DevMar Equities (DEVM) 10-K 2009 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2009

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to _______________

Commission file number:  333-138465

La Cortez Energy, Inc.

(Exact name of registrant as specified in its charter)

Nevada	20-5157768
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

Calle 67 #7-35, Oficina 409 Bogotá, Colombia	None
(Address of principal executive offices)	(Postal Code)

Registrant’s telephone number, including area code:  (941) 870-5433

Securities registered under Section 12(b) of the Act:  None

Securities registered under Section 12(g) of the Act:  Common Stock, $0.001 par value per share

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 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 x  No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨  No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.  x

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

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

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

On June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter,  16,995,224 shares of its Common Stock, $0.001 par value per share (its only class of voting or non-voting common equity) were held by non-affiliates of the registrant.  The market value of those shares was $33,990,448, based on the last sale price of $2.00 per share of the Common Stock on that date.  For this purpose, shares of Common Stock beneficially owned by each executive officer and director of the registrant, and each person known to the registrant to be the beneficial owner of 10% or more of the Common Stock then outstanding, have been excluded because such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of April 12, 2010, there were 40,000,349 shares of the registrant’s Common Stock, par value $0.001 per share, issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

Item Number and Caption		Page
Forward-Looking Statements		3
PART I		4
1.	Business	4
1A.	Risk Factors	19
1B.	Unresolved Staff Comments	36
2.	Properties	36
3.	Legal Proceedings	42
PART II		43
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	43
6.	Selected Financial Data	46
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
8.	Financial Statements and Supplemental Data	60
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
9A.[T]	Controls and Procedures	60
9B.	Other Information
PART III		63
10.	Directors, Executive Officers, and Corporate Governance	63
11.	Executive Compensation	69
12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	75
13.	Certain Relationships and Related Transactions and Director Independence	78
14.	Principal Accountant Fees and Services	78
PART IV		79
15.	Exhibits and Financial Statement Schedules	79
Financial Statements		F-1
Glossary of Oil and Gas Terms		G-1

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FORWARD-LOOKING STATEMENTS

Some of the statements contained in this Annual Report on Form 10-K that are not historical facts are “forward-looking statements” which can be identified by the use of terminology such as “estimates,” “projects,” “plans,” “believes,” “expects,” “anticipates,” “intends,” or the negative or other variations, or by discussions of strategy that involve risks and uncertainties. We urge you to be cautious of the forward-looking statements, that such statements, which are contained in this Annual Report, reflect our current beliefs with respect to future events and involve known and unknown risks, uncertainties and other factors affecting operations, market growth, services, products and licenses. No assurances can be given regarding the achievement of future results, and although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, actual results may differ materially as a result of the risks we face, and actual events may differ from the assumptions underlying the statements that have been made regarding anticipated events. Factors that may cause actual results, performance or achievements, or industry results, to differ materially from those contemplated by such forward-looking statements include without limitation those discussed in the sections of this Annual Report titled “Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and those set forth below:

● Changes in the political and regulatory environment and in business and fiscal conditions in South America, and in Colombia and Peru in particular;

● Our ability to attract and retain management and field personnel with experience in oil and gas exploration and production;

● Our ability to identify corporate acquisition, farm-in and/or joint venture opportunities in the energy sector in Colombia and Peru;

● Our ability to successfully operate, or influence the operator of, exploration and production blocks where we have participation interests, in a cost effective and efficient way;

● Our ability to raise capital when needed and on acceptable terms and conditions;

● The intensity of competition;

● Changes and volatility in oil and gas pricing; and

● General economic conditions.

You should carefully review the risks described in this Annual Report and in other documents we file from time to time with the Securities and Exchange Commission (the “SEC”).  You are cautioned not to place undue reliance on the forward-looking statements, which speak only as of the date of this Annual Report.

All written and oral forward-looking statements made in connection with this Annual Report that are attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. Given the uncertainties that surround such statements, you are cautioned not to place undue reliance on such forward-looking statements.

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All references in this Form 10-K to “La Cortez Energy,” the “Company,” “we,” “us” or “our” or similar terms are to La Cortez Energy, Inc., and its wholly owned subsidiaries.

PART I

ITEM 1.  BUSINESS

For definitions of certain oil and gas industry terms used in this annual report on Form 10-K, please see the Glossary appearing on page G-1.

Overview of Our Business

We are an international, early-stage oil and gas exploration and production company focusing our business in South America. We have established an operating branch in Colombia, and we have entered into two initial working interest agreements, with Petroleos del Norte S.A. (“Petronorte”), a subsidiary of Petrolatina Plc. (AIM: PELE), and with Emerald Energy Plc Sucursal Colombia (“Emerald”), a branch of Emerald Energy Plc. (discussed below).  In addition, in March 2010, we acquired all of the outstanding capital stock of Avante Colombia S.à r.l. (“Avante Colombia”) from Avante Petroleum S.A. (“Avante”); Avante Colombia currently has a 50% participation interest in, and is the operator of, the Rio de Oro and Puerto Barco production contracts with Ecopetrol S.A. in the Catatumbo region of northeastern Colombia, under an operating joint venture with Vetra Exploración y Producción S.A. (“Vetra”). We are currently evaluating additional investment prospects, companies and existing exploration and production opportunities in Colombia, while keeping alert for opportunities in other South American countries.

We expect to explore investment opportunities in oil and gas exploration and development as well as in associated infrastructure (e.g., storage tanks, processing facilities and/or pipelines). The scope of our activities in this regard may include, but not be limited to, the acquisition of or assignment of rights to develop exploratory acreage under concessions with government authorities and other private or public exploration and production (“E&P”) companies, the purchase of oil and gas producing properties, farm-in and farm-out opportunities (i.e., the assumption of or assignment of obligations to fund the cost of drilling and development), and/or the purchase of debt or equity in, and/or assets of, existing oil and gas exploration and development companies currently conducting activities in Colombia.

We are currently evaluating ways to optimize our business structure in each jurisdiction where we conduct and where we intend to develop our business, in order to comply with local regulations while optimizing our tax, legal and operational flexibility. To this end, we have established an operating branch in Bogotá, Colombia where we will engage in our initial business ventures.

Industry Introduction

The oil and gas industry is a complex, multi-discipline sector that varies greatly across geographies. As a heavily regulated industry, operating conditions are subject to political regimes and changing legislation. Governments can either induce or deter investment in exploration and production, depending on legal requirements, fiscal and royalty structures, and regulation. Beyond the political considerations, exploration and production for hydrocarbons is an extremely risky business with countless perils, both endogenous and exogenous to the core business. Exploration and production wells require substantial amounts of investment and are long-term projects, sometimes exceeding twenty to thirty years. Regardless of the efforts spent on an exploration or production prospect, success is difficult to attain. Even though modern equipment including seismic and advanced software has helped geologists find producing sands and map reservoirs, they do not guarantee any particular outcome. Early oil & gas explorers relied on surface indicators to find reservoirs. Drilling is the only method to determine whether a prospect will be productive, and even then many complications can arise during drilling (e.g., those relating to drilling depths, pressure, porosity, weather conditions, permeability of the formation and rock hardness). Typically, there is a significant probability that a particular prospect will turn-up a dry-well, leaving investors with the cost of seismic and a dry well which during current times can total in the millions of dollars. Even if oil is produced from a particular well, there is always the possibility that treatment, at additional cost, may be required to make production commercially viable.Furthermore, most production profiles decline over time, which hinders any cost-benefit analysis. In sum, oil and gas is an industry with high risks and high entry barriers but significant potential for success.

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Oil and gas prices determine the commercial feasibility of a project.  Certain projects may become feasible with higher prices or, conversely, may falter with lower prices. Volatility in the pricing of oil, gas, and other commodities has increased during the last few years, and particularly in the last year, complicating the practicability of a proper assessment of revenue projections.  Most governments have enforced strict regulations to uphold the highest standards of environmental awareness, thus, holding companies to the highest degree of responsibility and sensibility vis à vis protecting the environment. Aside from such environmental factors, oil and gas drilling is often conducted in populated areas. For a company to be successful in its drilling endeavors, working relationships with local communities are crucial, to promote its business strategies and to avoid any repercussions of disputes that might arise over local business operations.

Global Recession, Volatility and Crude Oil Prices

Aside from operational and regulatory issues that affect E&P companies, every major market has been affected by the global recession during the past year. The energy sector is no exception. West Texas Intermediate (“WTI”) crude prices, the standard oil benchmark for the western hemisphere, tumbled from over $140 per barrel in mid 2008 to less than $40 per barrel in early 2009, before rebounding somewhat to approximately $85 now. The new price threshold makes many previously economically viable opportunities less feasible.  We are currently re-evaluating opportunities to reflect this new market environment. Furthermore, the volatility in crude oil prices increases the risks involved. We cannot be sure that the projections we use in evaluating investment opportunities will be valid and in effect as conditions in the oil markets rapidly change. We compensate for this uncertainty by increasing the range of values for our assumptions and by working with numerous sensitivities that might be in line with the situation in the marketplace.

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One-Year Daily Spot Price of WTI FOB Cushing, OK (U.S. Dollars per Barrel)*

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Twenty-Year Monthly Spot Price of WTI FOB Cushing, OK (U.S. Dollars per Barrel)*

*     Source: U.S. Energy information Administration

Financing activity in both the equity and debt capital markets, the most common financing vehicles for E&P companies like ours, has increased from 2008 and 2009, when it had virtually disappeared. Financing is now more accessible to companies that have demonstrated sound managerial and technical capacity. Companies that are able to secure financing from existing and financially sound investor bases are in a position to take advantage of current business opportunities.

New Opportunities for Smaller Companies

In today’s energy market, there are significant opportunities for smaller companies. The greatest opportunity exists in countries where small scale resource opportunities have been overlooked or have been considered immaterial or uneconomic by medium to larger companies, and/or where local governments are promoting the development of small reservoirs to increase production to satisfy internal demand as well as export needs.  To accomplish this governmental purpose, certain of the regional governing bodies have modified their oil and gas E&P contracting terms and conditions making them more attractive for the oil industry in general, and in some cases, for smaller companies as well.

Business Plan and Strategic Outlook

We plan to build a successful oil and gas exploration and production company focused in select countries in South America.  We will concentrate our efforts initially in Colombia, where, we believe, good E&P opportunities exist with straight forward oil and gas contracting terms and conditions.  At a later stage, we will turn to opportunities in other regional countries if we deem the relevant considerations (see list of factors below) to merit our investment. Within the spectrum of the oil and gas business, we plan to focus on a blend between exploration and production of hydrocarbons through a variety of transactions. Our initial plan is to acquire oil and gas production and to start to build a reserves base.

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An integral part of our strategy is our focus on continuing to build a competent and professional management and operations team to enable us to successfully carry out our business plan. We have hired experienced personnel including technical specialists (e.g., geologists, geophysicists and petroleum and facilities engineers, as required by the scope of our operations), administrators, financial experts and functional specialists in fields such as environment and community relations, to encompass the different areas that are critical to our business. Because the focus of our business is in South America, the majority of our staff will be hired locally and will live in the region.  This will provide us with a significant base of relevant oil and gas business experience in the region.

We are motivating our employees through a positive, team oriented work environment and an incentive stock ownership plan. We believe that employee ownership, which is encouraged through our Amended and Restated 2008 Equity Incentive Plan, is essential for attracting, retaining and motivating qualified personnel.

We have established a time-line for our expansion into new geographies to avoid overextending our reach and to focus on immediate prospects. We have initially concentrated our efforts in Colombia and are looking at Peru as a potential next target. Both countries have similar E&P contract terms and conditions as well as business opportunities that are appropriate for a small, early stage company such as La Cortez Energy. Our second and subsequent development phases will focus on exploration and production opportunities in other South American countries as we explore investment opportunities in these locales. We plan to adhere to this time-line but reserve the option of being flexible if the right investment presents itself.

Acquisition Strategy

We intend to acquire producing oil and gas properties (and/or fields) where we believe significant value exists or where additional value can be created. Our senior management is primarily interested in developmental properties where some combination of the following factors exists:

(1) Opportunities for medium to long term production life with clear understandings of production mechanisms and output levels;

(2) Geological formations with multiple producing horizons;

(3) Substantial upside potential; and

(4) Relatively low capital investment and production costs.

We will continue to pursue joint ventures or farm-ins in exploration ventures with limited risk, in areas where nearby oil discoveries have been found.

Phased Approach

● Phase 1 – We are concentrating our initial efforts in Colombia where opportunities as well as operating terms and conditions are perceived in the industry to be appropriate for small, early stage oil and gas E&P companies. In these markets are pursuing:

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– Acquisitions of established oil and gas exploration and production fields and/or companies, which will enable us to establish base production with upside potential;

– Joint ventures and farm-ins on exploration projects with up to a 20% to 50% maximum participation interest; and

– Participation in bidding processes for property operator opportunities, in conjunction with established E&P companies or independently, if allowed under local regulations.

● Phase 2 – Once we have established our business in Colombia, we will turn our attention to new opportunities in other South American countries. We intend to take advantage of promising opportunities in these additional markets while we consolidate our E&P activities in our Phase 1 countries. In these markets, we intend to search for the following market environments and types of projects:

– Frontier exploration areas (joint ventures with up to a 25% ownership participation) where limited competition exists;

– Acquisitions with significant upside potential;

– Political stability; and

– Supportive local oil and gas industry regulatory environments.

The following is a list of some of the factors we take into account when considering potential investments in any country:

· Stable political regimes:

o Countries that exhibit a desire to uphold stability and progress in their legislation, striving towards open markets and a global approach to best business practices.

· Clear fiscal/taxation/royalty terms.

· Manageable security in and around production and exploration areas and facilities.

· Openness to foreign direct investment.

· Good oil and gas E&P prospects:

o Where despite the presence of large multi-national integrated oil companies, there are open acreage opportunities as well as farm-in, joint venture, and direct block negotiation opportunities, as well producing fields and/or company acquisition possibilities, with some access to local capital.

· Potential for underexploited hydrocarbon formations with promising upside potential:

o We are searching for investment opportunities in countries where there are regions with limited seismic coverage within hydrocarbon prospective areas.

La Cortez Energy can engage in any of the following types of transactions to achieve our strategic goals:

· Exploration and Production:

o Direct government concessions in blocks with specific exploration and development plans.

· Technical Evaluation Agreements.

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· Farm-ins and Farm-outs:

o The assumption of or assignment of obligations to fund the cost of exploration and/or drilling and/or development for a participating interest in a particular block.

· Corporate Transactions:

o Acquisitions of producing fields;

o Acquisitions of exploration acreage;

o Corporate acquisitions; and

o Asset based acquisitions (e.g., blocks and concession rights).

· Joint Ventures:

o Partnering with other established oil and gas companies will allow us to access certain government concession rounds, benefit from technical and market expertise from our potential partners and provide liquidity to our partners.

Role of Our Board of Directors

Our Board of Directors is an essential component of our successful operation and growth, serving in various support capacities. Because our Board of Directors is comprised of senior industry executives and experienced capital market professionals, we believe that our directors have the experience and skills necessary to effectively assist our management in the execution of our strategy.  We expect that our Board of Directors will be able to provide an informed view as to the commercial, technical and financial viability of our business prospects.

Through the establishment of relevant committees (Audit and Evaluation and Reserves, to date), the Board of Directors will provide an independent view into all of our operations, providing feedback and guidance on the quality of the projects we may invest in.  Additionally, our Board of Directors regularly confers with senior management to help us ensure that all relevant and required controls are in place and operating appropriately. Our Board of Directors serves as a means of confirming the integrity of senior management’s estimates with respect to valuations, reserve estimates and other crucial components of our business.

Aside from the functions enumerated above, we believe that our Board of Directors will serve as an integral element of our business development efforts. We expect that our Board of Directors will provide both invaluable insight and access to their business relationships in the region, as well as augment the technical, financial, accounting and other expertise of our management team.

Execution of our Strategy and Recent Developments

In February 2008, Nadine C. Smith became the Chairman of our Board of Directors (sometimes referred to hereinafter as the “Board”). Ms. Smith also became our Interim Chief Financial Officer and Vice President at that time.  Ms. Smith most recently served as a director of another publicly traded oil and gas exploration and production company, Gran Tierra Energy, Inc. (“Gran Tierra”), which also operates in South America.

On March 14, 2008, we closed a private placement of our Common Stock at a price of $1.00 per share pursuant to which we raised $2,400,000, or $2,314,895 net of offering expenses.

On September 10, 2008, we closed a private placement of 4,784,800 units at a price of $1.25 per unit, for an aggregate offering price of $5,981,000, or $5,762,126 after offering expenses. Each of these units consisted of (i) one share of our common stock and (ii) a common stock purchase warrant to purchase one-half share of our common stock, exercisable for a period of five years at an exercise price of $2.25 per share.

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On June 1, 2008, Andrés Gutierrez Rivera became our President and Chief Executive Officer and a member of our Board of Directors. Mr. Gutierrez recently served as the senior executive officer of Lewis Energy Colombia Inc. and a vice president of Hocol, S.A.  Both of these companies operate in the oil and gas sector in South America.

On June 19, 2009, we conducted an initial closing of a private placement of units.  Each unit consisted of (i) one share of our common stock and (ii) a common stock purchase warrant to purchase one share of our common stock, exercisable for a period of five years at an exercise price of $2.00 per share. We offered these units at a price of $1.25 per unit and we derived total proceeds at the initial closing of $6,074,914 ($5,244,279 net after expenses) from the sale of 4,860,000 units.  On July 31, 2009, we completed the final closing of this unit offering.  At the final closing, we received gross proceeds of $256,250 from the sale of 205,000 units.   In the aggregate, we received gross proceeds of $6,331,164 in this unit offering on the sale of a total of 5,065,000 units.  This unit offering terminated on July 31, 2009.

On December 29, 2009, we consummated the initial closing of a second 2009 private placement of units of our securities, selling 1,428,571 units at a price of $1.75 per unit, for aggregate gross proceeds of $2.5 million.  We consummated a second closing of this offering on January 29, 2010, in which we sold 571,428 units for an aggregate of $1 million, and a third closing on March 2, 2010, in which we sold 857,143 units for an aggregate of $1.5 million.

In connection with the acquisition of Avante Colombia, on March 2, 2010, Avante purchased (in addition to the shares of common stock issued to Avante in consideration for the acquisition) 2,857,143 shares of our common stock and three-year warrants to purchase 2,857,143 shares of our common stock at an exercise price of $3.00 per share (the “Avante Warrants”), for an aggregate purchase price of $5,000,000, or $1.75 per unit.

We have been using the funds raised in the private unit offerings (net of offering expenses) to continue building of our administrative and operations infrastructure and to invest in our initial oil and gas development projects in South America and have taken the following steps in our ramping-up process:

● Added the following independent directors to our Board of Directors: Jaime Ruiz Llano, a former Colombian senator and a member of the Board of Directors of the World Bank; Jaime Navas Gaona, an experienced oil industry executive; Richard G. Stevens, an “audit committee financial expert”; and José Fernando Montoya Carrillo, a 27-year veteran of the oil industry in South America and former President of Hocol, S.A.;

● Established a wholly owned subsidiary in the Cayman Islands, La Cortez Energy Colombia, Inc., to own our operating branch in Colombia;

● Established and organized a branch office in Colombia to conduct local operations and, to this end, opened and began staffing our headquarter offices in Bogotá, Colombia;

● Hired an Exploration Manager, Carlos Lombo, and a Production and Operations Manager, William Giron, as well as business development and administrative personnel;

● Signed a memorandum of understanding and joint operating agreement with one oil and gas exploration and production company in Colombia and a farm-in agreement with another, as further discussed below;

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Acquired a privately-held company that is the operator of, and owner of a 50% participation interest in, two production contracts with Ecopetrol S.A. in Colombia, as further discussed below; and

● Have begun identifying, investigating, evaluating and finalizing our participation in oil and gas investment opportunities in Colombia.

Additionally, in the coming months, we expect to:

● Hire a Chief Financial Officer, additional geologists and a petroleum engineer, to form a strong technical team, as well as additional finance and administrative personnel; and

● Enter into one or more additional agreements to acquire oil and gas exploration and/or production rights in Colombia. (Although we have not yet finalized decisions to pursue any such particular opportunities, we have begun to identify and evaluate potential prospects.)

Putumayo 4 Block

On December 22, 2008, we entered into a memorandum of understanding with Petronorte that entitles us to a 50% net working interest in the Putumayo 4 Block located in the south of Colombia.  We executed a related joint operating agreement with Petronorte on October 14, 2009, effective as of February 23, 2009.

Petronorte was the successful bidder on the Putumayo 4 Block in the Colombia Mini Round 2008 conducted by theAgencia Nacional de Hidrocarburos (the “ANH”), Colombia’s hydrocarbon regulatory agency, and signed an E&P contract with the ANH on February 23, 2009.  According to our memorandum of understanding and the joint operating agreement with Petronorte, we are entitled to the exclusive right to a fifty percent (50%) net participation interest in the Putumayo 4 Block and in the E&P contract (subject to approval by the ANH), after ANH royalties and an ANH one percent (1%) production participation.  Petronorte will be the “operator” of the E&P contract.

The Putumayo 4 Block covers an area of 126,845 acres (51,333 hectares) located in the Putumayo Basin in southern Colombia and has over 1,000 km of pre-existing 2D seismic through which we and Petronorte have identified promising leads. We and Petronorte have reprocessed relevant seismic information that confirmed our initial evaluation of seven potential leads. During this initial stage, we and Petronorte are conducting activities related to identification of the number of indigenous people and communities in the area.

We and Petronorte plan to acquire about 103 km of 2D seismic during the course of this year, as well as to drill an exploration well in early 2011.

Under the terms of the E&P contract, Petronorte is required to shoot 103 km of 2D seismic and to drill an exploratory well and to carry our certain additional work in the first three years of our work program in the Block (which ends in September 2012) at an estimated cost of $1.6 million.

The E&P contract will consist of two three-year exploration phases and a twenty-four year production phase.

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As criteria for awarding blocks in the 2008 Mini Round, the ANH considered proposed additional work commitments, comprised of capital expenditures and an additional production revenue payment after royalties, called the “X Factor.”  We and Petronorte offered to invest $1.6 million in additional seismic work in the Putumayo 4 Block and to pay ANH a 1% of net production revenues X Factor.

Under the memorandum of understanding and the joint operating agreement, we will be responsible for fifty percent (50%) of the costs incurred under the E&P contract, entitling us to fifty percent (50%) of the revenues originated from the Putumayo 4 Block, net of royalty and production participation interest payments to the ANH, except that we will be responsible for paying two-thirds (2/3) of the costs originated from the first 103 kilometers of 2D seismic to be performed in the Putumayo 4 Block, in accordance with the expected Phase 1 minimum exploration program under the E&P contract. If a prospective Phase 1 well in a prospect in the Putumayo 4 Block proves productive, Petronorte will reimburse us for its share of these seismic costs paid by us (one-sixth (1/6)) with their revenues from production from the Putumayo 4 Block.  We expect that our capital commitments to Petronorte will be approximately $2.8 million in 2010 for Phase 1 seismic reprocessing, seismic acquisition and permitting activities.  

Provided that we have satisfactorily complied with all ANH legal, financial and technical requirements for being a partner in an E&P contract (which we expect to be the case shortly) and we have made the required payment relating to our share of all costs incurred to the date of our request, Petronorte will submit a request to the ANH to have our 50% interest in the E&P contract officially assigned to us and will assist us in obtaining such assignment through reasonable means.

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Maranta Block

On February 6, 2009, La Cortez Energy Colombia, Inc., our wholly owned Cayman Islands operating subsidiary (“La Cortez Colombia”), entered into a farm-in agreement with Emerald for a 20% participating interest in the Maranta E&P block in the Putumayo Basin in Southwest Colombia.

Emerald signed an E&P contract for the Maranta Block with the ANH on September 12, 2006.  La Cortez Colombia executed a joint operating agreement with Emerald with respect to the Maranta Block on February 4, 2010, having met its Phase 1 and Phase 2 (drilling and completion of the Mirto-1 exploratory well) payment obligations described below.  We have asked Emerald to submit a request to the ANH to approve Emerald’s assignment of the 20% participating interest to us.  Under the farm-in agreement and the joint operating agreement, Emerald will remain the operator for the block.  If the ANH does not approve the assignment of this participating interest to us, Emerald and we have agreed to use our best endeavors to seek in good faith a legal way to enter into an agreement with terms equivalent to the farm-in agreement and the joint operating agreement, that shall privately govern the relations between the parties with respect to the Maranta Block and which will not require ANH approval.

The Maranta Block covers an area of 90,459 acres (36,608 hectares) in the foreland of the Putumayo Basin in southwest Colombia. Emerald completed the first phase exploratory program for the Maranta Block by acquiring 71 square kilometers of new 2D seismic and reprocessing 40 square kilometers of existing 2D seismic, identifying several promising prospects and leads. Emerald has identified the Mirto prospect, namely the Mirto-1 well, as the first exploratory well in the Maranta Block.  The Maranta Block is adjacent to Gran Tierra’s Chaza block and close to both the Orito and Santana crude oil receiving stations, allowing transportation by truck directly to either station (depending on going rates and capacity), and consequently tying into the pipeline to Colombia’s Pacific Ocean port at Tumaco.

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As consideration for its 20% participating interest, we reimbursed Emerald $0.948 million of its Phase 1 sunk costs.  This amount was paid to Emerald in February 2009.  Additionally, we have borne 65% of the Maranta Block Phase 2 costs, of which the “dry hole” costs1 were $4.875 million, $2.433 million of which we paid to Emerald in February 2009.  We made additional Phase 2 payments to Emerald in the amount of $2.433 million and $1.2285 million in May 2009 and July 2009, respectively.  We also paid Emerald a cash call of $0.2433 million in August 2009 for overhead costs.  On January 7, 2010, we paid an additional $1.41 million to Emerald, to cover exploration costs associated with the Mirto-1 well, as well as certain 3d seismic and facilities costs.  On February 5, 2010, we paid an additional $234,553 to Emerald for our share of the final exploration costs of the Mirto-1 well.

Emerald reached the intended total depth of 11,578 feet on the Mirto-1 exploration well in July 2009, with oil and gas recorded across the four target reservoirs.  On July 23, 2009, based on the preliminary results of the drilling of the Mirto-1 well, we decided to participate with Emerald in the completion and evaluation of Mirto-1.  In accordance with the terms of the farm-in agreement, we have borne 65% ($1.2285 million) of the currently estimated $1.8 million Mirto-1 completion costs.  We made this $1.2285 million payment to Emerald on July 27, 2009.  65% of any additional Phase 2 costs will be paid by us as needed, following cash calls by Emerald.  

Now that the Phase 2 work is completed, we will pay 20% of all subsequent costs related to the Maranta Block.

Evaluation of the Mirto-1 exploratory well across all of the target reservoirs has been completed2.  Following the completion of operations in the Mirto-1 well, the drilling rig was released from the location. After an unsuccessful workover attempting to isolate the water production, the Mirto-1 well is producing at an average rate of 145 bopd with a water cut close to 80%.

Emerald and La Cortez continue to believe that despite the mechanical problems encountered in the Mirto-1 well, there is sufficient accumulation of hydrocarbons in the area to merit the drilling of at least two additional wells.  Emerald, as operator of the Maranta Block, has determined to enter the exploration commitment in the Maranta Block, which will entail the drilling of an additional exploratory/appraisal well. We have acquired about 25 km2 of 3D seismic, and we are in the process of mobilizing the rig to start drilling the new appraisal well in early May 2010.  It is planned that after the Mirto-2 appraisal well has been drilled and completed, a new intervention in Mirto-1 well will be executed to increase perforation density of the producing "U" sand to increase total production capacity of the well. Now that the Company has the final Mirto-1 evaluation results, La Cortez Colombia has asked Emerald to file a request with the ANH to have the participating interest in the Maranta Block officially assigned from Emerald to La Cortez Colombia.

Effective October 12, 2009, Emerald’s parent, Emerald Energy Plc, was acquired by Sinochem Resources UK Limited, a United Kingdom subsidiary of Sinochem Group, a Chinese state-owned energy and chemicals conglomerate.

 

1.  Costs of getting to the abandon or complete decision point. 

2 . For a discussion of the Mirto-1 evaluation results, see “Description of Properties – Maranta Block” below.

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Rio de Oro and Puerto Barco Fields

On March 2, 2010, we acquired all of the outstanding capital stock of Avante Colombia, which became our wholly owned subsidiary.  As consideration for the acquisition, we issued an aggregate of 10,285,819 shares of our common stock to Avante.

Avante Colombia currently has a 50% participation interest (acquired in late 2005) in, and is the operator of, the Rio de Oro and Puerto Barco production contracts with Ecopetrol S.A. in the Department of North Santander in the Catatumbo region of northeastern Colombia, under an operating joint venture with Vetra.  The Rio de Oro field covers 5,590 acres (2,262 hectares), and the Puerto Barco field covers 5,945 acres (2,406 hectares).  Both production contracts are for a ten-year term expiring at the end of 2013.

The Catatumbo basin is the southern-most extension of the Maracaibo basin of Venezuela, the second most petroliferous basin in the world according to the US Department of Energy and Petroleos de Venezuela. This sub-basin has produced over 800 million barrels of oil to-date from numerous fields.

Under the Puerto Barco production contract, Ecopetrol has a 6% participation on production, Vetra a 47% participation on production and a 50% working interest and Avante Colombia a 47% participation on production and a 50% working interest, in each case after royalties.  Royalties payable are 20% of audited production. The operator is Avante Colombia.  Production on the field began in 1958 and was stopped in July 2008, as a result of insurgent activity.  Total historical production was 811,000 barrels of oil.

Under the Rio de Oro production contract, Ecopetrol has a 12% production participation, Vetra a 44% production participation and a 50% working interest and Avante Colombia a 44% production participation and a 50% working interest, in each case after royalties.  Royalties payable are 20% of audited production. The operator is Avante Colombia.  Production on the field began in 1950 and was stopped in June 1999, as a result of insurgent activity.  Total historical production was 11.3 million barrels of oil and 27,041 million cubic feet of gas.

In the Rio de Oro field, the remediation of certain historical environmental conditions generated prior to the Acquisition will be the responsibility of previous operators.  In addition to the contractual responsibility of previous operators for these liabilities, Avante has agreed in the SPA to indemnify us for 50% of any environmental losses we incur, up to a maximum of $2.5 million.

Under the terms of the stock purchase agreement, we and Avante have also agreed to pursue certain opportunities in the Catatumbo area on a joint venture basis.  If we enter into such a joint venture with Avante, then we would own 70% of the joint venture and commit to pay 70% of the geological and geophysical costs, and Avante would own 30% of the joint venture and commit to pay 30% of the geological and geophysical costs, up to a maximum commitment by Avante of $1,500,000.  If the total costs of the venture exceed $5,000,000, then Avante may elect either (a) not to pay any additional costs of the venture and incur dilution of its ownership percent from future payments by us, (b) to continue to pay additional costs of the venture at 30% or (c) to pay a larger proportion of the costs of the venture, in which case Avante’s ownership percent would be increased in proportion to the percentage of total venture costs paid by each party, up to a maximum ownership interest for Avante of 50%.

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Plan of Operation

We plan to use our currently available cash for work programs in our Maranta Block, Putumayo 4 Block and our Rio de Oro / Puerto Barco Fields, and for corporate transactions and/or acquisitions, as well as for general working capital purposes. The current work program for our Putumayo 4 Block is comprised of the acquisition of an additional 103 kilometers of new 2D seismic in 2010 and, subsequently, the drilling of an exploratory well in the first quarter of 2011. We have evaluated the reprocessed seismic information, which validated the existence of the seven initial leads we have identified to date, and will redirect our new seismic campaign of 103 km of 2D or equivalent 3D seismic in a more efficient manner. Under Petronorte’s contractual obligations with the ANH, we have until August 23, 2012, to complete Phase 1 commitments comprised of seismic acquisition and the drilling of an exploratory well. A complete evaluation of the project’s impact on the indigenous peoples in the area of the Putumayo 4 Block is also being conducted at this time.

In our Maranta Block, we have completed funding our share of the costs of the Mirto-1 exploratory well. We have acquired 25 km of 3D seismic over the field to better determine the extent of the reservoir and to determine the position of the two or three appraisal wells that we plan to drill in 2010.

In Catatumbo, we plan to reinitiate production in Puerto Barco during this year and have presented a work program to Ecopetrol.  Our plans with respect to Avante Colombia’s business depend, among other things, on obtaining an extension of the term of existing contracts between Avante Colombia and Ecopetrol, which expire in December 2013.  We believe that, in order to negotiate a term extension, we will have to commit to additional investment in the area, such as additional seismic acquisition as well the drilling of exploration wells.

During 2010, we expect to require the following amounts of capital in order to bear our share of expenses with respect to the Putumayo 4 Block, the Maranta Block and Avante Colombia’s projects:

● Approximately $2.8 million in the Putumayo 4 Block, related to Phase 1 seismic acquisition and permitting activities;

● Approximately $5.4 million in the Maranta Block, related to Phase 3 processing of the recently acquired 25 km of 3D seismic, conducting a workover on the Mirto-1 well, the drilling of two or three appraisal wells and the construction of the production facilities at the field; and

● Up to $3.4 million on Rio de Oro and Puerto Barco, related to additional seismic in the area and either deepening an existing well or drilling an additional well.

Additionally, we are actively pursuing strategic and acquisition opportunities with the goal of adding production and proven reserves to our current project portfolio.  While we have no definitive agreements or binding letters of intent in place with respect to any acquisition or strategic transactions, we may enter into one or more definitive agreement by the end of 2010.  We believe that current market conditions, (e.g., current WTI crude prices) are optimal for entering into corporate transactions and/or acquisitions and we plan to aggressively execute this strategy during 2010, provided that our assessment of market conditions remains favorable.

Governmental Regulation

The oil and gas industry in Colombia is broadly regulated. Rights and obligations with regard to exploration, development and production activities are explicit for each project; economics are governed by a royalty/tax regime. Various government approvals are required for acquisitions and transfers of exploration and exploitation rights, including, meeting financial, operational, legal and technical qualification criteria.  Oil and gas concessions are typically granted for fixed terms with opportunity for extension.

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Colombia

In Colombia, state owned Ecopetrol was formerly responsible for all activities related to the exploration, production, refining, transportation and marketing of oil for export. Historically, all oil and gas exploration and production was governed by agreements granted to local and foreign operators, under Association or Shared Risk Contracts with companies and joint ventures which generally provided Ecopetrol with back-in rights that allowed for Ecopetrol to acquire a working interest share in any commercial discovery by paying its share of the costs for that discovery.  Alternatively, exploration and production of certain areas and of those areas relinquished by operators, were operated directly by Ecopetrol.

Effective January 1, 2004, the regulatory regime in Colombia underwent a significant change with the formation of the Agencia Nacional de Hidrocarburos - ANH. The ANH is now exclusively responsible for regulating the Colombian oil industry, including managing all exploration areas not subject to a previously existing Association contract and collecting royalty payments on behalf of the Colombian government. The former state oil company, Ecopetrol, maintains title to agreements executed before January 1, 2004 and its own operated exploration, production, refining and transportation activities across the country.  It also continues to internationally market its oil related products and has become a direct competitor of private operators in E&P projects.

Ecopetrol is a Mixed Economy Company (private and public equity), established as a stock corporation, with a commercial orientation.

In conjunction with this change, the ANH developed a new exploration risk contract that took effect during the first quarter of 2005. This exploration and production contract has significantly changed the way the industry views Colombia. In place of the earlier Association contracts in which Ecopetrol had a direct co-management of the contract together with the associate and an immediate back-in to production, the new ANH agreement provides full risk/reward benefits for the contractor. Under the terms of the contract, the E&P operator retains the rights to all reserves, production and income from any new exploration block, subject to an existing royalty (variable royalty from 8% to 25% depending upon daily production rates) and an additional royalty for the ANH, payable beginning when total production reaches 5 MBBLS.

E&P companies have to comply with certain minimum requirements (legal, operational, financial, and technical) to become eligible to be granted an ANH Exploration and Production contract. Companies can also apply for Technical Evaluation Agreements (TEA).  Domiciled and non domiciled oil companies may participate in the various bidding rounds for E&P contracts on and offshore in Colombia. In a bidding round, the companies that offer greater investment programs in the initial exploration phase (Phase 1) and, in some cases, that provide ANH with a higher participation in production will be the ones to be awarded E&P contracts.

Colombia, in the last few years has become very attractive to foreign oil, gas and mining investors as a result of political and regulation stability, perceived good contract terms and conditions and improved security. It is, therefore, a competitive environment for us, with good business opportunities available.

See “Risk Factors” for information regarding the regulatory risks that we face.

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Environmental Regulation – Community Relations

Our activities will be subject to existing laws and regulations governing environmental quality and pollution control in the foreign countries where we expect to maintain operations. Our activities with respect to exploration, drilling and production from wells, facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing crude oil and other products, will be subject to stringent environmental regulation by regional, provincial and federal authorities in Colombia. Such regulations relate to, for example, environmental impact studies, permissible levels of air and water emissions, control of hazardous wastes, construction of facilities, recycling requirements and reclamation standards. Risks are inherent in oil and gas exploration, development and production operations, and we can give no assurance that significant costs and liabilities will not be incurred in connection with environmental compliance issues. There can be no assurance that all licenses and permits which may be required to carry out exploration and production activities will be obtainable on reasonable terms or on a timely basis, or that such laws and regulations would not have an adverse effect on any project that we may wish to undertake.

In some countries in South America, it is usually required for oil and gas E&P companies to present their operational plans to local communities or indigenous populations living in the area of a proposed project before project activities can be initiated. Usually, E&P companies try to benefit the community in which they are operating by hiring local, unskilled labor or contracting locally for services such as workers’ transportation. For La Cortez Energy, working with local communities will be an essential part of our work program for the development of any of our E&P projects in the region.

Competition

The oil and gas industry is highly competitive. We face competition from both local and international companies in matters such as acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources that exceed ours, and we believe that these companies have a competitive advantage in these areas. Others are smaller, and we believe our technical and managerial capabilities give us a competitive advantage over these companies.

Research and Development

We have not spent any amounts on research and development activities during either of the last two fiscal years.

Employees

We currently have 12 full time employees, all of whom, including our Chief Executive Officer, Andrés Gutierrez, our Exploration Manager, Mr. Carlos Lombo, and our Production and Operations Manager, William Giron, are based in our executive offices in Bogotá, Colombia.

We intend to continue to build an experienced leadership team of energy industry veterans with direct exploration and production experience in the region combined with an efficient managerial and administrative staff, to enable us to achieve our strategic and operational goals.

Additionally, we expect to maintain a highly competitive assembly of experienced and technically proficient employees, motivating them through a positive, team oriented work environment and our incentive stock ownership plan. We believe that employee ownership, which is encouraged through our 2008 Equity Incentive Plan, is essential for attracting, retaining and motivating qualified personnel.

18

Legacy Business Formation and Split-Off

The Company was incorporated in the State of Nevada on June 9, 2006, under the name La Cortez Enterprises, Inc. to pursue certain business opportunities in Mexico. La Cortez Enterprises, Inc. was originally formed to create, market and sell gourmet chocolates wholesale and retail throughout Mexico, as more fully described in our registration statement on Form SB-2 as filed with the Securities and Exchange Commission (the “SEC”) on November 7, 2006 (the “Legacy Business”). In early 2008 after the Legacy Business terminated, our new Board of Directors decided to redirect the Company’s efforts towards identifying and pursuing business in the oil and gas sector in South America. As a reflection of this change in our strategic direction, we changed our name to La Cortez Energy, Inc.

In connection with the discontinuation of our Legacy Business, we decided to sell all of the assets and liabilities of the Legacy Business (the “Split-Off”) to Maria de la Luz, our founding stockholder.

As of August 15, 2008, we assigned all of our assets and property and all of our liabilities relating to the Legacy Business, accrued, contingent or otherwise to our newly organized, wholly owned subsidiary, de la Luz Gourmet Chocolates, Inc., a Nevada corporation (“Split-Off Sub”). Additionally, we sold all the outstanding capital stock of Split-Off Sub to Ms. de la Luz in exchange for 9,000,000 shares of our common stock previously surrendered by Ms. de la Luz and all of our common stock that Ms. de la Luz then owned, an additional 2,250,000 shares.

Pursuant to the terms of the Split-Off, Ms. de la Luz agreed to indemnify us and our officers and directors against any third party claims relating to the Legacy Business. 

As of August 15, 2008, Ms. de la Luz is no longer a stockholder in the Company.

In conjunction with the Split-Off Agreement and effective as of August 15, 2008, we entered into a General Release Agreement with Split-Off Sub and Ms. de la Luz, whereby Split-Off Sub and Ms. de la Luz pledged not to sue us from any and all claims, actions, obligations, liabilities and the like, incurred by Split-Off Sub or Ms. de la Luz arising from any fact, event, transaction, action or omission that occurred or failed to occur on or prior to August 15, 2008 and related to the Legacy Business.

ITEM 1A.  RISK FACTORS

THIS ANNUAL REPORT ON FORM 10-K CONTAINS CERTAIN STATEMENTS RELATING TO FUTURE EVENTS OR THE FUTURE FINANCIAL PERFORMANCE OF OUR COMPANY. YOU ARE CAUTIONED THAT SUCH STATEMENTS ARE ONLY PREDICTIONS AND INVOLVE RISKS AND UNCERTAINTIES, AND THAT ACTUAL EVENTS OR RESULTS MAY DIFFER MATERIALLY. IN EVALUATING SUCH STATEMENTS, YOU SHOULD SPECIFICALLY CONSIDER THE VARIOUS FACTORS IDENTIFIED IN THIS ANNUAL REPORT ON FORM 10-K, INCLUDING THE MATTERS SET FORTH BELOW, WHICH COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE INDICATED BY SUCH FORWARD-LOOKING STATEMENTS.

RISKS RELATED TO OUR BUSINESS AND FINANCIAL CONDITION

We are an early stage oil and gas exploration and production company with very limited operating history for you to evaluate our business. We may never attain profitability.

We are an early stage oil and gas exploration and production company and very limited oil and no natural gas operations. We do not have a full management team in place.  As an early stage oil and gas exploration and development company with very limited operating history, it is difficult for potential investors to evaluate our business. Our proposed operations are therefore subject to all of the risks inherent in light of the expenses, difficulties, complications and delays frequently encountered in connection with the formation of any new business, as well as those risks that are specific to the oil and gas industry and to that industry in South America, in particular. Investors should evaluate us in light of the delays, expenses, problems and uncertainties frequently encountered by companies developing markets for new products, services and technologies. We may never overcome these obstacles.

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Our senior management team is relatively new to our company and may not be able to develop and execute a successful business strategy.

Although our Chief Executive Officer is experienced in the oil and gas industry in South America, he is relatively new to our Company which itself is new to this business.  Our Chief Executive Officer is in the process of developing and executing a business strategy for the Company including, for example, the possible acquisition of oil and gas resources or the participation in joint exploration and production ventures. If our Chief Executive Officer is not able to develop a business strategy that is appropriate for our Company and which we can execute in a successful manner, our business could fail and we could lose all of our money.

We may be unable to obtain development rights that we need to build our business, and our financial condition and results of operations may deteriorate.

Our business plan focuses on international exploration and production opportunities in South America, initially in Colombia. Thus far, we have signed two participation interest agreements with partners in Colombia, only one of which (Maranta) is operational, and have acquired one non-producing company (Avante Colombia). In the event that these two initial projects do not proceed successfully or we do not succeed in negotiating any other property acquisitions, our future prospects will likely be substantially limited, and our financial condition and results of operations may deteriorate.

Our business is speculative and dependent upon the implementation of our business plan and our ability to enter into agreements with third parties for the rights to exploit potential oil and gas reserves on terms that will be commercially viable for us.

We may not be able to renegotiate Avante Colombia’s agreements with Ecopetrol in a manner that would permit us to successfully execute our plans with respect to the affected projects.

Our plans with respect to Avante Colombia’s business depend, among other things, on obtaining an extension of the term of existing contracts between Avante Colombia and Ecopetrol, which expire in December 2013.  We believe that, in order to negotiate a term extension, we will have to commit to additional investment in the area.  There can be no assurance that we will be able to negotiate a term extension with Ecopetrol or to do so on favorable terms.  If we fail to obtain a sufficient extension, or to do so on sufficiently favorable terms, it would have a material adverse effect on our planned operations for Avante Colombia.

Our lack of diversification will increase the risk of an investment in our common stock.

Our business will focus on the oil and gas industry in a limited number of properties, initially in Colombia, with the intention of expanding elsewhere in South America. Larger companies have the ability to manage their risk by diversification. However, we will lack diversification, in terms of both the nature and geographic scope of our business. As a result, factors affecting our industry or the regions in which we operate will likely impact us more acutely than if our business were more diversified.

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Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully bid on and acquire properties, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair La Cortez Energy’s ability to grow.

To develop our business, we will endeavor to use the business relationships of our management and our Board of Directors to enter into strategic relationships, which may take the form of joint ventures with other private parties or with local government bodies, or contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

Our strategic partners may change ownership or senior management, and this may negatively affect our business relationships with these partners and our results of operations.

Our strategic partners may change ownership or senior management, and this may negatively affect our business relationships with these partners and our results of operations.  It is possible that the change of ownership of any of our current or future strategic partners could have a negative impact on our relationship with them and we could lose our investment and suffer considerable losses if any of them should choose to discontinue our relationship or their involvement in a particular project or their operations in Colombia.

Competition in obtaining rights to explore and develop oil and gas reserves and to market our production may impair our business.

The oil and gas industry is extremely competitive. Present levels of competition for oil and gas resources in South America, and particularly in Colombia, are high.  Significant amounts of capital are being raised world-wide and directed towards the South American markets and more and more companies are pursuing the same opportunities.  Other oil and gas companies with greater resources than ours will compete with us by bidding for exploration and production licenses and other properties and services we will need to operate our business in the countries in which we expect to operate.  Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger, foreign owned companies, which, in particular, may have access to greater financial resources than us, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests.  Because of some or all of these factors, we may not be able to compete.

21

We may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow.

Our current capital and our other existing financial resources may not be sufficient to enable us to execute our business plan.  We may not have funds sufficient for any initial investments we might want to undertake.  Currently, we are generating only limited revenues. We will require additional capital to continue to operate our business beyond the initial phase, and we may need additional capital to develop and expand our exploration and development programs. We may be unable to obtain the additional capital required. Furthermore, inability to obtain capital may damage our reputation and credibility with industry participants in the event we cannot close previously announced transactions.

We expect to require approximately $2.8 million for our share of costs related to Phase 1 seismic acquisition and permitting activities in the Putumayo 4 Block during 2010.  We expect to require an additional approximately $5.4 million for our share of Phase 3 costs with respect to the Maranta Block in 2010, related to processing of the recently acquired 25 km of 3d seismic, conducting a workover on the Mirto-1 well, the drilling of two appraisal wells and the construction of the production facilities at the field.  If our negotiations with Ecopetrol regarding extending the contract terms for Rio de Oro and Puerto Barco are successful, then we expect to require up to $15 million of additional funds to pay for our share of costs with respect to additional seismic in the area and, depending upon seismic results, drilling an additional well during the next two years.

If we are not able to raise the required funds, we will not be able to meet our funding commitments on the Putumayo 4 Block, the Maranta Block and the Rio de Oro and Puerto Barco fields.  As a result, we may lose our interests in these projects and all previously invested capital.

Because we are an early stage exploration and development company with limited resources, we may not be able to compete in the capital markets with much larger, established companies that have ready access to large sums of capital.

Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.

We will require such additional capital in the near term and we plan to pursue sources of such capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in locating suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do succeed in raising additional capital, the capital received may not be sufficient to fund our operations going forward without obtaining further, additional capital financing. Furthermore, future financings are likely to be dilutive to our stockholders, as we will most likely issue additional shares of our common stock or other equity to investors in future financing transactions. In addition, debt and other mezzanine financing may involve a pledge of assets and may be senior to interests of equity holders.

Our ability to obtain needed financing may be impaired by such factors as conditions in the capital markets (both generally and in the oil and gas industry in particular), our status as a new enterprise without a demonstrated operating history, the location of our prospective oil and natural gas properties in developing countries and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and/or the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decrease, then our potential revenues will likely decrease, and such decreased future revenues may increase our requirements for capital. Some of the contractual arrangements governing our operations may require us to maintain minimum capital, and we may lose our contract rights (including exploration, development and production rights) if we do not have the required minimum capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations.

22

There is substantial doubt as to the Company’s ability to continue as a going concern.

In the course of its development activities, the Company has sustained losses and expects such losses to continue through at least December 31, 2010. The Company expects to finance its operations primarily through its existing cash and any future financing. However, there exists substantial doubt about the Company’s ability to continue as a going concern for a period longer than the next twelve months, because the Company will be required to obtain additional capital in the future to continue its operations and there is no assurance that it will be able to obtain such capital, through equity or debt financing, or any combination thereof, or on satisfactory terms or at all. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements included in this report that raises substantial doubt about our ability to continue as a going concern.  Our audited consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months.  Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of the going concern uncertainty.

We may be unable to meet our capital requirements in the future, causing us to curtail future growth plans or cut back existing operations.

We will need additional capital in the future, which may not be available to us on reasonable terms or at all. The raising of additional capital may dilute our stockholders’ interests. We may need to raise additional funds through public or private debt or equity financings in order to meet various objectives, including but not limited to:

· complying with funding obligations under our existing contractual commitments;

· pursuing growth opportunities, including more rapid expansion;

· acquiring complementary businesses;

· making capital improvements to improve our infrastructure;

· hiring qualified management and key employees;

· responding to competitive pressures;

· complying with licensing, registration and other requirements; and

· maintaining compliance with applicable laws.

Any additional capital raised through the sale of equity may dilute stockholders’ ownership percentage in us. This could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights, the issuance of warrants or other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

Furthermore, any additional financing we may need may not be available on terms favorable to us, or at all. If we are unable to obtain required additional financing, we may be forced to curtail our growth plans or cut back our existing operations.

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We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes and warrants, which will adversely impact our financial condition.

We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions building and expanding our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:

· expand our systems effectively or efficiently or in a timely manner;

· optimally allocate our human resources;

· identify and hire qualified employees or retain valued employees; or

· incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth and our operations, our financial results could be adversely affected by inefficiency, which could diminish our profitability.

Our business may suffer if we do not attract and retain talented personnel.

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting the business of La Cortez Energy. We are in the process of building our management team which currently consists of Andrés Gutierrez, our President and Chief Executive Officer, Nadine C. Smith, our Chairman, Vice President, Interim Chief Financial Officer and Interim Treasurer, Carlos Lombo, our Exploration Manager, and William Giron, our Production and Operations Manager, as well as a controller, an accountant, a geologist, an administrative/HR analyst and an administrative assistant. We need to hire a Chief Financial Officer.  The loss of any of these individuals or our inability to hire a qualified Chief Financial Officer or attract suitably qualified staff could materially adversely impact our business. We may also experience difficulties in certain jurisdictions in our efforts to obtain suitably qualified staff and retaining staff who are willing to work in that jurisdiction. We do not currently carry “key man” life insurance on our key employees.

Our success depends on the ability of our management and employees to interpret market and geological data correctly and to interpret and respond to economic market and other conditions in order to locate and adopt appropriate investment opportunities, monitor such investments and ultimately, if required, successfully divest such investments. Further, our key personnel may not continue their association or employment with La Cortez Energy and we may not be able to find replacement personnel with comparable skills. We have sought to and will continue to ensure that management and any key employees are appropriately compensated; however, their services cannot be guaranteed. If we are unable to attract and retain key personnel, our business may be adversely affected.

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If we are unable to hire a chief financial officer with public company experience, our ability to adequately manage the company’s finance function may be compromised.

Nadine C. Smith is currently serving as our interim Chief Financial Officer.  Although Ms. Smith has experience as a private company chief financial officer and qualifies as an “audit committee financial expert,” she needs to dedicate a considerable portion of her time and energy to her functions as Chairman of our Board of Directors.  We intend to hire a new Chief Financial Officer as soon as possible but if we are not able to do so, the Company may not be able to comply with ongoing regulatory internal financial control and reporting requirements.  Additionally, without an experienced public company Chief Financial Officer, the Company may not be able to adequately manage its finance function with respect to capital management, cost control and cash flow and as a result, its financial performance may suffer.

Our management team does not have extensive experience in U.S. public company matters, which could impair our ability to comply with U.S. legal and regulatory requirements.

Although our management team has senior management experience with companies based in Colombia, which were subsidiaries of large, foreign public reporting E&P entities, it has had limited U.S. public company management experience or responsibilities, which could impair our ability to comply with legal and regulatory requirements in the U.S., such as the Sarbanes-Oxley Act of 2002 and applicable federal securities laws, including filing required reports and other information required on a timely basis. Our management may not be able to implement and affect programs and policies in an effective and timely manner that adequately respond to increased legal, regulatory compliance and reporting requirements imposed by such laws and regulations. Our failure to comply with such laws and regulations could lead to the imposition of fines and penalties and further result in the deterioration of our business.

The potential profitability of oil and gas ventures in South America depends upon factors beyond our control.

The potential profitability of oil and gas properties in South America is dependent upon many factors beyond our control. For instance, world prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls, or any combination of these and other factors, and respond to changes in domestic, international, political, social, and economic environments. Additionally, due to worldwide economic uncertainty and greater competition among unprecedented numbers of market participants, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. These changes and events may materially affect our financial performance.

Oil and gas operations are subject to comprehensive regulation which may cause substantial delays or require capital outlays in excess of those anticipated, causing an adverse effect on our company.

Oil and gas operations are subject to national and local laws in South America relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to national and local laws and regulations in South America which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Environmental standards imposed by national or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages which we may elect not to insure against due to prohibitive premium costs and other reasons. To date, because we have had very limited operations, we have not been required to spend any amounts on compliance with environmental regulations. However, we may be required to expend substantial sums in the future and this may affect our ability to develop, expand or maintain our operations.

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Any change to government regulation/administrative practices may have a negative impact on our ability to operate and profitability.

The laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency in Colombia or any other jurisdiction where we might conduct our business activities, may be changed, applied or interpreted in a manner which will fundamentally alter the ability of our company to carry on our business.

The actions, policies or regulations, or changes thereto, of any government body or regulatory agency, or other special interest groups, may have a detrimental effect on us. Any or all of these situations may have a negative impact on our ability to operate profitably.

We may not be able to repatriate our earnings.

We will be conducting all of our operations in South America through branches or subsidiaries of one or more wholly owned, offshore subsidiaries established for this purpose.  Therefore, we will be dependent on the cash flows of our South American branches (or subsidiaries, as the case may be) and our offshore subsidiaries to meet our obligations.  Our ability to receive such cash flows may be constrained by taxation levels in the jurisdictions where our branches (or subsidiaries) operate and by the introduction of exchange controls and/or repatriation restrictions in the jurisdictions where we intend to operate.  Currently there are no such restrictions in Colombia on local earnings of foreign entities, but we cannot assure you that exchange or repatriation restrictions will not be imposed in the future.

Risks Related to Our Industry and Regional Focus

Current volatile market conditions and significant fluctuations, generally downward, in energy prices may continue indefinitely, negatively affecting our business prospects and viability.

Commodities and capital markets have been under great stress and volatility during the past year in part due to the credit crisis affecting lenders and borrowers on a worldwide basis. As a result of this crisis, crude oil prices tumbled from over one hundred forty dollars ($140) per barrel in mid 2008 to less than forty dollars ($40) per barrel in early 2009, causing companies to re-think existing strategies and new business ventures. We are vigilant of the situation unfolding and are adjusting our strategy to reflect these new market conditions. Nonetheless, we will not be immune to lower commodities prices and significantly more restrictive credit market conditions.  Our ability to enter into exploration and production projects may be compromised, and in a continuing environment of lower crude oil and natural gas prices, our future results of operations and market value could be affected negatively.

Difficult conditions in the global capital markets may significantly affect our ability and that of our strategic partners to raise additional capital.

The ongoing worldwide financial and credit crisis may continue indefinitely.  Because of severely reduced market liquidity, we may not be able to raise additional capital when we need it.  Because the future of our business will depend on the completion of one or more investment transactions for which, most likely, we will need additional capital, we may not be able to complete such transactions or acquire revenue producing assets.  As a result, we may not be able to generate income and, to conserve capital, we may be forced to curtail our current business activities or cease operations entirely.

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Our exploration for oil and natural gas is risky and may not be commercially successful, impairing our ability to generate revenues from our operations.

Oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.

We may not be able to develop oil and gas reserves on an economically viable basis.

To the extent that we succeed in discovering or acquiring oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce oil and gas reserves. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we cannot be assured of doing so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our future revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

We incurred a significant increase in expenses for the year ended December 31, 2009, as compared to 2008, due to impairment expenses and depletion expense on proved oil properties recognized for the year ended December 31, 2009, amounting to $6,403,544 and $303,059, respectively.  No such amounts were recorded during the year ended December 31, 2008, as there were no proved oil and gas reserves and no production in 2008.  Under our full cost method of accounting for our oil and natural gas properties, costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Oil and Gas Properties” below and Notes 1 and 13 to our consolidated financial statements included in this report for more information regarding the full cost method of accounting for our oil and natural gas properties and recognition of impairment expenses and depletion expense, and regarding our proved oil and natural gas reserves.

Estimates of oil and natural gas reserves that we make may be inaccurate and our future actual revenues may be lower than our financial projections.

With respect to any oil and gas properties that we may acquire, we will make estimates of oil and natural gas reserves, upon which we will base our financial projections. We will make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. Economic factors beyond our control, such as interest rates and exchange rates, will also impact the value of our reserves. The process of estimating oil and gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

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A shortage of drilling rigs and other equipment and geophysical service crews could hamper our ability to exploit any oil and gas resources we may acquire.

Because of the increased oil and gas exploration activities in South America and in Colombia in particular, competition for available drilling rigs and related services and equipment has increased significantly and these rigs and related items have become substantially more expensive and harder to obtain.  If we do acquire properties and related rights to drill wells, we may not be able to procure the necessary drill rigs and related services and equipment, or the cost of such items may be prohibitive.  Our ability to comply with future license obligations or otherwise generate revenues from the production of operating oil and gas wells could be hampered as a result of this, and our business could suffer.  Additionally, a shortage of crews available to shoot and process seismic activity could cause us to breach our obligations to Petronorte with respect to the Putumayo 4 Block.

Drilling wells could result in liabilities, which could endanger our interests in our prospective properties and assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills. The occurrence of any of these events could significantly reduce our future revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. We will obtain insurance with respect to these hazards as appropriate to our activities, but such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Decommissioning costs are unknown and may be substantial; unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we may use for production of oil and gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We have not yet established a cash reserve account for these potential costs because currently we do not own any properties or facilities.  We may establish such an account, however, for properties in which we have a participation interest. If decommissioning is required before economic depletion of our future properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

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Our inability to obtain necessary facilities could hamper our operations.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment, transportation, power and technical support in the particular areas where these activities will be conducted, and our access to these facilities may be limited. To the extent that we conduct our activities in remote areas, needed facilities may not be proximate to our operations, which will increase our expenses. Demand for such limited equipment and other facilities or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. The quality and reliability of necessary facilities may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail unanticipated costs and delays. Shortages and/or the unavailability of necessary equipment or other facilities will impair our activities, either by delaying our activities, increasing our costs or otherwise.

We may have difficulty distributing our production, which could harm our financial condition.

In order to sell the oil and natural gas that we may produce in the future, we would have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and gas production and may increase our expenses.

Furthermore, future instability in one or more of the countries in which we will operate, weather conditions or natural disasters, actions by companies doing business in those countries, labor disputes or actions taken by the international community may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our company.

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. The average price for West Texas Intermediate crude, the standard oil benchmark for the western hemisphere, in 1999 was $22 per barrel. In 2002 it was $27 per barrel. In 2005, it was $57 per barrel, and as of December 31, 2009 it was approximately $79 per barrel. In less than one year it tumbled from over one hundred forty dollars ($140) per barrel in mid 2008 to less than forty dollars ($40) per barrel in early 2009.  We expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry. Future decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.

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Increases in our operating expenses will impact our operating results and financial condition.

Exploration, development, production, marketing (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues we derive from the oil and gas that we may produce. These costs are subject to fluctuations and variation in different locales in which we will operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our results of operations. In addition, we may not be able to earn net revenue at our predicted levels, which may impact our ability to satisfy our obligations.

Penalties we may incur could impair our business.

Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipmentor taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.

Environmental risks may adversely affect our business.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and federal, provincial and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to foreign governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

Managing local community relations where we and our partners operate could be problematic.

We or our operating partners may be required to present our operational plans to local communities or indigenous populations living in the area of a proposed project before project activities can be initiated. Additionally, working with local communities will be an essential part of our work program for the development of any of our E&P projects in the region.  If we or our partners fail to manage any of these community relationships appropriately, our operations could be delayed or interrupted and we or our partners could lose rights to operate in these areas, resulting in a negative impact on our business, our reputation and, possibly, our share price.

Our insurance may be inadequate to cover liabilities we may incur.

Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we will obtain insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event or occurrence that is not fully insured, or if the insurer of such event is not solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events.

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Civil liabilities may not be able to be enforced against us.

Substantially all of our assets and certain of our officers and directors will be located outside of the United States.  As a result of this, it may be difficult or impossible to enforce judgments awarded by a court in the United States against our assets or those of our officers and directors.

Our business is subject to local legal, political and economic factors which are beyond our control, which could impair our ability to build and expand our operations or operate profitably.

We expect to operate our business in Colombia and other South American countries.  There are risks that economic and political conditions will change in a manner adverse to our interests. These risks include, but are not limited to, terrorism, military repression, interference with private contract rights (such as privatization), extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls and other laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls. Any changes in oil and gas or investment and tax regulations and policies or a shift in political attitudes in Colombia or other countries in which we intend to operate are beyond our control and may significantly hamper our ability to build and expand our operations or operate our business at a profit.

For instance, changes in laws in the jurisdiction in which we operate or expand into with the effect of favoring local enterprises, changes in political views regarding the exploitation of natural resources and economic pressures may make it more difficult for us to negotiate agreements on favorable terms, obtain required licenses, comply with regulations or effectively adapt to adverse economic changes, such as increased taxes, higher costs, inflationary pressure and currency fluctuations.

Insurgent and criminal activities in the territories in which we operate, or the perception that such activities are likely, may disrupt our operations, hamper our ability to hire and keep qualified personnel and impair our access to sources of capital.

Colombia has been the site of South America’s largest and longest political and military insurgency and has experienced uncontrolled criminal activity relating to drug trafficking. While the situation has improved dramatically in recent years, there can be no guarantee that the situation will improve further or that it will not deteriorate in Colombia or any other territories in which we may operate.  Insurgent or criminal activities (including kidnapping and terrorism) in any of the territories in which we operate, or the perception that such activities are likely, may disrupt our operations in that country, hamper our ability to hire and keep qualified personnel and hinder or shut off our access to sources of capital.  Any such changes are beyond our control and may adversely affect our business.

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The Rio de Oro and Puerto Barco E&P projects operated by Avante Colombia were attacked and the facilities destroyed by insurgents in July 2008, and the field has been shut in since then.  Failure to successfully repair these facilities and avoid similar attacks in the future would materially impair Avante Colombia’s business.

In July 2008, the Revolutionary Armed Forces of Colombia (known by their Spanish acronym “FARC”) attacked the Rio de Oro and Puerto Barco E&P projects that Avante Colombia operates in the Catatumbo area of eastern Colombia.  As a result of such attack, Avante Colombia’s facilities were destroyed, and the fields have been shut in ever since then.  There can be no assurance that we will be able to successfully repair these facilities and re-open the fields.  Even if we do repair these facilities, there can be no assurance that future attacks by FARC or others will not damage or destroy these properties and have a material adverse effect on our business.  Moreover, even if our properties are not subject to actual attacks in the future, the perception that such attacks may occur could impair our ability to retain personnel, rent equipment or conduct other activities necessary or desirable to carry out our business plan.

Local legal and regulatory systems in which we operate may create uncertainty regarding our rights and operating activities, which may harm our ability to do business.

We are a company organized under the laws of the State of Nevada and are subject to United States laws and regulations. The jurisdictions in which we intend to operate our exploration, development and production activities may have different or less developed legal systems than the United States, which may result in risks such as:

· effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or regulation, or, in an ownership dispute, being more difficult to obtain;

· a higher degree of discretion on the part of governmental authorities;

· the lack of judicial or administrative guidance on interpreting applicable rules and regulations;

· inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions; and

· relative inexperience of the judiciary and courts in such matters.

In certain jurisdictions the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licenses and agreements for business. These licenses and agreements may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. Property right transfers, joint ventures, licenses, license applications or other legal arrangements pursuant to which we operate may be adversely affected by the actions of government authorities and the effectiveness of and enforcement of our rights under such arrangements in these jurisdictions may be impaired.

Our business will suffer if we or our strategic partners cannot obtain or maintain necessary licenses.

Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors. Our inability to obtain, or our loss of or denial of extension to any of these licenses or permits could hamper our ability to produce revenues from our operations.

The ANH may not approve the assignment of rights to us in the E&P properties in which we have invested and are continuing to invest, and, as a result, we may not be able to legally protect our rights under our agreements with the operators of the applicable properties.

Our operating subsidiary, La Cortez Colombia, has completed paying all of its Phase 2 commitments on the Maranta Block and Emerald is ready to assign and transfer to La Cortez Colombia the agreed upon 20% participating interest in the Maranta Block, subject to approval by Colombia’s hydrocarbon regulatory agency, the ANH.  We have submitted to Emerald the required written request for Emerald to apply to the ANH for approval of the assignment.  If the ANH does not approve this assignment, Emerald and we have agreed to use our best endeavors to seek in good faith a legal way to enter into an agreement with terms equivalent to their farm-in agreement and joint operating agreement, that shall privately govern the relations between the parties and which will not require ANH approval.  If Emerald and we are not able to do this, then we may not be able to legally protect or enforce our rights under the farm-in agreement, resulting, possibly, in capital and income losses to us.

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Once we have completed paying all of our Phase 2 commitments on the Putumayo 4 Block, Petronorte will assign and transfer to us the agreed upon 50% participating interest in the Putumayo 4 Block, subject to ANH approval.  Similarly, the ANH must approve any assignment of participating interests in Colombian E&P properties to us by the applicable operator.  If the ANH does not approve any of these assignments and we are not able to work out a favorable alternative arrangement with the applicable operator, then we may not be able to legally protect or enforce our rights to the affected E&P property and our business may be materially adversely affected.

Foreign currency exchange rate fluctuations may affect our financial results.

We expect to sell any future oil and natural gas production under agreements that will be denominated in United States dollars and foreign currencies. Many of the operational and other expenses we incur will be paid in the local currency of the country where we perform our operations. As a result, fluctuations in the United States dollar against the local currencies in jurisdictions where we operate could result in unanticipated and material fluctuations in our financial results.

Local operations may require funding that exceeds operating cash flow and there may be restrictions on expatriating proceeds and/or adverse tax consequences associated with such funding.

We will rely on technology to conduct our business and our technology could become ineffective or obsolete.

We will rely on technology, including geographic and seismic analysis techniques and economic models, to develop reserve estimates and to guide our planned exploration and development and production activities. We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

RISKS RELATED TO OUR SECURITIES

There is not now, and there may not ever be, an active market for our common stock.

There currently is a limited public market for our common stock.  Further, although our common stock is currently quoted on the OTC Bulletin Board (the “OTCBB”), trading of our common stock may be extremely sporadic.  For example, several days may pass before any shares are traded.  As a result, an investor may find it difficult to dispose of, or to obtain accurate quotations of the price of, our common stock.  Accordingly, investors must assume they may have to bear the economic risk of an investment in our common stock for an indefinite period of time.  There can be no assurance that a more active market for our common stock will develop, or if one should develop, there is no assurance that it will be sustained.  This severely limits the liquidity of our common stock, and would likely have a material adverse effect on the market price of our common stock and on our ability to raise additional capital.

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We cannot assure you that our common stock will become liquid or that it will be listed on a securities exchange.

Until our common stock is listed on a national securities exchange such as the New York Stock Exchange or the Nasdaq National Market, we expect our common stock to remain eligible for quotation on the OTCBB, or on another over-the-counter quotation system, or in the “pink sheets.” In those venues, however, an investor may find it difficult to obtain accurate quotations as to the market value of our common stock.  In addition, if we fail to meet the criteria set forth in SEC regulations, various requirements would be imposed by law on broker-dealers who sell our securities to persons other than established customers and accredited investors.  Consequently, such regulations may deter broker-dealers from recommending or selling our common stock, which may further affect the liquidity of our common stock.  This would also make it more difficult for us to raise capital.

Our common stock is subject to the “penny stock” rules of the SEC and the trading market in our common stock is limited, which makes transactions in our common stock cumbersome and may reduce the value of an investment in the stock.

The SEC has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

●  that a broker or dealer approve a person’s account for transactions in penny stocks; and

●  the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

●  obtain financial information and investment experience objectives of the person; and

●  make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form sets forth:

●  the basis on which the broker or dealer made the suitability determination; and

●  that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of common stock and cause a decline in the market value of stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

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The price of our common stock may become volatile, which could lead to losses by investors and costly securities litigation.

The trading price of our common stock is likely to be highly volatile and could fluctuate in response to factors such as:

· actual or anticipated variations in our operating results;

· announcements of developments by us, our strategic partners or our competitors;

· announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;

· adoption of new accounting standards affecting our Company’s industry;

· additions or departures of key personnel;

· sales of our common stock or other securities in the open market; and

· other events or factors, many of which are beyond our control.

The stock market is subject to significant price and volume fluctuations. In the past, following periods of volatility in the market price of a company’s securities, securities class action litigation has often been initiated against the company. Litigation initiated against us, whether or not successful, could result in substantial costs and diversion of our management’s attention and resources, which could harm our business and financial condition.

We do not anticipate dividends to be paid on our common stock, and investors may lose the entire amount of their investment.

Cash dividends have never been declared or paid on our common stock, and we do not anticipate such a declaration or payment for the foreseeable future. We expect to use future earnings, if any, to fund business growth. Therefore, stockholders will not receive any funds absent a sale of their shares. We cannot assure stockholders of a positive return on their investment when they sell their shares, nor can we assure that stockholders will not lose the entire amount of their investment.

If securities analysts do not initiate coverage or continue to cover our common stock or publish unfavorable research or reports about our business, this may have a negative impact on the market price of our common stock.

The trading market for our common stock may be affected by, among other things, the research and reports that securities analysts publish about our business and the Company. We do not have any control over these analysts. There is no guarantee that securities analysts will cover our common stock. If securities analysts do not cover our common stock, the lack of research coverage may adversely affect its market price. If we are covered by securities analysts, and our stock is the subject of an unfavorable report, our stock price and trading volume would likely decline. If one or more of these analysts ceases to cover the Company or fails to publish regular reports on the Company, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.

You may experience dilution of your ownership interests because of the future issuance of additional shares of our common stock.

In the future, we may issue our authorized but previously unissued equity securities, resulting in the dilution of the ownership interests of our present stockholders and the purchasers of our common stock offered hereby.  We are currently authorized to issue an aggregate of 310,000,000shares of capital stock consisting of300,000,000 shares of common stock and 10,000,000 shares of preferred stock with preferences and rights to be determined by the our  Board of Directors.  As of April 12, 2010, there were40,000,349 shares of our common stock and no shares of our preferred stock outstanding.  There are4,000,000 shares of our common stock reserved for issuance under our Amended and Restated 2008 Equity Incentive Plan.  These numbers do not include 12,218,636 shares of our common stock issuable upon the exercise of outstanding warrants.  We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for our common stock in connection with hiring or retaining employees, future acquisitions, future sales of its securities for capital raising purposes, or for other business purposes.  The future issuance of any such additional shares of our common stock may create downward pressure on the trading price of the common stock.  We will need to raise additional capital in the near future to meet our working capital needs and there can be no assurance that we will not be required to issue additional shares, warrants or other convertible securities in the future in conjunction with these capital raising efforts, including at a price (or exercise prices) below the price at which shares of our common stock are currently traded on the OTCBB.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

Executive Offices

Our executive offices are located at Calle 67 #7-35, Oficina 409, Bogota, Colombia.  At this location we rent approximately 3,000 square feet of office space under a three year lease.  We do not rent or own any other property.

Description of Properties

Colombia

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Source:  Google Earth

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Maranta and Putumayo 4 Blocks

Source: La Cortez Energy, Inc.

Putumayo 4

On December 22, 2008, we entered into the MOU with Petronorte that entitles us to a 50% net working interest in the Putumayo 4 Block.  We executed the joint operating agreement with Petronorte relating to the Putumayo 4 Block on October 14, 2009, effective retroactively to February 23, 2009.  

The Putumayo 4 Block covers an area of 126,845 acres (51,333 hectares) located in the Putumayo Basin in southern Colombia and has over 400 km of pre-existing 2D seismic through which Petronorte has identified promising leads.

There are four existing wells in the Putumayo 4 Block that date back to the 1970’s. Even though information is scarce, these wells intended to reach the Caballos formation and in doing so, oil shows were recorded from the Villeta formation, our primary objective. Furthermore, neighboring and close fields, including Nancy-Burdine-Maxine, Costayaco and Orito, have been prolific hydrocarbon producers, partially affirming our reserve expectations in the block.

Infrastructure in the Putumayo region has been rapidly improving. Several important discoveries, including one competitor’s discovery in Costayaco, have resulted in an influx of companies into the region, resulting in a reduction in oil services fees and improving security in the area. Specifically, the Putumayo 4 Block is located near the Orito field, run by Ecopetrol, which is a receiving station for a pipeline to the port Tumaco on the Colombian Pacific. Transportation of potential crude production from the Putumayo 4 Block could be trucked easily to Orito through the paved roads in the area.

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The Putumayo 4 Block

Source:  La Cortez Energy, Inc.

Maranta

On February 6, 2009, La Cortez Colombia entered into the Farm-In Agreement with Emerald for a 20% Participating Interest in the Maranta Block in the Putumayo Basin in Southwest Colombia.  We executed the joint operating agreement with Emerald relating to the Maranta Block on February 4, 2010.  The Maranta Block covers an area of 90,459 acres (36,608 hectares) in the foreland of the Putumayo Basin.  The Maranta Block is adjacent to the recent 20 million barrel proven discovery of the Costayaco field made by Gran Tierra Energy, Inc. (AMEX: GTE).

Emerald was awarded the Maranta Block E&P contract by the ANH on September 12, 2006.  The E&P contract granted Emerald a 100% working interest in the Maranta Block for an exploration period of up to six years with an initial production period of up to 24 years.

The first phase of the Emerald’s exploration period lasted 18 months with a minimum work program that was comprised of the acquisition of 30 square kilometers of new 2D seismic data and the re-processing of 40 square kilometers of existing 2D seismic data. Emerald extended its work program and shot an additional 41 square kilometers of 2D seismic to better map out the geological structures in the block.

The Maranta Block is adjacent to nearby producing oil fields and close to recent discoveries that have tested oil up to 7,000 barrels per day. Emerald identified a number of prospects and leads at an estimated depth of some 11,000 ft from the existing seismic data, each with an unrisked prospective resource potential estimated to be between 5 and 15 million barrels.

The Umbria #1 well was drilled in the Maranta Block in 1967 and encountered oil in the Villeta formation.  There may also be potential to re-enter this well to further test the formation productivity3.

3.  Source:  Emerald Energy Plc

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The Maranta Block

Source: Emerald Energy Plc., La Cortez Energy, Inc.

A 2D seismic program was acquired by Emerald in 2007 with the aim of maturing the identified prospects and leads to a drill-ready status. In March 2008, Emerald elected to enter the second phase of the exploration period, with a duration of 12 months and a minimum work program comprising the drilling of one well, planned to commence by the second quarter of 2009.

Emerald reached the intended total depth of 11,578 ft on the Mirto-1 exploration well on July 21, 2009, with oil and gas shows recorded across the four target reservoirs. All of the four potentially hydrocarbon bearing intervals have been flow tested with the Villeta U and N sand intervals flowing at an initial oil rate of 731 BOPD and 247 BOPD, respectively.  The well was completed with an Electric Submersible Pump (ESP) at 7,043 feet. The drilling rig was released on October 4, 2009.

The Caballos formation interval was flow tested with only formation water recovered at an average rate of 112 barrels per day. The Villeta T sand interval was also flow tested with an average oil rate of 8 barrels per day with a very high water production (water cut of 97%).

The Villeta U sand interval (encountered at a depth of 11,030 feet) produced an average oil rate of 731 barrels per day of 32.5 API crudeover a 48 hour period with a low average water production (water cut of 26%). An interval of 20 feet at the top of the sand was flow tested through a 128/64 inch choke, under artificial lift using a jet pump.

Flow testing operations have been completed in the Cretaceous aged Villeta N sands, the shallowest of four sands flow tested in this well. The 7 feet interval at 10,410 feet produced 15 degrees API oil at an average rate of 247 barrels per day over a 48 hour period, under artificial lift using a jet pump and through a 128/64 inch choke, with an average water cut of 64%.

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Currently, the Villeta U sand interval is being production tested at an average rate of 145 BOPD (gross) of good quality oil, 31.5 degrees API, with an average BS&W (basic sediment and water) of 80%. Emerald, as operator of the Maranta Block, determined to enter the Phase 3 exploration commitment in the Maranta Block, which entails the drilling of an additional exploratory/appraisal well plan for early May and the acquisition of 31 km2 of 3D seismic that have been acquired.

A workover job on the Mirto-1 well was completed on March 6, 2010, which attempted to isolate a water production formation. It is believed that water is coming into the well through poor cement bonding behind casing as observed in the “cement bond log.” After a technical meeting held with the operator on March 25 to evaluate the workover results, La Cortez has concluded that the attempt to isolate the water production formation was not successful; therefore, both the operator and La Cortez have decided to continue producing from the well with a high water cut. It is planned that after the Mirto-2 appraisal well has been drilled and completed, a new intervention in Mirto-1 well will be executed to increase perforation density of the producing “U” sand to increase total production capacity of the well.

Emerald and La Cortez continue to believe that despite the mechanical problems encountered in the Mirto-1 well, there is sufficient accumulation of hydrocarbons in the area to merit the drilling of at least two additional wells. The location for Mirto-2 appraisal well is completed. The drilling rig has been contracted out and rig mobilization is underway. Mobilization is expected to take at least three weeks; therefore, the estimated spud date of the Mirto-2 appraisal well is expected by late April or early May.

Rio de Oro and Puerto Barco

The Rio de Oro and Puerto Barco exploration and production contracts are located in the Catatumbo basin in eastern Columbia. These fields initiated production about 50 years ago and produced good quality oil mainly from the Uribante group (Tibu, Aguardiente and Mercedes cretaceous formations). Main production was obtained from the Rio de Oro field. The contracts cover an area of 2,262 hectares in Rio de Oro and 12,646 hectares in Puerto Barco. The contract started in December 2003 and will expire in December 2013.

After completion of the acquisition of Avante Colombia  on March 4, 2010, we have continued to conduct social activities in the area and have defined a potential long term activity program/investment in conjunction with our joint venture partner Vetra.  In addition, preliminary discussions with Ecopetrol seeking an extension of the exploration and production contract have been initiated. La Cortez is in the process of defining the activities to have an early production from Puerto Barco field by the end of this year by reopening one or more existing wells.

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ITEM 3. LEGAL PROCEEDINGS

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm business. We are currently not aware of any such legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse affect on business, financial condition or operating results.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information and Holders

As of April 12, 2010, there were 40,000,349 shares of our common stock issued and outstanding, 12,218,636 shares issuable upon exercise of outstanding warrants and 2,535,000 shares issuable upon exercise of outstanding options.  On that date, there were 59 holders of record of shares of our common stock. 

Our common stock is listed on the OTCBB under the symbol “LCTZ.OB.”

The following table sets forth the high and low closing bid prices for our common stock for the fiscal quarters indicated as reported on the OTCBB. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions. Our common stock is thinly traded and, thus, pricing of our common stock on the OTCBB does not necessarily represent its fair market value.

Period	High (1)			Low (1)
Fiscal Year Ended December 31, 2008:
First Quarter	$	2.00		$	0.06
Second Quarter		2.50	(2)		2.00
Third Quarter		2.90	(2)		1.01
Fourth Quarter		1.50	(2)		1.01
Fiscal Year Ending December 31, 2009:
First Quarter	$	1.75		$	1.50
Second Quarter		1.95			1.75
Third Quarter		2.10			1.50
Fourth Quarter		2.70			2.10

(1) All prices give retroactive effect to a 5:1 forward stock split that was effected on February 27, 2008.

(2) During this period, our common stock traded on the OTCBB above this closing bid price. Our common stock is thinly traded and, thus, pricing of our common stock on the OTCBB does not necessarily represent its fair market value.

Dividends

We have never declared any cash dividends with respect to our common stock.  Future payment of dividends is within the discretion of our Board of Directors and will depend on our earnings, capital requirements, financial condition and other relevant factors.  Although there are no material restrictions limiting, or that are likely to limit, our ability to pay dividends on our common stock, we presently intend to retain future earnings, if any, for use in our business and have no present intention to pay cash dividends on our common stock.

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Recent Sales of Unregistered Securities

On March 14, 2008, we closed a private placement of our common stock, $0.001 par value per share.  In this private placement, we offered our shares of common stock at a price of $1.00 per share and we derived total proceeds of $2,314,895, net after expenses, from the sale of 2,400,000 shares of our common stock.Investors in this offering included our Chairman, Nadine C. Smith, who purchased 500,000 shares, for an aggregate purchase price of $500,000, on the same terms as the other investors.

On September 10, 2008, we closed a private placement of units.  Each unit consisted of (i) one share of our common stock and (ii) a common stock purchase warrant to purchase one-half share of common stock, exercisable for a period of five years at an exercise price of $2.25 per share. We offered these units at a price of $1.25 per unit and we derived total proceeds of $5,981,000 ($5,762,126 net after expenses) from the sale of 4,784,800 units. Investors in this offering included our Chairman, Nadine C. Smith, who purchased 400,000 units, for an aggregate purchase price of $500,000, and our Chief Executive Officer, Andres Gutierrez Rivera, who purchased 50,000 units, for an aggregate purchase price of $62,500, on the same terms as the other investors.

On June 19, 2009, we conducted an initial closing of a private placement of units.  Each unit consisted of (i) one share of our common stock and (ii) a common stock purchase warrant to purchase one share of common stock, exercisable for a period of five years at an exercise price of $2.00 per share. We offered these units at a price of $1.25 per unit and we derived total proceeds at the initial closing of $6,074,914 ($5,244,279 net after expenses) from the sale of 4,860,000 units.  On July 31, 2009, we completed the final closing of our 2009 unit offering.  At the final closing, we received gross proceeds of $256,250 from the sale of 205,000 units.   In the aggregate, we received gross proceeds of $6,331,164 in the 2009 unit offering on the sale of a total of 5,065,000 units.  The 2009 unit offering terminated on July 31, 2009.Investors in this offering included our Chairman, Nadine C. Smith, who purchased 160,000 units on June 19, 2009, for an aggregate purchase price of $200,000, on the same terms as the other investors.

On December 29, 2009, we conducted an initial closing of our second 2009 private placement of units, selling 1,428,571 units at a price of $1.75 per unit, for aggregate gross proceeds to us of $2.5 million.  We conducted a second closing of this offering on January 29, 2010, in which we sold 571,428 units for aggregate gross proceeds of $1 million, and a third closing on March 2, 2010,in which we sold 857,144 units for aggregate gross proceeds of $1.5 million.  Each of these units consisted of (i) one share of our common stock and (ii) a common stock purchase warrant to purchase one-half (1/2) of one share of our common stock, exercisable for a period of three years at an exercise price of $3.00 per whole share.  Investors in this offering included our Chairman, Nadine C. Smith, who purchased 58,000 units on March 2, 2010, for an aggregate purchase price of $101,500, on the same terms as the other investors.

The sales of securities in the above private placements were exempt from registration under the Securities Act in reliance upon Regulation D and Regulation S promulgated by the SEC thereunder and were sold only to “accredited investors,” as defined in Regulation D, and non-“U.S. persons” as defined in Regulation S.

On March 2, 2010, in exchange for all of the outstanding capital stock of Avante Colombia, we issued to Avante an aggregate of 10,285,819 shares of our common stock, and Avante purchased 2,857,143 additional shares of our common stock and three-year warrants to purchase 2,857,143 shares of our common stock at an exercise price of $3.00 per share, for an aggregate purchase price of $5,000,000 (or $1.75 per share of common stock purchased).

Our issuance of the shares to Avante in connection with the acquisition and the purchase by Avante of the shares and warrants were not registered under the Securities Act in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act, which exempts transactions by an issuer not involving any public offering, and Regulation D and Regulation S.  

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The Avante warrants are initially exercisable until three years after the closing date; provided, that, in the event that we consummate any Covered Offering in which the securities sold include warrants to purchase our common stock (“Other Warrants”) and the expiration date of such Other Warrants is more than three years after the Closing Date, then the expiration date of the Avante warrants shall be extended to the latest expiration date of any such Other Warrants.  

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

During the fourth quarter of the fiscal year covered by this report, no purchases were made by or on behalf of the Company or any “affiliated purchaser,” as defined in Rule 10b-18(a)(3) under the Exchange Act, of shares or other units of any class of the Company’s equity securities.

Securities Authorized for Issuance under Equity Compensation Plans

We adopted our 2008 Equity Incentive Plan on February 7, 2008, and amended and restated the 2008 Equity Incentive Plan as of November 7, 2008. The Amended and Restated 2008 Equity Incentive Plan was approved by our Board and a majority of the outstanding shares of our common stock4 and allows for awards of up to an aggregate of 4,000,000 shares of our common stock, subject to adjustment under certain circumstances. If an incentive award granted under the 2008 Equity Incentive Plan expires, terminates, is unexercised or is forfeited, or if any shares are surrendered to us in connection with an incentive award, the shares subject to such award and the surrendered shares will become available for further awards under the 2008 Equity Incentive Plan. As of December 31, 2009, we have granted option awards under the 2008 Equity Incentive Plan exercisable for a net aggregate of 2,451,667 shares of our common stock. We have not maintained any other equity compensation plans since our inception.

See “Executive Compensation” for information regarding individual equity compensation arrangements received by our executive officers pursuant to their employment agreements with us.

 

4. Our November 7, 2008, amendment to increase the size of our equity incentive plan from 2,000,000 shares to 4,000,000 shares was approved by our majority stockholders as of October 12, 2009.

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The following table sets forth information about the Company’s equity compensation plans as of December 31, 2009:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights			Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders		2,435,000	(1)	$	2.12		1,465,000	(1)
Equity compensation plans not approved by security holders		-			-		-
Total		2,435,000		$	2.12		1,465,000

(1)  2008 Equity Incentive Plan.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. This discussion contains forward-looking statements that involve risks, uncertainties and assumptions. See “Note Regarding Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors discussed in “Risk Factors” and elsewhere in this report.

The following discussion and analysis of the Company’s financial condition and results of operations are based on our audited consolidated financial statements, which have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred.  

Overview and Going Concern

We are an international, early stage oil and gas exploration and production company focusing our business in South America. We have established an operating branch in Colombia.  We have entered into two initial working interest agreements, with Petronorte and with Emerald.  We have also acquired Avante Colombia. We are currently evaluating additional investment prospects, companies and existing exploration and production opportunities in Colombia, while keeping alert for opportunities in other South American countries.

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We were incorporated in the State of Nevada on June 9, 2006 under the name La Cortez Enterprises, Inc. to pursue certain business opportunities in Mexico5. During 2008, our Board of Directors decided to redirect the Company’s efforts towards identifying and pursuing business in the oil and gas sector in South America. As a reflection of this change in our strategic direction, we changed our name to La Cortez Energy, Inc.

Going Concern

In the course of its development activities, the Company has sustained losses and expects such losses to continue through at least December 31, 2010.  The Company expects to finance its operations primarily through its existing cash and any future financing. However, there exists substantial doubt about the Company’s ability to continue as a going concern because the Company will be required to obtain additional capital in the future to continue its operations and there is no assurance that it will be able to obtain such capital, through equity or debt financing, or any combination thereof, or on satisfactory terms or at all. Additionally, no assurance can be given that any such financing, if obtained, will be adequate to meet the Company’s ultimate capital needs and to support the Company’s growth. If adequate capital cannot be obtained on a timely basis and on satisfactory terms, the Company’s operations would be materially negatively impacted.   Therefore, there is substantial doubt as to the Company’s ability to continue as a going concern for a period longer than the next twelve months. Additionally, our independent auditors included an explanatory paragraph in their report on our consolidated financial statements included in this report that raises substantial doubt about our ability to continue as a going concern.  The Company’s ability to complete additional offerings is dependent on the state of the debt and/or equity markets at the time of any proposed offering, and such market’s reception of the Company and the offering terms. In addition, the Company’s ability to complete an offering may be dependent on the status of its oil and gas exploration activities, which cannot be predicted. There is no assurance that capital in any form would be available to the Company, and if available, on terms and conditions that are acceptable.

Our audited consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of the going concern uncertainty.

Recent Developments

The Maranta Block

Emerald, the operator of the Maranta Block reached the intended total depth of 11,578 feet on the Mirto-1 exploration well on July 21, 2009, with oil and gas recorded across three of the four target reservoirs.  Flow testing operations were completed in the  Villeta U sand interval (encountered at a depth of 11,030 feet) produced an average oil rate of 731 barrels of oil per day (bopd) of 32.5º API crude over a 48 hour period with a low average water production (water cut of 26%).  An interval of 20 feet at the top of the sand was flow tested through a 128/64 inch choke, under artificial lift using a jet pump. The Villeta N sand, the upper most of the sands tested in this well, produced oil of 15 º API (American Petroleum Institute) at an average rate of 247 bopd over a 48 hour period, under artificial lift using a jet pump and through a 128/64 inch choke, with an average water cut of 64%.  The drilling rig was released and the well was completed with an Electric Submersible Pump (ESP) at 7,043 feet on October 4, 2009.  Since then, the well has been on a production test of the Villeta U sand interval at a current stabilized average rate of 145 bopd gross of good quality oil (31.5 º API) with an average BS&W (basic sediment and water) of 82%, mainly due to the unsolved poor cement bonding problem.  We will hold a 20% participating interest in the Maranta Block through our Cayman Islands operating subsidiary, La Cortez Colombia.

 

5. We were originally formed to create, market and sell gourmet chocolates wholesale and retail throughout Mexico, as more fully described in our registration statement on Form SB-2 as filed with the SEC on November 7, 2006.

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On July 23, 2009, based on the preliminary results of the drilling of the Mirto-1 well, we decided to participate with Emerald in the completion and evaluation of Mirto-1.  In accordance with the terms of the Maranta Block farm-in agreement, we have borne 65% of the Maranta Block Phase 2 exploration costs, including 65% ($1.2285 million) of the $1.8 million Mirto-1 completion costs.  We made this $1.2285 million payment to Emerald on July 27, 2009.  65% of any additional Phase 2 costs were paid by us as needed, following cash calls by Emerald.  On August 4, 2009, we paid an additional $243,300 to Emerald for overhead costs, representing 5% of total expenditures, in accordance with the farm-in agreement.  As of December 31, 2009, we accrued costs amounting to $1,585,795 which were capitalized to oil and natural gas properties representing additional costs equivalent to 65% of Mirto well costs as of that date, in accordance with the farm-in agreement.  On January 7, 2010, we paid an additional $1.41 million to Emerald, consisting of exploration costs associated with the Mirto-1 well, as well as certain 3d seismic and facilities costs.  On February 5, 2010, we paid an additional $234,553 to Emerald for our portion of the cost of production facilities, 3D seismic acquisition and final exploration costs of the Mirto-1 well. 

Now that the Phase 2 work is completed (drilling and completion of the Mirto-1 exploratory well), we will pay 20% of all subsequent costs related to the Maranta Block. The Company has the final Mirto-1 evaluation results, and on January 12, 2010, La Cortez Colombia asked Emerald to file a request with the ANH, to have its agreed to 20% participating interest in the Maranta Block officially assigned from Emerald to La Cortez Colombia.  

The evaluation of the Mirto-1 exploratory well across all of the target reservoirs has been completed.  Following the completion of operations in the Mirto-1 well, the drilling rig was released from the well location. On March 6, 2010, Emerald completed a workover job on the Mirto-1 well, which attempted to isolate a water production formation. It is believed that water is coming into the well through poor cement bonding behind casing as observed in the “cement bond log”. After a technical meeting held with the operator on March 25, 2010 to evaluate the workover results obtained in the last two weeks, La Cortez has concluded that the attempt to isolate the water production formation was not successful; therefore, both the operator and La Cortez have decided to continue producing from the well with a high water cut. It is planned that after the Mirto-2 appraisal well has been drilled and completed, a new intervention in Mirto-1 well will be executed to increase perforation density of the producing “U” sand to increase total production capacity of the well.

Ryder Scott Company (“Ryder Scott”), an independent petroleum engineer, has estimated our proved developed oil and natural gas reserves in the Mirto field as 74,230 barrels as of December 31, 2009.  We held no proved reserves prior to 2009.  These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules and accounting standards based on the 12-month un-weighted first-day-of-the-month average price for December 31, 2009.   We incurred a significant increase in expenses for the year ended December 31, 2009, as compared to 2008, due to impairment expenses and depletion expense on our proved oil reserves in Maranta recognized for the year ended December 31, 2009, amounting to $6,403,544 and $303,059, respectively.  No such amounts were recorded during the year ended December 31, 2008, as there were no proved oil and gas reserves and no production in 2008.  Under our full cost method of accounting for our oil and natural gas properties, costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense.  Total production from the well in 2009 was 2,963 barrels. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Oil and Gas Properties” below and Notes 1 and 13 to our consolidated financial statements included in this report for more information regarding the full cost method of accounting for our oil and natural gas properties and recognition of impairment expenses and depletion expense, and regarding our proved oil and natural gas reserves.

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Emerald and La Cortez continue to believe that despite the mechanical problems encountered in the Mirto-1 well, there is sufficient accumulation of hydrocarbons in the area to merit the drilling of at least two additional wells. Consequently, civil works (access roads and rig locations) for the two appraisal wells planned for this year are underway. The location for Mirto-2 was completed at the end of first week of April.  The drilling rig has been contracted out, and the contractor initiated mobilization during the second week of April.  Mobilization is expected to take at least three weeks; therefore, the estimated spud date of the Mirto-2 appraisal well is expected by late April or early May 2010.

Emerald, as operator of the Maranta Block, has determined to enter the Phase 3 exploration work commitment in the Maranta Block, which will entail the drilling of an additional exploration/appraisal well, the workover of the Mirto-1 well Approximately 25 km of 3D seismic has already been acquired as part of this new phase of work.

On February 4, 2010, La Cortez Colombia signed a joint operating agreement with Emerald with respect to the Maranta Block and, we have asked Emerald to submit a request to the ANH to approve the assignment of our 20% participating interest to us.  If the ANH does not approve this assignment, Emerald and we have agreed to use our best endeavors to seek in good faith a legal way to enter into an agreement with terms equivalent to the farm-in agreement and the joint operating agreement, that shall privately govern the relations between the parties with respect to the Maranta Block and which will not require ANH approval.

Effective October 12, 2009, Emerald’s parent, Emerald Energy Plc, was acquired by Sinochem Resources UK Limited, a United Kingdom subsidiary of Sinochem Group, a Chinese state-owned energy and chemicals conglomerate.

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The Putumayo 4 Block

On October 14, 2009, we executed our joint operating agreement with Petronorte for joint development of the Putumayo 4 Block in Colombia.  This joint operating agreement governs our working relationship with Petronorte with respect to the Putumayo 4 Block, based on the terms of our agreement with Petronorte set forth in our memorandum of understanding with Petronorte dated December 4, 2008.  Under this memorandum of understanding, we are entitled to a fifty percent (50%) participation in the costs and revenues originated from the Putumayo 4 Block E&P contract signed by Petronorte and the ANH, Colombia’s hydrocarbon regulatory agency, including but not limited to any guarantees required by the ANH.   We expect that our capital commitments to Petronorte will be approximately $2.8 million in 2010 for Phase 1 seismic reprocessing, seismic acquisition and permitting.  Our total Phase 1 commitment under the memorandum of understanding over the 36 month Phase 1 period is currently projected to be approximately $8.1 million.  Our total Phase 2 commitment under the memorandum of understanding over the second 36 month project period is currently projected to be approximately $6.0 million, fifty percent of the total $12 million currently budgeted.  Pursuant to the joint operating agreement, in November 2009 we deposited $2.67 million into a trust account as our fifty percent portion of a Phase 1 performance guarantee required by the ANH under Petronorte’s Putumayo 4 Block E&P contract.  We expect that this guarantee deposit will remain in place for the 36 month Phase 1 period and that we may be required to supplement the guarantee deposit in Phase 2 to take into account our additional investment requirements of that phase.  If and when Phase 2 work is completed on the Putumayo 4 Block, we will ask Petronorte to file a request with the ANH to have our agreed to 50% participating interest in the Putumayo 4 Block officially assigned from Petronorte to us.

After reprocessing 1300 km of old seismic, which confirmed the potential of at least 7 leads in the block, both Petronorte and La Cortez have continued working on determining the number and location of indigenous people and communities in the area along with representatives from the Ministry of the Interior. This information is being used to define the layout of the 103 km of 2d seismic acquisition expected to take place by 2nd half of this year, as well as for obtaining the environmental permit for the drilling of the exploratory well. 

Under the terms of the contract signed with the ANH,   the acquisition of 103 km of seismic, the drilling of an exploratory well and additional work for a value of $1.6 million have to be conducted before September 2012, when the 3-year term of Phase I ends.

Avante Colombia/Rio de Oro and Puerto Barco Fields

On March 2, 2010, we acquired Avante’s subsidiary, Avante Colombia, in exchange for shares of our common stock. The purchase included Avante Colombia’s Colombian branch, Avante Colombia Ltd Sucursal.

Avante Colombia currently has a 50% participation interest and is the operator of the Rio de Oro and Puerto Barco exploration and production contracts with Ecopetrol in the Catatumbo area in eastern Colombia.  Under the terms of the letter of intent, we and Avante may also enter into a joint venture to develop other exploration opportunities in Colombia.

The main terms of the transaction were:

l We acquired 100% of the outstanding stock of Avante Colombia in exchange for 10,285,819 restricted shares of our common stock.

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l In addition, Avante invested $5 million in units of our securities at a price of $1.75 per unit, with each unit consisting of one share of our common stock and a three-year warrant to purchase one share of our common stock exercisable at $3.00 per share.

l Avante will have the right to nominate one member to our Board of Directors as long as Avante and/or its affiliates own voting shares representing 10% or more of the votes entitled to be cast in at a meeting of stockholders of La Cortez  to elect directors. Avante has nominated Alexander F. D. Berger, who joined our Board of Directors on March 2, 2010.

After completion of the acquisition of Avante Colombia, La Cortez through Avante Colombia has continued to conduct social activities in the area, and it has defined a potential long term activity program / investment in conjunction with its joint venture partner Vetra Exploración y Producción S.A. 

Initial Closings of Our 2009/2010 Private Placement

On December 29, 2009, we effected the initial closing of a private placement of units of our securities, selling 1,428,571 units at a price of $1.75 per unit, for aggregate gross proceeds to us of $2.5 million.  We conducted a second closing of this offering on January 29, 2010, in which we sold 571,428 units for an aggregate of $999,999, and a third closing on March 2, 2010, in which we sold 857,143 units for an aggregate of $1.5 million.  Each of these units consisted of (i) one share of our common stock and (ii) a common stock purchase warrant to purchase one-half (1/2) of one share of our common stock, exercisable for a period of three years at an exercise price of $3.00 per whole share.

Results of Operations

We are an early stage exploration and development company and have generated very limited operating revenues to date.

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

A summary of year-end results is as follows:

	Year Ended December 31						Percentage Increase /
	2009			2008			(Decrease)
Revenues	$	189,835		$	-			n/a
Costs and expenses		(10,464,966	)		(2,649,312	)		295.0	%
Non-operating income		133,401			68,783			93.9	%
Income tax expense		(656	)		-			n/a
Net Loss	$	(10,142,386	)	$	(2,580,529	)		293.0	%

Revenues

We earned oil and gas revenues of $189,835 for the year ended December 31, 2009, compared to $-0- for the year ended December 31, 2008.  These revenues were derived from the commencement of our production operations in the Mirto-1 well which started during the 4th quarter of 2009.

Costs and Expenses

Our operating costs and expenses for the years ended December 31, 2009 and 2008, consisted of the following:

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	Year Ended December 31,				Percentage Increase /
	2009		2008		(Decrease)
Operating costs	$	421,693	$	-		n/a
Depreciation, depletion, and amortization		364,787		38,719		842.1	%
Impairment of oil properties		6,403,544		-		n/a
Accretion expense		156		-		n/a
General and administrative		3,274,786		2,610,593		25.4	%
Total	$	10,464,966	$	2,649,312		301.9	%

Operating costs

Our operating costs for the year ended December 31, 2009, which pertain to our costs incurred in production activities for the Mirto-1 well, which began producing during the fourth quarter of 2009, amounted to $421,693.  No such costs were incurred during the year ended December 31, 2008.

Depreciation, depletion, and amortization, Impairment and Accretion expenses

The significant increase in the above expenses for the year ended December 31, 2009 as compared to 2008 was mainly due to the impairment expenses and depletion expense on proved oil properties recognized for the year ended December 31, 2009, amounting to $6,403,544 and $364,787, respectively.

Our proved oil reserves of La Cortez have been estimated by an independent petroleum engineer, Ryder Scott Company (“Ryder Scott”), as of December 31, 2009.  We held no proved reserves prior to 2009.  These reserve estimates have been prepared in compliance with SEC rules and accounting standards based on the 12-month un-weighted first-day-of-the-month average price for December 31, 2009.  The new SEC rules and accounting standards effective for fiscal years ending on or after December 31, 2009, require us to prepare our reserve estimates using revised reserve definitions and revised pricing based on 12-month un-weighted first-day-of-the-month average pricing.   Under our full cost method of accounting for our oil properties, costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense.  During 2009, we drilled our first exploratory well, Mirto-1.  We paid 65% of the drilling costs of this well and will receive a 20% working interest in the well.  After the completion of the drilling in October 2009, we are responsible for paying 20% of the operating costs of the well, and we expect to pay 20% of drilling and operating costs of any additional wells drilled in the Mirto prospect.  We agreed to pay the additional 45% of the costs for the drilling of the Mirto-1 well in order to be able to participate in the prospect; however the additional costs paid have resulted in the majority of the impairment recognized in 2009. No such amounts were recorded during the year ended December 31, 2008, as there were no proved oil and gas reserves and no production in 2008. See “Critical Accounting Policies—Oil and Gas Properties” below and Notes 1 and 13 to our consolidated financial statements included in this report for more information regarding the full cost method of accounting for our oil properties and recognition of impairment expenses and depletion expense, and regarding our proved oil reserves.

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General and Administrative Expenses

We incurred total general and administrative expenses of $3,274,786 for the year ended December 31, 2009 compared to $2,610,593 for the year ended December 31, 2008. Our payroll expenses decreased to $1,589,047 for the year ended December 31, 2009 from $505,783 for the year ended December 31, 2008; professional fees increased to $1,114,423 for the year ended December 31, 2009 from $441,683 for the year ended December 31, 2008; travel expenses increased to $191,320 for the year ended December 31, 2009 from $168,812 for the year ended December 31, 2008; rent expense increased to $103,936 for the year ended December 31, 2009 from $56,012 for the year ended December 31, 2008; and other expenses increased to $276,060 for the year ended December 31, 2009 from $230,869 for the year ended December 31, 2008. The increase in expenses for the year ended December 31, 2009 as compared to the year ended December 31, 2008 is attributable primarily to increased general, administrative and legal expenses incurred in connection with our new business activities in South America and related administrative costs.  In particular, excluding the effects of non-cash compensation expenses of $1,000,000 during the year ended December 31, 2008, the increase in our payroll expenses is due to the Company not having employees during the first quarter of 2008 and for the most part of the second quarter of 2008, and the increase in professional fees and other operating expenses during the year ended December 31, 2009 as compared to the year ended December 31, 2008 is primarily due to increased audit, accounting, legal and consultancy expenses arising from our administrative exploration activities and growth in our operations during the current year 2009.  Also, the increase in our rent expense during the year ended December 31, 2009 is due to us entering into a long-term office lease in Bogotá, Colombia, commencing on August 2008 at approximately $7,400 a month.  Prior to entering into this lease, we were only leasing commercial space for approximately $200 per month. 

Non-operating Income (Expense), Net

Net non-operating expense for the year ended December 31, 2009, was $133,401 compared to net non-operating income of $68,783 for the year ended December 31, 2008. Interest income in the amount of $49,404 was earned in the year ended December 31, 2009, on our cash deposits resulting from our private placement offerings.  Also, during the year ended December 31, 2009, we recognized an unrealized gain from the decrease in the fair value of derivative warrant instruments liability of $83,997.

Effective January 1, 2009, the Company adopted FASB ASC Topic No. 815 – 40, Derivatives and Hedging - Contracts in Entity’s Own Stock (formerly Emerging Issues Task Force Issue No. 07-5, Determining Whether an Instrument or Embedded Feature is Indexed to an Entity’s Own Stock). The adoption of FASB ASC Topic No. 815 – 40’s requirements can affect the accounting for warrants and many convertible instruments with provisions that protect holders from a decline in the stock price (or “down-round” provisions). For example, warrants with such provisions will no longer be recorded in equity.  As described below under “Critical Accounting Policies,” we are required to evaluate our equity-linked financial instruments to determine whether they are not indexed to our common stock and therefore should be treated as derivatives.  The common stock warrants that we have issued in our private placement offerings have typical anti-dilution adjustment mechanisms on the exercise price and therefore are not considered to be indexed to our common stock price.  As a result, we recognize our warrants as derivative liabilities on our balance sheet at their respective fair values on each reporting date, and we recognize a gain or loss on the fair value of the warrants on our statement of operations.  These common stock purchase warrants do not trade in an active securities market, and as such, we estimate the fair value of these warrants using a lattice valuation model.

Net Loss

Our net loss for the year ended December 31, 2009 was $10,142,386 compared to $2,580,529 for the year ended December 31, 2008.  The increase is mainly due to the impairment expense on proved oil and natural gas properties and the increase in our general and administrative expenses.

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Adjusted EBITDA

In evaluating our business, we consider earnings before interest, taxes, depreciation, impairment expenses on proved oil properties, depletion, amortization, unrealized gains and loss on investments, stock-based compensation expense, accretion of abandonment liability and the impact of derivative valuations (“Adjusted EBITDA”) as a key indicator of financial operating performance and as a measure of the ability to generate cash for operational activities and future capital expenditures.  We believe Adjusted EBITDA presents a more realistic picture of our performance than income from operations or cash flow from operations as presented in our financial statements and a more meaningful measure of our current liquidity. We believe that this measure may also be useful to investors for the same purpose and as an indication of our ability to generate cash flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for income from operations, or cash flow from operations determined under U.S. generally accepted accounting practices (“GAAP”), or any other measure for determining operating performance that is calculated in accordance with GAAP. In addition, because Adjusted EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.

Adjusted EBITDA is calculated as follows:

	Year ended December 31,
	2009			2008
Net loss	$	(10,142,386	)	$	(2,580,529	)
Adjustments:
Depreciation, depletion and amortization		364,787			38,719
Impairment		6,403,544			-
Accretion		156			-
Unrealized gain on fair value of derivative warrant instruments, net		(83,997	)		-
Interest income		(49,404	)		(69,005	)
Adjusted EBITDA	$	(3,507,300	)	$	(2,610,815	)

Adjusted EBITDA for fiscal 2009 was $3.51 million, compared to $2.61 million for fiscal 2008.  Approximately 97% of the difference between Adjusted EBITDA for 2009 and our $10.14 million net loss for 2009 is composed of the impairment of oil and gas properties discussed elsewhere in this report.  We believe that this impairment was driven by the additional costs incurred by the Company in drilling the first well.  Going forward, the Company will bear 20 percent of the costs and will receive 20 percent of the revenue.  Accordingly, management believes that that the reader should view our financial results for December 31, 2009, in this context.

Liquidity and Capital Resources

Our cash and cash equivalents balance as of December 31, 2009, was $2,376,585 compared to $6,733,381 as of December 31, 2008.  This decrease was due to $7,401,013 in payments for oil and gas properties and the deposit of $2,672,500 into a restricted cash account as a performance guarantee during the year ended December 31, 2009 offset by the receipt of $8,831,164 of capital from the closings of our 2009 unit offerings discussed below.

Subsequent to the end of 2009, we have raised $2.5 million in gross proceeds from the second and third closings of our private unit offering that began in December 2009, and $5 million from an investment by Avante as described above.

We presently do not have any available credit, bank financing or other external sources of liquidity.  Due to our brief history and historical operating losses, our operations have not been a source of liquidity.

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We have entered into a memorandum of understanding and joint operating agreement with Petronorte and a farm-in agreement and joint operating agreement with Emerald.  We expect that our capital commitments to Petronorte will be approximately $2.8 million in 2010 for Phase 1 seismic reprocessing, seismic acquisition and permitting activities.  In November 2009, we deposited $2.67 million into a trust account as our portion of the ANH required performance guarantee under Petronorte’s E&P contract, which funds we will not be able to use for other corporate purposes during the life of the guarantee.

In accordance with the terms of the Emerald farm-in agreement, we paid Emerald $0.948 million on February 12, 2009, as a reimbursement of Emerald’s Phase 1 sunk costs6, $2.433 million on February 18, 2009, as the first installment on Emerald’s Phase 2 exploratory well costs, an additional $2.433 million on May 15, 2009, as the second installment on Emerald’s Phase 2 exploratory well costs (when the drill rig was mobilized to begin drilling on the Maranta Block Mirto-1 exploratory well), and $1.2285 million on July 27, 2009, as our share of Emerald’s Phase 2 Mirto-1 exploratory well completion costs.  On August 4, 2009, we paid an additional $243,300 to Emerald for overhead costs, representing 5% of total expenditures, in accordance with the farm-in agreement.  As of December 31, 2009, we accrued costs amounting to $1,585,795 which were capitalized to oil and natural gas properties representing additional costs equivalent to 65% of Mirto well costs as of that date, in accordance with the farm-in agreement.  On January 7, 2010, we paid an additional $1.41 million to Emerald, consisting of exploration costs associated with the Mirto-1 well, as well as certain 3d seismic and facilities costs.  On February 5, 2010, we paid an additional $234,553 to Emerald for a portion of the final exploration costs of the Mirto-1 well. We expect to require an additional approximately $5.4 million for our share of Phase 3 costs with respect to the Maranta Block in 2010, related to processing of the recently acquired 25km of 3d seismic, conducting a workover on the Mirto-1 well, the drilling of the appraisal wells and the construction of the production facilities at the field. We believe that we have sufficient funds to cover our operational overhead for the next few months, but not to make all of the remaining Emerald and expected Petronorte payments.

While the purchase price for Avante Colombia consisted solely of shares of our common stock, Avante Colombia currently has a 50% participation interest and is the operator of the Rio de Oro and Puerto Barco exploration and production contracts with Ecopetrol in the Catatumbo area in eastern Colombia.  We will incur operating expenses in connection with Avante Colombia’s projects going forward.  Moreover, our agreement with Avante also provides that we and Avante will enter into a joint venture to develop another exploration opportunity in Colombia, which will require further commitment of our capital if it goes forward.

We are currently utilizing cash of approximately $170,000 per month in the day-to-day operations of our business, including payroll, professional fees and office expenses.  We expect this rate of cash utilization to increase over the next twelve months.

During 2010, we expect to require the following amounts of capital in order to bear our share of expenses with respect to the Putumayo 4 Block, the Maranta Block and Avante Colombia’s projects:

● Approximately $2.8 million in the Putumayo 4 Block, related to Phase 1 seismic acquisition and permitting activities;

● Approximately $5.4 million in the Maranta Block, related to Phase 3 processing of the recently acquired 25 km of 3D seismic, conducting a workover on the Mirto-1 well, the drilling of two or three appraisal wells and the construction of the production facilities at the field; and

● Up to $3.4 million on Rio de Oro and Puerto Barco, related to additional seismic in the area and either deepening an existing well or drilling an additional well.

6 All costs on this project are calculated in Colombian pesos and paid in US dollars.  Because of changes in exchange rates, our capital commitments in US dollars may be more or less than originally calculated and budgeted.

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We will need to obtain additional capital in order to meet our working capital needs and our commitments on the Maranta Block, the Putumayo 4 Block, the Rio de Oro and Puerto Barco fields and the Avante joint venture, and to continue to execute our business plan, build our operations and become profitable. In order to obtain capital, we may need to sell additional shares of our Common Stock or debt securities, or borrow funds from private or institutional lenders. Because of the recent problems in the credit markets, steep stock market declines, financial institution failures, government bail-outs, the sharp decline in oil and natural gas prices and our status as an early stage company, there can be no assurance that we will be successful in obtaining additional funding in amounts or on terms acceptable to us, if at all.  If we are unable to raise additional funding as necessary, which the Company is actively seeking, we may have to suspend our operations temporarily or cease operations entirely.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Critical Accounting Policies

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States ("U.S. GAAP").  U.S. GAAP represents a comprehensive set of accounting and disclosure rules and requirements.  The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.  The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis of making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates under different assumptions or conditions, however, in the past the estimates and assumptions have been materially accurate and have not required any significant changes.   Should we experience significant changes in the estimates or assumptions which would cause a material change to the amounts used in the preparation of our financial statements, material quantitative information will be made available to investors as soon as it is reasonably available.

The Company believes the following critical accounting policies, among others, affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

Consolidation.The accompanying financial statements include the accounts of the Company and all of its wholly-owned subsidiaries, including La Cortez Energy Colombia, Inc., a Cayman Islands corporation, and La Cortez Energy Colombia, E.U., a Colombia corporation, an international, early stage oil and gas E&P company concentrating on opportunities in South America.  All significant inter-company transactions and balances are eliminated in consolidation.

Cash and Cash Equivalents.  We consider all highly liquid debt instruments with original maturities of three months or less when acquired to be cash equivalents.

Oil and Gas Properties. We follow the full cost method of accounting for our oil and natural gas properties, whereby all costs incurred in connection with the acquisition, exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on non-producing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the statement of operations.

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Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes.  Costs in excess of the present value of estimated future net revenues as discussed above are charged to proved property impairment expense. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented.  

Impairment of Long-Lived Assets.  We periodically review the carrying amounts of our non-oil and gas property and equipment and its finite-lived intangible assets to determine whether current events or circumstances indicate that such carrying amounts may not be recoverable. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If it is determined that an impairment loss has occurred, the loss is measured as the amount by which the carrying amount of the long-lived asset exceeds its fair value.

Revenue Recognition. Sales of crude oil are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. These market indices are determined on a monthly basis. As a result, our revenues from the sale of oil will suffer if market prices decline and benefit if they increase.

Stock-Based Compensation.  We account for stock-based compensation issued to employees and non-employees by recording stock-based compensation expense ratably over the requisite service period based on the fair value of the awards determined at the grant date (net of estimated forfeitures) utilizing the Black-Scholes-Merton pricing model for options and warrants.  Key assumptions include (1) expected volatility (2) expected term (3) discount rate and (4) expected dividend yield.

Derivative Liabilities.We evaluate our equity-linked financial instruments to determine whether these financial instruments are not indexed to our common stock and therefore should be treated as derivatives.  As a result, beginning on January 1, 2009, we recognized our September 2008 private placement warrants as derivative liabilities at their respective fair values on each reporting date.   We also determined that warrants to purchase shares of common stock issued in the our 2009 unit offerings were not indexed toour own stock and were recognized as derivative warrant instruments and measured at fair value at the date of each offering and at each reporting period.  These common stock purchase warrants do not trade in an active securities market, and as such, we estimate the fair value of these warrants using a lattice valuation model.

Foreign Currency Translation.  We conduct our operations in two primary functional currencies: the U.S. dollar and the Colombian peso. Balance sheet accounts of our Colombian subsidiary are translated from foreign currencies into U.S. dollars at period-end exchange rates while income and expenses are translated at average exchange rates during the period. Cumulative translation gains or losses related to net assets located outside the U.S. are shown as a component of shareholders’ equity. Gains and losses resulting from foreign currency transactions, which are denominated in a currency other than the entity’s functional currency, are included in the consolidated statements of operations.

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New Accounting Pronouncements

In June 2009, the FASBissued SFAS No. 168, “The FASB Accounting Standards Codification TM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“SFAS 168”). The FASB Accounting Standards Codification TM, (“Codification” or “ASC”) became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of SFAS 168, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification became non-authoritative.

Following SFAS 168, the FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead, it will issue Accounting Standards Updates (ASU’s). The FASB will not consider ASU’s as authoritative in their own right; rather these updates will serve only to update the Codification, provide background information about the guidance, and provide the bases for conclusions on the change(s) in the Codification. SFAS No. 168 is incorporated in ASC Topic 105, Generally Accepted Accounting Principles. We adopted SFAS No. 168 in the third quarter of 2009, and we will provide reference to both the Codification topic reference and the previously authoritative references related to Codification topics and subtopics, as appropriate.

Effective January 1, 2009, we adopted FASB ASC Topic No. 815 – 40, Derivatives and Hedging - Contracts in Entity’s Own Stock (formerly Emerging Issues Task Force Issue No. 07-5, Determining Whether an Instrument or Embedded Feature is Indexed to an Entity’s Own Stock). The adoption of FASB ASC Topic No. 815 – 40’s requirements can affect the accounting for warrants and many convertible instruments with provisions that protect holders from a decline in the stock price (or “down-round” provisions). For example, warrants with such provisions will no longer be recorded in equity.  Down-round provisions reduce the exercise price of a warrant or convertible instrument if a company either issues equity shares for a price that is lower than the exercise price of those instruments or issues new warrants or convertible instruments that have a lower exercise price. The Company evaluated whether these warrants contained provisions that protect holders from declines in the Company’s stock price or otherwise couldresult in modification of the exercise price and/or shares to be issued under the respective warrant or preferred stock agreements based on a variable that is not an input to the fairvalue of a “fixed-for-fixed” option as defined under FASB ASC Topic No. 815 – 40.

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The use of average prices affected our fourth quarter 2009 impairment and depletion calculations and will affect future impairment and depletion calculations. In January 2010, the FASB issued ASU 2010-03, Extractive Activities – Oil and Gas (Topic 932) Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”), which aligns the oil and natural gas reserve estimation and disclosure requirements of ASC 932 with the requirements in the SEC’s Final Rule, Modernization of the Oil and Gas Reporting Requirements discussed above. We adopted the Final Rule and ASU effective December 31, 2009.

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In April 2009, the FASB issued FASB Staff Position (“FSP”) SFAS No. 141(R)-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”. FSP FAS 141(R)-1, which is incorporated in FASB ASC Topic No. 805, “Business Combinations” addresses application issues raised by preparers, auditors, and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We have not made any acquisitions during the year ended December 31, 2009 that would require such disclosures.

In April 2009, the FASB issued FASB Staff Position SFAS 157-4, “Determining the Fair Value of a Financial Asset When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP 157-4”). FSP 157-4, which is incorporated in FASB ASC Topic No. 820, “Fair Value Measurements and Disclosures”, clarified and provided additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased. This FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. This FSP shall be effective for interim and annual reporting periods ending after June 15, 2009, and shall be applied prospectively. Early adoption is permitted for periods ending after March 15, 2009. Earlier adoption for periods ending before March 15, 2009, is not permitted. If a reporting entity elects to adopt early either FSP FAS 115-2 and FAS 124-2 or FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, the reporting entity also is required to adopt early this FSP. Additionally, if the reporting entity elects to adopt early this FSP, FSP FAS 115-2 and FAS 124-2 also must be adopted early. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. Revisions resulting from a change in valuation technique or its application shall be accounted for as a change in accounting estimate (FASB ASC Topic No. 250 – 10 - 45, Accounting Changes and Error Corrections). In the period of adoption, a reporting entity shall disclose a change, if any, in valuation technique and related inputs resulting from the application of this FSP, and quantify the total effect of the change in valuation technique and related inputs, if practicable, by major category. The adoption of this topic did not have a material impact on the Company's results of operations or financial position.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”). SFAS 165, which is incorporated in FASB ASC Topic No. 855, “Subsequent Events”, establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this Statement sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. In accordance with SFAS 165, an entity should apply the requirements to interim or annual financial periods ending after June 15, 2009. We adopted SFAS 165 effective June 30, 2009 and the adoption did not have a material impact on our consolidated financial statements.

In June 2009, the FASB issued guidance which amends the consolidation guidance applicable to variable interest entities. This guidance is included in FASB ASC 810, Consolidation. The amendments significantly reduce the previously required quantitative consolidation analysis, and require ongoing reassessments of whether a company is the primary beneficiary of a variable interest entity. This new guidance also requires enhanced disclosures about an enterprise’s involvement with a variable interest entity. This statement is effective for the beginning of the first annual reporting period beginning after November 15, 2009. We do not currently expect the adoption of the new guidance in FASB ASC 810 to impact our consolidated financial statements.

In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurements, which enhances the usefulness of fair value measurements. The amended guidance requires both the disaggregation of information in certain existing disclosures, as well as the inclusion of more robust disclosures about valuation techniques and inputs to recurring and nonrecurring fair value measurements.  The amended guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disaggregation requirement for the reconciliation disclosure of Level 3 measurements, which is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. We adopted ASU 2010-06 effective December 31, 2009, and the adoption did not have a significant impact on our consolidated financial statements.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

Our audited consolidated financial statements as of, and for the years ended, December 31, 2009 and 2008, are included beginning on Page F-1 immediately following the signature page to this report.  See Item 15 for a list of the financial statements included herein.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.[T] CONTROLS AND PROCEDURES

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2009. Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered in this report, our disclosure controls and procedures were not effective to ensure that information required to be disclosed in reports filed by us under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the required time periods and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.  In particular, we concluded that internal control weaknesses in our accounting policies and procedures relating to our equity transactions and segregation of duties were material weaknesses.

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

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Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control—Integrated Framework and the Internal Control over Financial Reporting – Guidance for Smaller Public Companies both issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. We have identified the following material weaknesses.

1. As of December 31, 2009, we did not adequately segregate, or mitigate the risks associated with, incompatible functions among personnel to reduce the risk that a potential material misstatement of the financial statements would occur without being prevented or detected. Accordingly, management concluded that this control deficiency constituted a material weakness. We have recently come out of the exploration stage.  We have focused on hiring individuals to assist in identifying and acquiring oil and gas properties.  We have hired qualified individuals to carry out our day-to-day accounting and financial reporting obligations; however, we have not reached the point at which we have an adequate number of staff to provide the required segregation of duties.  We will continue to seek qualified individuals to add to our staff; however, we may not be fully staffed until we have sufficient cash flow from operations to support the related salary requirements.  The third party consultants have mitigated some segregation of duties issues as they perform reviews of certain financial accounting and reporting areas.

2. During the audit of our financial statements for the year ended December 31, 2009, some errors were detected in the valuation of warrants derivative liabilities associated with the 2009 private placements and subsequent revaluation of such warrants.   The errors in valuing these derivative liabilities totaled approximately $2.2 million.  These errors were identified by our independent registered public accounting firm during the performance of audit procedures.  The errors were related to the improper valuation model used for the initial valuation of the warrants issued in those private placements with stock and subsequent revaluations and the improper application of the appropriate valuation model, which included incorrect assumptions used and computations made within the model.  The errors were identified and corrected prior to the release of the financial statements.  We have implemented procedures to correct these errors, including taking action in providing technical training on valuation models and processes and more detailed management review of the valuations prior to the release of the financial statements, in order to remediate this weakness.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

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

During the fourth quarter of 2009, we continued to increase our workforce as increased operational activity is experienced. We were also able to remediate our material weakness related to financial statement disclosures and also intend to hire an experienced Chief Financial Officer with an oil and gas industry background.  We believe that these combined actions will remedy the material weaknesses in our current system of internal control over financial reporting.

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Officers’ Certifications

Appearing as exhibits to this Annual Report are “Certifications” of our Chief Executive Officer and Chief Financial Officer.  The Certifications are required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (the “Section 302 Certifications”).  This section of the Annual Report contains information concerning the Controls Evaluation referred to in the Section 302 Certification.  This information should be read in conjunction with the Section 302 Certifications for a more complete understanding of the topics presented.

Changes in Internal Control over Financial Reporting

We have engaged third party consultants and have increased and formalize internal review procedures in an effort to ensure that our consolidated financial statements accurately reflect our financial condition and results of operations.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Executive Officers and Directors

Below are the names and certain information regarding the Company’s current executive officers and directors:

Name	Age	Title	Date First Appointed
Nadine C. Smith	52	Director and Chairman of the Board, Vice President and Interim Chief Financial Officer	February 7, 2008
Andrés Gutierrez Rivera	51	President, Chief Executive Officer and Director	June 1, 2008
Alexander F. D. Berger	44	Director	March 2, 2010
José Fernando Montoya Carrillo	56	Director	October 15, 2008
Jaime Navas Gaona	71	Director	July 23, 2008
Jaime Ruiz Llano	55	Director	July 1, 2008
Richard G. Stevens	63	Director	July 23, 2008

Directors are elected to serve until the next annual meeting of stockholders and until their successors are elected and qualified.  Officers are elected by the Board of Directors and serve until their successors are appointed by the Board of Directors.

Biographical resumes of each officer and director of the Company are set forth below.

Nadine C. Smith became a director and our Chairman of the Board of Directors on February 7, 2008. On February 19, 2008, Ms. Smith was appointed our Vice President and on June 1, 2008 she assumed the positions of Interim Chief Financial Officer and Interim Treasurer.  Ms. Smith serves as a director of WaferGen Bio-systems, Inc., a publicly held company engaged in the development, manufacture and sales of systems for gene expression, genotyping and stem cell research, headquartered in Fremont, California.  She also serves as Chairman of the Board of Loreto Resources Corporation, a publicly held, early stage independent company that plans to be involved in the mining sector in South America.  Ms. Smith has previously served as a director of Gran Tierra Energy, Inc., an oil and gas exploration and production company operating in South America, Patterson-UTI Energy Inc. and American Retirement Corporation, all public companies. Ms. Smith has been a private investor and business consultant since 1990.

Andrés Gutierrez Rivera was appointed our President and Chief Executive Officer on June 1, 2008.  Mr. Gutierrez was most recently (from January 2007 to June 2008) the senior executive of Lewis Energy Colombia Inc.  In this role he was responsible for all aspects of Lewis Energy’s operational management and its business development initiatives in Colombia.  Prior to joining Lewis Energy, Mr. Gutierrez was briefly a consultant with Upside Energy & Mining Services, in charge of the execution of various consulting projects related to the oil and gas divisions of several multinational companies.

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From 2001 to 2006, Mr. Gutierrez was employed with Hocol, S.A., an oil and gas E&P company based in Bogotá, Colombia with operations in Colombia and Venezuela.  From 2004, Mr. Gutierrez served as one of three Vice Presidents reporting directly to the President of Hocol, S.A..  As Vice President Finance Administration, Human Talent and Operations, Mr. Gutierrez participated in defining Hocol’s long term strategy and company direction.  In 2005, Mr. Gutierrez participated in the development and execution of the divestiture of Hocol to Maurel & Prom for approximately $460 million.

Mr. Gutierrez obtained a bachelor degree in Civil Engineering from the Escuela Colombia de Ingenieria in 1982 in Bogotá, Colombia and a MSCE from Georgia Institute of Technology in March 1985 in Atlanta, Georgia.

Alexander F. D. Berger has been CEO of Oranje-Nassau Energie BV, a private Dutch exploration and production company, since 2009.  Mr. Berger worked for Shell International from 1993 to 2000, holding several technical and commercial positions in the United Kingdom and the Netherlands.  From 2000 to 2009, he worked for SHV Holdings NV as the Commercial Manager of its E&P subsidiary Dyas, an active North Sea investor in non-operated oil and gas assets, and in 2007 was appointed Managing Director of Dyas. While working for Dyas, Mr. Berger was instrumental in doubling the oil and gas portfolio through numerous successful North Sea and overseas acquisitions, plus he held several non-executive directorships on behalf of the company: Capricorn Energy, Delta Hydrocarbons and Ithaca Energy.

Mr. Berger holds an MSc degree in Petroleum Engineering from Delft University and an MBA degree from the Rotterdam School of Management.

José Fernando Montoya Carrillo began his career in the oil and gas industry 27 years ago at Shell and held various management positions over 19 years with the company and its Latin American subsidiaries. During this time, Mr. Montoya’s positions included Corporate Planning and Business Development Manager, Operations Manager, Oil Marketing Director and General Manager of Shell Downstream Paraguay.

In 1997, Mr. Montoya joined Hocol S.A. (a Colombian company previously owned by Shell) where he held various executive management positions, including Business Development Manager, Chief Financial Officer, Chief Operating Officer, President and Chief Executive Officer until September 2007. Mr. Montoya continued to be a board member and consultant to the management of Hocol S.A., a subsidiary of the French group Maurel & Prom (M&P) until September 2008. Mr. Montoya is currently a partner-owner of the energy consultant firm Upside - Energy and Marketing Services and a founding partner of The Leadership and Management Center. Both of these companies are located in Bogotá, Columbia.

Mr. Montoya holds a Bachelors Degree in Chemistry Engineering from the National University of Colombia.

Jaime Navas Gaona began his career as a geologist with Exxon in Colombia, where he was employed for 27 years, serving in a number of capacities including Exploration Manager.  Mr. Navas retired from Exxon as Production Geology Manager in 1992.  From 1993 to 1996, Mr. Navas worked as Senior Exploration Advisor with Maxus Energy in Bolivia.

From 1998 to 2002, Mr. Navas was a member of the Strategic Team and Mentor of the Exploration and New Ventures teams for Hocol, S.A.  Mr. Navas was one of five members of Hocol’s Management Team, accountable for the overall business results of the company. His responsibilities at Hocol included the development and implementation of strategies for the achievement of Hocol’s exploration goals and objectives, collaboration in managing government relations and securing approvals for the company’s exploration activities.

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In 2002, Mr. Navas co-founded AGN-Exploration, an exploration consulting firm based in Bogotá, Colombia, where he currently acts as the company’s President.  In 2005, Mr. Navas was appointed as one of the five members of the Investment Committee of LAEFM (Latin America Enterprise Fund Manager), the first hydrocarbon investment fund established in Colombia.

Mr. Navas holds a Masters in Science of Petroleum Geology from the Colorado School of Mines and a degree in Geology and Geophysics from Universidad Nacional, Bogotá, Colombia.

Jaime Ruiz Llano became our director on July 1, 2008.  Mr. Ruiz has been involved in government affairs in Colombia for the past 20 years.  Mr. Ruiz has held various high level government positions throughout his career.  In 1991, Mr. Ruiz was elected as a Senator in the Colombian Congress. He served in that capacity until 1994.  From 1998 to 1999, Mr. Ruiz held the position of Director for the Colombian National Planning Department, the government entity controlling the national budgeting and government planning strategies; in 1999 he served as Special Presidential Advisor for Government Affairs to the President of Colombia.

From 2000 to 2002, Mr. Ruiz served as Executive Director - Member of the Board of Directors of the World Bank.  The Executive Directors oversee the World Bank’s business, including approval of loans and guarantees, new policies, the administrative budget, country assistance strategies and borrowing and financial decisions.

In 2006, Mr. Ruiz served as Deputy Chief of Mission in the Colombian embassy in Washington, D.C. During the periods when he was not serving in the Colombian government, Mr. Ruiz held the position of President of his family-owned construction business.  Additionally, Mr. Ruiz has served on the Board of Directors of Ecopetrol, Colombia’s state-run oil company.

Mr. Ruiz received a Masters in Civil Engineering from the University of Kansas and a Masters in Development Studies from the Institute of Social Studies, The Hague, The Netherlands.

Richard G. Stevens is the founder and managing director of Hunter Stevens, a professional services firm that Mr. Stevens organized in 1995.  Prior to forming Hunter Stevens, Mr. Stevens served as a partner with Ernst & Young LLP and Coopers & Lybrand LLP (now known as PricewaterhouseCoopers, LLP), both of which are public accounting firms.

Since 2006, Mr. Stevens has been a director of Chordiant Software, Inc. and currently is their lead independent director.  Mr. Stevens previously served as Chairman of the Audit Committee of Verity, Inc., a software firm based in Sunnyvale, CA and at Pain Therapeutics, Inc., a bioscience company in South San Francisco.

Mr. Stevens holds a Bachelor of Science Degree with honors from the University of San Francisco, and is a licensed Certified Public Accountant in the States of California and New York, and a Certified Fraud Examiner.

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Non-Executive Senior Management

The following sets forth information regarding certain of our senior managers:

Exploration Manager - Mr. Carlos Lombo:  Carlos Lombo has more than 23 years of oil and gas industry experience. Mr. Lombo was most recently an external geological consultant (from 2003 to 2008) with numerous oil and gas companies and government entities including: Occidental Petroleum Colombia (OXY), Nexen Petroleum, Ecopetrol, ANH, and Solana Resources Ltd amongst many others. As a consultant, Mr. Lombo was responsible for all aspects of seismic interpretation, prospect and geological evaluations, assessment of exploration opportunities and other tasks. Prior to this period, Mr. Lombo was an Exploration Geologist Project Manager with Ecopetrol, the Colombia, state-owned oil and gas company, from 1986 to 2003. Mr. Lombo served over 17 years in this capacity, working extensively throughout every basin of the Colombian topography across numerous exploration projects. Mr. Lombo earned a Bachelor of Arts degree in Mathematics from the District University in Bogotá and a Masters degree in Geology from the National University of Colombia.

Production and Operations Manager – William Giron:  Mr. Girón brings over 26 years of oil and gas experience to La Cortez. Most recently, from 2007 to date, Mr. Girón was the Production Manager for Hocol’s Magdalena Valley assets where he was responsible for production in excess of 18,000 BOED (Barrels of Oil Equivalent per day), a capital expenditure budget exceeding $130 million, and relationships with Ecopetrol, the Colombian state-controlled oil company, the Colombian Ministry of Mines, local government officials and third party private partners. Mr. Girón also performed in other capacities at Hocol as field asset manager for the heavy crude oil of La Hocha field, as a reservoir engineer and a field development manager.

Prior to joining Hocol, Mr. Girón was employed by Texas Petroleum Company (Texaco) from 1982 to 1995. He was an independent consultant from 1996 to 1997. At Texaco, Mr. Girón held various posts as a production and reservoir engineer and as an assistant superintendent. He was involved in activities including budgeting and planning, reservoir management, production enhancement and pipeline operations management. Mr. Girón has a B.S. in Petroleum Engineering from the Universidad de America in Bogotá.

Business and Technical Advisors

We expect to recruit a number of experienced and highly regarded professionals to provide advice to us in their areas of specialization or expertise. These advisors will enter into agreements with us to serve for fixed terms ranging from one to three years. We will generally grant these advisors options to purchase our Common Stock as partial payment for their services. In addition, these advisors will receive cash compensation in connection with services rendered and will be reimbursed for their reasonable out-of-pocket expenses.

Director Independence

We are not currently subject to listing requirements of any national securities exchange or inter-dealer quotation system which has requirements that a majority of the board of directors be “independent” and, as a result, we are not at this time required to have our Board of Directors comprised of a majority of “Independent Directors.”  Nevertheless, our Board of Directors has determined that four of our six directors, Messrs. Ruiz Llano, Navas Gaona, Stevens and Montoya Carrillo, including all of our audit committee members (see below), are “independent” within the definition of independence provided in the Marketplace Rules of The Nasdaq Stock Market.

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Board Meetings and Attendance

Our Board held eight meetings (including regularly scheduled and special meetings) during the year ended December 31, 2009.  There was a quorum present for each of our Board meetings held during the fiscal year ended December 31, 2009.

Board Committees

Our Board currently maintains a standing audit committee and an evaluation and reserves committee.

Audit Committee

Our Board of Directors, by unanimous consent, established an audit committee (the “Audit Committee”) in October 2008.  The initial members of this committee are Messrs. Montoya, Ruiz and Stevens.  Our Board of Directors has determined that Mr. Stevens is an “audit committee financial expert”, as defined in Item 407 of Regulation S-K, and is the Chairman of the Audit Committee.  Although the Audit Committee has not yet adopted a formal charter, the Board resolution establishing the Audit Committee authorized the Audit Committee to operate with the customary responsibilities and authority typically granted to a public company audit committee.  During the fiscal year ended December 31, 2009, the Audit Committee held five meetings. There was a quorum present for each of our Audit Committee meetings held during the fiscal year ended December 31, 2009.

Evaluation and Reserves Committee

In October 2008, our Board of Directors, by unanimous consent, also established an evaluation and reserves committee.  The initial members of this committee are Messrs. Gutierrez, Montoya and Navas.  This committee was established to, among other things, fulfill the Board’s oversight responsibilities with respect to evaluating and reporting on our oil and gas reserves and reviewing and approving non-binding proposals, indications of interest, bids, memoranda of understanding and the like with respect to potential business prospects of and investments and acquisitions by us.  The evaluation and reserves committee currently does not operate under a charter although its authority and powers have been enumerated by the Board.

Other Committees

The Company currently has not established an executive committee, a compensation committee or a nominating committee.  We are not a “listed company” under SEC rules and are therefore not required to have a compensation committee or a nominating committee.

Compensation Committee

Our Board of Directors believes that it is not necessary to have a standing compensation committee at this time.  Because of the early stage of our development and our limited operations, the functions of such committee are adequately performed by the Board of Directors.  Currently, the non-management members of our Board of Directors administer and approve all elements of compensation and awards for our executive officers. These independent members of our Board have the responsibility to review and approve the business goals and objectives relevant to each executive officer’s compensation, evaluate individual performance of each executive in light of those goals and objectives, and determine and approve each executive’s compensation based on this evaluation.

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Shareholder Communications

Currently, we do not have a policy with regard to the consideration of any director candidates recommended by security holders.  To date, no security holders have made any such recommendations.

Code of Ethics

We have adopted a written code of ethics (the “Code of Ethics”) that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions. We believe that the Code of Ethics is reasonably designed to deter wrongdoing and promote honest and ethical conduct; provide full, fair, accurate, timely and understandable disclosure in public reports; comply with applicable laws; ensure prompt internal reporting of code violations; and provide accountability for adherence to the code.  To request a copy of the Code of Ethics, please make written request to our President, c/o La Cortez Energy, Inc. at Calle 67 #7-35, Oficina 409, Bogotá, Colombia.

Compliance with Section 16(a) of the Exchange Act

Prior to January 15, 2010, our common stock was not registered pursuant to Section 12 of the Exchange Act.  Accordingly, our officers, directors and principal shareholders were not subject to the beneficial ownership reporting requirements of Section 16(a) of the Exchange Act during the year ended December 31, 2009, or prior years.

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ITEM 11.       EXECUTIVE COMPENSATION

The following table sets forth information concerning the total compensation paid or accrued by us during the last two fiscal years ended December 31, 2009 to (i) all individuals that served as our principal executive officer or acted in a similar capacity for us at any time during the fiscal year ended December 31, 2009; (ii) all individuals that served as our principal financial officer or acted in a similar capacity for us at any time during the fiscal year ended December 31, 2009; and (iii) all individuals that served as executive officers of ours at any time during the fiscal year ended December 31, 2009 that received annual compensation during the fiscal year ended December 31, 2009 in excess of $100,000.

Summary Compensation Table

Name and Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards (1) ($)		Non-Equity Incentive Plan Compen- sation ($)		Change in Pension Value and Non- qualified Deferred Compen-sation Earnings ($)		All Other Compen- sation ($)		Total ($)
Andrés Gutierrez Rivera,	2009		250,000		125,000		0		0		0		0		0		375,000
Chief Executive Officer (2)	2008		145,833		72,915		0		870,738		0		0		0		1,089,486
Nadine C. Smith, Vice	2009		0		0		0		0		0		0		0		0
President and Interim	2008		0		0		0		152,379		0		0		0		152,379
Chief Financial Officer (3)

(1) Option Awards expense as reported here and in our financial statements has been recorded in accordance with the FASB ASC Topic 718.

(2) Effective June 1, 2008, Mr. Gutierrez was appointed our President and Chief Executive Officer.  No cash bonuses have yet been paid to Mr. Gutierrez for 2008 or 2009, however, we have accrued bonus payables for each such year in the indicated amounts.

(3) Ms. Smith was appointed Interim Chief Financial Officer on June 1, 2008.  Ms. Smith receives no compensation in her capacities as Vice President and Interim Chief Financial Officer.  However, for accounting purposes, we imputed compensation of $0 and $23,333 for her contributed services for the years ended December 31, 2009 and 2008.  The Option Awards value reflects option grants made to Ms. Smith in her capacity as director and Chairman.

We have not issued any stock options or maintained any stock option or other incentive plans other than our 2008 Equity Incentive Plan. (See “Stock Option Plans” below.) We have no plans in place and have never maintained any plans that provide for the payment of retirement benefits or benefits that will be paid primarily following retirement including, but not limited to, tax qualified deferred benefit plans, supplemental executive retirement plans, tax-qualified deferred contribution plans and nonqualified deferred contribution plans.

We are paying Mr. Gutierrez Rivera for his services to us as President and Chief Executive Officer according to his employment agreement with us.  We have no other contracts, agreements, plans or arrangements, whether written or unwritten, that provide for payments to the named executive officers listed above, other that our Board approved director compensation plan which includes the reimbursement to all directors of reasonable out-of-pocket expenses incurred in attending Board of Directors and committee meetings.

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Outstanding Equity Awards at Fiscal Year-End

The following table sets forth information regarding stock options held by the Company’s Named Executive Officers at December 31, 2009.

Option Awards
Name and Principal Position	Number of securities underlying unexercised options exercisable (#)		Number of securities underlying unexercised options unexercisable (#)		Equity incentive plan awards: Number of securities underlying unexercised unearned options (#)		Option plan exercise price ($)		Option expiration date
Andrés Gutierrez Rivera, Chief Executive Officer		333,334		-		666,666	$	2.20		July 1, 2018
Nadine Smith, Vice President and Interim Chief Financial Officer (1)		58,334		-		116,666	$	2.20	July 1, 2018

(1) Ms. Smith receives no compensation in her capacities as Vice President and Interim Chief Financial Officer.  The Option Awards value reflects option grants made to Ms. Smith in her capacity as director and Chairman.

Employment Agreements with Executive Officers

The Company has entered into an employment agreement effective as of June 1, 2008 (the “Employment Agreement”) with Andrés Gutierrez pursuant to which Mr. Gutierrez was appointed as our President and Chief Executive Officer, with the following terms:

Pursuant to the Employment Agreement, Mr. Gutierrez’s base annual compensation has been set at $250,000, which amount shall be paid in accordance with our customary payroll practices and may be increased annually at the discretion of the Board. This annual compensation shall be paid in equal monthly installments in Colombian Pesos (“COP”).  The exchange rate used to calculate Mr. Gutierrez’s monthly salary payment will be calculated each month and shall neither exceed a maximum of COP 2,400 nor be less than a minimum of COP 1,600. This minimum/maximum range will be adjusted at the end of each calendar year based upon changes in the consumer price index in Colombia.

In addition, Mr. Gutierrez is eligible to receive an annual cash bonus of up to fifty percent (50%) of his applicable base salary. Mr. Gutierrez’s annual bonus (if any) shall be in such amount (up to the limit stated above) as the Board may determine in its sole discretion, based upon Mr. Gutierrez’s achievement of certain performance milestones to be established annually by the Board in discussion with Mr. Gutierrez (the “Milestones”). For the first year of employment, in the event the Board and Mr. Gutierrez are unable to agree to Milestones acceptable to both, the amount of Mr. Gutierrez’s bonus shall be determined by the Board on a discretionary basis.  No Milestones have yet been established for the year ending December 31, 2009.  As of December 31, 2009, we had accrued a bonus payable to Mr. Gutierrez in the amount of $197,915.  Of such amount, $72,915 and $125,000 relate to Mr. Gutierrez’s performance during fiscal 2008 and 2009, respectively.

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On July 1, 2008, and in accordance with his employment agreement, we granted Mr. Gutierrez an option to purchase an aggregate of 1,000,000 shares of our Common Stock under our 2008 Equity Incentive Plan. This option vests in three equal annual installments beginning on June 1, 2009 and is exercisable at a price equal to the fair market value our Common Stock on the date of grant, as determined by the Board.

The initial term of the Employment Agreement expired on June 1, 2009; however, the Employment Agreement automatically renews for additional one (1) year terms thereafter, unless either party provides notice to the other party of its intent not to renew such Employment Agreement not less than thirty (30) days prior to the expiration of the then-current term or unless the Employment Agreement is terminated earlier in accordance with its terms. No such notice was provided prior to the end of the initial one year term.

In the event of a termination of employment “without cause” by the Company during the first 12 months following June 1, 2008, Mr. Gutierrez shall receive: (i) twelve (12) months of his base salary; plus (ii) to the extent the Milestones are achieved or, in the absence of Milestones, the Board has, in its sole discretion, otherwise determined an amount for Mr. Gutierrez’s bonus for the initial 12 months of his employment, a pro rata portion of his annual bonus for the initial 12 months of his employment, to be paid to him on the date such annual bonus would have been payable to him had he remained employed by the Company; plus (iii) any other accrued compensation and Benefits, as defined in the Employment Agreement. In the event of a termination of employment by Mr. Gutierrez for “good reason”, as defined in the Employment Agreement, Mr. Gutierrez shall receive: (i) twelve (12) months of his then in effect base salary, subject to his compliance with the non-competition, non-solicitation and confidentiality provisions of the Employment Agreement. All of the foregoing shall be payable in accordance with the Company’s customary payroll practices then in effect.

Further, in the event of the termination of Mr. Gutierrez’s employment in connection with a Change of Control, as defined in the Employment Agreement, without cause by the Company within 12 months of the Effective Date, or by Mr. Gutierrez for good reason, any options then held by Mr. Gutierrez that have not already vested in accordance with their terms shall immediately vest and become exercisable as of the date of such termination and Mr. Gutierrez shall have nine (9) months from the date of termination to exercise any or all such options.

The Employment Agreement also provides that Mr. Gutierrez shall not: (i) during his employment and for a period of one (1) year following the termination of his employment, unless such employment is terminated by us for cause or by him for no reason, directly or indirectly engage or invest in, own, manage, operate, finance, control or participate in the ownership, management, operation, financing, or control of, be employed by, associated with, or in any manner connected with, lend any credit to, or render services or advice to, any business, firm, corporation, partnership, association, joint venture or other entity that engages or conducts any business the same as or substantially similar to the business of the Company or to the business currently proposed to be engaged in or conducted by the Company and/or any of its affiliates, including its Colombia subsidiary, in South America or included in the future strategic plan of the business of the Company, anywhere within the United States of America or South America; provided, however, that Mr. Gutierrez may own less than 5% of the outstanding shares of any class of securities of any enterprise (but without otherwise participating in the activities of such enterprise) including those engaged in the oil and gas business, other than any such enterprise with which the Company competes or is currently engaged in a joint venture, if such securities are listed on any national or regional securities exchange or have been registered under Section 12(g) of the Exchange Act; (ii) during his employment and for a period of one (1) year following the termination of his employment, solicit any of our current and/or future employees to leave our employ, or solicit or attempt to take away any customers of the Company or any of its affiliates; or (iii) during his employment and thereafter, disclose, directly or indirectly, any confidential information of the Company to any third party, except as may be required by applicable law or court order, in which case the executive must promptly notify the Company so as to allow it to seek a protective order if the Company so elects.

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The employment agreement with Mr. Gutierrez including its terms of compensation were negotiated in an arm’s length transaction between Mr. Gutierrez and us and was approved by Ms. Smith our Chairman and sole director at the time of Mr. Gutierrez’s hiring.

Compensation of Non-Employee Directors

Our Board of Directors currently consists of four non-employee directors and two executive officers.  We do not provide cash or incentive compensation for the services of executive officers as directors.  Our Board of Directors, on July 23, 2008, approved a compensation package for our non-employee directors7. This compensation package provides for the grant of stock options to purchase 100,000 shares of our Common Stock to each new non-employee director upon his or her appointment or election to the Board of Directors. These options will have an exercise price equal to or greater than the fair market value of the Common Stock on the date of grant of an option award and will fully vest in equal, one-third installments over three years. In addition, each non-employee director will receive annual cash compensation of $12,000.  The chairman of the Audit Committee will also receive additional annual compensation of $15,000 and the chairmen of the Compensation, Reserves and Nominating and Corporate Governance Committees of our Board of Directors will also each receive additional annual cash compensation of $5,000. Each non-employee director will receive $1,000 for attendance at each committee meeting of the Board of Directors, or $500 for telephonic attendance. Directors are also reimbursed for reasonable out-of-pocket expenses incurred in attending Board of Directors and committee meetings.

Until we establish a compensation committee, amendments to our director compensation package must be approved by a majority of our independent directors.

7 On July 23, 2008, our Board of Directors approving our non-director compensation plan consisted of Nadine Smith, Andrés Gutierrez, Jaime Ruiz and Richard Stevens.

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The following table sets forth information regarding compensation accrued to the Company’s non-employee directors for the year ended December 31, 2009.

Director Compensation

Name	Fees earned or paid in cash ($)		Stock awards ($)		Option awards (1) ($)		Non- equity incentive plan compen- sation ($)		Nonqualified deferred compensation earnings ($)		All other compen- sation ($)		Total ($)
José Fernando Montoya Carrillo	$	14,500	$	-	$	88,605	$	-	$	-	$	-	$	103,105
Jaime Navas Gaona	$	17,000	$	-	$	90,419	$	-	$	-	$	-	$	107,419
Jaime Ruiz Llano	$	15,000	$	-	$	87,074	$	-	$	-	$	-	$	102,074
Richard G. Stevens	$	30,000	$	-	$	90,419	$	-	$	-	$	-	$	120,419

(1) Option awards expense as reported here and in our financial statements has been recorded in accordance with FASB ASC Topic 718.

Stock Option Plans

The Board of Directors and stockholders of the Company adopted the 2008 Equity Incentive Plan on February 7, 2008 and the Board of Directors approved an amendment and restatement of the 2008 Equity Incentive Plan on November 7, 2008.  The 2008 Equity Incentive Plan, as amended and restated, reserves a total of 4,000,000 shares of our common stock for issuance under the Plan.  Our stockholders approved the increase in reserved shares from 2,000,000 to 4,000,000 as of October 12, 2009.  If an incentive award granted under the 2008 Equity Incentive Plan expires, terminates, is unexercised or is forfeited, or if any shares are surrendered to us in connection with an incentive award, the shares subject to such award and the surrendered shares will become available for further awards under the 2008 Equity Incentive Plan.

Shares which may be issued under the 2008 Equity Incentive Plan through the settlement, assumption or substitution of outstanding awards or obligations to grant future awards as a condition of acquiring another entity are not expected to reduce the maximum number of shares available under the Plan.  In addition, the number of shares of our common stock subject to the 2008 Equity Incentive Plan, any number of shares subject to any numerical limit in the Plan, and the number of shares and terms of any incentive award are expected to be adjusted in the event of any change in our outstanding common stock by reason of any stock dividend, spin-off, split-up, stock split, reverse stock split, recapitalization, reclassification, merger, consolidation, liquidation, business combination or exchange of shares or similar transaction.

Administration

It is expected that the Compensation Committee of the Board of Directors, or the Board of Directors in the absence of such a committee, will administer the 2008 Equity Incentive Plan.  Subject to the terms of the 2008 Plan, the Compensation Committee would have complete authority and discretion to determine the terms of awards under the 2008 Equity Incentive Plan.

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Grants

The 2008 Equity Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, restricted stock awards, performance grants and stock appreciation rights, as described below:

Options granted under the 2008 Equity Incentive Plan entitle the grantee, upon exercise, to purchase a specified number of shares from us at a specified exercise price per share.  The exercise price for shares of common stock covered by an option cannot be less than the fair market value of the common stock on the date of grant unless agreed to otherwise at the time of the grant.  The compensation committee, or the Board of Directors in the absence of such a committee, may also grant options with a reload feature.

Restricted stock awards may be awarded on terms and conditions established by the Compensation Committee, which may include the lapse of restrictions on the achievement of one or more performance goals.

Stock appreciation rights (“SARs”) entitle the participant, upon exercise of the SAR, to receive a distribution in an amount equal to the number of shares of common stock subject to the portion of the SAR exercised multiplied by the difference between the market price of a share of common stock on the date of exercise of the SAR and the market price of a share of common stock on the date of grant of the SAR.

Duration, Amendment and Termination

The Board of Directors is expected to have the power to amend, suspend or terminate the 2008 Equity Incentive Plan without stockholder approval or ratification at any time or from time to time.  No change may be made that increases the total number of shares of common stock reserved for issuance pursuant to incentive awards or reduces the minimum exercise price for options or exchange of options for other incentive awards, unless such change is authorized by our stockholders within one year.  Unless sooner terminated, the 2008 Equity Incentive Plan would terminate ten years after it is adopted.

Grants to Officers and Directors

On July 1, 2008, the Board approved non-incentive stock option grants under the 2008 Equity Incentive Plan to the officers and directors of the Company and in the amounts listed in the table below.  These options can be exercised at a price of $2.20 per share, the fair market value of the Company’s common stock on the date of grant, as determined by the Board, vest over three years from the date of grant and expire after ten years.

Name of Optionee	Number of Shares
Andrés Gutierrez		1,000,000
Jaime Ruiz		100,000
Nadine C. Smith		175,000

On July 23, 2008, the Board approved non-incentive stock option grants under the 2008 Equity Incentive Plan to the officers and directors of the Company and in the amounts listed in the table below.  These options can be exercised at a price of $2.47 per share, vest over three years from the date of grant and expire after ten years.

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Name of Optionee	Number of Shares
Jaime Navas Gaona		100,000
Richard G. Stevens		100,000

On November 7, 2008, the Board approved non-incentive stock option grants under the 2008 Equity Incentive Plan to purchase 100,000 shares of its common stock to José Fernando Montoya, its newly appointed director. These options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term. These options can be exercised at a price of $1.71 per share, vest over three years from the date of grant and expire after ten years.

On March 2, 2010, the Board approved non-incentive stock option grants under the 2008 Equity Incentive Plan to purchase 100,000 shares of its common stock to Alexander F.D. Berger, its newly appointed director. These options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term. These options can be exercised at a price of $2.11 per share, vest over three years from the date of grant and expire after ten years.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth information with respect to the beneficial ownership of our common stock known by us as of April 12, 2010 by:

· each person or entity known by us to be the beneficial owner of more than 5% of our common stock;

· each of our directors;

· each of our executive officers; and

· all of our directors and executive officers as a group.

Except as otherwise indicated, the persons listed below have sole voting and investment power with respect to all shares of our common stock owned by them, except to the extent such power may be shared with a spouse.

Unless otherwise indicated in the following table, the address for each person named in the table is c/o La Cortez Energy, Inc., Calle 67 #7-35, Oficina 409, Bogotá, Colombia.

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Name and Address of Beneficial Owner	Title of Class	Amount and Nature of Beneficial  Ownership(1)			Percent of Class (2)
Nadine C. Smith 1266 1st Street, Suite 4 Sarasota, FL 34236	Common Stock		3,165,334	(3)		7.8	%
Andrés Gutierrez Rivera	Common Stock		408,334	(4)		1.0	%
Alexander F. D. Berger	Common Stock		0	(5)		*
José Fernando Montoya Carrillo	Common Stock		333,334	(6)		*
Jaime Navas Gaona	Common Stock		33,334	(7)		*
Jaime Ruiz Llano	Common Stock		33,334	(8)		*
Richard G. Stevens	Common Stock		33,334	(7)		*
All directors and executive officers as a group (7 persons)	Common Stock		4,007,004			9.8	%
Avante Petroleum S.A. 11b Boulevard Joseph II L-1840 Luxembourg Luxembourg	Common Stock		16,000,105	(5)(9)		37.3	%
Professional Trading Services SA Gerbergasse 5 CH 8001 Zurich, Switzerland	Common Stock		2,600,000	(10)		6.5	%
Asset Protection Fund Ltd.	Common Stock		2,250,000	(11)		5.6	%
3076 Sir Francis Drake’s Highway
Road Town, Tortola, BVI
LW Securities, Ltd. Centro San Ignacio, Torre Copernico Piso 7, Ofic 702, Urb. La Castellana Caracas, Venezuela	Common Stock		2,357,142	(13)		5.7	%

* Less than 1%.

(1) Beneficial ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities. Shares of common stock subject to options or warrants currently exercisable or convertible, or exercisable or convertible within 60 days of April 12, 2010 are deemed outstanding for computing the percentage of the person holding such option or warrant but are not deemed outstanding for computing the percentage of any other person.

(2) Percentage based upon 40,000,349 shares of our common stock outstanding as of April 12, 2010.

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(3) Includes 360,000 shares of our common stock issuable within 60 days upon the exercise of warrants.  Includes 58,334 shares of our common stock issuable within 60 days upon the exercise of vested options granted under our 2008 Equity Incentive Plan; does not include 116,666 shares of our common stock issuable upon the exercise of options granted under the 2008 Equity Incentive Plan, which vest in two equal annual installments beginning on July 1, 2010.

(4) Includes 25,000 shares of our common stock issuable within 60 days upon the exercise of warrants.  Includes 333,334 shares of our common stock issuable within 60 days upon the exercise of vested options granted under our 2008 Equity Incentive Plan; does not include 666,666 shares of our common stock issuable upon the exercise of options granted under the 2008 Equity Incentive Plan, which vest in two equal annual installments beginning on July 1, 2010.

(5) Mr. Berger is CEO of Oranje-Nassau Energie B.V, a privately held independent oil and gas investment company, which is an affiliate of Avante Petroleum SA.  Mr. Berger disclaims beneficial ownership of shares of our common stock beneficially owned by Avante Petroleum SA.

(6) Includes 200,000 shares of our common stock held by Jade & Adamo Associates (“JAA”) and 100,000 shares of our common stock issuable within 60 days upon the exercise of warrants held by JAA.  Mr. Montoya owns sixty-five percent (65%) of JAA and disclaims beneficial ownership of thirty-five percent (35%) of our common stock held by and issuable to JAA.  Includes 33,334 shares of our common stock issuable within 60 days upon the exercise of options granted under our 2008 Equity Incentive Plan; does not include 66,666 shares of our common stock issuable upon the exercise of options granted under the 2008 Equity Incentive Plan, which vest in two equal annual installments beginning on November 7, 2010.

(7) Includes 33,334 shares of our common stock issuable within 60 days upon the exercise of vested options granted under our 2008 Equity Incentive Plan; does not include 66,666 shares of our common stock issuable upon the exercise of options granted under the 2008 Equity Incentive Plan, which vest in two equal annual installments beginning on July 23, 2010.

(8) Includes 33,334 shares of our common stock issuable within 60 days upon the exercise of vested options granted under our 2008 Equity Incentive Plan; does not include 66,666 shares of our common stock issuable upon the exercise of options granted under the 2008 Equity Incentive Plan, which vest in two equal annual installments beginning on July 1, 2010.

(9) Includes 13,142,962 shares of common stock owned directly by Avante Petroleum S.A. and 2,857,143 shares of common stock issuable within 60 days upon the exercise of warrants owned by Avante Petroleum S.A.

(10) Includes 650,000 shares of our common stock issuable within 60 days upon the exercise of warrants.

(11) Includes 750,000 shares of our common stock issuable within 60 days upon the exercise of warrants.

(12) Includes 280,000 shares of our common stock issuable within 60 days upon the exercise of warrants.

(13) Includes 750,000 shares of common stock held by LW Securities, Ltd. and 750,000 shares of common stock issuable within 60 days upon the exercise of warrants held by LW Securities, Ltd.; and 571,428 shares of common stock held by LW Emerging Markets Opportunities Master Fund Ltd. and 285,714 shares of common stock issuable within 60 days upon the exercise of warrants held by LW Emerging Markets Opportunities Master Fund Ltd..

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Other than as disclosed under Item 5 above under “Recent Sales of Unregistered Securities” and elsewhere in this report, there have been no transactions since the beginning of our last fiscal year, and there are no currently proposed transactions, in which we were or are to be a participant and the amount involved exceeds the lesser of $120,000 or 1% of the average of our total assets at year end for the last two completed fiscal years, and in which any of our directors, executive officers or beneficial holders of more than 5% of our outstanding common stock, or any of their respective immediate family members, has had or will have any direct or material indirect interest.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees.

The aggregate fees billed to us by our principal accountant for services rendered during the fiscal years ended December 31, 2009 and 2008 are set forth in the table below:

Fee Category	Fiscal year ended  December 31, 2009		Fiscal year ended  December 31, 2008
Audit fees (1)	$	360,000	$	60,000
Audit-related fees (2)	$	40,000	$	10,000
Tax fees (3)		-		-
All other fees (4)		-		-
Total fees	$	400,000	$	70,000

(1) Audit fees consists of fees incurred for professional services rendered for the audit of consolidated financial statements, for reviews of our interim consolidated financial statements included in our quarterly reports on Forms 10-Q and 10-QSB and for services that are normally provided in connection with statutory or regulatory filings or engagements.

(2) Audit-related fees consists of fees billed for professional services that are reasonably related to the performance of the audit or review of our consolidated financial statements, but are not reported under “Audit fees.”

(3) Tax fees consists of fees billed for professional services relating to tax compliance, tax planning, and tax advice.

(4) All other fees consists of fees billed for all other services.

Audit Committee’s Pre-Approval Practice

Our Audit Committee is directly responsible for the appointment, compensation, retention and oversight of the work of any registered public accounting firm engaged by us for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for us, and each such registered public accounting firm must report directly to the Audit Committee.  Our Audit Committee must approve in advance all audit, review and attest services and all non-audit services (including, in each case, the engagement fees therefor and terms thereof) to be performed by our independent auditors, in accordance with applicable laws, rules and regulations.

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Our Audit Committee selected BDO Seidman, LLP as our independent registered public accountants for purposes of auditing our financial statements for the years ended December 31, 2009 and 2008.  In accordance with Audit Committee practice, BDO Seidman, LLP was pre-approved by the Audit Committee to perform these audit services for us prior to its engagement.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statement Schedules

The consolidated financial statements of La Cortez Energy, Inc. are listed on the Index to Financial Statements on this annual report on Form 10-K beginning on page F-1.

All financial statement schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.

Exhibits

The following Exhibits are being filed with this Annual Report on Form 10-K:

In reviewing the agreements included or incorporated by reference as exhibits to this Annual Report on Form 10-K, please remember that they are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. The agreements may contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the parties to the applicable agreement and:

• should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

• have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

• may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors; and

•  were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. Additional information about the Company may be found elsewhere in this Annual Report on Form 10-K and the Company’s other public filings, which are available without charge through the SEC’s website at http://www.sec.gov.

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Exhibit No.	SEC Report Reference Number	Description
3.1	3.1	Amended and Restated Articles of Incorporation of the Registrant as filed with the Nevada Secretary of State on February 8, 2008 (1)
3.2	3.2	By-Laws of the Registrant (2)
10.1	10.1	Employment Agreement dated May 13, 2008 by and between the Registrant and Andres Gutierrez Rivera (3)
10.2	10.1	Form of Stock Option Agreement to Directors under the Registrant’s 2008 Equity Incentive Plan, as amended (4)
10.3	10.1	Form of Stock Option Agreement to Executive Officers under the Registrant’s 2008 Equity Incentive Plan, as amended (4)
10.4	10.1	Split-Off Agreement dated August 15, 2008 by and among the Registrant, de la Luz Chocolates, Inc., and Maria de la Luz (5)
10.5	10.2	General Release Agreement dated August 15, 2008, by and among the Registrant, de la Luz Chocolates, Inc., and Maria de la Luz (5)
10.6	10.1	Form of Subscription Agreement for 2008 unit offering(6)
10.7	10.2	Form of Warrant for 2008 unit offering (6)
10.8	10.3	Form of Registration Rights Agreement for 2008 unit offering (6)
10.9	10.6	The Registrant’s Amended and Restated 2008 Equity Incentive Plan (7)
10.10	10.1	Memorandum of Understanding between the Registrant and Petroleos del Norte S. A. dated as of December 22, 2008 (8)
10.11	10.11	Farm-Out Agreement (Maranta E&P Block) by and between Emerald Energy Plc Sucursal Colombia and La Cortez Energy Colombia, Inc. dated as of February 6, 2008 (9)
10.12	10.1	Form of subscription agreement for 2009 unit offering (10)
10.13	10.2	Form of warrant for 2009 unit offering (10)
10.14	10.3	Form of registration rights agreement for 2009 unit offering (10)
10.15	10.1	Joint Operating Agreement between Petroleos del Norte S.A. and La Cortez Energy Colombia, Inc., dated as of February 23, 2009 (11)
10.16	4.1	Form of common stock purchase warrant dated December 29, 2009 (12)
10.17	*	Stock Purchase Agreement between the Registrant and Avante Petroleum SA, dated as of March 2, 2010

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Exhibit No.	SEC Report Reference Number	Description
10.18	*	Stockholder Agreement among the Registrant, Avante Petroleum SA, Nadine Smith and Andres Gutierrez, dated as of dated as of March 2, 2010
10.19	*	Share Escrow Agreement among the Registrant, Avante Petroleum SA and Robert Jan Jozef Lijdman, dated as of March 2, 2010
10.20	*	Subscription Agreement between the Registrant and Avante Petroleum SA, dated as of March 2, 2010
10.21	*	Registration Rights Agreement between the Registrant and Avante Petroleum SA, dated as of March 2, 2010
10.22	*	Form of Common Stock Warrant issued to Avante Petroleum SA
14.1	14	Code of Ethics (13)
21	*	List of Subsidiaries
31.1	*	Certification of Principal Executive Officer, pursuant to SEC Rules 13a-14(a) and 15d-14(a), adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	*	Certification of Interim Principal Financial Officer, pursuant to SEC Rules 13a-14(a) and 15d-14(a), adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	*	Certification of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**
32.2	*	Certification of Interim Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**

(1) Filed with the SEC on February 13, 2008 as an exhibit, numbered as indicated above, to the Registrant’s current report (SEC File No. 333-138465) on Form 8-K, which exhibit is incorporated herein by reference.

(2) Filed with the Securities and Exchange Commission on November 7, 2006 as an exhibit, numbered as indicated above, to the Registrant’s registration statement (SEC File No. 333-138465) on Form SB-2, which exhibit is incorporated herein by reference.

(3) Filed with the SEC on May 20, 2008 as an exhibit, numbered as indicated above, to the Registrant’s current report (SEC File No. 333-138465) on Form 8-K, which exhibit is incorporated herein by reference.

(4) Filed with the SEC on July 28, 2008 as an exhibit, numbered as indicated above, to the Registrant’s current report (SEC File No. 333-138465) on Form 8-K, which exhibit is incorporated herein by reference.

 (5) Filed with the SEC on August 21, 2008 as an exhibit, numbered as indicated above, to the Registrant’s current report (SEC File No. 333-138465) on Form 8-K, which exhibit is incorporated herein by reference.

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(6) Filed with the SEC on September 16, 2008 as an exhibit, numbered as indicated above, to the Registrant’s current report (SEC File No. 333-138465) on Form 8-K, which exhibit is incorporated herein by reference.

(7) Filed with the SEC on November 14, 2008 as an exhibit, numbered as indicated above, to the Registrant’s quarterly report (SEC File No. 333-138465) on Form 10-Q, which exhibit is incorporated herein by reference.

(8) Filed with the SEC on January 9, 2009 as an exhibit, numbered as indicated above, to the Registrant’s current report (SEC File No. 333-138465) on Form 8-K, which exhibit is incorporated herein by reference.

(9) Filed with the SEC on April 10, 2009 as an exhibit, numbered as indicated above, to the Registrant’s annual report (SEC File No. 333-138465) on Form 10-K, which exhibit is incorporated herein by reference.

(10) Filed with the SEC on June 22, 2009 as an exhibit, numbered as indicated above, to the Registrant’s current report (SEC File No. 333-138465) on Form 8-K, which exhibit is incorporated herein by reference.

(11) Filed with the SEC on November 16, 2009 as an exhibit, numbered as indicated above, to the Registrant’s quarterly report (SEC File No. 333-138465) on Form 10-Q, which exhibit is incorporated herein by reference.

(12) Filed with the SEC on January 4, 2010 as an exhibit, numbered as indicated above, to the Registrant’s current report (SEC File No. 333-138465) on Form 8-K, which exhibit is incorporated herein by reference.

(13) Filed with the SEC on March 31, 2008 as an exhibit, numbered as indicated above, to the Registrant’s annual report (SEC File No. 333-138465) on Form 10-KSB, which exhibit is incorporated herein by reference.

* Filed/furnished herewith.

** This certification is being furnished and shall not be deemed “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Registrant specifically incorporates it by reference.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	LA CORTEZ ENERGY, INC.
Dated:  April 16, 2010		By:	/s/ Andrés Gutierrez Rivera
			Andrés Gutierrez Rivera
			President and Chief Executive Officer
		By:	/s/ Nadine C. Smith
			Nadine C. Smith
			Interim Chief Financial Officer

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

SIGNATURE	TITLE	DATE
/s/ Nadine C. Smith	Chairman of the Board, Interim Chief	April 16, 2010
Nadine C. Smith	Financial Officer
/s/ Andrés Gutierrez Rivera	President and Chief Executive Officer,	April 16, 2010
Andrés Gutierrez Rivera	Director
/s/ Alexander F. D. Berger	Director	April 16, 2010
Alexander F. D. Berger
/s/ José Fernando Montoya	Director	April 16, 2010
José Fernando Montoya Carrillo
/s/ Jaime Navas Gaona	Director	April 16, 2010
Jaime Navas Gaona
/s/ Jaime Ruiz Llano	Director	April 16, 2010
Jaime Ruiz Llano
/s/ Richard G. Stevens	Director	April 16, 2010
Richard G. Stevens

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INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2009 and 2008	F-3
Consolidated Statements of Operations for the years ended December 31, 2009 and 2008	F-4
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the years ended December 31, 2009 and 2008	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2009 and 2008	F-6
Notes to Consolidated Financial Statements	F-7

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors

La Cortez Energy, Inc.

Bogota, Colombia

We have audited the consolidated balance sheets of La Cortez Energy, Inc. as of December 31, 2009 and 2008 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. 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 in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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 audits 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 audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of La Cortez Energy, Inc at December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, during 2009 the Company prepared and presented its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2009, the Company changed the manner in which it accounts for certain warrants pursuant to new authoritative guidance in FASB ASC topic 815-40, “Contract in Entity's Own Equity.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern.  As discussed in Note 2 to the financial statements, the Company has limited operating history, no historical profitability, and has limited available funds that raise substantial doubt about its ability to continue as a going concern. Management’s plan in regard to these matters is also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Houston, Texas

April 16, 2010

F-2

LA CORTEZ ENERGY, INC.

 Consolidated Balance Sheets

December 31, 2009 and 2008

	December 31,
	2009			2008
Assets
Cash and cash equivalents	$	2,376,585		$	6,733,381
Accrued oil receivables		189,835			-
Employee advances		26,294			-
Prepaid expenses		19,519			20,132
Total current assets		2,612,233			6,753,513
Oil properties, at cost:
Proved oil properties, using the full cost method of accounting		7,513,057			-
Unproved oil properties		1,599,951			-
Accumulated depletion and impairment		(6,706,603	)		-
		2,406,405			-
Other property and equipment, net of accumulated depreciation of $100,274 and $38,719, respectively		204,206			231,604
Restricted cash		2,672,500			-
Total assets	$	7,895,344		$	6,985,117
Liabilities and Shareholders' Equity (Deficit)
Liabilities:
Accounts payable	$	2,518,565		$	29,685
Accrued liabilities		267,155			127,107
Derivative warrant instruments		7,500,138			-
Total current liabilities		10,285,858			156,792
Asset retirement obligation		3,860			-
Total  liabilities		10,289,718			156,792
Commitments and contingencies (Note 10)
Shareholders' equity:
Preferred stock, $0.001 par value, 10,000,000 shares authorized, no shares issued or outstanding		-			-
Common stock, $.001 par value;  300,000,000 shares authorized; 25,428,815 and 18,935,244 shares issued and outstanding at December 31, 2009 and 2008, respectively		25,429			18,935
Additional paid-in capital		11,396,506			9,431,994
Accumulated deficit		(13,816,309	)		(2,622,604	)
Total shareholders' equity (deficit)		(2,394,374	)		6,828,325
Total liabilities and shareholders' equity (deficit)	$	7,895,344		$	6,985,117

See accompanying notes to consolidated financial statements.

F-3

LA CORTEZ ENERGY, INC.

Consolidated Statements of Operations

For the years ended December 31, 2009 and 2008

	Years Ended
	December 31,
	2009			2008
Oil revenues	$	189,835		$	-
Costs and Expenses:
Operating costs		421,693			-
Depreciation, depletion and amortization		364,787			38,719
Impairment of oil and gas properties		6,403,544			-
Accretion expense		156			-
General and administrative		3,274,786			2,610,593
Total costs and expenses		10,464,966			2,649,312
Loss from operations		(10,275,131	)		(2,649,312	)
Non-operating income (expense):
Unrealized gain on fair value of derivative warrant instruments, net		83,997			-
Interest income		49,404			69,005
Interest expense		-			(222	)
Loss before income taxes		(10,141,730	)		(2,580,529	)
Income taxes		(656	)		-
Net loss	$	(10,142,386	)	$	(2,580,529	)
Basic and diluted loss per share	$	(0.47	)	$	(0.15	)
Basic and diluted weighted average
common shares outstanding		21,625,442			17,730,971

See accompanying notes to consolidated financial statements

F-4

LA CORTEZ ENERGY, INC.

 Consolidated Statements of Changes in Shareholders’ Equity (Deficit)

 For the years ended December 31, 2009 and 2008

								Additional
		Common Stock						Paid-in			Accumulated
		Shares			Par Value			Capital			Deficit			Total
Balance at December 31, 2007	*		20,750,000		$	20,750		$	7,250		$	(42,075	)	$	(14,075	)
February 2008, common stock sold to an officer at $.01 per share	*		1,150,000			1,150			10,350			—			11,500
February 2008, common stock issued to a consultant in exchange for services at $1.00 per share	*		1,000,000			1,000			999,000			—			1,000,000
February 2008, cancellation of former officer's shares			(9,000,000	)		(9,000	)		9,000			—			—
February 2008, common stock issued in exchange for extinguishment of debt and accrued interest at $.50 per share			100,444			100			50,122			—			50,222
March 2008, common stock sold in private placement offering at $1.00 per share, less offering costs totaling $85,105			2,400,000			2,400			2,312,495			—			2,314,895
June 2008, indebtedness forgiven by related party			—			—			14,700			—			14,700
August 2008, cancellation of former officer's shares			(2,250,000	)		(2,250	)		2,250			—			—
September 2008, common stock and warrants sold in private placement offering at $1.25 per share, less offering costs totaling $218,874			4,784,800			4,785			5,757,341			—			5,762,126
Contributed services by interim CFO			—			—			23,333			—			23,333
Stock based compensation			—			—			246,153			—			246,153
Net loss, year ended December 31, 2008			—			—			—			(2,580,529	)		(2,580,529	)
Balance at December 31, 2008			18,935,244			18,935			9,431,994			(2,622,604	)		6,828,325
Cumulative effect of reclassification of warrants			—			—			(1,253,242	)		(1,051,319	)		(2,304,561	)
Balance at January 1, 2009, as adjusted			18,935,244			18,935			8,178,752			(3,673,923	)		4,523,764
June 2009, common stock and warrants sold in private placement offering at $1.25 per share, less offering costs totaling $830,635			4,860,000			4,860			637,934			—			642,794
July 2009, common stock and warrants sold in private placement offering at $1.25 per share, less offering costs totaling $39,452			205,000			205			47,757			—			47,962
December 2009, common stock and warrants sold in private placement offering at $1.75 per share, less offering costs totaling $145,730			1,428,571			1,429			1,843,588			—			1,845,017
Stock based compensation			—			—			688,475			—			688,475
Net loss, year ended December 31, 2009			—			—			—			(10,142,386	)		(10,142,386	)
Balance at December 31, 2009			25,428,815		$	25,429		$	11,396,506		$	(13,816,309	)	$	(2,394,374	)

* Restated for 5:1 forward stock spliteffected on February 27, 2008.

See accompanying notes to consolidated financial statements.

F-5

LA CORTEZ ENERGY, INC.

 Consolidated Statements of Cash Flows

For the years ended December 31, 2009 and 2008

	Years Ended December 31,
	2009			2008
Cash flows from operating activities:
Net loss	$	(10,142,386	)	$	(2,580,529	)
Adjustments to reconcile net loss to net cash used in operating
activities:
Depreciation, depletion and amortization and accretion		364,943			-
Impairment of oil properties		6,403,544			38,719
Stock-based compensation		688,475			1,246,153
Contributed services by interim CFO		-			23,333
Common stock issued in exchange for interest expense		-			222
Unrealized gain on fair value of derivative instruments, net		(83,997	)		-
Income taxes		656			-
Changes in operating assets and liabilities:
Accrued oil receivables		(189,835	)		-
Employee advances and other receivables		(26,294	)		-
Prepaid expenses		613			(19,632	)
Accounts payable		780,589			29,685
Accrued liabilities		139,392			126,107
Net cash used in operating activities		(2,064,300	)		(1,135,942	)
Cash flows from investing activities:
Investments in oil and natural gas properties		(7,401,013	)		-
Performance guarantee deposit		(2,672,500	)		-
Purchases of property and equipment		(34,330	)		(270,323	)
Net cash used in investing activities		(10,107,843	)		(270,323	)
Cash flows from financing activities:
Proceeds from the sale of common stock and derivative warrant
instruments		8,831,164			8,392,500
Payments for offering costs		(1,015,817	)		(303,979	)
Proceeds from issuance of note payable		-			50,000
Proceeds from related party debt		-			100
Net cash provided by financing activities		7,815,347			8,138,621
Net change in cash		(4,356,796	)		6,732,356
Cash, beginning of year		6,733,381			1,025
Cash, end of year	$	2,376,585		$	6,733,381
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes	$	139		$	-
Interest	$	-		$	-
Non-cash investing transactions:
Accrued capital expenditures in accounts payable	$	1,708,291		$	-
Non-cash investing and financing transactions:
Common stock issued in exchange for extinguishment of note payable and accrued interest	$	-		$	(50,222	)
Contributed capital associated with forgiveness of debt by  related
party	$	-		$	14,700
Asset retirement obligation costs and liabilities	$	3,704		$	-
Cumulative effect of reclassification of warrants	$	2,304,561		$	-

See accompanying notes to consolidated financial statements.

F-6

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

(1) Organization, Basis of Presentation and Summary of Significant Accounting Policies

Organization and Basis of Presentation

La Cortez Energy, Inc. (“LCE”, “La Cortez” or the “Company”), together with its 100% owned subsidiaries, La Cortez Energy Colombia, Inc., a Cayman Islands corporation (“LA Cortez Colombia”) and La Cortez Energy Colombia, E.U., a Colombia corporation (“Colombia E.U.”), is an international,  oil and gas exploration and production (“E&P”) company concentrating on opportunities in South America.

LCE had established Colombia E.U. in Colombia to explore E&P opportunities in Colombia and Peru.  On April 30, 2009, LCE elected to dissolve Colombia E.U.  The operations of Colombia E.U. were transferred to La Cortez Colombia.  The Colombian activities are being operated through a branch of La Cortez Colombia which was established during the quarter ended March 31, 2009.

The Company was incorporated under the name of La Cortez Enterprises, Inc. on June 9, 2006 in the State of Nevada. This entity was originally formed to create, market and sell gourmet chocolates wholesale and retail throughout Mexico, as more fully described in its registration statement on Form SB-2 as filed with the SEC on November 7, 2006 (the “Legacy Business”). This business has been discontinued. On February 7, 2008, the Company changed its name from La Cortez Enterprises, Inc. to La Cortez Energy, Inc.

Exploration Stage

The Company was in the exploration stage until September 30, 2009.  During October, 2009, the Company exited the exploration stage as a result of management’s determination that the Company held proved reserves and was receiving revenue from those reserves.

Split-off of Legacy Business

In connection with the discontinuation of the Company’s Legacy Business and the redirecting of its business strategy to focus on oil and gas exploration and production opportunities in South America, the Company split off and sold all of the assets and liabilities of the Legacy Business (the “Split-Off”) to Maria de la Luz, LCE’s founding stockholder. The Split Off closed on August 21, 2008. As more fully described in a Form 8-K filed by the Company with the SEC on August 21, 2008, the Company contributed all of its assets and liabilities relating to the Legacy Business, whether accrued, contingent or otherwise, and whether known or unknown, to a newly organized, wholly owned subsidiary, De La Luz Gourmet Chocolates, Inc., a Nevada corporation (“Split-Off Sub”), and immediately thereafter sold all of the outstanding capital stock of Split-Off Sub to Ms. de la Luz in exchange for 9,000,000 shares of the Company’s common stock, $0.001 par value per share (the “Common Stock”) previously surrendered by Ms. de la Luz and all of the Company’s common stock that Ms. de la Luz then owned, 2,250,000 shares. The 11,250,000 shares surrendered by Ms. de la Luz have been cancelled.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.  Estimates which are particularly significant to the consolidated financial statements include estimates of oil reserves, future cash flows from oil properties, depreciation, depletion, amortization, asset retirement obligations and accrued revenues.

F-7

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

Reclassifications

Certain prior year information has been reclassified to conform with current year presentation.

Cash and Cash Equivalents

The Company considers all highly liquid debt instruments with original maturities of three months or less when acquired to be cash equivalents. The Company places the majority of its cash and cash equivalents with financial institutions that are insured by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000.  From time to time, the Company’s cash balances exceeded FDIC insured limits. In October 2008, the Federal government temporarily increased the FDIC insured limits up to a maximum of $250,000 per depositor until January 1, 2014, after which time the insured limits will return to $100,000.  The Company mitigates this concentration of credit risk by monitoring the credit worthiness of financial institutions and its customers.   The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality.

The Company had cash equivalents of $15,106 and $-0- at December 31, 2009 and 2008, respectively.

Accounts receivable and allowance for doubtful accounts

The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. Accounts receivable are written down to reflect management's best estimate or realizability based upon known specific analysis, historical experience, and other currently available evidence of the net collectible amount. There is no allowance for doubtful accounts as of December 31, 2009 or 2008.

Property and equipment, net

Property and equipment consists primarily of office furniture, software and equipment and is stated at cost.  Depreciation is computed on a straight-line basis over the estimated useful lives ranging from two to five years.  Depreciation expense for the years ended December 31, 2009 and 2008 was $61,728 and $38,719, respectively.  

Oil and natural gas properties

The Company follows the full cost method of accounting for its oil and natural gas properties, whereby all costs incurred in connection with the acquisition, exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on non-producing leases, drilling, completing and equipping of oil and natural gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the statement of operations.

Depletion of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and natural gas properties, less related deferred taxes, are limited to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes.  As of December 31, 2009, the Company has properties in the amount of $1,599,951that are being excluded from amortization because they have not been evaluated to determine whether proved reserves are associated with those properties. Costs in excess of the present value of estimated future net revenues, as discussed above, are charged to impairment expense. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented.  

F-8

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

For the year ended December 31, 2009, the Company incurred an impairment of $6,403,544 on its oil and gas properties.  During the year ended December 31, 2009, the Company drilled its first exploratory well, Mirto-1.  As discussed in Note 3, the Company paid 65 percent of the drilling costs of this well and will receive a 20 percent working interest in the well.  After the completion of the drilling in October 2009, the Company is responsible for paying 20 percent of the operating costs of the well, and the Company expects to pay 20 percent of drilling and operating costs of any additional wells drilled in the Mirto prospect.  The Company paid the additional costs for the drilling of the Mirto-1 well in order to be able to participate in the prospect; however the additional costs paid have resulted in the majority of the impairment recognized in 2009, since the proven reserves from this well were determined to be insufficient to cover the cost incurred.

As discussed in Note 5, asset retirement costs are recognized when the asset is placed in service, and are included in the amortization base and amortized over proved reserves using the units of production method. Asset retirement costs are estimated by management using existing regulatory requirements and anticipated future inflation rates.

Oil and Natural Gas Reserve Quantities

The Company’s estimate of proved reserves is based on the quantities of oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. A third party specialist prepares a reserve and economic evaluation of all the Company’s properties utilizing information provided to it by management and other information available, including information from the operator of the property. As discussed in Note 13 below, the estimate of the Company’s proved reserves as of December 31, 2009 has been prepared and presented in accordance with new SEC rules and accounting standards. These new rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month un-weighted first- day-of-the-month average pricing. The previous rules required that reserve estimates be calculated using last-day-of-the-year pricing.

Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve report. The accuracy of the Company’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, eventually recovered.

Revenue Recognition

Sales of crude oil  are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.

Income Taxes

The Company accounts for income taxes under the provisions of FASB ASC Topic No. 740 (formerly SFAS No. 109, Accounting for Income Taxes) which provides for an asset and liability approach in accounting for income taxes.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.

F-9

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be realizable. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. The Company established a full valuation allowance and reduced its net deferred tax asset, principally related to the Company’s net operating loss carryovers, to zero as of December 31, 2009 and 2008. The Company will continue to assess the valuation allowance against deferred income tax assets considering all available information obtained in future reporting periods.  If the Company achieves profitable operations in the future, it may reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. The valuation allowance has no impact on the Company’s net operating loss (“NOL”) position for tax purposes, and if the Company generates taxable income in future periods prior to expiration of such NOLs, it will be able to use its NOLs to offset taxes due at that time.

Loss per Common Share

The Company accounts for earnings (loss) per share in accordance with FASB ASC Topic No. 260 – 10 (formerly SFAS No. 128, Earnings per Share), which establishes the requirements for presenting earnings per share (“EPS”).  FASB ASC Topic No. 260 – 10 requires the presentation of “basic” and “diluted” EPS on the face of the statement of operations.  Basic EPS amounts are calculated using the weighted average number of common shares outstanding during each period.  Diluted EPS assumes the exercise of all stock options, warrants and convertible securities having exercise prices less than the average market price of the common stock during the periods, using the treasury stock method. When a loss from continuing operations exists, as in the periods presented in these condensed consolidated financial statements, potential common shares are excluded from the computation of diluted EPS because their inclusion would result in an anti-dilutive effect on per share amounts.

For the year ended December 31, 2009, the Company had potentially dilutive shares outstanding, including 2,451,667 options to purchase shares of common stock, warrants to purchase 8,642,186 shares of common stock, and warrants to purchase 5,000 shares of common stock.  For the year ended December 31, 2008, the Company had potentially dilutive shares outstanding composed of 2,025,000 options to purchase shares of common stock.  There was no difference between basic and diluted loss per share for the years December 31, 2009 and 2008 as the effect of these potential common shares were anti-dilutive due to the net loss during both years.

Fair value of financial instruments

The carrying value of cash and cash equivalents, accrued oil and gas natural gas receivables, accounts payable and accrued expenses and other liabilities approximates fair value due to the short term nature of these accounts.

Foreign Currency Translation

The Company conducts its operations in two primary functional currencies: the U.S. dollar and the Colombian peso. Balance sheet accounts of the Company’s Colombian subsidiary are translated from foreign currencies into U.S. dollars at period-end exchange rates while income and expenses are translated at average exchange rates during the period. Cumulative translation gains or losses related to net assets located outside the U.S. are shown as a component of shareholders’ equity. Gains and losses resulting from foreign currency transactions, which are denominated in a currency other than the entity’s functional currency, are included in the consolidated statements of operations.  For the years ended December 31, 2009 and 2008, cumulative translation gains (losses) and foreign currency transaction gains (losses) were immaterial.

Recently Issued Accounting Standards and Developments

In June 2009, the FASBissued SFAS No. 168, “The FASB Accounting Standards Codification TM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“SFAS 168”). The FASB Accounting Standards Codification TM, (“Codification” or “ASC”) became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of SFAS 168, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification became non-authoritative.

F-10

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

Following SFAS 168, the FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead, it will issue Accounting Standards Updates (ASU’s). The FASB will not consider ASU’s as authoritative in their own right; rather these updates will serve only to update the Codification, provide background information about the guidance, and provide the bases for conclusions on the change(s) in the Codification. SFAS No. 168 is incorporated in ASC Topic 105, Generally Accepted Accounting Principles. The Company adopted SFAS No. 168 in the third quarter of 2009, and the Company will provide reference to both the Codification topic reference and the previously authoritative references related to Codification topics and subtopics, as appropriate.

Effective January 1, 2009, the Company adopted FASB ASC Topic No. 815 – 40, Derivatives and Hedging - Contracts in Entity’s Own Stock (formerly Emerging Issues Task Force Issue No. 07-5, Determining Whether an Instrument or Embedded Feature is Indexed to an Entity’s Own Stock). The adoption of FASB ASC Topic No. 815 – 40’s requirements can affect the accounting for warrants and many convertible instruments with provisions that protect holders from a decline in the stock price (or “down-round” provisions). For example, warrants with such provisions will no longer be recorded in equity.  Downward provisions reduce the exercise price of a warrant or convertible instrument if a company either issues equity shares for a price that is lower than the exercise price of those instruments or issues new warrants or convertible instruments that have a lower exercise price. The Company evaluated whether these warrants contained provisions that protect holders from declines in the Company’s stock price or otherwise couldresult in modification of the exercise price and/or shares to be issued under the respective warrant or preferred stock agreements based on a variable that is not an input to the fairvalue of a “fixed-for-fixed” option as defined under FASB ASC Topic No. 815 – 40. The Company determined that warrants to purchase 2,392,400 shares of common stock, issued in the September 2008 private placement, contained such provisions thereby concluding they were not indexed tothe Company’s own stock.

In accordance with FASB ASC Topic No. 815 – 40, the Company, beginning on January 1, 2009, recognized the September 2008 private placement warrants as liabilities at their respective fair values on each reporting date. The cumulative effect of the change in accounting for these instruments of $1,051,319 was recognized as an adjustment to the opening balance of accumulated deficit at January 1, 2009 and the transfer of the fair value of derivative warrant instruments as of January 1, 2009 from additional paid-in capital to derivative warrant instruments liability of $1,253,242.  The cumulative effect adjustment of $1,051,319 was the difference between the amounts representing the fair value of warrants to purchase 2,392,400 shares of common stock recognized in the consolidated balance sheet before initial adoption of FASB ASC Topic No. 815 – 40 and the amounts recognized in the consolidated balance sheet upon the initial application of FASB ASC Topic No. 815 – 40. The amounts recognized in the consolidated balance sheet as a result of the initial application of FASB ASC Topic No. 815 – 40 on January 1, 2009 were determined based on the amounts that would have been recognized if FASB ASC Topic No. 815 – 40 had been applied from the issuance date of the instruments. FASB ASC Topic No. 815 – 40 also requires that such instruments be measured at fair value at each reporting period.  The Company measured the fair value of these instruments as of December 31, 2009, and recorded $339,904 unrealized gain to the statement of operations for the year ended December 31, 2009. The Company determined the fair values of these securities using a lattice valuation model.

The Company also determined that warrants to purchase a total of 6,249,786 shares of common stock issued in the 2009 Unit Offerings (discussed below) contained provisions that protect holders from declines in the Company’s stock price or otherwise couldresult in modification of the exercise price and/or shares to be issued under the respective warrant or preferred stock agreements based on a variable that is not an input to the fairvalue of a “fixed-for-fixed” option as defined under FASB ASC Topic No. 815 – 40.  As a result, these warrants were not indexed tothe Company’s own stock.  The fair value of these 2009 Unit Offerings warrants was recognized as derivative warrant instruments and will be measured at fair value at each reporting period.  The Company measured the fair value of these instruments as of December 31, 2009, and recorded ($255,907) unrealized loss to the statement of operations for the year ended December 31, 2009. The Company determined the fair values of these securities using a lattice valuation model.

F-11

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The use of average prices affected our fourth quarter 2009 depletion and impairment calculations and will affect future impairment and depletion calculations. In January 2010, the FASB issued ASU 2010-03, Extractive Activities – Oil and Gas (Topic 932) Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”), which aligns the oil and natural gas reserve estimation and disclosure requirements of ASC 932 with the requirements in the SEC’s Final Rule, Modernization of the Oil and Gas Reporting Requirements discussed above. The Company adopted the Final Rule and ASU effective December 31, 2009.

In April 2009, the FASB issued FASB Staff Position (“FSP”) SFAS No. 141(R)-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”. FSP FAS 141(R)-1, which is incorporated in FASB ASC Topic No. 805, “Business Combinations” addresses application issues raised by preparers, auditors, and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company has not made any acquisitions during the year ended December 31, 2009 that would require such disclosures.  The Company is currently evaluating the extent of disclosures which will be required for the Avante acquisition which occurred subsequent to year end.

In April 2009, the FASB issued FASB Staff Position SFAS 157-4, “Determining the Fair Value of a Financial Asset When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP 157-4”). FSP 157-4, which is incorporated in FASB ASC Topic No. 820, “Fair Value Measurements and Disclosures”, clarified and provided additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased. This FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. This FSP shall be effective for interim and annual reporting periods ending after June 15, 2009, and shall be applied prospectively. Early adoption is permitted for periods ending after March 15, 2009. Earlier adoption for periods ending before March 15, 2009, is not permitted. If a reporting entity elects to adopt early either FSP FAS 115-2 and FAS 124-2 or FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, the reporting entity also is required to adopt early this FSP. Additionally, if the reporting entity elects to adopt early this FSP, FSP FAS 115-2 and FAS 124-2 also must be adopted early. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. Revisions resulting from a change in valuation technique or its application shall be accounted for as a change in accounting estimate (FASB ASC Topic No. 250 – 10 - 45, Accounting Changes and Error Corrections). In the period of adoption, a reporting entity shall disclose a change, if any, in valuation technique and related inputs resulting from the application of this FSP, and quantify the total effect of the change in valuation technique and related inputs, if practicable, by major category. The adoption of this topic did not have a material impact on the Company's results of operations or financial position.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”). SFAS 165, which is incorporated in FASB ASC Topic No. 855, “Subsequent Events”, establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this Statement sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. In accordance with SFAS 165, an entity should apply the requirements to interim or annual financial periods ending after June 15, 2009. The Company adopted SFAS 165 effective June 30, 2009 and the adoption did not have a material impact on its consolidated financial statements.

F-12

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

In June 2009, the FASB issued guidance which amends the consolidation guidance applicable to variable interest entities. This guidance is included in FASB ASC 810, Consolidation. The amendments significantly reduce the previously required quantitative consolidation analysis, and require ongoing reassessments of whether a company is the primary beneficiary of a variable interest entity. This new guidance also requires enhanced disclosures about an enterprise’s involvement with a variable interest entity. This statement is effective for the beginning of the first annual reporting period beginning after November 15, 2009. The Company does not currently expect the adoption of the new guidance in FASB ASC 810 to impact its consolidated financial statements.

In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurements, which enhances the usefulness of fair value measurements. The amended guidance requires both the disaggregation of information in certain existing disclosures, as well as the inclusion of more robust disclosures about valuation techniques and inputs to recurring and nonrecurring fair value measurements.  The amended guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disaggregation requirement for the reconciliation disclosure of Level 3 measurements, which is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. The Company adopted ASU 2010-06 effective December 31, 2009, and the adoption did not have a significant impact on the Company’s consolidated financial statements.

(2) Going Concern

At December 31, 2009, the Company had cash and cash equivalents of $2,376,585 and working capital deficit of $7,673,625. The Company believes that its existing capital resources may not be adequate to enable it to execute its business plan.  The Company estimates that it will require additional cash resources during 2010 based upon its current operating plan and condition.

Through December 31, 2009, the Company has been primarily engaged in locating viable investment prospects and recruiting personnel. In the course of its development activities, the Company has sustained losses and expects such losses to continue through at least December 31, 2010.  The Company expects to finance its operations primarily through its existing cash and any future financing. However, there exists substantial doubt about the Company’s ability to continue as a going concern because the Company will be required to obtain additional capital in the future to continue its operations and there is no assurance that it will be able to obtain such capital through equity or debt financing, or any combination thereof, or on satisfactory terms or at all. Additionally, no assurance can be given that any such financing, if obtained, will be adequate to meet the Company’s ultimate capital needs and to support the Company’s growth. If adequate capital cannot be obtained on a timely basis and on satisfactory terms, the Company’s operations would be materially negatively impacted.

The Company’s ability to complete additional offerings is dependent on the state of the debt and/or equity markets at the time of any proposed offering, and such market’s reception of the Company and the offering terms. In addition, the Company’s ability to complete an offering may be dependent on the status of its oil and gas exploration activities, which cannot be predicted. There is no assurance that capital in any form would be available to the Company, and if available, on terms and conditions that are acceptable.

As a result of the above discussed conditions, and in accordance with generally accepted accounting principles in the United States of America, there exists substantial doubt about the Company’s ability to continue as a going concern, and the Company’s ability to continue as a going concern is contingent upon its ability to secure additional adequate financing or capital during the coming year. If the Company is unable to obtain additional sufficient funds during this time, the Company might lose its interest in the Petronorte, Emerald and Avante projects described in Note 3 below.  This action would have an adverse effect on the Company’s future operations, the realization of its assets and the timely satisfaction of its liabilities. The Company’s consolidated financial statements are presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The consolidated financial statements do not include any adjustments relating to the recoverability of the recorded assets or the classification of liabilities that may be necessary should it be determined that the Company is unable to continue as a going concern.

F-13

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

(3) Oil and Gas Properties

The Company follows the full cost method of accounting for its oil and natural gas properties, whereby all costs incurred in connection with the acquisition, exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on non-producing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the statement of operations.

Depletion of proved oil and gas properties will be calculated on the units-of-production method based upon estimates of proved reserves. Such calculations include the estimated future costs to develop proved reserves. Costs of unproved properties are not included in the costs subject to depletion. These costs are assessed periodically ceiling test for impairment.  As of December 31, 2009, $1,599,951 of the Company’s oil and natural gas properties were unproved and were not subject to depletion or ceiling test impairment.

Agreement with Petronorte

On December 22, 2008, the Company entered into a memorandum of understanding (the “MOU”) with Petroleos del Norte S.A. (“Petronorte”), a Colombian subsidiary of Petrolatina Energy Plc., that entitles it to a 50% net working interest in the Putumayo 4 block located in the south of Colombia (the “Putumayo 4 Block”).  Petronorte was the successful bidder on the Putumayo 4 Block in the Colombia Mini Round 2008 run by the  Agencia Nacional de Hidrocarburos  (the “ANH”), Colombia’s hydrocarbon regulatory agency.  According to the MOU, the Company will have the exclusive right to a fifty percent (50%) net participation interest in the Putumayo 4 Block and in the exploration and production contract (the “E&P Contract”) after ANH production participation.   Petronorte signed an E&P Contract with the ANH in February 2009.  Petronorte will be the “operator” of the E&P Contract.

On October 14, 2009, La Cortez Energy Colombia, the Company’s1 wholly owned subsidiary, entered into a joint operating agreement (the “JOA”) with Petronorte. The JOA was signed pursuant to the MOU.  The JOA entitles the Company (through La Cortez Colombia) to a 50% net working interest in the Putumayo 4 Block located in the south of Colombia (the “Putumayo 4 Block”) subject to approval by ANH.

The Putumayo 4 Block covers an area of 126,845 acres (51,333 hectares) located in the Putumayo Basin in southern Colombia and has over 1000 km of pre-existing 2D seismic through which we and Petronorte have identified promising leads. The Company and Petronorte plan to reprocess any relevant seismic information before conducting our own seismic campaign to better direct the positioning of our seismic program within the block. During this initial stage, the Company and Petronorte plan to begin environmental and community consultations to expedite some of these timely processes.

Under the terms of the E&P Contract, Petronorte will shoot 103 km of 2D seismic and will drill an exploratory well in the first three years of the Company’s work program in the Block. The E&P Contract will consist of two three-year exploration phases and a twenty-four year production phase.

As criteria for awarding blocks in the 2008 Mini Round, the ANH considered proposed additional work commitments, comprised of capital expenditures and an additional production revenue payment after royalties, called the “X Factor.”   The Company and Petronorte offered to invest US $1.6 million in additional seismic work in the Putumayo 4 Block and to pay ANH a 1% of net production revenues X Factor.

According to the JOA, which is effective retroactively to February 23, 2009, the Company is entitled to a fifty percent (50%) net participation interest in the Putumayo 4 Block and in the E&P Contract.  These percentages are calculated after royalties and after an additional production participation of 1% payable to the ANH. Under the MOU and the JOA, the Company was responsible for fifty percent (50%) of the costs incurred under the E&P Contract, entitling the Company to fifty percent (50%) of the revenues originated from the Putumayo 4 Block, net of royalty and production participation to the ANH (including but not limited to any guarantees required by the ANH), except that the Company will be responsible for paying two-thirds (2/3) of the costs of the first 103 kilometers of 2D seismic to be performed in the Putumayo 4 Block, in accordance with the Phase 1 minimum exploration program under the E&P Contract. The Company expects that capital commitments to Petronorte will be approximately U.S. $2.8 million (which includes its portion of the US $1.6 million referenced in the previous paragraph) in 2010 for Phase 1 seismic reprocessing and acquisition activity costs.  If a prospective Phase 1 well in a prospect in the Putumayo 4 Block proves productive, Petronorte will reimburse La Cortez for its share of these seismic costs paid by La Cortez in excess of La Cortez’ agreed-upon 50% share of total costs, with production from the Putumayo 4 Block.  The JOA also governs other legal, technical and operational rights and obligations of the parties with respect to development of the Putumayo 4 Block.

F-14

LA CORTEZ ENERGY, INC.

 Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

The Company’s total Phase 1 commitment under the MOU over the 36 month Phase 1 period is currently projected to be approximately U.S. $5.8 million.  The Company’s total Phase 2 commitment under the contract over the second 36 month project period is currently projected to be approximately U.S. $6.0 million, fifty percent of the total U.S. $12 million currently budgeted.  In November 2009, the Company deposited  U.S. $2.67 million into a trust account as the Company’s fifty percent portion of a Phase 1 performance guarantee required by the ANH under Petronorte’s Putumayo 4 Block E&P contract.  The Company expects that this guarantee deposit will remain in place for the 36 month Phase 1 period and the Company may be required to supplement the guarantee deposit in Phase 2 to take into account its additional investment requirements of that phase and accordingly, the deposit has been classified as long term in the accompanying balance sheet.    

Provided that the Company has satisfactorily complied with all ANH legal, financial and technical requirements for being a partner in an E&P contract and with payment requirements relating to its share of all costs incurred to the date of its request, Petronorte will submit a request to the ANH to assign a 50% interest in the E&P Contract to La Cortez and will assist it in obtaining such assignment through reasonable means.

Emerald Farm-In Agreement

On February 6, 2009, the Company entered into a farm-in agreement (the “Farm-In Agreement”) with Emerald Energy Plc Sucursal Colombia (“Emerald”), a Colombian branch of Emerald Energy Plc. (“Emerald Energy”), a company existing under the laws of the United Kingdom, for a 20% participating interest (the “Participating Interest”) in the Maranta exploration and production block (“Maranta”) in the Putumayo Basin in Southwest Colombia.

Emerald signed an E&P Contract for the Maranta block with the ANH on September 12, 2006.  The Company expects to execute a joint operating agreement with Emerald with respect to the Maranta block once it has met its Phase 1 and Phase 2 (drilling and completion of the Mirto-1 exploratory well) payment obligations described below and the ANH has approved Emerald’s assignment of the participating interest to the Company.  Under the Farm-In Agreement and the joint operating agreement, Emerald will remain the operator for the block.  If the ANH does not approve the assignment of the Participating Interest to the Company, Emerald and the Company have agreed that they will use their best endeavors to seek in good faith a legal way to enter into an agreement with terms equivalent to the Farm-In Agreement and the joint operating agreement, that shall privately govern the relations between the parties with respect to the Maranta Block and which will not require ANH approval.

The Maranta block covers an area of 90,459 acres (36,608 hectares) in the foreland of the Putumayo Basin in southwest Colombia. Emerald completed the first phase exploratory program for the Maranta block by acquiring 71 square kilometers of new 2D seismic and reprocessing 40 square kilometers of existing 2D seismic, identifying several promising prospects and leads. Emerald has identified the Mirto prospect, namely the Mirto 1 well, as the first exploratory well in the Maranta block.  The Maranta block is adjacent to Gran Tierra’s Chaza block and close to both the Orito and Santana crude oil receiving stations, allowing transportation by truck directly to either station (depending on going rates and capacity), and consequently tying into the pipeline to Colombia’s Pacific Ocean port at Tumaco.

As consideration for its 20% participating interest, the Company reimbursed Emerald $0.9 million of its Phase 1 sunk costs.  This amount was paid to Emerald on February 12, 2009 and was capitalized as part of oil and natural gas properties.  Additionally, the Company agreed to bear 65% of the Maranta block Phase 2 costs, of which the Company’s portion of the exploratory well drilling costs amounted to approximately U.S. $4.9 million, U.S. $2.4 million of which La Cortez paid to Emerald on February 18, 2009 and U.S. $2.4 million of which La Cortez paid to Emerald on May 15, 2009 (both capitalized as part of oil and natural gas properties).

F-15

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

Emerald reached the intended total depth of 11,578 feet on the Mirto-1 exploration well, with oil and gas recorded across the target reservoirs.   On July 23, 2009, based on the preliminary results of the drilling of the Mirto-1 well, the Company decided to participate with Emerald in the completion and evaluation of Mirto-1.  In accordance with the terms of the Maranta Block Farm-In Agreement, the Company agreed to bear 65% of the Maranta Block Phase 2 costs, including 65% (U.S. $1.2 million) of the currently estimated U.S. $1.8 million Mirto-1 completion costs.  The Company made this U.S. $1.2 million payment to Emerald on July 27, 2009.  65% of any additional Phase 2 costs will be paid by the Company as needed, following cash calls by Emerald.  If La Cortez Colombia fails to make required payments in a timely way, it could be subject to a reduction in its 20% Participating Interest, depending on the circumstances.  After the Phase 2 work is completed, La Cortez Colombia will pay 20% of all subsequent costs related to the Maranta block.

Once the Company has the final Mirto-1 evaluation results, the Company will ask Emerald to file a request with the ANH to have the Participating Interest in the Maranta Block officially assigned from Emerald to La Cortez Energy Colombia (the “Assignment”). On August 4, 2009, La Cortez Colombia paid an additional U.S. $243,300 to Emerald for overhead costs, representing 5% of total expenditures, in accordance with the Farm-In Agreement. As of December 31, 2009, the Company had accounts payable in the amount of $1,708,291 related to capitalized costs for oil and natural gas properties.

The evaluation of the Mirto-1 exploratory well across all of the target reservoirs has been completed.  Following the completion of operations in the Mirto-1 well, the drilling rig has been released from the location. Currently, a production test from the Villeta U sand interval is being conducted.  Emerald, as operator of the Maranta block, has decided to enter the Phase 3 exploration work commitment in the Maranta block, which would entail the drilling of an additional exploratory/appraisal well and the acquisition of 30 kilometers of 3D seismic.  The operator has already acquired 31 kilometers of 3D seismic as part of this new phase of work.

On February 4, 2010, the Company signed a joint operating agreement with Emerald with respect to the Maranta Block and the Company has asked Emerald to submit a request to the ANH to approve the assignment of the Company’s 20% participating interest to us.  If the ANH does not approve this assignment, Emerald and the Company have agreed to use its best endeavors to seek in good faith a legal way to enter into an agreement with terms equivalent to the farm-in agreement and the joint operating agreement, that shall privately govern the relations between the parties with respect to the Maranta Block and which will not require ANH approval.

For the year ended December 31, 2009, the Company incurred an impairment of $6,403,544 on its oil and gas properties.  During the year ended December 31, 2009, the Company drilled its first exploratory well, Mirto-1.  As discussed above, the Company paid 65 percent of the drilling costs of this well and will receive a 20 percent working interest in the well.  After the completion of the drilling in October 2009, the Company is responsible for paying 20 percent of the operating costs of the well, and the Company expects to pay 20 percent of drilling and operating costs of any additional wells drilled in the Mirto prospect.  The Company paid the additional costs for the drilling of the Mirto-1 well in order to be able to participate in the prospect; however the additional costs paid have resulted in the majority of the impairment recognized in 2009, since the proven reserves from this well were determined to be insufficient to cover the cost incurred.  Management believes that mechanical problems with the well have resulted in lower oil production and a higher water cut, resulting in lower quantities of estimated proved reserves.  Management continues to believe that despite these mechanical problems, there is sufficient accumulation of hydrocarbons in the area to merit the drilling of at least two additional wells

Effective October 12, 2009, Emerald’s parent, Emerald Energy Plc, was acquired by Sinochem Resources UK Limited, a United Kingdom subsidiary of Sinochem Group, a Chinese state-owned energy and chemicals conglomerate.  At this time, the Company does not know what impact this acquisition will have on the management and corporate policies of Emerald in Colombia or on the future operation of the Company’s joint relationship with Emerald.

(4) Related Party Transactions

Common Stock sales

On July 28, 2006, the Company sold 11,250,000 (after giving effect to the common stock split referred to in Note 6 below) shares of its Common Stock to its then sole officer and director for $9,000, or $.0008 (post-split) per share.

F-16

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

On February 7, 2008, the Company sold 1,150,000 (after giving effect to the common stock split referred to in Note 6 below) shares of its Common Stock to its newly appointed, then sole officer and director for $11,500, or $.01 (post-split) per share.

On March 14, 2008, the Company closed our 2008 private placement in which we sold 500,000 shares of our restricted common stock to our Chairman, in consideration of cash in the amount of $1.00 per share, for a total of $500,000.

On September 10, 2008, as part of its 2008 Unit Offering, the Company sold 400,000 Units (see Note 6), at a price of $1.25 per Unit, for a total of $500,000 to its Chairman, and 50,000 Units for a total of $62,500 to its President and Chief Executive Officer.  Also, as part of its 2008 Unit Offering, the Company sold 200,000 Units to Jade & Adamo Associates, in consideration of cash in the amount of $1.25 per Unit, for a total of $250,000.  One of the Company’s directors owns sixty-five percent (65%) of Jade & Adamo Associates and disclaims beneficial ownership of thirty-five percent (35%) of the units held by Jade & Adamo Associates.

On June 19, 2009, as part of the Initial Closing of its 2009 Mid-Year Unit Offering, the Company sold 160,000 Units (see Note 6), at a price of $1.25 per Unit, for a total of $200,000 to its Chairman and Vice President.

Forgiveness of indebtedness to related party 

During 2006 and 2007, the then sole officer and director of the Company advanced a total of $14,700 to the Company for working capital. These advances bore no interest and were payable on demand. On June 30, 2008, the former sole officer and director forgave the total amount of the advances. Accordingly, the Company eliminated the $14,700 payable and treated the debt forgiveness as a capital contribution and recorded the amount as additional paid in capital

(5) Asset Retirement Obligation

ASC 41-20 (formerly FAS No. 143), requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon the Company’s quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using the Company’s credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost related to oil and gas property accounts.

The following table reflects the changes in the ARO during the year ended December 31, 2009.  There was no ARO liability recognized prior to 2009 as the Company’s first well was drilled during 2009.

	Amount
Asset retirement obligation — beginning of period	$	-
Liabilities incurred with properties drilled		3,704
Current period accretion		156
Asset retirement obligation — end of period	$	3,860

The credit adjusted, risk free rate used in calculating the ARO was 18% at December 31, 2009. These rates approximate the Company’s borrowing rate.

F-17

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

 

(6) Shareholders’ Equity

As of December 31, 2009, there were 25,428,815 shares of common stock and no shares of preferred stock issued and outstanding.

Common Stock split

On February 8, 2008, the articles of incorporation of LCE were amended to increase the authorized capital stock of LCE to 310,000,000 shares, of which 300,000,000 are common stock with a par value of $0.001 per share and 10,000,000 shares are preferred stock with a par value $0.001 per share.  The Board of Directors is authorized to fix or alter the designation, powers, preferences and rights of the preferred stock.  The Board of Directors has made no such designation as of December 31, 2009.

On February 7, 2008, the Company’s Board of Directors approved a 5-for-1 forward stock split on each share of its common stock issued and outstanding at the close of business on February 21, 2008. Shares issued prior to February 21, 2008 have been retroactively restated to reflect the impact of the stock split.

Common Stock issued for services

On February 7, 2008, the Company issued 1,000,000 (post-split) shares of its common stock in exchange for consulting services, which included assisting the Chairman in building the Board of Directors and senior management team for the Company. The transaction was valued in accordance with EITF 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.”  Management determined the fair value of the stock issued to the consultant at $1.00 (post-split) per share based on the stock price received in the Offering (defined below) on March 14, 2008. Accordingly, stock-based compensation expense of $1,000,000 was recognized in the accompanying consolidated statement of operations for the year ended December 31, 2008.

Common Stock sales

On July 28, 2006, the Company sold 11,250,000 (post-split) shares of Common Stock to its then sole officer and director for $9,000, or $.0008 (post split) per share.

On December 12, 2006, the Company sold 9,500,000 (post split) shares of Common Stock at a price of $.002 (post split) per share for total proceeds of $19,000 ($13,845 net after offering expenses). The offering was made pursuant to the Company’s SB-2 registration statement that became effective on December 4, 2006.

On February 7, 2008, the Company sold 1,150,000 (post split) shares of Common Stock to its then newly appointed sole officer and director for $11,500, or $.01 (post-split) per share.

On February 19, 2008 the Board of Directors authorized the Company to offer up to 2,000,000 shares of Common Stock to a limited number of accredited investors and/or non-U.S persons at a price of $1.00 per share, in a private placement offering (the “Offering”) pursuant to the exemption from registration provided by Rule 506 of Regulation D under the Securities Act, Regulation S under the Securities Act and/or Section 4(2) of the Securities Act. Because the offering was oversubscribed, the Company’s Board of Directors further authorized to increase the size of the Offering to up to 3,000,000 shares of Common Stock. On March 14, 2008, the Company issued a total of 2,400,000 shares of Common Stock for total proceeds to the Company of $2,400,000 ($2,314,895 net after offering expenses).

On July 23, 2008 the Board of Directors authorized the Company to offer up to a maximum of 10,000,000 units (the “2008 Unit Offering”) at an offering price of $1.25 per Unit. Each Unit consisted of one share of Common Stock and a common stock purchase warrant to purchase one-half share of Common Stock, exercisable for a period of five years at an exercise price of $2.25 per share. The Units were offered to a limited number of accredited investors and non-U.S persons, in a private placement offering pursuant to the exemption from registration provided by Rule 506 of Regulation D under the Securities Act of 1933, as amended (the “Securities Act”), Regulation S under the Securities Act and/or Section 4(2) of the Securities Act. On September 10, 2008, the Company issued 4,784,800 shares of Common Stock as the result of the sale of 4,784,800 Units, for total proceeds to the Company of $5,981,000 ($5,762,126 net after offering expenses), and warrants to purchase 2,392,400 shares of Common Stock.

Investors in the 2008 Unit Offering have “piggyback” registration rights for the shares of Common Stock issued in the Unit Offering included in the Units and underlying the Warrants included in the Units.

F-18

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

Additionally, investors in the 2008 Unit Offering have “demand” registration rights with respect to the shares of Common Stock included in the Units if the Company does not file a registration statement with the SEC in which the investors can exercise their ‘piggyback’ registration rights within six months of the Closing of the 2008 Unit Offering (which the Company did not do).  Therefore, at any time on or after the date that is six months after the Closing, one or more of the investors that in the aggregate beneficially own at least 50% of the Shares issued in the Unit Offering may make a demand that the Company effect the registration of all or part of the investors’ Shares (a "Demand Registration").  Investors have the right to one Demand Registration pursuant to these provisions.

The Company would be required to prepare a Registration Statement following receipt of the required investor demand, to be filed with the SEC and to become effective within two hundred ten (210) days from the receipt of the demand notice, registering for resale all shares of Common Stock issued in the 2008 Unit Offering included in the Units of those investors who choose to participate in such Demand Registration.  The Company will pay monetary penalties to these investors equal to one and one-quarter percent (1.25%) of the gross proceeds of the 2008 Unit Offering for each full month that the registration statement is late in being declared effective; provided, that in no event shall the aggregate of any such penalties exceed fifteen percent (15%) of the gross proceeds of the Unit Offering.  No penalties shall accrue with respect to any shares of Common Stock removed from the registration statement in respect to a comment from the SEC limiting the number of shares of Common Stock which may be included in the registration statement.  The holders of any Common Stock removed from the registration statement as a result of a comment from the SEC shall continue to have “piggyback” registration rights with respect to these shares.  There has been no request for a Demand Registration as of December 31, 2009.

On May 11, 2009 the Board of Directors authorized the Company to offer up to a maximum of 12,000,000 units (the “2009 Mid-Year Unit Offering”) at an offering price of $1.25 per Unit. Each Unit consisted of one share of Common Stock and a common stock purchase warrant to purchase one share of Common Stock, exercisable for a period of five years at an exercise price of $2.00 per share. The Units were offered to a limited number of accredited investors and non-U.S persons, in a private placement offering pursuant to the exemption from registration provided by Rule 506 of Regulation D under the Securities Act of 1933, as amended (the “Securities Act”), Regulation S under the Securities Act and/or Section 4(2) of the Securities Act. On June 19, 2009 (“Initial Closing’), the Company issued 4,860,000 shares of Common Stock as the result of the sale of 4,860,000 Units, for total proceeds to the Company of $6,074,914 ($5,244,279 net after offering expenses), and warrants to purchase 4,860,000 shares of Common Stock.  The Company offered the Units directly and through finders (the “Finders”).  Also at the Initial Closing, the Company paid Finders a commission in cash of ten percent (10%) of the principal amount of each Unit sold by them in the Offering, for an aggregate amount of $562,500, plus 450,000 five-year warrants exercisable at a price of $1.25 per share.  On July 31, 2009, the Company completed its final closing (the “Final Closing”) of the 2009 Mid-Year Unit Offering and closed on the sale of 205,000 Units.  At the Final Closing, the Company issued 205,000 shares of Common Stock, for total proceeds to the Company of $256,250 ($216,798 net after offering expenses), and warrants to purchase 205,000 shares of Common Stock.  The Company also paid Finders a commission in cash of ten percent (10%) of the principal amount of each Unit sold by them in the Offering, for an aggregate amount of $25,625, plus 20,500 five-year warrants exercisable at a price of $1.25 per share.  The 2009 Mid-Year Unit Offering was terminated on July 31, 2009.

On December 29, 2009, the Company closed a private placement offering of 1,428,571 Units (the “December 2009 Unit Offering”) at an offering price of $1.75 per Unit. Each Unit consisted of one share of Common Stock and a common stock purchase warrant to purchase one-half of one share of Common Stock, exercisable for a period of three years at an exercise price of $3.00 per share. The Units were offered to a limited number of accredited investors and non-U.S persons, in a private placement offering pursuant to the exemption from registration provided by Rule 506 of Regulation D under the Securities Act of 1933, as amended (the “Securities Act”), Regulation S under the Securities Act and/or Section 4(2) of the Securities Act. The Company issued 1,428,571 shares of Common Stock as the result of the sale of 1,428,571 Units, for total proceeds to the Company of $2,500,000 ($2,354,270 net after offering expenses), and warrants to purchase 714,286 shares of Common Stock.

F-19

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

The Company determined that warrants to purchase a total of 6,249,786 shares of common stock issued in the 2009 Mid-Year Unit Offering and December 2009 Unit Offering (collectively, the “2009 Unit Offerings”) contained provisions that protect holders from declines in the Company’s stock price or otherwise couldresult in modification of the exercise price and/or shares to be issued under the respective warrant or preferred stock agreements based on a variable that is not an input to the fairvalue of a “fixed-for-fixed” option as defined under FASB ASC Topic No. 815 – 40 - 15.  As a result, these warrants were not indexed tothe Company’s own stock.  At the Initial Closing of the 2009 Mid-Year Unit Offering, the fair value of these warrants was determined to be approximately $4,601,485, which was recorded as a derivative warrant instruments liability.  The Company also recorded $4,860 as par value to common stock and $637,934 to additional paid-in capital as part of the Initial Closing of the 2009 Unit Offering transaction.  At the Final Closing, the fair value of these warrants was approximately $168,776, which was recorded as a derivative warrant instruments liability.  The Company also recorded $205 as par value to common stock and $47,757 to additional paid in capital as part of the Final Closing of the 2009 Unit Offering transaction.  At the December 2009 Closing, the fair value of these warrants was approximately $509,313, which was recorded as a derivative warrant instruments liability.  The Company also recorded $1,429 as par value to common stock and $1,843,588 to additional paid in capital as part of the December 2009 Closing transaction.

The table below reflects the breakdown of the components of gross proceeds from the Company’s 2009 Unit Offerings:

Par value of common stock issued	$	6,494
Paid-in capital		2,529,279
Derivative warrant instruments		5,279,574
Offering expenses		1,015,817
Total gross proceeds	$	8,831,164

The Company entered into a registration rights agreement with the investors purchasing Units in the 2009 Mid-Year Unit Offering.  The registration rights agreement requires that the Company prepare and file with the SEC a registration statement on Form S-1 covering the resale of all shares of Common Stock issued in the Offering (the “Registrable Shares”). Shares of Common Stock underlying the Warrants included in the Units carry “piggyback” registration rights.  The registration rights agreement provides certain deadlines for the filing and effectiveness of the registration statement, including that the registration statement be declared effective by the SEC within 240 days after the final closing of the Offering.  If the Company is unable to comply with this deadline, the Company will be required to pay as partial liquidated damages to the investors a cash sum equal to 1% of any unregistered Registrable Shares for every month in which such registration statement has not been declared effective, up to maximum liquidated damages of 10% of each investor’s aggregate investment amount.

On November 6, 2009, the Company filed a registration statement on Form S-1 with the SEC to cover the resale from time to time by investors holding (i) 4,134,800 shares sold in the 2008 Unit Offering, (ii) 4,905,000 shares sold in the 2009 Mid-Year Unit Offering and (iii) and 2,067,400 shares that may be issued upon exercise of warrants issued to the investors in the 2008 Unit Offering.  On February 23, 2010, the Company filed an amended Form S-1 with the SEC to cover the resale of the same securities. The registration statement has not yet been declared effective by the SEC.

Common Stock issued to extinguish debt

On February 8, 2008, the Corporation issued a $50,000 promissory note to Milestone Enhanced Fund Ltd. (“Milestone”) in exchange for Milestone’s $50,000 working capital loan to the Company. The note was due within one year of its date of issuance and carried a 9% annual interest rate. On February 25, 2008, the Company issued 100,444 shares of Common Stock in exchange for full payment of the note and accrued interest. This transaction was valued by the Company’s Board of Directors at the fair value of the Common Stock issued, or 100,000 shares at $.50/share for the principal and 444 shares at $.50/share for the accrued interest which amounted to $222.

Common Stock cancelled

On February 26, 2008, 9,000,000 shares of LCE Common Stock owned by the founding stockholder were surrendered to LCE and cancelled.

F-20

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

On August 21, 2008, 2,250,000 shares of LCE common stock owned by the founding director, were surrendered in exchange for her interest in a split-off subsidiary of LCE, as more fully described in a Form 8-K of the same date filed by the Company with the SEC.  The net assets of the Split-Off Subsidiary were $Nil as of August 21, 2008.  Therefore, this transaction was valued at $Nil.

2008 Equity Incentive Plan

The Company’s 2008 Equity Incentive Plan (the “2008 Plan”) provides for the grant of incentive stock options to employees of the Company and non-statutory stock options, restricted stock and stock appreciation rights to employees, directors and consultants of the Company and of an affiliate or subsidiary of the Company. A maximum of 4,000,000 shares of common stock are available for issuance under the 2008 Plan. The 2008 Plan, originally adopted and approved by the Company’s Board of Directors and majority stockholders on February 7, 2008 to enable grants to issue up to 2,000,000 shares of our Common Stock, was amended and restated by approval of the Company’s Board of Directors on November 7, 2008 to, among other things, increase the number of shares that may be issued under the 2008 Plan to 4,000,000.  On October 12, 2009, the Company’s stockholders approved the increase in reserved shares under the 2008 Plan from 2,000,000 to 4,000,000.  As of December 31, 2009, options had been granted under the 2008 Plan exercisable for an aggregate of 2,451,667 shares of common stock.

The Company determines the fair value of stock option awards granted to employees in accordance with FASB ASC Topic No. 718 – 10 (formerly SFAS No. 123(R), Share-Based Payment) and to non-employees in accordance with FASB ASC Topic No. 505 – 50 (formerly EITF 96-18 “Accounting for Equity Instruments Issued to Non-Employees for Acquiring, or in Conjunction with Selling, Goods or Services”).

Stock Option Awards

On July 1, 2008, the Company granted options to purchase (i) 1,000,000 shares of its Common Stock to the Company’s President and Chief Executive Officer, (ii) 175,000 shares of its Common Stock to the Company’s Chairman and Vice President, (iii) 100,000 shares of its Common Stock to a newly appointed director, and (iv) an additional 175,000 shares of its Common Stock to three employees of its Colombian subsidiary. The options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term. They were granted with an exercise price equal to $2.20.

On July 23, 2008, the Company granted options to purchase (i) 100,000 shares of its Common Stock to each of two newly appointed directors. These were granted with an exercise price equal to $2.47.  An additional 75,000 options to purchase shares of its Common Stock was granted on August 1, 2008 to one employee of its Colombian subsidiary, with an exercise price equal to $2.57. The options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term.

Also on July 23, 2008, the Company granted options to purchase 150,000 shares to a consultant to the Company at an exercise price equal to $2.47.  These options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term. The Company recognized compensation expense of $47,390 for the year ended December 31, 2009. The fair value of the unvested shares was $52,239 as of December 31, 2009.

On November 7, 2008, the Company granted options to purchase (i) 100,000 shares of its common stock to a newly appointed director, and (ii) 50,000 shares to one employee.  The options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term. They were granted with an exercise price equal to $1.71.  The 50,000 options granted to the employee were forfeited during the three months ended March 31, 2009.

On January 7, 2009, the Company granted options to purchase 200,000 shares of its common stock to the Company’s new Production and Operations Manager.  The options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term. They were granted with an exercise price equal to $1.50.

On May 1, 2009, the Company granted options to purchase 50,000 shares of its Common Stock to its geologist. These options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term. They were granted with an exercise price equal to $1.59.

F-21

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

On June 16, 2009, the Company granted options to purchase 160,000 shares of its Common Stock to a consultant to the Company. These were granted with an exercise price equal to $2.00 per share, with one-third of the options vesting on grant date and the remaining options to vest pro-rata over a period of twelve months. The Company recognized compensation expense of $92,237 for the year ended December 31, 2009. The fair value of the unvested shares is $22,074 as of December 31, 2009.

On July 1, 2009, the Company granted options to purchase 100,000 shares of its Common Stock to its exploration manager. These options vest pro-rata in three annual installments beginning on the first anniversary of the date of grant and have a 10 year term. They were granted with an exercise price equal to $1.65.

Stock option activity summary covering options granted to the Company’s employees is presented in the table below:

	Number of Shares			Weighted- average Exercise Price		Weighted- average Remaining Contractual Term (years)		Aggregate Intrinsic Value
Outstanding at December 31, 2007		—			—
Granted		1,875,000		$	2.20
Exercised		—			—
Forfeited		—			—
Expired		—			—
Outstanding at December 31, 2008		1,875,000		$	2.20		8.79	$	—
Granted		350,000		$	1.56
Exercised		—			—
Forfeited		(83,333	)	$	1.91
Expired		—			—
Outstanding at December 31, 2009		2,141,667		$	2.11		8.64	$	—

Of the above employee options outstanding at December 31, 2009, 608,339 options are vested or exercisable.   During the year ended December 31, 2009, the Company recognized stock-based compensation expense of $682,783 related to stock options, including $543,156 related to options granted to employees.  As of December 31, 2009, there was approximately $969,558 of total unrecognized compensation cost related to non-vested stock options ($895,245 of which is related to employee options), which is expected to be recognized over a weighted-average period of approximately 1.64 years and 2.02 years for employee and non-employee options, respectively.

The fair value of the options granted during 2008 and 2009 was estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions:

Estimated market value of stock on grant date (1)	$	0.86 - $1.37
Risk-free interest rate (2)		2.02 – 3.77	%
Dividend yield  (3)		0.00	%
Volatility factor  (4)		83.63% - 90.00	%
Expected life (5)	6.5 years
Expected forfeiture rate (6)		10	%

(1) The estimated market value of the stock on the date of grant was based on a calculation by management after consideration of price per share received in the private offerings and reported public market prices.

(2) The risk-free interest rate was determined by management using the U.S. Treasury zero-coupon yield over the contractual term of the option on date of grant.

(3) Management determined the dividend yield to be 0% based upon its expectation that there will not be earnings available to pay dividends in the near term.

F-22

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

(4) The volatility factor was estimated by management using the historical volatilities of comparable companies in the same industry and region, because the Company does not have adequate trading history to determine its historical volatility.

(5) The expected life was estimated by management as the midpoint between the vesting date and the expiration date of the options.

(6) Management estimated that the forfeiture rate at 10% based on its experience with companies in similar industries and regions.

Warrants for Services

During the year ended December 31, 2009, as compensation for services received, the Company issued warrants to a third party to purchase 5,000 shares of common stock at an exercise price of approximately $1.49.  The warrants are exercisable at any time starting from the date of issuance and have a five year term.  During the year ended December 31, 2009, the Company recognized stock-based compensation expense of $5,692 related to these warrants based on the Black-Scholes option pricing model.

(7) Derivative Warrant Instruments (Liabilities)

In the 2008 Unit Offering and 2009 Unit Offerings, the Company incurred liabilities for the estimated fair value of derivative warrant instruments in the form of warrants (see Note 1).  The estimated fair value of the derivative warrant instruments was calculated using the lattice model as of December 31, 2009. Such estimates were revalued at each balance sheet date, with changes in value recorded as unrealized gains or losses in non-operating income (expense).

During the year ended December 31, 2009, a $83,997 decrease in the fair value of the derivative liabilities was recorded as unrealized gain on fair value of derivative warrant instruments in the accompanying consolidated statement of operations.

Activity for derivative warrant instruments during the year ended December 31, 2009 was as follows:

	December 31, 2008		Cumulative Effect of Change in Accounting Principle		Activity during the year		Increase (Decrease) in Fair Value of Derivative Liability			December 31, 2009
Derivative warrant instruments	$	—	$	2,304,561	$	5,279,574	$	(83,997	)	$	7,500,138
	$	—	$	2,304,561	$	5,279,574	$	(83,997	)	$	7,500,138

The fair value of the derivative warrant instruments is estimated using the lattice valuation model with the following assumptions as of December 31, 2009:

Common stock issuable upon exercise of warrants		8,642,186
Estimated market value of common stock on measurement date (1)	$	1.43
Exercise price	$	1.25 - $3.00
Risk free interest rate (2)		1.70% - 2.93	%
Warrant lives in years		3.00 – 4.58
Expected volatility (3)		72	%
Expected dividend yields (4)	None

F-23

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

(1) The estimated market value of the stock is measured each period end and is based on a calculation by management after consideration of price per share received in private offerings and reported public market prices and adjusted for the effect of previously issued warrants.

(2) The risk-free interest rate was determined by management using the U.S. Treasury zero-coupon yield over the contractual term of the warrant on date of grant.

(3) The volatility factor was estimated by management using the historical volatilities of comparable companies in the same industry and region, because the Company does not have adequate trading history to determine its historical volatility.

(4) Management determined the dividend yield to be 0% based upon its expectation that there will not be earnings available to pay dividends in the near term.

(8) Fair Value Measurements

As defined in FASB ASC Topic No. 820 – 10 (formerly SFAS 157), fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. FASB ASC Topic No. 820 – 10 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. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. 

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. This category includes those derivative instruments that La Cortez values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instruments, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). La Cortez’s valuation models are primarily industry standard models.  Level 3 instruments include derivative warrant instruments.  La Cortez does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 1 or Level 2.

As required by FASB ASC Topic No. 820 – 10 (formerly SFAS 157), financial assets and liabilities are classified 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 estimated fair value of the derivative warrant instruments was calculated using the lattice valuation model (see Note 7).

Fair Value on a Recurring Basis

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009:

F-24

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

	Fair Value Measurements at December 31, 2009
	Quoted Prices
	In Active		Significant				Total
	Markets for		Other		Significant		Carrying
	Identical		Observable		Unobservable		Value as of
	Assets		Inputs		Inputs		December
Description	(Level 1)		(Level 2)		(Level 3)			31, 2009
Derivative warrant instruments	$	-	$	-	$	7,500,138	$	7,500,138
Total	$	-	$	-	$	7,500,138	$	7,500,138

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy:

	Significant Unobservable Inputs (Level 3)
	Year Ended
	December 31,
	2009			2008
Beginning balance	$	-		$	-
Total gains (losses)		(83,997	)		-
Settlements		-			-
Additions		5,279,574			-
Transfers (1)		2,304,561			-
Ending balance	$	7,500,138		$	-
Change in unrealized gains (losses)
included in earnings relating to derivatives
still held as of December 31, 2009 and 2008	$	83,997		$	-

(1) Represents the $2,304,561 cumulative effect change in accounting principle as a result of the Company adopting FASB ASC Topic No. 815 – 40 (formerly EITF 07-5) effective January 1, 2009.

F-25

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

(9) Income Taxes

La Cortez Energy, Inc. files a U.S. Federal income tax return.  The Company’s foreign subsidiaries file income tax returns in their respective jurisdictions. The components of the consolidated net loss before income tax benefit are as follows:

	2009		2008
U.S.	$	3,011,995	$	1,909,043
Non-U.S.		7,130,391		671,486
Net Loss	$	10,142,386	$	2,580,529

The components of the Company’s deferred tax assets at December 31, 2009 and 2008 are as follows:

	2009			2008
Deferred tax assets and liabilities:
Loss carry-forwards	$	1,441,000		$	426,000
Oil properties		2,347,000			-
Property and equipment		(18,000	)		(5,000	)
Accounts receivable		(66,000	)		-
Stock-based compensation		241,000			83,000
Net deferred tax asset		3,945,000			504,000
Valuation allowance		(3,945,000	)		(504,000	)
	$	-		$	-

Income tax benefit differs from the amount computed at the federal statutory rates (approximately 34%) as follows:

	2009				2008
Income tax benefit at statutory rate	$	(3,550,000	)	��	$	(877,000	)
Stock issued to consultant		-				337,000
Other permanent differences		109,000				31,000
Increase in valuation allowance		3,441,000				494,000
Other		-				15,000
	$	-			$	-

As of December 31, 2009, the Company had generated U.S. net operating loss carry-forwards of approximately $755,000, which expire from 2027 to 2029 and net loss carry-forwards in certain non-U.S. jurisdictions of approximately $3,364,000, which do not expire.   As of December 31, 2008, the Company had generated U.S. net operating loss carry-forwards of approximately $555,000, which expire from 2027 to 2028 and net loss carry-forwards in certain non-U.S. jurisdictions of approximately $671,486, which do not expire. These net operating loss carry-forwards are available to reduce future taxable income. However, a, change in ownership, as defined by federal income tax regulations, could significantly limit the Company’s ability to utilize its U.S. net operating loss carry-forwards. Additionally, because federal tax laws limit the time during which the net operating loss carry-forwards may be applied against future taxes, if the Company fails to generate taxable income prior to the expiration dates it may not be able to fully utilize the net operating loss carry-forwards to reduce future income taxes. As the Company has had cumulative losses and there is no assurance of future taxable income, valuation allowances have been recorded to fully offset the deferred tax asset at December 31, 2009 and 2008. The valuation allowance increased $3,507,000 and $494,000 due primarily to the Company’s 2009 and 2008 net losses, respectively.

(10) Commitments and Contingencies

From time to time the Company is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes, if determined in a manner adverse to La Cortez, could have a potential material adverse effect on its financial condition, results of operations or cash flows.

Additionally, La Cortez is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of La Cortez could be adversely affected.

Leases

The Company has signed a three year lease for approximately 3,000 square feet of office space in Bogotá, Colombia. The rent for this office space is approximately $8,100 per month during the first year. The rental contract provides for a 2% increase per year in the base rent and an additional adjustment for inflation in Colombia as reflected in the Colombian consumer price index, or the “Indice de Precios al Consumidor” (the “IPC”). This lease will expire on July 2, 2011. 

For the years ended December 31 2009 and 2008, the Company paid rent of approximately $103,936 and $42,714, respectively.

F-26

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

Based on an estimated exchange rate of COP 2,250 per US dollar for each year (2010 and 2011), annual lease payment commitments for the remainder of the lease have been calculated as follows:

Year	Total Lease Payment Amount
2010	$	104,000
2011	$	63,000

These US dollar amounts for the remainder of the office lease could increase if the US dollar to COP exchange rate deteriorates in favor of the COP.

Employment Agreement

The Company has entered into an employment agreement effective as of June 1, 2008 (the “Employment Agreement”) with Andres Gutierrez pursuant to which Mr. Gutierrez was appointed as its President and Chief Executive Officer, Pursuant to the Employment Agreement, Mr. Gutierrez’s base annual compensation has been set at U.S. $250,000, which amount may be increased annually at the discretion of the Board of Directors. This annual compensation is paid in Colombian Pesos, which may result in foreign exchange rate fluctuations. The Company expects that such exchange rate fluctuations to be immaterial.

In addition, Mr. Gutierrez is eligible to receive an annual cash bonus of up to fifty percent (50%) of his applicable base salary. Mr. Gutierrez’s annual bonus (if any) shall be in such amount (up to the limit stated above) as the Board of Directors may determine in its sole discretion, based upon Mr. Gutierrez’s achievement of certain performance milestones to be established annually by the Board of Directors in discussion with Mr. Gutierrez (the “Milestones”).

Under the Employment Agreement, the Company agreed to grant Mr. Gutierrez an option to purchase an aggregate of 1,000,000 shares of our common stock under our 2008 Equity Incentive Plan (the “2008 Plan”) as of June 1, 2008. The option was granted on July 1, 2008. This option vests in three equal annual installments beginning on July 1, 2009 and is exercisable at $2.20 per share.

The initial term of the Employment Agreement expired on June 1, 2009, and was automatically extended by one year, until May 31, 2010. In the event of a termination of employment “without cause” by the Company during the first 12 months following June 1, 2008, Mr. Gutierrez shall receive: (i) twelve (12) months of his base salary; plus (ii) to the extent the Milestones are achieved or, in the absence of Milestones, the Board of Directors has, in its sole discretion, otherwise determined an amount for Mr. Gutierrez’s bonus for the initial 12 months of his employment, a pro rata portion of his annual bonus for the initial 12 months of his employment, to be paid to him on the date such annual bonus would have been payable to him had he remained employed by the Company; plus (iii) any other accrued compensation and Benefits, as defined in the Employment Agreement. In the event of a termination of employment by Mr. Gutierrez for “good reason”, as defined in the Employment Agreement, Mr. Gutierrez shall receive: (i) twelve (12) months of his then in effect base salary, subject to his compliance with the non-competition, non-solicitation and confidentiality provisions of the Employment Agreement.  As of December 31, 2009, the Company has accrued a bonus payable to Mr. Gutierrez in the amount of $197,917 representing nineteen months bonus accrual.

(11) Subsequent Events

On January 29, 2010 and March 2, 2010, the Company completed a second closing (“Second Closing”) and third closing (“Third Closing”), respectively, of the December 2009 Unit Offering.  At the Second Closing, the Company closed on the sale of 571,428 Units and received aggregate gross proceeds of $999,999 from the sale of these Units.  At the Third Closing, the Company closed on the sale of 857,144 Units and received aggregate gross proceeds of $1,500,000 from the sale of these Units.Each of these Units consisted of (i) one share of our common stock and (ii) a common stock purchase warrant to purchase one-half (1/2) of one share of our common stock, exercisable for a period of three years at an exercise price of $3.00 per share.

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LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

On March 2, 2010 (the “Closing Date”), the Company entered into a Stock Purchase Agreement (the “SPA”) with Avante Petroleum S.A., a Luxembourg public limited liability company (“Avante”), which closed on the same date.  Pursuant to the terms of the SPA, the Company acquired all of the outstanding capital stock (the “Acquisition”) of Avante’s wholly owned subsidiary, Avante Colombia S.à r.l., a Luxembourg private limited liability company (“Avante Colombia”), in exchange for 10,285,819 newly issued shares of the Company’s common stock (the “Purchase Price Shares”).

In connection with the Acquisition, on the Closing Date, the Company and Avante entered into a Subscription Agreement (the “Avante Subscription Agreement”), pursuant to which Avante purchased 2,857,143 shares of the Company’s common stock (the “Avante Shares”) and three-year warrants to purchase 2,857,143 shares of the Company’s common stock at an exercise price of $3.00 per share (the “Avante Warrants”), for an aggregate purchase price of $5,000,000 (or $1.75 per share of common stock purchased). This acquisition will be accounted for as a purchase. Due to the timing of the acquisition closing, the Company has not yet completed the analysis of the fair value of the properties acquired as of the date of close. Therefore, the final purchase price to be applied to the acquisition has not yet been determined.

(12) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

Costs incurred by La Cortez in oil and natural gas property acquisition, exploration and development for the year ended December 31, 2009 are presented below:

	Amount
Development costs	$	-
Exploration costs		9,109,304
Total acquisition, development and exploration costs	$	9,109,304

Unevaluated properties consist of seismic and other exploration costs. They are expected to be subject to depletion and ceiling test impairment once they are evaluated within the next twelve months.

(13) Net Proved Oil and Natural Gas Reserves (Unaudited)

The proved oil and natural gas reserves of La Cortez have been estimated by an independent petroleum engineer, Ryder Scott Company (“Ryder Scott”), as of December 31, 2009. La Cortez held no proved reserves prior to 2009.  These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules and accounting standards based on the 12-month un-weighted first-day-of-the-month average price for December 31, 2009. The estimate of the Company’s proved reserves as of December 31, 2009 has been prepared and presented under new SEC rules and accounting standards. These new rules and standards are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month un-weighted first-day-of-the-month average pricing.  All of the Company’s reserves are located in Colombia.

An analysis of the change in estimated quantities of oil and natural gas reserves is shown below:

	Oil
	(Bbls)
Total Proved Reserves:
Balance, December 31, 2008		-
Discoveries		77,193
Production		(2,963	)
Balance, December 31, 2009		74,230
Proved Developed Reserves:
December 31, 2008		-
December 31, 2009		74,230
Proved Undeveloped Reserves:
December 31, 2008		-

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LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2009 and 2008

(14) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)

Summarized in the following table is information for La Cortez with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying the 12-month un-weighted first-day-of-the-month average price for the year ended December 31, 2009 as a result of the adoption of ASU 2010-03 effective on December 31, 2009. Future production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Federal income taxes have not been deducted from future production revenues in the calculation of standardized measure as the carryforward of prior year net operating losses and future depletion are expected to result in no taxable income over the life of the properties.

	Amount
Future production revenues	$	4,133,131
Future costs:
Production		(1,634,044	)
Development		(382,320	)
Income taxes		-
Future net cash flows after income taxes		2,116,767
10% annual discount for estimated timing of cash flows		(1,310,312	)
Standardized measure of discounted net cash flows	$	806,455

The standardized measure is based on an oil price of $55.68 per barrel realized over the life of the properties at the wellhead as of December 31, 2009.

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:

	Amount
Increase (decrease):
Extensions and discoveries, net of future production and
development costs	$	996,290
Production		(189,835	))
Net increase		806,455
Standardized measure of discounted future net cash flows:
Beginning of year		-
End of year	$	806,455

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.

F-29

GLOSSARY OF OIL AND GAS TERMS

The following are the meanings of some of the oil and gas industry terms that may be used in this report.  

2D seismic data: Two-dimensional seismic data; geophysical data that depicts the subsurface strata in two dimensions; a vertical section of seismic data consisting of numerous adjacent traces acquired individually and sequentially.

3D seismic data:  Three-dimensional seismic data; geophysical data that depicts the subsurface strata in three dimensions; a vertical section of seismic data consisting of multiple closely spaced adjacent traces acquired together.

ANH:  National Hydrocarbon Agency of Colombia (Agencia Nacional de Hidrocarburos)

API gravity scale:  A gravity scale devised by the American Petroleum Institute.

association contract:  Prior to 2003, the type of contract in association with Ecopetrol in Colombia, regulating the exploration, production and development of hydrocarbons. Association contracts give Ecopetrol the right to back-in into any block. After 2003 with the creation of the ANH, Colombia adopted an international E&P contract.

basin:A depression of the earth’s surface into which sediments are deposited, usually characterized by sediment accumulation over a long interval; a broad area of the earth beneath which layers of rock are inclined, usually from the sides toward the center.

block:  Subdivision of an area for the purpose of licensing to a company or companies for exploration/production rights.

BOPD:  Abbreviation for barrels of oil per day, a common unit of measurement for volume of crude oil. The volume of a barrel is equivalent to 42 US gallons.

completion:  The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

concession: Usually used in foreign operations and refers to a large block of acreage granted to the operator by the host government for a certain time and under certain government conditions which allows the operator to conduct exploratory and/or development operations. The Concession Agreement assures the holder of certain rights under the law.

crude oil: A general term for unrefined petroleum or liquid petroleum.

dry hole:  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

E&P:  Exploration and production.

Ecopetrol:The Colombian state-controlled oil company.

exploration:  The initial phase in petroleum operations that includes generation of a prospect or play or both, and drilling of an exploration well.  Appraisal, development and production phases follow successful exploration.

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exploratory well:  A well drilled to find and produce oil and gas reserves that is not a development well.

field:  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

formation:  An identifiable layer of rocks named after the geographical location of its first discovery and dominant rock type.

hydrocarbon:  A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane [CH4], but many are highly complex molecules, and can occur as gases, liquids or solids. The molecules can have the shape of chains, branching chains, rings or other structures. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.

lead:A possible prospect.

operator:  The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or lease.

participation interest:  The proportion of exploration and production costs each party will bear and the proportion of production each party will receive, as set out in an operating agreement.

play:  An area in which hydrocarbon accumulations or prospects of a given type occur.

production:  The phase that occurs after successful exploration and development and during which hydrocarbons are drained from an oil or gas field.

prospect:  A specific geographic area, which based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

reservoir:A subsurface, porous, permeable rock formation in which oil and gas are found.

royalty:  A percentage share of production, or the value derived from production, paid, in cash or kind, from a producing well.

seismic:  Pertaining to waves of elastic energy, such as that transmitted by P-waves and S-waves, in the frequency range of approximately 1 to 100 Hz. Seismic energy is studied by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface.

spud, to:  To commence drilling operations.

sunk costs:  Costs that cannot be recovered once they have been incurred.

water cut: The term used in production testing to specify the ratio of water produced compared to the volume of total liquids (water and oil) produced.

West Texas Intermediate (“WTI”):  Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading.  WTI is deliverable at Cushing, Oklahoma, to fill NYMEX futures contracts for light, sweet crude oil.

G-2

working interest:  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

workover: Remedial work to the equipment within a well, the well pipework, or relating to attempts to increase the rate of flow.

X factor: The payment to the ANH of a percentage of net production revenues over and above the standard royalties.

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