Subscription Agreement as Limited Partners;

 

(ii)

the Managing General Partner to the extent of any optional subscription as a Limited Partner under §3.03(b)(1);

 

(iii)

the Investor General Partners on the conversion of their Investor General Partner Units to Limited Partner Units pursuant to §6.01(b); and

 

(iv)

any other Persons who are admitted to the Partnership as additional or substituted Limited Partners.

Except as provided in §3.05(b), with respect to the required additional Capital Contributions of Investor General Partners, all Limited Partners shall be of the same class and have the same rights.

 

29.	“Managing General Partner” means:

 

(i)

MDS Energy Development, LLC; or

 

(ii)

any Person admitted to the Partnership as a general partner, other than as an Investor General Partner, who is designated to exclusively supervise and manage the operations of the Partnership.

 

30.	“Managing General Partner Signature Page” means an execution and subscription instrument in the form attached as Exhibit (I-A) to this Agreement, which is incorporated in this Agreement by reference.

 

31.

“MDS Energy Development” means “MDS Energy Development, LLC,” a Pennsylvania limited liability company, whose principal executive offices are located at 409 Butler Road, Suite A, Kittanning, Pennsylvania, 16201, and any successor entity to MDS Energy Development, LLC whether by merger or any other form of reorganization, or the acquisition of all, or substantially all, of MDS Energy Development, LLC’s assets.

 

32.	“MDS Energy Public 2012 Program” means the offering of Units in a series of up to three limited partnerships entitled MDS Energy Public 2012-A LP, MDS Energy Public 2013-A LP and MDS Energy Public 2013-B LP.

 

33.	“MDS Securities” means MDS Securities, LLC, whose principal executive offices are located at 409 Butler Road, Kittanning, Pennsylvania 16201.

 

34.

“Offering Termination Date” means the date after the minimum amount of subscription proceeds has been received on which the Managing General Partner determines, in its sole discretion, that the Partnership’s subscription period is closed and the acceptance of subscriptions ceases, which may be any date up to and including December 31, 2012 for MDS Energy Public 2012-A LP [December 31, 2013 for MDS Energy Public 2013-A LP and MDS Energy Public 2013-B LP].

Notwithstanding the above, the Offering Termination Date may not extend beyond the time that subscriptions for the maximum number of Units set forth in §3.03(c)(1) have been received and accepted by the Managing General Partner.

 

35.	“Operating Costs” means expenditures made and costs incurred in producing and marketing natural gas or oil from completed wells. These costs include, but are not limited to:

 

(i)

labor, fuel, repairs, hauling, materials, supplies, utility charges and other costs incident to or related to producing and marketing natural gas and oil;

 

(ii)

ad valorem and severance taxes;

 

(iii)

insurance and casualty loss expense; and

 

(iv)

compensation to well operators or others for services rendered in conducting these operations.

 

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Operating Costs also include disposal and injection wells, transporting wastewater by pipeline, truck or barge, reworking, workover, subsequent equipping, and similar expenses relating to any well, the Managing General Partner’s gathering fees set forth in §4.04(a)(2)(d) and the reimbursement of the Managing General Partner’s Administrative Costs set forth in §4.04(a)(2)(c); but do not include the costs to re-enter and deepen an existing well, complete the well to deeper formations or reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper formations or reservoirs.

 

36.	“Operator” means MDS Energy Development, LLC, as operator of Partnership Wells in Pennsylvania or an Affiliate as Operator of Partnership Wells in other areas of the United States.

 

37.	“Organization and Offering Costs” means all costs of organizing and selling the offering including, but not limited to:

 

(i)

total underwriting and brokerage discounts and commissions, including fees of the underwriters’ attorneys, the Dealer-Manager fee, sales commissions and reimbursement for bona fide due diligence expenses;

 

(ii)

expenses for printing, engraving, mailing, salaries of employees while engaged in sales activities, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts;

 

(iii)

expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants’ and attorneys’ fees; and

 

(iv)

other front-end fees.

 

38.	“Organization Costs” means all costs of organizing the offering including, but not limited to:

 

(i)

expenses for printing, engraving, mailing, salaries of employees while engaged in sales activities, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts;

 

(ii)

expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants’ and attorneys’ fees; and

 

(iii)

other front-end fees.

 

39.	“Overriding Royalty Interest” means an interest in the natural gas and oil produced under a Lease, or the proceeds from the sale thereof, carved out of the Working Interest, to be received free and clear of all costs of development, operation, or maintenance.

 

40.	“Participants” means:

 

(i)

the Managing General Partner to the extent of its optional subscription under §3.03(b)(1);

 

(ii)

the Limited Partners; and

 

(iii)

the Investor General Partners.

 

41.	“Partners” means:

 

(i)

the Managing General Partner;

 

(ii)

the Investor General Partners; and

 

(iii)

the Limited Partners.

 

42.	“Partnership” means MDS Energy Public 2012-A LP [ MDS Energy Public 2013-A LP] [ MDS Energy Public 2013-B LP].

 

43.	“Partnership Net Production Revenues” means gross revenues after deduction of the related Operating Costs, Direct Costs, Administrative Costs and all other Partnership costs not specifically allocated.

 

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44.	“Partnership Well” means a well, some portion of the revenues from which is received by the Partnership.

 

45.	“Person” means a natural person, partnership, corporation, association, trust or other legal entity.

 

46.

“Production Purchase” or “Income” Program means any program whose investment objective is to directly acquire, hold, operate, and/or dispose of producing oil and gas properties. Such a program may acquire any type of ownership interest in a producing property, including, but not limited to, working interests, royalties, or production payments. A program which spends at least 90% of capital contributions and funds borrowed (excluding offering and organizational expenses) in the above described activities is presumed to be a production purchase or income program.

 

47.	“Program” means one or more limited or general partnerships or other investment vehicles formed, or to be formed, for the primary purpose of:

 

(i)

exploring for natural gas, oil and other hydrocarbon substances; or

 

(ii)

investing in or holding any property interests which permit the exploration for or production of hydrocarbons or the receipt of such production or its proceeds.

 

48.

“Prospect” means an area covering lands which are believed by the Managing General Partner to contain subsurface structural or stratigraphic conditions making it susceptible to the accumulations of hydrocarbons in commercially productive quantities at one or more Horizons. The area, which may be different for different Horizons, shall be:

 

(i)

designated by the Managing General Partner in writing before the conduct of Partnership operations; and

 

(ii)

enlarged or contracted from time to time on the basis of subsequently acquired information to define the anticipated limits of the associated hydrocarbon reserves and to include all acreage encompassed therein.

If the well to be drilled by the Partnership is to a Horizon containing Proved Reserves, then a “Prospect” for a particular Horizon may be limited to the minimum area permitted by state law or local practice, whichever is applicable, to protect against drainage from adjacent wells. Subject to the foregoing, a “Prospect” for wells drilled by the Partnership to the Marcellus Shale geological formation in western Pennsylvania shall be deemed:

 

•

for vertical wells a Prospect will be limited to not more than approximately 7.85 acres consisting of the wellbore and the acreage within a circle having a radius of 330 feet from the wellbore and extending in depth from the bottom of the Tully Limestone formation to the top of the Onondaga Limestone formation, subject to minimum spacing limitations under Pennsylvania law; and

 

•

for horizontal wells, if any, a Prospect will be composed of the wellbore plus 125 feet on all sides of the center line of each lateral in the well, and extending from the beginning of the first perforation to the end of the last perforation and will further be limited to a depth from the bottom of the Tully Limestone formation to the top of the Onondaga Limestone formation, subject to minimum spacing limitations under Pennsylvania law;

subject in each case to adjustments to take into account Lease boundaries.

 

49.

“Prospectus” means the Prospectus included in the Registration Statement on Form S-1 relating to the offer and sale of the Units which has been filed with the Securities and Exchange Commission (the “Commission”) under the Securities Act of 1933, as amended (the “Act”). As used in this Agreement, the terms “Prospectus” and “Registration Statement” refer solely to the Prospectus and Registration Statement, as amended, described above, except that:

 

(i)

from and after the date on which any post-effective amendment to the Registration Statement is declared effective by the Commission, the term “Registration Statement” shall refer to the Registration Statement as amended by that post-effective amendment, and the term “Prospectus” shall refer to the Prospectus then forming a part of the Registration Statement; and

 

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(ii)

if the Prospectus filed pursuant to Rule 424(b) or (c) promulgated by the Commission under the Act differs from the Prospectus on file with the Commission at the time the Registration Statement or any post-effective amendment thereto shall have become effective, the term “Prospectus” shall refer to the Prospectus filed pursuant thereto from and after the date on which it was filed.

 

50.

“Proved Reserves” means those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

(i)

The area of the reservoir considered as proved includes:

 

(a)

the area identified by drilling and limited by fluid contacts, if any; and

 

(b)

adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(a)

successful testing by a pilot project, in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

(b)

the project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

To see other SEC definitions of terms relating to oil and gas reserves, visit http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml, click on “Regulation S-X,” and then scroll down and click the link in the “Section Contents” to §210.4-10 and then read §210.4-10 (a) Definitions.

 

51.

“Reserves” means estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. To see other SEC definitions of terms relating to oil and gas reserves, visit http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml, click on “Regulation S-X,” and then scroll down and click the link in the “Section Contents” to §210.4-10 and then read §210.4-10 (a) Definitions.

 

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52.	“Roll-Up” means a transaction involving the acquisition, merger, conversion or consolidation, either directly or indirectly, of the Partnership and the issuance of securities of a Roll-Up Entity. The term does not include:

 

(i)

a transaction involving securities of the Partnership that have been listed for at least 12 months on a national exchange or traded through the National Association of Securities Dealers Automated Quotation National Market System; or

 

(ii)

a transaction involving the conversion to corporate, trust or association form of only the Partnership if, as a consequence of the transaction, there will be no significant adverse change in any of the following:

 

(a)

voting rights;

 

(b)

the Partnership’s term of existence;

 

(c)

the Managing General Partner’s compensation; and

 

(d)

the Partnership’s investment objectives.

 

53.	“Roll-Up Entity” means a partnership, trust, corporation or other entity that would be created or survive after the successful completion of a proposed roll-up transaction.

 

54.	“Sales Commissions” means all underwriting and brokerage discounts and commissions incurred in the sale of Units payable in cash to registered broker/dealers, but excluding the following:

 

(i)

the 3% Dealer-Manager fee; and

 

(ii)

the reimbursement for bona fide due diligence expenses.

All items of compensation to underwriters or dealers, including, but not limited to, sales commissions, expenses, rights of first refusal, consulting fees, finders’ fees and all other items of compensation of any kind or description paid by the Partnership, directly or indirectly, shall be taken into consideration in computing the amount of allowable Sales Commissions.

 

55.	“Selling Dealers” means the broker/dealers which are selected by the Dealer-Manager to participate in the offer and sale of the Units.

 

56.	“Sponsor” means any person directly or indirectly instrumental in organizing, wholly or in part, a program or any person who will manage or is entitled to manage or participate in the management or control of a program. The definition includes:

 

(i)

the managing and controlling general partner(s) and any other person who actually controls or selects the person who controls 25% or more of the exploratory, development or producing activities of the program, or any segment thereof, even if that person has not entered into a contract at the time of formation of the program; and

 

(ii)

whenever the context so requires, the term “sponsor” shall be deemed to include its affiliates.

“Sponsor” does not include wholly independent third-parties such as attorneys, accountants, and underwriters whose only compensation is for professional services rendered in connection with the offering of units.

 

57.	“Subscription Agreement” means an execution and subscription instrument in the form attached as Exhibit (I-B) to this Agreement, which is incorporated in this Agreement by reference.

 

58.	“Tangible Costs” or “Capital Expenditures” means those costs associated with property acquisition and drilling and completing natural gas and oil wells which are generally accepted as capital expenditures under the Code. This includes all of the following:

 

(i)

costs of equipment, parts and items of hardware used in drilling and completing a well;

 

(ii)

those items necessary to deliver acceptable natural gas and oil production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized under the Code and its regulations.

 

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59.	“Tax Matters Partner” means the Managing General Partner.

 

60.	“Undeveloped Reserves” means reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion, provided that:

 

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

To see other SEC definitions of terms relating to oil and gas reserves, visit http://www.sec.gov/divisions/ corpfin/ ecfrlinks.shtml, click on “Regulation S-X,” and then scroll down and click the link in the “Section Contents” to §210.4-10 and then read §210.4-10 (a) Definitions.

 

61.

“Units” or “Units of Participation” means up to 600 Limited Partner interests in the Partnership and up to 29,400 Investor General Partner interests in the Partnership, which will be converted to the same number of Limited Partner Units as set forth in §6.01(b), purchased by Participants in the Partnership under the provisions of §3.03 and its subsections, including any rights to profits, losses, income, gain, credits, deductions, cash distributions or returns of capital or other attributes of the Units. The Partnership reserves the right to adjust the number of Investor General Partner Units, Limited Partner Units and Investor General Partner Units converted to Limited Partner Units set forth above so long as they do not exceed 30,000 Units, in the aggregate.

 

62.	“Working Interest” means an interest in a Lease which is subject to some portion of the cost of development, operation, or maintenance of the Lease.

ARTICLE III

SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS

3.01. Designation of Managing General Partner and Participants. MDS Energy Development, LLC shall serve as Managing General Partner of the Partnership. MDS Energy Development, LLC shall further serve as a Participant to the extent of any subscription made by it pursuant to §3.03(b)(1).

Limited Partners and Investor General Partners, including the Managing General Partner and its Affiliates to the extent, if any, they purchase Units, shall serve as Participants.

3.02. Participants.

3.02(a). Limited Partner at Formation. M/D Gas, Inc., as Original Limited Partner, has acquired one Unit and has made a Capital Contribution of $100. On the admission of one or more Limited Partners, the Partnership shall return to the Original Limited Partner its Capital Contribution and shall reacquire its Unit. The Original Limited Partner shall then cease to be a Limited Partner in the Partnership with respect to that Unit.

3.02(b). Offering of Interests. The Partnership is authorized to admit to the Partnership at the Initial Closing Date, any Interim Closing Date(s), and the Offering Termination Date additional Participants whose Subscription Agreements are accepted by the Managing General Partner if, after the admission of the additional Participants, the total Units sold do not exceed the maximum number of Units set forth in §3.03(c)(1).

 

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3.02(c). Admission of Participants. No action or consent by the Participants shall be required for the admission of additional Participants pursuant to this Agreement.

All subscribers’ funds shall be held in an interest bearing account or accounts by an independent escrow holder and shall not be released to the Partnership until the receipt and acceptance of the minimum amount of subscription proceeds set forth in §3.03(c)(2). Thereafter, subscriptions may be paid directly to a Partnership account.

3.03. Subscriptions to the Partnership.

3.03(a). Subscriptions by Participants.

3.03(a)(1). Subscription Price and Minimum Subscription. The subscription price of a Unit in the Partnership shall be $10,000, except as set forth below, and shall be designated on each Participant’s Subscription Agreement and payable as set forth in §3.05(b)(1). The minimum subscription per Participant shall be one Unit ($10,000). Larger subscriptions shall be accepted in $1,000 increments, beginning with $11,000, $12,000, etc.

Notwithstanding the foregoing, the subscription price for:

 

(i)

the Managing General Partner, its officers, directors, and Affiliates, their family members and Participants who buy Units through the officers and directors of the Managing General Partner, shall be reduced by an amount equal to the 3.0% Dealer-Manager fee and the 7% Sales Commission, which shall not be paid with respect to those sales (for purposes of this discount, the Partnership considers a family member to be a spouse, child, sibling, cousin, mother- or father-in-law, son- or daughter-in-law or brother- or sister-in-law);

 

(ii)

Registered Investment Advisors and their clients, and Selling Dealers and their registered representatives and principals, shall be reduced by an amount equal to the 7% cash Sales Commission, which shall not be paid with respect to those sales; and

 

(iii)

volume subscriptions for Units shall be reduced for each incremental Unit purchased in the total volume ranges set forth in the table below:

 

Dollar Volume of Units Purchased For A “Single” Purchaser		Cash Sales Commission For Incremental Unit in Volume Discount Range				Purchase Price Per Unit to Participants
$1,000 — $500,000			7.0	%		$	10,000
500,001 — 1,000,000			6.0	%			9,900
1,000,001 — 2,000,000			5.0	%			9,800
2,000,001 — 3,000,000			4.0	%			9,700
3,000,001 — 5,000,000			3.0	%			9,600

For example, a single Participant would receive 55.051 Units rather than 55 Units for an investment of $550,000 and the Sales Commission would be $38,030. The discount would be calculated as follows: On the first $500,000 of the investment there would be no discount and the purchaser would receive 50 Units at $10,000 per Unit. On the remaining $50,000, the per Unit price would be $9,900 and the purchaser would receive 5.051 Units.

For purposes of determining Participants eligible for volume discounts, investments made by accounts with the same primary account holder, as determined by the account tax identification number, may be combined. This includes individual accounts and joint accounts that have the same primary holder as any individual account.

To the extent a Participant qualified for a volume discount on a particular purchase, any subsequent purchase, regardless of the number of Units subscribed for in that purchase, will also qualify for that volume discount or, to the extent the subsequent purchase when aggregated with the prior purchase(s) qualifies for a greater volume discount, such greater discount. For example, if an initial purchase is for

 

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$450,000, and a second purchase is for $80,000, then the first $50,000 of the second purchase will be priced at $10,000 per unit and the remaining $30,000 of the second purchase will be priced at $9,900 per unit. Any request to treat a subsequent purchase cumulatively for purposes of the volume discount must be made in writing and shall be subject to verification by the Partnership or the Dealer-Manager that all of the orders were made by a single purchaser. In the event orders are combined, the Sales Commission payable with respect to the subsequent purchase of Units shall equal the Sales Commission per Unit that would have been payable in accordance with the commission schedule set forth above if all purchases had been made simultaneously. Any reduction of the 7.0% Sales Commission otherwise payable to the Dealer-Manager or a Selling Dealer may be credited to the Participant as additional Units. Unless Participants indicate that orders are to be combined and provide all other requested information, the Partnership shall not be held responsible for failing to combine orders properly. Also, the volume shall be prorated among the separate accounts considered to be a single purchaser and the amount of total Sales Commissions thus computed shall be apportioned pro rata among the individual orders on the basis of the respective amounts of the orders being combined. Further, for purposes of distributions, all Participants shall be deemed to have contributed the same amount per Unit to the Partnership whether or not the Participant received a discount. Finally, Sales Commissions for purchases of more than $5 million are negotiable between the Dealer-Manager or Selling Dealer and the Participant. Sales Commissions paid shall in all cases be the same for the same level of sales and once a price is negotiated with the initial purchaser this shall be the price for all purchases at that volume.

All Sales Commissions and Dealer-Manager fees shall be paid in cash.

No more than 5% of the total Units in the Partnership shall be sold with the discounts described in subsections (i) and (ii) above.

3.03(a)(2). Effect of Subscription. Execution of a Subscription Agreement shall serve as an agreement by the Participant to be bound by each and every term of this Agreement.

3.03(b). Optional Subscriptions for Units by Managing General Partner.

3.03(b)(1). Managing General Partner’s Optional Subscriptions for Units. In addition to the Managing General Partner’s required Capital Contributions under §3.04(a), beginning on the Initial Closing Date the Managing General Partner may subscribe under the provisions of §3.03(a) and its subsections for up to 5% of the total Units sold in the Partnership as of the applicable closing date, which shall not be applied towards the minimum number of Units required to be sold under §3.03(c)(2), and, subject to the limitations on voting rights set forth in §4.03(c)(3), to that extent shall be deemed to be a Participant in the Partnership for all purposes under this Agreement.

3.03(b)(2). Effect of and Evidencing Subscription. The Managing General Partner has executed a Managing General Partner Signature Page which:

 

(i)

evidences the Managing General Partner’s required Capital Contributions under §3.04(a); and

 

(ii)

may be amended, from time-to-time, to reflect the amount of any optional subscriptions for Units as a Participant under §3.03(b)(1).

Execution of the Managing General Partner Signature Page serves as an agreement by the Managing General Partner to be bound by each and every term of this Agreement.

3.03(c). Maximum and Minimum Number of Units.

3.03(c)(1). Maximum Number of Units. The maximum number of Units may not exceed 30,000 Units, which is $300,000,000 of cash subscription proceeds, excluding the subscription discounts permitted under §3.03(a)(1).

 

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Notwithstanding the foregoing, the maximum number of Units in all of the partnerships in the MDS Energy Public 2012 Program, in the aggregate, shall not exceed 30,000 Units which is $300,000,000 of cash subscription proceeds, excluding the subscription discounts permitted under §3.03(a)(1).

3.03(c)(2). Minimum Number of Units. The minimum number of Units shall equal at least 200 Units, but in any event not less than the number of Units that provides the Partnership with cash subscription proceeds of $2,000,000, excluding the subscription discounts permitted under §3.03(a)(1).

If subscriptions for the minimum number of Units have not been received and accepted at the Offering Termination Date, then all monies deposited by subscribers shall be promptly returned to them. They shall receive interest earned on their subscription proceeds from the date the monies were deposited in escrow through the date of refund, without deduction for any fees.

The Partnership may break escrow and begin its drilling activities, in the Managing General Partner’s sole discretion, on receipt and acceptance of the minimum subscription proceeds.

3.03(d). Acceptance of Subscriptions.

3.03(d)(1). Discretion by the Managing General Partner. Acceptance of subscriptions is discretionary with the Managing General Partner. The Managing General Partner may reject any subscription for any reason it deems appropriate.

3.03(d)(2). Time Period in Which to Accept Subscriptions. Subscriptions shall be accepted or rejected by the Managing General Partner within 30 days of their receipt. If a subscription is rejected, then all of the subscriber’s funds shall be returned to the subscriber promptly, with interest earned and without deduction for any fees.

3.03(d)(3). Admission to the Partnership. The Participants shall be admitted to the Partnership as follows:

 

(i)

not later than 15 days after the release from the escrow account of Participants’ subscription proceeds to the Partnership; or

 

(ii)

if a Participant’s subscription proceeds are received by the Partnership after the close of the escrow account, then not later than the last day of the calendar month in which his Subscription Agreement was accepted by the Managing General Partner.

3.04. Capital Contributions of the Managing General Partner.

3.04(a). Managing General Partner’s Required Capital Contributions. The Managing General Partner, as a general partner and not as a Participant, is required to pay the costs or make the other required Capital Contributions charged to it under this Agreement, which includes its credit for Organization and Offering Costs under §5.01(a)(1) and contributing the Leases to the Partnership on the terms set forth in §4.01(a)(4), in an amount equal to not less than 15%, in the aggregate, of all Capital Contributions to the Partnership, at the time the costs are required to be paid by the Partnership, but in any event no later than December 31, 2013.

3.04(b). On Liquidation the Managing General Partner Must Contribute Deficit Balance in Its Capital Account. The Managing General Partner shall contribute to the Partnership any deficit balance in its Capital Account on the occurrence of either of the following events:

 

(i)

the liquidation of the Partnership; or

 

(ii)

the liquidation of the Managing General Partner’s interest in the Partnership.

This shall be determined after taking into account all adjustments for the Partnership’s taxable year during which the liquidation occurs, other than adjustments made pursuant to this requirement, by the end of the taxable year in which the liquidation occurs or, if later, within 90 days after the date of the liquidation.

 

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3.04(c). Managing General Partner’s Partnership Interest for Capital Contributions. The interest of the Managing General Partner, as Managing General Partner and not as a Participant, in the capital and profits of the Partnership is fully vested and nonforfeitable as of the date of the formation of the Partnership and is in consideration for, and is the only consideration for, its required Capital Contributions to the Partnership.

3.04(d). Managing General Partner’s Right to Assign Its Partnership Interest. Subject to a required participation of not less than 1% of the Partnership’s revenues (unless there is a substituted Managing General Partner) and §5.01(b)(4)(a) regarding the Managing General Partner’s subordination obligation, the Managing General Partner has the right at any time, in its discretion, without the consent of the Participants, and without affecting the allocation of costs and revenues to the Participants or the Managing General Partner’s voting rights under this Agreement, to sell, contribute, exchange or otherwise transfer all or any portion of its interest as Managing General Partner or as a Participant (if it purchases Units) in the Partnership, or any interest therein to an Affiliate of the Managing General Partner. In that event, except as otherwise may be permitted under this Agreement, if the Affiliated transferee of the Managing General Partner’s transferred interest in the Partnership does not become a substituted Managing General Partner in the Partnership, the Affiliated transferee, as a partner in the Partnership for tax purposes only, shall have the right to receive the share of the Partnership’s profits, losses, income, gains, deductions, credits and depletion allowances, or items thereof, and cash distributions and returns of capital (including, but not limited to, cash distributions and returns of capital on dissolution and liquidation of the Partnership) to which the Managing General Partner would otherwise be entitled under this Agreement with respect to its transferred interest in the Partnership.

Subject to the foregoing, the transfer of the Managing General Partner’s interest in the Partnership to any of its Affiliates may be made on any terms and conditions as the Managing General Partner determines, in its discretion, and the Partnership and the Participants shall have no right to receive or otherwise share in any consideration received by the Managing General Partner from its Affiliates for the transfer of the Managing General Partner’s interest in the Partnership.

No transfer of the Managing General Partner’s interest in the Partnership to its Affiliates under this §3.04(d) shall require an accounting by the Managing General Partner or the Partnership to the Participants.

3.05. Payment of Subscriptions.

3.05(a). Managing General Partner’s Subscriptions. The Managing General Partner shall pay any optional subscription under §3.03(b)(1) as set forth in §3.05(b)(1).

3.05(b). Participant Subscriptions and Additional Capital Contributions of the Investor General Partners.

3.05(b)(1). Payment of Subscription Agreements. A Participant shall pay the subscription amount designated on his Subscription Agreement 100% in cash at the time of subscribing. A Participant shall receive interest on the amount he pays from the time his subscription proceeds are deposited in the escrow account, or a Partnership account after the minimum number of Units has been received as provided in §3.06(b), until his subscription proceeds are paid by the Partnership under the Drilling and Operating Agreement for use in the Partnership’s drilling activities. All interest income shall be earned in the ratio that the Participant’s subscription proceeds multiplied by the number of days the Participant’s subscription proceeds were held in the escrow account, or a Partnership account after the minimum number of Units have been received as provided in §3.06(b), bears to the sum of that calculation for all Participants whose subscription proceeds were paid to the Managing General Partner at the same time. Interest on subscription amounts shall be paid as provided in §5.01(b)(2).

3.05(b)(2). Additional Required Capital Contributions of the Investor General Partners. Investor General Partners must make Capital Contributions to the Partnership when called by the Managing General Partner, in addition to their subscription amounts, for their pro rata share of any Partnership obligations and liabilities which are recourse to the Investor General Partners and are represented by their ownership of Units before the conversion of Investor General Units to Limited Partner Units under §6.01(b).

 

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3.05(b)(3). Default Provisions. The failure of an Investor General Partner to timely make a required additional Capital Contribution under this section results in his personal liability to the other Investor General Partners for the amount in default. The remaining Investor General Partners, in proportion to their respective number of Units, must pay the defaulting Investor General Partner’s share of Partnership liabilities and obligations called for by the Managing General Partner. In that event, the remaining Investor General Partners:

 

(i)

shall have a first and preferred lien on the defaulting Investor General Partner’s interest in the Partnership to secure payment of the amount in default plus interest at the legal rate;

 

(ii)

shall be entitled to receive 100% of the defaulting Investor General Partner’s cash distributions, in proportion to their respective number of Units, until the amount in default is recovered in full plus interest at the legal rate; and

 

(iii)

may commence legal action to collect the amount due plus interest at the legal rate.

3.06. Partnership Funds.

3.06(a). Fiduciary Duty. The Managing General Partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of the Partnership, whether or not in the Managing General Partner’s possession or control. The Managing General Partner shall not employ, or permit another to employ, the funds and assets of the Partnership in any manner except for the exclusive benefit of the Partnership.

Neither this Agreement nor any other agreement between the Managing General Partner and the Partnership shall contractually limit any fiduciary duty owed to the Participants by the Managing General Partner under applicable law.

3.06(b). Special Account After the Receipt of the Minimum Partnership Subscriptions. Following the receipt of the minimum number of Units and breaking escrow, the funds of the Partnership shall be held in a separate interest-bearing account maintained for the Partnership and shall not be commingled with funds of any other entity.

3.06(c). Investment.

3.06(c)(1). Investments in Other Entities. Partnership funds shall not be invested in the securities of another person except in the following instances:

 

(i)

investments in Working Interests or undivided Lease interests made in the ordinary course of the Partnership’s business;

 

(ii)

temporary investments made as set forth in §3.06(c)(2);

 

(iii)

multi-tier arrangements meeting the requirements of §4.03(d)(15);

 

(iv)

investments involving less than 5% of the Partnership’s subscription proceeds which are a necessary and incidental part of a property acquisition transaction; and

 

(v)

investments in entities established solely to limit the Partnership’s liabilities associated with the ownership or operation of property or equipment, provided that duplicative fees and expenses shall be prohibited.

3.06(c)(2). Permissible Investments Before Investment in Partnership Activities. After the Initial Closing Date and until proceeds from the offering are invested in the Partnership’s operations, the proceeds may be temporarily invested in income producing short-term, highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills. Any interest income from such temporary investments shall be allocated pro rata to the Participants providing such Capital Contributions.

 

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ARTICLE IV

CONDUCT OF OPERATIONS

4.01. Acquisition of Leases.

4.01(a). Assignment to Partnership.

4.01(a)(1). In General. The Managing General Partner shall select, acquire and assign or cause to have assigned to the Partnership full or partial interests in Leases, by any method customary in the natural gas and oil industry, subject to the terms and conditions set forth below.

The Partnership and the other partnerships in the MDS Energy Public 2012 Program may acquire and develop interests in Leases covering one or more of the same Prospects, in the Managing General Partner’s discretion.

The Partnership shall acquire only Leases reasonably expected to meet the stated purposes of the Partnership. No Leases shall be acquired for the purpose of a subsequent sale, Farmout, or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the Partnership’s best interest.

4.01(a)(2). Federal and State Leases. The Partnership is authorized to acquire Leases on federal and state lands.

4.01(a)(3). Managing General Partner’s Discretion as to Terms and Burdens of Acquisition. Subject to the provisions of §4.03(d) and its subsections, the acquisitions of Leases or other property may be made under any terms and obligations, including any limitations as to the Horizons to be assigned to the Partnership and subject to any burdens as the Managing General Partner deems necessary in its sole discretion.

4.01(a)(4). Cost of Leases. All Leases shall be:

 

(i)

contributed to the Partnership by the Managing General Partner or its Affiliates; and

 

(ii)

credited towards the Managing General Partner’s required Capital Contribution set forth in §3.04(a) at the Cost of the Lease as described in the Prospectus under “Compensation – Lease Costs,” unless the Managing General Partner has cause to believe that Cost is materially more than the fair market value of the property, in which case the credit for the contribution must be made at a price not in excess of the fair market value; except that the Managing General Partner’s credit for Leases in the Marcellus Shale primary area it acquires from Snyder Brothers, Inc., or another Affiliate, and then contributes to the Partnership, if any, shall be an amount equal to the fair market value of the Leases as set forth in an appraisal of the Leases by an Independent Expert selected by the Managing General Partner, but not to exceed the actual price paid for the Leases by the Managing General Partner.

Also, the Managing General Partner may average the cost of the Leases by area or type of drilling to arrive at an average Lease cost per Prospect.

If the sale, transfer or conveyance of a Lease is from an Affiliated Program that has held the lease for more than two years and in which Program the interest of the Managing General Partner or its Affiliates is substantially similar to, or less than, its interest in the Partnership, the sale, transfer or conveyance may be made at fair market value.

A determination of fair market value must be supported by an appraisal from an Independent Expert.

 

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4.01(a)(5). The Managing General Partner, Operator or Their Affiliates’ Rights in the Remainder Interests. Subject to the provisions of §4.03(d) and its subsections, to the extent the Partnership does not acquire a full interest in a Lease from the Managing General Partner or its Affiliates, the remainder of the interest in the Lease may be held by the Managing General Partner or its Affiliates. They may either:

 

(i)

retain and exploit the remaining interest for their own account; or

 

(ii)

sell or otherwise dispose of all or a part of the remaining interest.

Profits from the exploitation and/or disposition of their retained interests in the Leases shall be for the benefit of the Managing General Partner or its Affiliates to the exclusion of the Partnership and the Participants.

4.01(a)(6). No Breach of Duty. Subject to the provisions of §4.03 and its subsections, acquisition of Leases from the Managing General Partner, the Operator or their Affiliates shall not be considered a breach of any obligation owed by them to the Partnership or the Participants.

4.01(b). No Overriding Royalty Interests. Neither the Managing General Partner, the Operator nor any Affiliate shall retain any Overriding Royalty Interest on the Leases acquired by the Partnership.

4.01(c). Title and Nominee Arrangements.

4.01(c)(1). Legal Title. Legal title to all Leases acquired by the Partnership shall be held on a permanent basis in the name of the Partnership. However, Partnership properties may be held temporarily in the name of:

 

(i)

the Managing General Partner;

 

(ii)

the Operator;

 

(iii)

their Affiliates; or

 

(iv)

in the name of any nominee designated by the Managing General Partner to facilitate the acquisition of the properties.

Notwithstanding, legal title to such Leases may be held on a permanent basis in the mane of a special nominee entity organized by the Managing General Partner, provided that the nominee’s sole purpose is the holding of record title for oil and gas properties and it engages in no other business and incurs no other liabilities; and either ruling from the Internal Revenue Service or an opinion of qualified tax counsel is obtained to the effect that such arrangement will not change the ownership status of the Partnership for federal income tax purposes.

4.01(c)(2). Managing General Partner’s Discretion. The Managing General Partner shall take the steps which are necessary in its best judgment to render title to the Leases to be acquired by the Partnership acceptable for the purposes of the Partnership. The Managing General Partner shall be free, however, to use its own best judgment in waiving title requirements.

The Managing General Partner shall not be liable to the Partnership or to the other parties for any mistakes of judgment; nor shall the Managing General Partner be deemed to be making any warranties or representations, express or implied, as to the validity or merchantability of the title to the Leases assigned to the Partnership or the extent of the interest covered thereby except as otherwise provided in the Drilling and Operating Agreement.

4.01(c)(3). Commencement of Operations. The Partnership shall not begin operations on its Leases unless the Managing General Partner is satisfied that necessary title requirements have been satisfied.

4.02. Conduct of Operations.

4.02(a). In General. The Managing General Partner shall establish a program of operations for the Partnership. Subject to the limitations contained in Article III of this Agreement concerning the maximum Capital

 

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Contribution which can be required of a Limited Partner, the Managing General Partner, the Limited Partners, and the Investor General Partners agree to participate in the program so established by the Managing General Partner.

4.02(b). Management. Subject to any restrictions contained in this Agreement, the Managing General Partner shall exercise full control over all operations of the Partnership.

4.02(c). General Powers of the Managing General Partner.

4.02(c)(1). In General. Subject to the provisions of §4.03 and its subsections, and to any authority that may be granted the Operator under §4.02(c)(3)(b), the Managing General Partner shall have full authority to do all things deemed necessary or desirable by it in the conduct of the business of the Partnership. Without limiting the generality of the foregoing, the Managing General Partner is expressly authorized to engage in:

 

(i)

the making of all determinations of which Leases, wells and operations will be participated in by the Partnership, which includes:

 

(a)

which Leases are developed;

 

(b)

which Leases are abandoned; or

 

(c)

which Leases are sold or assigned to other parties, including other investor ventures organized by the Managing General Partner, the Operator, or any of their Affiliates;

 

(ii)

the negotiation and execution on any terms deemed desirable in its sole discretion of any contracts, conveyances, or other instruments, considered useful to the conduct of the operations or the implementation of the powers granted it under this Agreement, including, without limitation:

 

(a)

the making of agreements for the conduct of operations, including agreements and financial instruments relating to hedging up to 50% of the Partnership’s natural gas and oil production and the pledge of up to 100% of the Partnership’s assets and reserves in connection therewith, and in this regard the Partnership has confirmed its authorization to MDS Energy Development, LLC and its Affiliates to enter into hedging agreements on its behalf, and has ratified all actions previously taken by MDS Energy Development, LLC, its Affiliates, or their successors in interest by merger or otherwise, in connection therewith;

 

(b)

the exercise of any options, elections, or decisions under any such agreements; and

 

(c)

the furnishing of equipment, facilities, supplies and material, services, and personnel;

 

(iii)

the exercise, on behalf of the Partnership or the parties, as the Managing General Partner in its sole judgment deems best, of all rights, elections and options granted or imposed by any agreement, statute, rule, regulation, or order;

 

(iv)

the making of all decisions concerning the desirability of payment, and the payment or supervision of the payment, of all delay rentals and shut-in and minimum or advance royalty payments;

 

(v)

the selection of full or part-time employees and outside consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

(vi)

the maintenance of insurance for the benefit of the Partnership and the parties as it deems necessary, but in no event less in amount or type than the following:

 

(a)

worker’s compensation insurance in full compliance with the laws of the Commonwealth of Pennsylvania and any other applicable state laws where the wells will be drilled;

 

(b)

commercial general liability insurance covering bodily injury and products/completed operations, including certain pollution clean-up costs, subject to certain discovery and reporting requirements to the insurer with limits of $1,000,000 per occurrence and $2,000,000 in the aggregate;

 

(c)

automobile liability insurance with a $1,000,000 combined single limit for bodily injury and property damage, including hired and non-owned vehicles; and

 

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(d)

umbrella liability insurance with an aggregate limit of $50,000,000, except that the limit for pollution is $25,000,000. The excess liability insurance shall be in place and effective no later than the date drilling operations begin and, for purposes of satisfying this requirement, the Partnership shall have the benefit of the Managing General Partner’s $50,000,000 liability insurance on the same basis as the Managing General Partner and its other Affiliates, including their Affiliated Programs;

 

(vii)

the use of the funds and revenues of the Partnership, and the borrowing on behalf of, and the loan of money to, the Partnership, on any terms it sees fit, for any purpose, including without limitation:

 

(a)

the conduct or financing, in whole or in part, of the drilling and other activities of the Partnership;

 

(b)

the conduct of additional operations; and

 

(c)

the repayment of any borrowings or loans used initially to finance these operations or activities;

 

(viii)

the disposition, hypothecation, sale, exchange, release, surrender, reassignment or abandonment of any or all assets of the Partnership, including without limitation, the Leases, wells, equipment and production therefrom, provided that the sale of all or substantially all of the assets of the Partnership shall only be made as provided in §4.03(d)(6);

 

(ix)

the formation of any further limited or general partnership, tax partnership, joint venture, or other relationship which it deems desirable with any parties who it, in its sole discretion, selects, including any of its Affiliates;

 

(x)

the control of any matters affecting the rights and obligations of the Partnership, including:

 

(a)

the employment of attorneys to advise and otherwise represent the Partnership;

 

(b)

the conduct of litigation and incurring other legal expenses; and

 

(c)

the settlement of claims and litigation;

 

(xi)

the operation of producing wells drilled on the Leases or on a Prospect which includes any part of the Leases;

 

(xii)

the exercise of the rights granted to it under the power of attorney created under this Agreement; and

 

(xiii)

the incurring of all costs and the making of all expenditures in any way related to any of the foregoing.

4.02(c)(2). Scope of Powers. The Managing General Partner’s powers shall extend to any operation participated in by the Partnership or affecting its Leases, or other property or assets, irrespective of whether or not the Managing General Partner is designated operator of the operation by any outside persons participating therein.

4.02(c)(3). Delegation of Authority.

4.02(c)(3)(a). In General. The Managing General Partner may subcontract and delegate all or any part of its duties under this Agreement to any entity chosen by it, including an entity Affiliated with it, which party shall have the same powers in the conduct of the duties as would the Managing General Partner. The delegation, however, shall not relieve the Managing General Partner of its responsibilities under this Agreement.

4.02(c)(3)(b). Delegation to Operator. The Managing General Partner is specifically authorized to delegate any or all of its duties to the Operator by executing the Drilling and Operating Agreement. This delegation shall not relieve the Managing General Partner of its responsibilities under this Agreement.

In no event shall any consideration received for operator services be in excess of competitive rates or duplicative of any consideration or reimbursements received under this Agreement. The Managing General Partner may not benefit by interpositioning itself between the Partnership and the actual provider of operator services.

 

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4.02(c)(4). Related Party Transactions. Subject to the provisions of §4.03 and its subsections, any transaction which the Managing General Partner is authorized to enter into on behalf of the Partnership under the authority granted in this section and its subsections, may be entered into by the Managing General Partner with itself or with any other general partner, the Operator, or any of their Affiliates.

4.02(d). Additional Powers. In addition to the powers granted the Managing General Partner under §4.02(c) and its subsections or elsewhere in this Agreement, the Managing General Partner, when specified, shall have the following additional express powers.

4.02(d)(1). Drilling Contracts. All Partnership Wells shall be drilled under the Drilling and Operating Agreement for an amount equal to the sum of the following items:

 

(i)

the Cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by Affiliates of the Managing General Partner, then those items will be charged at competitive rates;

 

(ii)

fees for third-party services;

 

(iii)

fees for services provided by the Managing General Partner’s Affiliates, which will be charged at competitive rates;

 

(iv)

an administration and oversight fee, as described in the Drilling and Operating Agreement, which will be charged to the Participants as part of each well’s Intangible Drilling Costs and Tangible Costs paid by the Participants; and

 

(v)

a mark-up in an amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the Managing General Partner’s services as general drilling contractor.

Additionally, if the Managing General Partner drills a well for the Partnership that the Managing General Partner determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completing the well, or as otherwise determined by the Managing General Partner, the administration and oversight fee of the well described in §4.02(d)(1)(iv) may be increased to a competitive rate as determined by the Managing General Partner.

The Managing General Partner or its Affiliates, as drilling contractor, may not receive a rate that is not competitive with the rates charged by unaffiliated contractors in the same geographic region, enter into a turnkey drilling contract with the Partnership, profit by drilling in contravention of its fiduciary obligations to the Partnership, or benefit by interpositioning itself between the Partnership and the actual provider of drilling contractor services.

4.02(d)(2). Power of Attorney.

4.02(d)(2)(a). In General. Each Participant appoints the Managing General Partner his true and lawful attorney-in-fact for him and in his name, place, and stead and for his use and benefit, from time to time:

 

(i)

to create, prepare, complete, execute, file, swear to, deliver, endorse, and record any and all documents, certificates, government reports, or other instruments as may be required by law, or are necessary to amend this Agreement as authorized under the terms of this Agreement, or to qualify the Partnership as a limited partnership or partnership in commendam and to conduct business under the laws of any jurisdiction in which the Managing General Partner elects to qualify the Partnership or conduct business; and

 

(ii)

to create, prepare, complete, execute, file, swear to, deliver, endorse and record any and all instruments, assignments, security agreements, financing statements, certificates, and other documents as may be necessary from time to time to implement the borrowing powers granted under this Agreement and any agreements entered into by the Partnership to hedge its natural gas and oil reserves and pledge up to 100% of its assets and natural gas and oil reserves in connection therewith.

 

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4.02(d)(2)(b). Further Action. Each Participant authorizes the attorney-in-fact to take any further action which the attorney-in-fact considers necessary or advisable in connection with any of the foregoing powers and rights granted the Managing General Partner under this section and its subsections. Each party acknowledges that the power of attorney granted under §4.02(d)(2)(a):

 

(i)

is a special power of attorney coupled with an interest and is irrevocable; and

 

(ii)

shall survive the assignment by the Participant of the whole or a portion of his Units; except when the assignment is of all of the Participant’s Units and the purchaser, transferee, or assignee of the Units is admitted as a successor Participant, the power of attorney shall survive the delivery of the assignment for the sole purpose of enabling the attorney-in-fact to execute, acknowledge, and file any agreement, certificate, instrument or document necessary to effect the substitution.

4.02(d)(2)(c). Power of Attorney to Operator. The Managing General Partner is hereby authorized to grant a Power of Attorney to the Operator on behalf of the Partnership.

4.02(e). Borrowings and Use of Partnership Revenues.

4.02(e)(1). Power to Borrow or Use Partnership Revenues.

4.02(e)(1)(a). In General. If additional funds over the Participants’ Capital Contributions are needed for Partnership operations, then the Managing General Partner may:

 

(i)

use Partnership revenues for such purposes; or

 

(ii)

the Managing General Partner and its Affiliates may advance the necessary funds to the Partnership under §4.03(d)(8)(b), although they are not obligated to advance the funds to the Partnership.

4.02(e)(1)(b). Limitation on Borrowing. Partnership borrowings, other than credit transactions on open account customary in the industry to obtain goods and services, shall be subject to the following limitations:

 

(i)

the borrowings must be without recourse to the Investor General Partners and the Limited Partners; and

 

(ii)

the amount that may be borrowed at any one time may not exceed an amount equal to 5% of the Partnership’s subscription proceeds.

Notwithstanding, the above limitations shall not affect the Partnership’s ability to enter into agreements and financial instruments relating to hedging up to 50% of the Partnership’s natural gas and oil production and pledging up to 100% of the Partnership’s assets and reserves in connection therewith.

4.02(f). Tax Matters Partner.

4.02(f)(1). Designation of Tax Matters Partner. The Managing General Partner is hereby designated the Tax Matters Partner of the Partnership under Section 6231(a)(7) of the Code. The Managing General Partner is authorized to act in this capacity on behalf of the Partnership and the Participants and to take any action, including settlement or litigation, which it in its sole discretion deems to be in the best interest of the Partnership.

4.02(f)(2). Costs Incurred by Tax Matters Partner. Costs incurred by the Tax Matters Partner shall be considered a Direct Cost of the Partnership.

4.02(f)(3). Notice to Participants of IRS Proceedings. The Tax Matters Partner shall notify all of the Participants of any administrative or other legal proceedings involving the Partnership and the IRS or any other taxing authority, and thereafter shall furnish all of the Participants periodic reports at least quarterly on the status of the proceedings.

 

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4.02(f)(4). Participant Restrictions. Each Participant agrees as follows:

 

(i)

he will not file the statement described in Section 6224(c)(3)(B) of the Code prohibiting the Managing General Partner as the Tax Matters Partner for the Partnership from entering into a settlement on his behalf with respect to Partnership items, as that term is defined in Section 6231(a)(3) of Code, of the Partnership;

 

(ii)

he will not form or become and exercise any rights as a member of a group of Partners having a 5% or greater interest in the profits of the Partnership under Section 6223(b)(2) of the Code; and

 

(iii)

the Managing General Partner is authorized to file a copy of this Agreement, or pertinent portions of this Agreement, with the IRS under Section 6224(b) of the Code if necessary to perfect the waiver of rights under this subsection.

4.03. General Rights and Obligations of the Participants and Restricted and Prohibited Transactions.

4.03(a)(1). Limited Liability of Limited Partners. Limited Partners shall not be bound by the obligations of the Partnership other than as provided under the Delaware Revised Uniform Limited Partnership Act. Limited Partners shall not be personally liable for any debts of the Partnership or any of the obligations or losses of the Partnership beyond the subscription amount designated on the Subscription Agreement executed by each respective Limited Partner unless:

 

(i)

they also subscribe to the Partnership as Investor General Partners; or

 

(ii)

in the case of the Managing General Partner, it purchases Limited Partner Units.

4.03(a)(2). No Management Authority of Participants. Participants, other than the Managing General Partner if it buys Units, shall have no power over the conduct of the affairs of the Partnership. No Participant, other than the Managing General Partner if it buys Units, shall take part in the management of the business of the Partnership, or have the power to sign for or to bind the Partnership.

4.03(b). Reports and Disclosures.

4.03(b)(1). Annual Reports and Financial Statements. Beginning with the calendar year in which the Partnership had its Initial Closing Date, the Partnership shall provide each Participant an annual report within 120 days after the close of that calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing except as otherwise indicated, at least the information set forth below:

 

(i)

Audited financial statements of the Partnership, including a balance sheet and statements of income, cash flow, and Partners’ equity, which shall be prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation with respect to information furnished for income tax purposes and accompanied by an auditor’s report containing an opinion of an independent public accountant selected by the Managing General Partner stating that his audit was made in accordance with generally accepted auditing standards and that in his opinion the financial statements present fairly the financial position, results of operations, partners’ equity, and cash flows in accordance with generally accepted accounting principles. Semiannual reports are not required to be audited.

 

(ii)

A summary itemization, by type and/or classification of the total fees and compensation, including any nonaccountable, fixed payment reimbursements for Administrative Costs and Operating Costs, paid by, or on behalf of, the Partnership to the Managing General Partner, the Operator, and their Affiliates.

Also, the independent certified public accountant shall provide written attestation annually, which will be included in the annual report, that the method used to make allocations of the Partnership’s Administrative Costs was consistent with the method described in §4.04(a)(2)(c) of this Agreement and that the total amount of Administrative Costs allocated did not materially exceed the amounts described

 

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in §4.04(a)(2)(c). If the Managing General Partner subsequently decides to allocate Administrative Costs in a manner different from that described in §4.04(a)(2)(c) of this Agreement, then the change must be reported to the Participants together with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.

 

(iii)

A description of each Prospect in which the Partnership owns an interest, including:

 

(a)

the cost, location, and number of acres under Lease; and

 

(b)

the Working Interest owned in the Prospect by the Partnership.

Succeeding reports, however, must only contain material changes, if any, regarding the Prospects.

 

(iv)

A list of the wells drilled or abandoned by the Partnership during the period of the report, indicating:

 

(a)

whether each of the wells has or has not been completed;

 

(b)

a statement of the cost of each well completed or abandoned; and

 

(c)

justification for wells abandoned after production has begun.

 

(v)

A description of all Farmouts, farmins, and joint ventures, made during the period of the report, including:

 

(a)

the Managing General Partner’s justification for the arrangement; and

 

(b)

a description of the material terms.

 

(vi)

If Assessments have been made during any period covered by the report, then the report shall contain a detailed statement of the Assessments and the application of the proceeds derived from the Assessments.

 

(vii)

A schedule reflecting:

 

(a)

the total Partnership costs;

 

(b)

the costs paid by the Managing General Partner and the costs paid by the Participants;

 

(c)

the total Partnership revenues;

 

(d)

the revenues received or credited to the Managing General Partner and the revenues received and credited to the Participants; and

 

(e)

a reconciliation of the expenses and revenues in accordance with the provisions of Article V.

Additionally, on request the Managing General Partner will provide the information specified by Form 10-Q (if such report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period.

4.03(b)(2). Tax Information. The Partnership shall, by March 15 of each year, prepare, or supervise the preparation of, and transmit to each Participant the information needed for the Participant to file the following:

 

(i)

his federal income tax return;

 

(ii)

any required state income tax return; and

 

(iii)

any other reporting or filing requirements imposed by any governmental agency or authority.

4.03(b)(3). Reserve Report. Beginning with the second calendar year after the Initial Termination Date and every year thereafter, the Partnership shall provide to each Participant the following:

 

(i)

a summary of the computation of the Partnership’s total natural gas and oil Proved Reserves;

 

(ii)

a summary of the computation of the present worth of the reserves determined using:

 

(a)

a discount rate of 10%;

 

(b)

a constant price for the oil based on then existing prices; and

 

(c)

basing the price of natural gas on the existing natural gas contracts or prices;

 

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(iii)

a statement of each Participant’s interest in the reserves; and

 

(iv)

an estimate of the time required for the extraction of the reserves with a statement that because of the time period required to extract the reserves the present value of revenues to be obtained in the future is less than if the revenues were immediately receivable.

The reserve computations shall be based on engineering reports prepared by the Managing General Partner and reviewed by an Independent Expert.

Also, if any event reduces the Partnership’s Proved Reserves by 10% or more, excluding a reduction of reserves as a result of normal production, sales of reserves, or natural gas or oil price changes, then a computation and estimate of the amount of the reduction in reserves must be sent to each Participant within 90 days after the Managing General Partner determines that such a reduction in reserves has occurred.

4.03(b)(4). Cost of Reports. The cost of all reports described in this §4.03(b) shall be paid by the Partnership as Direct Costs.

4.03(b)(5). Participant Access to Records. The Managing General Partner shall maintain and preserve during the term of the Partnership and for four years thereafter all accounts, books and other relevant Partnership documents. The Participants and/or their representatives shall be permitted access to all Partnership records, provided that access to the list of Participants shall be subject to §4.03(b)(7) below. Subject to the foregoing, a Participant may inspect and copy any of the Partnership’s records after giving adequate notice to the Managing General Partner at any reasonable time.

Notwithstanding the foregoing, the Managing General Partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time. The Managing General Partner may release information concerning the operations of the Partnership to the sources that are customary in the industry or required by rule, regulation, or order of any regulatory body.

4.03(b)(6). Required Length of Time to Hold Records. The Managing General Partner must maintain and preserve during the term of the Partnership and for six years thereafter all accounts, books and other relevant documents which include:

 

(i)

a record that a Participant meets the suitability standards established in connection with an investment in the Partnership; and

 

(ii)

any appraisal of the fair market value of the Leases as set forth in §4.01(a)(4), along with associated supporting information, or the fair market value of any producing property as set forth in §4.03(d)(3).

4.03(b)(7). Participant Lists. The following provisions apply regarding access to the list of Participants:

 

(i)

an alphabetical list of the names, addresses, and business telephone numbers of the Participants along with the number of Units held by each of them (the “Participant List”) must be maintained as a part of the Partnership’s books and records and be available for inspection by any Participant or his designated agent at the home office of the Partnership on the Participant’s request;

 

(ii)

the Participant List must be updated at least quarterly to reflect changes in the information contained in the Participant List;

 

(iii)

a copy of the Participant List must be mailed to any Participant requesting the Participant List within 10 days of the written request, printed in alphabetical order on white paper, and in a readily readable type size in no event smaller than 10-point type and a reasonable charge for copy work will be charged by the Partnership;

 

(iv)

the purposes for which a Participant may request a copy of the Participant List include, without limitation, matters relating to Participant’s voting rights under this Agreement and the exercise of Participant’s rights under the federal proxy laws; and

 

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(v)

if the Managing General Partner neglects or refuses to exhibit, produce, or mail a copy of the Participant List as requested, the Managing General Partner shall be liable to any Participant requesting the list for the costs, including attorneys fees, incurred by that Participant for compelling the production of the Participant List, and for actual damages suffered by any Participant by reason of the refusal or neglect. It shall be a defense that the actual purpose and reason for the request for inspection or for a copy of the Participant List is to secure the list of Participants or other information for the purpose of selling the list or information or copies of the list, or of using the same for a commercial purpose other than in the interest of the applicant as a Participant relative to the affairs of the Partnership. The Managing General Partner will require the Participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the Participant’s interest in the Partnership. The remedies provided under this subsection to Participants requesting copies of the Participant List are in addition to, and shall not in any way limit, other remedies available to Participants under federal law or the laws of any state.

4.03(b)(8). State Filings. Concurrently with their transmittal to Participants, and as required, the Managing General Partner shall file a copy of each report provided for in this §4.03(b) with:

 

(i)

the California Commissioner of Corporations;

 

(ii)

the Ohio Securities Bureau;

 

(iii)

the Alabama Securities Commission; and

 

(iv)

the securities commissions of other states which request the report.

4.03(c). Meetings of Participants.

4.03(c)(1). Procedure for a Participant Meeting.

4.03(c)(1)(a). Meetings May Be Called by Managing General Partner or Participants. Meetings of the Participants may be called as follows:

 

(i)

by the Managing General Partner; or

 

(ii)

by Participants whose Units equal 10% or more of the total Units for any matters on which Participants may vote.

The call for a meeting by the Participants as described above shall be deemed to have been made on receipt by the Managing General Partner of a written request from holders of the requisite percentage of Units stating the purpose(s) of the meeting.

4.03(c)(1)(b). Notice Requirement. The Managing General Partner shall deposit in the United States mail within 15 days after the receipt of the request, written notice to all Participants of the meeting and the purpose of the meeting. The meeting shall be held on a date not less than 30 days nor more than 60 days after the date of the mailing of the notice, at a reasonable time and place.

Notwithstanding the foregoing, the date for notice of the meeting may be extended for a period of up to 60 days if, in the opinion of the Managing General Partner, the additional time is necessary to permit preparation of proxy or information statements or other documents required to be delivered in connection with the meeting by the SEC or other regulatory authorities.

4.03(c)(1)(c). May Vote by Proxy. Participants shall have the right to vote at any Participant meeting either:

 

(i)

in person; or

 

(ii)

by proxy.

 

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4.03(c)(2). Special Voting Rights. At the request of Participants whose Units equal 10% or more of the total Units, the Managing General Partner shall call for a vote by Participants. Each Unit is entitled to one vote on all matters, and each fractional Unit is entitled to that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of the total Units may, without the concurrence of the Managing General Partner or its Affiliates, vote to:

 

(i)

dissolve the Partnership;

 

(ii)

remove the Managing General Partner and elect a new Managing General Partner;

 

(iii)

elect a new Managing General Partner if the Managing General Partner elects to withdraw from the Partnership;

 

(iv)

remove the Operator and elect a new Operator;

 

(v)

approve or disapprove the sale of all or substantially all of the assets of the Partnership;

 

(vi)

cancel any contract for services with the Managing General Partner, the Operator, or their Affiliates without penalty on 60 days notice; and

 

(vii)

amend this Agreement; provided however:

 

(a)

any amendment may not increase the duties or liabilities of any Participant or the Managing General Partner or increase or decrease the profit or loss sharing or required Capital Contribution of any Participant or the Managing General Partner without the approval of the Participant or the Managing General Partner, respectively; and

 

(b)

any amendment may not affect the classification of Partnership income and loss for federal income tax purposes without the unanimous approval of all Participants.

4.03(c)(3). Restrictions on Managing General Partner’s Voting Rights. With respect to Units owned by the Managing General Partner or its Affiliates, the Managing General Partner and its Affiliates may vote or consent on all matters other than the following:

 

(i)

the matters set forth in §4.03(c)(2)(ii) and (iv) above; or

 

(ii)

any transaction between the Partnership and the Managing General Partner or its Affiliates.

In determining the requisite percentage in interest of Units necessary to approve any Partnership matter on which the Managing General Partner and its Affiliates may not vote or consent, any Units owned by the Managing General Partner and its Affiliates shall not be included.

4.03(c)(4). Restrictions on Limited Partner Voting Rights. The exercise by the Limited Partners of the rights granted Participants under §4.03(c), except for the special voting rights granted Participants under §4.03(c)(2), shall be subject to the prior legal determination that the grant or exercise of the powers will not adversely affect the limited liability of Limited Partners. Notwithstanding the foregoing, if in the opinion of counsel to the Partnership the legal determination is not necessary under Delaware law to maintain the limited liability of the Limited Partners, then it shall not be required. A legal determination under this paragraph may be made either pursuant to:

 

(i)

an opinion of counsel, the counsel being independent of the Partnership and selected on the vote of Limited Partners whose Units equal a majority of the total Units held by Limited Partners; or

 

(ii)

a declaratory judgment issued by a court of competent jurisdiction.

The Investor General Partners may exercise the rights granted to the Participants whether or not the Limited Partners can participate in the vote if the Investor General Partners represent the requisite percentage of Units necessary to take the action.

 

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4.03(d). Transactions with the Managing General Partner.

4.03(d)(1). Transfer of Equal Proportionate Interest. When the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) sells, transfers or conveys any natural gas, oil or other mineral interests or property to the Partnership, it must, at the same time, sell, transfer or convey to the Partnership an equal proportionate interest in all its other property in the same Prospect.

Additionally, neither the Managing General Partner nor its Affiliates shall drill any vertical well to the Marcellus Shale geological formation if the well would be within 330 feet of an existing Partnership Well.

Also, the Managing General Partner and its Affiliates, including their Affiliated Programs, may drill a horizontal well to the Marcellus Shale for their own account on the same well pad used by a Partnership Well or on a different well pad located anywhere else within the 330 feet circle around the well bore of the Partnership Well or on a well pad located more than 330 feet away from the well bore of the Partnership Well, and they may drill the horizontal well laterally through all or any portion of the 330 feet circle around the well bore of the Partnership Well, without paying any compensation to the Partnership, but they may not complete the horizontal well or any of its laterals within 330 feet of the well bore of the Partnership Well.

Notwithstanding, multiple laterals may be drilled in horizontal wells on the same Prospect on which a vertical well is drilled and a vertical well may be drilled on the same Prospect on which a horizontal well is drilled. If the area constituting the Partnership’s Prospect is subsequently enlarged to encompass any area in which the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) owns a separate property interest and the activities of the Partnership were material in establishing the existence of Proved Undeveloped Reserves that are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold, transferred, or conveyed to the Partnership as set forth in this section and §§4.01(a)(4) and 4.03(d)(2).

Notwithstanding the foregoing, Prospects drilled to the Marcellus Shale formation or any other formation or reservoir shall not be enlarged or contracted except in the Managing General Partner’s discretion if the Prospect was limited because the well was being drilled to Proved Reserves and to protect against drainage.

4.03(d)(2). Transfer of Less than the Managing General Partner’s and its Affiliates’ Entire Interest. A sale, transfer or a conveyance to the Partnership of less than all of the ownership of the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) in any Prospect shall not be made unless:

 

(i)

the interest retained by the Managing General Partner or the Affiliate is a proportionate Working Interest;

 

(ii)

the respective obligations of the Managing General Partner or its Affiliates and the Partnership are substantially the same after the sale of the interest by the Managing General Partner or its Affiliates; and

 

(iii)

the Managing General Partner’s interest in revenues does not exceed the amount proportionate to its retained Working Interest.

This section does not prevent the Managing General Partner or its Affiliates from subsequently dealing with their retained interest as they may choose with unaffiliated parties or Affiliated partnerships.

4.03(d)(3). Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner. Other than another Program managed by the Managing General Partner and its Affiliates as set forth in §§4.03(d)(5) and 4.03(d)(9), the Managing General Partner and its Affiliates shall not receive a Farmout or

 

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purchase any undeveloped Leases from the Partnership other than at the higher of Cost or fair market value. However, when a well is plugged and abandoned the Partnership’s Lease rights may be assigned by the Partnership to the Managing General Partner in return for a cash payment, Farmout, Overriding Royalty Interest or other interest in the Prospect as determined by the Managing General Partner, in its discretion, consistent with its fiduciary duty to the Partnership.

The Managing General Partner and its Affiliates, other than an Affiliated Income Program, shall not purchase any producing natural gas or oil property from the Partnership unless:

 

(i)

the sale is in connection with the liquidation of the Partnership; or

 

(ii)

the Managing General Partner’s well supervision fees under the Drilling and Operating Agreement for the well have exceeded the net revenues of the well, determined without regard to the Managing General Partner’s well supervision fees for the well, for a period of at least three consecutive months.

Under both (i) and (ii) above, the sale must be at fair market value supported by an appraisal of an Independent Expert selected by the Managing General Partner.

4.03(d)(4). Limitations on Activities of the Managing General Partner and its Affiliates on Leases Acquired by the Partnership. During a period of five years after the Offering Termination Date of the Partnership, if the Managing General Partner or any of its Affiliates (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) proposes to acquire an interest from an unaffiliated person in a Prospect in which the Partnership possesses an interest or in a Prospect in which the Partnership’s interest has been terminated without compensation within one year preceding the proposed acquisition, then the following conditions shall apply:

 

(i)

if the Managing General Partner or the Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) does not currently own property in the Prospect separately from the Partnership, then neither the Managing General Partner nor the Affiliate shall be permitted to purchase an interest in the Prospect; and

 

(ii)

if the Managing General Partner or the Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) currently owns a proportionate interest in the Prospect separately from the Partnership, then the interest to be acquired shall be divided between the Partnership and the Managing General Partner or the Affiliate in the same proportion as is the other property in the Prospect. Provided, however, if cash or financing is not available to the Partnership to enable it to complete a purchase of the additional interest to which it is entitled, then neither the Managing General Partner nor the Affiliate shall be permitted to purchase any additional interest in the Prospect.

4.03(d)(5). Transfer of Leases Between Affiliated Limited Partnerships. The transfer of an undeveloped Lease from the Partnership to another drilling Program sponsored or managed by the Managing General Partner or its Affiliates must be made at fair market value if the undeveloped Lease has been held by the Partnership for more than two years. Otherwise, if the Managing General Partner deems it to be in the best interest of the Partnership, the transfer may be made at Cost.

An Affiliated Income Program may purchase a producing natural gas and oil property from the Partnership at any time at:

 

(i)

fair market value as supported by an appraisal from an Independent Expert if the property has been held by the Partnership for more than six months or significant expenditures have been made in connection with the property; or

 

(ii)

Cost, as adjusted for intervening operations, if the Managing General Partner deems it to be in the best interest of the Partnership.

 

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However, these prohibitions shall not apply to joint ventures or Farmouts among Affiliated partnerships, provided that:

 

(i)

the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and

 

(ii)

the compensation arrangement or any other interest or right of either the Managing General Partner or its Affiliates is the same in each Affiliated partnership or if different, the aggregate compensation of the Managing General Partner or the Affiliate is reduced to reflect the lower compensation arrangement.

4.03(d)(6). Sale of All Assets. The sale of all or substantially all of the assets of the Partnership, including without limitation, Leases, wells, equipment and production therefrom, shall be made only with the consent of Participants whose Units equal a majority of the total Units.

4.03(d)(7). Services.

4.03(d)(7)(a). Competitive Rates. The Managing General Partner and any Affiliate shall not render to the Partnership any oil field, equipage, or other services nor sell or lease to the Partnership any equipment or related supplies unless:

 

(i)

the person is engaged, independently of the Partnership and as an ordinary and ongoing business, in the business of rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the partnerships in which the Managing General Partner or an Affiliate has an interest; and

 

(ii)

the compensation, price, or rental therefor is competitive with the compensation, price, or rental of other persons in the area engaged in the business of rendering comparable services or selling or leasing comparable equipment and supplies which could reasonably be made available to the Partnership.

If the person is not engaged in such a business, then the compensation, price or rental shall be the Cost of the services, equipment or supplies to the person or the competitive rate which could be obtained in the area, whichever is less.

4.03(d)(7)(b). If Not Disclosed in the Prospectus or This Agreement, Then Services by the Managing General Partner Must be Described in a Separate Contract and Cancelable. Any services for which the Managing General Partner or an Affiliate is to receive compensation, other than those described in this Agreement or the Prospectus, shall be set forth in a written contract which precisely describes the services to be rendered and all compensation to be paid. These contracts shall be cancelable without penalty on 60 days written notice by Participants whose Units equal a majority of the total Units.

4.03(d)(8). Loans.

4.03(d)(8)(a). No Loans from the Partnership. No loans or advances shall be made by the Partnership to the Managing General Partner or its Affiliates.

4.03(d)(8)(b). Loans to the Partnership. Neither the Managing General Partner nor any Affiliate shall loan money to the Partnership if the interest to be charged exceeds either:

 

(i)

the Managing General Partner’s or the Affiliate’s interest cost; or

 

(ii)

that which would be charged to the Partnership, without reference to the Managing General Partner’s or the Affiliate’s financial abilities or guarantees, by unrelated lenders, on comparable loans for the same purpose.

Neither the Managing General Partner nor any Affiliate shall receive points or other financing charges or fees, regardless of the amount, although the actual amount of the charges incurred by them from third-party lenders may be reimbursed to the Managing General Partner or the Affiliate.

 

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4.03(d)(9). Farmouts. The Managing General Partner shall not enter into a Farmout to avoid its paying its share of costs, if any, related to drilling a well on an undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or well activity to the Managing General Partner or its Affiliates except as set forth in §4.03(d)(3). Notwithstanding, this restriction shall not apply to Farmouts between the Partnership and another partnership managed by the Managing General Partner or its Affiliates, either separately or jointly, provided that the respective obligations and revenue sharing of all parties to the transactions are substantially the same and the compensation arrangement or any other interest or right of the Managing General Partner or its Affiliates is the same in each partnership, or, if different, the aggregate compensation of the Managing General Partner and its Affiliates is reduced to reflect the lower compensation agreement.

The Partnership may Farmout an undeveloped lease or well activity only if the Managing General Partner, exercising the standard of a prudent operator, determines that:

 

(i)

the Partnership lacks the funds to complete the oil and gas operations on the Lease or well and cannot obtain suitable financing;

 

(ii)

drilling on the Lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the Partnership;

 

(iii)

the Leases or well activity have been downgraded by events occurring after assignment to the Partnership so that development of the Leases or well activity would not be desirable; or

 

(iv)

the best interests of the Partnership would be served.

If the Partnership Farmouts a Lease or well activity, the Managing General Partner must retain on behalf of the Partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices.

If the Partnership acquires an undeveloped Lease pursuant to a Farmout or joint venture from an Affiliated partnership, the Managing General Partner’s and its Affiliates’ aggregate compensation associated with the property and any direct and indirect ownership interest in the property may not exceed the lower of the compensation and ownership interest in the property that the Managing General Partner and/or its Affiliates could receive if the property were separately owned or retained by either the Partnership or the Affiliated partnership.

4.03(d)(10). No Compensating Balances. Neither the Managing General Partner nor any Affiliate shall use the Partnership’s funds as compensating balances for its own benefit.

4.03(d)(11). Future Production. Neither the Managing General Partner nor any Affiliate shall commit the future production of a well developed by the Partnership exclusively for its own benefit.

4.03(d)(12). Marketing Arrangements. Subject to §4.06(c), all benefits from marketing arrangements or other relationships affecting the property of the Managing General Partner or its Affiliates, including its Affiliated partnerships and the Partnership, shall be fairly and equitably apportioned according to the respective interests of each in the property. Notwithstanding, the Partnership shall not be a party to, and shall not receive any interest in, the hedging pool, contracts and arrangements that Snyder Brothers, Inc. maintains for its own account and certain of its Affiliates, except in the discretion of the Managing General Partner. If the Partnership and any other partnership sponsored by the Managing General Partner and its Affiliates are parties to the same hedging agreements, then the benefits and liabilities of the hedging agreements shall be equitably allocated by and the Managing General Partner, its Affiliates, or their successors in interest by merger or otherwise, to the Partnership and the other partnerships sponsored by the Managing General Partner and its Affiliates pro rata based on actual production, consistent with past practice, and the Partnership and the other partnerships sponsored by the Managing General Partner and its Affiliates shall be severally liable for their respective allocated share thereof, but shall not be jointly and severally liable for the entire amount of the liabilities under the hedging agreements.

 

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Additionally, the Managing General Partner, its Affiliates, and their successors in interest by merger or otherwise, shall not be liable for any such liabilities, or be entitled to any such benefits, to the extent they are so allocated. Notwithstanding, the Partnership may enter into agreements and financial instruments relating to hedging up to 50% of the Partnership’s natural gas and oil and the pledging of up to 100% of the Partnership’s assets and reserves in connection therewith separate from and in addition to the hedging agreements described above.

4.03(d)(13). Advance Payments. Advance payments by the Partnership to the Managing General Partner and its Affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid Intangible Drilling Costs for a business purpose as set forth in the Drilling and Operating Agreement.

4.03(d)(14). No Rebates. No rebates or give-ups may be received by the Managing General Partner or any Affiliate nor may the Managing General Partner or any Affiliate participate in any reciprocal business arrangements that would circumvent the provisions of this section.

4.03(d)(15). Participation in Other Partnerships. If the Partnership participates in other partnerships or joint ventures (multi-tier arrangements), then the terms of any of these arrangements shall not result in the circumvention of any of the requirements or prohibitions contained in this Agreement, including the following:

 

(i)

there shall be no duplication or increase in Organization and Offering Costs, the Managing General Partner’s compensation, Partnership expenses or other fees and costs;

 

(ii)

there shall be no substantive alteration in the fiduciary and contractual relationship between the Managing General Partner and the Participants; and

 

(iii)

there shall be no diminishment in the voting rights of the Participants.

4.03(d)(16). Roll-Up Limitations.

4.03(d)(16)(a). Requirement for Appraisal and Its Assumptions. In connection with a proposed Roll-Up, an appraisal of all Partnership assets shall be obtained from a competent Independent Expert. If the appraisal will be included in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal shall be filed with the SEC and the Administrator as an exhibit to the registration statement for the offering. Thus, an issuer using the appraisal shall be subject to liability for violation of Section 11 of the Securities Act of 1933 and comparable provisions under state law for any material misrepresentations or material omissions in the appraisal.

Partnership assets shall be appraised on a consistent basis. The appraisal shall be based on all relevant information, including current reserve estimates prepared as set forth in §4.03(b)(3), and shall indicate the value of the Partnership’s assets as of a date immediately before the announcement of the proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation of the Partnership’s assets over a 12-month period.

The terms of the engagement of the Independent Expert shall clearly state that the engagement is for the benefit of the Partnership and the Participants. A summary of the independent appraisal, indicating all material assumptions underlying the appraisal, shall be included in a report to the Participants in connection with a proposed Roll-Up.

4.03(d)(16)(b). Rights of Participants Who Vote Against Proposal. In connection with a proposed Roll-Up, Participants who vote “no” on the proposal shall be offered the choice of:

 

(i)

accepting the securities of the Roll-Up Entity offered in the proposed Roll-Up; or

 

(ii)

one of the following:

 

(a)

remaining as Participants in the Partnership and preserving their Units in the Partnership on the same terms and conditions as existed previously; or

 

(b)

receiving cash in an amount equal to the Participants’ pro rata share of the appraised value of the net assets of the Partnership based on their respective number of Units.

 

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4.03(d)(16)(c). No Roll-Up If Diminishment of Voting Rights. The Partnership shall not participate in any proposed Roll-Up which, if approved, would result in the diminishment of any Participant’s voting rights under the Roll-Up Entity’s chartering agreement. In no event shall the democracy rights of Participants in the Roll-Up Entity be less than those provided for under §§4.03(c)(1) and 4.03(c)(2). If the Roll-Up Entity is a corporation, then the democracy rights of Participants shall correspond to the democracy rights provided for in this Agreement to the greatest extent possible.

4.03(d)(16)(d). No Roll-Up If Accumulation of Shares Would be Impeded. The Partnership shall not participate in any proposed Roll-Up transaction which includes provisions that would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-Up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-Up Entity. The Partnership shall not participate in any proposed Roll-Up transaction which would limit the ability of a Participant to exercise the voting rights of its securities of the Roll-Up Entity on the basis of the number of Units held by that Participant.

4.03(d)(16)(e). No Roll-Up If Access to Records Would Be Limited. The Partnership shall not participate in a Roll-Up in which Participants’ rights of access to the records of the Roll-Up Entity would be less than those provided for under §§4.03(b)(5), 4.03(b)(6) and 4.03(b)(7).

4.03(d)(16)(f). Cost of Roll-Up. The Partnership shall not participate in any proposed Roll-Up transaction in which any of the costs of the transaction would be borne by the Partnership if Participants whose Units equal a majority of the total Units do not vote to approve the proposed Roll-Up.

4.03(d)(16)(g). Roll-Up Approval. The Partnership shall not participate in a Roll-Up transaction unless the Roll-Up transaction is approved by Participants whose Units equal a majority of the total Units.

4.03(d)(17). Disclosure of Binding Agreements. Any agreement or arrangement which binds the Partnership must be disclosed in the Prospectus.

4.03(d)(18). Transactions Must Be Fair and Reasonable. Neither the Managing General Partner nor any Affiliate shall sell, transfer, or convey any property to or purchase any property from the Partnership, directly or indirectly, except under transactions that are fair and reasonable, nor take any action with respect to the assets or property of the Partnership which does not primarily benefit the Partnership.

4.04. Designation, Compensation and Removal of Managing General Partner and Removal of Operator.

4.04(a). Managing General Partner.

4.04(a)(1). Term of Service. Except as otherwise provided in this Agreement, MDS Energy Development, LLC shall serve as the Managing General Partner of the Partnership until either it:

 

(i)

is removed pursuant to §4.04(a)(3); or

 

(ii)

withdraws pursuant to §4.04(a)(3)(f).

4.04(a)(2). Compensation of Managing General Partner. In addition to the compensation set forth in §§4.01(a)(4) and 4.02(d)(1), the Managing General Partner shall receive the compensation set forth in §§4.04(a)(2)(b) through 4.04(a)(2)(g).

4.04(a)(2)(a). Charges Must Be Necessary and Reasonable. Charges by the Managing General Partner for goods and services must be fully supportable as to:

 

(i)

the necessity of the goods and services; and

 

(ii)

the reasonableness of the amount charged.

 

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All actual and necessary expenses incurred by the Partnership may be paid out of the Partnership’s subscription proceeds and revenues.

4.04(a)(2)(b). Direct Costs. The Managing General Partner and its Affiliates shall be reimbursed for all Direct Costs. Direct Costs, however, shall be billed directly to and paid by the Partnership to the extent practicable.

4.04(a)(2)(c). Administrative Costs. The Managing General Partner shall receive a fully accountable reimbursement for its Administrative Costs based on actual costs and the percentage of time the personnel of the Managing General Partner or its Affiliates devote to the Partnership and its business.

4.04(a)(2)(d). Gas Gathering. The Managing General Partner, not acting as a Partner, shall be responsible for gathering and transporting the natural gas produced by the Partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area (the “gathering services”). In providing the gathering services, the Managing General Partner may use pipelines, gathering systems and natural gas processing plants in which an Affiliate of the Managing General Partner owns an interest, and/or pipelines, gathering systems and natural gas processing plants owned by independent third-parties.

The Partnership shall pay a gathering fee directly to the Managing General Partner or its Affiliates at competitive rates for the gathering services as described in the “Compensation – Gathering Fees” section of the Prospectus. The gathering fees paid by the Partnership to the Managing General Partner or its Affiliates may be increased from time-to-time by the Managing General Partner, in its sole discretion, but may not increase beyond competitive rates as determined by the Managing General Partner. Initially, the Managing General Partner has determined that the competitive rates for natural gas gathering fees in the Marcellus Shale (western Pennsylvania) primary area are:

 

•

if transported through a pipeline owned by Snyder Brothers, Inc. or MDS Energy, Ltd., which are Affiliates of the Managing General Partner, 10% of the sales price the Partnership receives for its natural gas, plus processing, compression, dehydration and any other operating costs related to the Partnership’s natural gas transported, but not less than $0.50 per 1,000 cubic feet of natural gas(“mcf”) transported; and

 

•

if transported through pipelines owned by Furnace Run Pipeline, L.P. or Mushroom Farm Pipeline, L.P., which are Affiliates of the Managing General Partner, $0.60 per mcf transported, plus 4% for processing, compression, dehydration and any other operating costs related to the Partnership’s natural gas transported.

The payment of a competitive fee to the Managing General Partner or its Affiliates for their gathering and transportation services shall be subject to the following conditions:

 

(i)

If a gas gathering system owned or operated by an Affiliate of the Managing General Partner is used by the Partnership, the gathering fee may not exceed a competitive rate for similar services in the area.

 

(ii)

If a third-party gathering system is used by the Partnership, then the gathering fee paid by the Partnership shall be the actual transportation and compression fees charged by the third-party and the Managing General Partner shall pay all of the gathering fee it receives from the Partnership to the third-party gathering the natural gas. The Managing General Partner shall not receive any gathering fees from the Partnership that exceed the payments it makes to the third-party gas gatherer.

 

(iii)

If both a third-party gathering system and a gas gathering system owned by an Affiliate of the Managing General Partner are used by the Partnership, then the Partnership shall pay a competitive fee as described above for the natural gas transported by the segment of the gas gathering system owned by the Managing General Partner’s Affiliate, plus the actual amount charged by the third-party for the natural gas transported by the segment provided by the third-party as described above.

 

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4.04(a)(2)(e). Dealer-Manager Fee. Subject to §3.03(a)(1), the Dealer-Manager shall be paid in cash on each Unit sold to investors:

 

(i)

a 3.0% Dealer-Manager fee; and

 

(ii)

a 7.0% Sales Commission.

Also, an additional 0.5% Sales Commission may be reallowed from the Dealer-Manager fee to the Selling Dealers on the first 100 Units sold in the Partnership.

4.04(a)(2)(f). Drilling and Operating Agreement. The Managing General Partner and its Affiliates shall receive compensation as set forth in the Drilling and Operating Agreement. Notwithstanding anything to the contrary, neither the Managing General Partner nor its Affiliates may profit by drilling in contravention of its fiduciary obligation to the Participants.

4.04(a)(2)(g). Other Transactions. The Managing General Partner and its Affiliates may enter into transactions pursuant to §4.03(d)(7) with the Partnership and shall be entitled to compensation under that section.

4.04(a)(3). Removal of Managing General Partner.

4.04(a)(3)(a). Majority Vote Required to Remove the Managing General Partner. The Managing General Partner may be removed at any time on 60 days’ advance written notice to the outgoing Managing General Partner by the affirmative vote of Participants whose Units equal a majority of the total Units.

If the Participants vote to remove the Managing General Partner from the Partnership, then Participants must elect by an affirmative vote of Participants whose Units equal a majority of the total Units either to:

 

(i)

dissolve, wind-up, and terminate the Partnership; or

 

(ii)

continue as a successor limited partnership under all the terms of this Partnership Agreement as provided in §7.01(c).

If the Participants elect to continue as a successor limited partnership, then the Managing General Partner shall not be removed until a substituted Managing General Partner has been selected by an affirmative vote of Participants whose Units equal a majority of the total Units and installed as such.

4.04(a)(3)(b). Valuation of Managing General Partner’s Interest in the Partnership. If the Managing General Partner is removed, then its interest in the Partnership shall be determined by appraisal by a qualified Independent Expert. The Independent Expert shall be selected by mutual agreement between the removed Managing General Partner and the incoming Managing General Partner. The appraisal shall take into account an appropriate discount, to reflect the risk of recovering natural gas and oil reserves, which shall not be less than that used to calculate the presentment price in the most recent presentment offer under §6.03, if any.

The cost of the appraisal shall be borne equally by the removed Managing General Partner and the Partnership.

4.04(a)(3)(c). Incoming Managing General Partner’s Option to Purchase. The incoming Managing General Partner shall have the option to purchase 20% of the removed Managing General Partner’s interest in the Partnership as Managing General Partner, but not as a Participant, for the value determined by the Independent Expert.

4.04(a)(3)(d). Method of Payment. The method of payment for the removed Managing General Partner’s interest must be fair and protect the solvency and liquidity of the Partnership. The method of payment shall be as follows:

 

(i)

when the termination is voluntary, the method of payment shall be a non-interest bearing unsecured promissory note with principal payable, if at all, from distributions which the Managing General Partner otherwise would have received under this Agreement had the Managing General Partner not been terminated; and

 

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(ii)

when the termination is involuntary, the method of payment shall be an interest bearing unsecured promissory note coming due in no less than five years with equal installments each year. The interest rate shall be that charged on comparable loans.

4.04(a)(3)(e). Termination of Contracts. At the time of its removal, the removed Managing General Partner shall cause, to the extent it is legally possible to do so, its successor to be transferred or assigned all of its rights, obligations and interests as Managing General Partner of the Partnership in contracts entered into by it on behalf of the Partnership. In any event, the removed Managing General Partner shall cause all of its rights, obligations and interests as Managing General Partner of the Partnership in any such contract to terminate at the time of its removal.

4.04(a)(3)(f). The Managing General Partner’s Right to Voluntarily Withdraw. At any time beginning 10 years after the Offering Termination Date and the Partnership’s primary drilling activities, the Managing General Partner may voluntarily withdraw as Managing General Partner on giving 120 days’ prior written notice of withdrawal to the Participants. If the Managing General Partner withdraws, then the following conditions shall apply:

 

(i)

the Managing General Partner’s interest in the Partnership shall be determined as described in §4.04(a)(3)(b) above with respect to removal; and

 

(ii)

the interest shall be distributed to the Managing General Partner as described in §4.04(a)(3)(d)(i) above.

Any successor Managing General Partner shall have the option to purchase 20% of the withdrawing Managing General Partner’s interest in the Partnership at the value determined as described above with respect to removal.

4.04(a)(3)(g). Right of Managing General Partner to Hypothecate Its Interests. The Managing General Partner shall have the authority without the consent of the Participants and without affecting the allocation of costs and revenues incurred or received under this Agreement, to hypothecate, pledge, or otherwise encumber, on any terms it chooses for its own general purposes, either:

 

(i)

its Partnership interest; or

 

(ii)

an undivided interest in the assets of the Partnership equal to or less than its respective interest as Managing General Partner in the revenues of the Partnership.

All repayments of these borrowings and costs, interest or other charges related to the borrowings shall be borne and paid separately by the Managing General Partner. In no event shall the repayments, costs, interest, or other charges related to the borrowing be charged to the account of the Participants.

4.04(a)(3)(h). The Managing General Partner’s Right to Withdraw Property Interest. Subject to a required participation of not less than 1% in the Partnership, unless there is a substituted Managing General Partner, and its subordination obligations under §5.01(b)(4), the Managing General Partner shall have the right to withdraw a property interest held by the Partnership in the form of a Working Interest in the Partnership’s Wells equal to or less than its respective interest as Managing General Partner in the revenues of the Partnership if:

 

(i)

the withdrawal is necessary to satisfy the bona fide request of its creditors; or

 

(ii)

the withdrawal is approved by Participants whose Units equal a majority of the total Units.

If the Managing General Partner withdraws a property interest from the Partnership as described above, then the Managing General Partner shall:

 

(i)

pay all of the expenses of withdrawing; and

 

(ii)

fully indemnify the Partnership against any additional expenses which may result from the withdrawal of its property interest, including insuring that a greater amount of Direct Costs or Administrative Costs is not allocated to the Participants.

 

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4.04(a)(4). Removal of Operator. The Operator may be removed and a new Operator may be substituted at any time on 60 days advance written notice to the outgoing Operator by the Managing General Partner acting on behalf of the Partnership on the affirmative vote of Participants whose Units equal a majority of the total Units.

The Operator shall not be removed until a substituted Operator has been selected by an affirmative vote of Participants whose Units equal a majority of the total Units and installed as such.

4.05. Indemnification and Exoneration.

4.05(a)(1). Standards for the Managing General Partner Not Incurring Liability to the Partnership or Participants. The Managing General Partner, the Operator, and their Affiliates shall not have any liability whatsoever to the Partnership, or to any Participant for any loss suffered by the Partnership or the Participants which arises out of any action or inaction of the Managing General Partner, the Operator, or their Affiliates if:

 

(i)

the Managing General Partner, the Operator, and their Affiliates determined in good faith that the course of conduct was in the best interest of the Partnership;

 

(ii)

the Managing General Partner, the Operator, and their Affiliates were acting on behalf of, or performing services for, the Partnership; and

 

(iii)

the course of conduct did not constitute negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates.

4.05(a)(2). Standards for Managing General Partner Indemnification. The Managing General Partner, the Operator, and their Affiliates shall be indemnified by the Partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the Partnership, provided that:

 

(i)

the Managing General Partner, the Operator, and their Affiliates determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership;

 

(ii)

the Managing General Partner, the Operator, and their Affiliates were acting on behalf of, or performing services for, the Partnership; and

 

(iii)

the course of conduct was not the result of negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates.

Provided, however, payments arising from such indemnification or agreement to hold harmless are recoverable only out of the following:

 

(i)

the Partnership’s tangible net assets, which include its revenues; and

 

(ii)

any insurance proceeds from the types of insurance for which the Managing General Partner, the Operator and their Affiliates may be indemnified under this Agreement.

4.05(a)(3). Standards for Securities Law Indemnification. Notwithstanding anything to the contrary contained in this section, the Managing General Partner, the Operator, and their Affiliates and any person acting as a broker/dealer with respect to the offer or sale of the Units, shall not be indemnified for any losses, liabilities or expenses arising from or out of an alleged violation of federal or state securities laws by such party unless:

 

(i)

there has been a successful adjudication on the merits of each count involving alleged securities law violations as to the particular indemnitee;

 

(ii)

the claims have been dismissed with prejudice on the merits by a court of competent jurisdiction as to the particular indemnitee; or

 

(iii)

a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court

 

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considering the request for indemnification has been advised of the position of the SEC, the Massachusetts Securities Division, and any state securities regulatory authority in which plaintiffs claim they were offered or sold Units with respect to the issue of indemnification for violation of securities laws.

4.05(a)(4). Standards for Advancement of Funds to the Managing General Partner and Insurance. The advancement of Partnership funds to the Managing General Partner, the Operator, or their Affiliates for legal expenses and other costs incurred as a result of any legal action for which indemnification is being sought from the Partnership is permissible only if the Partnership has adequate funds available and the following conditions are satisfied:

 

(i)

the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the Partnership;

 

(ii)

the legal action is initiated by a third-party who is not a Participant, or the legal action is initiated by a Participant and a court of competent jurisdiction specifically approves the advancement; and

 

(iii)

the Managing General Partner or its Affiliates undertake to repay the advanced funds to the Partnership, together with the applicable legal rate of interest thereon, in cases in which such party is found not to be entitled to indemnification.

The Partnership shall not bear the cost of that portion of insurance which insures the Managing General Partner, the Operator, or their Affiliates for any liability for which they could not be indemnified pursuant to §§4.05(a)(1) and 4.05(a)(2).

4.05(b). Liability of Partners. Under the Delaware Revised Uniform Limited Partnership Act, the Investor General Partners are liable jointly and severally for all liabilities and obligations of the Partnership. Notwithstanding the foregoing, as among themselves, the Investor General Partners agree that each shall be solely and individually responsible only for his pro rata share of the liabilities and obligations of the Partnership based on his respective number of Units.

In addition, the Managing General Partner agrees to use its corporate assets to indemnify each of the Investor General Partners against all Partnership related liabilities which exceed the Investor General Partner’s interest in the undistributed net assets of the Partnership and insurance proceeds, if any. Further, the Managing General Partner agrees to indemnify each Investor General Partner against any personal liability as a result of the unauthorized acts of another Investor General Partner.

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

4.05(c). Order of Payment of Claims. Claims shall be paid as follows:

 

(i)

first, out of any insurance proceeds;

 

(ii)

second, out of Partnership assets and revenues; and

 

(iii)

last, by the Managing General Partner as provided in §§3.05(b)(2) and (3) and 4.05(b).

No Limited Partner shall be required to reimburse the Managing General Partner, the Operator, their Affiliates, or the Investor General Partners for any liability in excess of his agreed Capital Contribution, except:

 

(i)

for a liability resulting from the Limited Partner’s unauthorized participation in management of the Partnership; or

 

(ii)

from some other breach by the Limited Partner of this Agreement.

 

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4.05(d). Authorized Transactions Are Not Deemed to Be a Breach. No transaction entered into or action taken by the Partnership, or by the Managing General Partner, the Operator, or their Affiliates, which is authorized by this Agreement shall be deemed a breach of any obligation owed by the Managing General Partner, the Operator, or their Affiliates to the Partnership or the Participants.

4.06. Other Activities.

4.06(a). The Managing General Partner May Pursue Other Natural Gas and Oil Activities for Its Own Account. The Managing General Partner, the Operator, and their Affiliates are now engaged, and will engage in the future, for their own account and for the account of others, including other investors, in all aspects of the natural gas and oil business. This includes without limitation, the evaluation, acquisition, and sale of producing and nonproducing Leases, and the exploration for and production of natural gas, oil and other minerals.

The Managing General Partner is required to devote only so much of its time to the Partnership as it determines in its sole discretion, but consistent with its fiduciary duties, is necessary to manage the affairs of the Partnership. Except as expressly provided to the contrary in this Agreement, and subject to fiduciary duties, the Managing General Partner, the Operator, and their Affiliates may do the following:

 

(i)

continue their activities, or initiate further such activities, individually, jointly with others, or as a part of any other limited or general partnership, tax partnership, joint venture, or other entity or activity to which they are or may become a party, in any locale and in the same fields, areas of operation or prospects in which the Partnership may likewise be active;

 

(ii)

reserve partial interests in Leases being assigned to the Partnership or any other interests not expressly prohibited by this Agreement;

 

(iii)

deal with the Partnership as independent parties or through any other entity in which they may be interested;

 

(iv)

conduct business with the Partnership as set forth in this Agreement; and

 

(v)

participate in such other investor operations, as investors or otherwise.

The Managing General Partner and its Affiliates shall not be required to permit the Partnership or the Participants to participate in or share in any profits or other benefits from any of the other operations in which the Managing General Partner and its Affiliates may be interested as permitted under this section. However, except as otherwise provided in this Agreement, the Managing General Partner and its Affiliates may pursue business opportunities that are consistent with the Partnership’s investment objectives for their own account only after they have determined that the opportunity either:

 

(i)

cannot be pursued by the Partnership because of insufficient funds; or

 

(ii)

it is not appropriate for the Partnership under the existing circumstances.

4.06(b). Managing General Partner May Manage Multiple Partnerships. The Managing General Partner or its Affiliates may manage multiple Programs simultaneously.

4.06(c). Partnership Has No Interest in Natural Gas Contracts or Pipelines and Gathering Systems. Notwithstanding any other provision in this Agreement, the Partnership shall not:

 

(i)

be a party to any natural gas supply agreement that the Managing General Partner, the Operator, or their Affiliates enter into with an Affiliate of the Managing General Partner or an independent third-party or have any rights pursuant to such natural gas supply agreement;

 

(ii)

receive any interest in the Managing General Partner’s, the Operator’s and their Affiliates’ natural gas pipeline and gathering systems, transporting or purchase contracts or processing and compression facilities; or

 

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(iii)

receive any interest in the Managing General Partner’s, the Operator’s and their Affiliates’ natural gas hedging arrangements or other contracts (except as permitted in the Managing General Partner’s sole discretion). Notwithstanding, the Partnership may enter into its own agreements and financial instruments relating to hedging up to 50% of its natural gas and oil production and pledging up to 100% of its assets and reserves therefore.

ARTICLE V

PARTICIPATION IN COSTS AND REVENUES,

CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS

5.01. Participation in Costs and Revenues. Except as otherwise provided in this Agreement, costs and revenues of the Partnership shall be charged and credited to the Managing General Partner and the Participants as set forth in this section and its subsections.

5.01(a). Costs. Costs shall be charged as set forth below.

5.01(a)(1). Organization and Offering Costs. Organization and Offering Costs shall be charged 100% to the Managing General Partner. For purposes of sharing in revenues under §5.01(b)(4), the Managing General Partner shall be credited with Organization and Offering Costs paid by it and for services provided by it as Organization Costs up to an amount equal to 15% of the Partnership’s subscription proceeds. Any Organization and Offering Costs paid and/or provided in services by the Managing General Partner in excess of this amount shall not be credited towards the Managing General Partner’s required Capital Contribution or revenue share set forth in §5.01(b)(4). The Managing General Partner’s credit for services provided to the Partnership as Organization Costs shall be determined based on generally accepted accounting principles.

5.01(a)(2). Intangible Drilling Costs. The Partnership’s subscription proceeds received from the Participants shall be used by the Partnership to pay 100% of the Partnership’s Intangible Drilling Costs as provided in Section 5.01(a)(5).

5.01(a)(3). Tangible Costs. The Partnership’s subscription proceeds received from the Participants shall be used by the Partnership to pay 100% of the Partnership’s Tangible Costs as provided in Section 5.01(a)(5).

5.01(a)(4). Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating Costs, Direct Costs, Administrative Costs, and all other Partnership costs not specifically allocated shall be charged to the parties in the same ratio as the related production revenues are being credited.

5.01(a)(5). Allocation of Intangible Drilling Costs and Tangible Costs at Partnership Closings. Intangible Drilling Costs and Tangible Costs of a well or wells to be drilled and completed with the proceeds of a Partnership closing shall be charged 100% to the Participants who are admitted to the Partnership in that closing and shall not be reallocated to take into account other Partnership closings.

Although the subscription proceeds received by the Partnership in each closing may be used to pay the costs of drilling different wells, the same percentages of each Participant’s subscription proceeds shall be applied to Intangible Drilling Costs and Tangible Costs regardless of when the Participant is admitted to the Partnership. Subject to the foregoing, the Managing General Partner shall have the right to revise the allocation of a well’s costs between Intangible Drilling Costs and Tangible Costs based on the actual costs of drilling and completing the well, rather than the initial estimate of those costs by the Managing General Partner before the wells were drilled.

5.01(a)(6). Lease Costs. The Leases shall be contributed to the Partnership by the Managing General Partner as set forth in §4.01(a)(4).

 

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5.01(b). Revenues. Revenues shall be credited as set forth below.

5.01(b)(1). Allocation of Revenues on Disposition of Property. If the parties’ Capital Accounts are adjusted to reflect the simulated depletion of a natural gas or oil property of the Partnership, then the portion of the total amount realized by the Partnership on the taxable disposition of the property that represents recovery of its simulated tax basis in the property shall be allocated to the parties in the same proportion as the aggregate adjusted tax basis of the property was allocated to the parties or their predecessors in interest. If the parties’ Capital Accounts are adjusted to reflect the actual depletion of a natural gas or oil property of the Partnership, then the portion of the total amount realized by the Partnership on the taxable disposition of the property that equals the parties’ aggregate remaining adjusted tax basis in the property shall be allocated to the parties in proportion to their respective remaining adjusted tax bases in the property. Thereafter, any excess shall be allocated to the Managing General Partner in an amount equal to the difference between the fair market value of the Lease at the time it was contributed to the Partnership and its simulated or actual adjusted tax basis at that time. Finally, any excess shall be credited as provided in §5.01(b)(4), below.

In the event of the Partnership’s sale of developed natural gas and oil properties with equipment on the properties, the Managing General Partner may make any reasonable allocation of the sales proceeds between the equipment and the Leases.

5.01(b)(2). Interest. Interest earned on each Participant’s subscription proceeds under §3.05(b)(1) shall be credited to the accounts of the respective subscribers who paid the subscription proceeds to the Partnership. The interest shall be paid to the Participants not later than the Partnership’s first cash distribution from operations.

After the Offering Termination Date and until proceeds from the offering are invested in the Partnership’s natural gas and oil operations, any interest income from temporary investments shall be allocated pro rata to the Participants providing the subscription proceeds.

All other interest income, including interest earned on the deposit of production revenues, shall be credited as provided in §5.01(b)(4), below.

5.01(b)(3). Sale or Disposition of Equipment. Proceeds from the sale or disposition of equipment shall be credited to the parties charged with the costs of the equipment in the ratio in which the costs were charged.

5.01(b)(4). Other Revenues. Subject to §5.01(b)(4)(a), the Managing General Partner and the Participants shall share in all other Partnership revenues in the same percentage as their respective Capital Contribution bears to the Partnership’s total Capital Contributions, except that the Managing General Partner shall receive an additional 8% of Partnership revenues. For example, if the Managing General Partner contributes 15% of the Partnership’s total Capital Contributions and the Participants contribute 85% of the Partnership’s total Capital Contributions, then the Managing General Partner would receive 23% of the Partnership revenues and the Participants would receive 77% of the Partnership revenues.

5.01(b)(4)(a). Subordination. The Managing General Partner shall subordinate up to 60% of its share of Partnership Net Production Revenues to the receipt by Participants, regardless of the actual subscription price they paid for their Units, of cumulative cash distributions from the Partnership equal to $1,000 per Unit (10% of $10,000 per Unit) during each of the Partnership’s first five consecutive 12-month subordination periods and $750 per Unit (7.5% of $10,000 per Unit) during each of the Partnership’s sixth, seventh and eighth consecutive 12- month subordination periods, as set forth below. In this regard:

 

(i)

all Partnership distributions of cash from the Partnership’s natural gas and oil operations to the Participants before the first 12-month subordination period begins shall be included in the Participants’ cumulative cash distributions from the Partnership for all purposes of this §5.01(b)(4)(a), and, for example, shall be added to the Participants’ other cash distributions from the Partnership during the Partnership’s aggregate 96-month subordination period to determine whether the Participants’ received the specified returns of capital set forth above in each of the Partnership’s eight consecutive 12-month subordination periods;

 

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(ii)

the aggregate 96-month subordination period shall begin on the earlier of:

 

a.

when the Partnership begins receiving production revenues from the sale of natural gas or oil from all of its productive wells; or

 

b.

twelve (12) months after the Offering Termination Date;

 

(iii)

subordination distributions, if any, shall be determined and made at the time of each subsequent distribution of revenues to the Participants; and

 

(iv)

the Managing General Partner shall not subordinate more than 60% of its share of Partnership Net Production Revenues in any 12-month subordination period.

The Managing General Partner’s subordination obligation shall be determined by:

 

(i)

carrying forward to subsequent 12-month subordination periods the amount, if any, by which cumulative cash distributions to Participants, including any subordination payments, are less than:

 

(a)

$1,000 per Unit (10% of $10,000 per Unit) in the first 12-month period;

 

(b)

$2,000 per Unit (20% of $10,000 per Unit) in the second 12-month period;

 

(c)

$3,000 per Unit (30% of $10,000 per Unit) in the third 12-month period;

 

(d)

$4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month period;

 

(e)

$5,000 per Unit (50% of $10,000 per Unit) in the fifth 12-month subordination period;

 

(f)

$5,750 per Unit (57.5% of $10,000 per Unit) in the sixth 12-month period;

 

(g)

$6,500 per Unit (65% of $10,000 per Unit) in the seventh 12-month period; or

 

(h)

$7,250 per Unit (72.5% of $10,000 per Unit) in the eighth 12-month period (no carry forward is required if the Participant’s cumulative cash distributions are less than $7,250 per Unit (72.5% of $10,000 per Unit) in the eighth 12-month period, because the Managing General Partner’s subordination obligation terminates on the expiration of the eighth 12-month period).

 

(ii)

reimbursing the Managing General Partner for any previous subordination payments to the extent cumulative cash distributions to Participants, including any subordination payments, would exceed:

 

(a)

$1,000 per Unit (10% of $10,000 per Unit) in the first 12-month period;

 

(b)

$2,000 per Unit (20% of $10,000 per Unit) in the second 12-month period;

 

(c)

$3,000 per Unit (30% of $10,000 per Unit) in the third 12-month period;

 

(d)

$4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month period;

 

(e)

$5,000 per Unit (50% of $10,000 per Unit) in the fifth 12-month period;

 

(f)

$5,750 per Unit (57.5% of $10,000 per Unit) in the sixth 12-month period;

 

(g)

$6,500 per Unit (65% of $10,000 per Unit) in the seventh 12-month period; or

 

(h)

$7,250 per Unit (72.5% of $10,000 per Unit) in the eighth 12-month period.

The Managing General Partner’s subordination obligation also shall be subject to the following conditions:

 

(i)

the subordination obligation may be prorated in the Managing General Partner’s discretion (e.g. in the case of a monthly distribution the Managing General Partner shall not have any subordination obligation if the cumulative monthly distributions to Participants equal $83.33 per Unit (8.333% of $1,000 per Unit) or more during any of the first five 12-month subordination periods, assuming there are no subordination distributions owed for any preceding period);

 

(ii)

the Managing General Partner shall not be required to return Partnership distributions previously received by it, even though a subordination obligation arises after the distributions;

 

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(iii)

subject to the foregoing provisions of this section, only Partnership revenues in the current distribution period shall be debited or credited to the Managing General Partner as may be necessary to provide, to the extent possible, subordination distributions to the Participants and reimbursements to the Managing General Partner;

 

(iv)

no subordination distributions to the Participants or reimbursements to the Managing General Partner shall be made after the expiration of the eighth 12-month subordination period; and

 

(v)

subordination payments to the Participants shall be subject to any lien or priority granted by the Managing General Partner and/or its Affiliates to its lenders, whether granted before or after the subordination obligation arose.

5.01(b)(5). Commingling of Revenues From All Partnership Wells. The revenues from all Partnership wells shall be commingled, so regardless of when a Participant subscribes for Units or is admitted to the Partnership, he will share in the Partnership’s revenues from all of its wells on the same basis as the other Participants.

5.01(c). Allocations.

5.01(c)(1). Allocations among Participants. Except as provided otherwise in this Agreement, costs (other than Intangible Drilling Costs and Tangible Costs) and revenues charged or credited to the Participants as a group, which includes all revenue credited to the Participants under §5.01(b)(4), shall be allocated among the Participants, including the Managing General Partner to the extent of any optional subscription for Units under §3.03(b)(1), in the ratio of their respective Units based on $10,000 per Unit regardless of the actual subscription price paid by a Participant for his Units.

Intangible Drilling Costs and Tangible Costs charged to the Participants as a group shall be allocated among the Participants, including the Managing General Partner to the extent of any optional subscription for Units under §3.03(b)(1), in the ratio of the subscription amount designated on their respective Subscription Agreements rather than the number of their respective Units.

5.01(c)(2). Costs and Revenues Not Directly Allocable to a Partnership Well. Costs and revenues not directly allocable to a particular Partnership Well or additional operation shall be allocated among the Partnership Wells or additional operations in any manner the Managing General Partner in its reasonable discretion, shall select, and shall then be charged or credited in the same manner as costs or revenues directly applicable to the Partnership Well or additional operation are being charged or credited.

5.01(c)(3). Managing General Partner’s Discretion in Making Allocations For Federal Income Tax Purposes. In determining the proper method of allocating charges or credits among the parties, allocating any item of income, gain, loss, deduction or credit pursuant to new laws or new IRS or judicial interpretations of existing law, allocating any other item that is not otherwise specifically allocated in this Agreement or is subsequently determined by the Managing General Partner to be clearly inconsistent with a party’s economic interest in the Partnership, or making any other allocations under this Agreement, the Managing General Partner may adopt any method of allocation that it selects, in its sole discretion, after consultation with the Partnership’s legal counsel or accountants. Any new allocation provisions shall be made in a manner that is consistent with the parties’ economic interests in the Partnership and will result in the most favorable aggregate consequences to the Participants that are, as nearly as possible, consistent with the original allocations described in this Agreement.

5.02. Capital Accounts and Allocations Thereto.

5.02(a). Capital Accounts for Each Party to this Agreement. A single, separate Capital Account shall be established for each party, regardless of the number of interests owned by the party, the class of the interests and the time or manner in which the interests were acquired.

5.02(b). Charges and Credits.

 

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5.02(b)(1). General Standard. Except as otherwise provided in this Agreement, the Capital Account of each party shall be determined and maintained in accordance with Treas. Reg. §1.704-l(b)(2)(iv) and shall be increased by:

 

(i)

the amount of money contributed by him to the Partnership;

 

(ii)

the fair market value of property contributed by him to the Partnership, without regard to §7701(g) of the Code, net of liabilities secured by the contributed property that the Partnership is considered to assume or take subject to under §752 of the Code; and

 

(iii)

allocations to him of Partnership income and gain, or items thereof, including income and gain exempt from tax and income and gain described in Treas. Reg. §1.704-l(b)(2)(iv)(g), but excluding income and gain described in Treas. Reg. §1.704-l(b)(4)(i);

and shall be decreased by:

 

(iv)

the amount of money distributed to him by the Partnership;

 

(v)

the fair market value of property distributed to him by the Partnership, without regard to §7701(g) of the Code, net of liabilities secured by the distributed property that he is considered to assume or take subject to under §752 of the Code;

 

(vi)

allocations to him of Partnership expenditures described in §705(a)(2)(B) of the Code; and

 

(vii)

allocations to him of Partnership loss and deduction, or items thereof, including loss and deduction described in Treas. Reg. §1.704-l(b)(2)(iv)(g), but excluding items described in (vi) above, and loss or deduction described in Treas. Reg. §1.704-l(b)(4)(i) or (iii).

5.02(b)(2). Exception. If Treas. Reg. §1.704-l(b)(2)(iv) fails to provide guidance, Capital Account adjustments shall be made in a manner that:

 

(i)

maintains equality between the aggregate governing Capital Accounts of the parties and the amount of Partnership capital reflected on the Partnership’s balance sheet, as computed for book purposes;

 

(ii)

is consistent with the underlying economic arrangement of the parties; and

 

(iii)

is based, wherever practicable, on federal tax accounting principles.

5.02(c). Payments to the Managing General Partner. The Capital Account of the Managing General Partner shall be reduced by payments to it pursuant to §4.04(a)(2) only to the extent of the Managing General Partner’s distributive share of any Partnership deduction, loss, or other downward Capital Account adjustment resulting from the payments. Also, in the event, and to the extent, that the Managing General Partner is treated under the Code as having been transferred an interest in the Partnership in connection with the performance of services for the Partnership (whether before or after the formation of the Partnership):

 

(i)

any resulting compensation income shall be allocated 100% to the Managing General Partner;

 

(ii)

any associated increase in Capital Accounts shall be credited 100% to the Managing General Partner; and

 

(iii)

any associated deduction to which the Partnership is entitled shall be allocated 100% to the Managing General Partner.

5.02(d). Discretion of Managing General Partner in the Method of Maintaining Capital Accounts. Notwithstanding any other provisions of this Agreement, the method of maintaining Capital Accounts may be changed from time to time, in the discretion of the Managing General Partner, to take into consideration §704 and other provisions of the Code and the related rules, regulations and interpretations as may exist from time to time.

 

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5.02(e). Revaluations of Property. In the discretion of the Managing General Partner the Capital Accounts of the parties may be increased or decreased to reflect a revaluation of Partnership property, including intangible assets such as goodwill, on a property-by-property basis except as otherwise permitted under §704(c) of the Code and the regulations thereunder, on the Partnership’s books, in accordance with Treas. Reg. §1.704-l(b)(2)(iv)(f).

5.02(f). Amount of Book Items. In cases where §704(c) of the Code or §5.02(e) applies, Capital Accounts shall be adjusted in accordance with Treas. Reg. §1.704-l(b)(2)(iv)(g) for allocations of depreciation, depletion, amortization and gain and loss, as computed for book purposes, with respect to the property.

5.03. Allocation of Income, Deductions and Credits.

5.03(a). In General.

5.03(a)(1). Deductions Are Allocated to Party Charged with Expenditure. To the extent permitted by law and except as otherwise provided in this Agreement, all deductions and credits, including, but not limited to, intangible drilling and development costs and depreciation, shall be allocated to the party who has been charged with the expenditure giving rise to the deductions and credits; and to the extent permitted by law, these parties shall be entitled to the deductions and credits in computing taxable income or tax liabilities to the exclusion of any other party. Also, any Partnership deductions that would be nonrecourse deductions if they were not attributable to a loan made or guaranteed by the Managing General Partner or its Affiliates shall be allocated to the Managing General Partner to the extent required by law.

5.03(a)(2). Income and Gain Allocated in Accordance With Revenues. Except as otherwise provided in this Agreement, all items of income and gain, including gain on disposition of assets, shall be allocated in accordance with the related revenue allocations set forth in §5.01(b) and its subsections.

5.03(b). Tax Basis of Each Property. Subject to §704(c) of the Code, the tax basis of each oil and gas property for computation of cost depletion and gain or loss on disposition shall be allocated and reallocated when necessary based on the capital interest in the Partnership as to the property and the capital interest in the Partnership for this purpose as to each property shall be considered to be owned by the parties in the ratio in which the expenditure giving rise to the tax basis of the property has been charged as of the end of the year.

5.03(c). Gain or Loss on Oil and Gas Properties. Each party shall separately compute its gain or loss on the disposition of each natural gas and oil property in accordance with the provisions of §613A(c)(7)(D) of the Code, and the calculation of the gain or loss shall consider the party’s adjusted basis in his property interest computed as provided in §5.03(b) and the party’s allocable share of the amount realized from the disposition of the property.

5.03(d). Gain on Depreciable Property. Gain from each sale or other disposition of depreciable property shall be allocated to each party whose share of the proceeds from the sale or other disposition exceeds its contribution to the adjusted basis of the property in the ratio that the excess bears to the sum of the excesses of all parties having an excess.

5.03(e). Loss on Depreciable Property. Loss from each sale, abandonment or other disposition of depreciable property shall be allocated to each party whose contribution to the adjusted basis of the property exceeds its share of the proceeds from the sale, abandonment or other disposition in the proportion that the excess bears to the sum of the excesses of all parties having an excess.

5.03(f). Allocation If Recapture Treated As Ordinary Income. Any recapture treated as an increase in ordinary income by reason of §§1245, 1250 or 1254 of the Code shall be allocated to the parties in the amounts in which the recaptured items were previously allocated to them; provided that to the extent recapture allocated to any party is in excess of the party’s gain from the disposition of the property, the excess shall be allocated to the other parties but only to the extent of the other parties’ gain from the disposition of the property.

 

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5.03(g). Tax Credits. If a Partnership expenditure, whether or not deductible, that gives rise to a tax credit in a Partnership taxable year also gives rise to valid allocations of Partnership loss or deduction, or other downward Capital Account adjustments, for the year, then the parties’ interests in the Partnership with respect to the credit, or the cost giving rise thereto, shall be in the same proportion as the parties’ respective distributive shares of the loss or deduction, and adjustments. If Partnership receipts, whether or not taxable, that give rise to a tax credit, including a marginal well production credit under §45I of the Code, in a Partnership taxable year also give rise to valid allocations of Partnership income or gain, or other upward Capital Account adjustments, for the year, then the parties’ interests in the Partnership with respect to the credit, or the Partnership’s receipts or production of natural gas and oil production giving rise thereto, shall be in the same proportion as the parties’ respective shares of the Partnership’s production revenues from the sales of its natural gas and oil production as provided in §5.01(b)(4).

5.03(h). Deficit Capital Accounts and Qualified Income Offset. Notwithstanding any provision of this Agreement to the contrary, an allocation of loss or deduction which would result in a party having a deficit Capital Account balance as of the end of the taxable year to which the allocation relates, if charged to the party, to the extent the Participant is not required to restore the deficit to the Partnership, taking into account:

 

(i)

adjustments that, as of the end of the year, reasonably are expected to be made to the party’s Capital Account for depletion allowances with respect to the Partnership’s natural gas and oil properties;

 

(ii)

allocations of loss and deduction that, as of the end of the year, reasonably are expected to be made to the party under §§704(e)(2) and 706(d) of the Code and Treas. Reg. §1.751-1(b)(2)(ii); and

 

(iii)

distributions that, as of the end of the year, reasonably are expected to be made to the party to the extent they exceed offsetting increases to the party’s Capital Account, assuming for this purpose that the fair market value of Partnership property equals its adjusted tax basis, that reasonably are expected to occur during or prior to the Partnership taxable years in which the distributions reasonably are expected to be made;

shall be charged to the Managing General Partner. Further, the Managing General Partner shall be credited with an additional amount of Partnership income or gain equal to the amount of the loss or deduction as quickly as possible to the extent that the chargeback does not cause or increase deficit balances in the parties’ Capital Accounts which are not required to be restored to the Partnership.

Notwithstanding any provision of this Agreement to the contrary, if a party unexpectedly receives an adjustment, allocation, or distribution described in (i), (ii), or (iii) above, or any other distribution, which causes or increases a deficit balance in the party’s Capital Account which is not required to be restored to the Partnership, the party shall be allocated items of income and gain, consisting of a pro rata portion of each item of Partnership income, including gross income and gain for the year, in an amount and manner sufficient to eliminate the deficit balance as quickly as possible.

5.03(i). Minimum Gain Chargeback. To the extent there is a net decrease during a Partnership taxable year in the minimum gain attributable to a Partner nonrecourse debt, then any Partner with a share of the minimum gain attributable to the debt at the beginning of the year shall be allocated items of Partnership income and gain in accordance with Treas. Reg. §1.704-2(i).

5.03(j). Partners’ Allocable Shares. Except as otherwise provided in this Agreement, the Partners agree that each party’s allocable share of Partnership income, gain, loss, deductions and credits shall be determined for a taxable year of the Partnership by using any method that is prescribed or permitted by the Secretary of the Treasury by regulations or other guidelines and selected for that taxable year by the Managing General Partner which takes into account the varying interests of the parties in the Partnership during the taxable year. In the absence of those regulations or guidelines, except as otherwise provided in this Agreement, the allocable share shall be based on actual income, gain, loss, deductions and credits economically accrued each day during the taxable year in proportion to each party’s varying interest in the Partnership on each day during the taxable year.

 

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5.03(k). Contingent Income. Subject to §5.04(d), if it is determined that any taxable income results to any party by reason of its entitlement to a share of capital of the Partnership, or a share of profits or revenues of the Partnership before the profit or revenue has been realized by the Partnership, the resulting deduction, as well as any resulting gain, shall not enter into Partnership net income or loss, but shall be separately allocated to that party.

5.04. Elections.

5.04(a). Election to Deduct Intangible Costs. The Partnership’s federal income tax return shall be made in accordance with an election under the option granted by the Code to deduct intangible drilling and development costs.

5.04(b). No Election Out of Subchapter K. No election shall be made by the Partnership, any Partner, or the Operator for the Partnership to be excluded from the application of the partnership provisions of the Code, including Subchapter K of Chapter 1 of Subtitle A of the Code.

5.04(c). §754 Election. In the event of the transfer of an interest in the Partnership, or on the death of an individual party hereto, or in the event of the distribution of property to any party, the Managing General Partner may choose for the Partnership to file an election in accordance with the applicable Treasury Regulations to cause the basis of the Partnership’s assets to be adjusted for federal income tax purposes as provided by §§734 and 743 of the Code.

5.04(d). §83 Election. The Partnership, the Managing General Partner and each Participant hereby agree to be legally bound by the provisions of this §5.04(d) and further agree that, in the Managing General Partner’s sole discretion, the Partnership and all of its Partners may elect a safe harbor under which the fair market value of a Partnership interest that is transferred in connection with the performance of services is treated as being equal to the liquidation value of that interest for transfers on or after the date final regulations providing the safe harbor are published in the Federal Register. If the Managing General Partner determines that the Partnership and all of its Partners will elect the safe harbor, which determination may be made solely in the best interests of the Managing General Partner, the Partnership, the Managing General Partner and each Participant further agree that:

 

(i)

the Partnership shall be authorized and directed to elect the safe harbor;

 

(ii)

the Partnership and each of its Partners (including any Person to whom a Partnership interest is transferred in connection with the performance of services) shall comply with all requirements of the safe harbor with respect to all Partnership interests transferred in connection with the performance of services while the election remains effective; and

 

(iii)

the Managing General Partner, in its sole discretion, may cause the Partnership to terminate the safe harbor election, which determination may be made in the sole interests of the Managing General Partner.

5.05. Distributions.

5.05(a). In General.

5.05(a)(1). Monthly Review of Accounts. The Managing General Partner shall review the accounts of the Partnership at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any.

5.05(a)(2). Distributions. Except as otherwise provided in this Agreement, the Partnership shall distribute funds to the Managing General Partner and the Participants allocated to their respective accounts that the Managing General Partner deems unnecessary for the Partnership to retain.

 

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5.05(a)(3). No Borrowings. In no event shall funds be advanced or borrowed by the Partnership for distributions to the Managing General Partner and the Participants if the amount of the distributions would exceed the Partnership’s accrued and received revenues for the previous four quarters, less paid and accrued Operating Costs with respect to the revenues. The determination of revenues and costs shall be made in accordance with generally accepted accounting principles, consistently applied.

5.05(a)(4). Distributions to the Managing General Partner. Cash distributions from the Partnership to the Managing General Partner shall only be made as follows:

 

(i)

in conjunction with distributions to Participants; and

 

(ii)

out of funds properly allocated to the Managing General Partner’s account.

5.05(a)(5). Reserve. At any time after one year from the date each Partnership Well is placed into production, the Managing General Partner shall have the right to deduct each month from the Partnership’s net sales proceeds from the sale of the natural gas and oil production from each of its productive wells up to $200 per well for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the well. All of these funds shall be deposited in a separate interest bearing account for the benefit of the Partnership, and the total amount so retained and deposited shall not exceed the Managing General Partner’s reasonable estimate of the costs to plug and abandon the well.

5.05(b). Distribution of Uncommitted Subscription Proceeds. Any subscription proceeds not expended or committed for expenditure, as evidenced by a written agreement, by the Partnership within 12 months of the Offering Termination Date, except necessary operating capital, shall be distributed to the Participants in the ratio that the subscription amount designated on each Participant’s Subscription Agreement bears to the total subscription amounts designated on all of the Participants’ Subscription Agreements, as a return of capital. The Managing General Partner shall reimburse the Participants for the selling or other offering expenses, if any, allocable to the return of capital.

For purposes of this subsection, “committed for expenditure” shall mean contracted for, actually earmarked for or allocated by the Managing General Partner to the Partnership’s drilling operations, and “necessary operating capital” shall mean those funds which, in the opinion of the Managing General Partner, should remain on hand to assure continuing operation of the Partnership.

5.05(c). Distributions on Winding Up. On the winding up of the Partnership distributions shall be made as provided in Section7.02.

5.05(d). Interest and Return of Capital. No party shall under any circumstances be entitled to any interest on amounts retained by the Partnership. Each Participant shall look only to his share of distributions, if any, from the Partnership for a return of his Capital Contribution.

ARTICLE VI

TRANSFER OF UNITS

6.01. Transferability of Units. A Participant’s transfer of a portion or all his Units, or any interest in his Units, is subject to all of the provisions of this Article VI. For purposes of this Article VI, the term “transfer” shall include any sale, exchange, gift, assignment, pledge, mortgage, hypothecation, redemption or other form of transfer of a Unit, or any interest in a Unit, by a Participant (which may include the Managing General Partner or its Affiliates, if they purchase Units) or by operation of law, including any transfers of Units which a Participant presents to the Managing General Partner for purchase under §6.03.

6.01(a). Rights of Assignee. Unless a transferee of a Participant’s Unit becomes a substitute Participant with respect to that Unit in accordance with the provisions of §6.02(a)(3)(a), he shall not be entitled to any of the rights granted to a Participant under this Agreement, other than the right to receive all or part of the share of the

 

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profits, losses, income, gains, deductions, credits and depletion allowances, or items thereof, and cash distributions or returns of capital to which his transferor would otherwise be entitled under this Agreement.

6.01(b). Conversion of Investor General Partner Units to Limited Partner Units.

6.01(b)(1). Automatic Conversion. After all of the Partnership Wells have been drilled and completed, as determined by the Managing General Partner, the Managing General Partner shall file an amended certificate of limited partnership with the Secretary of State of the State of Delaware for the purpose of converting the Investor General Partner Units to Limited Partner Units. In this regard, a well shall be deemed to be completed when production equipment is installed on a well, even though the well may not yet be connected to a pipeline for production of natural gas in the case of a natural gas well.

6.01(b)(2). Investor General Partners Shall Have Contingent Liability. On conversion the Investor General Partners shall be Limited Partners entitled to limited liability; however, they shall remain liable to the Partnership for any additional Capital Contribution required for their proportionate share of any Partnership obligation or liability arising before the conversion of their Units as provided in §3.05(b)(2).

6.01(b)(3). Conversion Shall Not Affect Allocations. The conversion shall not affect the allocation to any Participant of any item of Partnership income, gain, loss, deduction or credit or other item of special tax significance other than Partnership liabilities, if any. Further, the conversion shall not affect any Participant’s interest in the Partnership’s natural gas and oil properties and unrealized receivables.

6.01(b)(4). Right to Convert if Reduction of Insurance. Notwithstanding the foregoing, the Managing General Partner shall notify all Participants at least 30 days before the effective date of any material adverse change in the Partnership’s insurance coverage. If the insurance coverage is to be materially reduced, then the Investor General Partners shall have the right to convert their Units into Limited Partner Units before the reduction by giving written notice to the Managing General Partner.

6.02. Special Restrictions on Transfers of Units by Participants.

6.02(a). In General. Transfers of Units by Participants are subject to the following general conditions:

 

(i)

except as provided by operation of law:

 

(a)

only whole Units may be transferred unless the Participant owns less than a whole Unit, in which case his entire fractional interest must be transferred; and

 

(b)

Units may not be transferred to a person who is under the age of 18 or incompetent (unless an attorney-in-fact, guardian, custodian or conservator has been appointed to handle the affairs of that person or the Units) without the Managing General Partner’s consent;

 

(ii)

the costs and expenses associated with the transfer must be paid by the assignor Participant;

 

(iii)

the transfer documents must be in a form satisfactory to the Managing General Partner; and

 

(iv)

the terms of the transfer must not contravene those of this Agreement.

Transfers of Units by Participants are subject to the following additional restrictions set forth in §§6.02(a)(1) and 6.02(a)(2).

6.02(a)(1). Tax Law Restrictions. Subject to transfers permitted by §6.03 and transfers by operation of law, no transfer of a Unit by a Participant shall be made which, in the opinion of counsel to the Partnership, would result in the Partnership being either:

 

(i)

terminated for tax purposes under §708 of the Code; or

 

(ii)

treated as a “publicly-traded” partnership for purposes of §469(k) of the Code.

 

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6.02(a)(2). Securities Laws Restriction. Subject to transfers permitted by §6.03 and transfers by operation of law, no Unit shall be transferred by a Participant unless there is either:

 

(i)

an effective registration of the Unit under the Securities Act of 1933, as amended, and qualification under applicable state securities laws; or

 

(ii)

an opinion of counsel acceptable to the Managing General Partner that the registration and qualification of the Unit is not required, unless this requirement is waived by the Managing General Partner.

Transfers of Units by Participants are also subject to any conditions contained in the Subscription Agreement and Exhibit (B) to the Prospectus.

6.02(a)(3). Substitute Participant.

6.02(a)(3)(a). Procedure to Become Substitute Participant. Subject to §§6.02(a)(1) and 6.02(a)(2), a transferee of a Participant’s Unit shall become a substitute Participant entitled to all the rights of a Participant if, and only if:

 

(i)

the transferor gives the transferee the right;

 

(ii)

the transferee pays to the Partnership all costs and expenses incurred by the Partnership in connection with the substitution; and

 

(iii)

the transferee executes and delivers the instruments necessary to establish that a legal transfer has taken place and to confirm the agreement of the transferee to be bound by all of the terms of this Agreement, in a form acceptable to the Managing General Partner.

6.02(a)(3)(b). Rights of Substitute Participant. A substitute Participant shall be entitled to all of the rights attributable to full ownership of the assigned Units including the right to vote.

6.02(b). Effect of Transfer.

6.02(b)(1). Amendment of Records. The Partnership shall amend its records at least once each calendar quarter to effect the substitution of substitute Participants.

Any transfer of a Unit by a Participant which is permitted under this Article VI, when the transferee does not become a substitute Participant, shall be effective as of midnight of the last day of the calendar month in which it is made.

6.02(b)(2). A Transfer of Units Does Not Relieve the Transferor of Certain Costs. No transfer of a Unit by a Participant, including a transfer of less than all of a Participant’s Units or the transfer of a Participant’s Units to more than one party, shall relieve the transferor of its responsibility for its proportionate part of any expenses, obligations and liabilities under this Agreement related to the Units so transferred, whether arising before or after the transfer.

6.02(b)(3). A Transfer of Units Does Not Require A Partnership Accounting. No transfer of a Unit by a Participant shall require an accounting of the Partnership. Also, no transfer of a Unit shall grant rights under this Agreement, including the exercise of any elections, as between the transferring Participant and the Partnership, the Managing General Partner and the remaining Participants to more than one Person unanimously designated by the transferee(s) of the Unit, and, if he has retained an interest in the transferred Unit, the transferor of the Unit.

6.02(b)(4). Required Notice to Managing General Partner of Transfer of Units. Until the Managing General Partner receives from the transferring Participant a written notice in a form acceptable to the Managing General Partner that designates the transferee(s) of a Unit, the Managing General Partner shall continue to account only to the Person to whom it was furnishing notices pursuant to §8.01 and its subsections before the purported transfer of the Unit. This party shall continue to exercise all rights under this Agreement applicable to the Units owned by the purported transferor of the Unit.

 

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6.03. Presentment.

6.03(a). In General. Participants shall have the right to present their Units to the Managing General Partner for purchase subject to the conditions and limitations set forth in this §6.03. A Participant, however, is not obligated to present his Units for purchase.

The Managing General Partner shall not be obligated to purchase more than 5% of the total outstanding Units in any calendar year and this 5% limit may not be waived. The Managing General Partner shall not purchase less than one Unit unless the lesser amount represents the Participant’s entire interest in the Partnership, however, the Managing General Partner may waive this limitation.

A Participant may present his Units in writing to the Managing General Partner every year beginning with the fifth calendar year after the Offering Termination Date subject to the following conditions:

 

(i)

the presentment request must be made by the Participant within 120 days of the reserve report described in §4.03(b)(3);

 

(ii)

in accordance with Treas. Reg. §1.7704-1(f), the purchase may not be made until at least 60 calendar days after the Participant notifies the Partnership in writing of the Participant’s intention to exercise the presentment right; and

 

(iii)

the purchase shall not be considered effective until the presentment price has been paid to the Participant in cash to the Participant.

The Managing General Partner’s obligation to purchase Units presented may be discharged for its benefit by a third-party or an Affiliate. The Units of the selling Participant shall be transferred to the party who pays for them. A selling Participant shall be required to deliver an executed assignment of his Units, in a form satisfactory to the Managing General Partner, together with any other documentation as the Managing General Partner may reasonably request. 6.03(b). Calculation of Presentment Price. The presentment price under either (i) or (ii) below shall be allocated pro rata to each Participant in the ratio that his number of Units bears to the total number of Units. Subject to the foregoing, the presentment price shall be the greater of the following:

 

(i)

the sum of the following Partnership items:

 

(a)

an amount based on 70% of the present worth of future net revenues from the Proved Reserves as determined under the last reserve report of the Partnership prepared by the Managing General Partner and reviewed by an Independent Expert, provided that the Managing General Partner shall estimate the present worth of future net revenues attributable to the Partnership’s interest in the Proved Reserves as described in §4.03(b)(3)(ii);

 

(b)

cash on hand;

 

(c)

prepaid expenses and accounts receivable less a reasonable amount for doubtful accounts; and

 

(d)

the estimated market value of all assets that are not separately specified above, determined in accordance with standard industry valuation procedures; and

there shall be deducted from the foregoing sum the following Partnership items:

 

(a)

an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and

 

(b)

any distributions made to the Participants between the date of the presentment request and the date the presentment price is paid to the selling Participant. However, if any amount of those cash distributions to the Participant by the Partnership was derived from the sale of natural gas, oil or other mineral production, or of a producing property owned by the Partnership, after the date of the presentment request, for purposes of determining the reduction of the presentment price the amount of those cash distributions shall be discounted using the same rate used to take into account the risk factors employed to determine the present worth of the Partnership’s Proved Reserves; or

 

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(ii)

an amount equal to three (3) times the total amount of distributions from the Partnership’s natural gas and oil operations paid by Partnership to the Participants as a group during the previous twelve (12) months.

6.03(c). Further Adjustment May Be Allowed. The presentment price determined under §6.03(b)(i) may be further adjusted by the Managing General Partner for estimated changes therein from the date of the report to the date of payment of the presentment price to the Selling Participant because of the following:

 

(i)

the production or sales of, or additions to, reserves and lease and well equipment, sale or abandonment of Leases, and similar matters occurring before the date of the presentment request; and

 

(ii)

any of the following occurring before payment of the presentment price to the selling Participant:

 

(a)

changes in well performance;

 

(b)

increases or decreases in the market price of natural gas, oil or other minerals;

 

(c)

revisions to regulations relating to the importing of hydrocarbons;

 

(d)

changes in income, ad valorem, and other tax laws, such as material variations in the provisions for depletion; and

 

(e)

similar matters.

6.03(d). Selection by Lot. If less than all of the Units presented at any time are to be purchased, then the Participants whose Units are to be purchased will be selected by lot.

The Managing General Partner’s obligation to purchase Units presented may be discharged for its benefit by a third-party or an Affiliate. The Units of the selling Participant shall be transferred to the party who pays for it, and such party shall hold the purchased Units for its own account and not for resale. A selling Participant shall be required to deliver an executed assignment of his Units, in a form satisfactory to the Managing General Partner, together with any other documentation as the Managing General Partner may reasonably request.

6.03(e). No Obligation of the Managing General Partner to Establish a Reserve. The Managing General Partner shall have no obligation to establish any reserve to satisfy the presentment feature under this section.

6.03(f). Suspension of Presentment Feature. The Managing General Partner may suspend this presentment feature by so notifying Participants at any time if it determines in its sole discretion that it:

 

(i)

does not have sufficient cash flow; or

 

(ii)

is unable to borrow funds for this purpose on terms it deems reasonable.

In addition, the presentment feature may be conditioned, in the Managing General Partner’s sole discretion, on the Managing General Partner’s receipt of an opinion of counsel that the transfers will not cause the Partnership to be treated as a “publicly traded partnership” under the Code.

6.04. Redemption of Units from Non-Citizens. If the Partnership, the Managing General Partner or any of its Affiliates become subject to federal, state or local laws or regulations that, in the reasonable determination of the Managing General Partner, create a substantial risk of cancellation or forfeiture of any property that they have an interest in, which is to the detriment of the other Participants, because of the nationality, citizenship or other related suitability status of any Participant or assignee of a Participant’s Units, the Partnership may redeem, on 30 days’ advance notice to the Participant, the Participant’s Units or the Units held by the assignee of a Participant, at a reasonable redemption price per Unit as determined by the Managing General Partner in its sole discretion.

 

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ARTICLE VII

DURATION, DISSOLUTION, AND WINDING UP

7.01. Duration.

7.01(a). Fifty Year Term. The Partnership shall continue in existence for a term of 50 years from the effective date of this Agreement unless sooner terminated as set forth below.

7.01(b). Termination. The Partnership shall terminate following the occurrence of:

 

(i)

a Final Terminating Event; or

 

(ii)

any event that causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act.

7.01(c). Continuance of Partnership Except on Final Terminating Event. Other than the occurrence of a Final Terminating Event, the Partnership or any successor limited partnership shall not be wound up, but shall be continued by the parties and their respective successors as a successor limited partnership under all of the terms of this Agreement. The successor limited partnership shall succeed to all of the assets of the Partnership. As used throughout this Agreement, the term “Partnership” shall include the successor limited partnership and the parties to the successor limited partnership.

7.02. Dissolution and Winding Up.

7.02(a). Final Terminating Event. On the occurrence of a Final Terminating Event the affairs of the Partnership shall be wound up and there shall be distributed to each of the parties its Distribution Interest in the remaining Partnership assets.

7.02(b). Time of Liquidating Distribution. To the extent practicable and in accordance with sound business practices in the judgment of the Managing General Partner, liquidating distributions shall be made by:

 

(i)

the end of the taxable year in which liquidation occurs, determined without regard to §706(c)(2)(A) of the Code; or

 

(ii)

if later, within 90 days after the date of the liquidation.

Notwithstanding, the following amounts are not required to be distributed within the foregoing time periods so long as the withheld amounts are distributed as soon as practical:

 

(i)

amounts withheld for reserves reasonably required for liabilities of the Partnership; and

 

(ii)

installment obligations owed to the Partnership.

7.02(c). In-Kind Distributions. The Managing General Partner shall not be obligated to offer in-kind property distributions to the Participants, but may do so, in its discretion. Any in-kind property distributions to the Participants shall be made to a liquidating trust or similar entity for the benefit of the Participants, unless at the time of the distribution:

 

(i)

the Managing General Partner offers the individual Participants the election of receiving in-kind property distributions and the Participants accept the offer after being advised of the risks associated with direct ownership; or

 

(ii)

there are alternative arrangements in place which assure the Participants that they will not, at any time, be responsible for the operation or disposition of Partnership properties.

If the Managing General Partner has not received a Participant’s consent within 30 days after the Managing General Partner mailed the request for consent, then it shall be presumed that the Participant has refused to give his consent.

 

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7.02(d). Sale If No Consent. Any Partnership asset which would otherwise be distributed in-kind to a Participant, except for the failure or refusal of the Participant to give his written consent to the distribution, may instead be sold by the Managing General Partner at the best price reasonably obtainable from an independent third-party, who is not an Affiliate of the Managing General Partner, or to the Managing General Partner itself or its Affiliates, including an Affiliated Income Program, at fair market value as determined by an Independent Expert selected by the Managing General Partner.

ARTICLE VIII

MISCELLANEOUS PROVISIONS

8.01. Notices.

8.01(a). Method. Any notice required under this Agreement shall be:

 

(i)

in writing; and

 

(ii)

given by mail or delivered by an overnight delivery company (although one-day delivery is not required) addressed to the party to receive the notice at the address designated in §1.03.

If there is a transfer of Units under this Agreement, no notice to the transferee shall be required, nor shall the transferee have any rights under this Agreement, until notice of the transfer has been given to the Managing General Partner.

Any transfer of Units under this Agreement shall not increase the Managing General Partner’s or the Partnership’s duty to give notice. If there is a transfer of Units under this Agreement to more than one party, then notice to any owner of any interest in the Units shall be notice to all of the owners of the Units.

8.01(b). Change in Address. The address of any party to this Agreement may be changed by notice as follows:

 

(i)

to the Participants, if there is a change of address by the Managing General Partner; or

 

(ii)

to the Managing General Partner, if there is a change of address by a Participant.

8.01(c). Time Notice Deemed Given. If the notice is given by the Managing General Partner, then the notice shall be considered given, and any applicable time shall run, from the date the notice is placed in the mail or delivered to the overnight delivery company.

If the notice is given by any Participant, then the notice shall be considered given and any applicable time shall run from the date the notice is received.

8.01(d). Effectiveness of Notice. Any notice to a party other than the Managing General Partner, including a notice requiring concurrence or nonconcurrence, shall be effective, and any failure to respond binding, irrespective of the following:

 

(i)

whether or not the notice is actually received; or

 

(ii)

any disability or death on the part of the noticee, even if the disability or death is known to the party giving the notice.

8.01(e). Failure to Respond. Except pursuant to §7.02(c) or when this Agreement expressly requires affirmative approval of a Participant, any Participant who fails to respond in writing within the time specified to a request by the Managing General Partner as set forth below, for approval of, or concurrence in, a proposed action shall be conclusively deemed to have approved the action. Except pursuant to §7.02(c), when this Agreement expressly requires affirmative approval of a Participant, the Managing General Partner shall send a first request and the

 

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time period for the Participant’s written response shall not be less than 15 business days from the date of mailing of the request. If the Participant does not respond in writing to the first request, then the Managing General Partner shall send a second request. If the Participant does not respond in writing to the second request within seven calendar days from the date of mailing the second request, then the Participant shall be conclusively deemed to have approved the action.

8.02. Time. Time is of the essence of each part of this Agreement.

8.03. Applicable Law. The terms and provisions of this Agreement shall be construed under the laws of the State of Delaware, other than its conflict of law provisions, however, this section shall not be deemed to limit causes of action for alleged violations of federal or state securities law to the laws of the State of Delaware. Neither this Agreement nor the Subscription Agreement shall require mandatory venue or mandatory arbitration of any or all claims by Participants against the Sponsor.

8.04. Agreement in Counterparts. This Agreement may be executed in counterpart and shall be binding on all of the parties executing this or similar agreements from and after the date of execution by each party.

8.05. Amendment.

8.05(a). Procedure for Amendment. No changes in this Agreement shall be binding unless:

 

(i)

proposed in writing by the Managing General Partner, and adopted with the consent of Participants whose Units equal a majority of the total Units; or

 

(ii)

proposed in writing by Participants whose Units equal 10% or more of the total Units and approved by an affirmative vote of Participants whose Units equal a majority of the total Units.

8.05(b). Circumstances Under Which the Managing General Partner Alone May Amend. The Managing General Partner is authorized to amend this Agreement and its exhibits without the consent of Participants in any way deemed necessary or desirable by it to do any or all of the following:

 

(i)

add, or substitute in the case of an assigning party, additional Participants;

 

(ii)

enhance the tax benefits of the Partnership to the parties and amend the allocation provisions of this Agreement as provided in §5.01(c)(3);

 

(iii)

satisfy any requirements, conditions, guidelines, options, or elections contained in any opinion, directive, order, ruling, or regulation of the SEC, the IRS, or any other federal or state agency, or in any federal or state statute, compliance with which it deems to be in the best interest of the Partnership;

 

(iv)

cure any ambiguity, correct or supplement any provision of this Agreement that may be inconsistent with any other provision of this Agreement, or add any provision to this Agreement with respect to matters, events or issues arising under this Agreement that is not inconsistent with the other provisions of this Agreement; or

 

(v)

facilitate any agreements entered into by the Partnership, or by MDS Energy Development, LLC or their Affiliates on the Partnership’s behalf, to hedge up to 50% of the Partnership’s natural gas and oil reserves and pledge up to 100% of its assets and natural gas and oil reserves in connection therewith.

Notwithstanding the foregoing, no amendment materially and adversely affecting the interests or rights of Participants shall be made without the consent of the Participants whose interests or rights will be so affected.

8.06. Additional Partners. Each Participant consents to the admission to the Partnership of additional Participants as the Managing General Partner, in its discretion, chooses to admit.

8.07. Legal Effect. This Agreement shall be binding on and inure to the benefit of the parties, their heirs, devisees, personal representatives, successors and assigns, and shall run with the interests subject to this

 

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Agreement. The terms “Partnership,” “Limited Partner,” “Investor General Partner,” “Participant,” “Partner,” “Managing General Partner,” “Operator,” or “parties” shall equally apply to any successor limited partnership, and any heir, devisee, personal representative, successor or assign of a party.

IN WITNESS WHEREOF, the parties hereto set their hands as of the     day of                     , 2012.

 

 

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EXHIBIT (I-A)

FORM OF

MANAGING GENERAL PARTNER SIGNATURE PAGE

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EXHIBIT (I-A)

MANAGING GENERAL PARTNER SIGNATURE PAGE

Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP of MDS ENERGY PUBLIC 2012-A LP

The undersigned agrees:

 

1.

to serve as the Managing General Partner of MDS ENERGY PUBLIC 2012-A LP (the “Partnership”), and hereby executes, swears to, and agrees to all the terms of the Partnership Agreement;

 

2.

to pay the required subscription of the Managing General Partner under §3.04(a) of the Partnership Agreement; and

 

3.

to subscribe to the Partnership as follows:

 

(a)

$                    [             ] Unit(s)] under Section 3.03(b)(1) of the Partnership Agreement as a Limited Partner; or

 

(b)

$                    [             ] Unit(s)] under Section 3.03(b)(1) of the Partnership Agreement as an Investor General Partner.

Managing General Partner:

 

ACCEPTED this              day of                     , 2012.

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EXHIBIT (I-B)

FORM OF

SUBSCRIPTION AGREEMENT

 

 

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MDS ENERGY PUBLIC 2012-A LP

 

 

SUBSCRIPTION AGREEMENT

 

I, the undersigned, hereby offer to purchase Units of MDS Energy Public 2012-A LP in the amount set forth on the Signature Page of this Subscription Agreement and on the terms described in the current Prospectus for the MDS Energy Public 2012 Program. I acknowledge and agree that my execution of this Subscription Agreement also constitutes my execution of the Agreement of Limited Partnership (the “Partnership Agreement”) the form of which is attached as Exhibit (A) to the Prospectus and I accept the terms and conditions of the Partnership Agreement if my subscription is accepted by MDS Energy Development, LLC, the Managing General Partner. I acknowledge that I may not assign this offer, nor may it be withdrawn after it has been accepted by the Managing General Partner. I (other than Massachusetts residents) further acknowledge that following the Signature Page there are certain representations, warranties and covenants which I must make before the Managing General Partner will accept my subscription.

 

 

POWER OF ATTORNEY

 

I hereby irrevocably constitute and appoint the Managing General Partner, and its duly authorized agents, my agent and attorney-in-fact, in my name, place and stead, to make, execute, acknowledge, swear to, file, record and deliver the Agreement of Limited Partnership and any certificates related thereto.

 

Print Name				Print Name
X				X
Signature				Signature

 

 

SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT

 

I, the undersigned, agree to purchase              Units at $10,000 per Unit in MDS ENERGY PUBLIC 2012-A LP (the “Partnership”) as (check one):

 

				Subscription Amount
¨     INVESTOR GENERAL PARTNER				$
¨     LIMITED PARTNER				(             # Units)
¨     Initial subscription		¨     Additional Subscription

Instructions

 

 

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Subscriber (All investors must personally sign this Signature Page.)

 

NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP:				Name
Tax I. D. No.:				Address of Record (Do not Use P.O. Box)
Print Name
X
Signature
Tax I. D. No.:				See the attached “Alternate Distribution Form” for electronic and alternate address information.
Print Name
X
Signature
I received my final Prospectus on                     , 2012

 

(CHECK ONE): OWNERSHIP OF THE UNITS-		¨    Tenants-in-Common		¨    Partnership
		¨    Joint Tenancy with Right of Survivorship		¨    C Corporation
		¨    Individual		¨    S Corporation
		¨    Community Property with Survivorship Rights		¨    Trust
		¨    Limited Liability Company		¨    Tenants by the Entirety

(Enclose supporting documents.) If a limited liability company, partnership, corporation, or trust or other entity, then the members, stockholders or beneficiaries thereof are citizens of                         .

Date:                     , 2012

 

My Telephone No.: Home		Business
My E-mail Address:

 

(CHECK ONE):		¨     I am at least twenty-one years of age		¨     I am not twenty-one years of age
(CHECK ONE): I am a:		¨     Calendar Year Taxpayer		¨     Fiscal Year Taxpayer
(CHECK IF APPLICABLE): I am a:		¨     Farmer (2/3 or more of my gross income in 2011 or 2012 is from farming)

 

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TO BE COMPLETED BY REGISTERED REPRESENTATIVE (For Commission and Other Purposes)

 

I hereby represent that I have discharged my affirmative obligations under Rule 2810(b)(2)(B) and (b)(3)(D) of the FINRA Conduct Rules and specifically have obtained information from the above-named subscriber concerning his/her age, net worth, annual income, federal income tax bracket, investment objectives, investment portfolio, and other financial information and have determined that an investment in the Partnership is suitable for such subscriber, that such subscriber is or will be in a financial position to realize the benefits of this investment, and that such subscriber has a fair market net worth sufficient to sustain the risks for this investment. I have also informed the subscriber of all pertinent facts relating to the liquidity and marketability of the Partnership and an investment in the Partnership, of the risks of unlimited liability regarding an investment as an Investor General Partner, and of the passive loss limitations for tax purposes of an investment as a Limited Partner.

 

Name of Registered Representative and CRD Number				Name of Broker/Dealer
Signature of Registered Representative				Broker/Dealer CRD Number
Registered Representative Office Address:				Broker/Dealer Facsimile Number:
				Broker/Dealer E-mail Address:
Phone Number:
Facsimile Number:
E-mail Address:
Company Name (if other than Broker/Dealer Name)

NOTICE TO BROKER-DEALER:

Send Subscription Documents completed and signed with check MADE PAYABLE TO: “Citizens Bank of Pennsylvania, N.A., Escrow Dealer, MDS Energy Public 2012-A LP” to:

Jason C. Knapp, President

c/o MDS Securities, LLC

409 Butler Road

Kittanning, Pennsylvania 16201

(855) 807-0807

Wire or ACH transfers are available. Please call Jason Knapp (855) 807-0807 ext. 304 or email Jason.knapp@mdsenergy.net for information.

 

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TO BE COMPLETED BY THE MANAGING GENERAL PARTNER

 

 

ACCEPTED THIS              day of                     , 2012		MDS ENERGY DEVELOPMENT, LLC, MANAGING GENERAL PARTNER
		By:

In order to induce the Managing General Partner to accept this subscription, I hereby represent, warrant, covenant and agree as follows:

Notice: Residents of Massachusetts should not complete or initial this page. Instead, residents of Massachusetts should read the statements below and treat them as notices to the Massachusetts investor of the information set forth in those statements.

 

Investor’s Initials		Co-Investor’s Initials
				I have received the Prospectus.
				I (other than if I am a Minnesota or Maine resident) acknowledge that before this offering there has been no public market for the Units and it is unlikely that after the offering there will be any such market, the transferability of the Units is restricted, and in case of emergency or other change in circumstances I cannot expect to be able to readily liquidate my investment in the Units.
				I am purchasing the Units for my own account, for investment purposes and not for the account of others, and with no present intention of reselling them.
				If an individual, I am a citizen of the United States of America and at least twenty-one years of age.
				If an individual, I am a foreign investor, and at least twenty-one years of age.
				If a limited liability company, partnership, corporation or trust, or other entity, then I am at least twenty-one years of age and empowered and duly authorized under a governing document, trust instrument, charter, certificate of incorporation, by-law provision or the like to enter into this Subscription Agreement and to perform the transactions contemplated by the Prospectus, including its exhibits.
				If a foreign liability company, corporation, partnership, trust or other entity, then I am at least twenty-one years of age and empowered and duly authorized under a governing document, trust instrument, charter, certificate of incorporation, by-law provision or the like to enter into this Subscription Agreement and to perform the transactions contemplated by the Prospectus, including its exhibits.
				I (other than if I am a Minnesota or Maine resident) acknowledge that if I am an Investor General Partner, then I will have unlimited joint and several liability for Partnership obligations and liabilities including amounts in excess of my subscription to the extent the obligations and liabilities exceed the Partnership’s insurance proceeds, the Partnership’s assets, and indemnification by the Managing General Partner. Also, the insurance may be inadequate to cover these liabilities and there is no insurance coverage for certain claims.
				I (other than if I am a Minnesota or Maine resident) acknowledge that if I am a Limited Partner, then I may only use my Partnership losses to the extent of my net passive income from passive activities in the year, with any excess losses being deferred.

 

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Investor’s Initials		Co-Investor’s Initials
				I (other than if I am a Minnesota or Maine resident) acknowledge that no state or federal governmental authority has made any finding or determination relating to the fairness for public investment of the Units and no state or federal governmental authority has recommended or endorsed or will recommend or endorse the Units.
				I (other than if I am a Minnesota or Maine resident) acknowledge that the Selling Dealer or registered representative is required to inform me and the other potential investors of all pertinent facts relating to the Units, including the following: the risks involved in the offering, including the speculative nature of the investment and the speculative nature of drilling for natural gas and oil; the financial hazards involved in the offering, including the risk of losing my entire investment; the lack of liquidity of my investment; the restrictions on transferability of my Units; the background of the Managing General Partner and the Operator; the tax consequences of my investment; and the unlimited joint and several liability of the Investor General Partners.

To meet the suitability requirements for an investment in your state, please check and initial either (a), (b) or (c) depending on your state of residence and whether you are buying limited partner units or investor general partner units. Initial (d) if you are a fiduciary and you meet the requirement. Also, initial (e) to be included in the Partnership’s consolidated state income tax returns if you meet the requirements.

 

Investor’s Initials		Co-Investor’s Initials
				(a)    If I purchase limited partner units, then I must have either: a minimum net worth of $330,000, exclusive of home, home furnishings, and automobiles, or a minimum net worth of $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:
				•     I am a resident of Iowa, Michigan, Missouri, Oklahoma or Pennsylvania, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.
				•     I am a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Division, respectively, that I should limit my investment in the Partnership and substantially similar programs to no more than 10% of my liquid net worth. Liquid net worth is that portion of my 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.
				•     I am a resident of Kentucky, then I must not make an investment in the Partnership which is in excess of 10% of my liquid net worth.
				•     I am a resident of Alabama, Ohio or Oregon, then I must not make an investment in the Partnership which would, after including my previous investments in the Partnership, if any, and any other similar natural gas and oil drilling programs, exceed 10% of my liquid net worth, exclusive of home, home furnishings and automobiles.

 

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				(b)    If I purchase investor general partner units and I am a resident of:
				•   Alaska,   •   Colorado,   •   Connecticut,   •   Delaware,   •   District of Columbia,   •   Florida,   •   Georgia,   •   Hawaii,   •   Idaho,   •   Illinois,		•   Louisiana,   •   Maryland,   •   Mississippi,   •   Missouri,   •   Montana,   •   Nebraska,   •   Nevada,   •   New Hampshire,   •   New York,   •   North Dakota,		•   Puerto Rico,   •   Rhode Island,   •   South Carolina,   •   South Dakota,   •   Utah,   •   Vermont,   •   Virginia,   •   West Virginia,   •   Wisconsin, or   •   Wyoming,
				then I must have either: a net worth of at least $330,000, exclusive of home, furnishings and automobiles, or a net worth or joint net worth with my spouse 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, 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:   •      I am a resident of Missouri, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.   •      I am a resident of Kentucky, then I must not make an investment in the Partnership which is in excess of 10% of my liquid net worth.

Investor’s Initials		Co-Investor’s Initials
				(c)    If I purchase investor general partner units and I am a resident of:
				•   Alabama,   •   Arizona,   •   Arkansas,   •   California,   •   Indiana,   •   Iowa,   •   Kansas,		•   Kentucky,   •   Maine,   •   Massachusetts,   •   Michigan,   •   Minnesota,   •   New Jersey,   •   New Mexico,		•   North Carolina,   •   Ohio,   •   Oklahoma,   •   Oregon,   •   Pennsylvania,   •   Tennessee,   •   Texas, or   •   Washington,
				then I must meet any one of the following suitability requirements:
				•      an individual or joint net worth with my 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
				•      a minimum individual or joint net worth with my spouse in excess of $1,000,000, inclusive of home, home furnishings and automobiles; or

 

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				•      an individual or joint net worth with my spouse in excess of $750,000, exclusive of home, home furnishings and automobiles; or
				•      a combined “gross income” as defined in Section 61 of the Internal Revenue Code of 1986, as amended, in excess of $200,000 in the current year and each of the two previous years.
				Additionally, if:
				•      I am a resident of Iowa, Michigan, Missouri, Oklahoma or Pennsylvania, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.
				•      I am a resident of Ohio or Oregon, then I must not make an investment in the Partnership which would, after including my previous investments in the Partnership, if any, and any other similar natural gas and oil drilling programs, exceed 10% of my net worth, exclusive of home, home furnishings and automobiles.
				•      I am a resident of Alabama, then I must not make an investment in the Partnership which would, after including my previous investments in the Partnership, if any, and any other similar natural gas and oil drilling programs, exceed 10% of my liquid net worth, exclusive of home, home furnishings and automobiles.
				•      I am a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Commission, respectively, that I should limit my investment in the program and substantially similar programs to no more than 10% of my liquid net worth. Liquid net worth is that portion of my 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.
				Further, if I am a resident of California, Iowa, North Carolina or Pennsylvania, then I am aware of the requirements set forth in Exhibit (B) to the Prospectus.
Investor’s Initials		Co-Investor’s Initials
				(d)    If I am a fiduciary, then I am purchasing for a person or entity having the appropriate income and/or net worth specified in (a), (b) or (c) above.
				(e)    STATE COMPOSITE FILING ELECTIONS. I am a natural person and I hereby elect to participate in the partnership state composite income tax filings in states, other than my state of residence, in which I have income, deductions or credits from the partnership. I acknowledge that if I do not elect to be part of this composite election that I may be required to file a state income tax return in each state in which income tax filing is required and I am a nonresident and the partnership derives income. I acknowledge that the partnership anticipates filing state income tax returns in Pennsylvania and possibly any other states in which partnership wells may be drilled.
				Please consult with your personal income tax advisor before you initial this item.

The above representations do not constitute a waiver of any rights that I may have under the Acts administered by the SEC or by any state regulatory agency administering statutes bearing on the sale of securities.

 

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Instructions to Investor

You are required to execute your own Subscription Agreement and the Managing General Partner will not accept any Subscription Agreement that has been executed by someone other than you unless the person has been given your legal power of attorney to sign on your behalf, and you meet all of the conditions in the Prospectus and this Subscription Agreement. In the case of sales to fiduciary accounts, the minimum standards set forth in the Prospectus and this Subscription Agreement must be met by the beneficiary, the fiduciary account, or by the donor or grantor who directly or indirectly supplies the funds to purchase the Partnership Units if the donor or grantor is the fiduciary.

Your execution of the Subscription Agreement constitutes your binding offer to buy Units in the Partnership. The Managing General Partner has the discretion to refuse to accept your subscription without liability to you. Subscriptions will be accepted or rejected by the Partnership within 30 days of their receipt. If your subscription is rejected, then all of your funds will be returned to you promptly. If your subscription is accepted before the first closing, then you will be admitted as a Participant not later than 15 days after the release from escrow of the investors’ funds to the Partnership. If your subscription is accepted after the first closing, then you will be admitted into the Partnership not later than the last day of the calendar month in which your subscription was accepted by the Partnership.

The Managing General Partner will not complete a sale of Units to you and send you a confirmation of purchase until at least five business days after the date you receive a final Prospectus. Before completion of the sale of the Units you will have a right to a return of your subscription.

NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from various requirements of Title 10 of the California Administrative Code. These deviations include, but are not limited to the following: the definition of Prospect in the Prospectus, unlike Rule 260.140.127.2(b), and Rule 260.140.121(1) does not require enlarging or contracting the size of the area on the basis of geological data in all cases. If I am a resident of California, I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus.

 

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SECTION D

TO BE COMPLETED BY ALL INVESTORS

Taxpayer Identification Number Certification – Check the first box below, unless you are a foreign investor or you are investing as a U.S. grantor trust.

Note: If there is a change in circumstances which makes any of the information provided by you in your certification below incorrect, then you are under a continuing obligation so long as you own units in the Partnership to notify the Partnership and furnish the Partnership a new certificate within thirty (30) days of the change.

 

¨	Back up Withholding. Under penalties of perjury, I certify that:

 

(1)

the number provided in my Subscription Agreement is my correct “TIN” (i.e., social security number or employer identification number);

 

(2)

I am not subject to backup withholding because (a) I am exempt from backup withholding under §3406(g)(1) of the Internal Revenue Code and the related regulations, or (b) I have not been notified by the Internal Revenue Service (IRS) that I am subject to backup withholding as a result of failure to report all interest or dividends, or (c) the IRS has notified me that I am no longer subject to backup withholding; and

 

(3)

I am a U.S. person (which includes U.S. citizens, resident aliens, entities or associations formed in the U.S. or under U.S. law, and U.S. estates and trusts.)

(Note: You must cross out item 2 above if you have been notified by the IRS that you are currently subject to backup withholding because you have failed to report all interest and dividends on your tax return.)

 

¨

Foreign Partner. I am at least 21 years of age, and I have provided the Partnership with the appropriate Form W-8 certification or, if a joint account, each joint account owner has provided the Partnership the appropriate Form W-8 certification, and if any one of the joint account owners has not established foreign status, that joint account owner has provided the Partnership with a certified TIN.

 

¨	U.S. Grantor Trusts. Under penalties of perjury, I certify that:

 

(1)

the trust designated as the investor on the Subscription Agreement is a United States grantor trust which I can amend or revoke during my lifetime;

 

(2)

under subpart E of subchapter J of the Internal Revenue Code (check only one of the boxes below):

 

¨ (a)

100% of the trust is treated as owned by me;

 

¨ (b)

the trust is treated as owned in equal shares by me and my spouse; or

 

¨ (c)

% of the trust is treated as owned by                     , and the remainder is treated as owned     % by me and     % by my spouse); and

 

(3)

each grantor or other owner of any portion of the trust has provided the Partnership with the appropriate Form W-8 or Form W-9 certification.

Note: If you check the box in (2)(c), you must insert the information called for by the blanks.

The Internal Revenue Service does not require your consent to any provision of this document other than the certifications required to avoid backup withholding.

 

X

X

Investor Signature(s)

 

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MDS ENERGY PUBLIC 2012-A LP.

DIRECT DEPOSIT FORM

MDS Energy Development, LLC, Managing General Partner

409 Butler Road, Suite A

Kittanning, Pennsylvania 16201

Phone: (724) 548–2501 Fax: (724) 548-2330

Investor Name:                                                                                                                                                                                        

Please provide the following information. Please note that if the requested information to allow your partnership distributions to be made to you by direct deposit is not provided, your Subscription Agreement may not be accepted by the managing general partner.

 

 

 

1. Direct Deposit of Partnership Distributions

 

 

 

Financial institution name:                                                                                                                                                                          

Routing Number (Nine digits are required):                                                                                                                                 

Account Number:                                                                                                                                                                                          

Further Reference:                                                                                                                                                                                         

Please check the account type:

             Checking/Broker

             Savings/Money Market (if the account has check writing privileges it is considered a checking account)

 

 

 

2. Internet Access to Check Stubs For Partnership Distributions

 

 

 

Payee: After your subscription is accepted by your partnership, a user name and password for your account will be provided to you on a secure page of the managing general partner’s website at www.mdsenergy.net so that you will be able to access and review “check stub” statements for each partnership distribution that is made to you by direct deposit into the account set forth above.

 

 

 

***Investor signature is required

Investor’s Signature:                                                                                                                                                                                     

Print Investor’s Name:                                                                                                                                                                                 

 

 

 

Office Use Only:

Date Received:                      Date Entered:                      Initials:                     

 

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CONSENT TO ELECTRONIC DELIVERY OF OFFERING MATERIALS

MDS Energy Public 2012-A LP, as well as all public drilling partnerships for which MDS Energy Development, LLC serves as the managing general partner (“MDS Partnerships”), can deliver offering materials to investors electronically. By signing the consent provided below, you can choose to have MDS Partnerships electronically deliver offering materials to them, including:

 

•

prospectuses;

 

•

prospectus supplements;

 

•

prospectus amendments;

 

•

annual, quarterly and periodic reports;

 

•

notices; and

 

•

supplemental sales literature (collectively, “Offering Materials”).

MDS Partnerships may accomplish electronic delivery by:

 

•

posting Offering Materials to the managing general partner’s Internet website (http://www.mdsenergy.net), and notifying you by e-mail, physical mail, or telephone that the materials are available for viewing on the website;

 

•

sending e-mails to you containing Offering Materials (which may be in portable document format (.pdf)); and

 

•

sending CD-ROMs to you containing Offering Materials (which may be in portable document format (.pdf)).

You should note that electronic delivery may impose costs on you that you would not bear with traditional, physical mailing. Also, you may incur Internet online costs for accessing e-mail.

At the same time, you may need to download a .pdf document viewer, such as Adobe Acrobat^®, in order to view Offering Materials sent as a .pdf file. You can download the Adobe Acrobat^® software free of charge at http://www.adobe.com/products/acrobat/readermain.html.

The managing general partner will assist you with electronic delivery of Offering Materials free of charge. If you need assistance, please contact the managing general partner toll free at (855) 807-0807.

You hereby consent to electronic delivery of all Offering Materials by MDS Partnerships in any or all of the manners described above. Information provided below as to your e-mail address will be used by MDS Partnerships in lieu of different instructions from you. You understand that you may revoke this consent at any time by providing timely notice of revocation to MDS Energy Public 2012-A LP. Revocation of this consent will act to revoke your consent to all future electronic deliveries of Offering Materials by MDS Partnerships. You also understand that you may elect to receive paper copies of Offering Materials at any time on request, with or without revoking this consent.

You also understand that this Consent to Electronic Delivery of Offering Materials is optional, and is not a part of the MDS Energy Public 2012-A LP Subscription Agreement, which must be separately executed.

 

Print Name
Signature		Date
E-mail Address (please print, and include domain extension (.com, .net, etc.)
Print Name
Signature		Date
E-mail Address (please print, and include domain extension (.com, .net, etc.)

 

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EXHIBIT (II)

FORM OF

DRILLING AND OPERATING AGREEMENT

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INDEX

 

Section						Page
1.		Assignment of Well Locations; Representations and Indemnification Associated with the Assignment of the Lease; Designation of Additional Well Locations; Outside Activities Are Not Restricted					1
2.		Drilling of Wells; Timing; Extent of Drilling; Interest of Developer; Right to Substitute Well Locations					3
3.		Operator – Responsibilities in General; Covenants; Term					4
4.		Operator’s Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole Determination; Excess Funds and Cost Overruns – Intangible Drilling Costs; Excess Funds and Cost Overruns – Tangible Costs					5
5.		Title Examination of Well Locations; Developer’s Acceptance and Liability; Additional Well Locations					8
6.		Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price Determinations; Plugging and Abandonment					9
7.		Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for Sale Proceeds; Records and Reports; Additional Information					11
8.		Operator’s Lien; Right to Collect From Oil or Gas Purchaser					12
9.		Successors and Assigns; Transfers; Appointment of Agent					13
10.		Operator’s Insurance; Subcontractors’ Insurance; Operator’s Liability					14
11.		Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind					14
12.		Effect of Force Majeure; Definition of Force Majeure; Limitation					15
13.		Term					16
14.		Governing Law; Invalidity					16
15.		Integration; Written Amendment					16
16.		Waiver of Default or Breach					16
17.		Notices					17
18.		Interpretation					17
19.		Counterparts					18
		Exhibit A		Description of Leases and Initial Well Locations
		Exhibits A-l through A-		Maps of Initial Well Locations
		Exhibit B		Form of Assignment
		Exhibit C		Form of Addendum

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DRILLING AND OPERATING AGREEMENT

THIS AGREEMENT is made this      day of                     , 20    , by and between MDS ENERGY DEVELOPMENT, LLC, a Pennsylvania limited liability company (hereinafter referred to as “MDS Energy Development” or “Operator”),

and

MDS Energy Public 2012-A LP [MDS Energy Public 2013-A LP] [MDS Energy Public 2013-B LP] a Delaware limited partnership, (hereinafter referred to as the “Developer”).

WITNESSETH THAT:

WHEREAS, the Operator, by virtue of the Oil and Natural Gas Leases (the “Leases”) described on Exhibit A attached to and made a part of this Agreement, has certain rights to develop the                      (            ) initial well locations (the “Initial Well Locations”) identified on the maps attached to and made a part of this Agreement as Exhibits A-l through A-        ;

WHEREAS, the Developer, subject to the terms and conditions of this Agreement, desires to acquire certain of the Operator’s rights to develop the Initial Well Locations and to provide for the development on the terms and conditions set forth in this Agreement of additional well locations (“Additional Well Locations”) that the parties may from time to time designate; and

WHEREAS, the Operator is in the oil and natural gas exploration and development business, and the Developer desires that Operator, as its independent contractor, perform certain services in connection with its efforts to develop the aforesaid Initial and Additional Well Locations (collectively the “Well Locations”) and to operate the wells completed on the Well Locations, on the terms and conditions set forth in this Agreement;

NOW THEREFORE, in consideration of the mutual covenants herein contained and subject to the terms and conditions hereinafter set forth, the parties hereto, intending to be legally bound, hereby agree as follows:

 

1.	Assignment of Well Locations; Representations and Indemnification Associated with the Assignment of the Lease; Designation of Additional Well Locations; Outside Activities Are Not Restricted.

 

(a)

Assignment of Well Locations. The Operator shall execute an assignment of an undivided percentage of Working Interest in the Well Location for each well to the Developer as shown on Exhibit A attached hereto, which assignment shall be limited by the Operator to the “Prospect” which is defined as an area covering lands which are believed by the Managing General Partner to contain subsurface structural or stratigraphic conditions making it susceptible to the accumulations of hydrocarbons in commercially productive quantities at one or more Horizons. The area, which may be different for different Horizons, shall be enlarged or contracted from time to time on the basis of subsequently acquired information to define the anticipated limits of the associated hydrocarbon reserves and to include all acreage encompassed therein.

If the well to be drilled by the Developer is to a Horizon containing Proved Reserves, then a “Prospect” for a particular Horizon may be limited to the minimum area permitted by state law or local practice, whichever is applicable, to protect against drainage from adjacent wells. Subject to the foregoing sentence, “Prospect” shall be deemed:

 

•

in the case of vertical wells in the Marcellus Shale formation in western Pennsylvania, not more than approximately 7.85 acres, which is designated by the area of a circle with a radius of 330 feet surrounding the wellbore, which may be less than 7.85 acres depending on:

 

(i)

the location of the drill site;

 

(ii)

the amount of acreage covered by the leases owned by Developer’s Managing General Partner before the beginning of drilling operations under this Agreement; and

 

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(iii)

after adjustments for lease boundaries;

which shall be further limited to a depth from the bottom of the Tully Limestone formation to the top of the Onondaga Limestone formation; and

 

•

in the case of horizontal wells in the Marcellus Shale formation in western Pennsylvania, if any, the wellbore plus 125 feet on either side of the center line of a lateral in the well extending from the beginning of the first perforation to the end of the last perforation and shall be further limited to a depth from the bottom of the Tully Limestone formation to the top of the Onondaga Limestone formation, as adjusted for lease boundaries.

The assignment shall be substantially in the form of Exhibit B attached to and made a part of this Agreement. The amount of acreage, or the wellbore, as the case may be, included in each Initial Well Location and the configuration of the Initial Well Location are indicated on the maps attached to this Agreement as Exhibits A-l through A-        . The amount of acreage, or the wellbore, as the case may be, included in each Additional Well Location and the configuration of the Additional Well Location shall be indicated on the maps to be attached as exhibits to the applicable addendum to this Agreement as provided in sub-section (c) below.

 

(b)

Representations and Indemnification Associated with the Assignment of the Lease. With respect to the Lease assignments described in Section 1(a), the Operator represents and warrants to the Developer that:

 

(i)

the Operator is the lawful owner of the Lease and rights and interest under the Lease and of the personal property on the Lease or used in connection with the Lease;

 

(ii)

the Operator has good right and authority to sell and convey the rights, interest, and property;

 

(iii)

the rights, interest, and property are free and clear from all liens and encumbrances, except as provided in Exhibit B to this Agreement; and

 

(iv)

all rentals and royalties due and payable under the Lease have been duly paid.

These representations and warranties shall also be included in each recorded assignment for each Initial Well Location and each Additional Well Location designated pursuant to sub-section (c) below, substantially in the form shown in Exhibit B, which is attached to and made a part of this Agreement.

The Operator agrees to indemnify, protect and hold the Developer and its successors and assigns harmless from and against all costs (including but not limited to reasonable attorneys’ fees), liabilities, claims, penalties, losses, suits, actions, causes of action, judgments or decrees resulting from the breach of any of the above representations and warranties. It is understood and agreed that, except as specifically set forth above, the Operator makes no warranty or representation, express or implied, as to its title or the title of the lessors in and to the lands or oil and natural gas interests covered by said Leases.

 

(c)

Designation of Additional Well Locations. If the parties hereto desire to designate Additional Well Locations to be developed in accordance with the terms and conditions of this Agreement, then the parties shall execute an addendum substantially in the form of Exhibit C attached to and made a part of this Agreement specifying:

 

(i)

the undivided percentage of Working Interest and the oil and natural gas Leases to be included as Leases under this Agreement;

 

(ii)

the amount and configuration of acreage included in each Additional Well Location on maps attached as exhibits to the addendum; and

 

(iii)

their agreement that the Additional Well Locations shall be developed in accordance with the terms and conditions of this Agreement.

 

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(d)

Outside Activities Are Not Restricted. It is understood and agreed that the assignment of rights under the Leases and the oil and natural gas development activities contemplated by this Agreement relate only to the Initial Well Locations and the Additional Well Locations. Nothing contained in this Agreement shall be interpreted to restrict in any manner the right of each of the parties to conduct without the participation of the other party any additional activities relating to exploration, development, drilling, production, or delivery of oil and natural gas on lands adjacent to or in the immediate vicinity of the Well Locations or elsewhere.

 

2.	Drilling of Wells; Timing; Extent of Drilling; Interest of Developer; Right to Substitute Well Locations.

 

(a)

Drilling of Wells. Operator, as Developer’s independent contractor, agrees to drill, complete (or plug) and operate                      (            ) oil and natural gas wells on the                      (            ) Initial Well Locations in accordance with the terms and conditions of this Agreement. Developer, as a minimum commitment, agrees to participate in and pay the Operator’s charges for drilling and completing (or plugging) the wells and any extra costs pursuant to Section 4 in proportion to the share of the Working Interest owned by the Developer in the wells with respect to all initial wells. It is understood and agreed that, subject to sub-section (e) below, Developer does not reserve the right to decline participation in the drilling of any of the initial wells to be drilled under this Agreement.

 

(b)

Timing. Operator shall begin drilling the first well within thirty (30) days after the date of this Agreement, and shall begin drilling each of the other initial wells for which payment is made pursuant to Section 4(b) before the close of the 90th day after the close of the calendar year in which this Agreement is entered into by Operator and the Developer. Subject to the foregoing time limits, Operator shall determine the timing of and the order of drilling the Initial Well Locations.

 

(c)

Extent of Drilling. All of the wells to be drilled under this Agreement shall be:

 

(i)

drilled and completed (or plugged) in accordance with the generally accepted and customary oil and natural gas field practices and techniques then prevailing in the geographical area of the Well Locations; and

 

(ii)

drilled to a depth sufficient to thoroughly test the objective formation or the deepest assigned depth, whichever is less, in the case of a vertical well, and drilled horizontally through one or more laterals to thoroughly test the objective formation in the case of a horizontal well.

 

(d)

Interest of Developer. Except as otherwise provided in this Agreement, all costs, expenses, and liabilities incurred in connection with the drilling and other operations and activities contemplated by this Agreement shall be borne and paid, and all wells, flow lines necessary to connect all natural gas Wells to a gathering system or pipeline, equipment, materials, and facilities acquired, constructed or installed under this Agreement shall be owned, by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Subject to the payment of lessor’s royalties and overriding royalties or other similar burdens, if any, production of oil and natural gas from the wells to be drilled under this Agreement shall be owned by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Additionally, all costs, expenses, and liabilities incurred in connection with the leasing, developing, drilling, drilling or acquisition and operation of water disposal or injection wells, and the transportation or injection, recycling or other treatment of wastewater from Developer’s productive wells under this Agreement shall be the sole responsibility of Developer in proportion to the share of the Working Interest owned by the Developer in the wells. In the event Operator provides any services related to wastewater disposal wells, injection wells, transportation and treatment of wastewater or similar matters under this Agreement, Operator shall be paid a monthly competitive fee, as agreed to by Developer and Operator in addition to the Operator’s other fees and reimbursements under this Agreement.

 

(e)

Right to Substitute Well Locations. Notwithstanding the provisions of sub-section (a) above, if the Operator or Developer determines in good faith, with respect to any Well Location, before operations

 

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begin under this Agreement on the proposed new well location, that it would not be in the best interest of the Developer to drill a well on the Well Location, then the party making the determination shall notify the other party of its determination and the basis for its determination and, unless otherwise instructed by Developer, the well shall not be drilled. This determination may be based on:

 

(i)

the production or failure of production of any other wells that may have been recently drilled in the immediate area of the Well Location;

 

(ii)

newly discovered title defects; or

 

(iii)

any other evidence with respect to the Well Location as may have been obtained.

If the well is not drilled, then Operator shall promptly propose a new well location (including all information for the proposed new well location as Developer may reasonably request) to be substituted for the original Well Location. Developer shall then have seven (7) business days to either reject or accept the proposed new well location. If the new well location is rejected, then Operator shall promptly propose another substitute well location pursuant to the provisions of this sub-section.

Once the Developer accepts a substitute well location or does not reject it within the seven (7) day period, this Agreement shall terminate as to the original Well Location and the substitute well location shall become subject to the terms and conditions of this Agreement.

 

3.	Operator – Responsibilities in General; Covenants; Term.

 

(a)

Operator – Responsibilities in General. MDS Energy Development shall be the Operator of the wells and Well Locations subject to this Agreement and, as the Developer’s independent contractor, shall, in addition to its other obligations under this Agreement do the following:

 

(i)

arrange for drilling and completing (or plugging) the wells and, if a natural gas well, installing the necessary natural gas gathering line systems and connection facilities;

 

(ii)

make the technical decisions required in drilling, testing, completing (or plugging), and operating the wells;

 

(iii)

manage and conduct all field operations in connection with the drilling, testing, completing (or plugging), equipping, operating, and producing the wells;

 

(iv)

maintain all wells, equipment, gathering lines if a natural gas well, and facilities in good working order during their useful lives;

 

(v)

perform the necessary administrative and accounting functions; and

 

(vi)

design water disposal plans, if needed, for the wells.

In performing the work contemplated by this Agreement, Operator is an independent contractor with authority to control and direct the performance of the details of the work.

 

(b)

Covenants. Operator covenants and agrees that under this Agreement:

 

(i)

it shall perform and carry on (or cause to be performed and carried on) its duties and obligations in a good, prudent, diligent, and workmanlike manner using technically sound, acceptable oil and natural gas field practices then prevailing in the geographical area of the Well Locations;

 

(ii)

all drilling and other operations conducted by, for and under the control of Operator shall conform in all respects to federal, state and local laws, statutes, ordinances, regulations, and requirements;

 

(iii)

unless otherwise agreed in writing by the Developer, all work performed pursuant to a written estimate shall conform to the technical specifications set forth in the written estimate and all equipment and materials installed or incorporated in the wells and facilities shall be new or used and of good quality;

 

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(iv)

in the course of conducting operations, it shall comply with all terms and conditions, other than any minimum drilling commitments, of the Leases (and any related assignments, amendments, subleases, modifications and supplements);

 

(v)

it shall keep the Well Locations and all wells, equipment and facilities located on the Well Locations free and clear of all labor, materials and other types of liens or encumbrances arising out of operations;

 

(vi)

it shall file all reports and obtain all permits and bonds required to be filed with or obtained from any governmental authority or agency in connection with the drilling or other operations and activities; and

 

(vii)

it will provide competent and experienced personnel to supervise drilling, completing (or plugging), and operating the wells and use the services of competent and experienced service companies to provide any third party services necessary or appropriate in order to perform its duties.

 

(c)

Term. MDS Energy Development shall serve as Operator under this Agreement until the earliest of:

 

(i)

the termination of this Agreement pursuant to Section 13;

 

(ii)

the termination of MDS Energy Development as Operator by the Developer at any time in the Developer’s discretion, with or without cause on sixty (60) days’ advance written notice to the Operator; or

 

(iii)

the resignation of MDS Energy Development as Operator under this Agreement, which may occur on ninety (90) days’ written notice to the Developer at any time after five (5) years from the date of this Agreement, it being expressly understood and agreed that MDS Energy Development shall have no right to resign as Operator before the expiration of the five-year period.

Any successor Operator shall be selected by the Developer. Nothing contained in this sub-section shall relieve or release MDS Energy Development or the Developer from any liability or obligation under this Agreement that accrued or occurred before MDS Energy Development’s removal or resignation as Operator under this Agreement. On any change in Operator under this provision, the then present Operator shall deliver to the successor Operator possession of all records, equipment, materials and appurtenances used or obtained for use in connection with operations under this Agreement and owned by the Developer.

 

4.	Operator’s Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole Determination; Excess Funds and Cost Overruns – Intangible Drilling Costs; Excess Funds and Cost Overruns – Tangible Costs.

 

(a)

Operator’s Charges for Drilling and Completing Wells. Each oil and natural gas well that is drilled and completed under this Agreement shall be drilled and completed for an amount equal to the sum of the following items: (i) the Cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by Affiliates of the Developer’s Managing General Partner, then those items shall be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the Developer’s Managing General Partner’s Affiliates, which shall be charged at competitive rates; (iv) an administration and oversight fee at a competitive rate in the area where the well is situated, which is $60,000 per vertical well and $250,000 per horizontal well in the Marcellus Shale (Pennsylvania) primary area; and (v) a mark-up in an amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the Developer’s Managing General Partner’s services as general drilling contractor as Operator under this Agreement. The 15% mark-up shall not be charged on the administration and supervision fee.

 

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“Cost” shall mean the price paid by Operator in an arm’s-length transaction. Additionally, if the Operator drills a well for the Developer that the Developer’s Managing General Partner determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completion activities or as otherwise determined by the Developer’s Managing General Partner, the administration and oversight fee for the well described above, and in §4.02(d)(1)(iv) of the Developer’s Partnership Agreement, may be increased to a competitive rate as determined by the Developer’s Managing General Partner.

The estimated price for drilling and completing each of the wells shall be set forth in an Authority for Expenditure (“AFE”) that shall be attached to this Agreement as an Exhibit, and shall cover all ordinary costs which may be incurred in drilling and completing (or plugging) each well. This includes without limitation, site preparation, permits and bonds, roadways, surface damages, power at the site, water, Operator’s compensation as set forth above, rights-of-way, drilling rigs, equipment and materials, costs of title examinations, logging, cementing, frackturing, casing, meters (other than utility purchase meters), connection facilities, salt water collection tanks, separators, siphon string, rabbit, tubing, gathering lines and water lines in connection with a natural gas well, and geological, geophysical and engineering services. After each initial well or additional well is drilled and completed under this Agreement, on request Operator shall prepare and deliver to the Developer an amended AFE that sets forth the allocation between Intangible Drilling Costs and Tangible Costs, as those terms are defined in Section 4(b), below, for the well based on the actual costs to drill and complete the well.

 

(b)

Payment. The Developer shall pay to Operator on execution of this Agreement, in proportion to the share of the Working Interest owned by the Developer in the wells, one hundred percent (100%) of the estimated Intangible Drilling Costs and Tangible Costs, as those terms are defined below, for drilling and completing all initial wells. The Developer’s payment shall be nonrefundable in all events in order to enable Operator to do the following:

 

(i)

commence site preparation for the initial wells;

 

(ii)

obtain suitable subcontractors for drilling and completing or plugging the initial wells at currently prevailing prices; and

 

(iii)

insure the availability of equipment and materials.

For purposes of this Agreement, “Intangible Drilling Costs” or “IDCs” shall mean those expenditures associated with property acquisition and the drilling and completion of oil and natural gas wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes:

 

(i)

all expenditures made with respect to any well before the establishment of production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for the drilling of the well and the preparation of the well for the production of oil or natural gas, that are currently deductible pursuant to Section 263(c) of the Internal Revenue Code of 1986, as amended (the “Code”), and Treasury Reg. Section 1.612-4, which are generally termed “intangible drilling and development costs”; and

 

(ii)

the expense of plugging and abandoning any well before a completion attempt.

“Tangible Costs” shall mean those costs associated with property acquisition and the drilling and completion of oil and natural gas wells that are generally accepted as capital expenditures pursuant to the provisions of the Code. This includes:

 

(i)

all costs of equipment, parts and items of hardware used in drilling and completing (or plugging) a well; and

 

(ii)

those items necessary to deliver acceptable oil and natural gas production to purchasers to the extent installed downstream from the wellhead of any well, which are required to be capitalized under the Code and its regulations.

 

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With respect to each additional well drilled on the Additional Well Locations, if any, the Developer shall pay to Operator, in proportion to the share of the Working Interest owned by the Developer in the wells, one hundred percent (100%) of the estimated IDCs and Tangible Costs for drilling and completing the well on execution of the applicable addendum pursuant to Section l(c) above. The Developer’s payment shall be nonrefundable in all events in order to enable Operator to do the following:

 

(i)

commence site preparation for the additional wells;

 

(ii)

obtain suitable subcontractors for drilling and completing the additional wells at currently prevailing prices; and

 

(iii)

insure the availability of equipment and materials.

Developer shall pay, in proportion to the share of the Working Interest owned by the Developer in the wells, any extra costs incurred for each well pursuant to sub-section (a) above within ten (10) business days of its receipt of Operator’s statement for the extra costs.

 

(c)

Completion Determination. Operator shall determine whether or not to run the production casing for an attempted completion or to plug and abandon any well drilled under this Agreement. However, a well shall be completed only if Operator has made a good faith determination that there is a reasonable possibility of obtaining commercial quantities of oil or natural gas.

 

(d)

Dry Hole Determination. If Operator determines at any time during the drilling or attempted completion of any well drilled under this Agreement, in accordance with the generally accepted and customary oil and natural gas field practices and techniques then prevailing in the geographic area of the Well Location that the well should not be completed, then it shall promptly and properly plug and abandon the well.

 

(e)

Excess Funds and Cost Overruns-Intangible Drilling Costs. Any estimated IDCs set forth on the AFE Exhibit and prepaid by Developer with respect to any well that exceed Operator’s actual price specified in sub-section (a) above for the Intangible Drilling Costs of the well shall be retained by Operator and shall be applied, in proportion to the share of the Working Interest owned by the Developer in the well, to:

 

(i)

the IDCs of an additional well or wells to be drilled on the Additional Well Locations; or

 

(ii)

any cost overruns owed by the Developer to Operator for IDCs on one or more of the other wells on the Well Locations.

Conversely, if Operator’s actual price specified in sub-section (a) above for the IDCs of any well exceeds the estimated IDCs set forth on the AFE Exhibit that were prepaid by Developer for the well, then:

 

(i)

Developer shall pay the additional price to Operator within ten (10) business days after notice from Operator that the additional amount is due and owing; or

 

(ii)

Developer and Operator may agree to delete or reduce Developer’s Working Interest in the well or one or more of the other wells to be drilled under this Agreement to provide funds to pay the additional amounts owed by Developer to Operator. If doing so results in any excess prepaid IDCs, then the excess shall be applied, in proportion to the share of the Working Interest owned by the Developer in the wells, to:

 

(a)

the IDCs of an additional well or wells to be drilled on the Additional Well Locations; or

 

(b)

any cost overruns owed by the Developer to Operator for IDCs on one or more of the other wells on the Well Locations.

The Exhibits to this Agreement with respect to the affected wells shall be amended as appropriate.

 

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(f)

Excess Funds and Cost Overruns – Tangible Costs. Any estimated Tangible Costs set forth on the AFE Exhibit and prepaid by Developer with respect to any well that exceed Operator’s actual price specified in sub-section (a) above for the Tangible Costs of the well shall be retained by Operator and shall be applied, in proportion to the share of the Working Interest owned by the Developer in the wells, to:

 

(i)

the Tangible Costs or IDCs for an additional well or wells to be drilled on the Additional Well Locations; or

 

(ii)

any cost overruns owed by the Developer to Operator for the Tangible Costs or IDCs of one or more of the other wells on the Well Locations.

Conversely, if Operator’s actual price specified in sub-section (a) above for the Developer’s share of Tangible Costs of any well exceeds the estimated Tangible Costs set forth on the AFE Exhibit that were prepaid by Developer for the Tangible Costs for the well, then:

 

(i)

Developer shall pay the additional price to Operator within ten (10) business days after notice from Operator that the additional price is due and owing; or

 

(ii)

Developer and Operator may agree to delete or reduce Developer’s Working Interest in the well or one or more of the other wells to be drilled under this Agreement to provide funds to pay the additional amounts owed by Developer to Operator. If doing so results in any excess prepaid Tangible Costs, then the excess shall be applied, in proportion to the share of the Working Interest owned by the Developer in the wells, to:

 

(a)

the Tangible Costs or IDCs of an additional well or wells to be drilled on the Additional Well Locations; or

 

(b)

any cost overruns owed by the Developer to Operator for the Tangible Costs or IDCs of one or more of the other wells on the Well Locations.

 

5.	Title Examination of Well Locations, Developer’s Acceptance and Liability; Additional Well Locations.

 

(a)

Title Examination of Well Locations, Developer’s Acceptance and Liability. The Developer acknowledges that Operator has furnished Developer with the title opinions identified on Exhibit A, and other documents and information that Developer or its counsel has requested in order to determine the adequacy of the title to the Initial Well Locations and leased premises subject to this Agreement. The Developer accepts the title to the Initial Well Locations and leased premises and acknowledges and agrees that, except for any loss, expense, cost, or liability caused by the breach of any of the warranties and representations made by the Operator in Section l(b), any loss, expense, cost or liability whatsoever caused by or related to any defect or failure of the Developer’s title shall be the sole responsibility of and shall be borne entirely by the Developer.

 

(b)

Additional Well Locations. Before beginning drilling of any well on any Additional Well Location, Operator shall conduct, or cause to be conducted, a title examination of the Additional Well Location, in order to obtain appropriate abstracts, opinions and certificates and other information necessary to determine the adequacy of title to both the applicable Lease and the fee title of the lessor to the premises covered by the Lease. The results of the title examination and such other information as is necessary to determine the adequacy of title for drilling purposes shall be submitted to the Developer for its review and acceptance. No drilling on the Additional Well Location shall begin until the title has been accepted in writing by the Developer or Developer has otherwise authorized the drilling on the Additional Well Location. After any title has been accepted by the Developer or drilling on the Additional Well Location has begun, any loss, expense, cost, or liability whatsoever, caused by or related to any defect or failure of the Developer’s title shall be the sole responsibility of and shall be borne entirely by the Developer, unless such loss, expense, cost, or liability was caused by the breach of any of the warranties and representations made by the Operator in Section l(b).

 

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6.	Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price Determinations; Plugging and Abandonment.

 

(a)

Operations Subsequent to Completion of the Wells. Beginning with the month in which a well drilled under this Agreement begins to produce, Operator shall be entitled to an operating fee at a competitive rate in the area where the well is situated, which in the Marcellus Shale primary area in western Pennsylvania is $800 per month for each productive vertical well and $2,000 per month for each horizontal well, if any. The operating fees shall be proportionately reduced, on a well-by-well basis to the extent the Developer owns less than 100% of the Working Interest in a well. The operating fees shall be in lieu of any direct charges by Operator for its services or the provision by Operator of its equipment for normal superintendence and maintenance of the wells and related pipelines and facilities.

The operating fees shall cover all normal, regularly recurring operating expenses for the production, delivery and sale of natural gas, including without limitation:

 

(i)

well tending, routine maintenance and adjustment;

 

(ii)

reading meters, recording production, pumping, maintaining appropriate books and records;

 

(iii)

preparing reports to the Developer and government agencies; and

 

(iv)

collecting and disbursing revenues.

The operating fees shall not cover costs and expenses related to the following:

 

(i)

the construction of oil storage tanks and third-party expenses to transport oil production, if any, from the well site;

 

(ii)

the production and sale of oil and natural gas liquids;

 

(iii)

the collection, transportation, recycling or other treatment and/or disposal of salt water or other wastewater produced by the wells;

 

(iv)

the rebuilding of access roads; and

 

(v)

the purchase of equipment, materials or third-party services;

which, subject to the provisions of sub-section (c) of this Section 6, shall be invoiced by Operator to the Developer on a monthly basis, and shall be paid by the Developer within ten (10) business days after notice from Operator that the additional amounts are due and owing in proportion to the share of the Working Interest owned by the Developer in the wells.

Any well that is temporarily abandoned or shut-in continuously for an entire calendar month shall not be considered a producing well for purposes of determining the number of wells in the month subject to the operating fee.

 

(b)

Fee Adjustments. The monthly operating fee set forth in sub-section (a) above may be adjusted by Operator annually, as of the first day of January (the “Adjustment Date”) of each year, beginning January 1, 2013. This adjustment, if any, shall not exceed the percentage increase in the average weekly earnings of “Crude Petroleum, Natural Gas, and Natural Gas Liquids” workers, as published by the U.S. Department of Labor, Bureau of Labor Statistics, and shown in Employment and Earnings Publication, Monthly Establishment Data, Hours and Earning Statistical Table C-2, Index Average Weekly Earnings of “Crude Petroleum, Natural Gas, and Natural Gas Liquids” workers, SIC Code #131-2, or any successor index thereto, since January l, 2012, in the case of the first adjustment, and since the previous Adjustment Date, in the case of each subsequent adjustment.

In addition, the monthly operating fee set forth in sub-section (a) above for any given well or wells being operated under this Agreement may be increased beyond the annual adjustment described in the prior paragraph without advance notice to the Developer, from time-to-time, to the competitive rate in the area where the well(s) are situated, as determined by the Operator in its sole discretion.

 

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(c)

Extraordinary Costs. Without the prior written consent of the Developer, pursuant to a written estimate submitted by Operator, Operator shall not undertake any single project or incur any extraordinary cost with respect to any well being produced under this Agreement that is reasonably estimated to result in an expenditure of more than $15,000, unless the project or extraordinary cost is necessary for the following:

 

(i)

to safeguard persons or property; or

 

(ii)

to protect the well or related facilities in the event of a sudden emergency.

In no event, however, shall the Developer be required to pay for any project or extraordinary cost arising from the negligence or misconduct of Operator, its agents, servants, employees, subcontractors, licensees, or invitees.

All extraordinary costs incurred and the cost of projects undertaken under this section with respect to a well being produced under this Agreement shall be billed to the Developer at the invoice cost of third-party services performed or materials purchased together with a reasonable and competitive charge by Operator for any services performed directly by it, in proportion to the share of the Working Interest owned by the Developer in the well. Operator shall have the right to require the Developer to pay in advance all or a portion of the estimated costs of a project undertaken under this section, before undertaking the project, in proportion to the share of the Working Interest owned by the Developer in the well or wells.

 

(d)

Pipelines. Subject to Sections 2 (d) and 4 (a) relating to Developer’s interest in gathering lines for the wells, Developer shall have no interest in any natural gas pipeline and gathering system or processing plant, including but not limited to pipelines, gathering systems and processing plants owned by the Operator or its Affiliates. Also, Developer shall not be charged any cost or expense for the construction, expansion or maintenance of those pipeline and gathering systems or processing plants.

 

(e)

Price Determinations. Notwithstanding anything in this Agreement to the contrary, the Developer shall pay all costs in proportion to the share of the Working Interest owned by the Developer in the wells with respect to obtaining price determinations under and otherwise complying with the Natural Gas Policy Act of 1978 and the implementing state regulations. This responsibility shall include, without limitation, preparing, filing, and executing all applications, affidavits, interim collection notices, reports and other documents necessary or appropriate to obtain price certification, to effect sales of natural gas, or otherwise to comply with the Act and the implementing state regulations.

Operator agrees to furnish the information and render the assistance as the Developer may reasonably request in order to comply with the Act and the implementing state regulations without charge for services performed by its employees.

 

(f)

Plugging and Abandonment. The Developer shall have the right to direct Operator to plug and abandon any well that has been completed under this Agreement as a producer. In addition, notwithstanding any other provision of this Agreement, Operator shall not plug and abandon any well that has been drilled and completed as a producer under this Agreement before obtaining the written consent of the Developer. In this regard, if the Operator determines that any well drilled and completed under this Agreement as a producer shall be plugged and abandoned in accordance with the generally accepted and customary oil and natural gas field practices and techniques then prevailing in the geographic area of the well location, and makes a written request to the Developer for authority to plug and abandon the well and the Developer fails to respond in writing to the request within forty-five (45) days following the date of the request, then the Developer shall be deemed to have consented to the plugging and abandonment of the well.

All costs and expenses related to plugging and abandoning wells that have been drilled and completed under this Agreement as producing wells shall be borne and paid by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Also, at any time after one (1) year

 

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from the date each well drilled and completed under this Agreement is placed into production, Operator shall have the right to deduct each month from the Developer’s share of the proceeds of the sale of the production from the well up to $200 for the purpose of establishing a fund to cover the Operator’s estimate of the Developer’s share of the costs of eventually plugging and abandoning the well. All of these funds shall be deposited by Operator in a separate interest bearing escrow account for the account of the Developer, and the total amount so retained and deposited shall not exceed Operator’s reasonable estimate of Developer’s share of the costs of eventually plugging and abandoning the well.

 

7.	Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for Sale Proceeds; Records and Reports; Additional Information.

 

(a)

Billing and Payment Procedure with Respect to Operation of Wells. Operator shall promptly and timely pay and discharge on behalf of the Developer, in proportion to the share of the Working Interest owned by the Developer in the wells, the following:

 

(i)

all expenses and liabilities payable and incurred by reason of its operation of the wells in accordance with this Agreement , such as severance taxes, royalties, overriding royalties, operating fees, and pipeline gathering charges; and

 

(ii)

any third-party invoices received by Operator with respect to the Developer’s share of the costs and expenses incurred in connection with the operation of the wells.

Operator, however, shall not be required to pay and discharge any of the above costs and expenses that are being contested in good faith by Operator.

Operator shall:

 

(i)

deduct the foregoing costs and expenses from the Developer’s share of the proceeds of the oil and/or natural gas sold from the wells; and

 

(ii)

keep an accurate record of the Developer’s account, showing expenses incurred and charges and credits made and received with respect to each well.

If the Developer’s share of the proceeds of the oil and/or natural gas sold from the wells is insufficient to pay the costs and expenses, then Operator shall promptly and timely pay and discharge the costs and expenses described above, in proportion to the share of the Working Interest owned by the Developer in the wells, and prepare and submit an invoice to the Developer each month for those costs and expenses. The invoice shall be accompanied by the form of statement specified in sub-section (b) below, and shall be paid by the Developer within ten (10) business days of its receipt.

 

(b)

Disbursements. Operator shall disburse to the Developer, on a monthly basis, the Developer’s share of the proceeds received from the sale of oil and/or natural gas sold from the wells operated under this Agreement, less:

 

(i)

the amounts charged to the Developer under sub-section (a); and

 

(ii)

the amount, if any, withheld by Operator for future plugging costs pursuant to sub-section (f) of Section 6.

Each disbursement made and/or invoice submitted to the Developer pursuant to sub-section (a) above shall be accompanied by a statement from the Operator itemizing with respect to each well:

 

(i)

the total production of oil and/or natural gas since the date of the last disbursement or invoice billing period, as the case may be, and the Developer’s share of the production;

 

(ii)

the total proceeds received from any sale of the production, and the Developer’s share of the proceeds;

 

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(iii)

the costs and expenses deducted from the proceeds and/or being billed to the Developer pursuant to sub-section (a) above;

 

(iv)

the amount withheld for future plugging costs; and

 

(v)

any other information as Developer may reasonably request, including without limitation copies of all third-party invoices listed on the statement for the period.

 

(c)

Separate Account for Sale Proceeds. Operator agrees to deposit all proceeds from the sale of oil and/or natural gas sold from the wells operated under this Agreement in a separate checking account maintained by Operator. This account shall be used solely for the purpose of collecting and disbursing funds constituting proceeds from the sale of production under this Agreement.

 

(d)

Records and Reports. In addition to the statements required under sub-section (b) above, Operator, within seventy-five (75) days after the completion of each well drilled, shall furnish the Developer with a detailed statement itemizing with respect to the well the total costs and charges under Section 4(a) and the Developer’s share of the costs and charges, and any other information as is necessary to enable the Developer:

 

(i)

to allocate any extra costs incurred with respect to the well between Tangible Costs and Intangible Drilling Costs; and

 

(ii)

to determine the amount of the investment tax credit or marginal well production tax credit, if applicable.

 

(e)

Additional Information. Operator shall promptly furnish the Developer with any additional information as it may reasonably request, including without limitation geological, technical, and financial information, in the form as may reasonably be requested, pertaining to any phase of the operations and activities governed by this Agreement. The Developer and its authorized employees, agents and consultants, including independent accountants shall, at Developer’s sole cost and expense:

 

(i)

on at least ten (10) days’ written notice to Operator have access during normal business hours to all of Operator’s records pertaining to operations under this Agreement, including without limitation, the right to audit the books of account of Operator relating to all receipts, costs, charges, expenses and disbursements and information regarding the separate account required under sub-section (c); and

 

(ii)

have access, at its sole risk, to any wells drilled by Operator under this Agreement at all times to inspect and observe any machinery, equipment and operations.

 

8.	Operator’s Lien; Right to Collect From Oil or Gas Purchaser.

 

(a)

Operator’s Lien. To secure the payment of all sums due from Developer to Operator under this Agreement, the Developer grants Operator a first and preferred lien on and security interest in the following:

 

(i)

the Developer’s interest in the Leases covered by this Agreement;

 

(ii)

the Developer’s interest in oil and natural gas produced under this Agreement and its share of the proceeds from the sale of the oil and natural gas; and

 

(iii)

the Developer’s interest in materials and equipment under this Agreement.

 

(b)

Right to Collect From Oil or Natural Gas Purchaser. If the Developer fails to timely pay any amount owing under this Agreement by it to the Operator, then Operator, without prejudice to other existing remedies, may collect and retain from any purchaser or purchasers of oil or natural gas the Developer’s share of the proceeds from the sale of the oil and natural gas until the amount owed by the

 

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Developer, plus twelve percent (12%) interest on a per annum basis, and any additional costs (including without limitation actual attorneys’ fees and costs) resulting from the delinquency, has been paid. Each purchaser of oil or natural gas shall be entitled to rely without inquiry on Operator’s written statement concerning the amount of any default.

 

9.	Successors and Assigns; Transfers; Appointment of Agent.

 

(a)

Successors and Assigns. This Agreement shall be binding on and inure to the benefit of the undersigned parties and their respective successors and permitted assigns. However, without the prior written consent of the Developer, the Operator may not assign, transfer, pledge, mortgage, hypothecate, sell or otherwise dispose of any of its interest in this Agreement, or any of its rights or obligations under this Agreement. Notwithstanding, this consent shall not be required in connection with:

 

(i)

the assignment of work to be performed for Operator to subcontractors, it being understood and agreed, however, that any assignment to Operator’s subcontractors shall not in any manner relieve or release Operator from any of its obligations and responsibilities under this Agreement;

 

(ii)

any lien, assignment, security interest, pledge or mortgage arising under Operator’s present or future financing arrangements; or

 

(iii)

the liquidation, merger, consolidation, or other corporate reorganization or sale of substantially all of the assets of Operator.

Further, in order to maintain uniformity of ownership in the wells, production, equipment, and leasehold interests covered by this Agreement, and notwithstanding any other provision of this Agreement to the contrary, the Developer shall not, without the prior written consent of Operator, sell, assign, transfer, encumber, mortgage or otherwise dispose of any of its interest in the wells, production, equipment or leasehold interests covered by this Agreement unless the disposition encompasses either:

 

(i)

the entire interest of the Developer in all wells, production, equipment and leasehold interests subject to this Agreement; or

 

(ii)

an equal undivided interest in all such wells, production, equipment, and leasehold interests.

 

(b)

Transfers. Subject to the provisions of sub-section (a) above, any sale, encumbrance, transfer or other disposition made by the Developer of its interests in the wells, production, equipment, and/or leasehold interests covered by this Agreement shall be made:

 

(i)

expressly subject to this Agreement;

 

(ii)

without prejudice to the rights of the Operator; and

 

(iii)

in accordance with and subject to the provisions of the Leases covering the Well Locations.

 

(c)

Appointment of Agent. If at any time the interest of the Developer is divided among or owned by co-owners, Operator may, in its discretion, require the Developer to appoint a single trustee or agent with full authority to do the following:

 

(i)

receive notices, reports and distributions of the proceeds from production;

 

(ii)

approve expenditures;

 

(iii)

receive billings for and approve and pay all costs, expenses and liabilities incurred under this Agreement;

 

(iv)

exercise any rights granted to the Developer under this Agreement;

 

(v)

grant any approvals or authorizations required or contemplated by this Agreement;

 

(vi)

sign, execute, certify, acknowledge, file and/or record any agreements, contracts, instruments, reports, or documents whatsoever in connection with this Agreement or the activities contemplated by this Agreement; and

 

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(vii)

deal generally with, and with power to bind, the Developer with respect to all activities and operations contemplated by this Agreement.

However, the Developer shall continue to have the right to enter into and execute all contracts or agreements for its share of the oil and natural gas produced from the wells drilled under this Agreement in accordance with sub-section (c) of Section 11.

 

10.	Operator’s Insurance; Subcontractors’ Insurance; Operator’s Liability.

 

(a)

Operator’s Insurance. Operator shall obtain and maintain at its own expense, so long as it is Operator under this Agreement, all required Workmen’s Compensation Insurance and commercial general liability insurance of not less than $2,000,000 in the aggregate.

Subject to the above limits, the Operator’s general public liability insurance shall be in all respects comparable to that generally maintained in the industry with respect to services of the type to be rendered and activities of the type to be conducted under this Agreement. Operator’s general public liability insurance shall, if permitted by Operator’s insurance carrier:

 

(i)

name the Developer as an additional insured party; and

 

(ii)

provide that at least thirty (30) days’ prior notice of cancellation and any other adverse material change in the policy shall be given to the Developer.

However, the Developer shall reimburse Operator for the additional cost, if any, of including it as an additional insured party under the Operator’s insurance.

Current copies of all policies or certificates of the Operator’s insurance coverage shall be delivered to the Developer on request. It is understood and agreed that Operator’s insurance coverage may not adequately protect the interests of the Developer and that the Developer shall carry at its expense the excess or additional general public liability, property damage, and other insurance, if any, as the Developer deems appropriate.

 

(b)

Subcontractors’ Insurance. Operator shall require all of its subcontractors to carry all required Workmen’s Compensation Insurance and to maintain such other insurance, if any, as Operator in its discretion may require.

 

(c)

Operator’s Liability. Operator’s liability to the Developer as Operator under this Agreement shall be limited to, and Operator shall indemnify the Developer and hold it harmless from, claims, penalties, liabilities, obligations, charges, losses, costs, damages, or expenses (including but not limited to reasonable attorneys’ fees), relating to, caused by or arising out of:

 

(i)

the noncompliance with or violation by Operator, its employees, agents, or subcontractors of any local, state or federal law, statute, regulation, or ordinance;

 

(ii)

the negligence or misconduct of Operator, its employees, agents or subcontractors; or

 

(iii)

the breach of or failure to comply with any provisions of this Agreement;

except as provided in Section 4.05 of the Developer’s Partnership Agreement.

 

11.	Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind.

 

(a)

Internal Revenue Code Election. With respect to this Agreement, each of the parties elects under Section 761(a) of the Internal Revenue Code of 1986, as amended, to be excluded from the provisions of Subchapter K of Chapter 1 of Subtitle A of the Internal Revenue Code of 1986, as amended. If the income tax laws of the state or states in which the wells and other property covered by this Agreement are located contain, or may subsequently contain, a similar election, each of the parties agrees that the election shall be exercised.

 

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Beginning with the first taxable year of operations under this Agreement, each party agrees that the deemed election provided by Section 1.761-2(b)(2)(ii) of the Regulations under the Internal Revenue Code of 1986, as amended, will apply; and no party will file an application under Section 1.761-2 (b)(3)(i) of the Regulations to revoke the election. Each party agrees to execute the documents and make the filings with the appropriate governmental authorities as may be necessary to effect the election.

 

(b)

Relationship of Parties. It is not the intention of the parties to create, nor shall this Agreement be construed as creating, a mining or other partnership or association or to render the parties liable as partners or joint venturers for any purpose. Operator shall be deemed to be an independent contractor and shall perform its obligations as set forth in this Agreement.

 

(c)

Right to Take Production in Kind. Subject to the provisions of Section 8 above and this Section 11, the Developer shall have the exclusive right to execute all contracts relating to the sale or disposition of its proportionate share of the production from the wells drilled under this Agreement and sell or dispose of its proportionate share of all oil and natural gas produced from the wells to be drilled under this Agreement, exclusive of production that may be:

 

(i)

used in development and producing operations;

 

(ii)

unavoidably lost; and

 

(iii)

used to fulfill any free natural gas obligations under the terms of the applicable Lease or Leases.

Except as provided below, Operator shall not have any right to sell or otherwise dispose of the oil and natural gas.

Developer shall have no interest in any natural gas supply agreements of Operator, except the right to receive Developer’s share of the proceeds received from the sale of any natural gas or oil from wells developed under this Agreement. The Developer agrees to designate Operator or Operator’s designated agent as the Developer’s collection agent in any contracts. On request, Operator shall assist Developer in arranging the sale or disposition of Developer’s oil and natural gas under this Agreement and shall promptly provide the Developer with all relevant information that comes to Operator’s attention regarding opportunities for selling production.

If Developer fails to take in kind or separately dispose of its proportionate share of the oil and natural gas produced under this Agreement, then Operator shall have the right, subject to the revocation at will by the Developer, but not the obligation, to purchase the oil and natural gas or sell it to others, including Operator’s Affiliates, at any time and from time to time, for the account of the Developer at a reasonable and competitive price in the area for the production. Notwithstanding, Operator shall have no liability to Developer should Operator fail to market the production.

Any such purchase or sale by Operator shall be subject always to the right of the Developer to exercise at any time its right to take in-kind, or separately dispose of, its share of oil and natural gas not previously delivered to a purchaser. Any purchase or sale by Operator of the Developer’s share of oil and natural gas under this Agreement shall be only for reasonable periods of time as are consistent with the minimum needs of the oil and natural gas industry under the particular circumstances, but in no event for a period in excess of one (1) year.

 

12.	Effect of Force Majeure; Definition of Force Majeure; Limitation.

 

(a)

Effect of Force Majeure. If Operator is rendered unable, wholly or in part, by force majeure (as defined below) to carry out any of its obligations under this Agreement, including but not limited to beginning the drilling of one or more wells by the applicable times set forth in Section 2(b), or any Addendum to this Agreement, the obligations of the Operator, so far as it is affected by the force majeure, shall be suspended during but no longer than, the continuance of the force majeure. The

 

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Operator shall give to the Developer prompt written notice of the force majeure with reasonably full particulars concerning it. Operator shall use all reasonable diligence to remove the force majeure as quickly as possible to the extent the same is within its reasonable control.

 

(b)

Definition of Force Majeure. The term “force majeure” shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, terrorist acts, blockade, public riot, lightning, fire, storm, flood, explosion, governmental restraint, unavailability of drilling rigs, equipment or materials, plant shut-downs, curtailments by oil and natural gas purchasers and any other causes whether of the kind specifically enumerated above or otherwise, which directly preclude Operator’s performance under this Agreement and is not reasonably within the control of the Operator including, but not limited to, the inability of Operator to begin the drilling of the wells subject to this Agreement by the applicable times set forth in Section 2(b) or in any Addendum to this Agreement due to decisions of third-party operators to delay drilling the wells, poor weather conditions, inability to obtain drilling permits, access rights to the drilling site or title problems.

 

(c)

Limitation. The requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts, or other labor difficulty affecting the Operator contrary to its wishes. The method of handling these difficulties shall be entirely within the discretion of the Operator.

 

13.

Term.

This Agreement shall become effective when executed by Operator and the Developer. Except as provided in sub-section (c) of Section 3, this Agreement shall continue and remain in full force and effect for the productive lives of each well being operated under this Agreement.

 

14.	Governing Law; Invalidity.

 

(a)

Governing Law. This Agreement shall be governed by, construed and interpreted in accordance with the laws of the Commonwealth of Pennsylvania, excluding its conflict of law provisions.

 

(b)

Invalidity. The invalidity or unenforceability of any particular provision of this Agreement shall not affect the other provisions of this Agreement, and this Agreement shall be construed in all respects as if the invalid or unenforceable provision were omitted.

 

15.	Integration; Written Amendment.

 

(a)

Integration. This Agreement and the Exhibits to this Agreement constitute and represent the entire understanding and agreement of the parties with respect to the subject matter of this Agreement and supersede all prior negotiations, understandings, agreements, and representations relating to the subject matter of this Agreement.

 

(b)

Written Amendment. No change, waiver, modification, or amendment of this Agreement shall be binding or of any effect unless in writing duly signed by the party against which the change, waiver, modification, or amendment is sought to be enforced.

 

16.	Waiver of Default or Breach.

No waiver by any party to any default of or breach by any other party under this Agreement shall operate as a waiver of any future default or breach, whether of like or different character or nature.

 

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17.

Notices.

Unless otherwise provided in this Agreement, all notices, statements, requests, or demands that are required or contemplated by this Agreement shall be in writing and shall be hand-delivered or sent by registered or certified mail, postage prepaid, to the following addresses until a party’s address is changed by certified or registered letter so addressed to the other party:

 

(i)

If to the Operator, to:

MDS Energy Development, LLC

409 Butler Road, Suite A

Kittanning, Pennsylvania, 16201

Attention: President

 

(ii)

If to Developer, to:

MDS Energy Public 2012-A LP

[MDS Energy Public 2013-A LP]

[MDS Energy Public 2013-B LP]

c/o MDS Energy Development, LLC

409 Butler Road, Suite A

Kittanning, Pennsylvania, 16201

Notices that are served by registered or certified mail on the parties in the manner provided above shall be deemed sufficiently served or given for all purposes under this Agreement at the time the notice is hand-delivered or mailed in any post office or branch post office regularly maintained by the United States Postal Service or any successor. All payments shall be hand-delivered or sent by United States mail, postage prepaid to the addresses set forth above until a party’s address is changed by certified or registered letter so addressed to the other party.

 

18.	Interpretation.

The titles of the Sections in this Agreement are for convenience of reference only and shall not control or affect the meaning or construction of any of the terms and provisions of this Agreement. As used in this Agreement, the plural shall include the singular and the singular shall include the plural whenever appropriate.

 

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19.	Counterparts.

The parties may execute this Agreement in any number of separate counterparts, each of which, when executed and delivered by the parties, shall have the force and effect of an original; but all counterparts of this Agreement shall be deemed to constitute one and the same instrument.

IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written.

 

		OPERATOR:			MDS ENERGY DEVELOPMENT, LLC
					By:
								Michael D. Snyder, President
		DEVELOPER:			MDS Energy Public 2012-A LP
					[MDS Energy Public 2013-A LP]
					[MDS Energy Public 2013-B LP]
					By its Managing General Partner:
					MDS ENERGY DEVELOPMENT, LLC
					By:
								Michael D. Snyder, President

 

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DESCRIPTION OF LEASES AND INITIAL WELL LOCATIONS

[To be completed as information becomes available]

 

1.	WELL LOCATION

 

(a)

Oil and Gas Lease from                                                                                   dated                                          and recorded in Deed Book Volume             , Page              in the Recorder’s Office of County,                     , covering approximately                  acres in                                                       Township,                                      County,                                                          .

 

(b)

The portion of the leasehold estate constituting the                                                                                            No.              Well Location is described on the map attached hereto as Exhibit A-l.

 

(c)

Title Opinion of                                                                          ,                                                                          ,                                                              ,                                                                  , dated                             , 20    .

 

(d)

The Developer’s interest in the leasehold estate constituting this Well Location is an undivided     % Working Interest to those oil and gas rights from the surface to the deepest depth penetrated at the cessation of drilling activities (which is              feet), subject to the landowner’s royalty interest and overriding royalty interests.

 

Exhibit A

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FORM OF WELL AREA ASSIGNMENT AGREEMENT

THIS WELL AREA ASSIGNMENT AGREEMENT (“Agreement”) is made and entered into as of                     , between MDS ENERGY DEVELOPMENT, LLC, a Pennsylvania limited liability company, with an address of 409 Butler Road, Suite A, Kittanning, PA 16201 (“Assignor”),

-AND-

MDS Energy Public 2012-A LP [MDS Energy Public 2013-A LP] [MDS Energy Public 2013-B LP], a Delaware limited partnership, with an address of 409 Butler Road, Suite A, Kittanning, PA 16201 (“Assignee”);

WITNESSETH:

-I-

Assignor hereby assigns to Assignee, without warranty of title of any kind, either expressed or implied, except as otherwise provided herein, the leasehold interests in the gas and oil and other liquid petroleum products in place in and under the tracts of land described in Schedule 1, attached hereto and made a part hereof (collectively, the “Assigned Interests”), subject to all the terms, conditions, provisions and limitations of the leases identified thereby (collectively, the “Leases”).

-II-

Except as otherwise provided herein, Assignee hereby agrees to assume all of the obligations of Assignor with respect to the Assigned Interests.

-III-

Upon abandonment of any of the wells identified by Schedule 1, Assignee agrees to plug the same in accordance with the rules and regulations established by the Commonwealth of Pennsylvania and to pay for all damage to the surface which may have been suffered by reason of Assignee’s drilling and plugging operations.

-IV-

Assignor shall continue to pay or cause to be paid the annual rental that may be payable under the Leases and any shut-in gas royalty payments that may be required to maintain the Leases in force and effect and Assignee agrees to promptly reimburse Assignor for Assignee’s proportionate share of the same.

-V-

The relationship of the parties hereto shall be that of assignor and assignee, and shall not be construed to create a partnership, joint venture or other mutual enterprise or endeavor. No provisions of this Agreement herein provided for shall be modified, altered, waived, or assigned except by written consent of the parties concerned.

-VI-

Assignor covenants with Assignee and its successors and assigns that: (a) Assignor is the lawful owner of the Assigned Interests; (b) Assignor has good right and authority to sell and convey the Assigned Interests unto Assignee as set forth herein; (c) the Assigned Interests are free and clear from all liens and encumbrances, with the exception of: (i) royalties, overriding royalties, reversionary interests, and other similar burdens to the extent

 

Exhibit B

(Page 1)

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that the net cumulative effect of such burdens does not reduce the net revenue interest attributable to any of the Leases below eighty-two (82.0%) percent; (ii) unit agreements, pooling agreements, operating agreements, production sales contracts, division orders, and other documents, instruments, contracts, and/or agreements associated with the Assigned Interests to the extent that the net cumulative effect of such burdens does not reduce the net revenue interest attributable to any of the Leases below eighty-two (82.0%) percent; (iii) liens for taxes or assessments not yet due or delinquent, or, if delinquent, being contested in good faith by appropriate action; (iv) materialmen, mechanic, repairmen, employee, contractor, operator, and other similar liens or charges arising in the ordinary course of business for amounts not yet delinquent, or, if delinquent, being contested in good faith by appropriate action; (v) rights of reassignment arising upon final intention to abandon or release all or any portion of the Assigned Interests; (vi) easements, rights-of-way, servitudes, permits, surface leases and other surface rights that do not restrict or interfere with the operation or enjoyment of the Assigned Interests; (v) all rights reserved to or vested in any governmental body to control or regulate all or any portion of the Assigned Interests in any manner, and all obligations and duties under all applicable laws, rules, and orders of such governmental body or under any franchise, grant, license or permit issued by any such governmental body; (vi) instruments, exceptions, covenants, conditions, restrictions, and reservations appearing of public record; and (vii) any other liens, charges, encumbrances, defects or irregularities which do not, individually or in the aggregate, restrict or interfere with the operation or enjoyment of the Assigned Interests, and such that would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties; and (d) that all rentals and royalties due and payable under the Assigned Interests have been duly paid.

This Agreement constitutes the entire agreement of the parties and shall be effective on the date first above written.

 

								ASSIGNOR:
Attest:								MDS Energy Development, LLC
					By
Name:								Name:
Title:								Title:
								ASSIGNEE:
								Attest:
								MDS Energy Public 2012-A LP
								[MDS Energy Public 2013-A LP]
								[MDS Energy Public 2013-B LP]
								By MDS Energy Development, LLC, its
								Managing General Partner
					By
Name:								Name:
Title:								Title:

 

Exhibit B

(Page 2)

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SCHEDULE 1 – WELL AREA ASSIGNMENT AGREEMENT

 

Lessor(s)		Date of Lease		Recording Information		Municipality, County, and State		Well Name		API #

The Assigned Interests are set forth and described as follows:

All of the right, title, and interest of Assignor in and to the above described leases and leasehold premises, subject to and defined by all of the following conditions, qualifications, and/or limitations:

(a) with respect to each of the above described leases and leasehold premises, limited to the corresponding well(s) as above described;

(b) with respect to each vertical well above described, limited to the wellbore of such well, together with that certain acreage attributable to the corresponding lease encompassed within a circle having a radius of three hundred thirty (330.0’) feet (such area consisting of approximately 7.85 acres), with such well at the center of such circle (individually, “Vertical Well Area”); provided, however, that such acreage shall be reduced to the extent necessary to account for minimum spacing requirements and/or the boundary(ies) of the corresponding lease, such that, the circumference of any such circle notwithstanding, no Well Area shall include any acreage lying beyond its corresponding lease boundary(ies);

(c) with respect to each horizontal well above described, limited to the wellbore of such well, together with respect to each horizontal lateral, if any, attributable to each horizontal well above described, the wellbore of such lateral, together with one hundred twenty-five (125’) feet on all sides of the center line of such lateral, and extending from the beginning of the first perforation to the end of the last perforation (individually, “Horizontal Well Area”);

(d) with respect to each Vertical Well Area and Horizontal Well Area, limited to those subsurface depths, intervals, formations, strata, and/or areas below the bottom of the Tully Limestone formation and above the top of the Onondaga Limestone formation, the said depths, intervals, formations, strata, and/or areas being known collectively as the Marcellus Shale formation (the “Assigned Depths”) together with any and all oil and/or gas attributable thereto and/or produced thereby and/or therefrom; and

(e) with respect to each Vertical Well Area and Horizontal Well Area, such non-exclusive road, pipeline and power line rights of way over and upon the corresponding leasehold premises as may from time to time be convenient or necessary for the purpose of producing and removing oil and/or gas from such each well, Vertical Well Area, Horizontal Well Area and corresponding Assigned Depths.

Anything to the contrary herein notwithstanding, Assignor hereby excepts and reserves from the operation of this Agreement the following:

(a) with respect to each well and each Vertical Well Area and Horizontal Well Area, any and all subsurface depths, intervals, formations, strata, and/or areas above the bottom of the Tully Limestone formation and below the top of the Onondaga Limestone formation (the “Excluded Depths”), together with any and all oil and/or gas attributable thereto and/or produced thereby and/or therefrom; and

(b) the right to reasonable ingress and egress on, over, under, and through the surface and the Assigned Interests so as to enable the Assignor to explore for, drill for, and/or produce oil and/or gas in and from the Excluded Depths, including, but not limited to, the right of Assignor and its successors and assigns to drill horizontal wells to and through the Marcellus Shale formation utilizing the same well pad as any one or more of the wells assigned hereby; provided, however, that Assignor shall not frack or complete any such horizontal well within three hundred thirty (330.0’) feet of the center of the wellbore of any well assigned hereby.

 

Exhibit B

(Page 3)

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ADDENDUM NO.     

TO DRILLING AND OPERATING AGREEMENT

DATED                     , 20    

THIS ADDENDUM NO.              made and entered into this      day of                     , 20    , by and between MDS ENERGY DEVELOPMENT, LLC, a Pennsylvania limited liability company (hereinafter referred to as “Operator”),

and

MDS Energy Public 2012-A, LP [ MDS Energy Public 2013-A, LP] [ MDS Energy Public 2013-B, LP], a Delaware limited partnership, (hereinafter referred to as the Developer).

WITNESSETH THAT:

WHEREAS, Operator and the Developer have entered into a Drilling and Operating Agreement dated                     , 20    , (the “Agreement”), which relates to the drilling and operating of                      (            ) wells on the                      (            ) Initial Well Locations identified on the maps attached as Exhibits A-l through A-     to the Agreement, and provides for the development on the terms and conditions set forth in the Agreement of Additional Well Locations as the parties may from time to time designate; and

WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer presently desire to designate                      Additional Well Locations described below to be developed in accordance with the terms and conditions of the Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained in this Addendum and intending to be legally bound, the parties agree as follows:

1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes Operator to drill, complete (or plug) and operate, on the terms and conditions set forth in the Agreement and this Addendum No.    ,                      additional wells on the                      Additional Well Locations described on Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits A-     through A-    .

2. Operator, as Developer’s independent contractor, agrees to drill, complete (or plug) and operate the additional wells on the Additional Well Locations in accordance with the terms and conditions of the Agreement and further agrees to begin drilling the first additional well within thirty (30) days after the date of this Addendum and to begin drilling all of the additional wells before the close of the 90^th day after the close of the calendar year in which the Agreement was entered into by Operator and the Developer, or, if this Addendum is dated after that 90 day period, to begin drilling the first additional well within thirty (30) days after the date of this Addendum and to drill and complete (or plug) all of the remaining additional wells by the end of the calendar year in which this Addendum is dated.

3. Developer acknowledges that:

 

(a)

Operator has furnished Developer with the title opinions identified on Exhibit A to this Addendum; and

 

(b)

such other documents and information which Developer or its counsel has requested in order to determine the adequacy of the title to the above Additional Well Locations.

The Developer accepts the title to the Additional Well Locations and leased premises in accordance with the provisions of Section 5 of the Agreement.

 

Exhibit C

(Page 1)

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4. The drilling and operation of the additional wells on the Additional Well Locations shall be in accordance with and subject to the terms and conditions set forth in the Agreement as supplemented by this Addendum No.     and except as previously supplemented, all terms and conditions of the Agreement shall remain in full force and effect as originally written.

 

a.

This Addendum No.     shall be legally binding on, and shall inure to the benefit of, the parties and their respective successors and permitted assigns.

WITNESS the due execution of this Addendum on the day and year first above written.

 

		OPERATOR:		MDS ENERGY DEVELOPMENT, LLC
				By:
						Michael D. Snyder, President
		DEVELOPER:		MDS Energy Public 2012-A, LP
				[MDS Energy Public 2013-A, LP]
				[MDS Energy Public 2013-B, LP]
				By its Managing General Partner:
				MDS ENERGY DEVELOPMENT, LLC
				By:
						Michael D. Snyder, President

 

Exhibit C

(Page 2)

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EXHIBIT (B)

SPECIAL DISCLOSURES TO INVESTORS

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SPECIAL DISCLOSURES TO SUBSCRIBERS IN

CALIFORNIA, IOWA, NORTH CAROLINA AND PENNSYLVANIA.

 

I.	If a resident of California, I am aware that:

IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER’S RULES.

NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from various requirements of Title 10 of the California Administrative Code. These deviations include, but are not limited to the following: the definition of Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule 260.140.121(1), does not require enlarging or contracting the size of the area on the basis of geological data in all cases. If I am a resident of California, I acknowledge the receipt of California Rule 260.141.11 set forth below.

As a condition of qualification of the units for sale in the State of California, the following rule is hereby delivered to each California purchaser.

California Administrative Code, Title 10, Ch. 3, Rule 260.141.11. Restriction on transfer.

 

(a)

The issuer of any security upon which a restriction on transfer has been imposed pursuant to Section 260.141.10 or 260.534 shall cause a copy of this section to be delivered to each issuee or transferee of such security at the time the certificate evidencing the security is delivered to the issuee or transferee.

 

(b)

It is unlawful for the holder of any such security to consummate a sale or transfer of such security, or any interest therein, without the prior written consent of the Commissioner (until this condition is removed pursuant to Section 260.141.12 of these rules), except:

 

(i)

to the issuer;

 

(ii)

pursuant to the order or process of any court;

 

(iii)

to any person described in Subdivision (i) of Section 25102 of the Code or Section 260.105.14 of these rules;

 

(iv)

to the transferor’s ancestors, descendants or spouse, or any custodian or trustee for the account of the transferor or the transferor’s ancestors, descendants or spouse, or to a transferee by a trustee or custodian for the account of the transferee or the transferee’s ancestors, descendants or spouse;

 

(v)

to holders of securities of the same class of the same issuer;

 

(vi)

by way of gift or donation inter vivos or on death;

 

(vii)

by or through a broker-dealer licensed under the Code (either acting as such or as a finder) to a resident of a foreign state, territory or country who is neither domiciled in this state to the knowledge of the broker-dealer, nor actually present in this state if the sale of such securities is not in violation of any securities law of the foreign state, territory or country concerned;

 

(viii)

to a broker-dealer licensed under the Code in a principal transaction, or as an underwriter or member of an underwriting syndicate or selling group;

 

(ix)

if the interest sold or transferred is a pledge or other lien given by the purchaser to the seller upon a sale of the security for which the Commissioner’s written consent is obtained or under this rule not required;

 

(x)

by way of a sale qualified under Sections 25111, 25112, 25113 or 25121 of the Code, of the securities to be transferred, provided that no order under Section 25140 or Subdivision (a) of Section 25143 is in effect with respect to such qualification;

 

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(xi)

by a corporation to a wholly-owned subsidiary of such corporation, or by a wholly-owned subsidiary of a corporation to such corporation;

 

(xii)

by way of an exchange qualified under Section 25111, 25112 or 25113 of the Code, provided that no order under Section 25140 or Subdivision (a) of Section 25143 is in effect with respect to such qualification;

 

(xiii)

between residents of foreign states, territories or countries who are neither domiciled nor actually present in this state;

 

(xiv)

to the State Controller pursuant to the Unclaimed Property Law or to the administrator of the unclaimed property law of another state;

 

(xv)

by the State Controller pursuant to the Unclaimed Property Law or by the administrator of the unclaimed property law of another state if, in either such case, such person (i) discloses to potential purchasers at the sale that transfer of the securities is restricted under this rule, (ii) delivers to each purchaser a copy of this rule, and (iii) advises the Commissioner of the name of each purchaser;

 

(xvi)

by a trustee to a successor trustee when such transfer does not involve a change in the beneficial ownership of the securities;

 

(xvii)

by way of an offer and sale of outstanding securities in an issuer transaction that is subject to the qualification requirement of Section 25110 of the Code but exempt from that qualification requirement by subdivision (f) of Section 25102;

provided that any such transfer is on the condition that any certificate evidencing the security issued to such transferee shall contain the legend required by this section.

 

(c)

The certificates representing all such securities subject to such a restriction on transfer, whether upon initial issuance or upon any transfer thereof, shall bear on their face a legend, prominently stamped or printed thereon in capital letters of not less than 10-point size, reading as follows:

“IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER’S RULES.”

 

II.	If a resident of Iowa or North Carolina, I am aware that:

IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR OWN EXAMINATION OF THE PERSON OR ENTITY CREATING THE SECURITIES AND THE TERMS OF THE OFFERING, INCLUDING THE MERITS AND RISKS INVOLVED. THESE SECURITIES HAVE NOT BEEN RECOMMENDED BY ANY FEDERAL OR STATE SECURITIES COMMISSION OR REGULATORY AUTHORITY. FURTHERMORE, THE FOREGOING AUTHORITIES HAVE NOT CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

 

III.

PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to a partnership in this offering, you are cautioned to carefully evaluate the partnership’s ability to fully accomplish its stated objectives and inquire as to the current dollar volume of partnership subscriptions. In addition, subscription proceeds received by a 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 for MDS Energy Public 2012-A LP means that subscriptions for at least $15,000,000 have been received by the partnership from investors, including Pennsylvania investors. If the appropriate minimum has not been met at the end of each escrow

 

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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 each 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 issuer must return such funds within 15 calendar days after receipt of the investor’s request.

Instructions to Investor

You are required to execute your own Subscription Agreement and the Managing General Partner will not accept any Subscription Agreement that has been executed by someone other than you unless the person has been given your legal power of attorney to sign on your behalf, and you meet all of the conditions in the Prospectus and this Subscription Agreement. In the case of sales to fiduciary accounts, the minimum standards set forth in the Prospectus and this Subscription Agreement must be met by the beneficiary, the fiduciary account, or by the donor or grantor who directly or indirectly supplies the funds to purchase the Partnership Units if the donor or grantor is the fiduciary.

Your execution of the Subscription Agreement constitutes your binding offer to buy Units in the Partnership. Once you subscribe you may withdraw your subscription only by providing the Managing General Partner with written notice of your withdrawal before your subscription is accepted by the Managing General Partner. The Managing General Partner has the discretion to refuse to accept your subscription without liability to you. Subscriptions will be accepted or rejected by the Partnership within 30 days of their receipt. If your subscription is rejected, then all of your funds will be returned to you promptly. If your subscription is accepted before the first closing, then you will be admitted as a Participant not later than 15 days after the release from escrow of the investors’ funds to the Partnership. If your subscription is accepted after the first closing, then you will be admitted into the Partnership not later than the last day of the calendar month in which your subscription was accepted by the Partnership.

The Managing General Partner will not complete a sale of Units to you and send you a confirmation of purchase until at least five business days after the date you receive a final Prospectus. Before completion of the sale of the Units you will have a right to a return of your subscription.

 

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EXHIBIT (C)

SUBSCRIPTION PACKET

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EXHIBIT (C) SUBSCRIPTION PACKET

INSTRUCTIONS

MDS ENERGY PUBLIC 2012-A LP

SUBSCRIPTION AGREEMENT

Photocopied, faxed, or emailed subscription agreements will not be accepted.

All the pages of the subscription agreement must be read, and completed, initialed, signed and dated by the investor(s), and signed by the registered representative as indicated;

 

•

sign Pages 1, 8 and 11 (if applicable) and initial Page 7.

Check the appropriate box to indicate if this is an initial or additional subscription in the partnership. If this is a net of commission purchase, designate type of purchase. The subscription agreement will need to be completed in its entirety, even if this is an additional investment in the partnership. Please see the “Plan of Distribution” section of the Prospectus for further information if this investment qualifies for a volume discount.

Electronic direct deposit on Page 11 is optional.

If you are a:

 

•

Trust—attach trust documents.

 

•

Partnership—attach current partnership agreement.

 

•

Corporation—attach Corporate Resolution to purchase, Articles of Incorporation and documentation naming the person authorized to sign for the entity.

 

•

L.L.C.—attach Company Resolution to purchase, Articles of Organization and documentation naming the person authorized to sign for the entity.

Make the check payable to: “Citizens Bank of Pennsylvania, N.A., Escrow Agent, MDS Energy Public 2012-A LP.” After breaking escrow make checks payable to “MDS Energy Public 2012-A LP” Under Anti-Money Laundering rules, Cashier’s Checks cannot be accepted.

Mail all completed documents and the check to:

Jason C. Knapp, President

c/o MDS Securities, LLC

409 Butler Road

Kittanning, Pennsylvania 16201

Phone: (855) 807-0807

Registered Representatives: If your Broker/Dealer requires you to send the subscription documents and checks to its home office instead of directly to the Managing General Partner and the escrow agent, which many do, or to deliver the subscription documents and checks to the Managing General Partner and the escrow agent by an overnight service, please adhere to your Broker/Dealer’s policy. If you do not know your Broker/Dealer’s sales policy, please make sure to contact your Broker/Dealer’s home office directly to inquire.

All information required by the subscription agreement will remain confidential, except that we may present the subscription agreement to appropriate parties to establish that this offering is exempt from registration under the Securities Act of 1933, as amended, or meets the requirements of applicable state securities laws.

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Units are being sold only to certain classes of qualified investors. To become an investor, you must demonstrate that you:

 

•

are an “Accredited Investor,” as that term is defined in Regulation D as promulgated by the SEC under the Securities Act of 1933, as amended; and

 

•

you are capable of evaluating the merits and risks of this investment, because you have the requisite knowledge and experience in business, tax, and financial matters.

MDS Securities, LLC—Dealer-Manager

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MDS ENERGY PUBLIC 2012-A LP

 

 

SUBSCRIPTION AGREEMENT

 

 

I, the undersigned, hereby offer to purchase Units of MDS Energy Public 2012-A LP in the amount set forth on the Signature Page of this Subscription Agreement and on the terms described in the current Prospectus for the MDS Energy Public 2012 Program. I acknowledge and agree that my execution of this Subscription Agreement also constitutes my execution of the Agreement of Limited Partnership (the “Partnership Agreement”) the form of which is attached as Exhibit (A) to the Prospectus and I accept the terms and conditions of the Partnership Agreement if my subscription is accepted by MDS Energy Development, LLC, the Managing General Partner. I acknowledge that I may not assign this offer, nor may it be withdrawn after it has been accepted by the Managing General Partner. I (other than Massachusetts residents) further acknowledge that following the Signature Page there are certain representations, warranties and covenants which I must make before the Managing General Partner will accept my subscription.

 

 

POWER OF ATTORNEY

 

 

I hereby irrevocably constitute and appoint the Managing General Partner, and its duly authorized agents, my agent and attorney-in-fact, in my name, place and stead, to make, execute, acknowledge, swear to, file, record and deliver the Agreement of Limited Partnership and any certificates related thereto.

 

Print Name				Print Name
X				X
Signature				Signature

 

 

SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT

 

 

I, the undersigned, agree to purchase                      Units at $10,000 per Unit in MDS ENERGY PUBLIC 2012-A LP (the “Partnership”) as (check one):

 

				Subscription Amount
¨       INVESTOR GENERAL PARTNER				$
¨       LIMITED PARTNER				(                    # Units)
¨       Initial subscription		¨       Additional Subscription

Instructions

 

 

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Subscriber (All investors must personally sign this Signature Page.)

 

NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP:						Name
Tax I. D. No.:						Address of Record (Do not Use P.O. Box)
Print Name
X
Signature
Tax I. D. No.:						See the attached “Alternate Distribution Form” for electronic and alternate address information.
Print Name
X
Signature
I received my final Prospectus on                     , 2012

 

(CHECK ONE): OWNERSHIP OF THE UNITS-		¨		Tenants-in-Common		¨		Partnership
		¨		Joint Tenancy with Right of Survivorship		¨		C Corporation
		¨		Individual		¨		S Corporation
		¨		Community Property with Survivorship Rights		¨		Trust
		¨		Limited Liability Company		¨		Tenants by the Entirety

(Enclose supporting documents.) If a limited liability company, partnership, corporation, or trust or other entity, then the members, stockholders or beneficiaries thereof are citizens of                         .

 

Date:                                              , 2012
My Telephone No.: Home		Business
My E-mail Address:

 

(CHECK ONE):		¨		I am at least twenty-one years of age		¨		I am not twenty-one years of age
(CHECK ONE): I am a:		¨		Calendar Year Taxpayer		¨		Fiscal Year Taxpayer
(CHECK IF APPLICABLE): I am a:		¨		Farmer (2/3 or more of my gross income in 2011 or 2012 is from farming)

 

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TO BE COMPLETED BY REGISTERED REPRESENTATIVE (For Commission and Other Purposes)

 

 

I hereby represent that I have discharged my affirmative obligations under Rule 2810(b)(2)(B) and (b)(3)(D) of the FINRA Conduct Rules and specifically have obtained information from the above-named subscriber concerning his/her age, net worth, annual income, federal income tax bracket, investment objectives, investment portfolio, and other financial information and have determined that an investment in the Partnership is suitable for such subscriber, that such subscriber is or will be in a financial position to realize the benefits of this investment, and that such subscriber has a fair market net worth sufficient to sustain the risks for this investment. I have also informed the subscriber of all pertinent facts relating to the liquidity and marketability of the Partnership and an investment in the Partnership, of the risks of unlimited liability regarding an investment as an Investor General Partner, and of the passive loss limitations for tax purposes of an investment as a Limited Partner.

 

Name of Registered Representative and CRD Number		Name of Broker/Dealer
Signature of Registered Representative		Broker/Dealer CRD Number
Registered Representative Office Address:		Broker/Dealer Facsimile Number:
		Broker/Dealer E-mail Address:
Phone Number:
Facsimile Number:
E-mail Address:
Company Name (if other than Broker/Dealer Name)

NOTICE TO BROKER-DEALER:

Send Subscription Documents completed and signed with check MADE PAYABLE TO: “Citizens Bank of Pennsylvania, N.A., Escrow Dealer, MDS Energy Public 2012-A LP” to:

Jason C. Knapp, President

c/o MDS Securities, LLC

409 Butler Road

Kittanning, Pennsylvania 16201

(855) 807-0807

Wire or ACH transfers are available. Please call Jason Knapp (855) 807-0807 ext. 304 or email Jason.knapp@mdsenergy.net for information.

 

 

TO BE COMPLETED BY THE MANAGING GENERAL PARTNER

 

 

 

ACCEPTED THIS      day of                     , 2012				MDS ENERGY DEVELOPMENT, LLC, MANAGING GENERAL PARTNER
				By:

 

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In order to induce the Managing General Partner to accept this subscription, I hereby represent, warrant, covenant and agree as follows:

Notice: Residents of Massachusetts should not complete or initial this page. Instead, residents of Massachusetts should read the statements below and treat them as notices to the Massachusetts investor of the information set forth in those statements.

 

Investor’s Initials		Co-Investor’s Initials
				I have received the Prospectus.
				I (other than if I am a Minnesota or Maine resident) acknowledge that before this offering there has been no public market for the Units and it is unlikely that after the offering there will be any such market, the transferability of the Units is restricted, and in case of emergency or other change in circumstances I cannot expect to be able to readily liquidate my investment in the Units.
				I am purchasing the Units for my own account, for investment purposes and not for the account of others, and with no present intention of reselling them.
				If an individual, I am a citizen of the United States of America and at least twenty-one years of age.
				If an individual, I am a foreign investor, and at least twenty-one years of age.
				If a limited liability company, partnership, corporation or trust, or other entity then I am at least twenty-one years of age and empowered and duly authorized under a governing document, trust instrument, charter, certificate of incorporation, by-law provision or the like to enter into this Subscription Agreement and to perform the transactions contemplated by the Prospectus, including its exhibits.
				If a foreign limited liability company, corporation, partnership, trust or other entity, then I am at least twenty-one years of age and empowered and duly authorized under a governing document, trust instrument, charter, certificate of incorporation, by-law provision or the like to enter into this Subscription Agreement and to perform the transactions contemplated by the Prospectus, including its exhibits.
				I (other than if I am a Minnesota or Maine resident) acknowledge that if I am an Investor General Partner, then I will have unlimited joint and several liability for Partnership obligations and liabilities including amounts in excess of my subscription to the extent the obligations and liabilities exceed the Partnership’s insurance proceeds, the Partnership’s assets, and indemnification by the Managing General Partner. Also, the insurance may be inadequate to cover these liabilities and there is no insurance coverage for certain claims.
				I (other than if I am a Minnesota or Maine resident) acknowledge that if I am a Limited Partner, then I may only use my Partnership losses to the extent of my net passive income from passive activities in the year, with any excess losses being deferred.
				I (other than if I am a Minnesota or Maine resident) acknowledge that no state or federal governmental authority has made any finding or determination relating to the fairness for public investment of the Units and no state or federal governmental authority has recommended or endorsed or will recommend or endorse the Units.

 

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Investor’s Initials		Co-Investor’s Initials
				I (other than if I am a Minnesota or Maine resident) acknowledge that the Selling Dealer or registered representative is required to inform me and the other potential investors of all pertinent facts relating to the Units, including the following: the risks involved in the offering, including the speculative nature of the investment and the speculative nature of drilling for natural gas and oil; the financial hazards involved in the offering, including the risk of losing my entire investment; the lack of liquidity of my investment; the restrictions on transferability of my Units; the background of the Managing General Partner and the Operator; the tax consequences of my investment; and the unlimited joint and several liability of the Investor General Partners.

To meet the suitability requirements for an investment in your state, please check and initial either (a), (b) or (c) depending on your state of residence and whether you are buying limited partner units or investor general partner units. Initial (d) if you are a fiduciary and you meet the requirement. Also, initial (e) to be included in the Partnership’s consolidated state income tax returns if you meet the requirements.

 

Investor’s Initials		Co-Investor’s Initials
				(a)    If I purchase limited partner units, then I must have either: a minimum net worth of $330,000, exclusive of home, home furnishings, and automobiles, or a minimum net worth of $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:
				•      I am a resident of Iowa, Michigan, Missouri, Oklahoma or Pennsylvania, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.
				•      I am a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Division, respectively, that I should limit my investment in the Partnership and substantially similar programs to no more than 10% of my liquid net worth. Liquid net worth is that portion of my 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.
				•      I am a resident of Kentucky, then I must not make an investment in the Partnership which is in excess of 10% of my liquid net worth.
				•      I am a resident of Alabama, Ohio or Oregon, then I must not make an investment in the Partnership which would, after including my previous investments in the Partnership, if any, and any other similar natural gas and oil drilling programs, exceed 10% of my liquid net worth, exclusive of home, home furnishings and automobiles.

 

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Investor’s Initials		Co-Investor’s Initials
				(b)    If I purchase investor general partner units and I am a resident of:
				•      Alaska,   •      Colorado,   •      Connecticut,   •      Delaware,   •      District of Columbia,   •      Florida,   •      Georgia,   •      Hawaii,   •      Idaho,   •      Illinois,		•      Louisiana,   •      Maryland,   •      Mississippi,   •      Missouri,   •      Montana,   •      Nebraska,   •      Nevada,   •      New Hampshire,   •      New York,   •      North Dakota,		•      Puerto Rico,   •      Rhode Island,   •      South Carolina,   •      South Dakota,   •      Utah,   •      Vermont,   •      Virginia,   •      West Virginia,   •      Wisconsin, or   •      Wyoming,
				then I must have either: a net worth of at least $330,000, exclusive of home, furnishings and automobiles, or a net worth or joint net worth with my spouse 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, 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:   •      I am a resident of Missouri, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.   •      I am a resident of Kentucky, then I must not make an investment in the Partnership which is in excess of 10% of my liquid net worth.
				(c)    If I purchase investor general partner units and I am a resident of:
				•      Alabama,   •      Arizona,   •      Arkansas,   •      California,   •      Indiana,   •      Iowa,   •      Kansas,		•      Kentucky,   •      Maine,   •      Massachusetts,   •      Michigan,   •      Minnesota,   •      New Jersey,   •      New Mexico,		•      North Carolina,   •      Ohio,   •      Oklahoma,   •      Oregon,   •      Pennsylvania,   •      Tennessee,   •      Texas, or   •      Washington,
				then I must meet any one of the following suitability requirements:
				•      an individual or joint net worth with my 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

 

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Investor’s Initials		Co-Investor’s Initials
				•      a minimum individual or joint net worth with my spouse in excess of $1,000,000, inclusive of home, home furnishings and automobiles; or
				•      an individual or joint net worth with my spouse in excess of $750,000, exclusive of home, home furnishings and automobiles; or
				•      a combined “gross income” as defined in Section 61 of the Internal Revenue Code of 1986, as amended, in excess of $200,000 in the current year and each of the two previous years.
				Additionally, if:
				•      I am a resident of Iowa, Michigan, Missouri, Oklahoma or Pennsylvania, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.
				•      I am a resident of Ohio or Oregon, then I must not make an investment in the Partnership which would, after including my previous investments in the Partnership, if any, and any other similar natural gas and oil drilling programs, exceed 10% of my net worth, exclusive of home, home furnishings and automobiles.
				•      I am a resident of Alabama, then I must not make an investment in the Partnership which would, after including my previous investments in the Partnership, if any, and any other similar natural gas and oil drilling programs, exceed 10% of my liquid net worth, exclusive of home, home furnishings and automobiles.
				•      I am a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Commission, respectively, that I should limit my investment in the program and substantially similar programs to no more than 10% of my liquid net worth. Liquid net worth is that portion of my 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.
				Further, if I am a resident of California, Iowa, North Carolina or Pennsylvania, then I am aware of the requirements set forth in Exhibit (B) to the Prospectus.
				(d)    If I am a fiduciary, then I am purchasing for a person or entity having the appropriate income and/or net worth specified in (a), (b) or (c) above.
				(e)    STATE COMPOSITE FILING ELECTIONS. I am a natural person and I hereby elect to participate in the partnership state composite income tax filings in states, other than my state of residence, in which I have income, deductions or credits from the partnership. I acknowledge that if I do not elect to be part of this composite election that I may be required to file a state income tax return in each state in which income tax filing is required and I am a nonresident and the partnership derives income. I acknowledge that the partnership anticipates filing state income tax returns in Pennsylvania and possibly any other states in which partnership wells may be drilled.
				Please consult with your personal income tax advisor before you initial this item.

The above representations do not constitute a waiver of any rights that I may have under the Acts administered by the SEC or by any state regulatory agency administering statutes bearing on the sale of securities.

 

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Instructions to Investor

You are required to execute your own Subscription Agreement and the Managing General Partner will not accept any Subscription Agreement that has been executed by someone other than you unless the person has been given your legal power of attorney to sign on your behalf, and you meet all of the conditions in the Prospectus and this Subscription Agreement. In the case of sales to fiduciary accounts, the minimum standards set forth in the Prospectus and this Subscription Agreement must be met by the beneficiary, the fiduciary account, or by the donor or grantor who directly or indirectly supplies the funds to purchase the Partnership Units if the donor or grantor is the fiduciary.

Your execution of the Subscription Agreement constitutes your binding offer to buy Units in the Partnership. The Managing General Partner has the discretion to refuse to accept your subscription without liability to you. Subscriptions will be accepted or rejected by the Partnership within 30 days of their receipt. If your subscription is rejected, then all of your funds will be returned to you promptly. If your subscription is accepted before the first closing, then you will be admitted as a Participant not later than 15 days after the release from escrow of the investors’ funds to the Partnership. If your subscription is accepted after the first closing, then you will be admitted into the Partnership not later than the last day of the calendar month in which your subscription was accepted by the Partnership.

The Managing General Partner will not complete a sale of Units to you and send you a confirmation of purchase until at least five business days after the date you receive a final Prospectus. Before completion of the sale of the Units you will have a right to a return of your subscription.

NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from various requirements of Title 10 of the California Administrative Code. These deviations include, but are not limited to the following: the definition of Prospect in the Prospectus, unlike Rule 260.140.127.2(b), and Rule 260.140.121(1) does not require enlarging or contracting the size of the area on the basis of geological data in all cases. If I am a resident of California, I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus.

 

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SECTION D

TO BE COMPLETED BY ALL INVESTORS

Taxpayer Identification Number Certification – Check the first box below, unless you are a foreign investor or you are investing as a U.S. grantor trust.

Note: If there is a change in circumstances which makes any of the information provided by you in your certification below incorrect, then you are under a continuing obligation so long as you own units in the Partnership to notify the Partnership and furnish the Partnership a new certificate within thirty (30) days of the change.

 

¨	Back up Withholding. Under penalties of perjury, I certify that:

 

(1)

the number provided in my Subscription Agreement is my correct “TIN” (i.e., social security number or employer identification number);

 

(2)

I am not subject to backup withholding because (a) I am exempt from backup withholding under §3406(g)(1) of the Internal Revenue Code and the related regulations, or (b) I have not been notified by the Internal Revenue Service (IRS) that I am subject to backup withholding as a result of failure to report all interest or dividends, or (c) the IRS has notified me that I am no longer subject to backup withholding; and

 

(3)

I am a U.S. person (which includes U.S. citizens, resident aliens, entities or associations formed in the U.S. or under U.S. law, and U.S. estates and trusts.)

(Note: You must cross out item 2 above if you have been notified by the IRS that you are currently subject to backup withholding because you have failed to report all interest and dividends on your tax return.)

 

¨

Foreign Partner. I am at least 21 years of age, and I have provided the Partnership with the appropriate Form W-8 certification or, if a joint account, each joint account owner has provided the Partnership the appropriate Form W-8 certification, and if any one of the joint account owners has not established foreign status, that joint account owner has provided the Partnership with a certified TIN.

 

¨	U.S. Grantor Trusts. Under penalties of perjury, I certify that:

 

(1)

the trust designated as the investor on the Subscription Agreement is a United States grantor trust which I can amend or revoke during my lifetime;

 

(2)

under subpart E of subchapter J of the Internal Revenue Code (check only one of the boxes below):

 

¨    (a)

100% of the trust is treated as owned by me;

 

¨    (b)

the trust is treated as owned in equal shares by me and my spouse; or

 

¨    (c)

% of the trust is treated as owned by                                 , and the remainder is treated as owned     % by me and     % by my spouse); and

 

(3)

each grantor or other owner of any portion of the trust has provided the Partnership with the appropriate Form W-8 or Form W-9 certification.

Note: If you check the box in (2)(c), you must insert the information called for by the blanks.

The Internal Revenue Service does not require your consent to any provision of this document other than the certifications required to avoid backup withholding.

 

X

X

Investor Signature(s)

 

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MDS ENERGY PUBLIC 2012-A LP.

DIRECT DEPOSIT FORM

MDS Energy Development, LLC, Managing General Partner

409 Butler Road, Suite A

Kittanning, Pennsylvania 16201

Phone: (724) 548–2501 Fax: (724) 548-2330

Investor Name:                                                                                                                                    

Please provide the following information. Please note that if the requested information to allow your partnership distributions to be made to you by direct deposit is not provided, your Subscription Agreement may not be accepted by the managing general partner.

 

 

 

1. Direct Deposit of Partnership Distributions

 

 

 

Financial institution name:                                                                                                                       

Routing Number (Nine digits are required):                                                                                                     

Account Number:                                                                                                                                  

Further Reference:                                                                                                                                

Please check the account type:

                     Checking/Broker

                     Savings/ Money Market (if the account has check writing privileges it is considered a checking account)

 

 

 

2. Internet Access to Check Stubs For Partnership Distributions

 

 

 

Payee: After your subscription is accepted by your partnership, a user name and password for your account will be provided to you on a secure page of the managing general partner’s website at www.mdsenergy.net so that you will be able to access and review “check stub” statements for each partnership distribution that is made to you by direct deposit into the account set forth above.

 

 

 

***Investor signature is required

Investor’s Signature:                                                                                                                                

Print Investor’s Name:                                                                                                                           

 

 

 

Office Use Only:

Date Received:                      Date Entered:                      Initials:                     

 

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CONSENT TO ELECTRONIC DELIVERY OF OFFERING MATERIALS

MDS Energy Public 2012-A LP, as well as all public drilling partnerships for which MDS Energy Development, LLC serves as the managing general partner (“MDS Partnerships”), can deliver offering materials to investors electronically. By signing the consent provided below, you can choose to have MDS Partnerships electronically deliver offering materials to them, including:

 

•

prospectuses;

 

•

prospectus supplements;

 

•

prospectus amendments;

 

•

annual, quarterly and periodic reports;

 

•

notices; and

 

•

supplemental sales literature (collectively, “Offering Materials”).

MDS Partnerships may accomplish electronic delivery by:

 

•

posting Offering Materials to the managing general partner’s Internet website (http://www.mdsenergy.net), and notifying you by e-mail, physical mail, or telephone that the materials are available for viewing on the website;

 

•

sending e-mails to you containing Offering Materials (which may be in portable document format (.pdf)); and

 

•

sending CD-ROMs to you containing Offering Materials (which may be in portable document format (.pdf)).

You should note that electronic delivery may impose costs on you that you would not bear with traditional, physical mailing. Also, you may incur Internet online costs for accessing e-mail.

At the same time, you may need to download a .pdf document viewer, such as Adobe Acrobat^®, in order to view Offering Materials sent as a .pdf file. You can download the Adobe Acrobat^® software free of charge at http://www.adobe.com/products/acrobat/readermain.html.

The managing general partner will assist you with electronic delivery of Offering Materials free of charge. If you need assistance, please contact the managing general partner toll free at (855) 807-0807.

You hereby consent to electronic delivery of all Offering Materials by MDS Partnerships in any or all of the manners described above. Information provided below as to your e-mail address will be used by MDS Partnerships in lieu of different instructions from you. You understand that you may revoke this consent at any time by providing timely notice of revocation to MDS Energy Public 2012-A LP. Revocation of this consent will act to revoke your consent to all future electronic deliveries of Offering Materials by MDS Partnerships. You also understand that you may elect to receive paper copies of Offering Materials at any time on request, with or without revoking this consent.

 

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You also understand that this Consent to Electronic Delivery of Offering Materials is optional, and is not a part of the MDS Energy Public 2012-A LP Subscription Agreement, which must be separately executed.

 

Print Name
Signature		Date
E-mail Address (please print, and include domain extension (.com, .net, etc.)
Print Name
Signature		Date
E-mail Address (please print, and include domain extension (.com, .net, etc.)

 

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13.

Other Expenses of Issuance and Distribution.

The expenses to be incurred in connection with the issuance and distribution of the securities to be registered, other than underwriting discounts, commissions and expense allowances, are estimated to be as follows:

 

Accounting Fees and Expenses		$	200,000	*
Legal Fees (including Blue Sky) and Expenses			485,000	*
Printing			765,000	*
SEC Registration Fee			34,380
Blue Sky Filing Fees (excluding legal fees)			111,140	*
FINRA Filing Fee			30,500
Miscellaneous			1,025,000	*(1)
Total		$	2,551,000	*

 

*

Estimated

(1)

These miscellaneous expenses include issuer seminar, office rent and utilities, rental equipment, repairs and maintenance, telephone and internet, hardware and software, software licenses and maintenance, supplies, office furniture, website hosting and development and industry associations and sponsorships.

 

Item 14.

Indemnification of Directors and Officers.

Section 17-108 of the Delaware Revised Uniform Limited Partnership Act states: “Subject to such standards and restrictions, if any, as are set forth in its partnership agreement, a limited partnership may, and shall have the power to, indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever.”

Under Section 4.05 of the Amended and Restated Certificate and Agreement of Limited Partnership, the Participants, within the limits of their Capital Contributions, and the Partnership, generally agree to indemnify and exonerate the Managing General Partner, the Operator and their Affiliates from claims of liability to any third party arising out of operations of the Partnership provided that:

 

•

they determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership;

 

•

they were acting on behalf of or performing services for the Partnership; and

 

•

the course of conduct was not the result of their negligence or misconduct.

Section 11 of the Dealer-Manager Agreement provides for the indemnification of the Managing General Partner, the Partnership and control persons under specified conditions by the Dealer-Manager and/or Selling Agent.

 

Item 15.

Recent Sales of Unregistered Securities.

None by the Registrant.

MDS Energy Development, LLC (“MDS Energy Development”), the Managing General Partner of the Registrant, and its affiliates have made sales of unregistered securities within the last three years. See the section of the Prospectus captioned “Prior Activities” regarding the sale of limited and general partner interests. In the opinion of MDS Energy Development, the foregoing unregistered securities in each case have been and/or are being offered and sold in compliance with exemptions from registration provided by the Securities Act of 1933, as amended, including the exemptions provided by Section 4(2) of that Act and certain rules and regulations promulgated thereunder, the securities in each case have been and/or are being offered and sold to a limited

 

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number of persons who had the sophistication to understand the merits and risks of the investment and who had the financial ability to bear such risks, and the units of limited and general partner interests were sold to persons who were Accredited Investors, as that term is defined in Regulation D (17 CFR 230.501(a)), or who otherwise satisfied MDS Energy Development or its affiliates that the investment was suitable.

 

Item 16.

Exhibits and Financial Statement Schedules.

 

(a)

Exhibits

 

Exhibit No.		Description
1.1		Form of Dealer-Manager Agreement with MDS Securities, LLC, including its Exhibit “A” Form of Escrow Agreement and its Exhibit “B” Form of Selling Dealer Agreement
2.1		Form of Selected Investment Advisor Agreement
3.1		Certificate of Organization of MDS Energy Development, LLC
3.2		Operating Agreement of MDS Energy Development, LLC
4.1		Certificate of Limited Partnership for MDS Energy Public 2012-A LP
4.2		Certificate of Limited Partnership for MDS Energy Public 2013-A LP
4.3		Certificate of Limited Partnership for MDS Energy Public 2013-B LP
4.4		Form of Limited Partnership Agreement (See Exhibit (A) to Prospectus)
5.1		Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units
8.1		Opinion of Kunzman & Bollinger, Inc. as to federal tax matters
10.1		Form of Escrow Agreement (See Exhibit “A” to Exhibit 1.1 Form of Dealer-Manager Agreement with MDS Securities, LLC)
10.2		Form of Drilling and Operating Agreement (See Exhibit (II) to the Form of Limited Partnership Agreement, Exhibit (A) to Prospectus)
10.3		Form of Term Sale Gas Contract with Snyder Brothers, Inc.
10.4		Form of Gas Purchase Agreement between <Seller> and <Buyer>
10.5		Form of Gas Purchase Agreement between <Seller> and Furnace Run Pipeline, L.P.
10.6		Form of Gas Purchase Contract between <Seller> and Snyder Brothers, Inc.
10.7		Form of Price Lock-In Confirmation between <Seller> and Snyder Brothers, Inc.
10.8		Business Loan Agreement dated June 6, 2011 between MDS Energy Development, LLC and Gateway Bank of Pennsylvania
10.9		Change in Terms of the Business Loan Agreement dated June 6, 2011 between MDS Energy Development, LLC and Gateway Bank of Pennsylvania
23.1		Consent of Registered Independent Public Accounting Firm
23.2		Consent of Kunzman & Bollinger, Inc. (See Exhibits 5.1 and 8.1)
24.1		Power of Attorney

 

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Item 17.

Undertakings.

The undersigned registrant hereby undertakes:

 

(1)

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

 

(i)

To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

 

(ii)

To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement.

 

(iii)

To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

 

(2)

That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

(3)

That all post-effective amendments will comply with the applicable forms, rules and regulations of the Commission in effect at the time such post-effective amendments are filed.

 

(4)

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

 

(5)

That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities:

The undersigned registrant hereby undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

(i)

Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

 

(ii)

Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

(iii)

The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

(iv)

Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

 

(6)

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange

 

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Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the undersigned registrant undertakes that it will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

[THE REST OF THIS PAGE INTENTIONALLY LEFT BLANK.]

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, Kittanning, Pennsylvania on June 8, 2012.

 

		MDS ENERGY PUBLIC 2012 PROGRAM (Registrant)
		By:		MDS Energy Development, LLC,
				its Managing General Partner
Michael D. Snyder, pursuant to the Registration Statement, has been granted Power of Attorney and is signing on behalf of the names shown below, in the capacities indicated.		By:		/s/ Michael D. Snyder
				Michael D. Snyder, Chief Executive Officer and President

In accordance with the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

 

Signature		Title		Date
/s/ Russell D. Hogue		Chief Financial Officer		June 8, 2012
Russell D. Hogue
/s/ Randall L. Morris, Jr.		Vice President and Chief Engineer		June 8, 2012
Randall L. Morris, Jr.
/s/ Brannon P. McPherson		Managing Executive Vice President of Partnership Administration		June 8, 2012
Brannon P. McPherson
/s/ Gregory R. Hill		Executive Vice President of Partnership Administration		June 8, 2012
Gregory R. Hill

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EXHIBIT INDEX

 

Exhibit No.		Description
1.1		Form of Dealer-Manager Agreement with MDS Securities, LLC, including its Exhibit “A” Form of Escrow Agreement and its Exhibit “B” Form of Selling Dealer Agreement
2.1		Form of Selected Investment Advisor Agreement
3.1		Certificate of Organization of MDS Energy Development, LLC
3.2		Operating Agreement of MDS Energy Development, LLC
4.1		Certificate of Limited Partnership for MDS Energy Public 2012-A LP
4.2		Certificate of Limited Partnership for MDS Energy Public 2013-A LP
4.3		Certificate of Limited Partnership for MDS Energy Public 2013-B LP
4.4		Form of Limited Partnership Agreement (See Exhibit (A) to Prospectus)
5.1		Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units
8.1		Opinion of Kunzman & Bollinger, Inc. as to federal tax matters
10.1		Form of Escrow Agreement (See Exhibit “A” to Exhibit 1.1 Form of Dealer-Manager Agreement with MDS Securities, LLC)
10.2		Form of Drilling and Operating Agreement (See Exhibit (II) to the Form of Limited Partnership Agreement, Exhibit (A) to Prospectus)
10.3		Form of Term Sale Gas Contract with Snyder Brothers, Inc.
10.4		Form of Gas Purchase Agreement between <Seller> and <Buyer>
10.5		Form of Gas Purchase Agreement between <Seller> and Furnace Run Pipeline, L.P.
10.6		Form of Gas Purchase Contract between <Seller> and Snyder Brothers, Inc.
10.7		Form of Price Lock-In Confirmation between <Seller> and Snyder Brothers, Inc.
10.8		Business Loan Agreement dated June 6, 2011 between MDS Energy Development, LLC and Gateway Bank of Pennsylvania
10.9		Change in Terms of the Business Loan Agreement dated June 6, 2011 between MDS Energy Development, LLC and Gateway Bank of Pennsylvania
23.1		Consent of Registered Independent Public Accounting Firm
23.2		Consent of Kunzman & Bollinger, Inc. (See Exhibits 5.1 and 8.1)
24.1		Power of Attorney