Treaty Energy Corp (Form: 10-K, Received: 06/13/2012 11:30:59)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

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

EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

Commission file number 000-28015

TREATY ENERGY CORPORATION

(Name of Small Business Issuer in Its Charter)

NEVADA		86-0884116
(State or other jurisdiction of incorporation or organization)		(Employer Identification No.)

201 St. Charles Ave., Suite 2558

New Orleans, LA 70170

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

(504) 599-5684

(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 o 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 o 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 o

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. o

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

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o	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 o 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. Based on the closing sale price on June 6, 2012 ($0.035 per share), the aggregate market value of the voting common stock held by non-affiliates (656,426,019) is $22,974,911.

State the number of shares outstanding of each of the registrant’s classes of common stock as of June 6, 2012: 746,449,069.

Documents Incorporated by reference: None.

TREATY ENERGY CORPORATION

FORM 10-K

For the Year Ended December 31, 2011

TABLE OF CONTENTS

PART 1 – Financial Information		3

Item 1.	Business Factors	3
Item 1A.	Risk Factors	6
Item 1B.	Unresolved Staff Comments	7
Item 2.	Properties	8
Item 3.	Legal Proceedings	8
Item 4.	Submission of Matters to a Vote of Security Holders	8

PART II - Other Information		9

Item 5.	Market for Common Equity and Related Stockholder Matters	9
Item 6.	Selected Financial Data	11
Item 7 .	Management’s Discussion and Analysis and Plan of Operation	11
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	15
Item 8.	Financial Statements and Supplemental Data	16
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	51
Item 9A.	Controls and Procedures	51
Item 9B.	Other Information	52

PART III

Item 10.	Directors, Executive Officers, Promoters and Control Persons and Corporate Governance; Compliance with Section 16(a) Of The Exchange Act	52
Item 11.	Executive Compensation	55
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	57
Item 13.	Certain Relationships and Related Transactions, and Director Independence	57
Item 14.	Principal Accountant Fees and Services	58
Item 15.	Exhibits, Financial Statement Schedules, Signatures	59

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

Treaty Energy Corporation, formerly known as Alternate Energy Corp., (“Treaty”, “the Company”, “we”, or “us”) was incorporated as COI Solutions, Inc. in the State of Nevada in August, 1997.

We incorporated as COI Solutions, Inc. on August 1, 1997 as a Nevada corporation. On May 22, 2003, we acquired all the assets of AEC I Inc., formerly known as Alternate Energy Corporation, and changed our name to Alternate Energy Corp. We commenced active business operations on June 1, 2003 and were a exploration stage company under Codification Topic No. 915 developing alternate renewable energy sources.

The Company merged with Treaty Petroleum, Inc., a Texas Corporation under a transaction commonly referred to as a reverse merger. With the change in ownership in December 2008, we embarked on a new business plan, focusing on oil and gas production.

We are a crude oil and natural gas producing company.

Our Business

Treaty is in the business of acquiring oil and gas properties with production capabilities and proven reserves.

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.

Our operations 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.

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 routine oil and natural gas operations, surface spills and leaks, including casing leaks of oil or other materials may occur, and we may incur 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. Moreover, we are able to control directly the operations of only those wells for which we act as the operator. 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 the process of achieving substantial 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.

Employees

Treaty Energy Corporation has no employees. All services are currently done through contracted vendors.

ITEM 1A. RISK FACTORS

An investment in our common stock 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. If any of the following risks actually occur, our business, financial condition or results of operations could be materially and adversely affected.

Risks Related to Our Business

Oil Prices

Oil prices are volatile. A substantial decrease in oil prices would significantly affect our business and impede our growth.

Our revenues, profitability and future growth depend upon prevailing oil prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil that we can economically produce. It is possible that prices will be low at the time periods in which the wells are most productive, thereby reducing overall returns. It is possible that prices will drop so low that production will become uneconomical. If production becomes uneconomical, we may decide to discontinue production until prices improve.

Prices for oil fluctuate widely. The prices for oil are subject to a variety of factors beyond our control, including:

●	the level of consumer product demand;

●	weather conditions;

●	domestic and foreign governmental regulations;

●	the price and availability of alternative fuels;

●	political conditions in oil producing regions;

●	the domestic and foreign supply of oil;

●	speculative trading and other market uncertainty; and

●	worldwide economic conditions.

The failure to develop reserves could adversely affect our production and cash flows.

Our success depends upon our ability to find, develop or acquire oil and natural gas reserves that are economically recoverable. We will need to conduct successful exploration or development activities or acquire properties containing proved reserves, or both. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investment to expand our oil and natural gas reserves from cash flows, and external sources of capital may be limited or unavailable. Our drilling activities may not result in significant reserves, and we may not have continuing success drilling productive wells. Exploratory drilling involves more risk than development drilling because exploratory drilling is designed to test formations in which proved reserves have not been discovered. Additionally, while our revenues may increase if prevailing gas prices increase significantly, our finding costs for reserves also could increase, and we may not be able to finance additional exploration or development activities.

We may have difficulty financing our planned growth.

We will require substantial additional financing to fund our planned growth. Additional financing may not be available to us on acceptable terms or at all. If additional capital resources are unavailable, we may be forced to curtail our acquisition, development drilling and other activities or to sell some of our assets on an untimely or unfavorable basis. We are in the process of evaluating strategic alternatives as of the date of this report.

Our current operating activity is concentrated in Texas and Belize. As a result, we may be disproportionately exposed to the impact of drilling and other delays or disruptions of production from these regions caused by weather conditions, governmental regulation, lack of field infrastructure, or other events which impact this area.

We may continue to incur losses.

We reported a net loss attributable to Treaty shareholders for the years ended December 31, 2011 and 2010 of $7,149,202 and $769,679, respectively. There is no assurance that we will be able to achieve and maintain profitability.

Our oil and natural gas reserve data are estimates based on assumptions that may be inaccurate and existing economic and operating conditions that may differ from future economic and operating conditions.

●

Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based upon assumptions that may change from year to year and vary considerably from actual results. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Information regarding discounted future net cash flows should not be considered as the current market value of the estimated oil and natural gas reserves that will be attributable to our properties. Examples of items that may cause our estimates to be inaccurate include, but are not limited to, the following:

●	The estimated discounted future net cash flows from proved reserves are based on twelve-month average prices and costs , while actual future prices and costs may be materially higher or lower;

●	Because we have limited operating cost data to draw upon, the estimated operating costs used to calculate our reserve values may be inaccurate;

●	Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation;

●

Our reserve report for our producing properties assumes that production will be generated from each well for a period of 15 years. Because production is expected for such an extended period of time, the probability is enhanced that conditions at the time of production will vary materially from the current conditions used to calculate future net cash flows; and

●

The 10% discount factor, which is required by the Financial Accounting Standards Board to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks that will be associated with our operations or the oil and natural gas industry in general.

We may incur non-cash charges to our operations as a result of current and future financing transactions.

Under current accounting rules and requirements, we may incur additional non-cash charges to future operations beyond the stated contractual interest payments required under our current and potential future credit facilities. While such charges are generally non-cash, they would impact our results of operations and earnings per share and could be material.

ITEM 1B. UNRESOLVED STAFF COMMENTS

The registrant is not an accelerated filer and is therefore not required to complete this section.

ITEM 2. PROPERTIES

Our administrative offices are located at 201 St. Charles Ave., Suite 2558, New Orleans, LA 70170.

ITEM 3. LEGAL PROCEEDINGS

On January 29, 2010, a lawsuit ( Highground et al. versus Ronald L. Blackburn et al. )was filed in the 22nd Judicial District Court, Parish of St. Tammany, Louisiana naming Treaty Energy Corporation, among others, as a defendant.

The lawsuit alleges certain wrongdoings by the defendants (other than Treaty) which have no bearing on our operations since inception. The lawsuit also alleges certain monies owed to some of the plaintiffs by the Company.

On March 11, 2010, we filed a Notice of Removal of the state action to the United States District Court, Eastern District of Louisiana, based upon the diversity of all the parties. The case has been moved to the United States District Court.

On April 11, 2010, the defendants filed a countersuit against the plaintiffs seeking damages against Highground, et al based on misrepresentation of the Crockett County, Texas leases.

Several of the defendants in the lawsuit filed for bankruptcy protection. On April 30, 2010, the case was moved to the US Bankruptcy Court for the Eastern District of Louisiana, Section B.

Treaty was dismissed from this lawsuit in June of 2012. The dismissal may be appealed however no appeal has been filed at this time.

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. Other than the litigation described above, we are not aware of any pending or threatened litigation against us or our officers and directors in their capacity as such that could 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 2011.

PART II - Other Information

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market Information

Our shares currently trade on the electronic OTCMarkets (OTC.BB), a regulated quotation service, under the symbol " TECO ." Listed below are the highest and lowest bid prices for our common stock for each calendar quarter for 2011 and 2010 as reported on the OTCBB, and represents inter-dealer quotations, without retail markup, markdown, or commission and may not be reflective of actual transactions.

Quarter Ended	High		Low

March 31, 2011	$	0.014	$	0.008
June 30, 2011		0.077		0.014
September 30, 2011		0.069		0.035
December 31, 2011		0.058		0.033

March 31, 2010	$	0.026	$	0.006
June 30, 2010		0.023		0.010
September 30, 2010		0.015		0.010
December 31, 2010		0.014		0.007

At December 31, 2011, there were 746,449,069 shares of our common stock issued and outstanding.

Holders

As of December 31, 2011, we had approximately 1,490 shareholders of record, including common shares held by brokerage clearing houses, depositories, or otherwise in unregistered form. We estimate that there are a total of about 6,500 shareholders.

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

On February 23, 2011 Treaty Energy adopted a stock option plan that is accounted for based on Accounting Standards Codification No. 718, Compensation – Stock Compensation . The plan allows the Company to grant stock and options to persons employed or associated with the Company, including, without limitation, any employee, attorney, accountant, consultant or advisor up to an aggregate of 10,000,000 common shares.

During the year ended December 31, 2011, we issued 99,776,623 shares under this plan and had 223,377 shares remaining.

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

The following is a list of unregistered sales of securities for the year ended December 31, 2011. For the accounting treatment of these issuances, see Note 7 to the financial statements.

●	On February 14, 2011, we issued 10,296,609 shares for cash and received $60,750.

●	On March 16, 2011, we issued 4 million shares to a previous director.

●	On April 6, 2011 we issued 1.5 million shares to a consultant for commissions on our Belize acquisition.

●	On April 8, 2011, we issued 6 million shares to the seller of one of our Texas acquisitions (see Note 5). .

●	On May 10, 2011, we issued 3.2 million shares for conversion of tranches 1 and 2 associated with our Texas leases.

●	On May 12, 2011, we issued 1 million shares to our President and Chief Operating Officer as a signing bonus.

●	On June 22, 2011, we issued 2,367,886 to certain creditors of a company controlled by our Chairman and Chief Executive Officer, Andrew Reid.

●	Also on June 22, 2011 we issued 11 million shares to the same company controlled by our Chairman and Chief Executive Officer, Andrew Reid in conversion of the outstanding balance of $664,190.

●	Also on June 22, 2011, we issued 2.5 million shares to two creditors who loaned us money to acquire the leases in Tennessee to convert their debt balances to equity.

●	Also on June 30, 2011, we issued 8.25 million shares to convert certain notes payable for debts we owed in connection with our Tennessee and Belize acquisitions.

●	Also on June 22, 2011, we issued 450,000 shares in connection with our acquisition of certain heavy equipment.

●	Also on June 22, 2011, we issued 5,670,000 shares to several accredited investors for $137,000 in cash.

●	Also on June 22, 2011, we issued an affiliate 77,258,753 shares as reimbursement for personal shares the affiliate used in various deals in Belize, Tennessee, Louisiana and Texas.

●	On July 1, 2011, we contracted to provide a broker with 20,000,000 shares at a discounted price over a period of nine months. On the same date, we issued 11,000,000 million of those shares from Treasury stock that we acquired from a related party.

●	On July 13, 2011, we issued 1,530,000 shares to various consultants for services.

●	Also on July 13, 2011, we issued 2,000,000 shares to a consultant for services.

●	On June 25, 2011, the Company issued 2,625,000 shares to convert related party liabilities owed of $105,000.

●	Also on July 13, 2011, we issued 2,090,119 shares to various investors who paid a total of $48,000.

●	On July 19, 2011, the Company issued 8,625,000 shares to convert the acquisition liability owed to C&C Petroleum of $285,000.

●	Also on July 19, 2011, the Company issued 500,000 shares to a consultant for services.

●	Also on July 19, 2011, we issued 76,548 shares to an investor who paid $2,000.

●	On August 12, 2011, we issued 1,400,000 shares to an individual for both cash payments and reduction of an advance.

●	Also on August 12, 2011, we issued 23,912 shares to a vendor who had provided services to a related party.

●	Also on August 12, 2011, we issued 3,068,165 shares to investors who had paid a cash total of $98,000.

●	On August 16, 2011, we issued 1,750,000 shares to a consultant for services.

●	On November 30, 2011, we issued 350,000 shares to a consultant for services.

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 consolidated financial statements and notes thereto, and other financial information included elsewhere in this Form 10-K. This report contains forward-looking statements that involve risks and uncertainties. Actual results in future periods may differ materially from those expressed or implied in such forward-looking statements as a result of a number of factors, including, but not limited to, the risks discussed under the heading "Risk Factors" and elsewhere in this Form 10-K.

Overview

Critical Accounting Policies, Estimates and New Accounting Pronouncements

Management's discussion and analysis of its financial condition and plan of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. At each balance sheet date, management evaluates its estimates. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The estimates and critical accounting policies that are most important in fully understanding and evaluating our financial condition and results of operations include those stated in our financial statements and those listed below:

Going Concern

The accompanying financial statements have been prepared assuming that Treaty will continue as a going concern. As shown in the accompanying financial statements, we had negative cash flows from operations of $1,472,153 in 2011 and $330,851 in 2010, and a working capital deficit of $2,081,092 at December 31, 2011. 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 making additional shareholder notes and seeking additional outside financing through either debt or sales of its common stock.

Recently Adopted Accounting Standards

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. This update defers the requirement to present items that are reclassified from accumulated other comprehensive income to net income in both the statement of income where net income is presented and the statement where other comprehensive income is presented. The adoption of ASU 2011-12 is not expected to have a material impact on our financial position or results of operations.

In September 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-08, Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment. The guidance in ASU 2011-08 is intended to reduce complexity and costs by allowing an entity the option to make a qualitative evaluation about the likelihood of goodwill impairment to determine whether it should calculate the fair value of a reporting unit. The amendments also improve previous guidance by expanding upon the examples of events and circumstances that an entity should consider between annual impairment tests in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Also, the amendments improve the examples of events and circumstances that an entity having a reporting unit with a zero or negative carrying amount should consider in determining whether to measure an impairment loss, if any, under the second step of the goodwill impairment test. The amendments in this ASU are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011, if an entity’s financial statements for the most recent annual or interim period have not yet been issued. The adoption of this guidance is not expected to have a material impact on the Company’s financial position or results of operations.

In June 2011, the FASB issued ASU 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income”, which is effective for annual reporting periods beginning after December 15, 2011. ASU 2011-05 will become effective for the Company on January 1, 2012. This guidance eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. In addition, items of other comprehensive income that are reclassified to profit or loss are required to be presented separately on the face of the financial statements. This guidance is intended to increase the prominence of other comprehensive income in financial statements by requiring that such amounts be presented either in a single continuous statement of income and comprehensive income or separately in consecutive statements of income and comprehensive income. The adoption of ASU 2011-05 is not expected to have a material impact on our financial position or results of operations.

In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”, which is effective for annual reporting periods beginning after December 15, 2011. This guidance amends certain accounting and disclosure requirements related to fair value measurements. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements, quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a nonfinancial asset that is different from the asset’s highest and best use, the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required, the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 will become effective for the Company on January 1, 2012. The adoption of ASU 2011-04 is not expected to have a material impact on our financial position or results of operations.

In April 2011, the FASB issued ASU 2011-02, “Receivables (Topic 310): A Creditor’s Determination of Whether a Restructuring is a Troubled Debt Restructuring”. This amendment explains which modifications constitute troubled debt restructurings (“TDR”). Under the new guidance, the definition of a troubled debt restructuring remains essentially unchanged, and for a loan modification to be considered a TDR, certain basic criteria must still be met. For public companies, the new guidance is effective for interim and annual periods beginning on or after June 15, 2011, and applies retrospectively to restructuring occurring on or after the beginning of the fiscal year of adoption. The adoption of ASU 2011-02 is not expected to have a material impact on our financial position or results of operations.

Results of Operations – Comparison of Years Ended December 31, 2011 versus 2011

Revenues

In 2011, we recorded $116,241 of revenues versus only $448 in 2010. The difference is made up of our production in the Texas leases, all acquired during 2011.

Expenses

Depreciation, Amortization and Depletion

Depreciation, amortization and depletion increased significantly in 2011 versus 2010 ($185,199 versus $125, respectively) because we depleted a significant portion of the oil reserves in our Texas leases.

Lease Operating Expenses

Our lease operating expenses are up significantly from 2010, $766,280 versus $460,137, principally due to the operation of our Texas leases.

General and Administrative Expenses

Our general and administrative expenses increased from $559,298 in 2010 to $4,399,624 for the same period in 2011. Of this increase, $2,963,393 was due to non-cash stock-based compensation. The remainder, $1,436,231 is up from 2010 due to additional activity in Belize and Texas.

Interest Expense

Our interest expense is significantly higher in 2011 versus 2010 ($115,728 versus $42,540), principally due to higher debt levels.

Cost of Drilling Operations

We acquired drilling equipment during 2011 and began drilling operations during 2011 in our subsidiary, Treaty Energy Drilling. Although we had no revenues for the year ended December 31, 2011, we had drilling operations costs of $82,497 for which we had no counterpart during 2010.

Transportation Costs and Production Taxes

Transportation and Production Taxes ($11,203 and $5,069, respectively) represent costs for which there was no counterpart in 2010 since we began producing from the Texas leases only during 2011.

Impairment of Oil and Gas Properties

We impaired $354,872 of costs from our oil and gas capitalized costs during 2011 whose future expected cash flows did not support their carrying values. We had no counterpart in 2010.

Accretion of Asset Retirement Obligations

We accreted $2,030 of asset retirement obligations, principally on our Texas leases. We had no counterpart in 2010.

Other Income and Expense Items

We had several items affecting Other Income and Expense, collectively totaling a loss of $1,519,438 for the year ended December 31, 2011 versus a collective gain of $249,433 during 2010. The principal reason for the difference of $1,768,871 was a loss on retirement of debt of $1,465,644 almost entirely from reduction of debt using common stock whose value on the date of settlement exceeded the nominal amount of the debt by that amount.

Net Loss

Our net loss increased for the year ended December 31, 2011 (a net comprehensive loss attributable to Treaty shareholders of $7,148,812) from the same period in 2010 (a net loss of $769,679) for the reasons set forth above.

Liquidity and Capital Resources

Our financial statements have been prepared on a going concern basis that contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business.

Currently, we are not able to maintain our existing operations through the existing cash balances and internally generated cash flows from sales of oil production. Moreover, we have determined that our existing capital structure is not adequate to fund our planned growth. We intend to finance our drilling, workover and acquisition program by issuing additional common stock and through loans from our shareholders. There can be no assurance that we will be successful in procuring the financing we are seeking. Future cash flows are subject to a number of variables, including the level of production, natural gas prices and successful drilling efforts. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.

Plan of Operation

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

Texas Projects

Treaty Energy Corporation has completed the funding for their 9 well and 12 well drilling packages on existing leaseholds. The total amount of both these projects, which has now been fully funded, is $2.2 million. The first 12 well project had previously been secured and the same investor group came back to complete the funding for both of these programs. The 12 well program will be drilled to depths of 600-900 ft. With production estimated to be 20-30 BOPD per well, while the deeper 9 well program will be drilled to depths of 2600 ft. to 3000 ft. and production is expected to be between 30-100 BOPD per well.

Treaty Energy has purchased a Wilson Mogul S/D Drilling Rig (the “Wilson Rig”) capable of drilling to 7500 ft. which will be used to drill all of the 9 wells on this current project. Mr. Steve York, President and Chief Operating Officer of Treaty Energy, has also stated that this rig has been contracted to drill 10 wells for an independent operator after the 9 well program is completed. Once these projects are completed and producing, Treaty plans on setting up a drilling program for the Ellenberger zone on several of our existing leases. The Ellenberger is one of the most prolific oil producing zones in Texas history, with successful wells typically producing 800 to 1,500 barrels per day.

Treaty’s existing Failing 2000 ft. rig that has been transported back from Belize will be drilling the 12 well project. This drilling project was begun during May, 2012.

Now that the funding has been secured for both of Treaty Energy’s current 12 well program and the 9 well program, and the drilling rig has been secured for the 9 well program, Treaty will have the ability to drill these two drilling programs simultaneously. Once drilling starts, Treaty will endeavor to fulfill its goal of maximizing production in Texas.

The Belize Project

Treaty Belize Energy Ltd., a subsidiary of Treaty Energy Corporation has drilled it 1st well, the San Juan #2, to 1,300 ft. Once the well is cleared of all debris it will be wire line logged. If that proves positive then the well will be completed and production is estimated to come in up to 50 barrels a day. All the pipe, casing, rods, mud pump, pump jack, chemicals and cement are already on route to Belize for the completion of San Juan #2 and moving forward to drill San Juan #1. Treaty has also purchased a water truck for the Belize operation costing $40,000.

The Shramm rig stationed in Belize has completed its scheduled maintenance and now is ready to continue drilling.

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			17
Balance Sheets – December 31, 2011 and 2010			18
Results of Operations for the years ended December 31, 2011 and 2010 and for the period from re entry to the Exploratory Stage (July 1, 2009) to December 31, 2011			19
Statement of Changes in Stockholders’ Deficit from December 31, 2008 to December 31, 2011			20
Statements of Cash Flows for the years ended December 31, 2011 and 2010 and for the period from re entry to the Exploratory Stage (July 1, 2009) to December 31, 2011			21
Notes to Financial Statements			22

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Treaty Energy Corporation

(An Exploratory Stage Company)

We have audited the accompanying balance sheets of Treaty Energy Corporation, (an Exploratory Stage Company) as of December 31, 2011 and 2010 and the related statements of operations, changes in stockholders' deficit, and cash flows for the years then ended, and for the period from re entry to the Exploratory Stage (July 1, 2009) to December 31, 2011. 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 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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 Treaty Energy Corporation as of December 31, 2011 and 2010, and the results of its operations, changes in stockholders' deficit and cash flows for the periods noted 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 3 to the financial statements, the Company had negative cash flows from operations and a working capital deficit as of December 31, 2011, which raises substantial doubt about its ability to continue as a going concern. Management's plans regarding those matters also are described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ M&K CPAS, PLLC

Houston, Texas

www.mkacpas.com

June 11, 2012

TREATY ENERGY CORPORATION

(An Exploratory Stage Company)

Consolidated Balance Sheets

As of December 31, 2011 and 2010

	December 31, 2011			December 31, 2010

ASSETS

Cash and equivalents	$	14,716		$	148
Accounts receivable		23,438			-
Total current assets		38,154			148

Oil and gas properties - proved (successful efforts method)		105,494			-
Oil and gas properties - unproved		48,075			212,448
Oilfield support equipment		1,141,701			40,101
Less: accumulated depreciation, depletion and amortization		(125,439	)		(125	)
Net oil and gas properties		1,169,831			252,424

Other property, plant and equipment, net of accumulated depreciation of $53,135 and $0 at December 31, 2011 and 2010, respectively		494,473			1,759
Other assets		65,363			-
Carved out interests, net of accumulated amortization of $3,879 and $0 at December 31, 2012 and 2011, respectively		76,005			-

TOTAL ASSETS	$	1,843,826		$	254,331

LIABILITIES

Accounts payable and accrued liabilities	$	742,612		$	469,775
Notes and accrued interest to related parties		-			298,722
Notes and accrued interest payable, net of discounts of $3,984 and $0, respectively		829,095			717,202
Total current liabilities		1,571,707			1,485,699

Asset retirement obligation		130,397			-
Deferred revenue		545,507			-

Total non-current liabilities		675,904			-

TOTAL LIABILITIES		2,247,611			1,485,699


COMMITMENTS AND CONTINGENCIES

Class A convertible preferred shares, 36,000 shares authorized, 12,000 and 0 shares issued and outstanding at December 31, 2011 and 2010, respectively.		60,000			-

STOCKHOLDERS' DEFICIT AND NON-CONTROLLING INTERESTS

Preferred stock - par value $0.001, 50 million shares authorized, none issued or outstanding at December 31, 2011		-			-
Common stock – par value $0.001, 750 million shares authorized. 746,449,069 and 496,605,424 shares issued and 737,446,069 and 496,605,424 shares outstanding at December 31, 2011 and 2010, respectively.		746,449			496,605
Additional paid in capital		8,730,631			527,483
Common stock payable		85,875			204,000
Treasury stock		(355,500	)		-
Accumulated loss - pre-exploration stage		(644,829	)		(644,829	)
Accumulated loss		(8,963,829	)		(1,814,627	)
Accumulated other comprehensive income		390			-

Total stockholders' deficit attributable to Treaty Energy Corporation shareholders		(400,813	)		(1,231,368	)

Non-controlling interests		(62,972	)		-
Total stockholders' deficit		(463,785	)		(1,231,368	)

TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$	1,843,826		$	254,331

The accompanying notes are an integral part of these financial statements.

TREATY ENERGY CORPORATION

(An Exploratory Stage Company)

Consolidated Statements of Operations

For the Years Ended December 31, 2011 and 2010

And from Re-entry to the Exploratory Stage (July 1, 2009)

to December 31, 2011

							From Re Entry
							to the Exploration
	Year Ended December 31,						Stage
	2011			2010			(7/1/09) to 12/31/11
REVENUES
Sales of oil	$	116,241		$	448			116,689
Total revenues		116,241		$	448			116,689

EXPENSES
Lease operating expenses		766,279			460,137			1,241,599
Cost of drilling operations		82,497						82,497
Transportation costs		11,203			-			10,849
Production taxes		5,069			-			4,717
Impairment of oil and gas properties		354,872			-			766,284
General and administrative		4,399,624			559,298			5,571,425
Depreciation, depletion and amortization		185,199			125			185,324
Accretion of asset retirement obligation		2,030			-			2,030
Total expenses		5,806,773			1,019,560			7,864,725

Operating loss		(5,690,532	)		(1,019,112	)		(7,748,036	)

OTHER INCOME AND EXPENSE ITEMS
Gains / (losses) on dispositions of properties		61,933			291,973			353,906
Gains / (losses) on retirements of debt		(1,465,644	)		-			(1,465,644	)
Interest expense		(115,728	)		(42,540	)		(164,824	)
Interest income		1						1
Net loss		(7,209,970	)		(769,679	)		(9,024,597	)

Less: loss attributable to non-controlling interests		60,768			-			60,768
Net loss attributable to Treaty Energy		(7,149,202	)		(769,679	)		(8,963,829	)
Foreign currency translation gain (loss)		390			-			390
Add: loss attributable to non-controlling interests		(60,768	)		-			(60,768	)
Total comprehensive loss		(7,209,580	)		(769,679	)		(9,024,207	)

Less: comprehensive loss attributable to non-controlling interests		60,768			-			60,768
Comprehensive loss attributable to Treaty Energy		(7,148,812	)		(769,679	)		(8,963,439	)

Net loss per common shares - basic and diluted	$	(0.01	)	$	0.00
Weighted average common shares outstanding - basic and diluted		659,779,623			496,605,424

The accompanying notes are an integral part of these financial statements.

TREATY ENERGY CORPORATION

(An Exploratory Stage Company)

Consolidated Statement of Changes in Stockholders’ Deficit

For the Period from December 31, 2008 to December 31, 2011

	Common Stock				Treasury Stock						Additional Paid In Capital			Common			Pre-Exploration			Exploration			Accumulated Other Comprehensive Income		Non-Controlling Interests
	Shares		Amount		Shares			Amount			Additional Paid In Capital			Stock Payable			Stage Losses			Stage Losses			Accumulated Other Comprehensive Income		Non-Controlling Interests			Total
Balances, December 31, 2008		460,061,553		460,062		-			-			(629,320	)		-			-			(487,587	)		-		-			(656,845	)

Cashless exercise of options		49,148		49								(49	)																-
Cash provided by a related party

Expenses paid on behalf of the Company by a related party:												104,000																	104,000
Paid in cash												61,822																	61,822
Paid in stock												162,695																	162,695

Interest imputed on notes payable												10,090																	10,090
Acquisitions of oil and gas properties		7,000,000		7,000								168,000																	175,000
Stock for services		4,000,000		4,000								48,400																	52,400
Sale of stock for cash		3,000,000		3,000								36,000																	39,000
Officer and director compensation		7,886,776		7,886								316,831																	324,717
Retirement of debt		14,607,947		14,608								197,219																	211,827
Net loss, year ended 12/31/09																		(644,829	)		(557,361	)							(1,202,190	)
																													-
Balances, December 31, 2009		496,605,424		496,605		-			-			475,688			-			(644,829	)		(1,044,948	)		-		-			(717,484	)

Expenses paid by a related party												1,155																	1,155
Interest imputed on notes payable												7,812																	7,812
Vesting of deferred compensation												42,828																	42,828
Stock payable to consultant															204,000														204,000
Net loss, for year ended 12/31/10																					(769,679	)							(769,679	)


Balances, December 31, 2010		496,605,424		496,605		-			-			527,483			204,000			(644,829	)		(1,814,627	)		-		-			(1,231,368	)

Stock issued for:
Cash		21,601,441		21,601								332,148			20,000														373,749
Services		89,031,616		89,032								2,874,361																	2,963,393
Exitnguishment of stock payable		15,000,000		15,000								189,000			(204,000	)													-
Acquisition of oil and gas properties		6,000,000		6,000								77,400																	83,400
Acquisition of equipment		11,283,333		11,283								156,417																	167,700
Extinguishment of debt and interest		76,918,502		76,919								3,168,398																	3,245,317
Reimbursement of shareholder		26,808,753		26,809								(26,809	)																-
Conversion of preferred stock		3,200,000		3,200								116,800																	120,000

Purchase of treasury shares						20,000,000			(790,000	)																			(790,000	)
Sale of treasury shares						(11,000,000	)		434,500			(214,500	)		26,875														246,875
Foregivness of debt												679,948																	679,948
Stock payable related to debt issuance															39,000														39,000
Foregivenss of accrued expenses												91,363																	91,363
Imputed interest												35,853																	35,853
Sale of equity interest in subsidiary												102,204														(2,204	)		100,000
Conversion of related-party debt for over-riding royalty interests												620,565																	620,565
Effect of foreign currency translation																								390					390

Net loss																					(7,149,202	)				(60,768	)		(7,209,970	)

Balance, December 31, 2011		746,449,069	$	746,449		9,000,000			(355,500	)	$	8,730,631		$	85,875		$	(644,829	)	$	(8,963,829	)	$	390	$	(62,972	)	$	(463,785	)

The accompanying notes are an integral part of these financial statements.

TREATY ENERGY CORPORATION

(An Exploratory Stage Company)

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2011 and 2010

And from Re-entry to the Exploratory Stage (July 1, 2009)

to December 31, 2011

							From Re Entry to the
	Year Ended December 31,						Exploration Stage
	2011			2010			(7/1/09) to 12/31/11

CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(7,209,970	)		(769,679	)		(9,024,597	)

Adjustments to reconcile net loss to net cash used in operating activities
Depreciation, depletion and amortization		185,199			125			185,324
(Gain) / loss on sales of oil and gas interests		(61,932	)		(291,972	)		(353,904	)
(Gain) / loss on debt settlements		1,465,644			-			1,465,644
Royalty interests issued for services and interest		15,692			-			15,692
Impairment of oil and gas assets		354,872			-			766,284
Amortization of discounts on notes payable		45,854			21,254			67,108
Amortization of deferred revenue		(27,866	)		-			(27,866	)
Accretion of asset retirement obligation		2,030			-			2,030
Stock based compensation		2,963,393			246,828			3,587,338
Interest imputed on related-party notes		35,853			7,812			47,571

Changes in operating assets and liabilities:
Accounts receivable		(23,438	)		-			(23,438	)
Inventories		34,254			-			34,254
Accounts payable and accrued liabilities		806,945			174,957			1,001,590
Officer and director liabilities		-			257,972			428,364
Interest payable		6,290			15,174			23,804
Prepaid expenses and other		(65,362	)		6,678			(65,362	)

Net cash used in operating activities	$	(1,472,542	)		(330,851	)		(1,870,164	)

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and gas properties		(150,000	)		(235,475	)		(385,475	)
Development of oil and gas properties		(26,984	)		(40,101	)		(67,085	)
Sale of equity interest in subsidiary		100,000			-			100,000
Purchases of other fixed assets		(422,786	)		(1,759	)		(424,545	)
Proceeds from sales of oil and gas properties		166,925			445,000			611,925
Proceeds from sales of ORRI and production		600,000			-			600,000
payment - deferred revenue
Cash received for future purchase option in potential subsidiary		25,000			-			25,000

Net cash provided by investing activities	$	292,155			167,665			459,820

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) to related parties		770,424			46,334			841,733
Proceeds from notes payable		350,000			122,000			472,000
Principal payments on notes payable		(548,465	)		(5,000	)		(553,465	)
Common stock issued for cash		373,749			-			412,749
Sale of treasury shares for cash		246,875			-			246,875
Bank overdraft		1,982			-			1,982

Net cash provided by / (used in) financing activities	$	1,194,565			163,334			1,421,874


Foreign currency translation gain		390			-			390
Net increase / (decrease) in cash and cash equivalents		14,568			148			11,920
Cash and cash equivalents, beginning of period		148			-			2,796
Cash and cash equivalents, end of period	$	14,716		$	148		$	14,716

SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest		17,791			-			17,791
Cash paid for income taxes		-						-

SUPPLEMENTAL DISCLOSURES OF NON-CASH FINANCING ACTIVITIES
Shares issued for retirement of related and non-related debt		3,245,316			-			3,457,143
Common shares issued to acquire equipment and oil and gas properties		251,100			-			426,100
Preferred shares issued for acquisition of oil and gas properties		180,000			-			180,000
Acquisition of oil and gas for promissory note		300,000			-			300,000
Equipment purchases with promissory notes		25,000			-			25,000
Revenue interests issued for related party and non-related party debt relief		765,000			-			765,000
Acquired asset retirement obligations and revisions		129,084			-			129,084
Promissory notes issued for acquisitions of equipment and oil and gas properties		935,581			-			935,581
Company debts paid by related parties		147,000			-			147,000
Common shares issued to extinguish stock payable		204,000			-			204,000
Common shares issued as enticement on promissory note recorded as discount		39,000			-			39,000
Treasury shares purchased with increase in related-party note		790,000			-			790,000
Debt forgiven by related party taken as increase in equity		771,310			-			771,310
Shares issued to reimburse shareholder		26,808			-			26,808
Conversion of preferred stock to common		120,000			-			120,000
Equipment given in exchange for debt relief		69,011			-			69,011
ORRI issued as enticement on promissory notes recorded as discount		1,570			-			1,570
Gains on ORRI related-party sales recorded to Additional Paid in Capital		620,565			-			620,565

The accompanying notes are an integral part of these financial statements.

TREATY ENERGY CORPORATION

(An Exploratory Stage Company)

Notes to Consolidated Financial Statements

Note 1 - Organization and Nature of Business

We incorporated as COI Solutions, Inc. on August 1, 1997 as a Nevada corporation. On May 22, 2003, we acquired all the assets of AEC I Inc., formerly known as Alternate Energy Corporation, and changed our name to Alternate Energy Corp. We commenced active business operations on June 1, 2003 and were an exploration stage company under Codification Topic No. 915 developing alternate renewable energy sources.

We are an oil producing company.

Note 2 - Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation and Consolidation

The financial statements of the Company have been prepared in accordance with Generally Accepted Accounting Principals in the United States. Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries and subsidiaries of which we own a 50% interest or greater.

These consolidated financial statements include the accounts of the parent company Treaty Energy Corporation, the wholly owned subsidiaries: Treaty Energy Drilling, LLC and C&C Petroleum Management, LLC, and the majority owned subsidiary: Treaty Energy Belize, LLC. All intercompany transactions have been eliminated.

Use of Estimates

The preparation of consolidated financial statements in conformity with generally accepted 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates underlying these consolidated financial statements include the estimated quantities of proved oil reserves used to compute depletion of oil and natural gas properties and the estimated fair value of asset retirement obligations.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an initial maturity of 3 months or less to be cash equivalents. The Company’s bank accounts periodically exceed federally insured limits. The Company maintains its deposits with high quality financial institutions and, accordingly, believes its credit risk exposure associated with cash is remote. There were no cash equivalents as of December 31, 2011 and 2010.

Accounts Receivable

Accounts receivable consists of amounts due for the sale of oil. Accounts receivable are evaluated for collectability based upon the financial condition of the customer and the age of the amount due. Amounts due to us for oil and gas receivables were $23,438 and $0 at December 31, 2011 and 2010, respectively.

Oil Producing Properties

We account for our oil producing property costs using the successful efforts accounting method. Under the successful efforts method, lease acquisition costs and intangible drilling and development costs on successful wells and development dry holes are capitalized. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful.

Capitalized proved property acquisition costs are depleted on the unit-of-production method on the basis of total estimated units of proved reserves. Development costs relating to producing properties are depleted on the unit-of-production method on the basis of total estimated units of proved developed reserves. When significant development costs are incurred in connection with a planned group of development wells before all of the planned wells have been drilled, it is occasionally necessary to exclude a portion of those development costs in determining the unit-of-production amortization rate until the additional development wells are drilled. However, in no case are future development costs anticipated in computing our amortization rate. Estimated dismantlement, restoration and abandonment costs are taken into account in determining depreciation, amortization and depletion provisions.

Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

We perform a review for impairment of proved oil producing properties on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our reservoir engineers’ estimate of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ reserves, future cash flows and fair value.

Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization base until the related properties are developed. Unproved properties are assessed quarterly and any impairment in value is charged to impairment expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and gas properties and amortized on a unit-of-production basis.

Oil Reserves

The process of estimating quantities of natural gas and crude oil reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. We use the unit-of-production method to amortize our oil and gas properties. This method requires us to amortize the capitalized costs incurred in developing a property in proportion to the amount of oil and gas produced as a percentage of the amount of proved reserves contained in the property. Accordingly, changes in reserve estimates as described above will cause corresponding changes in depletion expense recognized in periods subsequent to the reserve estimate revision.

Revenue Recognition

Oil revenue is recognized when persuasive evidence of an arrangement exists, our oil is delivered, the fee is fixed and determinable and collectability is reasonably assured.

Sales of Mineral Interests

From time to time we sell over-riding royalty (“ORRI”) and working interests in our properties to raise cash or to settle obligations.

For sales of interests in proved properties, we allocate a portion of the accumulated intangible lease costs, including acquired asset retirement obligations, to the sale of these working interests and record a gain or loss between the value of consideration received upon the sale and the allocated portion of the accumulated intangible costs., recording the gain or loss in the Other Income and Expense Items of our Consolidated Statement of Operations. In the case of a sale to a related party, any potential gain is recorded as an increase to Additional Paid in Capital.

For sales of interests in unproved properties, the proceeds received are treated as cost recoveries for the properties disposed of and the property is credited with no gain or loss unless the proceeds exceed the carrying value of the property disposed of or the proceeds received indicate the property’s cost is above fair market value. In a case indicating an impairment is necessary the property would be impaired down to its fair value.

Carved-Out Interests

A carved-out interest is one where an obligation is expressed not in monetary terms, but as an obligation to deliver, free and clear of all expenses associated with the operation of the property, a specified quantity of oil or gas out of a specified share of future production. We follow Accounting Standards Codification Topic 932 – Extractive Activities – Oil and Gas (“ASC 932”) in accounting for carved-out interests. ASC 932 requires that no gain or loss be recognized in recording the sale of a carved-out interest because the seller has a substantial future obligation for future performance. As such, we recognize the consideration received as unearned revenue to be recognized as the oil or gas is delivered. The percentage of the related oil and gas assets is reclassified to other assets, is recorded at cost and amortized by the unit-of-production method as delivery takes place.

Treasury Stock

We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets.

Stock-Based Compensation

Stock options and other stock-based compensation issued to employees, directors and consultants are recorded at grant-date fair value and are expensed over the requisite service period. Stock-based compensation to non-employees is re-measured at each reporting period until the instrument vests which represents the final measurement date.

Non-controlling interests

We account for changes in our controlling interests of subsidiaries according to Accounting Codification Standards 810 – Consolidations (“ASC 810”). ASC 810 requires that we record such changes as equity transactions, recording no gain or loss on such a sale.

Our non-controlling interests arise from the sale of equity in our Belize subsidiary. It represents the portion of our Belize subsidiary that we do not own. ASC 810 requires that we account for the equity and income or loss on that operation separately from other Treaty Energy Corporation activity. In the equity section of our Consolidated Balance Sheet, we present the portion of the negative equity attributable to non-controlling interests in the Belize subsidiary. In our Consolidated Statement of Operations, we present the portion of current period net loss in our Belize subsidiary attributable to non-controlling interests.

Class A Convertible Preferred shares

We account for convertible instruments depending on the nature and attributes contained within the instrument. During the year ended December 31, 2011, we issued 36,000 shares of Class A Convertible Preferred shares.

Because these shares are conditionally redeemable under circumstances that are not within the control of the Company, they were accounted for outside of permanent equity and liabilities consistent with the applicable literature on conditionally redeemable preferred stock. The instruments are carried at their redemption values and were evaluated for beneficial conversion features on the grant date. None were present. See Note 7 for a complete description of this transaction.

Purchase Price Allocations

We occasionally acquire assets and assume liabilities in transactions accounted for as business combinations. In connection with a purchase business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must prepare estimates. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.

imated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.

Asset Impairments

We assess proved crude oil and natural gas properties and other investments for possible impairment at least annually at year-end, or earlier, when circumstances indicate that the recorded carrying values of the assets may not be recoverable. We recognize an impairment loss as a result of an event that causes us to consider the possibility that impairment may have occurred and when the estimated undiscounted future cash flows from a property or other investment are less than the carrying value. If impairment is indicated, the carrying values are written down to fair value, which, in the absence of comparable market data, is estimated using a discounted cash flow method. In our cash flow method, cash flows are discounted using a risk-adjusted rate and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity prices, revenues and operating and development costs. Negative revisions in estimates of reserves quantities or expectations of falling commodity prices or rising operating or development costs could result in a reduction in undiscounted future cash flows and could indicate property impairment.

During 2011, we assessed proved properties for possible impairment due to lack of estimated future production and/or changes in our intended use. Certain assets were determined to be impaired and were written down to their estimated fair values under a discounted cash flow model. The discounted cash flow model included management’s estimates of future oil and gas production; commodity prices based on forward commodity price curves at the date of the estimate; operating and development costs, and discount rates.

We recorded total pre-tax (non-cash) asset impairment charges of $354,872 in 2011 and none in 2010.

Foreign Currency Translation

The Belize dollar is considered the functional currency for our Belize subsidiary. Transactions that are completed in Belize Dollars are translated into US dollars in the financial statements at prevailing foreign exchange rates. Assets and liabilities are translated on the balance sheet date, revenues and expenses are translated during the period incurred, and equity is translated based on their historical exchange rates. Gains and losses on foreign currency translation are recorded within other comprehensive income.

There were no foreign currency transaction gains or losses during the years presented in these financial statements.

Earnings Per Share

Basic earnings per common share is computed by dividing net earnings or loss (the numerator) by the weighted average number of common shares outstanding during each period (the denominator). Diluted earnings per common share is similar to the computation for basic earnings per share, except that the denominator is increased by the dilutive effect of stock options outstanding and unvested restricted shares and share units, computed using the treasury stock method. There are currently no common stock equivalents.

Income Taxes

We recognize deferred tax assets and liabilities based on differences between the financial reporting and tax bases of assets and liabilities using the enacted tax rates that are expected to be in effect when the differences are expected to be recovered. We provide a valuation allowance for deferred tax assets for which we do not consider realization of such assets to be more likely than not.

See Note 8 for our reconciliation of income tax expense and deferred income taxes as of and for the years ended December 31, 2011 and 2010.

Fair Value Measurement

In September 2006, the FASB issued ASC (Accounting Standards Codification) 820, Fair Value Measurements and Disclosures . ASC 820 defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. ASC 820 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. ASC 820 is effective for fiscal years beginning after November 15, 2007.

ASC 820 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, ASC 820 establishes a three-tiered fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows.

●	Level 1. Observable inputs such as quoted market 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.

See Note 10 – Fair Value Measurements and Disclosures.

Accounting for Conditional Asset Retirement Obligations

In June, 2006, the Company adopted the accounting guidance with respect to accounting for conditional obligations. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future dismantlement and removal of production equipment and facilities and the restoration and reclamation of a production operation’s surface to a condition similar to that existing before oil and natural gas extraction began.

In general, the amount of an Asset Retirement Obligation (“ARO”) and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the liability is increased each period as the retirement obligation approaches. See Note 6 for a discussion of our estimated Asset Retirement Obligation.

At December 31, 2011, we had $130,397 of asset retirement obligations.

New Accounting Pronouncements

Accounting for Business Combinations

In December 2010, the FASB Accounting Standards Update 2010-29 Business Combinations Topic 805, which requires a public entity to disclose pro forma information for business combinations that occurred in the current reporting period. The disclosures include pro forma revenue and earnings of the combined entity for the current reporting period as though the acquisition date for all business combinations that occurred during the year had been as of the beginning of the annual reporting period. If comparative financial statements are presented, the pro forma revenue and earnings of the combined entity for the comparable prior reporting period should be reported as though the acquisition date for all business combinations that occurred during the current year had been as of the beginning of the comparable prior annual reporting period. Effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption did not have an impact on the Company’s financial position and results of operations.

Note 3 – Going Concern

The accompanying financial statements have been prepared assuming that Treaty will continue as a going concern. As shown in the accompanying financial statements, we had negative cash flows from operations of $1,472,542 in 2011, $330,851 in 2010, and a working capital deficit of $1,533,553 at December 31, 2011. 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 making additional shareholder notes and seeking additional outside financing through debt.

Note 4 – Oil Producing Properties

Pickett County, Tennessee

On April 13, 2010, we acquired 100% undivided working interest (82.5% royalty interest) in eight leases in Pickett County, Tennessee in exchange for 1.5 million shares which were contributed by a major shareholder. These leases are: Herbert Groce #1, 77 acres; Herbert Groce #2, 80 acres; Leeta West, 20 acres; Joseph Schwallie, 47 acres; Byron Hill, 18.5 acres, Robin Moody, 18.5 acres, Terry Williams, 18.5 acres and Kimberly Hicks, 18.5 acres.

We valued the 1.5 million shares at the closing price on April 13, 2010 and valued the Tennessee properties at $19,500, or $0.013 per share. We then divided the purchase price, plus commissions and other costs, equally among the three properties expected to be developed during 2010, and arrived at a cost basis of $10,158 per well. Finally, we recorded a liability to the major shareholder in the amount of $19,500, the value of the shares given in exchange for the leases.

Joseph Schwallie #1

On June 11, 2010, we entered into an agreement to sell 35% of our working interest in the Joseph Schwallie #1 well to an investor for $20,000 cash.

Also on June 11, 2010, we entered into an agreement to sell another 20% of the Joseph Schwallie #1 well for $55,000 in cash. Under the terms of this agreement, we are obligated to increase the distributions of cash flows to this investor from 20% to 34% until such time as the investor has received $55,000, after which the distribution obligation will revert to the 20% working interest.

As a result of the two above sales, we recorded a reduction in our historical cost basis of the Joseph Schwallie well from $10,158 to $4,571, recorded a liability in the amount of $55,000 and a gain on the two sales in the amount of $14,413.

On June 22, 2011, we entered into an agreement creditor to convert a $55,000 liability into 2.5 million shares of common stock. We valued the shares at the closing price on the grant date, crediting equity with $97,500, reducing our liability by $55,000 with an offsetting loss on extinguishment of debt of $42,500.

Robin Moody #1

On May 27, 2010, we entered into an agreement to sell 50% of our working interest in the Robin Moody #1 well for $20,000 in cash. Under the terms of this agreement, we are obligated to increase the distributions of cash flows to this investor from 50% to 56% until such time as the investor has received $20,000, after which the distribution obligation will revert to the 50% working interest.

On June 11, 2010, we sold a 20% interest in the Robin Moody lease for $55,000 in cash. Under the terms of this agreement, we are obligated to increase the distributions of cash flows to this investor from 20% to 29% until such time as the investor has received $55,000, after which the distribution obligation will revert to the 20% working interest.

As a result of the two above sales of our interests in the Robin Moody well #1, we recorded a reduction in our historical cost basis of the Robin Moody lease from $10,158 to $3,047, recorded liabilities in the amount of $75,000 and a loss on the two sales in the amount of $7,111.

On June 15, 2011, we entered into an agreement with the holder of the $55,000 note to convert the debt into a 1% royalty interest in all existing and future Texas leases. We allocated a portion of the carrying values of the Texas leases to the sale of the royalty interest, reduced the carrying value of the oil and gas property by $6,015. Since the holder of the note was a related party, we recorded a credit to Additional Paid in Capital of $48,985 instead of recording a gain on the sale.

Additionally, on June 16, 2012, we entered into an agreement with the holder of the $20,000 note to convert the outstanding debt into common stock. This was done in conjunction with the conversion of $100,000 of debt related to our Belize acquisition.

We issued 8,250,000 shares to eliminate the debt. We valued the shares at the grant date ($330,000), removing the $120,000 of unpaid principal and $5,761 of unpaid interest, resulting in a loss on conversion of $204,239.

Herbert Groce #1

On June 18, 2010, we entered into an agreement to sell 50% of our working interest in the Herbert Groce #1 well for $45,000 in cash. We recorded the sale by reducing the carrying value of our interest in the Herbert Groce #1 well by an amount equal to the pro-rata portion of our historical cost in the property, and recorded a gain of $39,921.

Belize Concession and Joint Venture with Princess Petroleum Ltd.

On April 20, 2010, we entered into a 50/50 Joint Venture agreement with Princess Petroleum Limited, a company organized under the laws of Belize to explore for oil and gas on approximately 2 million acres in Belize. The country of Belize is located in Central America, in the south of the Yucatan Island to the southeast of Mexico. It is surrounded by Mexico in the north, by Guatemala in the west and south and by the Caribbean Sea in the east. Prior to becoming an independent country in 1981, Belize was known as British Honduras.

A major shareholder of the Company paid $100,000 cash as required under the agreement. We have recorded our basis in the $100,000 property and the corresponding debt to our shareholder.

On July 15, 2010, we sold a 10% interest (5% total) working interest in our Belize concession for $250,000 in cash.

On September 2, 2011, we sold a 25% working interest (50% of Treaty’s working interest) in Belize well numbers 1 and 2 to an investor for $156,925 in cash.

Recent Acquisitions

Acquisition of the Compton (Hope) Field

On March 30, 2011, we closed our asset acquisition of the Compton (Hope) field in Texas which consists