Frontera Resources Regulatory News (FRR)

FRONTERA RESOURCES CORPORATION

Houston, Texas, U.S.A. - 28 June 2011

2010 ANNUAL RESULTS AND OPERATIONS UPDATE

Frontera Resources Corporation (London Stock Exchange, AIM Market - Symbol: FRR; OTC Market, U.S.A. - Symbol: FRTE), an independent oil and gas exploration and production company ("Frontera" or the "Company"), today announced its audited final results for the year ended 31 December 2010 and provided an update of operations within its Block 12 license area in the country of Georgia.

Corporate Highlights

2010 Final Results

·; Results for the year ended 31 December 2010 reflect a net loss of $63.9 million, or $0.48 per share on a fully-diluted basis. This loss compares to a net loss of $28.5 million, or $0.31 per share for the fiscal year 2009. The increase in the net loss reported is due to a $44.6 million impairment charge related to compliance with exploration and production ceiling test requirements.

·; Revenues from crude oil sales for 2010 totaled $8.3 million, compared to $4.1 million during the same period in 2009. The increase was attributable to increases in sales volume in the 2010 period, as well as an increase in the price of Brent oil.

Recent Operational Developments

·; Mirzaani Field: Completed cleanout operations on multi-zone frac at the Mirzaani #5 well. Currently awaiting a packer to finalize completion of the well. Based on results from the Mirzaani #5 well, 10 new well locations have been identified and are planned for continued field development.

·; Mtsare Khevi Field: Operations currently ongoing to systematically upgrade plunger lift pumps to progressing cavity pumps to increase oil production from the field's Zone I interval. Plans to initiate gas sales including infrastructure design and construction have been finalized. Twenty new well locations have been identified and are planned for continued oil and gas exploitation.

·; Taribani Field Unit: Based on analysis of historical production results from the Dino#2 and T-#45 wells, 10 new well locations have been identified and are planned for ongoing exploitation at the Taribani Field

·; Basin Edge Play Unit: Completed new interpretations of reprocessed geophysical data related to the 'A', 'B' and 'C' prospects and advanced efforts to seek a strategic partner for continued exploration operations in this significant asset.

·; Shale Gas Play Unit: Advanced study of significant potential oil and gas prospectivity related to the Maykop shales. Identified and designed work program for next phase of technical analysis.

Operations Update

Shallow Fields Production Unit

The Shallow Fields Production Unit is located in the central portion of Block 12 and represents what the Company believes to be an extensive trend of low-cost, low-risk oil and gas resources. The unit contains a number of known oil fields--Mirzaani, Mtsare Khevi, Nazarlebi, and Patara Shiraki--representing undeveloped or under-developed fields that have additional associated exploitation potential. The unit also contains an inventory of "look-alike" exploration prospects--the Kakabeti, Lambalo, Mkralihevi, Mlashiskhevi-Oleskhevi and Tsitsmatiani prospects--each of which contains Soviet-era wells that had hydrocarbon shows while drilling but were never placed on production or adequately appraised. Reservoir objectives are the well-known, regional clastic reservoirs of Pliocene and Miocene age, situated at depths from 10 meters to 1,500 meters.

Mirzaani Field

Field operations have been focused on maintaining oil production from the numerous low-productivity wells in the historically developed portion of the Mirzaani Field, which has produced 7 million barrels of oil since 1932, and is currently producing 70 to 90 barrels of oil per day from a total of 119 wells. Meanwhile, the Company continues to evaluate results from its recent drilling operations, which discovered significant northwest (up-dip) and southeast (down-dip) extensions to the field. Ongoing analysis of results from the Mirzaani #1, #2 and #5 wells confirms the attractiveness of frac completions, which are expected to maximize production rates and enhance the economic value of the field.

A successful multi-zone frac completion of the Mirzaani #5 well was conducted by Schlumberger in 2010, targeting the Pliocene (Shiraki Formation) reservoir Zones 13 and 16/17, at depths of 897-909 and 1,057-1,075 meters. Production testing of these co-mingled zones initially yielded oil at more than 100 barrels of oil per day, although increasing water production, probably from the deepest horizon, began to impair oil production and the well was temporarily suspended. A "bridge plug" will be installed to isolate the lower water zone which should allow production to resume. Based on results observed to date, 10 new well locations have been identified for exploitation of the undeveloped, up-dip northwest area of the Mirzaani field.

The Mirzaani Field is now recognised to be a large accumulation with over 500 million barrels "original oil in place" (OOIP) (gross best estimate numbers) independently assessed by Netherland Sewell & Associates ("NSA") in 2010. Primary recovery factors are, however, quite low in the mainly low pressure reservoirs (around 10%), and NSA have assigned 17.9 million barrels as Best Estimate gross Contingent Resources for the main part of the field, with an additional 25.9 million barrels as the Best Estimate gross Prospective Resources (un-risked) in the northwest field extension area, which appears to be significantly higher pressure. The Company holds a 100% working interest in the field.

Mtsare Khevi Field

The Mtsare Khevi Field is located in the western portion of Block 12, with multiple Upper Pliocene sandstone reservoirs of the Akchagil formation situated at depths between 200 and 1,100 meters. A large number of shallow wells were drilled following field discovery in the 1960's, although there was very little production. Five wells were known to be on production during 1989 to 1994, but there has never been a coherent development plan for the field and total production is reported to be less than 30,000 barrels. Some gas is present in the field, mainly on the crest although there is no clearly defined gas cap.

Since 2008, the Company has been implementing a re-development plan designed to bring the field back to significant production levels. A well workover program was followed by a total of 18 new wells drilled into the Akchagil reservoir, and frac completions have been used to improve well deliverability. A program to install Progressive Cavity pumps in the field, replacing the traditional sucker rod pumps, was completed in March 2011 and early results show a reduction in downtime and operating costs. Current production is around 90 barrels of oil per day from a total of 14 wells. Twenty new well locations have been identified, targeting both oil and gas reservoirs and providing for some pressure support through three proposed water injection wells. A previously disclosed infrastructure project designed to initiate gas sales from shut in wells within the field is now on track for implementation.

The NSA (2010) independent assessment identifies approximately 15 million barrels of OOIP and 2.6 billion cubic feet of original gas in place (OGIP) in the field (gross Best Estimate numbers). Primary oil recovery is again quite low, although gas recovery of about 60% is anticipated; NSA accordingly assigns 1.4 million barrels and 0.516 billion cubic feet as Best Estimate gross Contingent Resources, with an additional 0.7 million barrels and 1.017 billion cubic feet as the Best Estimate gross Prospective Resources (un-risked) in the northwest part of the field which is thought to be prospective mainly for gas.

These assessments are generally consistent with the Company's internal estimates for the Akchagil formation, although the Company's estimates reflect additional resource potential along the northwest trend of the fault block, which NSA was not asked to evaluate.

Taribani Field Unit

The Taribani Field is a large, under-developed oil field covering an area of approximately 80 square kilometers on the southern side of Block 12, with up to 12 productive horizons situated in Pliocene and Miocene age reservoirs at depths between 2,200 and 3,500 meters. The field, which has been known since the 1930s, has been penetrated by 41 wells drilled during the Soviet era, but production has been very poor due to inadequate drilling and completion practices. Around 550,000 barrels have been produced from the field to date; current production is 38 barrels of oil per day from 5 wells.

The Company has acquired a significant seismic database over the field, including 2D and 3D data, and has drilled three new wells in the field as the initial steps in its re-development of this asset. The Dino #2 and T #45 wells were originally completed with first-generation fracs in the field, and these results along with analysis of more recent frac results from the nearby Mirzaani Field, have resulted in the re-design of future frac completions for the Taribani Field. Ten new well locations have been identified for the next campaign of development drilling, along with the re-entry and recompletion of the three Frontera-drilled wells, targeting reservoir Zones 9, 14 and 15.

Taribani is known to be a very large oil accumulation with around 788 million barrels OOIP independently assessed by NSA (2005) for Zones 9, 14, 15 and 19. Recoveries are expected to be somewhat higher in these deeper reservoirs and NSA assigns a 15% recovery factor giving "Technical Possible Reserves" of 118 million barrels for the field, contingent upon declaration of commerciality and approval of a development plan, among other factors. An additional 36 million barrels are assessed as un-risked Prospective Resources in five deeper zones in the field.

Basin Edge Play Unit

Ongoing analysis has continued associated with a recent remapping project relating to the Basin Edge "A", "B" and "C" prospects. Of note, relating to this analysis, new well locations have been identified for the continued future appraisal and exploration of these prospects. Additionally, an effort is underway to seek a strategic partner for the continuation of exploration efforts.

The Basin Edge Play Unit is located along the northern border of Block 12 and represents what the Company believes is one of the newest and potentially most prolific exploration plays in the Upper Kura Basin, with very large potential structures in Cretaceous carbonate reservoirs. In 2005, NSA estimated total unrisked prospective resource potential to be in excess of 680 million barrels within the primary Cretaceous and secondary Miocene (Sarmatian) reservoir targets of two major prospects in the play ("B" and "C").

Shale Gas Play Unit

Since the completion of a study last year that resulted in the identification of significant liquids and gas prospectivity associated with the Maykop shales within Block 12, work has continued to advance this opportunity. Work to date has resulted in the identification of a prospective area encompassing approximately 2,000 square kilometers where potentially significant quantities of natural gas and liquids could be exploited from the regionally present Oligocene-Lower Miocene age Maykop shales and Mesozoic age Liassic shales. Potentially similar to extensive natural gas shale plays in North America and Europe, study work to further define the play's prospectivity continues. The Company's internal estimates indicate over 1 trillion cubic feet of recoverable gas reserves and up to 500 million barrels of oil potential associated with the play. The next phase of planned work includes an independent assessment of these internal prospectivity estimates.

Financial Report

Year Ending 31 December, 2010

For the year ending 31 December, 2010, Frontera incurred a net loss of $63.9 million, or $0.48 per share on a fully-diluted basis. This loss compares to a net loss of $28.5 million, or $0.31 per share for the fiscal year 2009. The increase in the net loss reported is due to a $44.6 million impairment charge due to compliance with exploration and production ceiling test requirements.

Revenues from crude oil sales for 2010 were $8.3 million, compared to $4.1 million during the same period in 2009. The increase was attributable to increases in sales volume in the 2010 period, as well as an increase in the price of Brent oil.

Operating expenses were $61.1 million in 2010, an increase of $39.0 million from $22.1 million in 2009, primarily due to an impairment provision attributable to the 2010 ceiling test write-down with no like adjustment in the 2009 period. Field operating costs increased $0.9 million in 2010, mainly due to higher oil production levels. General and administrative expenses decreased $5.0 million to $9.9 million for 2010 from $14.9 million in 2009. The decrease was generally due to a series of cost cutting measures instituted in 2010, primarily related to headcount reductions in Georgia and Houston.

Total other expenses increased to $11.0 million in 2010 from $10.6 million in 2009. The $0.4 million increase is primarily attributable to a $3.0 million increase in interest expense, partially offset by a $0.9 million increase in derivative income and a $1.9 million increase in "other", mainly attributable to a gain on the extinguishment of debt in 2010.

Going Concern

The Company's consolidated financial statements for the fiscal year ending 31 December 2010 contained an explanatory paragraph regarding the Company's ability to continue as a going concern in its report of independent auditors. The Company's ability to continue as a going concern is discussed in more detail in Note 2 to the financial statements. Additional disclosure and financial information about the Company, including the audited financial statements of the Company as of 31 December 2010, can be found at www.fronteraresources.com.

Appointment of Joint Broker

The Company is pleased to announce the appointment of Old Park Lane Capital Plc as Joint Broker to the Company, with immediate effect

Corporate Transactions Announcement

The Company has today also announced a series of transactions designed to significantly reposition the Company to facilitate the execution of its business plan, including the redomicile of the Company to the Cayman Islands, the conversion of a significant portion of Frontera's convertible debt securities and management debt for shares, and an equity placing of new shares to raise approximately £6.8 million (US$11.0 million) before expenses (the "Proposals"). Full details of the Proposals are contained in a separate Frontera announcement made simultaneously with this announcement and also available on the Company's website at www.fronteraresources.com.

Enquiries:

Frontera Resources Corporation

Liz Williamson

Vice President, Investor Relations and Corporate Communications

(713) 585-3216

lwilliamson@fronteraresources.com

Nominated Advisor:

Strand Hanson Limited

James Harris / Andrew Emmott / Paul Cocker / Liam Buswell

+44 (0)20 7409 3494

Brokers:

Arbuthnot Securities Limited

Richard Johnson / Adam Lloyd

+44 (0)20 7012 2000

Old Park Lane Capital Plc

Michael Parnes / Luca Tenuta

+44 (0)20 7493 8188

Financial PR:

Buchanan Communications

Tim Thompson / Ben Romney

+44 (0)20 7466 5000

Notes to editors:

1. Frontera Resources Corporation is an independent Houston, Texas, U.S.A.-based international oil and gas exploration and production company whose strategy is to identify opportunities and operate in emerging markets around the world. Frontera Resources Corporation shares are traded on the London Stock Exchange, AIM Market - Symbol: FRR and via the Over-the-Counter Market, U.S.A. - OTC Symbol: FRTE. For more information, please visit www.fronteraresources.com.

2. Information on Resource Estimates: The contingent and prospective resources estimates in this announcement for Mirzaani and Mtsare Khevi Fields were determined by the independent consulting firm of Netherland, Sewell & Associates (NSA) in 2010 in accordance with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System (PRMS) adopted by the Society of Petroleum Engineers (SPE). Contingent resources are those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from known accumulations but for which the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent resources estimates in this announcement for Mirzaani Field are contingent solely upon demonstration of the economic viability of the project and an approved development program. If this issue is resolved, some portion of the contingent resources may be reclassified as reserves. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. The reserve estimates in this announcement for Taribani Field and the prospective resources estimates for the Basin Edge Play Unit were determined by NSA in 2005. The full reports of NSA are available at www.fronteraresources.com.

3. This release may contain certain forward-looking statements, including, without limitation, expectations, beliefs, plans and objectives regarding the potential drilling and construction schedule, well results, debt restructuring and financing transactions and other matters discussed in this release, as well as reserves, future drilling, development and production. Exploration for oil is a speculative business that involves a high degree of risk. A number of factors could cause developments to differ materially from those expressed or implied by the forward-looking statements including, without limitation, risks inherent in oil and gas production operations; availability and performance of needed equipment and personnel; the Company's ability to raise further capital to fund exploration and development programs; seismic data; evaluation of logs, cores and other data from wells drilled; inherent uncertainty in estimation of oil and gas resources; fluctuations in oil and gas prices; weather conditions; general economic conditions; the political situation in Georgia and relations with neighboring countries; and other factors listed in the Company's financial reports, which are available at www.fronteraresources.com. There is no assurance that the Company's expectations will be realized, and actual results may differ materially from those expressed in the forward-looking statements.

Frontera Resources Corporation and Subsidiaries

Consolidated Financial Statements

December 31, 2010 and 2009

Page(s)

Report of Independent Auditors........................................................................................................ 1

Consolidated Financial Statements

Balance Sheets.................................................................................................................................. 2

Statements of Operations.................................................................................................................... 3

Statements of Stockholders' Deficit and Comprehensive Loss................................................................. 4

Statements of Cash Flows................................................................................................................... 5

Notes to Consolidated Financial Statements.................................................................................... 6-21

Report of Independent Auditors

To the Board of Directors of

Frontera Resources Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholders' deficit and comprehensive loss and cash flows present fairly, in all material respects, the financial position of Frontera Resources Corporation and its subsidiaries (the "Company") at December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. 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 audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations and has limited available funds as of December 31, 2010, which raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to this matter are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ PricewaterhouseCoopers LLP

May 20, 2011

1. Nature of Operations

Frontera Resources Corporation, a Delaware corporation, and its subsidiaries (collectively "Frontera" or the "Company") are engaged in the development of oil and gas projects in emerging marketplaces. Frontera was founded in 1996 and is headquartered in Houston, Texas. The Company emphasizes development of reserves in known hydrocarbon-bearing basins, and is attracted to projects that have significant exploration upside. Since 2002, the Company has focused substantially all of its efforts on the exploration and development of oilfields within the Republic of Georgia ("Georgia"), a member of the Former Soviet Union.

In June 1997, the Company entered into a 25-year production sharing agreement with the Ministry of Fuel and Energy of Georgia and State Company Georgian Oil ("Georgian Oil"), which gives the Company the exclusive right to explore, develop and produce crude oil in a 5500 square kilometer area in eastern Georgia known as Block 12, hereafter referred to as the "Block 12 PSA". The Block 12 PSA can be extended if commercial production remains viable upon its expiration in June 2022.

Under the terms of the Block 12 PSA, the Company is entitled to conduct exploration and production activities and is entitled to recover its cumulative costs and expenses from the crude oil produced from Block 12. Following recovery of cumulative costs and expenses from Block 12 production, the remaining crude oil sales, referred to as Profit Oil, are allocated between Georgian Oil and Frontera in the proportion of 51% and 49%, respectively.

Under the terms of the Block 12 PSA, Frontera is exempt from all taxes imposed by the government of Georgia, and any taxes imposed on the Company are paid by Georgian Oil on behalf of the Company from Georgian Oil's 51% share of Profit Oil. Taxes are defined by the Block 12 PSA to mean all levies, duties, payments, fees, taxes or contributions payable to or imposed by any government agency, subdivision, municipal or local authorities within the government of Georgia.

Frontera's future revenues depend on operating results from its operations in the Republic of Georgia. The success of Frontera's operations is subject to various contingencies beyond management control. These contingencies include general and regional economic and political conditions, prices for crude oil, competition and changes in regulation. Frontera is subject to various additional political and economic uncertainties in Georgia which could include restrictions on transfer of funds, import and export duties, quotas and embargoes, domestic and international customs and tariffs, and changing taxation policies, foreign exchange restrictions, political conditions and regulations.

2. Liquidity and Capital Resources

The following key financial measurements reflect the Company's financial position and capital resources as of December 31, 2010 and December 31, 2009 (dollars in thousands):

The Company has incurred net losses and negative cash flows from operations in most fiscal periods since inception. Based on the Company's current operating plan, its existing working capital will not be sufficient to meet the cash requirements to fund the Company's planned operating expenses and capital expenditures through December 31, 2011 without additional sources of financing. Management plans to continue to reduce costs and raise additional financing to meet its cash needs for 2011 and has commenced discussions with various financial institutions to seek additional financing in order to facilitate the Company's 2011 operating plan. There can be no assurance that these discussions will result in a successful financing.

Failure to generate sufficient operating cash flows, raise additional capital or further reduce spending will have a material adverse effect on the Company's ability to continue as a going concern and to achieve its intended business objectives. There can be no assurance that sufficient revenues will be generated in the future to sustain the Company's operations. These consolidated financial statements do not include any adjustments related to the outcome of this uncertainty.

Notwithstanding management's plan to reduce costs and raise additional financing, the Company's viability is dependent upon producing oil and gas in sufficient quantities and marketing such oil and gas at sufficient prices to provide positive operating cash flow to the Company. The Company is solely responsible for providing all of the funding for the development of Block 12 in Georgia and will require additional funding in order to obtain certain levels of production and generate sufficient cash flows to meet future capital and operating spending requirements. This is dependent upon, among other factors, achieving significant increases in production, production of oil and gas at costs that provide acceptable margins, reasonable levels of taxation from local authorities, and the ability to market the oil and gas produced at or near world prices.

Management's plan for addressing the above uncertainties is partially based on forward looking events which have yet to occur, including the completion of a successful development program, and accordingly, there is no assurance that those events will transpire as initially contemplated.

3. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of Frontera Resources Corporation and its wholly owned subsidiaries. All intercompany transactions and accounts have been eliminated in consolidation.

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent asset and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company's control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploitation and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect the Company's future depletion, depreciation and amortization expenses.

The Company's revenue, profitability, and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, regulatory developments and competition from other energy sources. The energy markets have historically been volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company's financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances, money market accounts and certificates of deposit, all of which have original maturities of three months or less.

Restricted Cash

At December 31, 2009 the Company had $0.6 million of restricted cash which served as partial collateral for a $9.5 million short-term note payable. The restricted cash was released and used in conjunction with the M-STAR proceeds (see Note 3 - Investments) to pay the $9.5 million short-term note payable. The Company has no restricted cash as of December 31, 2010.

Deferred Financing Costs

Costs incurred in connection with the issuance of the Company's convertible notes payable are capitalized and amortized using the effective interest method over the term of the related notes payable.

Derivative Stock Warrant Liabilities

In June 2008, the FASB issued authoritative guidance relating to financial instruments indexed to an entity's own stock. The adoption of this guidance required us to reclassify our stock warrants, at their fair value as liabilities. The fair value of these liabilities is re-measured at the end of every reporting period with the change in fair value recorded in the statement of operations. The difference between the amount at which the warrants were originally recorded in the consolidated financial statements and the fair value of the instruments on January 1, 2009 was considered a cumulative effect of a change in accounting principle and required an adjustment to the opening balance of accumulated deficit in the amount of $2.2 million and a reduction of common stock warrants of $3.1 million. The liability will continue to be adjusted for changes in fair value until the earlier event of the exercise date or the cancellation of the warrants at the end of their respective terms.

Investments

Investments consisted of Municipal Short Term Auction Rate Securities ("M-STARS") and were classified as available-for-sale and were carried at fair market value, as of December 31, 2009.

During the year ended December 31, 2010 the Company liquidated the remaining $10.0 million par value of the M-STARS for $8.1 million. No loss was recognized in 2010 related to the sale of the investments, as the Company had previously recognized an other-than-temporary impairment loss of $1.9 million during the year ended December 31, 2009, due to widespread failure of the auction rate securities market. In June 2010, the Company initiated an arbitration against the broker and bank from which it had purchased the M-STARS seeking damages for, among other things, violations of federal and state securities laws and common law fraud in connection with the Company's original purchase of the M-STARS. In August 2010, the arbitration was settled for release of approximately $0.9 million in accrued liabilities and a payment of $0.9 million from the broker and bank. The total $1.8 million settlement was recognized as other income for the year ended December 31, 2010.

Fair Value Measurements

Frontera's financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivative stock warrant liabilities, and convertible notes payable. The fair value of cash, accounts receivable and accounts payable are estimated to approximate the carrying value due to the liquid nature of these instruments. The fair value of the line of credit and notes payable was determined based upon discount rates which approximate variable interest rates for borrowings of a similar nature. The fair values of the convertible notes payable at December 31, 2010 and 2009 were approximately $89,219,351 and $89,870,000, respectively.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The guidance requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3: Measured based on prices or valuation models that required inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

The Company classifies financial assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company estimates the fair value of its common stock warrants using the black-scholes model. The Company classified the derivative stock warrant liabilities as level 2 due to the fact that the warrants are not traded in an active market, but have observable inputs.

The following table summarizes the valuation of the Company's financial assets and liabilities by pricing levels as of December 31, 2010 and 2009.

The table below sets forth a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the year ended December 31:

Inventory

Inventory consists primarily of materials to be used in the Company's foreign oilfield operations and crude oil held in stock tanks. Inventory is valued using the first-in, first-out method and is stated at the lower of cost or market. Inventory consists of the following:

Property and Equipment

Property and equipment are stated at cost. Expenditures for major renewals and betterments, which extend the original estimated economic useful lives of applicable assets, are capitalized. Expenditures for normal repairs and maintenance are charged to expense as incurred. The costs and related accumulated depreciation of assets sold or retired are removed from the accounts, and any gain or loss thereon is reflected in operations. Depreciation of property and equipment is computed using the straight-line method over the estimated useful lives of the assets, ranging from three to seven years.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including directly related overhead costs, are capitalized.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are depleted on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not depleted until proved reserves associated with the projects can be determined or until impairment occurs. In addition, the capitalized costs are subject to a "ceiling test," which limits such costs to the aggregate of the future net revenues from proved reserves, based on current economic and operating conditions, discounted at a 10% interest rate, plus the lower of cost or fair market value of unproved properties. A ceiling test calculation is performed at each year-end. For the year ended December 31, 2010 and 2009, the ceiling test calculation used a 12-month natural gas and oil average, as adjusted for basis or location differentials using a 12-month average, and held constant over the life of the reserves. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling test calculation. For the years ended December 31, 2010 and 2009, the Company recorded ceiling test impairments of $44.6 million and $1.1 million, respectively related to its fields in Georgia.

Sales or other dispositions of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in earnings.

Costs Excluded

The costs associated with unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful.

Costs associated with unproved properties of $51.7 million were transferred to the amortization base in 2010 due to changes in the Company's development strategy and management's plans to reduce capital spending in certain oil and gas properties.

Income Taxes

The Company recognizes deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statements and the tax basis of assets and liabilities using enacted rates in effect for the years in which the differences are expected to reverse. Valuation allowances are established, when appropriate, to reduce deferred tax assets to the amount expected to be realized.

The Company accounts for uncertain tax positions by reporting a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. The Company recognizes interest and penalties, if any, related to tax benefits in income tax expense.

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Oil and natural gas sold is not significantly different from the Company's share of production.

Allowance for Doubtful Accounts

The Company has established an allowance for doubtful accounts that is based on the Company's review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance when they are deemed uncollectible. The allowance for doubtful accounts balance was $0.4 million at December 31, 2010. There was no allowance recorded at December 31, 2009.

Foreign Currency Transactions

The financial statements of the foreign subsidiaries are prepared in United States dollars, and the majority of transactions are denominated in United States dollars. Gains and losses on foreign currency transactions are the result of changes in the exchange rate between the time a foreign currency-denominated invoice is recorded and when it is ultimately paid and are included in operations.

Concentrations of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. The Company maintains its cash in bank deposits with various major financial institutions. These accounts, at times, may exceed federally insured limits. Deposits in the United States are guaranteed by the Federal Deposit Insurance Corporation up to $250,000. The Company monitors the financial condition of the financial institutions and does not anticipate any losses on such accounts.

For the year ended December 31, 2010, 100% of the Company's crude oil sales were to one unrelated customer.

Loss Per Share

Basic and diluted loss per share amounts is calculated based on the weighted average number of common stock outstanding during the year. Diluted loss per share is calculated using the weighted average number of shares of common stock outstanding during the year, including the dilutive effect of stock options, warrants and convertible notes. Basic and diluted loss per share for the years ended December 31, 2010 and 2009 are the same since the effect of all common stock equivalents would be antidilutive to the Company's net loss per share.

Stock-Based Compensation

The Company accounts for all share-based payments to employees, including grants of employee stock options, in the financial statements based on their grant-date fair values using a Black-Scholes fair valuation model. The Company estimated forfeiture rates for the year based on its historical experience of approximately 3%. At December 31, 2010 and 2009, there was $244,814 and $1,458,505, respectively, of total unrecognized compensation cost related to non-vested stock options. This compensation cost is expected to be recognized over a weighted-average period of approximately 0.7 and 0.6 years, respectively.

The Black-Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest is the related U.S. Treasury yield curve for periods within the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero as we have historically not paid dividends and have no current plans to do so in the future. The expected volatility is based on historical volatility of the Company's common stock.

4. Accrued Liabilities

Accrued liabilities consist of the following:

5. Debt

Debt consists of the following:

Related Party Notes Payable

During 2010, the Company entered into two series of notes payable with two of the Company's officers in the aggregate amounts of $3.9 million and $1.4 million. These notes are due in 2011 and bear interest of 15%.

Notes Payable

In February 2009, the Company renewed a short-term note of approximately $9.5 million under an agreement with a bank, collateralized by its long-term investments in M-STARS. In May 2009, the note was renewed and collateralized by $10.0 million in face value of the Company's investment in M-STARS, along with $0.6 million of restricted cash. The note was subsequently paid on February 1, 2010 and the related cash restrictions released.

Convertible Notes Payable

During May 2007, the Company raised approximately $67.0 million through a private placement of convertible unsecured notes due May 2012. The notes were issued at par and bear interest at 10% per annum, payable quarterly in arrears in cash or in kind at the Company's discretion. The notes are convertible into shares of common stock at a conversion price of $1.67 per share. The notes will be automatically converted into common stock at the conversion price if the stock price exceeds two times the conversion price for at least 20 consecutive trading days.

On July 3, 2008, the Company raised $23.5 million through a private placement of convertible unsecured notes due July 2013. The notes were issued at par and bear interest at 10% per annum, payable quarterly in arrears in cash or in kind at the Company's discretion. The notes are convertible into common stock at a conversion price of $1.71 per share.

During 2009, noteholders of the Company's convertible notes elected to convert $0.1 million of convertible notes into 32,000 shares of common stock. No such conversions occurred during 2010.

During 2010 and 2009, the Company elected to pay the quarterly interest payments in kind on the convertible notes and issued approximately $10.8 million and $9.8 million, respectively, in additional convertible notes in accordance with terms of the note purchase agreement.

6. Derivative Stock Warrant Liabilities

In July 2008, the Company solicited consents from holders of its 10% convertible notes due May 2012 to amend the note purchase agreements governing such notes to permit the issuance of the new notes and to release escrowed proceeds of $5.0 million from a prior private placement. In connection with the solicitation, each consenting holder received a warrant exercisable into shares of common stock in an amount equal to 7.5% of the number of shares of common stock into which such consenting holder's existing notes were convertible. The warrants are exercisable for 6,593,037 shares in the aggregate at an exercise price of $1.69 per share. The warrants have a five-year term and include a cashless exercise provision along with other customary terms and provisions. The issuance date fair value of these warrants was estimated to be $0.9 million and was recorded as a derivative stock warrant liability. The warrants were valued on the issuance date using the following assumptions: risk-free interest rate of 3.42%, expected volatility of 146.3%, no expected dividend yield and a term of 5 years.

In September 2009, the Company issued 45,186,536 units, each comprised of one Common Share and one Common Share purchase warrant at an issue price of $0.1684 per unit, for gross proceeds of approximately $7.6 million. Each warrant entitles the holder the ability to purchase from the Company one Common Share for a period of two years following the transaction closing date at an exercise price of 15 pence per Common Share. An additional 1,355,596 units were issued to an advisor in exchange for issuance fees. These additional units have the same provisions, with the exception that the term for these warrants is 18 months versus 2 years for those related to the offering. The issuance date fair value of these warrants was estimated to be $3.8 million and was recorded as a derivative stock warrant liability. The warrants were valued on the issuance date using the following assumptions: risk-free interest rates of 0.58% and 0.82%, expected volatilities of 103.5% and 110.3%, no expected dividend yield and terms ranging from 1.5 years and 2 years.

The change in the aggregate fair value of the warrants resulted in derivative income of $2.4 million and $1.5 million, respectively, for 2010 and 2009. The Company determined the fair value of these warrants as of December 31, 2010 using the following assumptions: risk-free interest rates ranging from 0.02% to 0.81%, expected volatilities ranging from 86.27% to 170.85%, no expected dividend yield and remaining terms ranging from 0.22 years to 2.51 years.

7. Income Taxes

Income (loss) before income taxes was comprised of the following:

The Company has incurred losses since inception and, therefore, has not been required to pay federal income taxes. As of December 31, 2010, the Company has generated net operating loss ("NOL") carryforwards of approximately $106.9 million that may be available to reduce future income taxes. These carryforwards begin to expire in 2012 with a limited annual utilization. Several factors may further limit the Company's ability to utilize these carryforwards, including a lack of future taxable income, a change of Company ownership (as defined by federal income tax regulations) or the expiration of the utilization period allowed by federal income tax regulations.

During 2010 and 2009, the valuation allowance increased $7,091,676 and $7,699,730, respectively, primarily due to the Company's losses. The effective tax rate for 2010 and 2009 differs from the statutory tax rate due primarily to the valuation allowance. The components of the Company's deferred tax liabilities and assets at December 31, 2010 and 2009, are as follows:

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are reduced by a valuation allowance as necessary when a determination is made that it is more likely than not that some or all of the deferred tax assets will not be realized based on the weight of all available evidence. As of December 31, 2010 and 2009, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset.

The Company has determined that no uncertain tax positions exist where the Company would be required to make additional tax payments. As a result, the Company has not recorded any additional liabilities for any unrecognized tax benefits as of December 31, 2010. The Company and its subsidiaries file income tax returns in the US federal jurisdiction. Tax years 2007 to present remain open for these taxing authorities due to the Company's net operating losses. The Company's accounting policy is to recognize penalties and interest related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for the payment of penalties and interest at December 31, 2010 or 2009.

8. Commitments and Contingencies

Operating Leases

The Company has noncancelable operating leases for office facilities and lodging. Approximate future minimum annual rental commitments under these operating leases are as follows:

Rental expense for the years ended December 31, 2010 and 2009 was approximately $574,000 and $640,000, respectively.

ARAR Arbitration

In January 2008, Frontera Eastern Georgia Limited ("FEGL"), served a notice of arbitration and claim on ARAR, Inc. ("ARAR"), for breach of contract under a drilling services contract dated May 2007, specifically for, among other things, failure to commence work by the time specified in the contract, failure of the drilling rig to meet required specifications and failure to reconcile advance payments made by FEGL with work actually performed. FEGL terminated the contract after ARAR failed to mobilize the rig to the required location and failed to commence work as otherwise required under the contract. FEGL claimed damages of approximately $7.0 million in the arbitration. ARAR denied FEGL's claims and filed counterclaims against FEGL, seeking payments of approximately $7.1 million for, among other things, standby charges for the period of time the rig was undergoing inspection and repairs to bring it into contract specification, early termination fees and demobilization fees. The parties entered into a settlement agreement in December 2008 pursuant to which ARAR is required to make a series of payments to FEGL through December 2009. The settlement resolves all outstanding claims and counterclaims between Frontera and ARAR arising out of the drilling services contract. Beginning in August 2009, ARAR defaulted on its monthly payments and remains in default on payments due August - December 2009. The Company applied to the arbitration panel for entry of an agreed award pursuant to the settlement agreement. The panel held a hearing on the Company's application in March 2010, and in April 2010, entered a final, binding award in the amount of $1.4 million in favor of FEGL.

In April 2010, FEGL filed an action in the U.S. District Court for the Southern District of Texas seeking confirmation of the final arbitration award pursuant to the Convention on Recognition and Enforcement of Foreign Arbitral Awards of June 10, 1958 as a precursor to further enforcement action in the U.S. In May 2010, ARAR filed a counterclaim in the district court seeking to deny confirmation and to vacate the award. In July 2010, FEGL filed an enforcement action in the 4th Commercial Court in Ankara, Turkey, seeking to enforce the final award against assets of ARAR located in Turkey.

An affiliate of ARAR initiated a lawsuit against FEGL in the 7th Commercial Court in Ankara, Turkey in July 2010 claiming damages of $0.3 million in connection with the exportation of the rig from Georgia. The Company believes the claims made by ARAR in the Turkish lawsuit are subject to the arbitration clause of the contract, were resolved by the December 2008 settlement, and in any event are completely without merit, and intends to vigorously defend itself.

9. Stockholders' Equity

Preferred Stock

The Company has the authority to issue up to 10,000,000 shares, par value $.00001, of serial preferred stock. No preferred stock is outstanding at December 31, 2010 and 2009. The Board of Directors may designate and authorize the issuance of such shares with such voting power and in such classes and series, and with such designation, preferences and relative participation, optional, or other special rights, qualifications, limitations, or restrictions as deemed appropriate by the Company's Board of Directors.

Common Stock

As of December 31, 2010, the Company is authorized to issue 300,000,000 shares of common stock, par value $.00004 per share. As of December 31, 2010 and 2009, the Company had 135,318,282 and 131,793,282 shares of common stock issued and outstanding, respectively. At December 31, 2010 and 2009, additional shares in the amount of 69,301,629 and 69,633,000, respectively, of common stock were reserved for the exercise of existing options and warrants.

Treasury Stock

As of December 31, 2010 and 2009, the Company had 5,739,855 shares of treasury stock, all held as common stock.

2000 Nonqualified Stock Option and Stock Award Plan

In 2000, the Company's Board of Directors approved the 2000 Nonqualified Stock Option and Stock Award Plan (the "Stock Award Plan"), pursuant to which options may be granted to purchase up to 15% of the Company's common stock authorized to be issued by the Company, reduced by the total number of shares of stock subject to stock options and stock awards that have been granted under the Stock Award Plan and the Frontera Resources Corporation 1998 Employee Stock Incentive Plan. The Board of Directors has appointed Frontera's chief executive officer as administrator (the "Administrator") of the Stock Award Plan. In this capacity, the Administrator determines which employees will receive options, the number of shares covered by any option agreement, and the exercise price and other terms of each such option. The Board of Directors is responsible for administering the Stock Award Plan as it relates to options granted to the chief executive officer.

Under the terms of the Stock Award Plan, any issued options expire ten years after the date of grant or upon earlier of termination of employment or affiliation relationship between the grantee and the Company. Options granted vest over periods ranging from immediate vesting to vesting in equal increments over three years from the date of grant.

A summary of the Company's stock option activity and related information is as follows:

The following table summarizes information about stock options outstanding at December 31, 2010:

Stock option information related to the nonvested options for the year ended December 31, 2010, was as follows:

The Company granted 500,000 options to employees during 2010 with exercise prices for $0.12, which was at the market value of the Company's common stock at the time of grant. The weighted average fair value of the options granted in 2010 was $0.12. The fair value of the option grants were calculated using a Black-Scholes option pricing model, with the following weighted average assumptions: risk free interest rate of 2.43%; no dividend yield; volatility factor of 301%; and an expected option life of 9.31 years. At December 31, 2010 and 2009, the stock options outstanding had no intrinsic value.

During 2009 the Company completed a stock option exchange program for employees and directors of the Company pursuant to which, stock options previously granted at strike prices ranging from $1.00 to $2.87 were eligible to be exchanged on a three-for-one basis at a strike price equal to the closing price on September 29, 2009, the date the election period ended. All vesting and expiration dates of the options remained unchanged. As a result of the exchange program, approximately 7.8 million previously granted options were exchanged for approximately 2.6 million options with a strike price of $0.27 per share.

10. Related Party Transactions

In conjunction with an ongoing consulting agreement, a director of the Company received consulting fees for the years ended December 31, 2010 and 2009 of $150,750 and $458,390, respectively.

Additionally, the Company entered into a series of notes payable with two of the Company's officers in the aggregate amounts of $3.9 million and $1.4 million, respectively, at December 31, 2010. See further discussion in Note 5.

11. Subsequent Events

Events occurring after December 31, 2010 were evaluated through May 20, 2011, the date this report was available to be issued, to ensure that any subsequent events meeting the criteria for recognition or disclosure were included. There were no such subsequent events.