Southfield Energy CORP - FORM S-1/A

Attached files

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EX-10.6 - Southfield Energy CORP	v172604_10-6.htm
EX-23.1 - Southfield Energy CORP	v172604_ex23-1.htm
EX-23.3 - Southfield Energy CORP	v172604_ex23-3.htm
EX-23.2 - Southfield Energy CORP	v172604_ex23-2.htm

As filed with the Securities and Exchange Commission on January 28, 2010

(Registration No. 333-162029)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 4 to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Southfield Energy Corporation

(Exact name of registrant as specified in its charter)

Nevada		1311		20-5361270
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

1240 Blalock Road, Suite 150

Houston, Texas 77055

( 713) 266-3700

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

Ben Roberts

Chief Executive Officer

Southfield Energy Corporation

1240 Blalock Road, Suite 150

Houston, Texas 77055

Telephone: (713) 266-3700

Facsimile: (713) 266-3701

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

Copiesto:

Locke Lord Bissell & Liddell LLP

600 Travis Street, Suite 3400

Houston, Texas 77002

(713) 226-1249

Attn: J. Eric Johnson

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

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. (Check one):

Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company x
	(Do not check if a smaller reporting company)

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities To Be Registered		Amount to be Registered				Proposed Maximum Offering Price Per Unit				Proposed Maximum Aggregate Offering Price				Amount of Registration Fee
Three Year 10% Notes		$	10,000,000				100	%		$	10,000,000			$	558

The registrant hereby amends this registration statement on such date or 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 the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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.

SUBJECT TO COMPLETION DATED [●] , 2010

PROSPECTUS

Southfield Energy Corporation

$10,000,000 Three Year 10% Notes

We are offering up to $10,000,000 in aggregate principal amount of our Three Year Notes (“3 Year Notes”) in a direct public offering on a continuous basis (the “Offering”). A minimum initial investment of $1,000 is required. The Offering will end upon the earlier of the receipt of the maximum aggregate principal amount of $10,000,000 or one year from the effective date of this prospectus (the “Closing”).

We will issue the 3 Year Notes in denominations of at least $1,000, subject to the initial investment requirement of $1,000. The 3 Year Notes shall mature three years from the date of issuance. The 3 Year Notes shall bear interest at a fixed rate (calculated based on a 365-day year) of ten percent (10%) per annum. We will pay interest on a 3 year Note on a quarterly basis in arrears; simple interest will accrue from the date of purchase.

We are offering the 3 Year Notes on a “self-underwritten” basis, with no minimum. The officers and directors of the Company intend to sell the 3 Year Notes directly, who will not be separately compensated therefor. The intended methods of communication include, without limitation, telephone and personal contact. For more information, see the section titled “Plan of Distribution” herein. However, we reserve the right to utilize broker-dealers, placement agents and/or finders (“Placement Agent”), where permitted by law, to assist us in locating potential investors, in which case we will pay commissions and non-accountable expenses of up to 11% of the gross offering price of the 3 Year Notes. The Placement Agent will not be required to sell any specific number or dollar amount of securities but will use their best efforts to sell the 3 Year Notes.

We do not have to sell any minimum amount of 3 Year Notes to accept and use the proceeds from this Offering. We cannot assure you that all or any portion of the 3 Year Notes we are offering will be sold. If we fail to raise the maximum aggregate principal amount of $10,000,000, we may not be able to execute our business plan. You will not be entitled to the return of your investment. The 3 Year Notes are not listed on any securities exchange and there is no public trading market for the 3 Year Notes. We have the right to reject any subscription, in whole or in part, for any or no reason. We may redeem the 3 Year Notes in whole or in part and from time to time after one year from the closing, but upon at least 15 days prior written notice to you.

You should read this prospectus and any applicable prospectus supplement carefully before you invest in the 3 Year Notes. These 3 Year Notes are our general unsecured obligations and will rank junior and be subordinate in right of payment to all future senior debt. The 3 Year Notes will not be secured by liens on any of our assets. Payment of the 3 Year Notes is not insured or guaranteed by the Federal Deposit Insurance Corporation (“FDIC”), any governmental or private insurance fund, or any other entity. We will establish an initial interest reserve equal to five percent of the gross proceeds from the Offering and will deposit such reserve with a third party as subscriptions are accepted. With the exception of the interest reserve account, we have not made any arrangements to place any of the proceeds from this Offering in an escrow, trust or similar account.

We are issuing the 3 Year Notes pursuant to an Indenture that contains provisions related to events of default, the collective rights of the 3 Year Note holders, and the servicing and administration of the 3 Year Notes.

See “Risk Factors” beginning on page 12 for certain factors you should consider before buying the 3 Year Notes.

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

	Per 3 Year Note		Total
Public offering price	$	1,000	$	10,000,000
Underwriting Commission and Non-Accountable Expense Allowance (1)	$	110	$	1,100,000
Other Expenses (2)	$	100	$	100,000
Proceeds, before expenses, to Southfield Energy Corporation	$	880	$	8,800,000

(1) Assuming a Placement Agent is retained, represents the maximum amount of commissions and non-accountable expenses to be paid assuming the maximum aggregate principal amount of $10,000,000 is raised.

(2) Includes professional services fees, printing and distribution costs and Offering related travel and communication costs.

The date of this prospectus is [●], 2010.

TABLE OF CONTENTS

About this Prospectus			5
Where You Can Find More Information			5
Cautionary Statement Concerning Forward-Looking Statements			6
Prospectus Summary			8
Risk Factors			12
Use of Proceeds			22
Description of 3 Year Notes			23
Summary of Indenture			24
Material Tax Consequences			27
Capitalization			32
Management’s Discussion and Analysis of Financial Condition and Results of Operations			33
Quantitative and Qualitative Disclosures About Market Risk			40
Business			41
Management			53
Director and Executive Officer Compensation			56
Certain Relationships and Related Party Transactions			58
Security Ownership of Certain Beneficial Owners and Management			59
Plan of Distribution			60
Legal Matters			61
Experts			61
Changes In and Disagreements With Accountants On Accounting and Financial Disclosure			61
Index to Financial Statements			F-1

ABOUT THIS PROSPECTUS

This prospectus highlights selected information about us and our 3 Year Notes but does not contain all the information that you should consider before investing in the 3 Year Notes. You should read this entire prospectus carefully, including the information included under the heading “Risk Factors.”

You should rely only on the information contained in this prospectus or to which we have referred you. We a have not authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer to sell these securities in any jurisdiction where such offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC, under the Securities Act of 1933, as amended (the “Securities Act”), a registration statement on Form S-1 with respect to the 3 Year Notes offered in this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). Statements made in this prospectus regarding the contents of any contract or other document are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and to the 3 Year Notes offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which may be inspected, without charge, at the public reference facilities of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of all or any portion of the registration statement may be obtained from the SEC at prescribed rates. Information on the public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements, and other information that is filed electronically with the SEC. The web site can be accessed at www.sec.gov.

After effectiveness of the registration statement, which includes this prospectus, we will be required to comply with the informational requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and, accordingly, will file current reports on Form 8-K, quarterly reports on Form 10-Q, annual reports on Form 10-K, proxy statements and other information with the SEC. Those reports, proxy statements and other information will be available for inspection and copying at the public reference facilities, the SEC web site referred to above and our own website at www.southfieldenergy.com .

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated by reference in this prospectus contain or incorporate by reference certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could,” “should,” “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict” and other similar expressions. Forward-looking statements appear in a number of places throughout this prospectus and the documents incorporated by reference into this prospectus with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations.

By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. We caution you that forward-looking statements are not guarantees of future performance and that our actual results of operations, financial condition and liquidity, and the development of the industry in which we operate, may differ materially from those made in or suggested by the forward-looking statements made in this prospectus. In addition, even if our results of operations, financial condition and liquidity and the development of the industry in which we operate are consistent with the forward-looking statements contained in this prospectus, those results or developments may not be indicative of results or developments in subsequent periods.

The following listing represents some, but not necessarily all, of the risk factors that may cause actual results to differ from those anticipated or predicted:

•

the volatility of oil, natural gas and natural gas liquid prices;

•

estimation, development and acquisition of oil and gas reserves;

•

cash flow, liquidity and financial condition;

•

business and financial strategy;

•

amount, nature and timing of capital expenditures;

•

availability and terms of capital;

•

timing and amount of future production of oil and gas;

•

availability of drilling, production and well service equipment for our operators;

•

operating costs and other expenses;

•

prospect development and property acquisitions;

•

marketing of oil, natural gas and natural gas liquids;

•

competition in the oil and gas industry;

•

the impact of weather and the occurrence of natural disasters such as fires, earthquakes and other catastrophic events;

•

governmental regulation of the oil and gas industry;

•

developments in oil-producing and gas-producing countries;

•

strategic plans, expectations and objectives for future operations;

•

the costs and legal liabilities associated with being a “public” company;

•

the amount of time required by management to comply with being a public company;

•

the depletion of our oil and gas assets at a rate faster than anticipated;

•

our ability to generate sufficient revenues and cash flow to meet our short and long term obligations;

•

our ability to hire and retain qualified personnel to execute our operations; and

•

global demand for and supply of oil & natural gas.

You should also read carefully the factors described in the “Risk factors” section beginning on page 12 to better understand the risks and uncertainties inherent in our business and underlying any forward-looking statements .

PROSPECTUS SUMMARY

This summary highlights information about us and the Offering contained elsewhere in this prospectus. Because it is a summary, it does not contain all the information that you should consider before investing in our 3 Year Notes. You should read the entire prospectus carefully before making an investment decision, including the information presented under the heading “Risk Factors” and the historical financial statements and the accompanying notes thereto included elsewhere in this prospectus.

All references in this prospectus to “we,” “us,” “our,” “Company” and “Southfield” refer to Southfield Energy Corporation.

Overview

We are an independent energy company based in Houston, Texas that invests in the exploration, development, and production of moderate risk, oil and gas wells in the United States. We focus on partnering alongside proven operators with strong track records of success. The Company’s core strategy is to earn revenue from existing non-operated working interests while investing in new opportunities to increase our oil and gas production and reserves; primarily through acquisitions of existing production and working interest investments in drilling programs of experienced and successful oil and gas operators active in Texas, Louisiana and Oklahoma .

We currently focus our efforts on our oil and natural gas properties on the Mary King Estell lease in the Richard King Field of Nueces County, Texas. We intend on building our business by acquiring additional non-operated working interests in productive oil and natural gas wells and other oil and gas interests. A non-operated working interest grants us a proportionate share of the property’s oil and gas production, and requires us to pay a proportionate share of the costs associated with drilling and production without acting as the operator of the property’s wells.

We have a non-operated working interest in five gas wells in the Richard King Field of Nueces County, Texas. Durango Resources Corporation is the operator of the wells.

Our Properties

We currently have the following oil and gas property interests:

Property		Non-Operated Working Interest		Net Revenue Interest		Area (acres)
Richard King Field		15%		11.25% (1)		160

(1) Based on a 75% net revenue interest for all working interest owners.

We are mainly focused on the following activities:

Identifying attractive investment opportunities in the oil and gas industry with moderate risk and favorable upside potential;

Negotiating the acquisition of working interests on terms that we feel are favorable to us;

Acquiring non-operated working interests in oil and gas wells and mineral interests that we can exploit for the benefit of our stockholders;

Earning secure and reliable revenue from non-operated working interests while engaging in the exploration and development of oil and gas properties to generate additional revenue; and

Managing the return on our investments to replace reserves and increase revenue through re-investment activities.

The following table sets forth summary information about our net oil and gas assets as of December 31, 2008:

Estimated Proved Reserves at

December 31, 2008(1)

Production for

the Year

Ended

December 31,

Reserve-to-

Production

Estimated 2008

Production

Oil

(Bbl)

NGL

(Bbl)

Gas

(MMcf)

Total

(BOE)(2)

2008

(BOE)(2)

Ratio

(Years)(3)

Decline

Rate(4)

5,690

1,780

217

43,637

7,127

6.12

14%

(1)

Proved Reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations.

(2)

Barrels of oil Equivalent (BOE) is a unit of energy that approximates the energy released by burning one barrel of oil. A BOE is typically 6,000 cubic feet of natural gas. BOE calculations are estimates due to the variance of btu content amongst barrels of oil and cubic feet of natural gas. BOE’s in the above table are used as an approximation for measuring the total energy contained in oil and natural gas either produced or remaining as reserves.

(3)

This ratio estimates the number of years that it would require to produce our remaining reserves assuming that production rates are held constant.

(4)

Estimated production decline measures the petroleum produced as a percentage of the total reserves remaining at the end of the period plus production in that period.

Proved Reserves as of 12/31/2008

	Aldwell Unit				Mary King Estell
	Oil (bbl)		Gas (MMcf)		Oil (bbl)		Gas (MMcf)
PDP		4,094		10.8		40		38.6
PBP		0		0		129		75.6
PUD		1,279		4.6		149		87.8
Total		5,372		15.4		318		202

Engineering abbreviations are as follows: Proved Developed Reserves (PDP), Proved Behind Pipe Reserves (PBP), and Proved Undeveloped Reserves (PUD)

We also make equity investments in other oil and gas companies. In September and October 2008, we purchased an aggregate of 350,000 shares of common stock of Meridian Resources Corporation, an exploration and production company whose shares trade on the New York Stock Exchange under the ticker symbol “TMR.” As of December 31, 2008, we incurred an unrealized holding loss of $325,465 on our investment. As of December 31, 2008 the net market value of our investment was $199,500, comprising approximately 22.2% of total assets. In June 2009, we sold an aggregate of 100,000 shares of common stock of Meridian Resources and realized a loss of $134,096. On January 4, 2010, we sold our remaining 250,000 shares of common stock in Meridian Resources Corporation and realized a loss of approximately $280,000 based on an average cost basis. Although we no longer have an equity investment in Meridian Resources Corporation or any other company, we may buy such equities in the future. We do not have any current plans, proposals or arrangements, written or otherwise, to purchase shares of common stock in Meridian Resources Corporation or any other company. As of September 30, 2009 we determined the decline in value of the Meridian Resources shares to be other than temporary. Based on this determination the shares were adjusted to their market value as of September 30, 2009 of $102,500. The difference between the cost and market value of the shares was recorded as impairment expense for $243,095.

In the future, we may make investments depending on whether we find any unique investment opportunities and if we have sufficient capital to execute such plans. Our future business plans may also include the acquisition of mineral lease interests, purchase of existing production and infrastructure and equipment.

Our principal office is located at 1240 Blalock Road, Suite 150, Houston, Texas 77055. We currently lease approximately 3,000 square feet and incurred approximately $25,000 in rent expense for 2008. We believe the size of our office space is sufficient for our business purposes.

The Offering

	Securities Offered		We are offering up to $10,000,000 in aggregate principal amount of our 3 Year Notes. The Company will establish an initial interest reserve equal to five percent of gross proceeds from the Offering and deposit with a third party as subscriptions are received. See “Description of 3 Year Notes.”

	Denominations		Increments of at least $1,000.

	Minimum Investment		A minimum initial investment of $1,000 is required.

	Form of Investment		Investments in 3 Year Notes may be made by check or wire.

	Interest Rate		Fixed interest rate, calculated using 365-day year, of 10% per annum.

	Payment of Interest		Interest is payable on a quarterly basis in arrears.

	3 Year Maturity		3 Year Notes shall mature 3 years from the date of your purchase.

	Redemption by Us		We may redeem the 3 Year Notes at any time after one year from the date of purchase and upon 15 days prior written notice to you for a price equal to principal plus interest accrued to the date of redemption.

	Subordinated		3 Year Notes are general unsecured obligations and will rank junior and be subordinate in right of payment to all future senior debt. The 3 Year Notes will not be secured by liens on any of our assets. This means that if we are unable to pay our debts when due, the 3 Year Notes would all be paid, if at all, after any payment would be made on any senior debt.

	Event of Default		An event of default on the 3 Year Notes is generally defined as a default in the payment of principal, or a default in the payment of interest, our becoming subject to certain events of bankruptcy or insolvency, or our failure to comply with any covenant contained in the Indenture.

	Indenture and Trustee		The 3 Year Notes will be governed by an Indenture and a trustee will represent the interest of holders of 3 Year Notes.

	Use of Proceeds		If all the 3 Year Notes offered by this prospectus are sold, we expect to receive approximately $8,800,000 in net proceeds after deducting all costs and expenses associated with this Offering, assuming a Placement Agent is retained. We intend to use the net proceeds from this Offering to first pay for operating expenses, including management compensation related to the operation of the Company. We then plan on using the proceeds to purchase working interests in existing oil and gas production and new drilling opportunities. Further, we will reserve an amount of money equal to 5% of the gross proceeds from the Offering for payment of interest. See “Use of Proceeds” for more information.

	Material Tax Consequences		For a discussion of material federal income tax consequences that may be relevant to prospective 3 Year Note holders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

	Listing and Trading Symbol		Our 3 Year Notes have not been approved for trading on any exchange and we have no current plans to request such a listing.

	Risk Factors		See “Risk Factors” on page 12 and other information included in this prospectus and any prospectus supplement for a discussion of factors you should carefully consider before investing in the 3 Year Notes.

Our Company

We were incorporated in the State of Nevada on July 5, 2005 with the objective to own and acquire producing oil and gas properties and to participate in the drilling of new oil & gas wells. Our principal office is located at 1240 Blalock Road, Suite 150, Houston, Texas 77055. Our telephone number is (713) 266-3700. Information about us can be found at www.southfieldenergy.com . Information contained in our website does not constitute part of this prospectus.

Other Information

We expect to make our periodic reports and other information filed or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

RISK FACTORS

The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our 3 Year Notes.

The risk factors set forth below are not the only risks that may affect our business. Our business could also be impacted by additional risks not currently known to us or that we currently deem to be immaterial. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the principal and interest on our3 Year Notes, and you could lose part or all of your investment.

Risks Related to Our Business

We may not have sufficient cash flow from operations to pay interest on the 3 Year Notes when due or to repay principal upon maturity.

Revenue and profit from oil and gas is uncertain. Prices may drop lower than they are today. We expect to invest in working interests in new oil and gas wells. These investments may not be profitable and we may lose our entire investment. Oil and gas properties are depleting assets and we will have to successfully continue to find additional oil and gas to offset the natural decline of producing wells in which we own an interest. These uncertainties are a material risk of investing in oil and gas and may materially affect our ability to make interest payments when due and to repay principal upon maturity.

The amount of cash we actually generate will depend upon numerous factors related to our business including, among other things:

•

the amount of oil and gas our operators produce;

•

the prices at which our operators sell our oil and gas production;

•

the level of our operating costs, including fees and reimbursement of expenses expended to operate the company and to compensate its management team, board of directors and employees;

•

our ability to replace declining reserves;

•

prevailing economic conditions;

•

the level of competition we face;

•

fuel conservation measures and alternate fuel requirements; and

•

government regulation and taxation.

In addition, the actual amount of cash that we will have available to make payments on the principal and interest of the 3 Year Notes will depend on other factors, including:

•

the level of our expenditures for acquisitions of additional oil and gas investments;

•

our ability to make borrowings or to raise additional capital in the future;

•

sources of cash used to fund acquisitions;

•

debt service requirements of our 3 Year Notes or future financing agreements;

•

fluctuations in our working capital needs;

•

general and administrative expenses;

•

timing and collectability of any receivables; and

•

the amount of cash reserves established by our management team for the proper conduct of our business.

All of our current revenues are generated by our interest in the Richard King Field. Delays or interruptions in our interests in the Richard King Field natural gas and production operations including, but not limited to, the failure of third parties on which we rely to provide key services, could negatively impact our revenues.

Approximately 80% of our oil and natural gas revenue for the year ended December 31, 2008 and the nine months ended September 30, 2009 was derived from the Richard King Field. As of September 30, 2009, 100% of our oil and natural gas properties were derived from the Richard King Field. Should the production in this field decrease at a rate faster than anticipated, our revenues and cash flow to make payments on the 3 Year Notes could be adversely affected. In connection with the Richard King Field, we have partnered with Durango Resources Corporation as operator. The failure of Durango Resources to perform its duties as operator in the Richard King Field could prevent us from generating revenues. In addition, events referred to as force majeure, such as an act of God, act of a public enemy, fire, flood, lightning, etc. could prevent us from generating revenues.

Effective September 2009, we sold our assets located in the Aldwell Unit to Mariner Energy, Inc., the operator, for approximately $300,000, excluding a six percent sales commission. The Aldwell Unit accounted for the remaining balance of our oil and natural gas revenue for the year ended December 31, 2008 and the nine months ended September 30, 2009. As such, for the remainder of the fiscal year, our future revenues will be derived primarily from our Richard King Field properties.

Our business may be harmed by failures of third party operators on which we rely.

Our ability to manage and mitigate the various risks associated with our operations in Nueces County, Texas, is limited since we rely on third parties to operate our projects. We are a non-operating interest owner in our properties. With respect to our non-operated working interests, we have entered into agreements with third party operators for the conduct and supervision of drilling, completion and production operations. In the event that commercial quantities of oil and natural gas are discovered on one of our properties, the success of the oil and natural gas operations on that property depends in large measure on whether the operator of the property properly performs its obligations. The failure of such operators and their contractors to perform their services in a proper manner could result in materially adverse consequences to the owners of interests in that particular property, including us.

We cannot control activities on properties we do not operate. Our inability to fund required capital expenditures with respect to non-operated properties may result in a reduction or forfeiture of our interests in those properties.

Other companies operated all of our production as of September 30, 2009. We have limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital with respect to exploration, exploitation, development or acquisition activities. The success and timing of exploration, exploitation and development activities on properties operated by others depend upon a number of factors determined by the operator, including:

•

the timing and amount of capital expenditures;

•

the operator's expertise and financial resources;

•

approval of other participants in drilling wells; and

•

selection of drilling, completion and production equipment.

Where we are not the majority owner or operator of a particular oil and natural gas project, we may have no control over the timing or amount of capital expenditures associated with the project. If we are not willing and able to fund required capital expenditures relating to a project when required by the majority owner or operator, our interests in the project may be reduced or forfeited.

Because oil and gas properties are depleting assets we mustdrill new wells or make acquisitions in order to maintain our production and reserves and sustain our payments of principal and interest to the 3 Year Note holders over time.

Producing oil and gas reservoirs are characterized by declining production rates. Because our reserves and production decline continually over time, we will need to drill additional wells or make acquisitions to sustain revenue over time. We may be unable to accomplish this if:

•

Sellers do not agree to sell any assets to us;

•

we are unable to identify attractive drilling or acquisition opportunities in our area of operations;

•

we are unable to agree on investment terms or a purchase price for assets that are attractive to us; or

•

we are unable to obtain financing for acquisitions on economically acceptable terms.

We will require substantial capital expenditures to replace our production and reserves, which will reduce our available cash for interest and principal payments. We may be unable to obtain needed capital or financing due to our financial condition, which could adversely affect our ability to replace our production and proved reserves.

To fund our projects, we will be required to use cash generated from our operations in addition to the proceeds of this Offering. We may also engage in additional borrowings or obtain financing from the issuance of additional equity interests in the Company, or some combination thereof. To the extent our production declines faster than we anticipate or the cost to acquire additional reserves is greater than we anticipate, we will require a greater amount of capital to maintain our production and proved reserves. The use of cash generated from operations to fund oil and gas investments will reduce cash available to pay interest and principal on our 3 Year Notes. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, the covenants in our 3 Year Notes or future financing agreements, adverse market conditions or other contingencies and uncertainties that are beyond our control. Our failure to obtain the funds necessary for future oil and gas investments could materially affect our business, results of operations, financial condition and ability to pay interest and principal on the 3 Year Notes.

Any new wells in which we participate are subject to substantial risks that could reduce our ability to make profits from operations.

Investments that we believe will increase revenue, may nevertheless result in losses. Any oil and gas investment involves potential risks, including, among other things:

•

the validity of our assumptions about reserves, future production, revenues and costs, including synergies;

•

a decrease in our liquidity by using a significant portion of our available cash to finance investments;

•

a significant increase in our interest expense or financial leverage if we incur additional debt to finance investments;

•

the diversion of management’s attention from other business concerns; and

•

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets.

We could lose our ownership interests in our properties due to a title defect of which we are not presently aware.

As is customary in the oil and gas industry, only a perfunctory title examination, if any, is conducted at the time properties believed to be suitable for drilling operations are first acquired. Before starting drilling operations, a more thorough title examination is usually conducted and curative work is performed on known significant title defects. We typically depend upon title opinions prepared at the request of the operator of the property to be drilled. The existence of a title defect on one or more of the properties in which we have an interest could render it worthless and could result in a large expense to our business. Industry standard forms of operating agreements usually provide that the operator of an oil and natural gas property is not to be monetarily liable for loss or impairment of title. The operating agreements to which we are a party provide that, in the event of a monetary loss arising from title failure, the loss shall be borne by all parties in proportion to their interest owned.

The pricesof oil and gas have reached historic highs in recent years and are highly volatile. A sustained decline in these commodity prices wouldcause a decline in our cash flow from operations, which may force us to reduceprincipal and interest payments on the 3 Year Notes or cease paying them altogether.

The oil and gas markets are highly volatile, and future oil and gas prices are uncertain. Oil and gas prices reached historically high levels in mid 2008, when oil sold for over $140 per barrel and natural gas sold for over $12 per thousand cubic feet (mcf). However, as of the date of this Offering, prices for oil and natural gas are currently fluctuating between $60-80 per barrel and $3-5 per mcf, less than 50% of their previous highs. Prices for oil and gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors, such as:

•

domestic and foreign supply of and demand for oil and gas;

•

weather conditions;

•

overall domestic and global political and economic conditions, including those in the Middle East, Africa and South America;

•

actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

•

the impact of increasing liquefied natural gas, or LNG, deliveries to the United States;

•

technological advances affecting energy consumption and energy supply;

•

domestic and foreign governmental regulations and taxation;

•

the impact of energy conservation efforts;

•

the capacity, cost and availability of oil and gas pipelines and other transportation facilities, and the proximity of these facilities to our wells; and

•

the price and availability of alternative fuels.

Our revenue, profitability and cash flow depend upon the prices and demand for oil and gas, and a drop in prices can significantly affect our financial results and impede our growth. We may not be able to sustain payments of principal and interest to the 3 Year Note holders during periods of lower commodity prices.

Future price declines may result in another write-down of our asset carrying values, which could adversely affect our results of operations and limit our ability to borrow and make payments on the principal and interest to the 3 Year Note holders.

Further declines in oil and gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of production or economic factors change, accounting rules may require us to write down, as a noncash expense, the carrying value of our oil and gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying values may not be recoverable and therefore require write-downs. We may incur further impairment charges in the future, which could materially affect our results of operations in the period incurred and our ability to borrow funds, which in turn may adversely affect our ability to generate revenues.

Our futurehedging activities could result in financial losses or could reduce our income, which may adversely affect our ability to repayinterest and principal on the 3 Year Notes when due.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we may enter into derivative arrangements covering a significant portion of our oil and gas production that could result in both realized and unrealized hedging losses.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our proved reserves.

It is not possible to measure underground accumulations of oil or gas in an exact way. Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and gas and assumptions concerning future oil, natural gas and natural gas liquid (“NGL”) prices, production levels, and operating and development costs. In estimating our level of proved oil and gas reserves, we and our independent reservoir engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

•

a constant level of future oil, NGL and gas prices;

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future production levels;

•

capital expenditures;

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operating and development costs;

•

the effects of regulation; and

•

availability of funds.

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil, NGL and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our proved reserves could change significantly. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and gas properties also will be affected by factors such as:

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the actual prices we receive for oil, NGL and gas;

•

our actual operating costs in producing oil, NGL and gas;

•

the amount and timing of actual production;

•

the amount and timing of our capital expenditures;

•

supply of and demand for oil, NGL and gas; and

•

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the production and development of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s Statement of Financial Accounting Standards No. 69 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Producing oil and gas involves numerous risks and uncertainties that could adversely affect our financial condition or results of operations and, as a result, limitour ability to pay principal and interest payments to our3 Year Note holders.

As non-operated working interest owners we do not operate wells; however, we share in the costs of production for these wells. The operating cost of a well includes variable costs, and increases in these costs can adversely affect the economics of a well. Furthermore, our producing operations may be curtailed or delayed or become uneconomical as a result of other factors, including:

•

high costs, shortages or delivery delays of equipment, labor or other services;

•

unexpected operational events and/or conditions;

•

reductions in oil, NGL and gas prices;

•

limitations in the market for oil, NGL and gas;

•

adverse weather conditions;

•

facility or equipment malfunctions;

•

equipment failures or accidents;

•

title problems;

•

pipe or cement failures or casing collapses;

•

compliance with environmental and other governmental requirements;

•

environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

•

lost or damaged oilfield work over and service tools;

•

unusual or unexpected geological formations or pressure or irregularities in formations;

•

fires;

•

natural disasters; and

•

uncontrollable flows of oil, gas or well fluids.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.

We may incur debt to enable us to pay our interest and principal payments, which may negatively affect our ability to execute our business plan.

If we use borrowings under a credit facility to meet 3 Year Note obligations for an extended period of time rather than toward funding future investments and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available to make payments of principal and interest on our 3 Year Notes and will materially affect our business, financial condition and results of operations.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Operators of our wells are subject to a variety of operating risks in our wells, gathering systems and associated facilities, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses.

We currently possess a Business Owners insurance policy which includes property, business interruption and general liability insurance at levels we believe are appropriate for an early stage company; however, insurance against all operational risk is not available to us. We are not fully insured against all risks. In addition, pollution and environmental risks generally are not fully insurable.

Shortages of drilling rigs, supplies, oilfield services, equipment and crews could delay our operations and reduce our availablecash.

To the extent that in the future we acquire and develop undeveloped properties, higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our future ability to drill wells and conduct operations. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our future revenues and cash available for distribution.

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, and results of operations.

If third-party pipelines and other facilities interconnected to our gas pipelines and processing facilities become partially or fully unavailable to transport gas, our revenues from operations could be adversely affected.

We depend upon third party pipelines and other facilities that provide delivery options to and from pipelines and processing facilities that our operators utilize. If any of these third-party pipelines and other facilities become partially or fully unavailable to transport gas, or if the gas quality specifications for these pipelines or facilities change so as to restrict our operators’ ability to transport gas on these pipelines or facilities, our revenues and cash available to make principal and interest payments to the 3 Year Note holders could be adversely affected.

Our operations are subject to various litigation risks that could increase our expenses, impact our profitability and lower the value of your investment in us.

We are not currently involved in any litigation; however, the nature of our operations exposes us to possible future litigation claims. There is a risk that any claim could be adversely decided against us, which could harm our financial condition and results of operations. Similarly, the costs associated with defending against any claim could dramatically increase our expenses, as litigation is often very expensive. Possible litigation matters may include, but are not limited to, environmental damage and remediation, insurance coverage, property rights and easements and the maintenance of oil and gas leases. Should we become involved in any litigation we will be forced to direct our limited resources to defending against or prosecuting the claim(s), which could impact our profitability and lower the value of your investment in us.

Our business is subject to environmental legislation and any changes in such legislation could prevent us from earning revenues.

The oil and gas industry is subject to many laws and regulations that govern the protection of the environment, health and safety and the management, transportation and disposal of hazardous substances. These laws and regulations may require the removal or remediation of pollutants and may impose civil and criminal penalties for any violations thereof. Some of the laws and regulations authorize the recovery of natural resource damages by the government, injunctive relief and the imposition of stop, control, remediation and abandonment orders.

Complying with environmental and natural resource laws and regulations may increase our operating costs as well as restrict the scope of our operations. Any regulatory changes that impose additional environmental restrictions or requirements on us could affect us in a similar manner. If the costs of such compliance or changes exceed our budgeted costs, we may not be able to earn revenues.

We may become an “investment company” as defined in the Investment Company Act of 1940.

Under the Investment Company Act of 1940 (the “ Company Act”), as amended, we may be deemed to be an inadvertent investment company if it is determined that the value of the Company’s future equity investments, if any, account for more than 40% of the total value of the Company’s assets, and no other exemption is available. As of September 30, 2009 our investment in Meridian Resources Corporation comprised only approximately 12.4% of total assets. However, on January 4, 2010, we sold 250,000 shares of common stock in Meridian Resources Corporation and realized an approximate loss of $280,000 based on an average cost basis. This sale comprised all of our remaining shares in Meridian Resources and we thus no longer have an equity investment in Meridian Resources or any other corporation. We do not have any current plans, proposals or arrangements, written or otherwise, to make an equity investment in Meridian Resources Corporation or any other company. But, if we do make an equity investment in another company in the future, we may be deemed an “investment company” under the Company Act if such investment constitutes more than 40% of the total value of our assets.

Investment companies are subject to substantial regulation concerning management, operations, transactions with affiliated persons, portfolio composition, including restrictions with respect to diversification and industry concentration and other restrictions, and, unless we complied with the Company Act, we would be prohibited from engaging in transactions involving interstate commerce. To comply, we would be required to significantly modify our operating structure and file reports with the SEC regarding various aspects of our business. The cost of such compliance would result in the Company incurring substantial additional annual expenses. In addition, compliance with the Company Act may not be consistent with the Company’s current business strategies.

Risks Related to this Offering

We may issue additional debt, including notesthat are senior to the current 3 Year Notes, without your approval.

The amount of additional debt that can be raised by us is not limited. We may issue an unlimited number of notes that are senior to the 3 Year Notes without your approval.

3 Year Note Holders will not have the same rights to vote on matters submitted to the shareholders for consideration and approval as the holders of common shares.

Certain matters, such as the appointment of directors, amendment of corporate documents, etc. must be submitted to a vote of the shareholders for approval. The 3 Year Note Holders will not have voting rights on such matters as do the common shareholders.

3 Year Note Holders will have very limited liquidity for their 3 Year Notes. We do not intend nor expect to request that Southfield be listed for trading on any exchange.

The Company does not intend nor expect to list the 3 Year Notes registered in this Offering for trading on any exchange or over-the-counter listing service. As a result, the Holders of the 3 Year Notes are not expected to have any market liquidity in their investment and should be prepared to hold the 3 Year Notes to Maturity.

As a result of investing in our 3 Year Notes, you may become subject to state and local taxes.

Interest earned on the 3 Year Notes will be taxed by the Federal and state governments in accordance with current and future tax laws. You should expect to pay taxes at your marginal rate for investments of this type.

Some of our officers and directors have relationships with other companies in the oil and natural gas industry that could result in conflicts of interest.

Some of our officers and directors serve as officers and directors of other companies engaged in the oil and natural gas industry and may have other relationships with such companies. For example, Chet Gutowsky and Tyson Rohde both serve as officers and directors of Biotricity Corporation, an alternative energy company located in Houston, Texas. To the extent those companies are involved in ventures in which we may participate, or compete for acquisitions or financial resources with us, the relevant director will face a conflict of interest. In the event such a conflict arises, the relevant director will be required to disclose the nature and extent of the conflict and abstain from voting for or against any action of the board of directors that is or could be affected by the conflict.

We are dependent upon our key officers and employees and our inability to retain and attract key personnel could significantly hinder our growth strategy and cause our business to fail.

A loss of one or more of our current directors, officers or key employees could severely and negatively impact our operations and delay or preclude us from achieving our business objectives. Our executive officers have a combined experience of approximately 50 years in the oil and gas industry. We have not entered into employment agreements with our officers, and we could suffer the loss of key individuals for one reason or another at any time in the future. There is no guarantee that we could attract or locate other individuals with similar skills or experience to carry out our business objectives.

Our directors and officers hold significant positions in our shares of common stock and their interests may not always be aligned with those of our other shareholders.

As of September 30, 2009 our directors and officers beneficially own 18.9% of our outstanding common stock. See “Security Ownership of Certain Beneficial Owners and Management.” This shareholding level will allow the directors, officers and certain beneficial owners to have a significant degree of influence on matters that are required to be approved by shareholders, including the election of directors and the approval of significant transactions. The short-term interests of our directors, officers and certain beneficial owners may not always be aligned with the long-term interests of our shareholders, and vice versa. Because our directors, officers and certain beneficial owners have a significant degree of influence on matters that are required to be approved by our shareholders, they could influence the approval of transactions.

The 3 Year Notes will not be issued under the protections of the Trust Indenture Act of 1939.

You should be aware that the Indenture is not a trust indenture qualified under the Trust Indenture Act of 1939, as amended (the “ Indenture Act” ) . A qualified trust indenture is often required for public offerings of debt securities in principal amounts of more than $10 million. A non-qualified trust indenture may also be required in public offerings of debt securities in principal amounts less t han $10 million. The term “ qualified” relates to mandatory provisions of a trust indenture and the requirements of independence of the indenture trustee in relation to the entity offering the debt securities. The presence of a qualified trust indenture a nd independent indenture trustee is generally intended to provide for the collective representation of debt investors through the monitoring activities of the indenture trustee as to:

The authentication and issuance of debt sec urities;

The monitoring of events of default and the taking of remedial action by the trustee for the collective benefit of the investors;

The maintenance of collateral which may secure the debt secur ity obligations; and

Other matters relating to the terms of the debt security issuance intended to protect investor initially and on a continuous basis.

While we believe the Indenture contains some of the terms an d provisions of a qualified trust indenture, you do not have all the protective aspects of a trust indenture and an independent trustee and may be required to act individually on your own behalf if we fail to make a required principal or interest payment o n your 3 Year Note.

We have not deposited any collateral with the Trustee to secure payment of any interest of principal on the 3 Year Notes.

We are offering unsecured, general obligation 3 Year Notes. As such, we are not required and have not deposited any collateral with the Trustee to secure payment of interest and principal on 3 Year Notes. We will only reserve an amount equal to 5% of gross proceeds from the Offering for payment of interest.

There may not be any money available to pay your respective 3 Year Note.

We will issue 3 Year Notes as subscriptions are accepted by us. Each 3 Year Note will be issued as of the acceptance date, and will mature 3 years from the date of issuance. Your 3 Year Note may have a later maturity date than investors who subscribed before you. It is possible that some investors who subscribed before you will receive principal and interest payments before you, by virtue of them subscribing to the Offering before you. We may run out of money to fulfill our principal and interest obligations to you and other investors who subscribed at the same time or later than you.

USE OF PROCEEDS

We expect to receive net proceeds from this Offering of approximately $8.8 million, assuming the maximum offering of $10.0 million is raised and further assuming that we will engage the services of a Placement Agent to assist in selling the 3 Year Notes. In such event, we estimate that we would pay Placement Agent commissions of up to $800,000 and a non-accountable expense allowance of up to $300,000. In addition, we will incur Other Expenses of up to $100,000. Other Expenses below include legal, accounting and engineering fees, printing and distribution costs for the Offering and Offering related travel and communication costs. From the Net proceeds to Company, an amount of money will be reserved equal to five percent of gross proceeds from the Offering for interest payments due on the 3 Year Notes. Such interest payments will be managed by a third party trustee (the “Trustee”), and paid as due to the 3 Year Note holders.

Estimated Offering expenses:

Total Offering Amount	$	10,000,000

Sales Commissions		800,000

Non-Accountable Expense Allowance		300,000

Other Expenses		100,000

Net Proceeds to Company	$	8,800,000

We intend to use the estimated net proceeds of the Offering to first pay for operating expenses, including management compensation related to the operation of the Company. We then intend to use the proceeds to purchase non-operated working interests in new and existing oil and gas projects. We may also make equity investments in other oil and gas companies. Further, we may acquire mineral lease interests, purchase interests in oil and gas properties with existing production, make investments in the drilling and completion of new wells, purchase certain oil and gas infrastructure and equipment, and use the proceeds for other general corporate purposes. Additionally, we may also use a portion of the proceeds of the Offering to address future capital requirements to convert proved behind pipe reserves and proved undeveloped reserves into proved developed producing reserves.

The goal of management will be to maximize the returns available from the investment of the capital raised in this Offering through an investment strategy designed to manage risk through portfolio diversification. In order to achieve that goal, management will reserve the right to make related investments outside of the scope of our primary current expectations as market conditions change and as unique opportunities present themselves. This discretion by management may allow for the use of proceeds in ways other than those described above when management and the Board of Directors finds it is in the best interests of the shareholders and 3 Year Note holders to do so.

DESCRIPTION OF 3 YEAR NOTES

The complete terms of the 3 Year Notes are set forth under this Description of 3 Year Notes, Summary of Indenture the Trust Indenture and, together with the Subscription Agreement provided to prospective investors with this prospectus, constitute the entire agreement between us and any prospective investor with respect to the 3 Year Notes. See “Risk Factors” beginning on page 12 for certain factors you should consider before buying the 3 Year Notes .

The 3 Year Notes

The 3 Year Notes that we are offering by means of this Prospectus have been authorized by our board of directors. The 3 Year Notes are general obligation instruments and are issued as such. The following are the terms under which the 3 Year Notes are offered.

General

The Offering of the 3 Year Notes pursuant to this Prospectus is limited to the aggregate principal amount of $10,000,000. The 3 Year Notes will be issued in denominations of at least $1,000 and multiples thereof as may be authorized by the Company. A minimum purchase of $1,000 is required. The 3 Year Notes will mature three years from the date of purchase.

Principal, Interest and Type of 3 Year Notes

The 3 Year Notes will mature three years from the date of issuance. The interest rate on the 3 Year Notes will be fixed at 10% per annum calculated based on a 365-day year. Interest due on the 3 Year Notes will be paid to the holder of record on the last day of each quarter on a quarterly basis in arrears. Simple interest will accrue on the 3 Year Notes from the date of purchase when an executed Subscription Agreement and payment is received and accepted by us or at the office of the Placement Agent, if applicable. The issue date will be the same as the date of purchase. Principal and interest will be paid to the holder of the 3 Year Note specified by the subscriber in the Subscription Agreement.

The total pay out to an investor on a $10,000 investment in a 3 Year Note will be $13,000 over its term. All payments of principal and interest will be made in U.S. dollars.

Subordination

The 3 Year Notes are general unsecured liabilities of the Company, and will rank junior and be subordinate in right of payment to all future senior debt. The 3 Year Notes will not be secured by liens on any of our assets. This means that if we are unable to pay our debts when due, the 3 Year Notes would all be paid, if at all, after any payment would be made on any senior debt.

Acceptance

An offer of the 3 Year Notes will be accepted by the Company upon the receipt by you of a countersigned signature page to the Subscription Agreement.

Rejection

The Company may reject your offer of 3 Year Notes for any reason or no reason at all. Any rejection will result in any funds tendered by you to be promptly returned, without deduction of interest.

Restrictions on Transfer

The Company does not expect to list the 3 Year Notes for trading on any exchange or listing service. It is not expected that there will be any liquid market for the sale of the 3 Year Notes. 3 Year Note Holders should expect to hold their 3 Year Notes until maturity.

No personal liability of directors, officers, employees and stockholders

No director, officer, employee, incorporator or stockholder of the Company shall have any liability for any obligations of the Company under the 3 Year Notes, the prospectus for any claim based on, in respect of, or by reason of, such obligations or their creation. Each 3 Year Note holder waives and releases all such liability. The waiver and release are part of the consideration for issuance of the 3 Year Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the Securities and Exchange Commission that such a waiver is against public policy.

Voting Rights

3 Year Note holders will not have voting rights like those held by the owners of common stock and will not be able to vote on the election of directors or on other matters submitted to the shareholders for a vote by the Corporation.

Issuance of Additional Securities

The Company is not restricted by the terms of the 3 Year Notes from issuing additional equity or debt securities. As needed in the future, the Company may sell common or preferred stock to raise capital. It may also retain additional senior secured or subordinated debt to finance future operations. 3 Year Note holders could be affected by future issuances of securities by the Company and no approval by the 3 Year Note holders will be required.

Information Returns and Audit Procedures

We intend to furnish to each 3 Year Note Holder a copy of our annual report, upon request, as filed with the SEC for as long as any of the 3 Year Notes remain outstanding.

Governing Law

The 3 Year Notes and Indenture shall be interpreted, construed and governed by and in accordance with the laws of the state of Texas, without regard to conflicts of laws.

SUMMARY OF INDENTURE

The 3 Year Notes are being issued pursuant to the provisions of an Indenture which we have entered into with an Attorney at Law licensed to practice in the State of Texas who will act as the trustee under the Indenture. The features of the Indenture are as follows:

Trustee

The Company has entered into an Indenture that appoints a trustee to assist in managing the payment of the interest and principal to the 3 Year Note holders. Under the Indenture, the Company will establish an initial interest reserve equal to 5% of the gross proceeds from the Offering and deposit with the Trustee as subscriptions are received. The trustee will be obligated to facilitate interest payments to the 3 Year Note holders, including payment under the initial interest reserve, among other duties. In exchange, we will pay the trustee and/or the trustee’s agents cash and/or the value of our common stock not exceeding an aggregate of $100,000 per year. The Trustee may contract with a Servicing Agent to assist with the administration of the 3 Year Notes including; payment of principal and interest, registration and transfer of holders of 3 Year Notes, and administration of the interest reserve account.

Registrar

The trustee shall cause to be kept at an office or agency, to be maintained by the trustee or one of its agents, a register that provides for the ownership of the 3 Year Notes and any transfer thereof.

Reregistration

Upon written request, submission of legal authorization, payment of transfer charges and subject to Company approval, you may reregister 3 Year Notes to be held in the name of a related entity.

No Mandatory Redemption

The 3 Year Notes are not subject to any mandatory redemption. No holder of a 3 Year Note shall have any right whatsoever to require the Company to purchase or to redeem any 3 Year Note prior to the stated maturity date.

Optional Redemption

The 3 Year Notes are subject to redemption at the option of the Company in whole or in part from time to time of the principal amount plus accrued interest to such redemption date. After one year from the date of purchase, the Company may elect to redeem or call any or all of the 3 Year Notes at its discretion with fifteen (15) days prior written notice to the investor.

Limitations On Mergers

The Company will not consolidate with or merge into any corporation or convey or transfer its assets in their entirety or substantial entirety unless the successor corporation expressly assumes in writing the payment of principal and interest on all 3 Year Notes as they come due, in accordance with the covenants in this Offering. Upon any such consolidation, merger, conveyance or transfer, the successor corporation will succeed to and be substituted for the Company under this prospectus and, thereafter, the Company will be relieved of all obligations under the prospectus and 3 Year Notes.

Default and Notice Thereof

The occurrence of only any of the following events will constitute an event of default:

failure for 60 days to pay the interest when due on any of the 3 Year Notes;

failure for 60 days to pay the principal when due on any of the 3 Year Notes;

failure for 60 days after notice to perform any other covenant or agreement contained in this prospectus; or

the occurrence of acts of bankruptcy, insolvency or reorganizations.

The Company is not required to notify the 3 Year Note holders of the occurrence of any of the above events of default known to it. Upon the occurrence of default, the trustee may elect to send notice of said event of default to the Company. The trustee may then pursue any available remedy granted in the Indenture and/or by suit at law or take any other action to enforce payment of principal and interest on the 3 Year Notes. Holders of 3 Year Notes may institute a proceeding at law or in equity to enforce its rights under the Indenture in only limited circumstances.

Waiver of Default

The trustee shall waive any event of default and rescind any declaration of maturity of principal upon the written request of the holders of a majority in aggregate principal amount of the 3 Year Notes then outstanding in respect of which such default exists; provided, however, that the same shall not be waived without the consent of the holder of each 3 Year Note so affected.

Notice

Within ninety days after the occurrence of any event of default of which the trustee has actual knowledge or notice, the trustee shall unless such default has been cured or waived, mail notice thereof to each registered owner of 3 Year Notes.

Amendments Without Consent of 3 Year Note Holders

The Indenture may be amended and supplemented from time to time when authorized by resolution of the board of directors, without any notice to or action on the part of the 3 Year Note holders to enter into a supplemental indenture as may or shall be deemed necessary for any of the following purposes, among others:

(a)

to correct scrivener’s errors; and

(b)

to add to the covenants of the Issuer for the protection of the 3 Year Note holders.

Amendments and Supplements with Consent of 3 Year Note holders.

The Indenture may be amended or supplemented for any purpose other than those described above, when authorized by resolution of the board of directors provided that no such amendment or supplement shall occur without the consent of the holder of any 3 Year Note affected thereby to extend the maturity of such 3 Year Note, reduce the rate of interest, or otherwise change the terms of payment of principal or interest, or impair the right of a holder of a 3 Year Note holder to institute suit for the enforcement of payment of principal or interest on or after the respective due date thereof.

Notwithstanding the foregoing, anytime that the trustee is required or requested to obtain the consent of the 3 Year Note holders to any matter, the trustee may do so in such a manner that the failure of a 3 Year Note holder to deliver an objection to the trustee within twenty (20) days from the date of notice to the 3 Year Note holder shall be deemed as the consent of such 3 Year Note holder.

Limitations of Trustee’s Liability

The trustee shall not be liable except in connection with the performance of such duties as are specifically set out in the Indenture. The Company by its execution of the Indenture and the 3 Year Note holders by their subscriptions of the 3 Year Notes agree that the trustee shall not be responsible for any act or omission hereunder unless due to its own gross negligence or willful neglect.

MATERIAL TAX CONSEQUENCES

The following is a summary of certain material United States federal income tax considerations relating to the purchase, ownership and disposition of the 3 Year Notes, but does not purport to be a complete analysis of all the potential tax considerations relating thereto. This summary is based upon the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations promulgated or proposed thereunder, administrative pronouncements and judicial decisions, each as of the date hereof. These authorities may be changed, perhaps retroactively, so as to result in United States federal income tax consequences different from those set forth below. We have not sought any ruling from the Internal Revenue Service or an opinion of counsel with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the Internal Revenue Service will agree with such statements and conclusions. We will treat the 3 Year Notes as indebtedness for federal income tax purposes, and the following discussion assumes that this treatment is correct.

This summary only applies to 3 Year Notes that meet all of the following conditions:

they are purchased by those initial holders who purchase the 3 Year Notes at the “issue price,” which will equal the first price to the public (not including bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers) at which a substantial amount of the 3 Year Notes is sold for money; and

they are held as capital assets within the meaning of Section 1221 of the Code (generally, for investment).

This summary also does not address United States federal estate or gift tax laws or the tax considerations arising under the laws of any foreign, state or local jurisdiction. In addition, this discussion does not address all tax considerations that may be applicable to a holder’s particular circumstances or to holders that may be subject to special tax rules, including, without limitation:

holders subject to the alternative minimum tax;

banks, insurance companies or other financial institutions;

tax-exempt organizations;

regulated investment companies;

real estate investment trusts;

dealers in securities, commodities of foreign currencies;

traders in securities that elect to use a market-to-market method of accounting for their securities holdings;

foreign persons or entities (except to the extent specifically set forth below);

S-corporations, partnerships or other pass-through entities (except to the extent specifically set forth below);

expatriates and certain former citizens or long-term residents of the United States;

U.S. holders (as defined below) whose “functional currency” is not the United States dollar;

persons holding 3 Year Notes as part of a hedge, straddle or other integrated transaction for United States federal income tax purposes; or

persons deemed to sell the 3 Year Notes under the constructive sale provisions of the Code.

If a partnership (or other entity taxable as a partnership for United States federal income tax purposes) holds 3 Year Notes, the tax treatment of a partner in a partnership generally will depend upon the status of the partner and the activities of the partnership. If you are a partner in a partnership holding our 3 Year Notes, you should consult your tax advisor regarding the tax consequences of the purchase, ownership and disposition of the 3 Year Notes.

THIS SUMMARY OF CERTAIN MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS IS FOR GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. YOU ARE URGED TO CONSULT YOUR TAX ADVISOR WITH RESPECT TO THE APPLICATION OF UNITED STATES FEDERAL INCOME TAX LAWS TO YOUR PARTICULAR SITUATION AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF THE 3 YEAR NOTES ARISING UNDER UNITED STATES FEDERAL ESTATE OR GIFT TAX RULES OR UNDER THE LAWS OF ANY STATE, LOCAL, FOREIGN OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.

Consequences to U.S. Holders

The following is a summary of certain material United States federal income tax consequences that will apply to you if you are a U.S. holder of the 3 Year Notes. As used herein, the term “U.S. holder” means a beneficial owner of the note that is, for United States federal income tax purposes:

an individual who is a citizen or resident of the United States;

a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States or of any political subdivision thereof;

an estate, the income of which is subject to United States federal income taxation regardless of its source; or

a trust that: (1) is subject to the primary supervision of a United States court and the control of one or more United States persons; or (2) has a valid election in effect under applicable Treasury Regulations to be treated as a United States person.

Payment of Interest

The 3 Year Notes will be issued without original issue discount for United States federal income tax purposes. Accordingly, you generally will be required to recognize any stated interest as ordinary income at the time it is paid or accrued on the 3 Year Notes in accordance with your method of accounting for United States federal income tax purposes.

Sale, Exchange, Redemption or Other Taxable Disposition of 3 Year Notes

You generally will recognize capital gain or loss upon the sale, exchange, redemption or other taxable disposition of a note in an amount equal to the difference between: (1) the sum of cash plus the fair market value of all other property received on such disposition (except to the extent such cash or property is attributable to accrued but unpaid interest not previously included in income, which generally will be taxable as ordinary income) and (2) your adjusted tax basis in the note. Your adjusted tax basis in a note generally will equal the amount you paid for the note. Under current law, if you are a non-corporate U.S. holder, including an individual, and have held the note for more than one year at the time of disposition, such capital gain generally will be subject to tax at a maximum rate of 15%, which maximum tax rate currently is scheduled to increase to 20% for dispositions occurring during taxable years beginning on or after January 1, 2011. Your ability to deduct capital losses may be limited.

Backup Withholding and Information Reporting

Payments of interest and principal on 3 Year Notes held by U.S. holders and the proceeds received upon the sale, exchange, redemption or other disposition of such 3 Year Notes may be subject to information reporting and backup withholding. Payments to certain holders (including, among others, corporations and certain tax-exempt organizations) are generally not subject to information reporting or backup withholding. If you are a U.S. holder and you are not otherwise exempt from information reporting and backup withholding, payments to you will be subject to information reporting and backup withholding if:

you fail to furnish your taxpayer identification number (“TIN”), which, for an individual, is ordinarily his or her social security number, in the manner required by the Code and applicable Treasury Regulations;

we or our agent (or other payor) are notified by the Internal Revenue Service that the TIN you furnished is incorrect;

there has been a “notified payee underreporting” with respect to interest or dividends paid to you, as described in the Code; or

you have failed to certify under penalty of perjury that you have furnished a correct TIN and that you are not subject to backup withholding under the Code.

The amount of any reportable payments, including interest, made to you (unless you are an exempt recipient) and the amount withheld, if any, with respect to such payments will be reported to and the Internal Revenue Service for each calendar year.

You should consult your tax advisor regarding your qualification for an exemption from backup withholding and information reporting and the procedures for obtaining such an exemption, if applicable. Backup withholding is not an additional tax, and you may use amounts withheld under the backup withholding rules as a credit against your United States federal income tax liability or may claim a refund as long as you provide the required information to the Internal Revenue Service in a timely manner.

Consequences to Non-U.S. Holders

The following is a summary of certain material United States federal income tax consequences that will apply to you if you are a non-U.S. holder of 3 Year Notes. The term “non-U.S. holder” means a beneficial owner of a note that is not a U.S. holder.

Special rules may apply to certain non-U.S. holders such as “controlled foreign corporations” and “passive foreign investment companies.” Such entities should consult their tax advisors to determine the United States federal, state, local and other tax consequences that may be relevant to them.

Payment of Interest

The 30% United States federal withholding tax will not apply to any payment to you of interest on a note provided that:

you do not own, actually or constructively, 10% or more of the total combined voting power of all classes of our stock entitled to vote;

you are not a “controlled foreign corporation” with respect to which we are, directly or indirectly, a “related person” within the meaning of the Code;

you are not a bank receiving interest pursuant to a loan agreement entered into in the ordinary course of your trade or business; and

(1) you provide your name and address, and certify, under penalties of perjury, that you are not a United States person (which certification may be made on an Internal Revenue Service Form W-8BEN (or successor form)); or (2) a securities clearing organization, bank, or other financial institution that holds customers’ securities in the ordinary course of its business holds the note on your behalf and certifies, under penalties of perjury, that it has received Internal Revenue Service Form W-8BEN from you or form another qualifying financial institution intermediary, and, in certain circumstances, provides a copy of the Internal Revenue Service Form W-8BEN. If you hold your 3 Year Notes through certain foreign intermediaries or certain foreign partnerships, such foreign intermediaries or partnerships must also satisfy the certification requirements of applicable Treasury Regulations.

If you cannot satisfy the requirements described above, you will be subject to the 30% United States federal withholding tax with respect to payments of interest on the 3 Year Notes, unless you provide us with a properly executed (1) Internal Revenue Service Form W-8BEN (or successor form) claiming an exemption from or reduction in withholding under the benefit of an applicable United States income tax treaty or (2) Internal Revenue Service Form W-8ECI (or successor form) stating that the interest paid on the note is not subject to withholding tax because it is effectively connected with your conduct of a trade or business in the United States.

If you are engaged in a trade or business in the United States and interest on a note is effectively connected with your conduct of that trade or business, you will be subject to United States federal income tax on that interest on a net income basis (although you will be exempt from the 30% withholding tax, provided the certification requirements described above are satisfied) in the same manner as if you were a United States person as defined under the Code, except as otherwise provided by an applicable United States income tax treaty. In addition, if you are a foreign corporation, you may be subject to a branch profits tax equal to 30% (or lower applicable treaty rate) of your earnings and profits for the taxable year, subject to adjustments, that are effectively connected with your conduct of a trade or business in the United States. For this purpose, interest will be included in the earnings and profits of such foreign corporation.

Sale, Exchange, Redemption or Other Taxable Disposition of 3 Year Notes

Any gain realized upon the sale, exchange, redemption or other taxable disposition of a note (except with to accrued and unpaid interest, which would be taxable as described above) generally will not be subject to United States federal income tax unless:

that gain is effectively connected with your conduct of a trade or business in the United States; or

you are an individual who is present in the Unites States for 183 days or more in the taxable year of that disposition, and certain other conditions are met.

If your gain is effectively connected with your conduct of a United States trade or business, you generally will be subject to United States federal income tax on the net gain derived from the sale, exchange, redemption or other disposition, except as otherwise required by an applicable United States income tax treaty. If you are a corporation, any such effectively connected gain received by you may also, under certain circumstances, be subject to the branch profits tax at a 30% rate (or such lower rate as may be prescribed under an applicable United States income tax treaty). If you are described in the second bullet point above, you will be subject to a 30% United States federal income tax on the gain derived from the sale, exchange, redemption or other disposition, which may be offset by United States source capital losses, even though you are not considered a resident of the United States.

Backup Withholding and Information Reporting

If you are a non-U.S. holder, in general, you will not be subject to backup withholding and information reporting with respect to payments that we make to you provided that we do not have actual knowledge or reason to know that you are a United States person, as defined under the Code, and you have given us the statement described above under “Consequences to Non-U.S. Holders – Payments of Interest.” In addition, you will not be subject to backup withholding or information reporting with respect to the proceeds of the sale of a note within the United States or conducted through certain United States-related financial intermediaries, if the payor receives the statement described above and does not have actual knowledge or reason to know that you are a United States person, as defined under the Code, or you otherwise established an exemption. However, we may be required to report annually to the Internal Revenue Service and to you the amount of, and the tax withheld with respect to, any interest paid to you, regardless of whether any tax was actually withheld. Copies of these information returns may also be made available under the provisions of a specified treaty or agreement to the tax authorities of the country in which you reside.

You generally may be entitled to credit any amount withheld under the backup withholding rules against your United States federal income tax liability provided that the required information is furnished to the Internal Revenue Service in a timely manner.

CIRCULAR 230: ANY DISCUSSION OF UNITED STATES FEDERAL TAX ISSUES SET FORTH HEREIN WAS WRITTEN IN CONNECTION WITH THE PROMOTION AND MARKETING OF THE OFFERING DESCRIBED HEREIN. SUCH DISCUSSION IS NOT INTENDED OR WRITTEN TO BE LEGAL OR TAX ADVICE TO ANY PERSON AND IS NOT INTENDED OR WRITTEN TO BE USED, AND IT CANNOT BE USED, BY ANY PERSON FOR THE PURPOSE OF AVOIDING UNITED STATES FEDERAL TAX PENALTIES THAT MAY BE IMPOSED ON SUCH PERSON. EACH PROSPECTIVE PURCHASER SHOULD SEEK ADVICE BASED ON ITS PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR.

CAPITALIZATION

The following table sets forth (i) our capitalization at September 30, 2009 and (ii) our pro forma capitalization giving effect to the receipt of the gross proceeds from the sale of the 3 Year Notes, assuming no subscriptions and assuming the maximum aggregate Offering of $10 million is raised, as if the sale of the 3 Year Notes occurred on September 30, 2009. The 3 Year Notes are being offered on a no-minimum, best efforts basis. This table is based on, and is qualified in its entirety by, our historical financial statements, including the related notes, which are included elsewhere in this prospectus. This table should be read in conjunction with these financial statements.

	Actual			Pro Forma No Subscriptions			Pro Forma Fully Subscribed

Total Liabilities:	$	2,040,575		$	2,040,575		$	12,040,575

Stockholders’ equity:
Common stock, par value $0.001 per share; 50,000,000 shares authorized; 7,410,000 shares issued and outstanding	$	7,410		$	7,410		$	7,410
Additional paid-in capital	$	99,373		$	99,373		$	99,373
Deficit accumulated during the development stage	$	(24,718	)	$	(24,718	)	$	(24,718	)
Accumulated deficit	$	(1,296,522	)	$	(1,296,522	)	$	(1,296,522	)
Total stockholders’ deficit	$	(1,214,457	)	$	(1,214,457	)	$	(1,214,457	)

Total capitalization	$	826,118		$	826,118		$	10,826,118

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the financial statements and related notes included elsewhere in this prospectus. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil, NGL andgas prices, production timing and volumes, estimates of proved reserves, operating costs and capitalexpenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

Southfield Energy Corporation, a Nevada corporation formed in July 2005, is a Houston, Texas based company engaged in the investment in acquisition, exploration and development of moderate risk, oil and gas wells in the United States. The Company’s core strategy is to earn revenue from existing non-operated working interests while investing in new opportunities to increase our oil and gas production and reserves; primarily through acquisitions of existing production and working interest investments in drilling programs of experienced and successful oil and gas operators active in Texas, Louisiana and Oklahoma.

Recent Developments

Equity Investment

In September and October 2008, we purchased an aggregate of 350,000 shares of common stock of Meridian Resources Corporation, an exploration and production company whose shares trade on the New York Stock Exchange under the ticker symbol “TMR.” As of December 31, 2008, we incurred an unrealized holding loss of $325,465 on our investment. As of December 31, 2008, the net market value of our TMR investment was $199,500, comprising approximately 22.2% of total assets. In June 2009, we sold an aggregate of 100,000 shares of common stock of Meridian Resources Corporation and realized a loss of $134,096. On January 4, 2010, we sold our remaining 250,000 shares of common stock in Meridian Resources Corporation and realized an approximate loss of $280,000 based on an average cost basis. We no longer have an equity investment in Meridian Resources or any other corporation. We do not have any current plans, proposals or arrangements, written or otherwise, to make any equity investment in Meridian Resources Corporation or any other company. As of September 30, 2009 we determined the decline in value of the Meridian shares to be other than temporary. Based on this determination the shares were adjusted to their market value as of September 30, 2009 of $102,500. The difference between the cost and market value of the shares was recorded as impairment expense for $243,095.

Aldwell Unit

Due to low commodity prices for oil and gas at December 31, 2008, we were required to impair our assets located in the Aldwell Unit. An impairment test was conducted using data in a reserve report prepared by a reserve engineering firm. While conducting the impairment test, management determined that the estimated undiscounted future net cash flow provided in the reserve report was less that the carrying value of the Aldwell Unit on the Company’s Balance Sheet on December 31, 2008 and that the assets were subject to impairment. The assets were subsequently impaired by taking the difference between the discounted future net cash flow, using a 10% discount rate, which was estimated by the reserve engineer and the carrying value of the assets on the Company’s Balance Sheet. Management found the difference to be $116,553 and impaired the Aldwell Unit by that amount.

Effective September 2009, we sold our assets located in the Aldwell Unit to Mariner Energy, Inc., the operator, for approximately $300,000, excluding a six percent sales commission. The Aldwell Unit accounted for approximately 20% of our oil and natural gas revenue for the year ended December 31, 2008 and the nine months ended September 30, 2009. As such, for the remainder of the fiscal year, our future revenues will be derived primarily from our Richard King Field properties.

Durango Resources

Since partnering with Durango Resources, we have participated in the drilling and completion of five commercially viable oil and gas wells on the Mary King Estell lease in the Richard King Field in Nueces County, Texas. All of the wells were drilled to depths less than 6,500 feet, and are currently producing natural gas at various rates. We have not made any unsuccessful investments in this field and have thus far completed all of the wells that we have drilled. These wells produce gas from the Frio formation and constitute all of our revenues. Our share of production from these wells was 486 barrels of oil equivalent in 2007 and 5,970 barrels of oil equivalent in 2008. Durango Resources has identified additional drilling locations that are adjacent to our current producing wells and has plans for additional drilling over the next twelve to twenty four months. We anticipate investing in additional wells with Durango should the opportunity arise.

Results of Operation

Three and Nine Months Ended September 30, 2009 Compared to September 30, 2008

Revenues. Total revenues before the inclusion of Discontinued Operations decreased by $98,202 and $209,246 for the three and nine months ended September 30, 2009 respectively, as compared to the three and nine months ended September 30, 2008, due to a decrease in oil and gas prices and as a result of a decrease in our total oil and gas production from the Aldwell Unit and the Richard King Field. Details of production and oil and gas prices are listed in the Revenues and Production table below.

Production costs. Production costs before the inclusion of Discontinued Operations decreased by $16,277 and increased by $7,235 for the three and nine months ended September 30, 2009 respectively, as compared to the three and nine months ended September 30, 2008. As a percentage of revenue, however, our production costs increased from 21% to 51% and from 9% to 67% for the three and nine months ended September 30, 2009 respectively, as compared to the three and nine months ended September 30, 2008. Because of reductions in oil and gas prices and our production rates, the decrease in our revenues was much larger than any change in our production costs, and therefore our production costs as a percentage of revenue increased for the respective periods.

Depreciation, depletion and amortization (“DD&A”) expense. For the nine months ended September 30, 2008 and September 30, 2009, the company incurred depreciation, depletion and amortization on its remaining proved property, the Richard King Field lease, of $10,078 and 24,834, respectively. This was due to an increase in our capitalized expenses in proved properties. Depreciation, depletion, and amortization have been calculated using the units of production method.

G&A expense. G&A expense increased from $172,034 for the nine months ended September 30, 2008 to $347,887 for the nine months ended September 30, 2009. This increase was primarily due to increases in rent and salaries & benefits, which increased by approximately $12,300 and $119,300 respectively. In these periods the rent increased because we were utilizing more office space; and salaries increased to provide management with remuneration that more closely reflected market values. G&A expense also increased from $86,884 for the three months ended September 30, 2008 to $120,201 for the three months ended September 30, 2009. This increase can be attributed primarily to increases in legal and accounting expenses related to costs associated with this offering totaling approximately $37,800.

Income taxes. Southfield experienced losses during these periods and was not subject to federal income taxes.

Year Ended December 31, 2008 Compared to December 31, 2007

Revenues and production. The following table illustrates the primary components of revenues, production volumes and realized prices for the periods noted.

	2007						2008
	Production (BOE)		Avg. Price per BOE ($)		Total Revenues ($)		Production (BOE)		Avg. Price per BOE ($)		Total Revenues ($)
Aldwell Unit		1,064		50.50		53,732		1,157		55.49		64,200
Richard King		486		50.50		24,544		5,970		55.49		331,274
TOTAL		1,550		50.50		78,276		7,127		55.49		395,474

Revenues. Total revenues increased by $317,198 for the year ended December 31, 2008, as compared to the year ended December 31, 2007, due to an increase in oil and gas prices and as a result of an increase in our total oil and gas production from successfully drilling developmental wells in the Aldwell Unit and the Richard King Field. Production in the Aldwell Unit increased from 1,064 barrels of oil equivalent (BOE) to 1,157 BOE; and production in the Richard King Field increased from 486 BOE to 5,970 BOE. Addtionally, the average price per BOE increased from $50.50 in 2007 to $55.49 in 2008.

Production. Our average monthly production increased from 129 Barrels of Oil Equivalent (“BOE”) in 2007 to 594 BOE in 2008. Most wells produce at higher initial rates and their production declines as they deplete over time. Our monthly production increased because we participated in the successful drilling and completion of 27 new wells in the Aldwell Unit and 2 wells in the Richard King Field in 2008.

Production costs. Production costs increased from $20,090 to $54,218 during the years ended December 31, 2007 and 2008, respectively. As a percentage of revenue, however, our production costs decreased from 26% to 14%. Because of increases in oil and gas prices and our production rates, our revenues increased over the respective periods by more than the increase in our production costs, and therefore our production costs as a percentage of revenue decreased for the respective periods.

Depreciation, depletion and amortization (“DD&A”) expense. DD&A expense increased from $9,896 to $56,572 during the years ended December 31, 2007 and 2008, respectively. This was due to an increase in our capitalized expenses in proved properties and a higher depletion rate of our production in 2008 as compared to 2007.

G&A expense. Our general and administrative expense was $85,256 for 2007 and $273,143 for 2008. These expenses include rent, office expenses, travel expenses, salaries for employees, and benefits for employees. This increase can be attributed primarily to increases in rent and salaries, which increased by approximately $15,000 and $201,000 respectively. In these periods the rent increased because we were utilizing more office space; and salaries increased to provide management with remuneration necessary for their retention.

Income taxes. Southfield experienced losses in 2007 and 2008 and was not subject to federal income taxes.

During May 2006, the State of Texas enacted legislation that changed the existing Texas franchise tax from a tax based on net income or taxable capital to an income tax based on a defined calculation of taxable margin (the Texas Margin tax). Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” requires that deferred tax balances be adjusted to reflect tax rate changes during the periods in which the tax rate changes are enacted.

Liquidity and Capital Resources

Historically, we have financed our operations through the sale of debt and equity securities and cash generated from operations. As of September 30, 2009 we had $293,046 of cash and cash equivalents, a working capital deficit of $77,529 and a total stockholders’ deficit of $1,214,457. Our expenses exceeded our revenues for the nine months ended September 30, 2009; thus, we have incurred a net loss of $818,925 for the nine months ended September 30, 2009.

Our current burn rate is approximately $30,000 per month. Our available cash will support our operations at current levels through March 2010. We will need to raise money through the Offering to fund our business plan and support our operations after March 2010. The length of time we are able to operate is contingent on the amount of money we raise through our Offering. We offer no assurance that we will be able to raise any amount of money through the Offering. To the extent we are able to raise an amount of money in the Offering to cover our operating expenses, we plan to invest the proceeds in additional working interests in existing oil and gas production as well as new oil and gas wells. Because our proved reserves and production decline continually over time, we will need to make additional investments in oil and gas projects to sustain our level of revenue. The report of our independent auditors with regard to our financial statements for the fiscal year ended December 31, 2008 includes a going concern qualification. Although we have successfully funded our operations to date by attracting investors to our equity and debt, there is no assurance that our capital raising efforts will be able to attract additional necessary capital for our operations. If we are unable to obtain additional funding for operations at any time now or in the future, we may not be able to continue operations as proposed, requiring us to modify our business plan, curtail various aspects of our operations, sell our assets or cease operations.

From September 2009 through the date of this Offering, the Company provided existing Debenture holders the option of extending the maturity dates on their Debentures by either one or two years. The following table provides the dollar amount of debentures due in the next five years after taking into account the debenture extensions:

Maturities of Notes over the next five years ended September 30, 2009

	2009		2010		2011		2012		2013		2014

Debenture Maturities ($)		0		164,000		577,000		650,000		305,000		138,000

Cash Flows

Operating activities . Net cash used in operating activities for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008 was $354,174 and $340,945, respectively. We incurred an impairment of available for sale securities of $243,095; a loss on the sale of available for sale securities of $134,096; amortization of loan and debenture costs of $105,753; depreciation, depletion and amortization costs of $24,834; a reduction in accounts payable of $26,598; and increases in accrued expenses, receivables, and prepaid expenses of $96,738, $41,226, and $30,933, respectively.

Investing activities . Net cash provided / (used) in investing activities for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008 was $202,725 and $(384,010), respectively. Our capitalized investment in proved leaseholds increased from $50,286 to $133,147. The primary reason for the increase in cash flows from investing activities was due to the sale of our discontinued operations, the Aldwell Unit, which provided us $300,000. Additions to the Aldwell unit prior to its disposal accounted for negative cash flows related to investing of $9,401 during the nine months ended September 30, 2009.

Financing activities . Net cash provided from financing activities for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008 was $300,891 and $493,983, respectively. This change was primarily due to a decrease in debenture sales from $590,000 to $352,000 for the respective periods.

Outlook

Significant factors that may impact future commodity prices include developments in the issues currently impacting the Middle East, Africa and South America in general; the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing liquefied natural gas (“LNG”) deliveries to the United States and political and regulatory changes by the U.S. government. Generally, the prices for any commodity that we produce will approximate market prices in the geographic region of the production.

Our future oil and gas reserves, production, cash flow and ability to make principal and interest payments on the 3 Year Notes depend on our success in producing our current reserves efficiently and acquiring additional proved reserves economically. We expect to pursue acquisitions of producing oil and gas properties, invest in working interests in new wells and to acquire lease rights and royalty rights to oil and gas properties.

Contractual Obligations

	Payments Due By Period
Contractual Obligations at December 31, 2008	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Convertible Debentures	$	1,482,000	$	304,000	$	1,178,000	$	0	$	0
Total	$	1,482,000	$	304,000	$	1,178,000	$	0	$	0

Off-Balance Sheet Arrangements

We have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future affect on our financial condition, revenues or expense, results of operations, liquidity, capital expenditures or capital resources that are material to our shareholders.

Critical Accounting Estimates

We prepared our financial statements in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the application of GAAP.

Asset retirement obligations. We have significant obligations to remove tangible equipment and facilities and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Changes in any of these estimates can result in revisions to the estimated asset retirement obligation. Revisions to the estimated asset retirement obligation are recorded with an offsetting change to the carrying amount of the related oil and gas properties, resulting in prospective changes to depletion and accretion expense. Because of the subjectivity of assumptions and the relatively long life of most of our oil and gas properties, the costs to ultimately retire these assets may vary significantly from our estimates.

Successful efforts method of accounting. We utilize the successful efforts method of accounting for oil and gas producing activities as opposed to the full cost method. The critical difference between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur, whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense.

Proved reserve estimates. Estimates of our proved reserves included in this prospectus are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

•

The quality and quantity of available data;

•

The interpretation of that data;

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The accuracy of various mandated economic assumptions; and

•

the judgment of the persons preparing the estimate.

Proved reserve information included in this prospectus as of December 31, 2007, and 2008 was prepared by Huddleston and Company, an independent engineering firm. Estimates prepared by Huddleston and Company may be higher or lower than actual reserves. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

It should not be assumed that the standardized measure included in this prospectus as of December 31, 2008 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the standardized measure on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we recognize depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of our proved properties for impairment.

Impairment of proved oil and gas properties. We review our proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties and if a significant downward revision has occurred to the estimated proved reserves. If the sum of the undiscounted future net cash flows of a proved producing property is less than the carrying value of the proved producing property, then an impairment is made to reduce the value at which those assets are carried on our balance sheet.

Environmental contingencies. Our management makes judgments and estimates in recording liabilities for ongoing environmental remediation. Actual costs can vary from such estimates for a variety of reasons. Environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. Under GAAP, a liability is recorded for these types of contingencies if we determine the loss to be both probable and reasonably estimable.

New Accounting Pronouncements

We adopted the Financial Accounting Standards Board’s (FASB) Standard related to fair value measurement at inception. The standard defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. The standard applies under other accounting pronouncements that require or permit fair value measurements and accordingly, does not require any new fair value measurements. The standard clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, the standard established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows.

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Level 1. Observable inputs such as quoted prices in active markets;

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Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

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Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” refers to the risk of loss arising from changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Due to the historical volatility of commodity prices, we may elect to enter into various derivative instruments to manage our exposure to volatility of commodity market prices. We may use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in commodity prices on our cash available for distributions. All contracts will be settled with cash and do not require the delivery of physical volumes to satisfy settlement. While in times of higher commodity prices this strategy may result in our having lower net cash inflows than we would otherwise have if we had not utilized these instruments, management believes the risk reduction benefits of this strategy outweigh the potential costs. As of the date of this prospectus, we have not entered into any derivative instruments.

We may borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. Our objective in borrowing under fixed or variable rate debt would be to satisfy capital requirements while minimizing our costs of capital . If we borrow under variable rate debt, any increase in interest rates would increase our future interest expense. We may thus enter into various derivative instruments to manage our exposure to such interest rate risk. As of the date of this prospectus, we have not entered into any derivative instruments.

BUSINESS

Overview

We are an independent energy company based in Houston, Texas that invests in the exploration, development, and production of moderate risk oil and gas projects in the United States. We focus on partnering alongside operators with substantial experience. The Company’s core strategy is to earn revenue from existing non-operated working interests while investing in proven producing fields and drilling programs primarily in Texas, Louisiana and Oklahoma. We do not have any subsidiaries.

We currently focus our efforts on investments in oil and natural gas properties under the Mary King Estell lease in the Richard King Field area of Nueces County, Texas. We intend on building our business by acquiring additional non-operated working interests in productive oil and natural gas wells and other oil and gas interests. A non-operated working interest grants us a proportionate share of the property’s oil and gas production, and requires us to pay a proportionate share of the costs associated with drilling and production without acting as the operator of the property’s wells.

Non-operated Working Interest

We will generally invest as a non-operated working interest owner. A working interest owner pays its pro-rata portion of the cost of leasing, drilling, completing, and operating the well. Collectively, the working interest owners pay 100% of these costs. We expect to invest in projects under common industry terms often referred to as “a third for a quarter.” Under this structure, non-operated working interest investors typically incur 100% of the leasing, drilling and completion costs and receive 75% of the leasehold or “working” interest of the project. The structure is so named because, in the case where a single operator, acting as a “promoter,” transfers 75% of the working interest in equal proportion to three non-operating working interest owners, each such non-operating working interest owner would pay one third of the expenses in exchange for one-fourth of the working interest in each well. For example, if the net revenue interest attributable to the entire leasehold estate is 75% , then the non-operating working interest owners would receive three quarters of 75% or 56.25%, which would usually be divided pro-rata among such owners in proportion to their respective working interests.

This investment strategy provides us with multiple advantages as we build the value of Southfield. First, it allows us to balance the risk of failure in any one well (i.e., drilling a dry hole) by investing a smaller amount in a larger number of wells. In the oil and gas business, results of drilling programs can vary significantly. We plan to participate in wells that we determine have a high probability of successfully finding and producing oil or gas.

Because we are a small, early stage oil and gas company, we will invest in the drilling of wells that are relatively inexpensive compared to the projects undertaken by the major oil companies. While some wells cost tens of millions of dollars to drill and complete, we will invest in wells that are far less costly to exploit. This limits the amount that we would potentially lose from any individual, unsuccessful well.

We will generally use outside consultants to evaluate each potential investment prior to making an investment decision. These consultants will consist of petroleum engineers, industry professionals and geologists who will assist with:

evaluation of the geological characteristics of the drilling target;

analysis of the reservoir characteristics for the prospective well;

evaluation of other nearby, analogous wells and production zones;

synthesis of costs and revenue projections to determine economic viability, and

overall financial evaluation of the project to determine its expected return.

Equity Investments

We also make equity investments in other oil and gas companies. In September and October 2008, we purchased an aggregate of 350,000 shares of common stock of Meridian Resources Corporation, an exploration and production company whose shares trade on the New York Stock Exchange under the ticker symbol “TMR.” As of December 31, 2008, we incurred an unrealized holding loss of $325,465 on our investment. As of December 31, 2008, the net market value of our TMR investment was $199,500, comprising approximately 22.2% of total assets. In June 2009, we sold an aggregate of 100,000 shares of Meridian Resources Corporation and realized a loss of $134,096. On January 4, 2010, we sold our remaining 250,000 shares of common stock in Meridian Resources Corporation and realized an approximate loss of $280,000 based on an average cost basis. We no longer have an equity investment in Meridian Resources or any other corporation. Although we do not currently own equity investments in any company, we may buy such equities we feel are undervalued in the future. We make no assurance that we will realize a profit on any future equity investment. We do not have any current plans, proposals or arrangements, written or otherwise, to make an equity investment in Meridian Resources Corporation or any other company. As of September 30, 2009 we determined the decline in value of the Meridian shares to be other than temporary. Based on this determination the shares were adjusted to their market value as of September 30, 2009 of $102,500. The difference between the cost and market value of the shares was recorded as impairment expense for $243,095.

Our Strategy

We believe that several factors that currently exist in this industry have created a good opportunity for investors to realize attractive returns from well-managed investments in oil and gas. Factors that we consider important to our operations include:

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Rising world demand for oil and gas products over the next decade;

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Rapidly depleting world reserves of oil and gas;

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The need for the U.S. to import significant amounts of both oil and gas;

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Political instability in oil producing countries that tends to increase the cost of energy;

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Limited production and refining capacity which will prevent the industry from over producing in the foreseeable future; and

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Growing world population combined with the increased worldwide use of energy.

Our plan includes an investment strategy that we believe will significantly reduce risk while creating profits for our shareholders. Our investment strategy manages risk by the implementation of the following investment guidelines:

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We will diversify our investment in oil and gas projects by typically investing between five to twenty five percent in the cost of any individual project;

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We have focused our early investments on lower-cost drilling opportunities in the U.S. for shallow gas and oil;

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Our investment per well is expected to continue to range from $50,000 to $250,000;

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We will typically invest in non-operated interests in wells so that we do not have to hire technical operating personnel or manage the day-to-day operation of our wells; and

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Investments will typically be reviewed by outside consultants consisting of seasoned petroleum engineers, geologists and oil & gas investors.

Competition and markets

The oil and gas industry is a mature, well developed industry with several major companies and hundreds of independent companies competing for opportunities. The projects in which we will invest are not typically projects that would be large enough to attract the major oil companies. Therefore, the major oil companies are generally not our competition. There were approximately 1,500 drilling rigs operating onshore in the United States in 2006. Today, there are about 1,100 to 1,200 drilling rigs operating. We will partner with proven independent oil and gas companies to participate in the exploration and development of moderate-risk, oil and gas reserves. By investing as a non-operated working interest owner, we turn potential competitors into partners. In other words, our business model is to find successful operators and invest in five to twenty five percent of their projects. We expect they will welcome us as investment partners because this allows them to develop their properties more quickly by drilling more wells and diversifying their risk.

Although Southfield competes directly and indirectly with all exploration, development and production companies; we experience heightened competition from other non-operated working interest investors. Because there are a finite number of oil and gas investments that are available at any given time to non-operated working interest investors, we compete directly with other investment capital derived from private and corporate sources. Some of the larger non-operated working interest investors in Texas include Five States Energy Capital, LLC; Limerock Resources and Quantum Energy Partners.

The oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. Alternative energy sources are generally more expensive per British thermal unit (“BTU”) than fossil fuels and still represent a very small percentage of the energy market.

Business strengths

Concentrated focus on core areas

We have concentrated our business model such that we do not require any personnel for day-to-day field operations. The essential expertise core to our success is the ability to identify and evaluate potential projects and make intelligent investment decisions. We expect to be a minority working interest owner in most of the wells in which we invest. This means that we will be partnering with other oil and gas investors in the development of our prospects. This broadened pool of expertise will provide us with both better data on our investments and expanded opportunities to invest with our partners.

Mitigation of risk by diversifying investments

Because we are spreading our investment over a large number of wells in which we will typically own a minority interest, the risks associated with oil and gas exploration and production can be reduced. In addition, we will be investing in relatively inexpensive drilling prospects that will reduce the amount of loss we will experience from any well that is not successful. We expect to invest from $50,000-$250,000 in any given well. We may, however, invest substantially more in a group of wells or other oil and gas project if management believes that the project is beneficial to its shareholders.

Experienced and motivated management team

Our entire senior management team has extensive business and finance experience. We believe that this team will deliver the leadership we need to generate attractive returns from our investment strategy. See, “Management,” below.

Technical expertise

We plan to engage as consultants oil and gas technical professionals, including geophysicists, geologists, petroleum engineers, production and reservoir engineers and land men who have extensive experience in their respective fields to assist us in evaluating potential investments and divestitures. We anticipate that we will be able to retain high-quality experts as needed, and not be required to hire full time staff professionals for the technical expertise needed. This approach should significantly reduce our operating costs while giving us the desired access to top tier talent.

Partnering with proven operators

We have been successful in partnering with high quality operators that are able to effectively find oil and gas reserves at reasonable costs. In an industry that has high rates of failures in the exploration and development of hydrocarbons, partnering with experienced operators is beneficial to our operations.

Our Properties

Richard King Field

We have participated in the drilling and completion of five wells in Nueces County, Texas in a prolific natural gas trend. Our lease is located on the Mary King Estell lease in the Richard King Field. We participated in the drilling and completion of the C-31 well in 2007, and the C-32 and C-33 wells in 2008, and the C-34 and C-35 in 2009. All of the wells are commercially viable and generate the majority of our natural gas revenues. Each of the wells was drilled between 5,000 and 6,500 feet and encountered multiple layers of hydrocarbons in commercially viable quantities.

The first well that we invested in was the C-31 well. The well was connected to the pipelines as a “Dual Completion” meaning we are producing natural gas from two separate reservoirs. The other wells were each completed in one reservoir. All of the wells have additional zones of oil and/or gas that the operator can bring on line at a later date. Over time, perhaps five to seven years, the existing reservoirs will deplete to a point below which they are not economically viable to produce. When this happens, we plan to complete the other zones of oil and/or natural gas that are behind pipe in order to bring new production back on line in the existing wells.

This method of reentering wells and completing different zones for new production is less costly than drilling a new well since the infrastructure is already in place. All of these wells contain untapped resources that will provide us with revenues in the future.

There are also additional drilling opportunities on this lease that can be exploited in the future. We expect to encounter multiple pay zones, as with the previous wells, and anticipate the combined gross production from all five wells to exceed 500,000 cubic feet of gas per day. This project has been our most successful endeavor to date and still contains additional reserves.

Aldwell Unit

Effective December 31, 2006, the Company acquired a non-operated working interest in 130 producing oil and gas wells located in Reagan County, Texas. On January 23, 2007 the Company paid for the acquisition and received an assignment of leases. The operator of the wells is Mariner Energy Inc., a publicly traded company under the symbol “ME.” Since we acquired our interest, we have participated in the drilling 70 additional wells with Mariner Energy.

Effective September 2009, we sold our assets located in the Aldwell Unit to Mariner Energy, for approximately $300,000, excluding a six percent sales commission. The Aldwell Unit accounted for approximately 20% of our oil and natural gas revenue for the year ended December 31, 2008 and the nine months ended September 30, 2009. As such, for the remainder of the fiscal year, our future revenues will be derived primarily from our Richard King Field properties.

Proved Reserves

Huddleston & Co., Inc., an independent reservoir engineering firm that reports to our board of directors, provided a report related to its estimates of reserves as of January 1, 2008 and January 1, 2009. The service performed by Huddleston included the preparation of an independent estimate of proved natural gas and oil reserves estimates for our properties in the Richard King Field and Aldwell Unit. Based on the amount of proved reserves determined by Huddleston, we believe our reported reserve amounts are reasonable.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production, and projecting the timing and costs of development expenditures, including many factors beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The reserve data represents only estimates which are often different from the quantities of natural gas and oil that are ultimately recovered. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based, and on engineering and geological interpretations and judgment.

All estimates of proved reserves are determined according to the rules currently prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive or upward revision is more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate.

In general, the volume of production from natural gas and oil properties declines as reserves are depleted. Except to the extent we acquire additional non-operated working interests in properties with proved reserves, our proved reserves will decline as reserves are produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of proved undeveloped reserves and proved non-producing reserves are subject to greater uncertainties than estimates of proved producing reserves.

Our Production, Price and Cost History

Annual oil, gas and natural gas liquid (NGL) production

	Aldwell Unit						Mary King Estell
	Oil (bbl)		Gas (mcf)		NGL (bbl)		Oil (bbl)		Gas (mcf)		NGL (bbl)
2007		494		1,580		307		0		2,918		0
2008		550		1,852		299		0		35,622		33

The following table sets forth the historical information for our proved producing leases for the periods indicated, regarding net production of oil, NGL and gas and certain price and cost information.

	Total Production (BOE)		Average Price per BOE, ($)		Total Sales ($)		Average Cost of Sales per BOE, ($)		Total Cost of Sales ($)		Total Net Revenues ($)
2007		1,550		50.50		78,276		12.96		20,090		58,186
2008		7,127		55.49		395,474		16.93		54,218		341,256

Our Productive Wells

The following table sets forth historical information relating to the productive wells in which we owned a working interest for the periods indicated. Productive wells consist of producing wells and wells capable of production, including shut-in wells.

Gross and Net Productive oil and gas wells as of 12/31/2007 and 12/31/2008 (A) (B)

	2007				2008
	Gross		Net		Gross		Net
Aldwell Unit – Oil		163		.29		190		.33
Richard King Field – Gas		1		.15		3		.45
Total		164		.44		193		.78

Our Developed and Undeveloped Acreage

Gross and Net, Developed and Undeveloped Acreage as of 12/31/2008 (A)

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Aldwell Unit – Oil		16,000		22.72		840		1.47
MKE – Gas		160		24		64		9.6
Total		7,160		46.72		904		11.07

(A) The Mary King Estell Lease (MKE) contains all of our gas wells, and the Alwell Unit contained all of our oil wells. Wells in the Aldwell Unit that produce both oil and gas have been classified as oil wells. Southfield’s working interest in the Aldwell Unit was .1749% and our working interest in the Mary King Estell Lease is 15%.

All of Southfield’s properties are considered to contain proved reserves. Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations. Proved reserves can be categorized as developed or undeveloped.

Developed reserves are expected to be recovered from existing wells including reserves behind pipe. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor.

Undeveloped reserves are expected to be recovered: (1) from new wells on undrilled acreage, (2) from deepening existing wells to a different reservoir, or (3) where a relatively large expenditure is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

(B) Effective September 2009, the Company sold its assets in the Aldwell Unit to Mariner Energy.

As of December 31, 2007 and December 31, 2008 we had the following proved developed and proved undeveloped reserves as a percentage of our future net revenue discounted at 10%:

Our Drilling Activities

The following tables set forth the historical number of gross and net productive and dry hole wells for exploratory and development wells in which Southfield had a working interest that were drilled during the years ended December 31, 2007 and 2008. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to Southfield of productive wells compared to the costs of dry holes.

Gross Productive and Dry Exploratory Wells Drilled

	2007				2008
	Gross Productive Wells		Gross Dry Holes		Gross Productive Wells		Gross Dry Holes
Aldwell Unit		0		0		0		0
Richard King Field		1		0		0		0
McManus #2 Well		0		0		0		1

Net Productive and Dry Exploratory Wells Drilled

	2007				2008
	Net Productive Wells		Net Dry Holes		Net Productive Wells		Net Dry Holes
Aldwell Unit		0		0		0		0
Richard King Field		.15		0		0		0
McManus #2 Well		0		0		0		.02

Gross Productive and Dry Development Wells Drilled

	2007				2008
	Gross Productive Wells		Gross Dry Holes		Gross Productive Wells		Gross Dry Holes
Aldwell Unit		33		0		27		0
Richard King Field		0		0		2		0
McManus #2 Well		0		0		0		0

Net Productive and Dry Development Wells Drilled

	2007				2008
	Net Productive Wells		Net Dry Holes		Net Productive Wells		Net Dry Holes
Aldwell Unit		.06		0		.05		0
Richard King Field		0		0		.3		0
McManus #2 Well		0		0		0		0

On November 11, 2008 the Company elected to invest in a non-operated working interest in the McManus #2 well with Quatro D Exploration. BD Production, an affiliate of Quatro D Exploration, was the operator of the well. The prospect was located in Lavaca County, Texas and targeted multiple gas formations. We agreed to pay the sum of the turnkey lease acquisition cost of $7,250 and the dry hole cost of $23,683, which amounted to 2.416667% of the total costs through the casing point. We funded our pro rata portion of the well of $30,933 in November of 2008. A test well was drilled in March of 2009 to a terminal depth of 10,300 feet and did not encounter commercially viable amounts of hydrocarbons. The well resulted in a dry hole and was plugged and abandoned.

Title to Properties

We believe that we have satisfactory title to our wellbore interests in accordance with standards generally accepted in the oil and gas industry. Our wellbore interests are subject to customary royalty and other interests, liens under operating agreements, liens for current taxes, and other burdens, easements, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect our carrying value of the wellbore interests.

Some of our easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances can be a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus. Record title to some of our assets will continue to be held by our affiliates until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations generally will be obtained after the closing of this offering, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

Environmental Matters and Regulation

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

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require the acquisition of various permits before drilling commences;

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enjoin some or all of the operations of facilities deemed in non-compliance with permits;

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production and transportation activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and state legislatures and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes.

Wastes containing naturally occurring radioactive materials, or NORM, may also be generated in connection with our operations. Certain processes used to produce oil and gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is not subject to regulation under the Atomic Energy Act of 1954, or the Low Level Radioactive Waste Policy Act. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration, or OSHA. These state and OSHA regulations impose certain requirements concerning worker protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; as well as restrictions on the uses of land with NORM contamination.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own or lease numerous properties that have been used for oil and gas exploration and production for many years. Although we believe that Southfield has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Clean Water Act, or the CWA, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The primary federal law imposing liability for oil spills is the Oil Pollution Act, or OPA, which sets minimum standards for prevention, containment, and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Operations associated with our properties also produce wastewaters that are disposed via injection in underground wells. These activities are regulated by the Safe Drinking Water Act, or the SDWA, and analogous state and local laws. The underground injection well program under the SDWA classifies produced wastewaters and imposes restrictions on the drilling and operation of disposal wells as well as the quality of injected wastewaters. This program is designed to protect drinking water sources and requires permits from the EPA or analogous state agency for our disposal wells. Currently, we believe that disposal well operations on our properties comply with all applicable requirements under the SDWA. However, a change in the regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations.

Air Emissions. The Federal Clean Air Act, or the CAA, and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions; obtain or strictly comply with air permits containing various emissions and operational limitations; or utilize specific emission control technologies to limit emissions of certain air pollutants. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Moreover, states can impose air emissions limitations that are more stringent than the federal standards imposed by EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require us to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies for gas and oil exploration and production operations. In addition, some gas and oil production facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Gas and oil exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Health and Safety. Operations associated with our properties are subject to the requirements of the federal Occupational Safety and Health Act, or OSH Act, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSH Act hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statues require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSH Act and comparable requirements.

Global Warming and Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states (not including Texas) have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA , the EPA may be required to regulate greenhouse gas emissions from mobile sources ( e.g. , cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases, pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for oil and gas.

We believe that we are in compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2008. Additionally, as of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2009. However, accidental spills or releases may occur in the course of our operator’s operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, results of operations or ability to make distributions to you.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry may increase our cost of doing business by increasing the cost of transporting our production to market, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS is currently in the process of adopting regulations that will determine whether some of our facilities or operations will be subject to additional DHS-mandated security requirements. Presently, it is not possible to accurately estimate the costs we could incur, directly or indirectly, to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Development and Production. Development and production operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds in connection with various types of activities and filing reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

•

the location of wells;

•

the method of drilling and casing wells;

•

the surface use and restoration of properties upon which wells are drilled;

•

the plugging and abandoning of wells; and

•

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing requirements governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil, NGL and gas that may be produced from our wells, and/or to limit the number of locations we can drill.

Regulation of Transportation and Sale of Gas. The availability, terms and cost of transportation significantly affect sales of gas. Federal and state regulations govern the price and terms for access to gas pipeline transportation. The interstate transportation and sale for resale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. The FERC’s regulations for interstate gas transmission in some circumstances may also affect the intrastate transportation of gas.

Gas prices are currently unregulated, however Congress historically has been active in the area of gas regulation. We cannot predict whether new legislation to regulate gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and gas liquids are not currently regulated and are made at market prices.

Gas Gathering. While we do not own or operate any gas gathering facilities, we depend on gathering facilities owned and operated by third parties to gather production from our reservoirs, and therefore we are impacted by the rates charged by such third parties for gathering services. To the extent that changes in federal and/or state regulation affect the rates charged for gathering services, we also may be affected by such changes. However, we do not anticipate that we would be affected any differently than similarly situated gas producers.

Plan of Operation

Our current business plan is to acquire additional non-operated working interests; however, our future business plans may include the following depending on whether we find any unique investment opportunities and if we have sufficient capital to execute such plans:

Acquisition of Mineral Lease Interests

A future investment strategy we may pursue involves the identification and leasing of mineral rights that can be developed by drilling for oil and gas. Mineral rights are generally sold separately from the surface rights held by the land owner. We will work with entities and individuals in the future that we know to identify areas that can be leased where there appear to be commercially viable oil or gas reserves. Working with geologists and petroleum engineers, we will then put together a data package on the project and its potential to produce profits through the drilling, completion and development of these reserves.

The minerals are leased from the “mineral owner” who is often different from the owner of the surface rights to the land. Leases are most often for one to three years and are typically extended as long as oil or gas is being produced from the property. When appropriate, we expect to use a “land man” to negotiate leases, review title and assist us in securing all proper rights to the leases we acquire.

After acquiring the lease, we plan to sell the rights to drill and develop these reserves to third-party oil and gas companies that will drill and produce the oil and gas reserves we purchased under the mineral lease. This is called “farming out” the lease. When this happens, we expect to retain a 25% interest in the wells’ NRI (net revenue interest) as the leaseholder. This means that we will generally retain 25% of the revenue available to the working interest owners without having to invest in the drilling and completing costs of the well.

Purchase of Existing Production

Purchasing interests in wells that are already producing oil or gas is a far less risky investment strategy than investing in the drilling of new wells because there is little risk of not receiving revenues from the investment. However, this reduced risk is factored into the price generally required to acquire existing production, so it typically provides less return per dollar invested. We expect opportunities to arise where we can make attractive, safe acquisitions of small oil and gas assets with existing production that would be beneficial to our shareholders. In this category, we may also purchase operated interests or royalty interests when we find the terms are attractive.

Infrastructure and Equipment

In conjunction with our other investments, we may need to invest from time to time in distribution systems, or equipment related to the exploration and development of the oil and gas assets in which we invest.

Employees

The Company currently has three employees: its President, Ben Roberts, its Chief Financial Officer, Chet Gutowsky, and its Chief Operating Officer, Tyson Rohde. The Company also has a consultant who provides business development services. In the next twelve months, we will consider hiring a consulting geologist and/or petroleum engineer. The board of directors may approve employment agreements for the management team.

Our Office

Legal Proceedings

We are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes or any other statutes to which we are subject.

MANAGEMENT

Directors and Executive Officers

The following sets forth the names of our executive officers and directors, their ages as of September 30 2009, and their current position and offices.

Name	Age	Position

Ben L. Roberts	63	Chief Executive Officer and Director
Chet Gutowsky	62	Chief Financial Officer and Director
Tyson Rohde	29	Chief Operating Officer and Director

Ben L. Roberts. Mr. Roberts has served as our Chief Executive Officer and as a director since our inception in July 2005. He has been instrumental in developing high-level relationships with oil and gas operators and originating investment opportunities for Southfield. Mr. Roberts served as a principal of Goldbridge Capital, LLC from 2001 until co-founding Southfield in July 2005. Goldbridge Capital is a boutique investment advisory firm that provides financial consulting and business development services to private and small public companies. Mr. Roberts has over 26 years of experience in energy and related businesses which includes 17 years oil & gas exploration and production as well as nine years in oil services and petrochemicals. Over half of his experience has been in senior management positions. Mr. Roberts holds an M.B.A. from the University of Texas in Austin and a B.S. in Physics and Mathematics from Baylor University. Mr. Roberts is a Certified Public Accountant licensed in the State of Texas.

Chet Gutowsky. Mr. Gutowsky has served as our Chief Financial Officer and as a director since our inception in July 2005. His primary role at Southfield is to facilitate the capitalization of our operations, review potential oil and gas investments and assist in the preparation of our financial reporting. Mr. Gutowsky has also served as the Chief Financial Officer and director of Biotricity Corporation, an alternative energy company, since December 2008. From September 2004 to July 2005, Mr. Gutowsky served as a principal of Brewer Capital Group, LLC, a boutique business that focused on mergers and acquisitions , and the Chief Financial Officer of Mobil Steel International, a steel products manufacturer. At Brewer Capital Group, Mr. Gutowsky provided financial consulting and advisory services related to mergers, acquisitions and small business development. Since May 2005, Mr. Gutowsky has been a managing member in Goldbridge Energy Partners, LLC a boutique investment advisory firm that facilitates capital formation and provides financial consulting to the energy sector. Goldbridge Energy Partners, LLC is not affiliated with Goldbride Capital. Mr. Gutowsky holds an M.B.A. from the University of Texas and a B.A. in Economics from Southwestern University. Mr. Gutowsky is a Chartered Financial Analyst.

Tyson Rohde. Mr. Rohde has served as our Chief Operating Officer and as a director since our inception in July 2005. His primary role at Southfield is to assist with the origination and management of oil and gas investments. Mr. Rohde has also been the Chief Executive Officer and director of Biotricity Corporation since December of 2008 where he oversees technological and business development activities. From February 2005 to July 2005, Mr. Rohde joined the executive management team of Mobil Steel International where he assisted in restarting operations and facilitated business development. Mr. Rohde has also been a managing member of Goldbridge Energy Partners, LLC since May 2005. In November 2003, Mr. Rohde founded Onyx, an importer and wholesaler of men’s apparel. Mr. Rohde holds a B.A. in Economics from the University of Texas.

Composition of the Board of Directors

The board of directors has responsibility for establishing broad corporate policies and reviewing our overall performance rather than day-to-day operations. The primary responsibility of our board of directors is to oversee the general direction and management of our Company and, in doing so, serve the best interests of the Company and our shareholders. The board of directors selects, evaluates and provides for the succession of executive officers and, subject to shareholder election, directors. It reviews and approves corporate objectives and strategies, and evaluates significant policies and proposed major commitments of corporate resources. Our board of directors also participates in decisions that have a potential major economic impact on our company. Management keeps the directors informed of Company activity through regular communication.

Our board of directors currently consists of three members: Messrs. Ben Roberts, Chet Gutowsky and Tyson Rohde. Each of our directors is elected annually at our annual meeting. All board action requires the approval of a majority of the directors in attendance at a meeting at which a quorum is present. We will increase the size of our board of directors as we deem necessary to accommodate the growth of our business.

Independence

As of the date hereof, the Company has not adopted a standard of independence nor does it have a policy with respect to independence requirements for its board members or that a majority of its board be comprised of “independent directors.” As of the date hereof, none of our directors would qualify as “independent” under any recognized standards of independence.

Board Committees

We do not currently have a standing audit, nominating or compensation committee of the board of directors, or any committee performing similar functions. Our board of directors performs the functions of audit, nominating and compensation committees. As of the date of this prospectus, no member of our board of directors qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of Regulation S-K promulgated under the Securities Act of 1933, as amended. Since the board of directors currently consists of three members, it does not believe that establishing separate audit, nominating or compensation committees are necessary for effective governance.

Shareholder Communications

Shareholders who wish to communicate with any or all members of the board of directors may write to them in care of the Corporate Secretary, Southfield Energy Corporation, 1240 Blalock Road, Suite 150, Houston, Texas 77055. All such communications which raise issues of significant interest to all shareholders generally, as determined by the Company in consultation with counsel when appropriate, will be referred to the appropriate director or directors as specified in the communication.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics (“Code”) applicable to all of the Company's directors, officers and employees. The purpose of the Code is to advise individuals of their obligations to comply with applicable law as well as the fundamental principles of business ethics to which they must adhere, such as avoidance of conflicts of interests or misuse of corporate opportunities and confidential information. A copy of the Code is available on our website at www.southfieldenergy.com.

Family Relationships

There are no family relationships among our directors, executive officers or persons nominated to become executive officers or directors.

Involvement in Certain Legal Proceedings

During the past five (5) years, none of our directors, persons nominated to become directors, executive officers, promoters or control persons:

was a general partner or executive officer of any business against which any bankruptcy petition was filed, either at the time of the bankruptcy or two (2) years prior to that time;

was convicted in a criminal proceeding or named subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

was subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

was found by a court of competent jurisdiction (civil action), the SEC or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.

Arrangements

There are no arrangements or understandings between an executive officer, director or nominee and any other person pursuant to which he was or is to be selected as an executive officer or director.

Compensation Committee Interlocks and Insider Participation

DIRECTOR AND EXECUTIVE OFFICER COMPENSATION

Summary Compensation Table

NAME AND PRINCIPAL POSITION	FISCAL YEAR	SALARY ($)		BONUS ($)		STOCK AWARDS ($)		ALL OTHER COMPENSATION ($)(1)(2)		TOTAL ($)

Ben Roberts	2008	$	12,000	$	—	$	—	$	2,327	$	14,327
Chief Executive Officer and	2007		—		—		—		—		—
Director	2006		—		—		—		—		—

Chet Gutowsky	2008	$	66,000	$	—	$	—	$	2,318	$	68,318
Chief Financial Officer and	2007		14,600		—		—		—		14,600
Director	2006		—		—		—		—		—

Tyson Rohde	2008	$	66,000	$	—	$	—	$	2,497	$	68,497
Chief Operating Officer and	2007		14,600		—		—		—		14,600
Director	2006		—		—		—		—		—

(1)

Represents payments of health, dental, vision, disability and life insurance premiums and other ancillary benefits.

(2)

Above benefits were administered commencing July 2008.

Incentive Plans

No deferred compensation or long-term incentive plan awards were issued or granted to our management during the last two fiscal years. We do not have a stock option plan, but we intend on adopting one in the near future.

Option Grants in Last Fiscal Year

We have never granted options to purchase our common stock to our executive officers or directors.

Employment

None of our executive officers are subject to employment agreements, but we may enter into such agreements with them in the future.

Director Compensation

We reimburse our directors for all reasonable ordinary and necessary business related expenses, but we did not pay director's fees or other cash compensation for services rendered as a director in the year ended December 31, 2008. We have no standard arrangement pursuant to which our directors are compensated for their services in their capacity as directors. We expect to pay fees for services rendered as a director when and if additional directors are appointed to the board of directors.

Compensation Discussion and Analysis

Our compensation approach is necessarily tied to our stage of development. During the initial stages of the Company’s business following the Offering, the duties of the executive officers will not require their full-time attention. While it is expected that they will devote such time and attention to their duties as is appropriate to discharge their duties fully and properly, it is also expected that they may undertake duties to other entities, so long as such duties do not conflict with or otherwise impede their performance of their duties to the Company. Therefore, our compensation program currently consists solely of cash compensation for the services provided.

The entire board of directors performs the functions that would be performed by a compensation committee. Chet Gutowsky is the Chief Financial Officer and a director of Southfield. He is also the Chief Financial Officer and a director of Biotricity Corporation. Tyson Rohde is the Chief Operating Officer and a director of Southfield. He is also the Chief Executive Officer and director of Biotricity Corporation. Each Mr. Rohde and Mr. Gutowsky spend approximately 30 hours per week working for Southfield. Mr. Roberts does not maintain employment outside of Southfield Energy. All of the directors participate in deliberations concerning the compensation paid to executive officers, including Messrs. Gutowsky and Rohde. The directors of Southfield determine the compensation of its executives by assessing the value of each of its executives and collectively determine what amounts of compensation are required to retain the services of the company’s executives.

The Company does not currently have or provide, and does not currently have any plans to adopt or provide in the future, any bonus or other cash incentive awards, equity-based compensation, or retirement or other executive benefits or perquisites, other than health benefits. The board of directors, which consists of our executive officers, will review and approve the compensation of our named executive officers and consultants and oversee and administer our executive compensation programs and initiatives. As we gain experience as a public company, we expect that the specific direction, emphasis and components of executive compensation programs will continue to evolve. Factors that may influence our decision to change our compensation policies include the hiring of full-time employees, our future revenue growth and profitability, the implementation of our business plan and strategy and increasing complexity of our business.

In approving compensation necessary to attract and retain our present executive officers, the board of directors concluded that the present annual salaries provided for Messrs. Roberts, Rohde and Gutowsky are reasonable considering management’s experience and unique skill sets. The objective of the executive compensation plan is to provide our executives with competitive remuneration for their skills such that we can retain our personnel for an extended period of time. Southfield’s board of directors will review its executive compensation plans from time to time and take Company performance as well as general labor market conditions into account when implementing executive compensation plans.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Transactions with Officers and Directors

From July 2005 to present, we shared office space with Goldbridge Energy Partners, LLC, whose principals include our officers and directors. Goldbridge Energy Partners is an investment advisory and consulting group that facilitates financing and assists with business development for companies in the energy sector. We paid approximately $25,000 and $9,200 in rent expense for 2008 and 2007, respectively, for our portion of the office space. Other than the sharing of office space, there have been no material transactions between us and Goldbridge Energy Partners.

On September 4, 2008 the Company loaned $2,000 to one of its officers. The loan was repaid in full on October 30, 2009.

Transactions with our Founders

On August 14, 2006 The Internet Business Factory, one of our founders, loaned to us $20,000 evidenced by a promissory note bearing interest at an annual rate of six percent. As partial consideration for the promissory note, we agreed to issue The Internet Business Factory 300,000 shares of our common stock. In November 2006, the promissory note was paid in full.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth, as of December 31, 2009, the number and percentage of outstanding shares of our common stock owned by: (a) each person who is known by us to be the beneficial owner of more than 5% of our outstanding shares of common stock; (b) each of our directors; (c) the named executive officers as defined in Item 402 of Regulation S-K; and (d) all current directors and executive officers, as a group. As of December 31, 2009, there were 7,410,000 shares of Company common stock issued and outstanding.

Beneficial ownership has been determined in accordance with Rule 13d-3 under the Exchange Act. Under this rule, certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares). In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire shares (for example, upon exercise of an option or warrant) within sixty days of the date as of which the information is provided. In computing the percentage ownership of any person, the amount of shares is deemed to include the amount of shares beneficially owned by such person by reason of such acquisition rights. As a result, the percentage of outstanding shares of any person as shown in the following table does not necessarily reflect the person's actual voting power at any particular date.

To our knowledge, except as indicated in the footnotes to this table and pursuant to applicable community property laws, the persons named in the table have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them. Unless otherwise indicated, the business address of the individuals listed is 1240 Blalock Rd., Suite 150, Houston, Texas 77055.

Name and Address of Beneficial Owner	Number of Shares of Common Stock Beneficially Owned		Percentage Of Class (%)

Beneficial Owners of more than 5% :
Oklahoma Ventures, Inc. (1)		2,025,000		27.33
Amyclare Gutowsky (2)		600,000		8.10
Mary E. Gutowsky (2)		600,000		8.10
Carew Rohde (3)		600,000		8.10
Drexel Rohde (3)		600,000		8.10

Officers and Directors :
Chet Gutowsky		600,000		8.10
Ben Roberts		200,000		2.70
Tyson Rohde		600,000		8.10
All named directors & executive officers as a group (3 persons)		1,400,000		18.89	%

(1)	The mailing address is Centro Commercial Bal Harbour - M-38, Panama City, Panama

(2)	The mailing address is 302 Pinesap Drive, Houston, Texas 77079.

(3)	The mailing address is 7508 Chevy Chase Drive, Houston, Texas 77063.

PLAN OF DISTRIBUTION

The Company is offering up to the aggregate offering amount of $10,000,000. There is no minimum amount of 3 Year Notes that must be sold in this Offering. Therefore, proceeds of the Offering will not be placed in escrow. They will be available to the Company upon acceptance of the subscription. Once the Company has accepted one or more subscriptions, the Company may have periodic closings for the issuance of such 3 Year Notes. The Company reserves the right, with or without cause, and at its sole discretion to accept or reject any subscription for the 3 Year Notes. The Offering Period will end upon the earlier of the receipt and acceptance of subscriptions for the maximum Offering Amount of $10,000,000 or one year from the effective date of this prospectus. We reserve the right to terminate this Offering at any time and to refuse to sell 3 Year Notes to any person.

The Company is offering the 3 Year Notes pursuant to registration under the Securities Act. The Company will offer the 3 Year Notes on a “self-underwritten” basis, with no minimum. This means that the Offering does not involve the participation of an underwriter to market, distribute or sell the 3 Year Notes offered under this prospectus. The officers and directors of the Company intend to sell the 3 Year Notes directly, who will not be separately compensated therefore, except for the reimbursement of actual out-of-pocket expenses incurred in connection with the sale of 3 Year Notes. The intended methods of communication include, without limitation, telephone and personal contact. In connection with their efforts, our officers and directors will rely on the safe harbor provisions of Rule 3a4-1 of the Securities Exchange Act of 1934. Rule 3a4-1 provides an exemption from the broker/dealer registration requirements of the Securities Exchange Act of 1934 for persons associated with an issuer provided that they meet certain requirements.

Notwithstanding the above, we reserve the right to utilize a Placement Agent, where permitted by law, to assist us in locating potential investors, in which case we will pay commissions and non-accountable expenses of up to 11% of the gross offering price of the 3 Year Notes. The Company will pay the Placement Agent(s) a commission of up to eight percent (8%) of the offering price of the 3 Year Notes subscribed to and sold and non-accountable expenses in an amount equal to three percent (3%) of the 3 Year Notes sold for its technical assistance. The Placement Agent will not be required to sell any specific number or dollar amount of securities but will use their best efforts to sell the 3 Year Notes. At this time we do not have any bidding commitments, agreements or understandings with any broker/dealers, placement agents or finders. We may use, however, MMR Investment Bankers, Inc. who served as placement agent with our prior private placements of debt. We provide no assurance that all or any of the 3 Year Notes will be sold by us or any future Placement Agent(s).

The 3 Year Notes may not be offered or sold in certain jurisdictions unless they are registered or otherwise comply with the applicable securities laws of such jurisdiction by exemption, qualification or otherwise. We intend to sell the 3 Year Notes only in the states in which this Offering has been qualified or an exemption from the registration requirements is available, and purchases of 3 Year Notes may be made only in those states.

How to Subscribe

Included with this prospectus is a “Subscription Agreement” which, along with this prospectus and Indenture, forms the contractual basis for your investment in the 3 Year Notes described in this prospectus. The Subscription Agreement will be delivered along with the prospectus to prospective investors by us. The Subscription Agreement requires prospective investors of the 3 Year Notes to furnish personal and financial information so that such purchaser may be deemed eligible by the Company. The Subscription Agreement is self-explanatory.

Payment for the 3 Year Notes may be made by check or money orders made payable to “Southfield Energy Corporation.” The funds will be deposited in a bank account until the subscription is approved by the Company.

LEGAL MATTERS

The validity of the 3 Year Notes will be passed upon for us by Jack Chapline Vaughan, Attorney at Law.

EXPERTS

The financial statements included in this prospectus have been audited by M&K CPAS, PLLC, an independent registered public accounting firm, as set forth in their reports appearing herein and elsewhere in the registration statement, and are included in reliance upon such reports given upon their authority as experts in accounting and auditing.

Estimated quantities of our proved oil and gas reserves as of December 31, 2007 and 2008 and the net present value of such proved reserves set forth in this prospectus, are based upon reserve reports prepared by Huddleston & Company.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON

ACCOUNTING AND FINANCIAL DISCLOSURE

We have no changes in, or disagreements with, our auditors.

INDEX TO FINANCIAL STATEMENTS

		Page

Southfield Energy Corporation, Inc. Audited Financial Statements:

Report of Independent Registered Public Accounting Firm		F-2

Statements of Operations for the years ended December 31, 2008 and 2007		F-3

Balance Sheets as of December 31, 2008 and 2007		F-4

Statements of Cash Flows for the years ended December 31, 2008 and 2007		F-5

Statements of Changes in Stockholders’ Deficit for the years ended December 31, 2008 and 2007		F-6

Notes to Financial Statements		F-7

Southfield Energy Corporation, Inc. Financial Statements (Unaudited):

Statements of Operations for the three and nine months ended September 30, 2009 and September 30, 2008		F-23

Balance Sheets as of September 30, 2009 and as of December 31, 2008		F-24

Statements of Cash Flows for the nine months ended September 30, 2009 and 2008		F-25

Statements of Changes in Stockholders’ Deficit for the nine months ended September 30, 2009		F-26

Notes to Financial Statements		F-27

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Southfield Energy Corporation

Houston, Texas

We have audited the accompanying balance sheets of Southfield Energy Corporation (the “Company”) as of December 31, 2008 and 2007, and the related statements of operations, changes in stockholders’ deficit, and cash flows for the years ended December 31, 2008 and 2007. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southfield Energy Corporation as of December 31, 2008 and 2007 and the results of its operations and cash flows for the period described above in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company suffered a net loss from operations and has a net capital deficiency, which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters also are described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 14 to the financial statements, the 2008 and 2007 financial statements have been restated to correct misstatements in the financial statements.

/s/ M&K CPAS, PLLC

www.mkacpas.com

Houston, Texas

April 20, 2009, except for Notes 14 and 15 which are January 15, 2010

F-2

SOUTHFIELD ENERGY CORPORATION

STATEMENTS OF OPERATIONS

For the years ended December 31, 2008 and 2007

	Year Ended			Year Ended
	December			December
		31, 2008			31, 2007
REVENUES:

Oil and Gas Production	$	310,299		$	18,894
Cost of Sales		94,364			6,361
GROSS MARGIN		215,935			12,553

EXPENSES:
Amortization of Loan and Debenture Costs		98,827			41,799
General and Administrative Expenses		273,143			85,256
TOTAL OPERATING EXPENSES		371,970			127,055

OPERATING LOSS		(156,035	)		(114,502	)

Other Income (Expense)
Interest Income		3,870			532
Gain on Sale of Securities		14,479			-
Interest Expense		(128,431	)		(75,547	)
Total Other Income (Expenses)		(110,082	)		(75,015	)

Net Loss from Continuing Operations	$	(266,117	)	$	(189,537	)
Net Income / (Loss) from Discontinued Operations	$	(57,700	)	$	35,757

Net Loss	$	(323,817	)	$	(153,780	)

Other Comprehensive Income:
Unrealized loss on available for sale securities		(325,465	)		-
Total Comprehensive Loss		(649,282	)		(153,780	)

Weighted average common shares outstanding		7,363,005			7,026,397

Net loss per common share from continuing
operations (Basic and Diluted)	$	(0.04	)	$	(0.03	)

Net income/( loss) per common share from discontinued
operations (Basic and Diluted)	$	(0.01	)	$	0.01

Basic and diluted net loss per common share	$	(0.05	)	$	(0.02	)

*See accompanying notes to the financial statements.

F-3

SOUTHFIELD ENERGY CORPORATION

BALANCE SHEETS

As of December 31, 2008 and 2007

	December			December
		31, 2008			31, 2007
ASSETS
Current Assets:
Cash	$	123,104		$	353,112
Accounts Receivable		49,068			12,051
Accounts Receivable - Related Party		2,000			4,163
Prepaid Expenses		30,933			-
Current assets of discontinued operations		10,658			8,518

TOTAL CURRENT ASSETS		215,763			377,844

Property & Equipment:
Oil & Gas, on the basis of successful efforts accounting
Gross Proved Properties		222,888			96,584
Less: Accumulated Depletion and Depreciation		(66,981	)		(513	)
Net Proved Properties		155,907			96,071

Office Equipment		427			-

Other Long Term Assets:
Gross Capitalized Loan and Debenture Costs		370,353			267,240
Less: Accumulated Amortization		(148,739	)		(49,912	)
Net Capitalized Loan and Debenture Costs		221,614			217,328

Available for Sale Securities		524,965			-
Less: Valuation Allowance		(325,465	)		-
Net (market value)		199,500			-

Long term assets of discontinued operations		104,228			190,159

TOTAL ASSETS	$	897,439		$	881,402

LIABILITIES AND STOCKHOLDERS' DEFICIT

LIABILITIES:
Current Liabilities:
Accounts Payable	$	11,944		$	32,517
Accrued interest on Debentures		108,987			48,727
Current Portion of Debentures Payable		304,000			-
Current Liabilities of discontinued operations		15,505			10,873
TOTAL CURRENT LIABILITIES		440,436			92,117

Long Term Liabilities:
Convertible Debentures Payable		1,178,000			866,000
TOTAL LONG TERM LIABILITIES		1,178,000			866,000

TOTAL LIABILITIES		1,618,436			958,117

STOCKHOLDERS' DEFICIT:
Common stock, $0.001 par value; 50,000,000 shares authorized, 7,410,000
and 7,360,000 issued and outstanding at 12/31/08 and 12/31/2007, respectively		7,410			7,360
Additional Paid-in Capital		99,373			94,423
Deficit accumulated during the development stage		(24,718	)		(24,718	)
Accumulated deficit		(477,597	)		(153,780	)
Accumulated other comprehensive income (loss)		(325,465	)		-

TOTAL STOCKHOLDERS' DEFICIT		(720,997	)		(76,715	)

TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$	897,439		$	881,402

*See accompanying notes to the financial statements.

F-4

SOUTHFIELD ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

For the years ended December 31, 2008 and 2007

	Year Ended			Year Ended
	December			December
		31, 2008			31, 2007
Cash Flows From Operating Activities
Net loss from continuing operations	$	(266,117	)	$	(189,537	)
Net income/(loss) from discontinued operations		(57,700	)		35,757
Net loss		(323,817	)		(153,780	)

Adjustments to reconcile net loss to net cash
(used) provided by operating activities
Stock based consulting expense		5,000			76,500
Gain on trading securities		(14,479	)		-
Amortization of Loan & Debenture Costs		98,827			41,799
Depreciation, Depletion and Amortization		55,700			6,361
Changes in operating assets and liabilities:
Payables		(20,574	)		39,257
Accrued Interest		60,260			48,727
Receivables		(34,854	)		(12,051	)
Prepaid Expenses		(30,933	)		-
Net cash flows from discontinued operations		129,811			(174,446	)
Net cash (used) provided by operating activities		(75,059	)		(127,633	)

Cash Flows From Investing Activities
Capitalized Investment in Proved Leaseholds		(126,264	)		(96,584	)
Purchase of Available for Sale Securities		(510,486	)		-
Purchase of fixed assets		(427	)		-
Net cash flows from discontinued operations		(30,662	)		(34,542	)
Net cash used by investing activities		(667,839	)		(131,126	)

Cash Flows From Financing Activities
Capital Contributions from Shareholders		-			9,183
Deferred financing costs		(103,110	)		(174,064	)
Debentures Payable		616,000			562,000
Net cash provided from financing activities		512,890			397,119

Net increase in cash		(230,008	)		138,360
Cash, beginning of period		353,112			214,752
Cash, end of period	$	123,104		$	353,112

Supplemental disclosure of non-cash items:
Unrealized loss on available for sale securities		(325,465	)		-

Income taxes paid in cash		-			-
Interest expense paid in cash	$	101,449		$	30,952

*See accompanying notes to the financial statements.

F-5

SOUTHFIELD ENERGY CORPORATION

STATEMENT OF CHANGES IN STOCKHOLDERS' DEFICIT

For the years ended December 31, 2008 and 2007

							Deficit
							Accumulated						Accumulated
					Additional		During						Other
	Common Stock				Paid-in		Development			Accumulated			Comprehensive
	Shares		Amount		Capital		Stage			Deficit			Income			Total

Balance, December 31, 2006		6,595,000	$	6,595	$	9,505	$	(24,718	)	$	-		$	-		$	(8,618	)

Issuance of common stock at $0.10 per share to Don Ellison on February 22, 2007		50,000		50		4,950		-			-			-			5,000

Issuance of common stock at $0.10 per share to Sunflower Management Group on June 15, 2007		705,000		705		69,795		-			-			-			70,500

Issuance of common stock at $0.10 per share to Jack Arnold on October 12, 2007		10,000		10		990		-			-			-			1,000

Rent contributed by shareholder		-		-		9,183		-			-			-			9,183

Net Loss		-		-		-		-			(153,780	)		-			(153,780	)

Balance, December 31, 2007		7,360,000	$	7,360	$	94,423	$	(24,718	)	$	(153,780	)	$	-		$	(76,715	)

Issuance of common stock at $0.10 per share to John Brewster on December 10, 2008		50,000		50		4,950		-			-			-			5,000

Net Loss		-		-		-		-			(323,817	)		-			(323,817	)

Unrealized loss on available for sale securities		-		-		-		-			-			(325,465	)		(325,465	)

Balance, December 31, 2008		7,410,000	$	7,410	$	99,373	$	(24,718	)	$	(477,597	)	$	(325,465	)	$	(720,997	)

*See accompanying notes to financial statements

F-6

SOUTHFIELD ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS

For the years ended December 31, 2008 and 2007

NOTE 1 – Nature of Operations and Basis of Reporting

SOUTHFIELD ENERGY CORPORATION (the "Company" or “Southfield”), a development stage company through December 31, 2006, was incorporated in Nevada on July 5, 2005 with the objective to acquire oil and gas interests in the United States. On July 6, 2005, the Company sold 6,200,000 shares of its common stock at par value for $6,200. On December 31, 2006 the Company exited the Development Stage with its first acquisition of oil and gas interests. The Company selected December 31 as its year-end.

Southfield is an oil and gas investment company. It invests in the exploration, development, and production of oil & gas in the United States. The focus of its activity is in Texas, Louisiana, Oklahoma, Colorado and the Gulf of Mexico . The Company intends to invest its funds primarily as a working interest owner, royalty interest owner or mineral lease owner. Generally, the Company will be a minority owner in each well. The Company expects most of its investments to range from 5-25% of the total investment required for any given project, and anticipates that its investment in each project will range from $50,000 to $250,000.

NOTE 2 – Going Concern

These financial statements have been prepared on a going concern basis and do not include any adjustments to the measurement and classification of the recorded asset amounts and classification of liabilities that might be necessary should the Company be unable to continue as a going concern. The Company has experienced losses and incurred negative cash flows in the periods and since inception. The Company’s ability to realize its assets and discharge its liabilities in the normal course of business is dependent upon continued support. The Company is currently attempting to obtain additional financing through its debenture offering to continue its operations. However, there can be no assurance that the Company will obtain sufficient additional funds from these sources.

These conditions cause substantial doubt about the Company’s ability to continue as a going concern. A failure to continue as a going concern would require that stated amounts of assets and liabilities be reflected on a liquidation basis that could differ from the going concern basis.

NOTE 3 - Summary of Significant Accounting Policies

OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS) – The Company follows the successful efforts method of accounting for oil and gas property acquisition, exploration, development and production activities.

Capitalization Policies: Oil and gas property acquisition costs, exploration well costs, and development costs are capitalized as incurred. Net capitalized costs of unproved property and exploration well costs are reclassified as proved property and well costs when related proved reserves are found. If an exploration well is unsuccessful in finding proved reserves, the capitalized well costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, and the costs of carrying unproved property are charged to exploration expense as incurred. Costs to operate and maintain wells and field equipment are expensed as incurred.

F-7

Sales and retirement Policies: Gains and losses on the sale or abandonment of oil and gas properties are generally reflected in income. Costs of retired equipment, net of salvage value, are usually charged to accumulated amortization. Unusual retirements are reflected in income. As of December 31, 2008, management has determined that the asset retirement obligation related to the plugging and abandonment of wells is immaterial individually and to the financial statements taken as a whole. As such, no asset retirement obligation is recorded in the statements presented. Management will review the potential obligation on an on-going basis and will record the obligation in the period it becomes material, either individually or in aggregate, to the financial statements.

Impairment Policies: Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows are less than the carrying value of the asset group, the carrying value is written down to the estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets – generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of the expected future cash flows using discount rates commensurate with the risks involved in the asset group. Long-lived assets committed by management for disposal are accounted for at the lower of amortized cost or fair value less cost to sell.

EARNINGS PER SHARE – Southfield’s loss per share has been calculated by dividing the net loss for the period by the weighted average number of shares outstanding. There are no potentially dilutive securities outstanding; therefore basic loss per share equals the fully diluted loss per share.

DEFERRED FINANCING COSTS – Southfield incurred Deferred Financing Costs in connection with raising capital through the sale of debentures. The costs have been capitalized as incurred and amortized over the three year life of the debentures using the effective interest method.

STOCK BASED COMPENSATION – On January 1, 2006, the Company adopted SFAS 123 (revised 2004), Share-Based Payment (“SFAS 123(R)”), which requires the measurement and recognition of compensation expense for all share-based awards made to employees and directors, including employee stock options and shares issued through its employee stock purchase plan, based on estimated fair values. In March 2005, the Securities and Exchange Commission issued Staff Accounting Bulletin 107 (“SAB 107”) relating to SFAS 123(R). The Company has applied the provisions of SAB 107 in its adoption of SFAS 123(R). The Company adopted SFAS 123(R) using the modified prospective transition method, which requires the application of the accounting standard as of the beginning in 2006. The Company’s financial statements as of and for the years ended December 31, 2007 and 2008 reflect the impact of SFAS 123(R). In accordance with the modified prospective transition method, the Company’s financial statements for prior periods do not include the impact of SFAS 123(R).

FAIR VALUE OF FINANCIAL INSTRUMENTS – Southfield includes fair value information in the Notes to the Financial Statements when the fair value of its financial instruments can be determined and is different from the carrying amounts reflected in the accompanying statements. Southfield generally assumes that the carrying amounts of cash, short-term debt and long-term debt approximate fair value. For non-current financial instruments, Southfield uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments. Management believes that the carrying amounts of the financial instruments are fairly represented in the financial statements.

F-8

USE OF ESTIMATES – The preparation of financial statements in conformity with accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Southfield’s most significant financial estimates are based on the valuation of remaining proved oil and gas reserves, impairment of its long-lived assets, valuation of its assets using successful efforts accounting, and revenue recognition. Because of the nature of these estimates and the nature of exploration, development and production of oil and gas reserves, actual results could differ from these estimates and losses and reductions in value could occur. These possible losses and reductions in values which have not been reflected in the accompanying financial statements could be material to the Company’s revenues/earnings or losses and stockholders’ equity (deficit). Due to the nature of the Company’s business plan to acquire additional properties to explore for oil and gas reserves, additional losses and reductions in value of the Company may occur in the future both related to properties currently being developed and new properties not yet acquired and those amounts could be substantial with respect to the Company’s financial position and operations. To be successful, the Company must acquire properties that result in significant amounts of recoverable amounts of oil and gas reserves and be successful in the marketing of those reserves over a long period of time in order to pay its acquisition, development, production and operating costs, to cover its credit and debt obligations, and to provide a return to its shareholders.

INCOME TAXES – The Company has incurred losses since inception and, therefore, has not been subject to federal income taxes. As of December 31, 2007 and December 31, 2008, the Company estimates an accumulated net operating loss (“NOL”) carryforward of approximately $169,000 and $493,000, respectively, resulting in deferred tax assets of approximately $64,000 and $172,550, respectively. These carryforwards begin to expire in 2026 if not previously utilized. Because U.S. tax laws limit the time during which NOL and tax credit carryforwards may be applied against future taxable income and tax liabilities, the Company may not be able to take full advantage of its NOL and tax credits for federal income tax purposes. Because the company determined that it will not likely realize the deferred tax asset, a full valuation allowance has been taken to reduce the deferred tax asset to zero as of December 31, 2008, and 2007, respectively.

CONCENTRATIONS OF CREDIT RISK – Financial instruments that may potentially subject the Company to concentration of risk in the future consist primarily of cash which will be placed with high credit quality financial institutions at amounts that may at times exceed FDIC limits.

ACCOUNTS RECEIVABLE – Accounts receivable represent the amounts due from the sale of oil and gas. Based on collections history and review of accounts receivable aging, management does not believe that any allowance for doubtful accounts is necessary as of December 31, 2008 or 2007.

REVENUE RECOGNITION – Southfield recognizes oil, gas and natural gas condensate revenue in the period of delivery. Settlement for oil sales occurs 30 days after the oil has been sold; and settlement for gas sales occurs 60 days after the gas has been sold. Southfield has reviewed the revenue recognition requirements in SAB104, which state that revenue should be recognized when an arrangement exists, the product or service has been provided, the sales price is fixed or determinable, and collectability is reasonably assured, and concludes that the revenue policies in place meet these criteria.

CASH AND CASH EQUIVALENTS – Southfield considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents at December 31, 2007 and December 31, 2008 are $353,112 and $123,104, respectively.

F-9

Recent Accounting Pronouncements

In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 establishes an approach that requires quantification of financial statement misstatements based on the effects of the misstatements on each of the Company’s consolidated financial statements and the related financial statement disclosures. SAB 108 is effective for the year ending February 28, 2009.

In December 2007, the Financial Accounting Standards Board issued FASB Statement No. 141 (Revised 2007), Business Combinations (“SFAS 141R”). SFAS 141R provides additional guidance on improving the relevance, representational faithfulness, and comparability of the financial information that a reporting entity provides in its financial reports about a business combination and its effects. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.

We adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standard (SFAS) No. 157, Fair Value Measurement at inception. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements and accordingly, does not require any new fair value measurements. SFAS No. 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, SFAS No. 157 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows.

¨	Level 1. Observable inputs such as quoted prices in active markets;

¨	Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

¨	Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

The Company values Proved Properties at their fair value if impairment is identified in accordance with FAS 144. The inputs that are used in determining the fair value of these assets are Level 3 inputs. These inputs consist of but are not limited to the following: estimates of reserve quantities, estimates of future production costs and taxes, estimates of consistent pricing of commodities, 10% discount rate, etc. In 2008, the company recognized impairment on one of the oil and gas fields, the Aldwell Unit. This field was written down to the fair value of the field, and all other unimpaired fields were carried at cost. All activity related to the Aldwell Unit has been presented as discontinued operations as a result of the subsequent sale of this property on September 1, 2009. The table below represents the remaining asset balances within continuing operations.

The following table presents assets that are measured and recognized at fair value as of December 31, 2008 and the year then ended on a non-recurring basis :

							Total
							Unrealized
Description	Level 1		Level 2		Level 3		(losses)
Convertible note (net)	$	-	$	-	$	1,482,000	$	-
Available for Sale Securities		199,500		-		-		(325,465	)
Proved Properties (net)		-		-		155,907		-
Total	$	199,500	$	-	$	1,637,907	$	(325,465	)

The FASB’s SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, including an Amendment of SFAS 115 became effective for us as of January 1, 2008. SFAS 159 establishes a fair value option that permits entities to choose to measure eligible financial instruments and certain other items at fair value at specified election dates. A business entity shall report unrealized gains and losses on items for which the fair value options have been elected in earnings at each subsequent reporting date. For the period ended December 31, 2008, there were no applicable items on which the fair value option was elected.

F-10

NOTE 4 - Related Party Transactions

In 2007 the Company paid business expenses on behalf of one of its officers in the amount of $4,163. These expenses were repaid to the Company on August 14, 2008. In 2008, Southfield loaned $2,000 dollars to one of its officers which was classified as a receivable on the Balance Sheet as of December 31, 2008. The $2,000 loan that was made to one of our officers while we were a private company has been repaid. In 2008 and 2007, shared office space with a related party, Goldbridge Energy Partners, LLC. Southfield used 50% of the office space 50% of the time; therefore, we took the monthly rent for the entire space of $3,061, annualized it, and then divided by four. Therefore the rent expense that should be recognized by Southfield for 2007 is $9,183. In the first half of 2008, Southfield used 50% of the space 100% of the time and paid roughly $1,500 per month. For the second half of 2008, Southfield used 100% of the office space 100% of the time and therefore paid the entire rent of roughly $3,100 per month. The company that manages the administration of the office rent granted a waiver for the rent due in the month of August and therefore Southfield did not pay rent for the month of August. The total rent expense for 2008 was $24,483.

NOTE 5 – Convertible Debentures Payable

We have retained the services of MMR Investment Bankers, Inc. to represent the Company in a convertible Debenture offering of $10 million. We also engaged Sunflower Management Group, a third party administrator for interest payments and technical compliance with the repayment requirements of the Debentures that have been sold.

MMR Investment Bankers, Inc. has created an account to reserve from the gross offering proceeds the first six months of interest payments due to any investor. Sunflower Management Group is managing the interest reserve account and is responsible for accruing and funding interest to investors as it becomes due. On June 15, 2007, the Company issued 705,000 shares to Sunflower Management Group as consideration for providing financial management services. These shares were valued at $70,500 by the company and included in its deferred financing costs.

As of December 31, 2008 and 2007, the Company has issued $866,000 and $1,482,000 of three-year convertible Debentures to investors, respectively. The Debentures bear interest at a rate of 10% and mature three years from the date of purchase. The investors may elect to have simple interest paid on a monthly basis, or may have the interest compounded semiannually and paid at maturity. The investors may convert the face value of the Debenture to common stock in the Company at any time during the term of the Debenture at a conversion price of $5.00 per share. The Company has the right to call for the conversion of the Debentures when the common stock of the Company trades on a public market for 20 consecutive days at a price higher than $7.50 per share and upon notice, unless the Debenture holder elects not to accept the conversion offer.

After review of FAS 133 and EITF 00-27, the Company concluded that there is not a derivative or beneficial conversion option associated with the debentures that is in-the-money and therefore the Company is not required to calculate the intrinsic value of such conversion option.

Maturities of the notes over the next five years are as follows:

2009			2010				2011				2012				2013
$	304,000		$	454,000			$	724,000			$	0			$	0

F-11

NOTE 6 – Acquisitions & Capital Investments

On January 23, 2007 the Company paid for the acquisition and received an assignment of leases. The operator of the wells is Mariner Energy Inc., a publicly traded company under the symbol ME. This assignment was subsequently sold on August 12, 2009, and has been retroactively presented on the financial statements as discontinued operations as a result of this sale. On August 8, 2007, the Company approved the capital investment of $91,100 for the drilling and completion of a well located in the Mary King Estell lease in Nueces County, Texas. The operator of this lease is Durango Resources, a private company with offices located in Houston, Texas.

In 2008 the Company invested $156,926 in oil and gas exploration and production projects. The Company successfully drilled the C-32 and C-33 wells located on the Mary King Estell Lease and spent approximately $61,000 and $65,000, respectively. The remainder of the capital investment in proved leaseholds was in the Aldwell Unit for roughly $31,000. This capital investment was used to drill and complete new wells and to recomplete existing production wells to enhance production in the field. All activity related to the Aldwell Unit has been presented as discontinued operations as a result of the subsequent sale of this property on September 1, 2009.

In 2008 the Company invested approximately $510,000 in the common stock of Meridian Resources, a publicly traded exploration and production company on the New York Stock Exchange listed under the symbol TMR. In 2008 the market price of the stock decreased such that the Company incurred an unrealized holding loss of $325,465.

NOTE 7 – Non-cash Compensation

Don Ellison was issued 50,000 shares on February 22, 2007 for engineering services related prospect evaluation. Sunflower Management Group was issued 705,000 shares on June 15, 2007 for financial management services. Jack Arnold was issued 10,000 shares October 12, 2007 for designing and implementing our website and providing information technology services. John Brewster was issued 50,000 shares on December 10, 2008 for providing consulting services to the Company. The equity that was issued in 2007 and 2008 was valued by the Company at $0.10 per share based upon management’s discounted cash flow analysis.

NOTE 8 – Depletion and Depreciation

For 2007 and 2008, the Company incurred depreciation, depletion and amortization of its continuing operations of proved producing properties of $6,361 and $55,700, respectively. For 2007 and 2008, the Company incurred depreciation, depletion and amortization of its discontinued operations of proved producing properties of $3,535 and $10,768, respectively When the company purchased the Aldwell Unit, it allocated 25% of the purchase price to tangible well costs and 75% to intangible well costs. Depreciation, depletion and amortization has been calculated using the units of production method.

NOTE 9 – Capitalized Expenses

The Company is capitalizing expenses related to the Debenture Offering and amortizing them over the three year life of the Debentures. The gross capitalized loan and debenture costs were $267,240 and $370,353 as of December 31, 2007 and December 31, 2008, respectively. The accumulated amortization was $49,912 and $148,739; and the net capitalized loan and debenture costs were $217,328 and $221,614 for the same periods respectively.

F-12

NOTE 10 – Impairment of Proved Properties

Due to the low commodity prices for oil and gas at December 31, 2008, the Company was required to impair its assets located in the Aldwell Unit. An impairment test was conducted using data in a reserve report compiled by Huddleston and Company, a Houston based petroleum engineering company. While conducting the impairment test, management determined that the estimated undiscounted future net cash flow provided in the reserve report was less that the carrying value of the Aldwell Unit on the Company’s Balance Sheet on December 31, 2008 and that the assets were subject to impairment. The assets were subsequently impaired by taking the difference between the discounted future net cash flow, using a 10% discount rate, which was estimated by Huddleston and Company and the carrying value of the assets on our Balance Sheet. Management found the difference to be $116,553 and impaired the Aldwell Unit by that amount. The impairment expense is included in net loss from discontinued operations due to the sale of this unit subsequent to the balance sheet date.

NOTE 11 – Commitments and Contingencies

Litigation

In the normal course of business, the Company may become subject to lawsuits and other claims and proceedings. Such matters are subject to uncertainty and outcomes are not predictable with assurance. Management is not aware of any pending or threatened lawsuits or proceedings which would have a material effect on the Company’s financial position, liquidity, or results of operations.

Concentrations

The Company’s sales are dependent upon the performance of its producing wells and our ability to successfully partner with high quality oil and gas operators; any impacts to this industry could have a significant impact to the Company. For the years ended December 31, 2007 and 2008, two leases represented 100% of the total revenues of the company and 100% of the accounts receivable. The Company generally does not require collateral to support accounts receivable or financial instruments subject to credit risk.

Fair Value of assets and liabilities

							Total
							Gains
Description	Level 1		Level 2		Level 3		(losses)
Convertible note (net)	$	-	$	-	$	1,482,000	$	-
Available for Sale Securities		199,500		-		-		(325,465	)
Proved Properties (net)		-		-		260,135		-
Total	$	199,500	$	-	$	1,742,135	$	(325,465	)

NOTE 12 – Oil and Gas Properties

The Company owns non-operated working interests in the Aldwell Unit located in Reagan County and in the Mary King Estell Lease which are operated by Mariner Energy and Durango Resources, respectively. As of December 31, 2008 the company owns an interest in approximately 200 wells. According to the reserve report prepared by Huddleston and Company and the Company’s estimate of future income taxes, as of December 31, 2007 and December 31, 2008 the Company had proved reserves with estimated discounted net cash flows after taxes of $805,815 and $609,427, respectively. Estimated future net cash flows of the properties were discounted at 10% consistent with FAS 69. All assets and liabilities related to the Aldwell Unit have been presented as discontinued operations due to the sale of this unit subsequent to the balance sheet date.

F-13

NOTE 13 – Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities

The following disclosures provide unaudited information required by SFAS No. 69, “Disclosures About Oil and Gas Producing Activities.” These disclosures include all oil and gas properties for the years ended December 31, 2008 and 2007. This includes the oil and gas property, the “Aldwell Unit” which was subsequently sold on September 1, 2009, see note 15.

Results of operation from oil and natural gas producing activities

The Company’s oil and natural gas properties are located in Texas. The Company currently has no oil and gas investments or operations in foreign jurisdictions. Results of operations from oil and natural gas producing activities are summarized below for the years ended December 31:

Results of Operations

	As of December 31,
	2008			2007
Sales of oil and gas	$	395,474		$	78,276
Production costs		(54,218	)		(20,090	)
Depreciation, depletion and amortization		(66,468	)		(9,896	)
Accretion of asset retirement obligation		-			-
Results of producing activities	$	274,788		$	48,290

Supplemental reserve information

The Company emphasizes that reserve estimates are inherently imprecise. Our reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties, and volumetric calculations. Accordingly, these estimates are expected to change and such changes could be material and occur in the near term as future information becomes available.

The Company retained the service of an independent petroleum consultant Huddleston and Company, Inc. to estimate its proved oil and gas reserves at December 31, 2008 and 2007.

Changes to reserves resulted from revisions of previous estimates, purchases of minerals in place, and extensions and discoveries.

In 2007, oil and gas reserves increased due to purchases of oil and gas properties, and revisions of reserve estimates for properties held prior to 2007. These revisions were based on the company not having a reserve report in 2006 and the resulting revision to adjust the reserves based on the economic information uncovered with the 2007 reserve report.

In 2008, proved gas reserves increased from approximately 175 to 217 MMcf due primarily to the drilling of two additional gas wells on the Mary King Estell lease which more than offset 2008 production.

In 2008, proved net oil reserves decreased from 15,768 to 7,470 bbls due primarily to earlier projected production curtailment in the Aldwell Unit caused by more wells becoming uneconomic years sooner. Oil prices required to be used for projections were 53% lower ($45/bbl versus $96/bbl) for estimating reserves at year end 2008 compared to those used for reserves estimates at the end of 2007. Using significantly lower oil prices resulted in projected revenues becoming lower than the relatively constant projected costs much sooner. Another reason for the decrease in reserves estimates is that, based on information available a year later, production was projected to decline over the life of the reserves at an increased rate compared to that of the previous year.

The following table sets forth a summary of changes in estimated reserves for 2008 and 2007:

	2008						2007
Proved developed and undeveloped reserves	Oil (bbl)			Gas (Mcf)			Oil (bbl)			Gas (Mcf)
Beginning of year		15,768			174,510			-			-
Revisions of previous estimates		(7,417	)		-			16,402			39,493
Purchases of minerals in place		-			-			247			146,680
Extensions and discoveries		-			79,091			-			-
Production		(881	)		(36,241	)		(881	)		(11,663	)
End of year		7,470			217,360			15,768			174,510

Proved developed reserves:
Beginning of year		12,059			77,550			-			-
End of year		5,512			125,010			12,059			77,550

(1) Includes natural gas liquids expressed in measurements of bbl.

Costs incurred

Total Costs incurred related to oil and natural gas properties, and accumulated depreciation, depletion, amortization, and valuation allowances are summarized below for the years ended December 31:

Capitalized Costs Related to Oil Producing Activities

	As of December 31,
	2008			2007
Proved Oil and Gas		453,052			296,126
Accumulated depreciation, depletion,
and amortization, and valuation allowances		(192,917	)		(9,896	)
Net capitalized costs		260,135			286,230

Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below for the years ended December 31:

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

	As of December 31,
	2008		2007
Acquisitions of proved properties		-		190,600
Exploration costs		-		70,983
Development costs		156,926		34,543

F-14

Standardized Measure

The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves for the years ended December 31 are shown below:

Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil Reserves

	2008			2007
Future cash inflows		1,549,473			2,571,650
Future production costs		(431,453	)		(711,093	)
Future development costs		(165,765	)		(194,685	)
Future income tax expenses		(62,340	)		(164,061	)
Future net cash flows		889,915			1,501,811
10% annual discount for estimated timing of cash flows		(280,488	)		(695,996	)
Standardized measure of discounted future net cash flows		609,427			805,815

Year end oil and gas price information	2008		2007
Year end oil price per barrel		45		96
Year end oil price per mcf	$	5.66	$	6.73

From 2007 to 2008, the PV10 value was reduced significantly primarily as a result of the sharp decline in the prices of oil and natural gas. Future cash flows are computed by applying current year-end prices of oil and natural gas to future estimates of year-end quantities of proved oil and natural gas reserves. The year-end prices used in computing future cash flows as of December 31, 2007 and 2008 were $95.98 and $44.60 for oil, respectively, and $6.73 and $5.66 for gas, respectively. Future operating expenses and development costs were estimated by engineers from Huddleston and Company, a Houston based petroleum engineering company, based on year-end costs and assuming continuation of existing economic conditions.

Future income taxes are based on year-end statutory rates, adjusted for tax basis of oil and natural gas properties. A discount factor of 10% was used to reflect the timing of future net cash flows.

The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value may also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated changes in future prices and costs, and may require a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

F-15

Changes in Standard Measure

Included within standard measure are reserves purchased in place. The purchase of reserves in place includes undeveloped reserves that were acquired at minimal value which have been estimated by independent reserve engineers to be recoverable through existing wells utilizing equipment and operating methods available to the Company and that are expected to be developed in the near term based on an approved plan of development contingent on available capital.

Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended December 31 are summarized below:

Changes in Standardized Measure of Discounted Future Cash Flows

	As of December 31,
	2008			2007
Beginning Balance	$	988,653		$	-
Accretion of Discount		98,865			-
Sales of oil and gas net of production costs		(341,256	)		(58,186	)
Development cost changes		25,901			(35,120	)
Previously estimated development costs incurred during period		(40,373	)		-
Revisions in previous price estimates		(893,457	)		-
Revisions in quantity estimates		266,753			792,177
Net changes in prices and production costs		191,713			(225,755	)
Changes in estimated future severance & ad valorem taxes		58,731			(55,439	)
Purchases of minerals property		-			512,791
Other-Unspecified		(6,782	)		58,185
Net change in standardized measure of discounted cash flows		348,746			988,653
Ending Balance	$	639,907		$	988,653

NOTE 14 – Correction of Errors

The Company intends to restate its previously issued December 31, 2008 and 2007 financial statements for matters related to the following previously reported items: 1. The Company sold the oil and gas asset “Aldwell Unit” subsequent to the balance sheet date and prior to the company’s registration statement being declared effective by the SEC. The 2008 and 2007 financial statements have been retroactively adjusted for the discontinued operations of this segment consistent with the FASB’s guidance on reporting discontinued operations. 2. Depreciation, depletion, and amortization have been moved from operating expenses to cost of sales in the Statements of Operations for the years ended December 31, 2008 and 2007. 3. Basic and diluted net loss per share was originally calculated based on the total comprehensive loss for the year ended December 31, 2008 on the Statements of Operations. This was revised to show the net loss per share for net loss only. 4. The net loss per share on the Statements of Operations was rounded to the nearest penny rather than the nearest tenth of a penny to provide more precision. 5. The Statement of Cash Flows originally showed a portion of cash flows related to debenture offerings as an operating activity rather than financing activity for the year ended December 31, 2008. The cash flow has been re-classified to financing activities. The accompanying financial statements for the years ended December 31, 2008 and 2007 have been restated to reflect these corrections. The aforementioned errors required no accounting entries to adjust any balances. The errors were all related exclusively to presentation on the financial statements.

F-16

The following is a summary of the restatements for December 31, 2008 and December 31, 2007.

Statement of Operations for the year ended December 31, 2008:

	Previously			Net
	Reported			Change			Restated
REVENUES:

Oil and Gas Production	$	395,474			(85,175	)	$	310,299
Cost of Sales		54,218			40,146			94,364
GROSS MARGIN		341,256			(45,029	)		215,935

EXPENSES:
Amortization of Loan and Debenture Costs		98,827			-			98,827
Depreciation, Depletion and Amortization		66,468			(66,468	)		-
General and Administrative Expenses		273,143			-			273,143
TOTAL OPERATING EXPENSES		438,438			(66,468	)		371,970

OPERATING LOSS		(97,182	)		(58,853	)		(156,035	)

Other Income (Expense)
Interest Income		3,870			-			3,870
Gain on Sale of Securities		14,479			-			14,479
Interest Expense		(128,431	)		-			(128,431	)
Impairment of Proved Reserves		(116,553	)		116,553			-
Total Other Income (Expenses)		(226,553	)		116,553			(110,082	)

Net Loss from continuing operations		-			(266,117	)		(266,117	)
Net loss from discontinued operations		-			(57,700	)		(57,700	)
Net Loss	$	(323,817	)				$	(323,817	)

Other Comprehensive Income:
Unrealized loss on available for sale securities		(325,465	)		-			(325,465	)
Total Comprehensive Loss		(649,282	)		-			(649,282	)

Weighted average common shares outstanding		7,363,005			-			7,363,005

Net loss per common share from continuing
operations (Basic and Diluted)		-			(0.04	)		(0.04	)

Net loss per common share from continuing
operations (Basic and Diluted)		-			(0.01	)		(0.01	)

Basic and diluted net loss per common share	$	(0.088	)		0.133		$	(0.05	)

F-17

Statement of Operations for the year ended December 31, 2007:

	Previously			Net
	Reported			Change			Restated
REVENUES:

Oil and Gas Production	$	78,276			(59,382	)	$	18,894
Cost of Sales		20,090			(13,729	)		6,361
GROSS MARGIN		58,186			45,633			12,553

EXPENSES:
Amortization of Loan and Debenture Costs		41,799			-			41,799
Depreciation, Depletion and Amortization		9,896			(9,896	)		-
Impairment of proved reserves		-			-			-
General and Administrative Expenses		85,256			-			85,256
TOTAL OPERATING EXPENSES		136,951			(9,896	)		127,055

OPERATING LOSS		(78,765	)		(35,737	)		(114,502	)

Other Income (Expense)
Interest Income		532			-			532
Gain on Sale of Securities		-			-			-
Interest Expense		(75,547	)		-			(75,547	)
Impairment of Proved Reserves		-			-			-
Total Other Income (Expenses)		(75,015	)		-			(75,015	)

Net Loss from continuing operations		-			(189,537	)		(189,537	)
Net income from discontinued operations		-			35,757			35,757
Net Loss	$	(153,780	)		-		$	(153,780	)

Weighted average common shares outstanding		7,026,397			-			7,026,397

Net loss per common share from continuing
operations (Basic and Diluted)		-			(0.03	)		(0.03	)

Net income/(loss) per common share from continuing
operations (Basic and Diluted)		-			0.01			0.01

Basic and diluted net loss per common share	$	(0.022	)		0.002		$	(0.02	)

F-18

Balance sheet for the year ended December 31, 2008

	Previously			Net
	Reported			Change			Restated
ASSETS
Current Assets:
Cash	$	123,104		$	-		$	123,104
Accounts Receivable		59,726			(10,658	)		49,068
Accounts Receivable - Related Party		2,000			-			2,000
Prepaid Expenses		30,933			-			30,933
Current assets of discontinued operations		-			10,658			10,658

TOTAL CURRENT ASSETS		215,763			-			215,763

Property & Equipment:
Oil & Gas, on the basis of successful efforts accounting
Gross Proved Properties		336,499			(113,611	)		222,888
Less: Accumulated Depletion and Depreciation		(76,364	)		9,383			(66,981	)
Net Proved Properties		260,135			(104,228	)		155,907

Office Equipment		427			-			427

Other Long Term Assets:
Gross Capitalized Loan and Debenture Costs		370,353			-			370,353
Less: Accumulated Amortization		(148,739	)		-			(148,739	)
Net Capitalized Loan and Debenture Costs		221,614			-			221,614

Available for Sale Securities		524,965			-			524,965
Less: Valuation Allowance		(325,465	)		-			(325,465	)
Net (market value)		199,500			-			199,500

Long term assets of discontinued operations		-			104,228			104,228

TOTAL ASSETS	$	897,439		$	-		$	897,439

LIABILITIES AND STOCKHOLDERS' DEFICIT

LIABILITIES:
Current Liabilities:
Accounts Payable	$	27,449		$	(15,505	)	$	11,944
Accrued interest on Debentures		108,987			-			108,987
Current Portion of Debentures Payable		304,000			-			304,000
Current Liabilities of discontinued operations		-			15,505			15,505
TOTAL CURRENT LIABILITIES		440,436			-			440,436

Long Term Liabilities:
Convertible Debentures Payable		1,178,000			-			1,178,000
TOTAL LONG TERM LIABILITIES		1,178,000			-			1,178,000

TOTAL LIABILITIES		1,618,436			-			1,618,436

STOCKHOLDERS' DEFICIT:
Common stock, $0.001 par value; 50,000,000 shares authorized, 7,410,000		7,410			-			7,410
and 7,360,000 issued and outstanding at 12/31/08 and 12/31/2007, respectively
Additional Paid-in Capital		99,373			-			99,373
Deficit accumulated during the development stage		(24,718	)		-			(24,718	)
Accumulated deficit		(477,597	)		-			(477,597	)
Accumulated other comprehensive income (loss)		(325,465	)		-			(325,465	)

TOTAL STOCKHOLDERS' DEFICIT		(720,997	)		-			(720,997	)

TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$	897,439		$	-		$	897,439

F-19

Balance sheet for the year ended December 31, 2007

	Previously			Net
	Reported			Change			Restated
ASSETS
Current Assets:
Cash	$	353,112		$	-		$	353,112
Accounts Receivable		20,569			(8,518	)		12,051
Accounts Receivable - Related Party		4,163			-			4,163
Prepaid Expenses		-			-			-
Current assets of discontinued operations		-			8,518			8,518

TOTAL CURRENT ASSETS		377,844			-			377,844

Property & Equipment:
Oil & Gas, on the basis of successful efforts accounting
Gross Proved Properties		296,126			(199,542	)		96,584
Less: Accumulated Depletion and Depreciation		(9,896	)		9,383			(513	)
Net Proved Properties		286,230			(190,159	)		96,071

Other Long Term Assets:
Gross Capitalized Loan and Debenture Costs		267,240			-			267,240
Less: Accumulated Amortization		(49,912	)		-			(49,912	)
Net Capitalized Loan and Debenture Costs		217,328			-			217,328

Long term assets of discontinued operations		-			190,159			190,159

TOTAL ASSETS	$	881,402		$	-		$	881,402

LIABILITIES AND STOCKHOLDERS' DEFICIT

LIABILITIES:
Current Liabilities:
Accounts Payable	$	43,390		$	(10,873	)	$	32,517
Accrued interest on Debentures		48,727			-			48,727
Current Portion of Debentures Payable		-			-			-
Current Liabilities of discontinued operations		-			10,873			10,873
TOTAL CURRENT LIABILITIES		92,117			-			92,117

Long Term Liabilities:
Convertible Debentures Payable		866,000			-			866,000
TOTAL LONG TERM LIABILITIES		866,000			-			866,000

TOTAL LIABILITIES		958,117			-			958,117

STOCKHOLDERS' DEFICIT:
Common stock, $0.001 par value; 50,000,000 shares authorized, 7,410,000
and 7,360,000 issued and outstanding at 12/31/08 and 12/31/2007, respectively		7,360			-			7,360
Additional Paid-in Capital		94,423			-			94,423
Deficit accumulated during the development stage		(24,718	)		-			(24,718	)
Accumulated deficit		(153,780	)		-			(153,780	)
Accumulated other comprehensive income (loss)		-			-			-

TOTAL STOCKHOLDERS' DEFICIT		(76,715	)		-			(76,715	)

TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$	881,402		$	(1,762,804	)	$	(881,402	)

F-20

Cash flow worksheet for the year ended December 31, 2008

	Previously			Net
	Reported			Change			Restated
Cash Flows From Operating Activities
Net loss from continuing operations		-			(266,117	)		(266,117	)
Net income/(loss) from discontinued operations		-			(57,700	)		(57,700	)
Net Loss	$	(323,817	)		-		$	(323,817	)

Adjustments to reconcile net loss to net cash (used)
provided by operating activities
Stock based consulting expense		5,000			-			5,000
Impairment of oil and gas properties		116,553			(116,553	)		-
Gain on trading securities		(14,479	)		-			(14,479	)
Amortization of Loan & Debenture Costs		98,827			-			98,827
Depreciation, Depletion and Amortization		66,468			(10,768	)		55,700
Changes in operating assets and liabilities:
Payables		(15,941	)		(4,633	)		(20,574	)
Current Portion of Debentures Payable		304,000			(304,000	)		-
Accrued Interest		60,260			-			60,260
Receivables		(36,997	)		2,143			(34,854	)
Prepaid Expenses		(30,933	)		-			(30,933	)
Net cash flows from discontinued operations		-			129,811			129,811
Net cash (used) provided by operating activities		228,941			(304,000	)		(75,059	)

Cash Flows From Investing Activities
Capitalized Investment in Proved Leaseholds		(156,926	)		30,662			(126,264	)
Purchase of Available for Sale Securities		(510,486	)		-			(510,486	)
Purchase of fixed assets		(427	)		-			(427	)
Net cash flows from discontinued operations		-			(30,662	)		(30,662	)
Net cash used by investing activities		(667,839	)		-			(667,839	)

Cash Flows From Financing Activities
Capital Contributions from Shareholders		-						-
Deferred financing costs		(103,110	)		-			(103,110	)
Debentures Payable		312,000			304,000			616,000
Net cash provided from financing activities		208,890			304,000			512,890

Net increase in cash		(230,008	)		-			(230,008	)
Cash, beginning of period		353,112			-			353,112
Cash, end of period	$	123,104			-		$	123,104

Supplemental disclosure of non-cash items:
Unrealized loss on available for sale securities		(325,465	)		-			(325,465	)

Income taxes paid in cash		-			-			-
Interest expense paid in cash	$	101,449			-		$	101,449

F-21

Cash flow worksheet for the year ended December 31, 2007

	Previously			Net
	Reported			Change			Restated
Cash Flows From Operating Activities
Net loss from continuing operations	$	-			(189,537	)	$	(189,537	)
Net income/(loss) from discontinued operations		-			35,757			35,757
Net loss		(153,780	)		-			(153,780	)

Adjustments to reconcile net loss to net cash
(used) provided by operating activities
Stock based consulting expense		76,500			-			76,500
Amortization of Loan & Debenture Costs		41,799			-			41,799
Depreciation, Depletion and Amortization		9,896			(3,535	)		6,361
Payables		(126,043	)		165,300			39,257
Accrued Interest		48,727			-			48,727
Receivables		(24,732	)		12,681			(12,051	)
Net cash flows from discontinued operations		-			(174,446	)		(174,446	)
Net cash (used) provided by operating activities		(127,633	)		-			(127,633	)

Cash Flows From Investing Activities
Capitalized Investment in Proved Leaseholds		(131,126	)		34,542			(96,584	)
Net cash flows from discontinued operations		-			(34,542	)		(34,542	)
Net cash used by investing activities		(131,126	)		-			(131,126	)

Cash Flows From Financing Activities
Capital Contributions from Shareholders		9,183			-			9,183
Deferred financing costs		(174,064	)		-			(174,064	)
Debentures Payable		562,000			-			562,000
Net cash provided from financing activities		397,119			-			397,119
					-
Net increase in cash		138,360			-			138,360
Cash, beginning of period		214,752			-			214,752
Cash, end of period	$	353,112			-		$	353,112

Supplemental disclosure of non-cash items:

Income taxes paid in cash		-			-			-
Interest expense paid in cash	$	30,952			-		$	30,952

Note 15 – Subsequent Events / Discontinued Operations

On August 12, 2009, the Company sold its interest in the Aldwell Unit to the operator of the unit, Mariner Energy Inc., for $300,000. Southfield divested the asset through an intermediary that charged the company 6% of the sales price to list the property, find qualified buyers and execute the sale. The effective date of the sale is September 1, 2009. The carrying amount of the Aldwell Unit at the time of the sale was $239,566 less DDA of $132, 699. The realized gain on the sale was $193,134. Commissions and fees of $18,389 were paid related to the sale. The major assets of the Aldwell Unit as of December 31, 2007 and 2008 were accounts receivable and proved properties. The balances for accounts receivable as of December 31, 2007 and 2008 were $8,518 and $10,658, respectively. The balances for net proved properties as of December 31, 2007 and 2008 were $190,159 and $104,228, respectively. The major liabilities of the disposal group consisted of accounts payable with a balance of $10,873 and $15,505 as of December 31, 2007 and 2008, respectively. Prior to the sale, the Aldwell Unit had revenues of $59,382 and $85,175 for the years ended December 31, 2007 and 2008. Net income related to the Aldwell unit was $35,757 for the year ended December 31, 2007. Net loss for the year ended December 31, 2008 from the Aldwell Unit was $57,700.

F-22

SOUTHFIELD ENERGY CORPORATION

STATEMENTS OF OPERATIONS

For the three and nine months ended

September 30, 2009 and September 30, 2008

	Three Months			Three Months			Nine Months			Nine Months
	Ended			Ended			Ended			Ended
	9/30/2009			9/30/2008			9/30/2009			9/30/2008
	(unaudited)			(unaudited)			(unaudited)			(unaudited)
REVENUES:

Oil and Gas Production	$	15,511		$	113,713		$	47,361		$	256,607
Cost of Sales		7,919			24,196			62,482			24,314
GROSS MARGIN / (DEFICIT)		7,592			89,517			(15,121	)		232,293

EXPENSES:
Amortization of Loan and Debenture Costs		38,919			38,243			105,753			79,970
Unsuccessful Exploratory Wells		-			-			-			-
General and Administrative Expenses		120,201			86,884			347,887			172,034
TOTAL OPERATING EXPENSES		159,120			125,127			453,640			252,004

OPERATING INCOME (LOSS)		(151,528	)		(35,610	)		(468,761	)		(19,711	)

Other Income (Expense)
Interest Income		18			1,476			119			3,623
Gain (Loss) on Sale of Securities		-			13,921			(134,096	)		13,921
Permanent Impairment of Securities		(243,095	)		-			(243,095	)		-
Interest Expense		(48,844			(44,547	)		(138,170	)		(89,882	)
Total Other Income (Expenses)		(291,921			(29,150	)		(515,242	)		(72,338	)

Net Loss before Discontinued Operations		(443,449	)		(64,760	)		(984,003	)		(92,049	)
Gain from Discontinued Operations		169,097			15,799			165,078			21,238

Net Loss	$	(274,352	)	$	(48,961	)	$	(818,925	)	$	(70,811	)

Other Comprehensive Income:
Unrealized gain on available for sale securities		-			3,563			-			3,563
Total Comprehensive Income/(Loss)		-			(45,398	)		-			(67,248	)

Net loss per common share from continuing operations
(Basic and Diluted)	$	(0.06	)	$	(0.01	)	$	(0.13	)	$	(0.01	)

Net Income per common share from discontinued
operations (Basic and Diluted)	$	0.02		$	-		$	0.02		$	-

Total Net Loss per common share (Basic and Diluted)	$	(0.04	)	$	(0.01	)	$	(0.11	)	$	(0.01	)

Weighted average common shares outstanding		7,410,000			7,360,000			7,410,000			7,360,000

*See accompanying notes to the financial statements.

F-23

SOUTHFIELD ENERGY CORPORATION

BALANCE SHEETS

As of September 30, 2009, and

As of December 31, 2008

	September			December
	30, 2009			31, 2008
	(unaudited)
ASSETS
Current Assets:
Cash	$	272,546		$	123,104
Accounts Receivable		18,500			59,726
Accounts Receivable - Related Party		2,000			2,000
Prepaid Expenses		-			30,933
TOTAL CURRENT ASSETS		293,046			215,763

Property & Equipment:
Oil & Gas, on the basis of successful efforts accounting
Gross Proved Properties		356,035			232,271
Less: Accumulated Depletion and Depreciation		(92,860	)		(76,364	)
Net Proved Properties		263,175			155,907

Office Equipment		427			427

Other Long Term Assets:
Gross Capitalized Loan and Debenture Costs		438,513			370,353
Less: Accumulated Amortization		(271,543	)		(148,739	)
Net Capitalized Loan and Debenture Costs		166,970			221,614

Available for Sale Securities		102,500			524,965
Less: Valuation Allowance		-			(325,465	)
Net (market value)		102,500			199,500

Long term assets discontinued operations		-			104,228

TOTAL ASSETS	$	826,118		$	897,439

LIABILITIES AND STOCKHOLDERS' DEFECIT

LIABILITIES:
Current Liabilities:
Accounts Payable	$	24,235		$	27,449
Accrued interest on Debentures		182,340			108,987
Current portion of Debentures Payable		164,000			304,000
TOTAL CURRENT LIABILITIES		370,575			440,436

Long Term Liabilities:
Convertible Debentures Payable		1,670,000			1,178,000
TOTAL LONG TERM LIABILITIES		1,670,000			1,178,000

TOTAL LIABILITIES		2,040,575			1,618,436

STOCKHOLDERS' DEFICIT:
Common stock, $0.001 par value; 50,000,000 shares
authorized, 7,410,000 issued and
outstanding at 9/30/09 and 12/31/08, respectively		7,410			7,410
Additional Paid-in Capital		99,373			99,373
Deficit accumulated during the development stage		(24,718	)		(24,718	)
Accumulated deficit		(1,296,522	)		(477,597	)
Accumulated other comprehensive income (loss)		-			(325,465	)

TOTAL STOCKHOLDERS' DEFICIT		(1,214,457	)		(720,997	)

TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$	826,118		$	897,439

*See accompanying notes to the financial statements.

F-24

SOUTHFIELD ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

For the nine months ended September 30, 2009, and September 30, 2008

	Nine Months			Nine Months
	Ended			Ended
	9/30/2009			9/30/2008
	(unaudited)			(unaudited)
Cash Flows From Operating Activities
Net loss from operations	$	(984,003	)	$	(92,049	)
Net gain from discontinued operations	$	165,078		$	21,238
Net Loss	$	(818,925	)	$	(70,811	)

Adjustments to reconcile net loss to net cash (used) provided
by operating activities
Impairment of AFS - Securities		243,095			-
Loss on sale of AFS - Securities		134,096			-
Gain on sale of AFS - Securities		-			(13,921	)
Amortization of Loan & Debenture Costs		105,753			79,970
Depreciation, Depletion and Amortization		24,834			26,740
Changes in operating assets and liabilities:
Payables		(26,598	)		2,833
Accrued expenses		96,738			40,788
Receivables		41,226			(97,591	)
Prepaid Expenses		30,933			-
Cash flows from discontinued operations		(185,326	)		(308,953	)

Net cash used by operating activities		(354,174	)		(340,945	)

Cash Flows From Investing Activities
Capitalized Investment in Proved Leaseholds		(133,147	)		(50,286	)
Sale of AFS - Securities		45,273			-
Purchase of fixed assets		-			(427	)
Purchase of AFS - Securities		-			(302,297	)
Cash flows from discontinued operations		290,599			(31,000	)

Net cash provided / (used) by investing activities		202,725			(384,010	)

Cash Flows From Financing Activities
Deferred financing costs		(51,109	)		(96,017	)
Debentures Payable		352,000			590,000
Net cash provided from financing activities		300,891			493,983

Net increase (decrease) in cash		149,442			(230,972	)
Cash, beginning of period		123,104			353,112
Cash, end of period	$	272,546		$	122,140

Supplemental disclosure of non-cash items:
Unrealized gain on available for sale securities prior to impairment		-			3,563

Income taxes paid in cash	$	-		$	-
Interest expense paid in cash		-			-

*See accompanying notes to the financial statements.

F-25

SOUTHFIELD ENERGY CORPORATION

STATEMENT OF CHANGES IN STOCKHOLDERS' DEFICIT

For the nine months ended September 30, 2009

(unaudited)

							Deficit
							Accumulated						Accumulated
					Additional		During						Other
	Common Stock				Paid-in		Development			Accumulated			Comprehensive
	Shares		Amount		Capital		Stage			Deficit			Income			Total

Balance, December 31, 2008		7,410,000	$	7,410	$	99,373	$	(24,718	)	$	(477,597	)	$	(325,465	)	$	(720,997	)

Sale of Available for sale securities		-		-		-		-			-			134,096			134,096

Impairment of Available for Sale Securities		-		-		-		-			-			191,369			191,369

Net Loss		-		-		-		-			(818,925	)		-			(818,925	)

Balance, September 30, 2009		7,410,000	$	7,410	$	99,373	$	(24,718	)	$	(1,296,522	)	$	-		$	(1,214,457	)

*See accompanying notes to financial statements

F-26

NOTE 1 – Nature of Operations

SOUTHFIELD ENERGY CORPORATION (the "Company" or “Southfield”), is an oil and gas investment company. It invests in the exploration, development, and production of oil & gas in the United States. The focus of its activity is in Texas, Louisiana, Oklahoma, Colorado and the Gulf of Mexico. The Company intends to invest its funds primarily as a working interest owner, royalty interest owner or mineral lease owner. Generally, the Company will be a minority owner in each well. The Company expects most of its investments to range from 5-25% of the total investment required for any given project, and anticipates that its investment in each project will range from $50,000 to $250,000.

NOTE 2 – Basis of Presentation

The accompanying unaudited financial statements have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission, and U.S. GAAP. The information furnished in the interim financial statements includes normal recurring adjustments and reflects all adjustments which, in the opinion of management, are necessary for a fair presentation of such financial statements.

The Company does not expect the adoption of recently issued accounting pronouncements to have a significant impact on its results of operation, financial position or cash flow.

Although management believes the disclosures and information presented are adequate to not make the information misleading, it is suggested that these interim financial statements be read in conjunction with the Company's most recent audited financial statements and notes thereto included in its December 31, 2008 Annual Report in the S-1 registration statement. Operating results for the nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the entire year or any other period.

NOTE 3 – Going Concern

NOTE 4 - Summary of Significant Accounting Policies

Capitalization Policies: Oil and gas property acquisition costs, exploration well costs, and development costs are capitalized as incurred. Net capitalized costs of unproved property and exploration well costs are reclassified as proved property and well costs when related proved reserves are found. If an exploration well is unsuccessful in finding proved reserves, the capitalized well costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs and the costs of carrying unproved property are charged to exploration expense as incurred. Costs to operate and maintain wells and field equipment are expensed as incurred.

Sales and retirement Policies: Gains and losses on the sale or abandonment of oil and gas properties are generally reflected in income. Costs of retired equipment, net of salvage value, are usually charged to accumulated amortization. Unusual retirements are reflected in income. As of September 30, 2009, management has determined that the asset retirement obligation related to the plugging and abandonment of wells is immaterial individually and to the financial statements taken as a whole. As such, no asset retirement obligation is recorded in the statements presented. Management will review the potential obligation on an on-going basis and will record the obligation in the period it becomes material, either individually or in aggregate, to the financial statements.

F-27

EARNINGS PER SHARE – Southfield’s net income/loss per share has been calculated by dividing the net income/ loss for the period by the weighted average number of shares outstanding. There are no potentially dilutive securities outstanding; therefore basic loss per share equals the fully diluted loss per share. Earnings per share from discontinued operations for the three months ended September 30, 2008 and September 30, 2009 respectively are ($0.00) and $0.02; earnings per share from continuing operations for the three months ended September 30, 2008 and September 30, 2009 respectively are ($0.01) and ($0.06). Earnings per share from discontinued operations for the nine months ended September 30, 2008 and September 30, 2009 respectively are ($0.00) and $0.02; earning per share from continuing operations for the nine months ended September 30, 2008 and September 30, 2009 respectively are ($0.01) and ($0.13).

STOCK BASED COMPENSATION – On January 1, 2006, the Company adopted the FASB standard which requires the measurement and recognition of compensation expense for all share-based awards made to employees and directors, including employee stock options and shares issued through its employee stock purchase plan, based on estimated fair values. In March 2005, the Securities and Exchange Commission issued a bulletin related to the aforementioned FASB standard. The Company has applied the provisions of the SEC bulletin in its adoption of the FASB standard. The Company adopted the standard using the modified prospective transition method, which requires the application of the accounting standard beginning in 2006. The Company’s financial statements as of and for the years ended December 31, 2008 and nine months ended September 30, 2009 reflect the impact of this standard. In accordance with the modified prospective transition method, the Company’s financial statements for prior periods do not include the impact of the standard.

We adopted the Financial Accounting Standards Board’s (FASB) standard on fair value measurements at inception. The standard defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. The standard applies under other accounting pronouncements that require or permit fair value measurements and accordingly, does not require any new fair value measurements. It clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, the standard established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows.

¨	Level 1. Observable inputs such as quoted prices in active markets;

¨	Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

¨	Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

The following table presents assets that are measured and recognized at fair value as of September 30, 2009 and for the nine months then ended on a recurring basis :

							Total			Total
							Realized (Loss			Unrealized
Description	Level 1		Level 2		Level 3		due to valuation)			(Loss)
Available for Sale Securities		102,500		-		-		(234,095	)		-
Totals	$	102,500	$	-	$	-	$	(234,095	)	$	-

F-28

The following table presents assets that are measured and recognized at fair value as of September 30, 2009 and for the nine months then ended on a non-recurring basis :

							Total		Total
							Realized (Loss		Unrealized
Description	Level 1		Level 2		Level 3		due to valuation)		(Loss)
Proved Properties (net)		-		-		263,175		-		-
Totals	$	-	$	-	$	263,175	$	-	$	-

REVENUE RECOGNITION – Southfield recognizes oil, gas and natural gas condensate revenue in the period of delivery. Settlement for oil sales occurs 30 days after the oil has been sold; and settlement for gas sales occurs 60 days after the gas has been sold. Southfield recognizes revenue when an arrangement exists, the product or service has been provided, the sales price is fixed or determinable, and collectability is reasonably assured.

CASH AND CASH EQUIVALENTS – Southfield considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents at December 31, 2008 and September 30, 2009 were $123,104 and 275,546, respectively.

INVESTMENTS – We account for securities available for sale in accordance with Financial Accounting Standards Board (“FASB”) guidance regarding accounting for certain investments in debt and equity securities, which requires that available-for-sale and trading securities be carried at fair value. Unrealized gains and losses deemed to be temporary on available-for-sale securities are reported as other comprehensive income (“OCI”) within shareholders’ investment. Realized gains and losses and decline in value deemed to be other than temporary on available-for-sale securities are included in “(Gain) loss on short- and long-term investments” and “Other income” on our consolidated statements of operations. Trading gains and losses also are included in “(Gain) loss on short- and long-term investments.” Fair value of the securities is based upon quoted market prices in active markets or estimated fair value when quoted market prices are not available. The cost basis for realized gains and losses on available-for-sale securities is determined on a specific identification basis. We classify our securities available-for-sale as short- or long-term based upon management’s intent and ability to hold these investments. In addition, throughout 2009, the FASB issued various authoritative guidance and enhanced disclosures regarding fair value measurements and impairments of securities which helps in determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly.

Recent Accounting Pronouncements

On January 1, 2009, the FASB issued a new accounting standard related to the disclosure of derivative instruments and hedging activities. This standard expanded the disclosure requirements about an entity’s derivative financial instruments and hedging activities including qualitative disclosures about objectives and strategies for issuing derivatives, quantitative disclosures about fair value amounts of any gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative instruments. Southfield had no instruments that fell within the scope of this pronouncement as of September 30, 2009.

F-29

Effective January 1, 2009, a new accounting standard was issued related to determining whether an instrument (or an embedded feature) is indexed to an entity’s own stock, which would qualify as a scope exception from hedge accounting. Southfield had no instruments that fell within the scope of this pronouncement as of September 30, 2009.

In August 2009, the FASB issued an amendment to the accounting standards related to the measurement of liabilities that are recognized or disclosed at fair value on a recurring basis. This standard clarifies how a company should measure the fair value of liabilities and that restrictions preventing the transfer of a liability should not be considered as a factor in the measurement of liabilities within the scope of this standard. This standard is effective on October 1, 2009. Southfield had no instruments that fall within the scope of this pronouncement as of September 30, 2009.

In October 2009, the FASB issued an amendment to the accounting standards related to the accounting for revenue in arrangements with multiple deliverables including how the arrangement consideration is allocated among delivered and undelivered items of the arrangement. Among the amendments, this standard eliminates the use of the residual method for allocating arrangement consideration and requires an entity to allocate the overall consideration to each deliverable based on an estimated selling price of each individual deliverable in the arrangement in the absence of having vendor-specific objective evidence or other third party evidence of fair value of the undelivered items. This standard also provides further guidance on how to determine a separate unit of accounting in a multiple-deliverable revenue arrangement and expands the disclosure requirements about the judgments made in applying the estimated selling price method and how those judgments affect the timing or amount of revenue recognition. This standard, which Southfield is currently assessing the impact of, will become effective for the Company on January 1, 2011.

In October 2009, the FASB issued an amendment to the accounting standards related to certain revenue arrangements that include software elements. This standard clarifies the existing accounting guidance such that tangible products that contain both software and non-software components that function together to deliver the product’s essential functionality, shall be excluded from the scope of the software revenue recognition accounting standards. Accordingly, sales of these products may fall within the scope of other revenue recognition accounting standards or may now be within the scope of this standard and may require an allocation of the arrangement consideration for each element of the arrangement. This standard, which Southfield is currently assessing the impact of, will become effective for the Company on January 1, 2011.

NOTE 5 - Related Party Transactions

In the first half of 2008, Southfield used 50% of its office space 100% of the time and paid roughly $1,500 per month. For the second half of 2008, Southfield used 100% of the office space 100% of the time and therefore paid the entire rent of roughly $3,100 per month. The company that manages the administration of the office rent granted a waiver for the rent due in the month of August and, therefore Southfield did not pay rent for the month of August. The total rent expense for 2008 was $24,483. The total rent expense for the nine months ended September 30, 2009 was $27,549.

NOTE 6 – Convertible Debentures Payable

We have retained the services of MMR Investment Bankers, Inc. to represent the Company in a $10 million private placement of Debentures under Reg. D, 506. We also engaged Sunflower Management Group, a third party administrator for interest payments and technical compliance with the repayment requirements of the Debentures that have been sold.

MMR Investment Bankers, Inc. has created an account to reserve from the gross offering proceeds the first six months of interest payments due to any investor. Sunflower Management Group is managing the interest reserve account and is responsible for accruing and funding interest to investors as it becomes due. As of December 31, 2008 and September 30, 2009, the Company has issued $1,482,000 and $1,834,000 of three-year convertible Debentures to investors, respectively. The Debentures bear interest at a rate of 10% and mature three years from the date of purchase.

The investors may elect to have simple interest paid on a monthly basis, or may have the interest compounded semiannually and paid at maturity. The investors may convert the face value of the Debenture to common stock in the Company at any time during the term of the Debenture at a conversion price of $5.00 per share.

The Company reviewed accounting literature related to embedded derivatives and beneficial conversion features and its application to the Company’s convertible debentures. The Company concluded that there is not a derivative or beneficial conversion option associated with the debentures that is in-the-money and therefore the Company is not required to calculate the intrinsic value of such conversion option.

Maturities of the notes over the next five years ending September 30 are as follows:

2010			2011				2012				2013				2014
$	164,000		$	577,000			$	650,000			$	305,000			$	138,000

NOTE 7 – Acquisitions & Capital Investments

F-30

In 2009, the Company successfully drilled the C-34 and C-35 wells located on the Mary King Estell Lease and invested approximately $71,231 and $61,916, respectively. The remainder of the capital investment in proved leaseholds was in the Aldwell Unit for roughly $7,057. This capital investment was used to drill and complete new wells and to recomplete existing production wells to enhance production in the field.

Note 8 – Available for Sale Securities

In 2008 the Company invested approximately $510,000 in the common stock of Meridian Resources, a publicly traded exploration and production company on the New York Stock Exchange listed under the symbol TMR. During the nine months ended September 30, 2008 the company had an unrealized gain of $3,563 related to this investment. As of December 31, 2008 the value of the stock declined significantly consistent with the overall stock market at that time. As of September 30, 2009, the Company determined the decline in the value of the stock to be other than temporary according to the applicable SEC Staff Accounting Bulletin. Due to this determination, the difference between the cost of the securities and the market value was recorded as a loss on the income statement for the nine months ended September 30, 2009, rather than in other comprehensive income. The impairment expense was $243,095 for the nine months ended September 30, 2009.

Note 9 – Discontinued Operations

NOTE 10 – Non-cash Compensation

A consultant was issued 50,000 shares on December 10, 2008 for providing services to the Company. The equity that was issued in 2008 was valued by the Company at $0.10 per share based upon management’s discounted cash flow analysis. There have been no additional issuances of equity for the nine months ended September 30, 2009.

NOTE 11 – Depletion and Depreciation

For the nine months ended September 30, 2008 and September 30, 2009, the Company incurred depreciation, depletion and amortization on its remaining proved producing property, the Mary King Estell Lease, of $10,078 and $24,834, respectively. Depreciation, depletion and amortization have been calculated using the units of production method.

NOTE 12 – Capitalized Expenses

The Company is capitalizing expenses related to the Debenture Offering and amortizing them over the three year life of the Debentures according to the effective interest method. The gross capitalized loan and debenture costs were $370,353 and $438,513 as of December 31, 2008 and September 30, 2009, respectively. The accumulated amortization was $148,739 and $271,543; and the net capitalized loan and debenture costs were $221,614 and $166,970 for the same periods respectively.

NOTE 13 – Impairment of Proved Properties

The assets were subsequently impaired by taking the difference between the discounted future net cash flow, using a 10% discount rate, which was estimated by Huddleston and Company and the carrying value of the assets on our Balance Sheet. Management found the difference to be $116,553 and impaired the Aldwell Unit by that amount. The remaining unimpaired balance of the property has been included in discontinued operations on the balance sheet as of December 31, 2008 due to the disposal of the property in September of 2009. There were no impairment indicators and therefore no impairment on oil and gas producing properties during the nine months ended September 30, 2009.

F-31

NOTE 14 – Commitments and Contingencies

Litigation

Concentrations

The Company’s sales are dependent upon the performance of its producing wells and our ability to successfully partner with high quality oil and gas operators; any impacts to this industry could have a significant impact to the Company. For the year ended December 31, 2008, two leases represented 100% of the total revenues of the company and 100% of the accounts receivable. After September 1, 2009 100% of the company’s revenues were derived from the Mary King Estell lease. The Company generally does not require collateral to support accounts receivable or financial instruments subject to credit risk.

NOTE 15 – Oil and Gas Properties

The Company owns non-operated working interests in the Mary King Estell Lease which is operated by Durango Resources. As of December 31, 2008 the company owned an interest in approximately 200 wells, and as of September 30, 2009 the company owned an interest in five wells. According to the reserve report prepared by Huddleston and Company, the Company’s estimate of future income taxes, as of December 31, 2008 the Company had proved reserves with estimated discounted net cash flows after taxes of $565,092 from the Mary King Estell Unit. Estimated future net cash flows of the properties were discounted at 10% consistent with FAS 69. A reserve analysis has not been conducted for the nine months ended September 30, 2009.

NOTE 16 – Correction of Errors

The Company intends to restate its previously issued September 30, 2009 financial statements for matters related to the following previously reported items: 1. The Company originally reported “Unscuccessful Exploratory Wells” expense in operating expenses below gross margin in the Statements of Operations for the nine month period ending September 30, 2009. 2. The Company did not show the total loss per share on the Statements of Operations. This was added to the amended financial statements. The aforementioned errors required no accounting entries to adjust any balances. The errors were all related exclusively to presentation on the financial statements. The quantitative differences as a result of these changes are shown on the following page.

Statement of Operations for the nine month period ended September 30, 2009:

	Previously			Net
	Reported			Change			Restated
REVENUES:

Oil and Gas Production	$	47,361			-		$	47,361
Cost of Sales		31,549			30,933			62,482
GROSS MARGIN / (DEFICIT)		15,812			(30,933	)		(15,121	)

EXPENSES:
Amortization of Loan and Debenture Costs		105,753			-			105,753
Unsuccessful Exploratory Wells		30,933			(30,933	)		-
General and Administrative Expenses		347,887			-			347,887
TOTAL OPERATING EXPENSES		484,573			(30,933	)		453,640

OPERATING INCOME (LOSS)		(468,761	)		-			(468,761	)

Other Income (Expense)
Interest Income		119			-			119
Gain (Loss) on Sale of Securities		(134,096	)		-			(134,096	)
Permanent Impairment of Securities		(243,095	)		-			(243,095	)
Interest Expense		(138,170	)		-			(138,170	)
Total Other Income (Expenses)		(515,242	)		-			(515,242	)

Net Loss before Discontinued Operations		(984,003	)		-			(984,003	)
Gain from Discontinued Operations		165,078			-			165,078

Net Loss	$	(818,925	)		-		$	(818,925	)

Other Comprehensive Income:
Unrealized gain on available for sale securities		-			-			-
Total Comprehensive Income/(Loss)		-			-			-

Net loss per common share from continuing operations
(Basic and Diluted)	$	(0.13	)		-		$	(0.13	)

Net Income per common share from discontinued
operations (Basic and Diluted)	$	0.02			-		$	0.02

Total Net Loss per common share (Basic and Diluted)	$	-			(0.11	)	$	(0.11	)

Weighted average common shares outstanding		7,410,000			-			7,410,000

NOTE 17 – Subsequent Events

In 2008, the company made a $2,000 loan to one of our officers. This loan was repaid on November 3, 2009.

After September 30, 2009, $351,000 of convertible debentures due on or prior to September 30, 2010 were extended for a period of two years. An additional $867,000 of convertible debentures due after September 30, 2010 were extended for a period of two years. The financial statements and footnotes have been presented according to the extended maturity dates.

On January 4, 2010, we sold our remaining 250,000 shares of common stock in Meridian Resources Corporation and realized an approximate loss of $280,000 based on an average cost basis. We no longer have an equity investment in Meridian Resources or any other corporation.

The Company evaluated all subsequent events through the filing date of January 28, 2010.

F-32

Southfield Energy Corporation

$10,000,000 Three Year Notes

Prospectus

[.], 2010

Until [●], 2010 (25 days after the commencement of the Offering), all dealers that effect transactions in the 3 Year Notes, whether or not participating in this Offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

The following table sets forth an estimate of the costs and expenses, other than the underwriting discounts and commissions, payable by the registrant in connection with the issuance and distribution of the 3 Year Notes being registered.

SEC registration fee	$	558
Legal fees and expenses		55,498
Accounting fees and expenses		37,689
Engineer fees and expenses		16,681
Printing and engraving expenses		*6,802

Total	$	117,228

* The Company incurred $4,302 of printing fees before filing this Amendment, and estimates an additional $2,500 of printing fees through the date of this filing.

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Our officers and directors are indemnified as provided by the Nevada Revised Statutes and by our bylaws.

Under the Nevada Revised Statutes, director immunity from liability to a company or its stockholders for monetary liabilities applies automatically unless it is specifically limited by a company’s Articles of Incorporation. Our Articles of Incorporation do not specifically limit our directors’ immunity. Excepted from that immunity are: (a) a willful failure to deal fairly with the company or its stockholders in connection with a matter in which the director has a material conflict of interest; (b) a violation of criminal law, unless the director had reasonable cause to believe that his or her conduct was lawful or no reasonable cause to believe that his or her conduct was unlawful; (c) a transaction from which the director derived an improper personal profit; and (d) willful misconduct.

Our bylaws provide that we will indemnify our directors and officers as follows: (a) Every director or officer of the Company shall be indemnified by the Company to the full extent allowed by law against all expenses and liabilities in connection with any threatened, pending or completed action, suit or proceeding, to which he may be made a party, or in which he may become involved, by reason of his being or having been a director or officer of the Company or any settlement thereof, whether or not he is a director or officer at the time such expenses are incurred, except in such cases wherein the director or officer is adjudged guilty of willful misfeasance or malfeasance in the performance of his duties; provided that in the event of a settlement the indemnification herein shall apply only when the board of directors approves such settlement and reimbursement as being for the best interests of the Company; (b) The Company shall provide to any person who is or was a director or officer of the Company or is or was serving at the request of the Company as a director or officer of the corporation, partnership, joint venture, trust or enterprise, the indemnity against expenses of suit, litigation or other proceedings which is specifically permissible under applicable law; (c) The board of directors may, in its discretion, direct the purchase of liability insurance.

The Company has purchased director and officer liability insurance for its officers and directors.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

In the three years preceding the filing of this registration statement, we have issued and sold the following securities that were not registered under the Securities Act.

On July 5, 2005, our date of incorporation, we sold an aggregate of 6.2 million shares of our common stock to our four founders: Ben Roberts, Chet Gutowsky, Tyson Rohde and The Internet Business Factory, Inc. Each of Messrs. Gutowsky and Rohde and The Internet Business Factory purchased 2,000,000 shares, and Mr. Roberts purchased 200,000 shares. Such shares were sold to the founders at $0.001 per share for a total consideration of $6,200. Each of the four founders issued promissory notes to us in the aggregate principal amount of $6,200 which they paid on August 14, 2006. The issuance of these shares of common stock to our founders was exempt from the registration requirements of the Securities Act under Reg. D and Section 4(2) of the Securities Act due to the fact that it did not involve a public offering of securities. These issuances were made to accredited investors.

On August 14, 2006 The Internet Business Factory, one of our founders, loaned to us $20,000 evidenced by a promissory note bearing interest at an annual rate of 6%. As partial consideration for the promissory note, we agreed to issue The Internet Business Factory an additional 300,000 shares of common stock. The issuance of these shares of common stock to The Internet Business Factory was exempt from the registration requirements of the Securities Act under Reg. D and Section 4(2) of the Securities Act due to the fact that it did not involve a public offering. This issuance was made to an accredited investor.

On October 19, 2006 we issued 50,000 shares of common stock to a consultant for the development and review of oil and gas prospects. On December 10, 2008, we issued 50,000 shares of our common stock to the same consultant for providing business development services to the Company. The issuance of these shares of common stock to this consultant was exempt from the registration requirements of the Securities Act under Reg. D and Section 4(2) of the Securities Act due to the fact that it did not involve a public offering. These issuances were made to accredited investors.

On December 31, 2006 we issued 45,000 shares of common stock to a consultant for financial management services. On June 15, 2007, we issued 705,000 shares of common stock to the same consultant for additional financial management services. The issuance of these shares of common stock to this consultant was exempt from the registration requirements of the Securities Act under Reg. D and Section 4(2) of the Securities Act due to the fact that it did not involve a public offering. The owner of the financial management company is an accredited investor.

On February 22, 2007, we issued 50,000 shares of common stock to a consultant for engineering services related to prospect evaluation. The issuance of these shares of common stock to this consultant was exempt from the registration requirements of the Securities Act under Reg. D and Section 4(2) of the Securities Act due to the fact that it did not involve a public offering. This issuance was made to an accredited investor.

On October 12, 2007 we issued 10,000 shares of common stock to a consultant for designing and implementing our website and providing information technology services. The issuance of these shares of common stock to this consultant was exempt from the registration requirements of the Securities Act under Reg. D and Section 4(2) of the Securities Act due to the fact that it did not involve a public offering. This issuance was made to an unaccredited investor with access to information about the company.

The shares of common stock that were issued to the aforementioned consultants were valued by us at $0.10 per share based upon management’s discounted cash flow analysis.

As of December 31, 2008 and 2007, the Company had issued $866,000 and $1,482,000, respectively, of three-year 10% convertible debentures to investors. The investors may elect to have simple interest paid on a monthly basis, or may have the interest compounded semiannually and paid at maturity. The investors may convert the face value of the debenture to shares of common stock in the Company at any time during the term of the debenture at a conversion price of $5.00 per share. The Company has the right to call for the conversion of the debentures when the common stock of the company trades on a public market for 20 consecutive days at a price higher than $7.50 per share and upon notice, unless the debenture holder elects not to accept the conversion offer.

MMR Investment Bankers, Inc. served as placement agent for these debentures offerings and received a placement fee of eight percent of the gross proceeds raised and a non-accountable expense allowance of three percent of the gross proceeds. The issuance of the three-year 10% convertible debentures to the aforementioned investors was exempt from the registration requirements of the Securities Act under Reg. D, 506 and Section 4(2) of the Securities Act due to the fact that it did not involve a public offering. The Company has made periodic filings of Form D that detail the classification of investors subscribed to the private placement of Debentures. The Company used the net proceeds from these debenture offerings to make oil and gas investments, and fund the general operations of our business including general and administrative and offering expenses.

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	The following exhibits are filed on behalf of the registrant as part of this Registration Statement:

Exhibit Number		Description

3.1		Articles of Incorporation of Southfield Energy Corporation (1)
3.2		Bylaws of Southfield Energy Corporation (1)
4.1		Southfield Trust Indenture (1)
4.2		Book Entry Specimen Three Year 10% Note (1)
5.1*		Legal Opinion of Jack Chapline Vaughan, Attorney at Law
10.1		Mary King Estell Lease Assignment (1)
10.2		Durango Letter Agreement (1)
10.3		B D Production Co., Inc. Letter Agreement (1)
10.4		Aldwell Unit Purchase Letter Agreement and Assignment (1)
10.5		Listing Agreement with Oil & Gas Asset Clearinghouse and Assignment (1)
10.6*		Form of Subscription Agreement
23.1*		Consent of M&K CPAS, PLLC
23.2*		Consent of Huddleston & Co., Inc.
23.3*		Consent of of Jack Chapline Vaughan, Attorney at Law (included in Exhibit 5.1)

*	Filed herewith.

(1)	Incorporated by reference to the comparable exhibit filed with the Company’s Registration Statement on Form S-1 (File No. 333-162029).

(b)	Financial Statement Schedules:

All financial statement schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are either included in the financial information set forth in the prospectus or are inapplicable and therefore have been omitted.

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;

(ii)

To reflect in the prospectus any facts or events which, individually or together, represent a fundamental change in the information 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 twenty percent (20%) change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

(iii)

To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2)	For determining liability under the Securities Act, to treat each post-effective amendment as a new registration statement of the securities offered, and the offering of the securities at that time to be the initial bona fide offering thereof.

(3)	To file a post-effective amendment to remove from registration any of the securities that remain unsold at the end of the offering.

(4)

For determining liability of the undersigned issuer under the Securities Act to any investor in the initial distribution of the securities, the undersigned issuer undertakes that in a primary offering of securities of the undersigned issuer pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the investor, if the securities are offered or sold to such investor by means of any of the following communication, the undersigned issuer will be a seller to the investor and will be considered to offer or sell such securities to such investor:

(i)

Any preliminary prospectus or prospectus of the undersigned issuer 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 issuer or used or referred to by the undersigned issuer;

(iii)

The portion of any other free writing prospectus relating to the offering containing material information about the undersigned issuer or its securities provided by or on behalf of the undersigned issuer; and

(iv)

Any other communication that is an offer in the offering made by the undersigned issuer to the Investor.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling the registrant pursuant to the foregoing provisions, the registrant has been informed that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

In the event that a claim for indemnification against such liabilities (other than the payment by the issuer of expenses incurred or paid by a director, officer or controlling person of the issuer 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 issuer will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

That for the purpose of determining any liability under the Securities Act to any Investor:

(i)

Each prospectus filed by the undersigned issuer pursuant to Rule 424(b)(3) shall be deemed to be part of the registration statement as of the date the filed prospectus was deemed part of and included in the registration statement; and

(ii)

Each prospectus required to be filed pursuant to Rule 424(b)(2), (b)(5), or (b)(7) as part of a registration statement in reliance on Rule 430B relating to an offering made pursuant to Rule 415(a)(1)(i), (vii), or (x) for the purpose of providing the information required by section 10(a) of the Securities Act shall be deemed to be part of and included in the registration statement as of the earlier of the date such form of prospectus is first used after effectiveness or the date of the first contract of sale of securities in the offering described in the prospectus. As provided in Rule 430B, for liability purposes of the issuer and any person that is at that date an underwriter, such date shall be deemed to be a new effective date of the registration statement relating to the securities in the registration statement to which that prospectus relates, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement will, as to a Investor with a time of contract of sale prior to such effective date, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such effective date.

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Houston, State of Texas, on January 28, 2010.

SOUTHFIELD ENERGY CORPORATION

By:	/s/ Ben Roberts
	Ben Roberts
	Chief Executive Officer and Director

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Capacity	Date

/s/ Chet Gutowsky	Chief Financial Officer and Director	January 28, 2010

/s/ Tyson Rohde	Chief Operating Officer and Director	January 28, 2010

EXHIBIT INDEX

Exhibit Number		Description

3.1		Articles of Incorporation of Southfield Energy Corporation (1)
3.2		Bylaws of Southfield Energy Corporation (1)
4.1		Southfield Trust Indenture (1)
4.2		Book Entry Specimen Three Year 10% Note (1)
5.1*		Legal Opinion of Jack Chapline Vaughan, Attorney at Law
10.1		Mary King Estell Lease Assignment (1)
10.2		Durango Letter Agreement (1)
10.3		B D Production Co., Inc. Letter Agreement (1)
10.4		Aldwell Unit Purchase Letter Agreement and Assignment (1)
10.5		Listing Agreement with Oil & Gas Asset Clearinghouse and Assignment (1)
10.6*		Form of Subscription Agreement
23.1*		Consent of M&K CPAS, PLLC
23.2*		Consent of Huddleston & Co., Inc.
23.3*		Consent of of Jack Chapline Vaughan, Attorney at Law (included in Exhibit 5.1)

*	Filed herewith.

(1)	Incorporated by reference to the comparable exhibit filed with the Company’s Registration Statement on Form S-1 (File No. 333-162029).

Southfield Energy CORP - FORM S-1/A - January 28, 2010

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