Southfield Energy 10-K 2009 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

þ ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

Commission file number 000-28015

SOUTHFIELD ENERGY CORPORATION

 (Name of Small Business Issuer in Its Charter)

NEVADA	20-5361270
(State or other jurisdiction of incorporation or organization)	(Employer Identification No.)

1240 Blalock Rd., Suite 150, Houston, TX 77055

(Address of principal executive offices, including zip code.)

(713) 266-3700

(Registrant's telephone number, including area code)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨   No þ

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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 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 þ
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ¨ No þ

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity. We have not listed our common equity for public quotation or trading, and therefore do not currently have a market derived valuation for our common equity.

State the number of shares outstanding of each of the registrant’s classes of common stock as of December 31, 2009: 7,410,000

Documents Incorporated by reference: None.

SOUTHFIELD ENERGY CORPORATION

FORM 10-K

For the Year Ended December 31, 2009

TABLE OF CONTENTS

	Page
PART 1 – Financial Information	3
Item 1.Business Factors	3
Item 1A.Risk Factors	6
Item 1B.Unresolved Staff Comments	16
Item 2.Properties	16
Item 3.Legal Proceedings	21
Item 4.Submission of Matters to a Vote of Security Holders	21
PART II -   Other Information	22
Item 5.Market for Common Equity and Related Stockholder Matters	22
Item 6.Selected Financial Data	23
Item 7.Management’s Discussion and Analysis and Plan of Operation	23
Item 7A.Quantitative and Qualitative Disclosures About Market Risk.	31
Item 8.Financial Statements and Supplemental Data	31
Item 9.Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	52
Item 9A.Controls and Procedures	52
Item 9B.     Other Information	53
PART III	54
Item 10.Directors, Executive Officers, Promoters and Control Persons and Corporate Governance; Compliance with Section 16(a) Of The Exchange Act	54
Item 11.Executive Compensation	58
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	60
Item 13.Certain Relationships and Related Transactions, and Director Independence	61
Item 14.Principal Accountant Fees and Services	62
Item 15.Exhibits, Financial Statement Schedules, Signatures	63
SIGNATURES	64

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PART 1 – Financial Information

Item 1.

Business Factors

Information Regarding Forward-Looking Statements

This report contains forward-looking statements that involve risks and uncertainties. We generally use words such as "believe," "may," "could," "will," "intend," "expect," "anticipate," "plan," and similar expressions to identify forward-looking statements. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in the forward-looking statements for many reasons, including the risks described below and elsewhere in this report. Although we believe the expectations reflected in the forward-looking statements are reasonable, they relate only to events as of the date on which the statements are made, and our future results, levels of activity, performance or achievements may not meet these expectations. We do not intend to update any of the forward-looking statements after the date of this document to conform these statements to actual results or to changes in our expectations, except as required by law.

History

Southfield Energy Corporation, (“Southfield”, “the Company”, “we”, or “us”) is 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 Business

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 disclosure.

Government Regulation 

Proposals and proceedings that might affect the oil and gas industry are periodically presented to Congress, the Federal Energy Regulatory Commission (“FERC”), the Minerals Management Service (“MMS”), state legislatures and commissions and the courts. We cannot predict when or whether any such proposals may become effective. The natural gas industry is heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we currently do not anticipate that compliance with existing federal, state and local laws, rules and regulations, will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

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Although we are not an operator of oil and gas properties, we are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing of wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used or generated in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas we can produce from our wells in a given state and may limit the number of wells or the locations at which we can drill.

Currently, there are no federal, state or local laws that regulate the price for our sales of natural gas, natural gas liquids, crude oil or condensate. However, the rates charged and terms and conditions for the movement of gas in interstate commerce through certain intrastate pipelines and production area hubs are subject to regulation under the Natural Gas Policy Act of 1978, as amended. Pipeline and hub construction activities are, to a limited extent, also subject to regulations under the Natural Gas Act of 1938, as amended. While these controls do not apply directly to us, their effect on natural gas markets can be significant in terms of competition and cost of transportation services, which in turn can have a substantial impact on our profitability and costs of doing business. Additional proposals and proceedings that might affect the natural gas and crude oil extraction industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective and their effect, if any, on our operations. We do not believe that we will be affected by any action taken in any materially different respect from other crude oil and natural gas producers, gatherers and marketers with whom we compete.

State regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements. This regulation has not generally been applied against producers and gatherers of natural gas and crude oil to the same extent as processors, although natural gas and crude oil gathering may receive greater regulatory scrutiny in the future.

Our oil and natural gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials (“NORM”) are subject to stringent environmental regulation. Compliance with environmental regulations is generally required as a condition to obtaining drilling permits. State inspectors frequently inspect regulated facilities and review records required to be maintained for document compliance. We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries, fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures.

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Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and natural gas exploration, development and production operations, and consequently may impact our operations and costs. These regulations include, among others, (i) regulations by the Environmental Protection Agency (“EPA”), and various state agencies regarding approved methods of disposal for certain hazardous and non-hazardous wastes; (ii) the Comprehensive Environmental Response, Compensation and Liability Act, and analogous state laws, which regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may require certain pollution controls with respect to air emissions from our operations; (iv) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; and (vi) state regulations and statutes governing the handling, treatment, storage and disposal of NORM.

In the course of our operators’ routine oil and natural gas operations, surface spills and leaks, including casing leaks of oil or other materials may occur, and we may incur our pro-rata costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM are present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Michigan and Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Despite our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributed to us under applicable state, federal or local laws or regulations.

We are in compliance with all currently applicable environmental laws and regulations. Since these laws and regulations are periodically amended, however, we are unable to predict the additional cost of compliance, if any. To our knowledge, there are currently no material adverse environmental conditions that exist on any of our properties and there are no current or threatened actions or claims by any local, state or federal agency, or by any private landowner against us pertaining to such a condition. Further, we are not aware of any currently existing condition or circumstance that may give rise to such actions or claims in the future.

Competition

We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties and oil and natural gas leases, marketing of oil and natural gas, and obtaining goods, services and labor. Most of our competitors have substantially larger financial and other resources than we have. Factors that affect our ability to acquire producing properties include available funds, available information about prospective properties and our limited number of employees. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. Renewable energy sources may become more competitive in the future.

The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control including, but not limited to, the amount of domestic production and imports of foreign oil and liquefied natural gas, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of allowable rates of production, taxation, the conduct of drilling operations and federal regulation of crude oil and natural gas. In addition, the restructuring of the natural gas pipeline industry virtually eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. Producers of natural gas have therefore been required to develop new markets among gas marketing companies, end users of natural gas and local distribution companies. All of these factors, together with economic factors in the marketing arena, generally affect the supply of and/or demand for oil and natural gas and thus the prices available for sales of oil and natural gas.

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Employees

Southfield Energy Corporation has three full-time employees and two part-time employees. Our full-time employees are our CEO, Ben Roberts; our CFO, Chet Gutowsky; and our COO, Tyson Rohde.

Item 1A.

Risk Factors

An investment in our common stock or debt involves a high degree of risk. You should carefully consider the following risk factors, other information included in this annual report and information in our other periodic reports filed with the SEC. 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 actually occur, our business, financial condition or results of operations could be materially and adversely affected, 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 debt when due or to repay principal upon maturity. Reductions in cash flow from operations could adversely affect holders of our debt or equity.

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. They may also cause a reduction in the value of our equity.

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

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• government regulation and taxation.

In addition, the actual amount of cash that we will have available to make payments on the principal and interest on our debt 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 debt 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.

As of December 31, 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 our debt 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 three months ending December 31, 2009, our revenues were derived 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.

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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 December 31, 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 must drill new wells or make acquisitions in order to maintain our production and reserves and sustain our payments of principal and interest to our debt holders over time. Failure to do this could adversely affect investments in our debt or equity.

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.

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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 cash raised in financing activities. We may 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 debt.  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 existing debt 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, the value of our equity and our ability to pay interest and principal on our debt.

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;

• 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.

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The prices of oil and gas have reached historic highs in recent years and are highly volatile. A sustained decline in these commodity prices would cause a decline in our cash flow from operations, which may adversely affect investments in our debt or equity.

The oil and gas markets are highly volatile, and future oil and gas prices are uncertain. 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, impede our growth, and reduce the value of our equity. In addition, we may not be able to sustain payments of principal and interest to our debt 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, limit our ability to make payments on the principal and interest to our debt holders, and could adversely affect the value of our equity.

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.

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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 raise capital, which in turn may adversely affect our ability to generate revenues.

Our future hedging activities could result in financial losses or could reduce our income, which may adversely affect the value of our equity or our ability to repay interest and principal on our debt 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. These losses could adversely affect investments in our debt or equity.

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;

• future production levels;

• capital expenditures;

• operating and development costs;

• the effects of regulation; and

• Future 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 average prices and costs from the preceding year. 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 FASB standards 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, decrease the value of our equity or limit our ability to pay principal and interest payments to our debt 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;

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• 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 our current liability obligations 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 debt 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 available cash.

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.

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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 our debt holders could be adversely affected, as well as the value of our equity.

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.

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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 “Act”), as amended, we may be deemed to be an inadvertent investment company if it is determined that the value of investments in other company’s securities accounts for more than 40% of the total value of our assets, and no other exemption is available. If so, and if we were to be deemed an inadvertent investment company, we believe that we may be eligible for temporary relief from the application of the Act if we have a bona fide intent to be engaged primarily, as soon as reasonably possible (in any event within one year), in a business other than that of investing, reinvesting, owning, holding or trading in securities. We do not have any current plans, proposals or arrangements, written or otherwise, to invest in the securities of any other company.

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 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 Act may not be consistent with the Company’s current business strategies.

Risks Related to Financing Activities

We may issue additional debt, including notes that are senior to our current debt, without your approval.

The amount of additional debt that can be raised by us is not limited. We may incur an unlimited amount of indebtedness that is senior to our existing debt without your approval.

Debt 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. Debt Holders will not have voting rights on such matters as do the common shareholders.

Debt Holders will have very limited liquidity in their investments. We do not intend nor expect to request that Southfield’s debt instruments be listed for trading on any exchange.

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

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

Interest earned on our debt instruments 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 and related industries. 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 December 31, 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.

Item 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

Richard King Field

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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 100% 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 initially 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 currently producing 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 250,000 cubic feet of gas per day. This project has been our most successful endeavor to date and still contains additional reserves.

Exploratory and Developmental Acreage

Our principal oil and gas property, in the Richard King Field, consists of productive wells and reserves of oil and gas in place. The following table indicates our interest in developed and undeveloped acreage as of December 31, 2009.

	Developed Acreage				Undeveloped Acreage				Total
	Gross Acres		Net Acres		Gross Acres		Net Acres		Net Acres
Richard King		160		24		32		4.8		28.8

Productive Wells

The following table sets forth our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2009.

	Oil				Gas
	Gross		Net		Gross		Net
Richard King		-		-		5		.75

Proved Reserves

Netherland, Sewell, and Associates, Inc. (“NSAI”) an independent reservoir engineering firm that reports to our board of directors, provided a report related to its estimates of reserves as of December 31, 2009. The service performed by NSAI included the preparation of an independent estimate of proved natural gas and oil reserves estimates for our properties in the Richard King Field. Based on the amount of proved reserves determined by NSAI, we believe our reported reserve amounts are reasonable.

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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.

The following table sets forth certain information regarding estimates of our oil and gas reserves as of December 31, 2008 and December 31, 2009. All of our reserves are located in the United States.

Summary of oil and gas reserves as of Fiscal-Year End [1]

	2009						2008
Reserves Category:	Oil (mbbls)		Natural Gas (mmcf)		Total (BOE)[2]		Oil (mbbls)		Natural Gas (mmcf)		Total (BOE)[2]
PROVED
Developed:
Aldwell		-		-		-		5,344		10.8		7,144
MKE field[3]		4,028		312.78		56,159		169		114.2		19,202
Undeveloped:
Aldwell		-		-		-		1,809		4.6		2,576
MKE field[3]		131		65.12		10,984		149		87.8		14,782
TOTAL PROVED		4,159		377.90		67,143		7,471		217.4		43,704
PROBABLE
Developed:
MKE field[3]		264		164.7		27,723
POSSIBLE
Developed:
MKE field[3]		-		76.66		12,776
Undeveloped
MKE field[3]		-		13.66		2,276

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[1] The summary of oil and gas reserves as of December 31, 2009 was based on average fiscal year prices, while the summary of oil and gas reserves as of December 31, 2008 was based on year-end prices. Additionally, disclosure of probable and possible reserves became optional under SEC guidelines for the year ended December 31, 2009; accordingly, no probable or possible reserves are included for the year ended December 31, 2008.

[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 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 or natural gas either produced or remaining as reserves.

[3] The Mary King Estell field has been abbreviated as “MKE field” in this table.

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.

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

Summary of Production and Ratios as of Fiscal-Year End [1]

	2009		2008
Annual Production (BOE)		4,849		7,127
Reserve-to-Production Ratio (Years)[1]		13.84		6.12
Estimated Production Decline Rate [2]		7%		14%

[1] This ratio estimates the number of years that it would require to produce our remaining reserves assuming that production rates remain constant.

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

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Oil and Gas Production and Sales Price

	2009		2008		2007
Oil production (Bbls)[1]		373		550		494
Gas production (Mcf)		25,576		37,474		4,498
Total production (BOE)[2]		4,636		7,127		1,550
Average sales price per BOE ($)		24.21		55.49		50.50
Average cost of sales per BOE[3]($)		21.24		16.93		12.96

[1]           Oil production set forth in the table above includes the production of natural gas liquids (NGLs)

[2]           Oil and gas were combined by converting to a BOE equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil.

[3]           Production costs include direct operating expenses, ad valorem taxes and production taxes.

Drilling Activities

The following table sets forth our gross and net working interests in exploratory and development wells drilled throughout each of the last three fiscal years ended December 31[1]:

	2009				2008				2007
	Gross		Net		Gross		Net		Gross		Net
Exploratory
Productive
Oil		-		-		-		-		-		-
Gas		-		-		-		-		1		.15
Dry Holes		1		.02		-		-		-		-
Total		1		.02		-		-		1		.15
Development
Productive
Oil		-		-		27		.05		33		.06
Gas		2		.45		2		.30		-		-
Dry Holes		-		-		-		-		-		-
Total		3		.45		29		.35		33		.06

[1] Southfield’s working interest in the Aldwell Unit was .1749% and our working interest in the Mary King Estell Lease is 15%.

In 2009, Durango Resources drilled the C-34 and the C-35 wells in which we own a 15% working interest. Both wells resulted in successful gas wells. The five wells that we have drilled with Durango Resources presently constitute 100% 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.

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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.

Item 3. 

Legal Proceedings

We may be involved from time to time in ordinary litigation, negotiation and settlement matters that will not have a material effect on our operations or finances. We are not a party to any legal proceedings, and are not aware of any pending or threatened litigation against us or our officers and directors in their capacity as such that may have a material impact on our operations or finances.

Item 4. 

Submission of Matters to a Vote of Security Holders

There were no matters submitted to the shareholders during the fourth quarter of 2009.

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PART II -   Other Information

Item 5. 

Market for Common Equity and Related Stockholder Matters Market Information

Our common stock is not traded on an exchange or quoted on an automated quotation system.

On December 31, 2009, there were 7,410,000 shares of our common stock issued and outstanding.

Holders

As of December 31, 2009, we had approximately 28 holders of record.

Dividends

We have not declared or paid cash dividends on our common stock since inception and do not anticipate paying such dividends in the foreseeable future. The payment of dividends may be made at the discretion of the Board of Directors and will depend upon, among other factors, our operations, capital requirements, and overall financial condition.

Securities Authorized for Issuance under Equity Compensation Plans

We do not currently have any equity compensation plans or stock option plans under which equity securities are authorized for issuance.

Recent Sales of Unregistered Securities

As of December 31, 2007, 2008 and 2009, the Company had issued $866,000, $1,482,000 and $1,874,000, 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.

Use of Proceeds from Registered Securities

We filed a registration statement for $10 million of 3 Year Notes that became effective on February 11, 2010. The 3 Year Notes are not convertible and are being offered directly through the company with the assistance of placement agents. The sales process for the placement of 3 Year Notes has commenced, however no sales have been made as of the date of this filing. The reason that sales have not been made is because we are working to fulfill state regulatory requirements and register the offering in certain states pursuant to Blue Sky Laws.

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Item 6. 

Selected Financial Data

A smaller reporting company is not required to provide the information required by this item.

Item 7. 

Management’s Discussion and Analysis and Plan of Operation

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto, and other financial information included elsewhere if this form 10-K. This report 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 and gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in form 10-K, 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 that invests in the 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

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 5,970 barrels of oil equivalent in 2008 and 4,057 barrels of oil equivalent in 2009. 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.

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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.

From January 1, 2009 through August 31, 2009 the pro rata portion of production net to our working interest from the Aldwell Unit was 792 barrels of oil equivalent. 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 three months ending December 31, 2009, our revenues were derived from our Richard King Field properties.

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. As of December 31, 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 December 31, 2009 of $66,250. The difference between the cost and market value of the shares was recorded as impairment expense for $243,095. On January 4, 2010, we sold our remaining 250,000 shares of common stock in Meridian Resources Corporation and realized an approximate loss of $654 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.

Results of Operations

Year Ended December 31, 2009 Compared to December 31, 2008

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

	2008						2009
	Production (BOE)		Avg. Price per BOE ($)		Total Revenues ($)		Production (BOE)		Avg. Price per BOE ($)		Total Revenues ($)
Aldwell Unit		1,157		73.62		85,175		792		29.11		23,056
Richard King		5,970		51.98		310,299		4,057		21.98		89,181
TOTAL		7,127		55.49		395,474		4,849		25.50		112,237

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           Revenues.   Revenues from continuing operations decreased by $221,118 and revenues from both continuing operations and discontinued operations decreased by $283,236 for the year ended December 31, 2009, as compared to the year ended December 31, 2008, due to a decrease in oil and gas prices and decrease in production. Production realized from the Aldwell Unit decreased from 1,157 barrels of oil equivalent (BOE) to 792 BOE; and production in the Richard King Field decreased from 5,970 BOE to 4,057 BOE. Additionally, the average price per BOE decreased from $55.49 in 2008 to $24.21 in 2009.

Production.   Our average monthly production decreased from 594 Barrels of Oil Equivalent (“BOE”) in 2008 to 386 BOE in 2009. Most wells produce at higher initial rates and their production declines as they deplete over time. Our monthly production decreased for two reasons. First, our operator choked back the production from the Mary King Estell Lease to retain some of our gas to sell at higher prices. Second, we sold the Aldwell Unit for a profit to create additional liquidity for operating expenses and debt service.

Production costs.   Production costs, which includes lease operating expenses and excludes severance and ad valorem taxes, decreased from $28,556 to $24,827 during the years ended December 31, 2008 and 2009, respectively. As a percentage of revenue, however, our production costs increased from 9% to 28%. Because of decreases in oil and gas prices and our production rates, our revenues decreased over the respective periods by more than the decrease 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.   DD&A expense from continuing operations decreased from $41,791 to $18,198 during the years ended December 31, 2008 and 2009, respectively.  This was due to a decrease in our capitalized expenses in proved properties and a lower depletion rate of our production in 2009 as compared to 2008.

G&A expense.   Our general and administrative expense was $273,143 for 2008 and $665,392 for 2009. These expenses include rent, office expenses, travel expenses, salaries for employees, consulting expenses, legal and accounting expenses and benefits for employees. This increase can be attributed primarily to increases in the following: legal and accounting expenses increased by approximately $147,000; consulting expenses increased by $77,000; rent and salaries increased by approximately $12,000 and $139,000, respectively due to utilizing more office space and management retention incentives; and office supplies, insurance premiums, utilities and miscellaneous expenses increased by $16,000. Most of the above expenses increased in connection with filing a registration statement with the Securities and Exchange Commission and becoming a publicly reporting company.

           Income taxes.   Southfield experienced losses in 2008 and 2009 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). FASB standards require 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 December 31, 2009 we had $68,826 of cash and cash equivalents, a working capital deficit of $379,089 and a total stockholders’ deficit of $1,607,759.  Our expenses exceeded our revenues for the year ended December 31, 2009; thus, we incurred a net loss of $1,212,227 for the year ended December 31, 2009.

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We will need to raise money through our registered offering of 3 Year Notes to fund our business plan and support our operations after April 1, 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, 2009 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.

The accompanying financial statements have been prepared assuming that Southfield will continue as a going concern. As shown in the accompanying financial statements, we had negative cash flows from operations of $618,211 in 2009 and $75,059 in 2008, and a working capital deficit of $379,089 at December 31, 2009. These conditions raise substantial doubt as to our ability to continue as a going concern. The financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern. Management intends to finance these deficits by selling 3 Year Notes and seeking additional outside financing through either debt or sales of its common stock.

From September 2009 through the filing date of this 10-K, 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 as of December 31, 2009, after taking into account the debenture extensions:

Maturities of Convertible Notes over the next five years ended December 31, 2010:

	2010	2011	2012	2013	2014
Debenture Maturities	190,000*	461,000	686,000	364,000	173,000

*As a subsequent event to 12/31/2009, we repaid $29,000 of convertible debentures in the first quarter of 2010.

Cash Flows

Operating activities. Net cash used in operating activities for the year ended December 31, 2009 as compared to the year ended December 31, 2008 was $618,211 and $75,059, respectively. We incurred a loss on the sale of available for sale securities of $134,096; amortization of loan and debenture costs of $137,799; depreciation, depletion and amortization costs from continuing operations of $18,198; an impairment of available for sale securities of $279,345; an increase in accounts payable of $44,823; a decrease in receivables of $48,720, and increases in accrued interest and prepaid expenses of $89,662 and $30,933, respectively. Accrued interest increased because of compounding interest that continued to accrue to the benefit of those convertible debenture holders that elected to receive that option. Prepaid expenses decreased as a result of the fact that in 2009 we did not advance unapplied drilling funds as we did in 2008.

26

Investing activities.  Net cash provided / (used) in investing activities for the year ended December 31, 2009 as compared to the year ended December 31, 2008 was $216,178 and $(667,839), respectively. Our capitalized investment in proved leaseholds for the year ended December 31, 2009 was $123,311. 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 net cash flow from discontinued operations of $294,215. The sale of available for sale securities in this period also accounted for an additional $45,274 of cash provided by investing activities.

Financing activities.  Net cash provided from financing activities for the year ended December 31, 2009 as compared to the year ended December 31, 2008 was $347,755 and $512,890, respectively. This change was primarily due to a decrease in debenture sales from $616,000 to $392,000 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 our debt obligations 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.

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 stakeholders.

Contractual Obligations

	Payments Due By Period
Contractual Obligations at December 31, 2009	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Convertible Debentures	$	1,874,000	$	190,000	$	1,511,000	$	173,000	$	0
Total	$	1,874,000	$	190,000	$	1,511,000	$	173,000	$	0

27

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 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. Based on our calculation as of December 31, 2009 the asset retirement obligation liability was immaterial to the financial statements. We will continually evaluate this liability and record it, if and when it becomes material.

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;

• The accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

28

Proved reserve information included in this 10-K was prepared by the independent engineering firms Netherland, Sewell & Associates and Huddleston and Company as of December 31, 2009 and December 31, 2008, respectively. Estimates prepared by these engineering firms 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 10-K as of December 31, 2009 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.

29

• 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.

Recently Issued 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 December 31, 2009.

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 December 31, 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 December 31, 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.

30

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.

In May 2008, the FASB issued an amendment to the accounting standards related to the hierarchy of GAAP. The standard identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (“GAAP”) in the United States (the GAAP hierarchy). The standard becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (“PCAOB”) amendment to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles” and is not expected to have a significant impact on our financial statements.

Plan of Operation

Over the next twelve months we intend to develop the following initiatives:

Financing

We anticipate raising $10 million in debt financing over the next 12-24 months through the sale of 3 Year Notes as described in our S-1 filing. In addition to the sale of 3 Year Notes, we anticipate raising additional equity capital provided that the terms and conditions for the placement of such funding is based upon an equity valuation and underwriting fees that are amenable to our board of directors.

Revenue Generation

We intend to invest the predominance of the gross proceeds from the issuance of the $10 million in 3 Year Notes into oil and gas projects. We expect these to include a combination of acquisitions of proved producing properties with drilling or recompletion upside and investment in exploratory and development drilling programs. After the deployment of this capital, we expect our production, reserves, revenues and cash flow to increase substantially.

Item 7A. 

Quantitative and Qualitative Disclosures About Market Risk.

A smaller reporting company is not required to provide the information required by this item.

Item 8. 

Financial Statements and Supplemental Data

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	32
Balance Sheets – December 31, 2009 and 2008	33
Results of Operations for the years ended December 31, 2009 and 2008	34
Statements of Cash Flows for the years ended December 31, 2009 and 2008	35
Statement of Changes in Stockholders’ Equity from December 31, 2007 to December 31, 2009	36
Notes to Financial Statements	37

31

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, 2009 and 2008, and the related statements of operations, changes in stockholders’ deficit, and cash flows for the years ended December 31, 2009 and 2008. 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, 2009 and 2008 and the results of its operations and cash flows for the periods 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 4 to the financial statements, the Company has experienced losses and incurred negative cash flows from operations since inception, which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters also are described in Note 4. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ M&K CPAS, PLLC

www.mkacpas.com

Houston, Texas

April 5, 2010

32

SOUTHFIELD ENERGY CORPORATION

BALANCE SHEETS

As of December 31, 2009 and 2008

	December			December
		31, 2009			31, 2008
				(Restated)
ASSETS
Current Assets:
Cash	$	68,826		$	123,104
Accounts Receivable		13,006			49,068
Accounts Receivable - Related Party		-			2,000
Prepaid Expenses		-			30,933
Current assets of discontinued operations		-			10,658
TOTAL CURRENT ASSETS		81,832			215,763
Property & Equipment:
Oil & Gas, on the basis of successful efforts accounting
Gross Proved Properties		346,199			222,888
Less: Accumulated Depletion and Depreciation		(85,179	)		(66,981	)
Net Proved Properties		261,020			155,907
Office Equipment		-			427
Other Long Term Assets:
Gross Capitalized Loan and Debenture Costs		413,002			370,353
Less: Accumulated Amortization		(284,942	)		(148,739	)
Net Capitalized Loan and Debenture Costs		128,060			221,614
Available for Sale Securities		345,595			524,965
Less: Valuation Allowance		(279,345	)		(325,465	)
Net (market value)		66,250			199,500
Long term assets of discontinued operations		-			104,228
TOTAL ASSETS	$	537,162		$	897,439
LIABILITIES AND STOCKHOLDERS' EQUITY
LIABILITIES:
Current Liabilities:
Accounts Payable	$	72,272		$	11,944
Accrued interest on Debentures		198,649			108,987
Current portion of Debentures Payable		190,000			304,000
Current liabilities of discontinued operations		-			15,505
TOTAL CURRENT LIABILITIES		460,921			440,436
Long Term Liabilities:
Convertible Debentures Payable		1,684,000			1,178,000
TOTAL LONG TERM LIABILITIES		1,684,000			1,178,000
TOTAL LIABILITIES		2,144,921			1,618,436
STOCKHOLDERS' DEFICIT:
Common stock, $0.001 par value; 50,000,000 shares  authorized, 7,410,000 issued and outstanding at 12/31/09 and 12/31/08		7,410			7,410
Additional Paid-in Capital		99,373			99,373
Deficit accumulated during the development stage		(24,718	)		(24,718	)
Accumulated deficit		(1,689,824	)		(477,597	)
Accumulated other comprehensive income (loss)		-			(325,465	)
TOTAL STOCKHOLDERS' DEFICIT		(1,607,759	)		(720,997	)
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$	537,162		$	897,439

*See accompanying notes to the financial statements.

33

SOUTHFIELD ENERGY CORPORATION

STATEMENTS OF OPERATIONS

For the years ended December 31, 2009 and 2008

	December			December
	31, 2009			31, 2008
				(Restated)
REVENUES:
Oil and Gas Production	$	89,181		$	310,299
EXPENSES:
Production Costs		24,827			28,556
Severance & Ad Valorem		9,758			24,017
DD&A		18,198			41,791
Unsuccessful Exploration Costs		30,933			-
Amortization of Loan and Debenture Costs		137,799			98,827
General and Administrative Expenses		665,392			273,143
TOTAL OPERATING EXPENSES		886,907			466,334
OPERATING LOSS		(797,726	)		(156,035	)
Other Income (Expense)
Interest Income		119			3,870
Gain (Loss) on Sale of Securities		(134,096	)		14,479
Interest Expense		(177,751	)		(128,431	)
Impairment on AFS Securities		(279,345	)		-
Other Expense		(6,525	)		-
Total Other Expenses		(597,598	)		(110,082	)
Net loss from continuing operations	$	(1,395,324	)	$	(266,117	)
Net income/(loss) from discontinued operations	$	183,097		$	(57,700	)
Net Loss	$	(1,212,227	)	$	(323,817	)
Other Comprehensive Loss:
Unrealized loss on available for sale securities		-			(325,465	)
Total Comprehensive Loss	$	(1,212,227	)	$	(649,282	)
Weighted average common shares outstanding		7,410,000			7,363,005
Net Loss per common share from continuing operations (Basic & Diluted)	$	(0.19	)	$	(0.04	)
Net Income/Loss per common share from discontinued operations (Basic & Diluted)	$	0.02		$	(0.01	)
Basic and diluted net loss per common share	$	(0.16	)	$	(0.05	)

*See accompanying notes to the financial statements.

34

SOUTHFIELD ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

For the years ended December 31, 2009 and 2008

	December			December
	31, 2009			31, 2008
				(Restated)
Cash Flows From Operating Activities
Net loss from continuing operations	$	(1,395,324	)	$	(266,117	)
Net income/(loss) from discontinued operations		183,097			(57,700	)
Net loss		(1,212,227	)		(323,817	)
Adjustments to reconcile net loss to net cash used by by operating activities
Stock based consulting expense		-			5,000
Gain on trading securities		-			(14,479	)
Loss on sale of AFS - Securities		134,096			-
Amortization of Loan & Debenture Costs		137,799			98,827
Depreciation, Depletion and Amortization		18,198			55,700
Impairment of AFS-Securities		279,345			-
Changes in operating assets and liabilities:
Payables		44,823			(20,574	)
Accrued Interest		89,662			60,260
Receivables		48,720			(34,854	)
Prepaid Expenses		30,933			(30,933	)
Net cash flows from discontinued operations		(189,560	)		129,811
Net cash used by operating activities	$	(618,211	)	$	(75,059	)
Cash Flows From Investing Activities
Capitalized Investment in Proved Leaseholds		(123,311	)		(126,264	)
Purchase of AFS - Securities		-			(510,486	)
Sale of AFS - Securities		45,274			-
Purchase of fixed assets		-			(427	)
Net cash flows from discontinued operations		294,215			(30,662	)
Net cash (used) provided by investing activities	$	216,178		$	(667,839	)
Cash Flows From Financing Activities
Deferred financing costs		(44,245	)		(103,110	)
Debentures Payable		392,000			616,000
Net cash provided from financing activities	$	347,755		$	512,890
Net decrease in cash		(54,278	)		(230,008	)
Cash, beginning of period		123,104			353,112
Cash, end of period	$	68,826		$	123,104
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	$	88,622		$	68,171

*See accompanying notes to the financial statements.

35

SOUTHFIELD ENERGY CORPORATION

STATEMENT OF CHANGES IN STOCKHOLDERS' DEFICIT

For the years ended December 31, 2009 and 2008

							Deficit
							Accumulated						Accumulated
							During						Other
	Common Stock						Development			Accumulated			Comprehensive
	Shares		Amount		APIC		Stage			Deficit			Income			Total
Balance December 31, 2007		7,360,000	$	7,360	$	94,423	$	(24,718	)	$	(153,780	)	$	-		$	(76,715	)
Issuance of common
stock at $0.10 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	)
Sale of available for sale securities														134,096			134,096
Impairment of available for sale securities		-		-		-		-			-			191,369			191,369
Net Loss		-		-		-		-			(1,212,227	)		-			(1,212,227	)
Balance December 31, 2009		7,410,000	$	7,410	$	99,373	$	(24,718	)	$	(1,689,824	)	$	-		$	(1,607,759	)

*See accompanying notes to the financial statements.

36

SOUTHFIELD ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

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, and Oklahoma. 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.

37

NOTE 2 – Basis of Presentation

The accompanying audited 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 December 31, 2009 end of year 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.

Because the Aldwell Unit was sold with an effective date of September 1, 2009, the accompanying audited financial statements for the years ended December 31, 2009 and 2008 have been presented with the financial results from the Aldwell Unit in discontinued operations. All of the revenues and expenses associated with the Aldwell Unit prior to September 1, 2009 were part of our continuing operations at the time. However, subsequent to the sale, we separated the financial results of the Aldwell Unit from the continuing operations in 2008 and 2009 and reclassified them into discontinued operations so that the impact of the sale of the Aldwell Unit can be compared across periods. Also, all assets and liabilities of the Aldwell Unit have been segregated from continuing operations on the balance sheet as of December 31, 2008.

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.

NOTE 3 – Reclassification

Certain items from the December 31, 2008 statements of operations have been reclassified to conform with the year ended December 31, 2009 financial statement presentation. There is no effect on net income, cash flows or stockholders’ equity as a result of these reclassifications.

NOTE 4 – 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 from operations 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 offering of three year notes 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 5 - 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.

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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. As of December 31, 2009 and 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. Oil and gas producing assets are evaluated for impairment at least annually at the end of every year. 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 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. Since all potentially dilutive securities would be considered anti-dilutive, the basic loss per share equals the fully diluted loss per share.  Earnings per share from discontinued operations for the twelve months ended December 31, 2009 is $.02 and earnings per share from continuing operations for the twelve months ended December 31, 2009 is ($.19).  For the twelve months ended December 31, 2008, earnings per share for discontinued operations and from continuing operations were ($0.01) and ($0.04), respectively.

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.  The net costs capitalized as of 12/31/09 year ended are $128,060 and the net costs capitalized as of 12/31/08 year ended were $221,614.

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’s financial statements as of and for the years ended December 31, 2009 and 2008 reflect the impact of this standard.

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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.

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 Company valued the Aldwell Unit Proved Properties at their fair value in accordance with the applicable FASB standard due to the impairment indicators prevalent as of December 31, 2008. The inputs that were used in determining the fair value of these assets were 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. Impairment expense of $116,553 was recorded on this asset based on the adjustment to fair value during the year ended December 31, 2008. No oil and gas assets were valued at fair value as of December 31, 2009 as no impairment was noted in the Company’s annual evaluation.

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The following table presents assets that are measured and recognized at fair value as of December 31, 2009 and for the twelve months then ended on a recurring basis:

12/31/2009							Total
							Realized (Loss due to			Total Unrealized
Description	Level 1		Level 2		Level 3		valuation)			(Loss)
Available for Sale Securities	$	66,250	$	-	$	-	$	(279,345	)	$	-
Totals	$	66,250	$	-	$	-	$	(279,345	)	$	-

12/31/2008							Total
							Realized (Loss		Total
Description	Level 1		Level 2		Level 3		due to valuation)		Unrealized (Loss)
Available for Sale Securities	$	199,500	$	-	$	-	$	-	$	(325,465	)
Totals	$	199,500	$	-	$	-	$	-	$	(325,465	)

The following table presents all assets that were measured and recognized at fair value as of December 31, 2008 and for the twelve months then ended on a non-recurring basis. No assets were valued at fair value on a non-recurring basis as of December 31, 2009. The asset shown below was presented at fair value due to the impairment analysis indicating an estimated fair value below cost for the Aldwell Unit. All other proved properties were presented at cost due to their estimated fair values exceeding cost in the impairment analyses conducted at December 31, 2009 and 2008:

								Total
								Realized (Loss		Total
Description	Level 1		Level 2		Level 3			due to valuation)		Unrealized (Loss)
Proved Properties (Aldwell Unit) (net)	$	-	$	-		$	104,228	$	116,553	$	-
Totals	$	-	$	-		$	104,228	$	116,553	$	-

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.

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Income Taxes: The Company has incurred losses since inception and, therefore, has not been subject to federal income taxes. As of December 31, 2009 and December 31, 2008, the Company estimates an accumulated net operating loss (“NOL”) carryforward of approximately $1,470,127 and $493,000, respectively, resulting in deferred tax assets before valuation allowances of approximately $514,544 and $172,550, respectively. The company also estimates current deferred tax assets before valuation allowances related to temporary differences between tax and financial accounting of $82,285 and $0 for the years ended December 31, 2009, and December 31, 2008, respectively. These differences are primarily related to the differences in accounting for de-valuations in investments held as available for sale securities, and differences related to deferred financing costs. The NOL 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 any of the deferred tax assets, a full valuation allowance has been taken to reduce the deferred tax asset to zero as of December 31, 2009, and 2008, 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 December 31, 2009.

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 December 31, 2009 were $123,104 and $68,826, 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.

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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 December 31, 2009.

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 December 31, 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 fell within the scope of this pronouncement as of December 31, 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.

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NOTE 6 - 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 approximately $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 the twelve months ended December 31, 2008 was $24,483. The total rent expense for the twelve months ended December 31, 2009 was $36,814. After taking into account comparable rents in the immediate area, the rent paid by Southfield is a fair market value.

NOTE 7 – Convertible Debentures Payable

We have retained the services of MMR Investment Bankers, Inc. to represent the Company in a 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. As of December 31, 2008 and December 31, 2009, the Company has issued $1,482,000 and $1,874,000 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 twenty (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.

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
$	190,000	$	461,000	$	686,000	$	364,000	$	173,000

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NOTE 8 – Acquisitions & Capital Investments

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.

In 2009, the Company successfully drilled the C-34 and C-35 wells located on the Mary King Estell Lease and invested approximately $61,395 and $61,916, respectively. The remainder of the capital investment in proved leaseholds was in the Aldwell Unit for roughly $5,785. This capital investment was used to drill and complete new wells and to recomplete existing production wells to enhance production in the field.

Note 9 – 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. As of December 31, 2008 the value of the stock declined significantly consistent with the overall stock market at that time. As of December 31, 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 twelve months ended December 31, 2009, rather than in other comprehensive income. The impairment expense was $279,345 for the twelve months ended December 31, 2009.

Note 10 – 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 $132,012 less depreciation, depletion, and amortization of $6,146. The realized gain on the sale was 193,134. Commissions and fees of $18,389 were paid related to the sale.  Prior to the sale, the Aldwell Unit had revenues of $85,175 and $23,056 for the twelve months ended December 31, 2008 and 2009. Net loss related to the Aldwell unit was $57,700 for the twelve months ended December 31, 2008. Accounts receivable from the Aldwell Unit from that same period were $10,658; and as of December 31, 2008, the carrying value of the Aldwell Unit after its impairment was $104,228. Net income for the twelve months ended December 31, 2009 from the Aldwell Unit was $183,097.

NOTE 11 – Non-cash Compensation

John Brewster was issued 50,000 shares on December 10, 2008 for providing consulting 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 twelve months ended December 31, 2009

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NOTE 12 – Depletion and Depreciation

DD&A expense from continuing operations decreased from $41,791 to $18,198 during the years ended December 31, 2008 and 2009, respectively. This was due to a decrease in our capitalized expenses in proved properties and a lower depletion rate of our production in 2009 as compared to 2008. Depreciation, depletion and amortization have been calculated using the units of production method.

NOTE 13 – 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 $413,002 as of December 31, 2008 and December 31, 2009, respectively. The accumulated amortization was $148,739 and $284,942; and the net capitalized loan and debenture costs were $221,614 and $128,060 for the same periods respectively.

NOTE 14 – 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 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. The Company analyzed its remaining proved oil and gas properties located in the Mary King Estell lease as of December 31, 2009. The estimated undiscounted net cash flows provided in the December 31, 2009 reserve report was greater than the carrying value of the assets, therefore no impairment was necessary.

NOTE 15 – 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 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.

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NOTE 16 – Oil and Gas Properties

As of the date of this report and as of December 31, 2009, the Company owned non-operated working interests in five wells 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, most of which were located in the Aldwell Unit. According to the reserve report prepared by Huddleston and Company, and 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 $609,427. Estimated future net cash flows of the properties were discounted at 10% consistent with FASB standards. According to the reserve analysis conducted by Netherland, Sewell and Associates, Inc., and the Company’s estimate of future income taxes, the estimated discounted net cash flow after taxes was $457,500 for the twelve months ended December 31, 2009. Because of our significant net loss carryforward, we do not expect to pay any federal income taxes on future net revenues provided from our Mary King Estell production, and therefore the pre-tax and after-tax estimate of discounted future net cash flows are both $457,000.

NOTE 17 – Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (unaudited).

Summary of general presentation and assumptions used in our Reserve Analysis

Netherland, Sewell & Associates, Inc. (NSAI) estimated the proved, probable, and possible reserves and future revenue, as of December 31, 2009, to our interest in certain oil and gas properties located in the Mary King Estell lease, Richard King Field, Nueces County, Texas. The full report can be found as an Exhibit to Form 10-K. The proved reserves in this report constitute all of the proved reserves owned by us. The estimates prepared by NSAI have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and, with the exception of future income taxes, conform to the FASB Accounting Codification Topic 932, Extractive Activities-Oil and Gas.

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in barrels that are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard temperature and pressure bases.

The estimates shown in the NSAI report include proved, probable, and possible reserves. However, only proved reserves are disclosed in the tables within this footnote.  This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves sub-categorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Future gross revenue to our interest is presented prior to deducting state production taxes and ad valorem taxes. Future net revenue is calculated after deductions for these taxes, future capital costs, and operating expenses but before consideration of federal income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

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Prices used in this report are based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2009. For oil volumes, the average Wall Street Journal NYMEX West Texas Intermediate (WTI) of $61.18 per barrel is adjusted by lease for transportation fees and regional price differentials. For gas volumes, the average Wall Street Journal NYMEX Henry Hub price of $4.189 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. As a reference, for the same time period the average Plains Marketing, L.P. WTI posted price was $57.65 per barrel and the average Platts Gas Daily Henry Hub spot price was $3.866 per MMBTU. All prices are held constant throughout the lives of the properties.

Leases and well operating costs used in the NSAI report are based on operating expense records of Durango Resources Corporation (Durango), the operator of the properties. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. No headquarters general and administrative overhead expenses of Southfield or Durango are included. Lease and well operating costs are held constant through the lives of the production equipment. The future capital costs are held constant to the date of expenditure.

The reserves shown in the NSAI report and in this filing are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geosciences data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. If the reserves are recovered, the revenues there from and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Estimates of reserves may increase or decrease as a result of future operations, market conditions, or changes in regulations.

For the purposes of this report, NSAI used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in the NSAI report have been estimated using deterministic methods; these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation principals. NSAI used standard engineering and geoscience methods, or a combination of methods, such as performance analysis, volumetric analysis, and analogy that it considered to be appropriate and necessary to establish reserves quantities and reserves categorization that conform to SEC definitions and guidelines. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, and undeveloped locations. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics.

In evaluating our reserves, NSAI excluded from its consideration all matters as to which the controlling interpretation may be legal or accounting, rather that engineering or geoscience. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, NSAI’s conclusions necessarily represent only informed professional judgment.

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The technical persons responsible for preparing the reserves estimates presented in the NSAI report meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis.

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:

	As of December 31,
	2009			2008
Future cash inflows	$	1,693,500		$	1,549,473
Future production costs		(525,800	)		(431,453	)
Future development costs		(96,200	)		(165,765	)
Future income tax expenses		-			(62,340	)
Future net cash flows		1,071,500			889,915
10% annual discount for estimated timing of cash flows		(614,000	)		(280,488	)
Standardized measure of discounted future net cash flows	$	457,500		$	609,427

Year-end and average oil and gas price information	2009		2008
Year-end oil price per barrel		N/A	$	44.60
Average oil price per barrel	$	61.18		N/A
Year-end gas price per mcf		N/A	$	5.66
Average gas price per mcf	$	4.19		N/A

From 2008 to 2009, the PV10 value was reduced primarily as a result of the low average pricing of oil and natural gas.  Based on the SEC’s amended rules, 2009 reserve calculations are computed by applying an average of historical prices of oil and natural gas over the twelve months in 2009 to future estimates of quantities of proved oil and natural gas production. The year-end price used to compute 2008 future cash flow was $44.60 for oil and $5.66 for natural gas.  The average price used to compute 2009 future cash flow is $61.18 for oil and $4.19 for natural gas.  Future operating expenses and development costs were estimated by engineers from Netherland, Sewell & Associates, Inc., a Dallas based petroleum engineering company based on a twelve month averaging of oil and gas prices and economic conditions. Future income tax expense, estimated by management, is 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 gas properties.  An estimate of fair value may also take into account 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.

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Changes in Standard Measure of Discounted Future Net Cash Flows

	As of December 31,
	2009			2008
Beginning Balance	$	609,427		$	988,653
Accretion of Discount		60,943			98,865
Sales of oil and gas net of production costs		(13,767	)		(341,256	)
Development cost changes		29,702			25,901
Previously estimated development costs incurred during period		129,096			40,373
Revisions in previous price estimates		(948,046	)		(893,457	)
Revisions in quantity estimates		916,074			266,753
Net changes in production costs		(63,001	)		191,713
Changes in estimated future severance, ad valorem taxes, & income tax		(6,119	)		89,210
Sales of minerals in place		(207,676	)		-
Other-unspecified		(49,133	)		142,672
Net change in standardized measure of discounted cash flows		(151,927	)		(379,226	)
Ending Balance	$	457,500		$	609,427

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

	As of December 31,
	2009		2008
Acquisitions of proved properties		-		-
Exploration Costs		30,933		-
Development costs		129,096		156,926

Capitalized Costs Related to Oil Producing Activities

	As of December 31,
	2009			2008
Proved Oil and Gas	$	346,199		$	453,052
Accumulated depreciation, depletion, & amortization, and valuation allowances		(85,179	)		(192,917	)
Net capitalized costs	$	261,020		$	260,135

Results of Operation

	As of December 31,
	2009			2008
Sales of oil and gas	$	112,237		$	395,474
Production costs		(42,576	)		(54,218	)
Depreciation, depletion and amortization		(24,961	)		(66,468	)
Unsuccessful Exploration Costs		(30,933	)		-
Results of producing activities	$	13,767		$	274,788

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Supplemental Reserve Information

	2009						2008
	Oil (bbl) [1]			Gas Mcf)			Oil (bbl) [1]			Gas Mcf)
Proved developed and undeveloped reserves
Beginning of year		7,470			217,360			15,768			174,510
Revision in previous estimates		2,434			21,519			(7,417	)		-
Sales of Minerals in Place		(5,372	)		(15,420	)		-			-
Extensions and discoveries		-			180,022			-			79,091
Production		(373	)		(25,576	)		(881	)		(36,241	)
End of year		4,159			377,905			7,470			217,360
Proved developed reserves
Beginning of year		5,512			125,110			12,059			77,550
End of year		4,028			312,784			5,512			125,010

[1] Includes natural gas liquids expressed in bbls.

NOTE 18 – Subsequent Events

On January 4, 2010, we sold our remaining 250,000 shares of common stock in Meridian Resources Corporation and realized an approximate loss of $654 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.

On February 11, 2010, the SEC approved the S1 filing submitted by Southfield Energy Corporation to become a fully public reporting company.  The initial public offering by Southfield Energy Corporation in the public domain is in the amount of $10,000,000.

On March 24, 2010, Ben Roberts, Tyson Rohde, and Goldbridge Consulting each made loans to the Company for $1,300. The loans have been evidenced by short terms notes due in 90 days with no accompanying interest. The loans are general obligations of the Company and do not contain any first liens on the Company’s assets or liquidation preferences.

The Company evaluated all subsequent events through the audit report date. No material events came to our attention from the report date to the date these financial statements were issued.

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Item 9.

Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered in this report, our disclosure controls and procedures were not effective to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the required time periods and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Our management, including our principal executive officer and principal financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Due to the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. To address the material weaknesses, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this annual report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. We have identified the following material weaknesses.

1.) As of December 31, 2009, we did not maintain effective controls over the control environment. Specifically we have not developed and effectively communicated to our employees its accounting policies and procedures. This has resulted in inconsistent practices. Further, the Board of Directors does not currently have any independent members and no director qualifies as an audit committee financial expert as defined in Item 407(d)(5)(ii) of Regulation S-B. Since these entity level programs have a pervasive effect across the organization, management has determined that these circumstances constitute a material weakness.

2.) As of December 31, 2009, we did not maintain effective controls over financial statement disclosure. Specifically, controls were not designed and in place to ensure that all disclosures required were originally addressed in our financial statements. Accordingly, management has determined that this control deficiency constitutes a material weakness.

Because of these material weaknesses, management has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2009, based on the criteria established in "Internal Control-Integrated Framework" issued by the COSO.

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Change In Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our last fiscal year that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  

Attestation Report of the Registered Public Accounting Firm

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the SEC that permit us to provide only management’s report in this annual report.

Item 9B.

Other Information

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PART III

Item 10.

Directors, Executive Officers, Promoters and Control Persons and Corporate Governance; Compliance with Section 16(a) Of The Exchange Act

As of December 31, 2009, the directors and executive officers and their positions, are as follows:

Name	Age	Position
Ben Roberts	64	President, CEO and Director
Chet Gutowsky	63	CFO and Director
Tyson Rohde	29	COO, Director and Secretary

None of our directors or executive officers is currently a director of any company that files reports with the SEC, except as described below. None of our directors have been involved in any bankruptcy or criminal proceeding (excluding traffic and other minor offenses), nor has been enjoined from engaging in any business. Our directors are elected at the annual meeting of stockholders and hold office until their successors are duly elected and qualified. Officers are appointed by our Board of Directors and serve at the pleasure of the Board and are subject to employment agreements, if any, approved and ratified by the Board.

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 Goldbridge 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.  Mr. Rohde holds a B.A. in Economics from the University of Texas.

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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 filing, 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.

55

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 and the rules there under require our officers and directors, and persons who beneficially own more than ten percent of our common stock to file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with copies. To our knowledge, no person required to file such a report failed to file a required report with respect to the fiscal year covered by this report.

Code of Ethics

The Company has adopted a code of ethics applicable to our Chief Executive Officer, Chief Financial Officer, controller, our other employees, and our suppliers. This code is intended to promote honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships; full, fair, accurate, timely, and understandable disclosure in reports and documents that we file with, or submit to the SEC and in other public communications that we make; compliance with applicable governmental laws, rules and regulations; the prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and accountability for adherence to the code. A copy of our code of ethics is included as an exhibit to this Form 10-K.  The Company will provide a copy of our code of ethics, without charge, to any person who requests it. In order to request a copy of our code of ethics, please contact our headquarters and speak with our investor relations department.

Procedure for Nominating Directors

We have not made any material changes to the procedures by which security holders may recommend nominees to our board of directors.

The board does not have a written policy or charter regarding how director candidates are evaluated or nominated for the board. Additionally, the board has not created particular qualifications or minimum standards that candidates for the board must meet. Instead, the board considers how a candidate could contribute to the Company's business and meet the needs of the Company and the board.

The board will consider candidates for director recommended by our shareholders. Candidates recommended by shareholders are evaluated with the same methodology as candidates recommended by management or members of the board. To refer a candidate for director, please send a resume or detailed description of the candidate's background and experience with a letter describing the candidate's interest in the Company to 1240 Blalock Rd., Suite 150, Houston, TX 77055. All candidate referrals are reviewed by at least one current board member.

Significant Employees

Jonathan Gilchrist. Mr. Gilchrist is a co-founder and former Chairman of Southfield Energy. On June 16, 2007 Mr. Gilchrist resigned as Chairman and has been providing business development and financial services to the Company since his resignation as Chairman. For the last five years Mr. Gilchrist has served as a principal for Goldbridge Capital, LLC.

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:

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· 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.

57

Item 11.

Executive Compensation

DIRECTOR AND EXECUTIVE OFFICER COMPENSATION

Summary Compensation Table

NAME AND PRINCIPAL POSITION	FISCAL YEAR	SALARY ($)		BONUS ($)		STOCK AWARDS ($)		ALL OTHER COMPENSA TION ($)(1)			TOTAL ($)
Ben Roberts	2009	$	24,000	$	—	$	—	$	4,540		$	28,540
Chief Executive Officer and	2008		12,000		—		—		2,327	(2)		14,327
Director	2007		—		—		—		—			—
Chet Gutowsky	2009	$	84,000	$	3,000	$	—	$	4,531		$	91,531
Chief Financial Officer and	2008		66,000		—		—		2,318	(2)		68,318
Director	2007		14,600		—		—		—			14,600
Tyson Rohde	2009	$	84,000	$	3,000	$	—	$	4,723		$	91,723
Chief Operating Officer,	2008		66,000		—		—		2,497	(2)		68,497
Director and Secretary	2007		14,600		—		—		—			14,600

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

(2) Above benefits were administered commencing July 2008.

(3) One-time bonuses of $3,000 were paid to Mr. Gutowsky and Mr. Rohde for outstanding business development efforts.

Incentive Plans

No deferred compensation or long-term incentive plan awards were issued or granted to our management during the last three 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.

58

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, 2009.  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, 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 determining the amounts of compensation required to retain the services of the company’s executives.

The Company paid each Messrs. Gutowsky and Rohde a one-time $3,000 bonus in 2009 for outstanding efforts related to business development. Aside from these bonuses, 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.

59

Director Compensation

The following table sets forth a summary of the compensation earned by our directors and/or paid to certain of our directors in 2009:

Director Compensation Table (2009)

Name

Fees Earned or paid in cash

Stock awards

Option Awards

Non-equity Deferred comp. earnings

Non-qualified Deferred comp. earnings

All other

Total

Ben Roberts

$

––

$

––

$

––

$

––

$

––

$

––

$

––

Chet Gutowsky

––

––

––

––

––

––

––

Tyson Rohde

––

––

––

––

––

––

––

Our board of directors is comprised of Ben Roberts, Chet Gutowsky and Tyson Rohde who also serve as officers of the Company. None of our directors has a compensation arrangement with the Company and have not been compensated since the Company’s inception in 2005.

Compensation Committee Interlocks and Insider Participation

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.  Both Mr. Gutowsky and Mr. Rohde participated in deliberations concerning the compensation paid to executive officers during the year 2009, including Messrs. Gutowsky and Rohde. 

Item 12.

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.

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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.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

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 $36,814 and $25,000 in rent expense for 2009 and 2008, 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.

On March 24, 2010, Ben Roberts, Tyson Rohde, and Goldbridge Consulting each made loans to the Company for $1,300. The loans have been evidenced by short term notes due in 90 days with no accompanying interest. The loans are general obligations of the Company and do not contain any first liens on the Company’s assets or liquidation preferences.

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.

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Director Independence

During the year ended December 31, 2009, Ben Roberts, Chet Gutowsky, and Tyson Rohde served as our directors.  

As our common stock is not currently traded on an exchange or quoted on an automated quotation system, we are not subject to the rules of any national securities exchange which require that a majority of a listed company’s directors and specified committees of the board of directors meet independence standards prescribed by such rules.

Item 14.

Audit Fees

We paid M&K CPAS, PLLC audit and review fees of $34,000 for 2009 related to the audit and review of our financial statements and registration statement. For 2008, we paid approximately $25,000 for audit and audit-related fees.

Audit-Related Fees.

None.

Tax Fees.

We paid M&K CPAS, PLLC $800 for professional services related to tax preparation, filing and compliance for the tax year 2008. We have not incurred any fees for services related to 2009 tax filings as of the date of this report.

All Other Fees.  

None.

Audit Committee pre-approval policies and procedures. The entire Board of Directors, which acts as our audit committee, approved the engagement of M&K, CPAS, PLLC.

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Item 15.

Exhibits, Financial Statement Schedules, Signatures

Exhibit No.	Description of Exhibit
3.1	Articles of Incorporation, as filed July 05, 2005 (included as Exhibit 3.1 to the Form S-1 filed September 19, 2009, and incorporated herein by reference).
3.2	Bylaws (included as Exhibit 3.2 to the Form S-1 filed September 19, 2009, and incorporated herein by reference).
4.1	Southfield Trust Indenture (included as Exhibit 4.1 to the Form S-1A filed December 17, 2009, and incorporated herein by reference)
4.2	Book Entry Specimen 3 Year 10% Note (included as Exhibit 4.2 to the Form S-1A filed November 2, 2009, and incorporated herein by reference).
10.1	Mary King Estell Lease Assignment (included as Exhibit 10.1 to the Form S-1A filed November 2, 2009, and incorporated herein by reference).
10.2	Durango Letter Agreement (included as Exhibit 10.2 to the Form S-1A filed November 2, 2009, and incorporated herein by reference).
10.3	B D Production Co., Inc. Letter Agreement (included as Exhibit 10.3 to the Form S-1A filed November 2, 2009, and incorporated herein by reference).
10.4	Aldwell Unit Purchase Letter Agreement and Assignment (included as Exhibit 10.4 to the Form S-1A filed November 2, 2009, and incorporated herein by reference).
10.5	Listing Agreement with Oil & Gas Asset Clearinghouse and Assignment (included as Exhibit 10.5 to the Form S-1A filed November 2, 2009, and incorporated herein by reference).
10.6	Form of Subscription Agreement (included as Exhibit 10.6 to the Form S-1A filed December 17, 2009, and incorporated herein by reference).
14.1	Corporate Code of Ethics (filed herewith).
23.1	Consent of Netherland, Sewell & Associates (filed herewith)
31.1	Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2	Certification of Chief Financial Officer and Treasurer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.1	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.2	Certification of Chief Financial Officer and Treasurer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
99.1	Engineering Report Summary Letter of Netherland, Sewell & Associates, Inc. (filed herewith)

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SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Southfield Energy Corp.
Date: April 8, 2010	By:	/s/ Ben Roberts
		Ben Roberts
		President and Chief Executive Officer

In accordance with the Exchange Act, this report has been duly signed by the following persons on behalf of the Company and in the capacities and on the dates indicated.

/s/ Ben Roberts
Ben Roberts	Date: April 8, 2010
Director
/s/ Chet Gutowsky
Chet Gutowsky	Date: April 8, 2010
Director
/s/ Tyson Rohde
Tyson Rohde	Date: April 8, 2010
Director

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