DevMar Equities 10K 2011 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, 2011

¨	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		(IRS Employer Identification No.)
incorporation or organization)

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 x 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. ¨

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, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, 30,763,718 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 $14,151,310, based on the last sale price of $0.46 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 10, 2012, there were46,467,849shares 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	16
1B.	Unresolved Staff Comments	31
2.	Properties	31
3.	Legal Proceedings	48
4.	Mine Safety Disclosures	48

PART II		49

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	49
6.	Selected Financial Data	50
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
8.	Financial Statements and Supplemental Data	61
9.	Changes in and Disagreements with Accountants on Accounting, and Financial Disclosure	61
9A.	Controls and Procedures	61

PART III		62

10.	Directors, Executive Officers, and Corporate Governance	62
11.	Executive Compensation	68
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	74
13.	Certain Relationships and Related Transactions and Director Independence	76
14.	Principal Accountant Fees and Services	77

PART IV		78

15.	Exhibits and Financial Statement Schedules	78

Financial Statements		F-1

Glossary of Oil and Gas Terms		G-1

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K, particularly in Item 1, “Business”, and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the Securities Act) and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). All statements other than statements of historical facts included in this Annual Report on Form 10-K including without limitation statements in the Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct and because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, those set out in Part I, Item 1A “Risk Factors” in this Annual Report on Form 10-K. The information included herein is given as of the filing date of this Form 10-K with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Annual Report on Form 10-K to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any such statement is based.

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 our corporate headquarters in Bogota, Colombia, and have entered into two working interest agreements, with Petroleos del Norte S.A. (“Petronorte”), a subsidiary of PetroLatina Energy Limited (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”).

Our plan was to build an oil and gas exploration and production company focused in select countries in South America. We concentrated our efforts in Colombia, where we believed good E&P opportunities existed with straightforward oil and gas contracting terms and conditions. Within the spectrum of the oil and gas business, we planned to focus on a blend between exploration and production of hydrocarbons through a variety of transactions. Our plan was to concentrate our efforts on lower risk exploration ventures and then seek to acquire oil and gas production fields to start building our reserves base.

In late 2010 and 2011, access to the credit and financial markets by small to mid-cap oil and gas exploration companies deteioratted considerably. As a result, in 2011, we were unable to access either the capital markets or obtain bank financing to obtain additional financing to fund our operations, which are highly capital intensive due to the costs involved in planning, permitting and drilling wells. While all of our rights flow through the working interest agreements described above, failure to pay our obligations under those agreements will result in a loss of all of our rights under those agreements, including our rights to share in any of the future oil or gas discoveries, should there be any. We anticipate, in the near term, that there will be mandatory capital calls made under these working interest agreements.

Due to this lack of availability to the financial and credit markets, and our historical operating losses, unless we raise additional capital by the end of May 2012, the Company will be required to take, and has been in the process of considering, actions to address this liquidity shortfall. Such actions include: deregistering our common stock under the Securities Exchange Act of 1934 to reduce accounting, auditing, legal and other associated public company costs which will have the adverse result in our stockholders being unable to sell their securities in the over-the-counter market; implementing further headcount reductions,which will make it difficult to operate our business; the sale of all or some of our interests in the Putumayo-4 (Petronorte), Maranta (Emerald), Rio de Oro or Puerto Barco projects at prices which may not reflect market value; the sale of the Company; and the sale of our equity or debt securities at discounted prices. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity” and “Risk Factors—Risks Related to Our Business and Financial Condition”.

Sales to Major Customers

The Company, through its 20% interest share in the agreement with Emerald, sold oil representing 10% or more of total revenues for the years ended December 31, 2011 and 2010 to the customers shown below:

	December 31,			December 31,
	2011			2010
HOCOL S.A.		69	%		50	%
Petrobras International Braspetro BV		19	%		27	%
Comercializadora International Exportecnicas Ltda.		4	%		14	%

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.

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 exploration and production (“E&P”) companies, every major market has been affected by the recent global recession and volatility over the past three years. 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. The lower price threshold made many previously economically viable opportunities less feasible. More recently, civil unrest and armed conflict in North Africa and the Middle East, relations between the international community and Iran and threats to the oil supply from the Persian Gulf,as well as economic fears regarding some of the European countries have driven oil pricesinto the range of $80 to $110 that prevailed through most of 2011and 2012 to date. 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.

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

* Source: U.S. Energy Information Administration

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

* Source: U.S. Energy Information Administration

Inflation-Indexed Monthly Average U.S. Imported Crude Oil Price, January 1974 – January 2012

* Source: U.S. Energy information Administration

The availability of financing alternatives in the equity and debt capital markets, the most common financing vehicles for microcap international E&P companies like ours, has virtually disappearedduring the second half of 2011. The price decline experienced by most, if not all publicly traded microcap/small Colombian E&P companies was on average 42% over last 12 months (April 2011 to March 2012). Financing is now more accessible to companies that have a great base of proven reserves, steady production with some exploration risk, rather than to companies with a high exploration risk, modest production and proven reserves. 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.

Business Plan and Strategic Outlook

Our initial plan was to build a successful oil and gas exploration and production company focused in select countries in South America. We concentrated our efforts in Colombia, where we believed good E&P opportunities existed with straightforward oil and gas contracting terms and conditions. Within the spectrum of the oil and gas business, we planned to focus on a blend between exploration and production of hydrocarbons through a variety of transactions. Our initial planwas to concentrate our efforts on lower risk explorationventures and later on to seek to acquire oil and gas production fields to start building our reserves base.

An integral part of our strategy has been to focus on building a competent and professional management and operations team that will enable us to successfully carry out our business plan. We have hired experienced personnel including technical specialists (e.g., geologists, geophysicists and petroleum 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 has been hired locally and resides in the region, which is consistent with our business plan and provides a significant competitive advantage in the region.

We motivated 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 concentrated our efforts in Colombia and we look at Peru as a potential 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. Ourrecent efforts have been concentrated in developing our current asset base as well as looking in obtaining financial support to grow via corporate transactions. We plan to adhere to this strategy, but reserve the option to be flexible if the right opportunity presents itself.

Execution of our Strategy to Date

In February 2008, Nadine C. Smith was appointed Chairman of our Board of Directors (sometimes referred to hereinafter as the “Board”). Ms. Smith was also appointed 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.

On June 1, 2008, Andrés Gutierrez Rivera became our President and Chief Executive Officer and a member of our Board of Directors. Mr. Gutierrez previously 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.

In December 2009, January 2010, March 2010 and April 2010, we closed on a private placement offering of units. Each unit was sold at a price of $1.75 and consisted of (i) one share of our common stock, and (ii) a warrant representing the right to purchase one-half (1/2) of one share of our common stock, for a period of three years at an exercise price of $3.00 per whole share. On December 29, 2009, we closed on the sale of 1,428,571 Private Placing Offering (“PPO”) Units (as defined below) in a private placement offering for gross proceeds of $2.5 million; on January 29, 2010, we closed on the sale of 571,428 PPO Units in our PPO, for gross proceeds of $1.0 million; and on March 2, 2010, we closed on the sale of 857,144 in our PPO, for gross proceeds of $1.5 million. On April 19, 2010, we conducted the fourth and final closing of our PPO for an additional 5,905,121 PPO Units, for gross proceeds of $10.33 million. In the aggregate, in all four closings of the PPO, we sold 8,762,264 PPO Units, consisting of an aggregate of 8,762,264 shares of our common stock and warrants to purchase an aggregate of 4,381,138 shares of our common stock, for total gross proceeds of $15.33 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.

(The foregoing discussion does not include warrants issued to brokers and finders as compensation in connection with certain of the offerings.)

The funds raised in the private unit offerings (net of offering expenses) have been used to build our administrative and operations infrastructure and to invest in initial oil and gas development projects in Colombia. In addition, we have taken the following steps to ramp-up growth and development:

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, organized, and staffed our corporate headquarters in Bogotá, Colombia;

Redomiciliated Avante Colombia S.a.r.l from Luxembourg to Cayman Islands and changed its name to Avante Colombia, Inc.;

Hired an Exploration Manager, Carlos Lombo, 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;

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 been diligently working to identify, evaluate and finalize our participation in other potential oil and gas investment opportunities in Colombia.

Putumayo 4 Block

The Putumayo 4 Block is an exploration block with no revenues or proven reserves at present. 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 the Agencia 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 have completed identification of the number of indigenous people and communities in the area, along with representatives from the Ministry of the Interior. A total of seven communities were identified, and the consultation process with these communities has been initiated.An agreement has been reached with four communities. In the southern area, the consultation process is ongoing with two communities. Based on reprocessed seismic information, the layout for the new seismic acquisition has also been completed, resulting in a 2D seismic acquisition plan of some 105 km in the north part of the block, where at least two leads have been determined with the reprocessed seismic. During 2010, we reprocessed approximately 1,000 km of 2D seismic covering the Putumayo-4 Block. During 2012, we plan to conduct two seismic acquisition campaigns. We plan to initiate shooting of the first 105 km of the 2D seismic campaign in April 2012, and the second 2D seismic acquisition of approximately 50 km in May 2012, upon completion of the preconsultation process with the remaining local communities for this acquisition. The preconsultation process was suspended for a period of seven months from December 2010 to July 2011 because no representative from the Colombian Ministry of Interior was available.

Results from the seismic acquisition will permit us to finalize the drill location for the first exploration well. Subject to completion of permitting and civil works at the drill-site, we, together with Petronorte, anticipate spudding the first Putumayo-4 exploration well early in 2013. We and Petronorte are also continuing to work and consult with the local communities to enable us to spud the first exploration well early in 2013. In addition, an Environmental Impact Study (Estudio de Impacto Ambiental - EIA) is ongoing and, when completed, will be presented to the relevant authorities to obtain the necessary exploration well drilling license. We remain optimistic on the potential of this block.

Under the terms of the contract signed with the ANH, we, together with Petronorte, must complete the acquisition of at least 103 km of seismic, the drilling of an exploratory well and additional work for a value of $1.6 million gross before August 25, 2012.We and Petronorte requested from the ANH an extension of the contract for a period of seven months due to problems encountered in the preconsultation process during 2010 and 2011. On February 23, 2012, the ANH approved a seven months and five day extension of the exploration Phase 1. The E&P contract consists 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.” In regards to capital expenditures, we and Petronorte offered to invest $1.6 million in additional seismic work in the Putumayo 4 Block, which we plan to accomplish with the seismic program anticipated during April and May 2012. Then, in regards to the “X Factor” mentioned above, we and Petronorte offered to pay ANH a 1% of net production revenues.

Under the memorandum of understanding and the joint operating agreement with PetroNorte, 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 $4.6million in 2012 for Phase 1 seismic reprocessing, seismic acquisition and permitting activities. The drilling of the referred well was deferred to the first quarter of 2013.

Petronorte filed a request with the ANH for the official assignment of the 50% working interest in the Putumayo-4 block to La Cortez and is obligated to assist La Cortez Energy in obtaining assignment of its working interest from the ANH through reasonable means.The ANHhas recently informed Petronorte that it requires La Cortez to provide an additional financial guarantee. We are evaluating various options to decide whether to provide the additional guarantee or submit a new request later in 2012.In the event that ANH will not approve the assignment, La Cortez will continue to be a private working interest party under the agreement with Petronorte.

Maranta Block

The Maranta Block was our original entry into our oil and gas business, and all revenue and proved oil reserves from inception through December 31, 2011 are associated with this 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. 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, we, together with Emerald, 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 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, we reimbursed Emerald in 2009 $7.28 million of its Phase 1 sunk costs. In 2010, we paid an additional $1.1 million to Emerald, to cover exploration costs associated with the Mirto-1 well, as well as $5.09 million for several projects such as appraisal seismic, drilling of the Mirto-2 well, production facilities and operating costs. In 2011, we paid an additional $1.69 million for activities such as workover of Mirto-1 well and operating costs.

Emerald reached the intended total depth of 11,578 feet on the Mirto-1 exploration well in July 2009, with oil and gas shows recorded across the four target reservoirs. Following the completion of operations in the Mirto-1 well, the drilling rig was released from the location. 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% ($1.2 million) of the $1.8 million Mirto-1 completion costs. We made this $1.2 million payment to Emerald on July 27, 2009. Additional Phase 2 costs were paid by us as needed, following cash calls by Emerald, as follows: $948,044 for seismic on the Mirto-1 well (equivalent to 60% share) and $7,440,354 for drilling cost on the Mirto-1 well (equivalent to 65% share), totaling $8,388,398. With Phase 2 work completed, we will pay 20% of all subsequent costs related to the Maranta Block.

During production testing on Mirto-1, the Villeta N sand interval produced an average oil rate of 247 bopd of 15 degree API oil under artificial lift over a 48 hour period (average water cut of 64%), and the Villeta U sand produced 32 degree API oil at an average rate of 731 bopd (average water cut of 26%) during the same production test. After an unsuccessful workover attempt to isolate the water production, the Mirto-1 well production decreased to an average rate of 60 bopd exclusively from the U sand with water cut close to 90%. Subsequently, the Mirto-1 well was shut in on September 27, 2010, due to mechanical problems, pending evaluation of the technical and operational feasibility to be completed in the Villeta N sand formation.

Emerald, as operator of the Maranta Block, decided to enter the exploration commitment in the Maranta Block, which entailed the drilling of an additional exploratory/appraisal well, Mirto-2. We, together with Emerald, acquired about 25 km of 3D seismic in the area. Emerald completed drilling operations of the Mirto-2 exploratory well on August 15, 2010, after having conducted a sidetrack on the well to a “measured depth” (“MD”) of 11,590 feet. Mirto-2 production tests initiated on September 23, 2010 for a 5-day period on the Villeta U sand had an average production of 29 bopd and water cut of 95.9%. The well was put back on an extended production test from October 16, 2010 until December 10, 2010. During that period, the well produced on average 89.08 bopd gross with an average water cut of 88.4%.

The workover rig on Mirto-2 was used to run cased-hole logs to confirm the appropriate perforation positions. This activity was completed on January 2, 2011, and after N Sand production testing was initiated on January 9, 2011, the well has been on production since then with the following results: Average oil production over the testing period (January 9, 2011 to December 31, 2011) was 450 bopd gross (90 bopd net to La Cortez before royalties) with an average Base Sediment and Water (BS&W) of 0.57% over the same period. Cumulative oil gross production from Mirto-2 is 197,010 bbls from the N reservoir as of April 10, 2012.

On August 23, 2011 the Mirto-1 well was put back in production from the Villeta N sand formation. The well has been on production since August 23^rd, 2011 having an ESP (Electric Submersible Pump) failure in early October, which was corrected during the month, in addition to other minor mechanical problems during this year, which were corrected in the same month. The well has showed an average rate of 330 bopd gross (66 bopd net to La Cortez before royalties). The well will continue to be produced under a long term test. The table below summarizes the Mirto Field production and production on a gross basis and net to our interest (after royalties).

Cumulative Production Mirto-1

Formation	Date			Total Fluids (bls)		Oil (bls) Gross		Oil net after royalties (bls)
Test U, T, N		August 9, 2009	September 29, 2009		8,969		4,173		768
Sandstone U		October 1, 2009	September 17, 2010		210,995		41,514		7,639
Sandstone N		August 23, 2011	December 31, 2011		30,769		32,971		6,067
Sandstone N		January 1, 2012	April 10, 2012		23,738		23,063		4,244
TOTAL					274,471		101,721		18,718

Cumulative Production Mirto-2

Formation	Date			Total Fluids (bls)		Oil (bls) Gross		Oil net after royalties (bls)
Sandstone U		September 24, 2010	December 31, 2010		46,221		5,281		972
Sandstone N		January 9, 2011	December 31, 2011		158,775		160,658		29,561
Sandstone N		January 1, 2012	April 10, 2012		36,465		36,352		6,689
TOTAL					241,461		202,291		37,222

Cumulative Production Mirto Field (Mirto-1 and Mirto-2)

Date		Total Fluids (bls)		Oil (bls) Gross		Oil net after royalties (bls)
October 1, 2009	April 10, 2012		515,932		304,012		55,940
TOTAL (bbl)			515,932		304,012		55,940

Emerald, as operator of the Block, has received authorization from the Colombian Ministry of Mines to continue production from the well under a long-term test. This period will be used to conduct well pressure testing and to gather other information that will be used to define the potential of this reservoir and to optimize production rates.

With the drilling of the Mirto-2 well, Phase 3 of the exploration program has been completed. Both Emerald and La Cortez have complied with the exploration obligations on this block in accordance with the contract signed with the ANH. Under the contract terms and conditions, and after completion of this phase, both La Cortez and Emerald are required to relinquish 50% of the area of the block, as selected by both parties, and the option to continue exploration activities in the remaining 50% of the area was exercised by committing to additional exploration activities with the ANH, such as new seismic acquisition or drilling a new exploration well. This is a normal procedure and in accordance with the contracts entered into with the ANH.

Emerald presented to the ANH the area to be relinquished along with the work commitments to be conducted in the remaining area of the Maranta Block during the first additional exploration phase. The work commitment suggested in for Phase 1 is either a new seismic acquisition (120 km of 2D seismic) or the drilling of an exploration well, which have been accepted by the ANH. The Agapanto-1 well was presented to the ANH to comply with activity required under Phase 1. Emerald is expecting an answer from the ANH before May 2012. If the drilling of the Agapanto-1 well is not approved as an activity commitment for the additional exploration phase, the Company and Emerald plan to carry on with seismic acquisition.

Emerald filed a request with the ANH for the assignment of the 20% working interest in the Maranta Block to La Cortez. To qualify as a contractor with ANH, we have submitted legal, operating, technical and financial information to be reviewed by ANH. Because the financial information required audited financial statements for the last three years, the ANH granted La Cortez until April 15, 2011 to present the 2010 audited financial statements along with other financial information required. Accordingly, we submitted the audited financial statements and the ANH initiated the review process for the assignment to La Cortez of the 20% participation interest in the contract. However, the ANH denied the assignment of the 20% to La Cortez Energy because our financial indicators did not comply with the minimum requirements set out by the ANH, mainly arising from the classification of derivative warrants instruments as a current liability in the Company’s balance sheet under US GAAP (Generally Accepted Accounting Principles) rules. The Company will ask Emerald to present an application for assignment to the ANH once our financial condition meets the ANH criteria. In the meantime, La Cortez will continue to be a private interest holder under agreement with Emerald.

The activity plan for 2012 includes the drilling of the Agapanto 1 well, which is located 1.7 km south of Mirto-1 and Mirto-2, the construction of permanent production facilities, the potential acquisition of additional seismic and a workover on the Umbria-1 well, which is contingent on obtaining the required permits. The Umbria-1 well was drilled in the Maranta Block in 1967 and encountered oil in the Villeta formation. The drilling of the Agapanto-1 well or the acquisition of additional seismic must be executed before the end of the additional phase 1 exploration (by the end of August of 2012). The activity budget for 2012 in this block is $4.97 million, excluding the contingent items such as the seismic and the Umbria workover.

Both Emerald and La Cortez believe that based on the testing results from the Mirto-2 well, and despite the mechanical problems encountered in the Mirto-1 well, there could be sufficient accumulation of hydrocarbons in the area to merit the proposed work commitments.

On March 22, 2012, Emerald submitted to the ANH the report of the evaluation program and declaration of commerciality of the Mirto field. ANH approval is currently pending.

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. The Rio de Oro and Puerto Barco fields are production projects, the costs of which are currently classified as unproved properties. As consideration for the acquisition, we issued an aggregate of 10,285,819 shares of our common stock to the Avante shareholders.

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 prolific 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 in production, Vetra a 47% participation in 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 our acquisition will be the responsibility of the previous operators. In addition to the contractual responsibility of the previous operators for these liabilities, Avante has agreed in the stock purchase agreement (“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 SPA, 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%.

Our plans with respect to Avante Colombia’s business depend, among other things, on obtaining an extension of the term of the existing contracts between Avante Colombia and Ecopetrol, which expires in December 2013. We believe that, to negotiate a term extension, we will have to commit to additional investment in the area. We are actively engaged with Ecopetrol regarding these issues, but 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.

Avante Colombia, as operator of the Rio de Oro and Puerto Barco Fields, has completed the technical evaluation of these fields, which is encouraging as to future upside potential. Avante Colombia has also completed the program to re-initiate the Puerto Barco field in conjunction with our joint venture partner Vetra. We have met with representatives from the local communities and with several local and regional government officials, who we believe are supportive of the initiatives to reinitiate operations in the fields.

Avante Colombia has performed a detailed evaluation of the current road conditions, which will allow the Company to determine cost and timing for the necessary road improvements. Our technical evaluation has identified several attractive workover opportunities, andas previously anticipated, the 2011 activity was concentrated on the re-establishment of production in the Puerto Barcofield’s PB-2 well. Activities were carried out at the end of 2011 in this field, and the Company conducted a field evaluation and test of a well. The well test resulted in oil produced at natural flow with 43.3degrees API gravity oil. No further tests were conducted due to lack of production facilities at the site. Despiteoperating conditions in the area remaining challenging due to weather, security and infrastructure constraints, we estimatethat if an agreement is reached with Ecopetrol by May 2012,initiation of future activitycoild start in the second half of this year.The Company continues to work with the communities in the area, and we believe we have developed an excellent relation with the local communities and their leaders.

We have been in discussions with Ecopetrol with regard to contract terms and conditions modifications, and we presented to Ecopetrol a proposal to commit to new investment in the area, which is being evaluated at this time.We expect a definitive resolution on this negotiation during 2012. This plan assumes that the Company will obtain additional funding. If no additional funds are obtained, the Company may be obligated to default on its obligations which may cause the loss of its rights in the agreement.

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.

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 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 million barrels.

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.

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 is 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 14 full time employees, all of whom, including our Chief Executive Officer, Andrés Gutierrez, our Exploration Manager, Mr. Carlos Lombo,and our Operations and Production Manager, Luis Eduardo Goyeneche,are based in our corporate headquarters location in Bogotá, Colombia.Our Chairman, Ms. Nadine Smith, is currently acting as our Interim Chief Financial Officer.

We intend to maintain our 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. Our ability to provide continued employment to such individuals is dependent upon our ability to raise additional funds to support our ongoing operations, and we may be forced to implement headcount reductions if we are unable to do so.

Additionally, we strive 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.

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

Our operations have resulted in negative cash flows, we are seeking to raise additional funds to fund our operating expenses and capital obligations as soon as possible, which could cause us to have to accept terms that are harmful to our business, dilutive to our stockholders or otherwise disadvantageous to our existing stockholders, and if we are unable to secure additional funding, or enter into a sales agreement, we may be required to significantly scale back our operations, seek protection under the provisions of the U.S. Bankruptcy Code, or discontinue many of our activities which could negatively affect our business and prospects.

As of April 10, 2012, we had cash and cash equivalents of $2,289,010. Our current cash resources are not sufficient to fund our operations.

We have agreed to fund an additional $1.32 million for the acquisition of Phase 1 2D seismic on the Putumayo-4 Block by the end of May, 2012. On the Maranta block, we expect the operator to make a cash call on us by May-June, 2012 of $1.71 million for the drilling of the Agapanto-1 well, and $0.70 million for the construction of production facilities.

Over the remainder of 2012, we expect to use, in addition to the above immediate requirements:

approximately $3.29 million to bear our share of commitments with respect to the Putumayo-4 Block, related to Phase 1 seismic acquisition, permitting activities and exploration activities;

approximately $2.56 million for our share of the costs on the Maranta block for drilling the Agapanto-1 well, which is located 1.7 km south of Mirto-1 and Mirto-2, and the community consultation for the acquisition of additional seismic;

approximately $0.30 million for community and social programs in the Catatumbo area; and

up to an additional $4.32 million to cover our administrative expenses and for general working capital to continue to execute our business plan and build our operations, this amount includes a provision for potential strategic transaction costs of $ 0.75 million and approximately $ 0.66 million for tax payments.

Our total cash capital requirements for the remainder of 2012 are anticipated to be approximately $14.2 million. With our cash and cash equivalents on hand, we will require additional capital by the end of May 2012. We currently 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.

If we raise additional funds through the issuance of debt securities, these securities would have rights that are senior to holders of our common stock and could contain covenants that restrict our operations. Any additional equity financing would likely be substantially dilutive to our stockholders, particularly given the prices at which our common stock has been recently trading. In addition, if we raise additional funds through the sale of equity securities, new investors could have rights superior to our existing stockholders. 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. There can be no assurance that we will be successful in obtaining additional funding, in sufficient amounts or on terms acceptable to us, if at all.

If we are unable to raise sufficient additional funds when needed, we would be required to further reduce operating expenses by, among other things, curtailing significantly or delaying or eliminating part or all of our operations and properties, or we may need to seek protection under the provisions of the U.S. Bankruptcy Code.

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.

We may have to sell our assets or enter into a transaction upon terms that are disadvantageous to us and which could negatively affect our business and prospects.

We may seek to raise additional funds through the sale of our interests in the Putumayo-4 (Petronorte), Maranta (Emerald), Rio de Oro or Puerto Barco projects, or a sale of the Company. If we raise funds through a farm-out or sale of any of our rights in Putumayo-4, Maranta, Rio de Oro or Puerto Barco projects, we may be required to relinquish, on terms that are not favorable to us, our interests in those projects. Our need to raise capital soon may require us to accept terms that may harm our business or be disadvantageous to our current stockholders, particularly in light of the current illiquidity. There can be no assurance that we will be successful selling or farming-out assets, in sufficient amounts or on terms acceptable to us, if at all. Additionally, our ability to sell or farm-out our rights under our existing joint operating agreements is subject to rights of first refusal or similar rights of our joint venture partners.

We have recorded significant impairments to goodwill and to our oil properties

During 2011, we recorded both a goodwill impairment loss of $5,591,422 (eliminating the goodwill attributed to our acquisition of Avante Colombia in 2010), and an impairment expense on our oil properties of $4,201,385. The circumstances leading to our goodwill assessment and subsequent impairment charges are attributed to the impact of changes in the forecasted results of our business operations, discussions with potential investors regarding possible investments in our securities, our current market capitalization, and as a consequence of proposals from various parties regarding potential corporate strategic transactions.

We assess the carrying value of our unproved properties for impairment periodically. If the results of an assessment indicate that an unproved property is impaired (which was assessed in connection with our evaluation of goodwill impairment), then the carrying value of our unproved properties is added to the proved oil property costs to be amortized and subject to the ceiling test. During the fourth quarter of 2011, we transferred approximately $7.8 million in unproved properties to proved oil properties as a result of this assessment. Subsequent to the transfer, we recorded an impairment expense on our oil properties of $4,201,385 as the unamortized costs for proved oil properties exceeded the cost ceiling limitation.

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

In the course of our development activities, we have sustained losses and expect such losses to continue through at least the end of April 2013. In addition, during the fourth quarter of 2011, we recorded significant impairments of our oil properties and goodwill.We expect to finance our operations primarily through our existing cash and any future financing. However, there exists substantial doubt about our ability to continue as a going concern for at least the next twelve months, because we will be required to obtain additional capital in the future to continue our operations and there is no assurance that we 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.

Our long-term business plans and prospects will also require us to obtain additional capital.

We require additional capital to continue to operate our business beyond the initial phase, and we will 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 and government agencies in the event we cannot close previously announced transactionsor meet or ongoing operating commitments under our joint venture agreements.

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 $18.5 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 of an additional well during the next three years.

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.

We will need to raise additional funds and/or generate cash flow 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;

meeting administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses)

complying with licensing, registration and other requirements; and

maintaining compliance with applicable laws.

We plan to pursue sources of such capital through various financing transactions or arrangements, including corporate transactions, 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. Although improving considerably, the turmoil in the world capital markets over the past couple of years has made it difficult for companies to raise funds. 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. 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. In addition, debt and other mezzanine financing may involve a pledge of assets and may be senior to interests of equity holders.

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.

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.

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 with 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.

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 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 our ability to successfully obtain a modification to the terms and conditions of the existing contract between Avante Colombia and Ecopetrol, which expires in December 2013. We believe that to negotiate a change in the contract terms, as well as to acquire additional exploration acreage, we will have to commit to additional investment in the area. There can be no assurance that we will be able to negotiate these items with Ecopetrol or to do so on favorable terms or that we will be able to obtain enough cash to fulfill our commitments. If we fail to obtain sufficient changes to the contract or new exploration acreage, or to do so on sufficiently favorable terms, it would have a material adverse effect on our financial condition and 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.

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 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 pursue to in order to fulfill our obligations to these partners or maintain our relationships. If we fail to make the cash calls required by our joint venture partners in the joint ventures we do not operate, we may be required to forfeit our interests in these joint ventures. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

In addition, in cases where we are the operator, our partners may not be able to fulfill their obligations, which would require us to either take on their obligations in addition to our own, or possibly forfeit our rights to the area involved in the joint venture. Alternatively, our partners may be able to fulfill their obligations, but will not agree with our proposals as operator of the property. In this case there could be disagreements between joint venture partners that could be costly in terms of dollars, time, deterioration of the partner relationship, and/or our reputation as a competent operator.

In cases where we are not the operator of the joint venture, the success of the projects held under these joint ventures is substantially dependent on our joint venture partners. The operator is responsible for day-to-day operations, safety, environmental compliance and relationships with government and vendors.

We have various work obligations on our blocks that must be fulfilled or we could face penalties, or lose our rights to those blocks if we do not fulfill our work obligations. Failure to fulfill obligations in one block can also have implications on the ability to operate other blocks in the country ranging from delays in government process and procedure to loss of rights in other blocks or in the country as a whole. Failure to meet obligations in one particular country may also have an impact on our ability to operate in others.

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 have been 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. 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. In the event that we do not succeed in negotiating additional property acquisitions, our future prospects will likely be substantially limited, and our financial condition and results of operations may deteriorate.

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. Our senior management team 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; our Exploration Manager andour Production and Operations Manager. 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 in retaining staff who are willing to work in such jurisdictions.

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 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.

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 practical, 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 effect 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.

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, 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 three years 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 $140 per barrel in mid 2008 to less than $40 per barrel in early 2009, causing companies to re-think existing strategies and new business ventures. More recently, civil unrest and armed conflict in North Africa and the Middle East, relations between the international community and Iran and threats to the oil supply from the Persian Gulf,as well as economic fears regarding some of the European countrieshave driven oil prices into the range of $80 to $110 that has prevailed through most of 2011 and 2012 to date. 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. Given the current level of production, the Company has not entered into any type of crude oil hedging activity.

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

The current worldwide financial and credit situation may have an effect on our ability to access new capital, therefore we may not be able to raise additional capital when needed. 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.

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 additional oil and gas reserves. Without the addition of reserves through exploration, acquisition or development activities, our reserves and production will decline over time as reserves are produced. 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. We may not be able to find, develop or acquire additional reserves at acceptable costs.

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 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 depletion and impairment expense of oil properties for the year ended December 31, 2011 as compared to 2010. This was primarily due to a larger impairment of costs associated with unproved oil properties added to proved oil property costs during 2011 as compared 2010. For the year ended December 31, 2011 and 2010, the Company incurred impairment expense of $4,201,385 and $3,563,417, respectively, on its oil properties. Furthermore, as a result of the goodwill impairment assessment as of December 31, 2011, the Company recorded an impairment loss amounting to $5,591,422. No goodwill was impaired for the year ended December 31, 2010.

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.

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. Earthquakes or weather related phenomena such have heavy rain, landslides, storms and hurricanes can also cause problems in drilling new wells. There are also risks in producing oil and natural gas from existing facilities. 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. Incidents such as these can lead to serious injury, property damage and even loss of life. We generally 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.

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.

To sell the oil and natural gas that we produce now and 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. In certain areas, we may be required to rely on only one gathering system, trucking company or pipeline, and, if so, our ability to market our production would be subject to their reliability and operations. 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.

Guerrilla Activity in Colombia Could Disrupt or Delay Our Operations, and We Are Concerned About Safeguarding Our Operations and Personnel in Colombia.

A 40-year armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups - both funded by the drug trade - continues in Colombia. Insurgents continue to attack civilians, and violent guerilla activity continues in many parts of the country.

We operate principally in the Putumayo basin in Colombia, and have properties in the Catatumbo basin. The Putumayo and Catatumbo regions have been prone to guerilla activity in the past. 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. 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.

Pipelines have also been targets, including the Ecopetrol-operated Trans Andean export pipeline, which transports oil from the Putumayo region.Recent activity continues against sections of the Trans Andean pipeline where guerrillas blew up sections, which temporarily reduced operation of the pipeline.

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, 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.

Continuing attempts to reduce or prevent guerilla activity may not be successful, and guerilla activity may disrupt our operations in the future. There can also be no assurance that we can maintain the safety of our operations and personnel in Colombia or that this violence will not affect our operations in the future. Continued or heightened security concerns in Colombia could also result in a significant loss to us.

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, 2011 it was approximately $99 per barrel. In less than one year it tumbled from over $140 per barrel in mid 2008 to less than $40 per barrel in early 2009, before rebounding. More recently, civil unrest and armed conflict in North Africa and the Middle East, relations between the international community and Iran and threats to the oil supply from the Persian Gulfas well as the economic crisis in Europe have driven oil prices into the range of $80 to $110 that has prevailed through most of 2011 and 2012 to date. 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. Furthermore, prices that we receive for our oil sales, while based on international oil prices, are established by contract with purchasers with prescribed deductions for transportation and quality differences. These differentials can change over time and have a detrimental impact on realized prices. 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. The company does not have in place a crude oil hedge agreement.

Our operations involve substantial costs and are subject to certain risks because the oil and gas industries in the countries in which we operate are less developed.

The oil and gas industry in South America is not as efficient or developed as the oil and gas industry in North America. As a result, our exploration and development activities may take longer to complete and may be more expensive than similar operations in North America. The availability of technical expertise, specific equipment and supplies may be more limited than in North America. We expect that such factors will subject our operations to economic and operating risks that may not be experienced in North American operations.

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.

Our exploration, development, production and marketing operations are regulated extensively under foreign, federal, state and local laws and regulations. Under these laws and regulations, we could be held liable for personal injuries, property damage, site cleanup and restoration obligations or costs and other damages and liabilities. 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 safety or environmental 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 costs of compliance, remedy or indemnification of our employees.

Policies, procedures and systems to safeguard employee health, safety and security may not be adequate.

Oil and natural gas exploration and production are dangerous. Detailed and specialized policies, procedures and systems are required to safeguard employee health, safety and security. We have undertaken to implement best practices for employee health, safety and security; however, if these policies, procedures and systems are not adequate, or employees do not receive adequate training, the consequences can be severe including serious injury or loss of life, which could impair our operations and cause us to incur significant legal liability.

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 costly and difficult.

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. Our operations have a significant effect on the areas in which we operate, and to enjoy the confidence of local populations and the local governments, we or our operating partners must invest in the communities where were operate. In many cases, these communities are impoverished and lack many resources taken for granted in North America. The opportunities for investment are large, many and varied; however, we must be careful to invest carefully in projects that will truly benefit these areas. These costs, while incidental to our operation, would not be capitalized for financial reporting purposes and would be recorded as expenses immediately in our statement of operations. If we or our partners fail to manage any of these investments and 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.

Challenges to our properties may impact our financial condition.

Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interest in and to the properties to which the title defects relate.

Furthermore, applicable governments may revoke or unfavorably alter the conditions of exploration and development authorizations that we procure, or third parties may challenge any exploration and development authorizations we procure. Such rights or additional rights we apply for may not be granted or renewed on terms satisfactory to us.

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 operate our business in Colombia and expect to operate in other South American countries in the future. 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. For example, starting on November 21, 2008, certain oil and gas companies were forced to reduce production in Colombia on a gradual basis, culminating on December 11, 2008 when they suspended all production from the certain blocks in the Putumayo Basin. This temporary suspension of production operations was the result of a declaration of a state of emergency and force majeure by Ecopetrol due to a general strike in the region. In January 2009, the situation was resolved and these companies were able to resume production and sales shipments.

Certain countries in South America have a history of political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including the imposition of additional taxes. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. 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, or 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. 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.

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. These licenses and permits are subject to numerous requirements, including compliance with the environmental regulations of the local governments. Our or our joint venture partners’ 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. As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines. Our or our joint venture partners’ 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 submitted to Emerald the required written request for Emerald to apply to the ANH for approval of the assignment. The ANH denied the assignment of the 20% to La Cortez Energy because our financial indicators did not comply with the minimum requirements set out by the ANH, mainly arising from the classification of derivative warrants instruments as a current liability in the Company’s balance sheet under US GAAP rules.

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.

Likewise, we have submitted to Petronorte the required written request for Petronorte to apply to the ANH for approval of the assignment. Petronorte will assign and transfer to us the agreed upon 50% participating interest in the Putumayo 4 Block, subject to ANH approval. Petronorte filed a request with the ANH for the official assignment of the 50% working interest in the Putumayo-4 block to La Cortez.The ANHinformed Petronorte that it requires La Cortez to provide an additional financial guarantee. We are evaluating various options to decide whether to provide the additional guarantee or submit a new request later in 2012.

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. However, in both cases we believe that if we comply with our financial obligations under the private contracts, there is limited risk of losing our participation interest.

Foreign currency exchange rate fluctuations and exchange controls 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. We have not engaged in any formal hedging activity with regard to foreign currency risk. Our reporting and functional currency is U.S. dollars. In Colombia, we have to date received 100% of oil revenues in U.S. dollars. The majority of our capital expenditures in Colombia are in U.S. dollarsand the majority of payroll and local office costs are in local currency. Our spending for acquisitions has to date been valued and paid in U.S. dollars.

Since we began operating in Colombia, (April 2, 2008), the rate of exchange between the Colombian peso and US dollar has varied between 1,827.94 pesos to one US dollar and 2,590 pesos to one US dollar, a significant fluctuation The table below shows exchange rates over the last year.

Source: Colombia – Banco de la Republica

Further, 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. To the extent that funding is required, there may be exchange controls limiting such funding or adverse tax consequences associated with such funding. In addition, taxes and exchange controls may affect the dividends that we receive from foreign subsidiaries.

Exchange controls may prevent us from transferring funds abroad.

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

An active market for our common stock may not develop.

There currently is a very 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 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. 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 may severely limit the liquidity of our common stock, and could have a material adverse effect on the market price of our common stock and on our ability to raise additional capital.

We cannot assure you that our common stock will become liquid or that it will be listed on a securities exchange or that it will continue to be eligible for trading on the OTC Bulletin Board.

Until our common stock is listed on a national securities exchange such as the New York Stock Exchange or the Nasdaq National Market, our common stock may only be 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. If we decide to deregister our common stock under the Securities Exchange Act, it may cease to be eligible for quotation on the OTCBB, or on another over-the-counter quotation system, or in the “pink sheets.” This would further severely limit an investor’s ability to obtain information about or to trade 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

that 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.

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.

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 of 300,000,000 shares of common stock and 10,000,000 shares of preferred stock with preferences and rights to be determined by our Board of Directors. As of April 10, 2012, there were46,467,849 shares of our common stock and no shares of our preferred stock outstanding. There are 4,000,000 shares of our common stock reserved for issuance under our Amended and Restated 2008 Equity Incentive Plan. These numbers do not include 15,515,203 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 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.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

Executive Offices

Our corporate headquarter is located at Calle 67 #7-35, Oficina 409, Bogotá, Colombia. At this location we rent approximately 3,000 square feet of office space. We also have leased a house in the town of La Gabarra, Colombia, where we have office facilities, accommodations for our employees and contractors and some equipment for the Puerto Barco and Rio de Oro fields.

Reserves

The proved oil reserves of La Cortez Energy have been estimated by an independent engineering company DeGolyer and MacNaughton (D&M), as of December 31, 2011. These reserve estimates have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (the “SEC”). Their report as of December 31, 2011 presents estimates of the value of the proved, probable, and possible crude oil reserves and the estimates of the value of the proved, proved-plus-probable, and proved-plus-probable-plus-possible reserves of the Mirto field in the Maranta Block in Colombia, in which La Cortez Energy (La Cortez) owns an interest. The report of D&M as of December 31, 2011, is filed as an exhibit to this Annual Report on Form 10-K.

Reserves estimated are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced after December 31, 2011 from the properties where La Cortez has interests. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by La Cortez after deducting all interests owned by others, including royalties paid in kind.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)”. The method or combination of methods in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. When applicable, the volumetric method was used to determine the original in place. Estimates were made by using various types of logs, core analysis, and other available data. Formation tops, gross thickness, and representative values for net pay thickness, porosity, and interstitial fluid saturations were used to prepare structural maps to delineate each reservoir and isopachous maps to determine reservoir volumes.

Estimates of ultimate recovery were obtained by applying recovery efficiency factors to the original quantities of petroleum in place. These factors were based on consideration of the type of energy inherent in the reservoir, analysis of the fluid and rock properties, the structural position of the properties, and the production history. In some instances, comparisons were made with similar producing reservoirs in the area where more compete data were available.

Where adequate data were available and where circumstances justified, material balance and other engineering methods were used to estimate recovery factors. In these instances, reservoir performance parameters such as cumulative production, producing rate, reservoir pressure, gas oil ratio behavior, and water production were considered in estimating recovery efficiencies used in determining gross ultimate recovery.

For depletion-type reservoirs or other reservoirs where performance has disclosed a reliable decline in producing rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In analyzing decline curves, reserves were estimated to the calculated economic limits based on the current economic conditions.

In certain cases where the previously named methods could not be used, reserves were estimated by analogy with similar reservoirs where more complete data were available.

The reserves estimated by D&M were based on consideration of monthly production data through December 31, 2011. Cumulative production, as of December 31, 2011, was deducted from the gross ultimate recovery to determine the estimated gross reserves. Oil reserves estimated are expressed in 42 United States gallons per barrel.

Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standard Board (FASB). Values for proved, probable, and possible reserves were based on projections of estimated future production and revenue prepared for the properties with no risk adjustment applied to the probable and possible reserves. Probable and possible reserves involve substantially higher risks that proved reserves. Oil prices were based on a 12-month average price, calculated as the unweighted average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The 12-month average adjusted product price was U.S. $77.97 per barrel for crude oil based on 12-month average benchmark price of U.S. $95.96 per barrel. The adjustments to price include differentials from WTI to Vasconia, transportation costs, blending and diluents costs and trading fees.

No natural gas volumes produced were included in the estimation as this gas will be used for internal consumption or will be flared. All of the Company’s reserves are located in Colombia, primarily in the Putumayo basin.

The technical person responsible for overseeing the reserves evaluation is a Senior Vice President of D&M. He has a Bachelor degree in Chemical Engineering and is a registered professional engineer in Houston, Texas. He has over 34 years of industry experience in various domestic and international engineering and management roles.

Proved, probable and possible reserves as of December 31, 2011 are as follows:

	Oil
	Thousands of barrels
	Gross		Net
	reserves		reserves
Proved
Developed		468.0		86.1
Undeveloped		-		-
Total proved		468.0		86.1

Probable		813.0		149.6
Possible		2,488.0		457.9

Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves

An analysis of the change in estimated quantities of proved oil reserves is shown below:

	Oil (Bbls)
	December 31, 2011			December 31, 2010
Total Proved Reserves:
Beginning balance		92,574			74,230
Discoveries		-			61,249
Production		(35,148	)		(4,741	)
Revisions of previous estimates due to performance		28,686			(38,164	)
Ending balance		86,112			92,574
Proved Developed Reserves:
Beginning balance		92,574			74,230
Ending balance		86,112			92,574

2010 reserves audit was conducted by Ryder Scott

2011 reserves audit was conducted by DeGolyer and MacNaugthon

Difference in both years is mainly due to revision of previous estimates due to performance

Description of Properties

Colombia

Source: Google Earth

Maranta and Putumayo 4 Blocks

Source: La Cortez Energy, Inc.

Putumayo 4

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 Limited, that entitles the Company to a 50% net working interest in the Putumayo 4 block (the “Putumayo 4 Block”). According to the MOU, the Company will have the exclusive right to a 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 is the “operator” under the E&P Contract.

General Description

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 La Cortez and Petronorte have identified promising leads.

There are four existing wells in the Putumayo 4 Block that date back to the 1970’s, though information about them is scarce. These wells were 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 expectations in the block.

Location

The Putumayo-4 Block is located in the southwest part of Colombia, approximately 1,000 km from Bogotá, Colombia's capital city. It covers an extension of 51,333 hectares (126,847 acres) located in the Putumayo Basin.

The Block can be accessed by secondary roads, which are in good condition, as well as by rivers, which for some indigenous communities are the primary means of transport. The Block is intersected by the Puerto Asis - Orito and Puerto Asis - Mocoa roads. It is also possible to access the Block by airplane. The terrain is somewhat hilly with abundant rainforest.

There are some fluvial streams and rivers. The climate is warm (approximately 30 degrees Celsius on average), with high humidity and frequent, heavy rainfall.

The Transandean pipeline, which runs parallel to the Puerto Asis – Orito road, has oil transport capacity of over 100,000 barrels per day. This pipeline runs from the SurOriente Block and takes production to the port of Tumaco on the Pacific Ocean. In addition there is oil infrastructure in neighboring blocks.

Regional Geology

The Putumayo Basin is located in southwest Colombia and is a foreland basin type. It has 19 oil and gas field discoveries with reserves of 365 million barrels of oil and reserves of 305 billion cubic feet of gas. The Caguán-Putumayo Basin is the northern extension of the Oriente Basin of Ecuador. This basin has an extension of about 104,000 square kilometers.

In this area, exploration activities started in 1948 by Texaco. In 1963 Texaco discovered the major Orito oil field with reserves of approximately 250 million barrels of oil. The existence of a petroliferous system at work is documented by the several oil fields discovered in the basin. Oil fields in the basin are related to structural traps, mainly contractional fault-related folds, and reverse faulting. Additional oil reserves could be found in significant quantities trapped in sub-basement traps, wrench related anticlines, and drapes over basement highs and subtle stratigraphic traps at the eastern flank of the basin. Presence of these traps suggests that large parts of the basin still have significant exploration potential.

The boundaries of this basin are: the Eastern Cordillera foothills thrust system to the northwest; the Macarena structural high to the northeast; the Ecuadorian and Peruvian international border to the south and a structural high to the east, which includes the Serranía de Chiribiquete.

The principal reservoir in the basin is the cretaceous sandstones of the Caballos Formation with an average thickness of 300 ft, with porosities range from 10% to 16% and with an average permeability of 50 md. The secondary reservoirs are found in sandstones of the Villeta Formation and Pepino conglomerates.

Field Geology

No oil fields have been discovered in the block. The analogous and nearest oil fields are Nancy and Burdine Fields. These fields have commercial production from the Villeta Formation, N and U sands respectively. Both fields were discovered in the 1970s.

Four exploration wells have been drilled in this block in the 1970s, called Susan-1, Helen-1, Evelin and Setuko-1. These wells were drilled having as the main objective, the Caballos formation, which is not productive in this part of the basin. However, some of the wells presented oil shows in the sandstones of the Villeta formation, which now is the main exploratory objective.

Seismic Coverage

The Putumayo-4 Block has over 1,200 km of pre-existing 2D seismic acquired between the 1960’s and the 1980’s by different companies and during different acquisition campaigns. La Cortez and Petronorte have reprocessed all the seismic information acquired that confirmed our initial evaluation of several potential leads.

Legal and Environmental Licenses

The Ministry of Environment and Sustainable Development (hereinafter “MADS) requires the establishment of an environmental plan to monitor the compliance of the environmental regulations during all the phases of the project. In the year 2012 Petronorte will continue working in the activities addressed to get the exploration drilling license to be able to drill the first exploratory well in the block planned to the first quarter of 2013. In addition for the seismic phase and to be in compliance with the local authorities of Putumayo where the project is located, the Local Environmental Corporation (“CORPOAMAZONIA”) requires the establishment of a permit for the water use. This permit is in process with the CORPOAMAZONIA.

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.

Petronorte and the Company have been conducting the community consultation process for the seismic acquisition in the northern part of the Putumayo 4 Block. This process was recently completed, and the bidding process for the seismic work was done. Several seismic service companies were invited to participate for the acquisition of 104.8 km of 2D seismic in the area, which is part of the work commitment to the ANH. An additional 45 - 50 km of 2D seismic will also be acquired as part of the additional investment commitment of $1.6 million grossmade to the ANH during the 2008 bidding round. The bid was awarded to Satellite Surveying Services Ltda (SSS Ltda), which is a company well experienced in this Putumayo area. They have successfully conducted more than 12 seismic acquisition projects based on good relationships with the communities; a part of their staff belongs to the same communities. We expect to start the seismic program by late April 2012 after contract configuration and acquiring permits from CORPOAMAZONIA. The seismic acquisition process is expected to take no longer than three months.

Petronorte and the Company are also working on the community consultation process for the drilling of the first exploration well in 2013, in addition to working in preparing the Environmental Impact Study or Estudio de Impacto Ambiental (EIA), to be presented to the Colombian authorities to obtain the exploration well drilling license. It is expected that drilling operations will be initiated in the first quarter of 2013, as soon as all permits are obtained. This exploration well will also be targeting the Villeta formation N, U, and T sands as well as the Caballos formation. Other companies are currently producing from these sands in fields located near the Putumayo 4 Block, though there can be no assurance that this is indicative of the results of our test well.

Petronorte sent a letter to the ANH on May 23, 2011 asking for an extension of the contract for about seven months, due to a delay of that length of time caused by unavailability of the Ministry of Interior representative to carry on with the consultation process with communities, to compensate for the impact on the original schedule. On February 23, 2012, the ANH approved an extension of seven months and five days.

Petronorte has filed a request with the ANH for the assignment of the 50% working interest in the Putumayo 4 Block to the Company. To qualify as a contractor with the ANH, the Company has submitted, legal, operating, technical and financial information, including prior years’ audited financial statements, to be reviewed by the ANH. As indicated before, The ANH has advised that La Cortez needs to provide additional guarantees for the required investment for the first exploration phase.We are evaluating various options to decide whether to provide the additional guarantee or submit a new request later in 2012.

Under the MOU and the joint operating agreement, the Company will be responsible for fifty percent (50%) of the costs incurred under the E&P Contract, entitling it 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 the Company 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 the Company for its share of these seismic costs paid by the Company (which is one-sixth (1/6) share) with their revenues from production from the Putumayo 4 Block.

Social and Other Agreements

In December 2009, a socio-cultural analysis of the social and territorial context of the block was completed, with the participation and support from local government representatives and ethnic communities’ leaders.

The study concluded that there were 22 ethnic communities in and nearby the exploration area.

With this information, the Company sent a request to the Ministry of Interior and Justice to confirm the presence or not of ethnic communities that would be directly affected by the project.

In July 2010, the Ministry of Interior and Justice officially established that the following seven communities were located in the Block:

MUNICIPALITY	ETHNIC COMMUNITY	DENOMINATION
Puerto Caicedo	Awá Indigenous Community	Las Vegas Villa Unión San Andrés

	Versabal Afro Community	Versabal

Orito	Los Andes Afro Community	Los Andes
	Siona Indigenous Community	Ten Të Yä
	Villarbolense Afro Community	Villarbolense
Valle del Guamúez	Cofán Indigenous Community	Villanueva
	Cofán Indigenous Community	Bocana del Luzón

In September 2010, the pre-consultation process began to establish agreements with the seven communities.

Current Status of the Pre-Consultation Process with the Seven Communities:

The status of the pre-consultation process with the seven communities by the end of 2011 is as follows and particularly in relation to the seismic operations:

SEISMIC PHASE

NORTH AREA OF THE BLOCK

COMUNITY		STATUS
Versabal		Agreements - Done
Resguardo Las Vegas Villa Unión San Andres		Agreements - Done

SOUTH AREA OF THE BLOCK

COMUNITY		STATUS
Cabildo Ten Te Ya		Pre Consultation Agreements - Done
Villarbolense		Pre Consultation Agreements – Done
Los Andes		No agreement was reached
Bocana de Luzon		Pre-consultation started
Villanueva		Pre-consultation done

In relation with the drilling phase, three communities were identified by the Interior Ministry in the North part of the Block. A new preconsultation process is going to start. At the same time the processes for the seismic phase with the two communities pending in the south area of the block will continue.

DRILLING PHASE

NORTH AREA OF THE BLOCK

COMUNITY		STATUS
Versabal		Process will start in Feb 2012
Nsa Kwuma Te’wezx		Process pending to start
Inkal Awa		Process pending to start

Source: La Cortez Energy, Inc.

Maranta

General Description

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 Block”).

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 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 a 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 productivity.

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 the Company. Emerald filed a request with the ANH for the assignment of the 20% working interest in the Maranta Block to La Cortez. To qualify as a contractor with the ANH, the Company submitted, on April 15, 2011, legal, operating, technical and financial information, including prior years’ audited financial statements, to be reviewed by the ANH. On July 12, 2011, the Company was informed by Emerald that the request for transfer of the 20% interest was not approved because the ANH determined that the submitted information did not comply with the financial requirements demanded by the contract signed between the ANH and Emerald. The Company plans to submit a new request to the ANH once the financial indicators are met. It is expected that this will be done during 2012. Non-approval by the ANH does not affect the current joint operating agreement between Emerald and La Cortez.

This map shows the Maranta Block location.

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

Location

The Maranta Block covers an area of 36,608 hectares (90,459 acres) in the foreland of the Putumayo Basin, southern Colombia and has over 600 km of pre-existing 2D seismic through which we and Emerald have identified some leads. After the 50% relinquishment, the area will be reduced to approximately 18,000 hectares.

The Block is accessible by secondary roads in good condition as well as by rivers, which for some indigenous communities are the main way of transport. It is possible to access the block by road from Bogota, Colombia's capital, situated some 1,000 km away and by airplane. Some pipelines pass close to the Block and production can be easily transported by truck to the pipeline receiving stations located no more than 50 km away. There is also oil infrastructure in neighboring blocks which the Company has the potential to access.

The terrain is somewhat hilly with abundant rain forest. There are some fluvial streams rivers. The climate is warm (approximately 30 degrees Celsius on average), with high humidity and frequent heavy rainfall.

Regional Geology

The Putumayo Basin is part of a series of north-south Andean foreland basins, which was formed on the eastern side of the Andes Mountains. The basin is a northern extension of the Oriente Basin in Ecuador and the Maranon Basin in Peru. The Putumayo Basin formed during the late Triassic early Jurassic cordillerean rifting and associated metamorphism. Deposition began in the early Cretaceous with the deposition of clastic fluvial sediments of the Caballos Formation deposited, unconformably on the Jurassic rocks. The Putumayo Basin dips gently to the west where the sediments reach a thickness greater than 10,000 meters. The basin underwent several tectonic events including a period of compression resulting in thrust faulting and strike-slip fault movement in the late Cretaceous, early Tertiary, which resulted in the development of a network of low relief north trending basement fault blocks.

Mirto Field Geology

Geologically, the Maranta Block is located in the Putumayo Basin, and within the regional framework it is divided into two tectonic provinces.

Lower Platform: Corresponds to the zone over which the Umbría-1, Umbría-2, El Tigre-1 wells and fields such as Yurilla, Alborada, Mansoya, Cemcella, among others are located. This zone is mainly characterized by being a deep zone with well total depth between 10,300 and 11,300 ft. and faults at the Cretaceous level with small displacement jumps.

Middle Depocentre: Corresponds to the north sector of the block, within which are found the structures associated to the Toroyaco, Linda, Mary, Costayaco and Juanambú fields. The main characteristic of this province is the presence of structural type traps, generated by inverse faults, which denote a high relief in respect to the deepening zone observed toward the sector of the Umbria-1 well.

In the case of the Maranta Block, for the Low Platform sector, the traps are mainly associated to low relief structures to the hanging block of normal faults at the Cretaceous level with small displacement jumps and dipping closes in term of directions. For the North Sector (Middle Depocentre), the structures are mainly associated to the neighboring and hanging blocks of the inverse faults, which denote high relief. Other traps with potential within the block are those of a stratigraphic type (pinch-outs, carbonate build-ups).

The Caballos Formation is the main target in the basin's foothills, while the "T,” "U" and "N" sandstones of the Villeta Formation, constitute the main bearing rocks in the foreland area.

The sandstones of the Caballos Formation reach a total thickness of 200 to 250 feet and net sands between 80 and 150 feet. The range of porosities varies between 8% and 12%. The T sandstones of the Villeta Formation have a net oil-bearing thickness of approximately 40 feet, porosities ranging between 10 and 15%. The U Interval sandstones have a 25 foot net oil bearing thickness, porosity between 13% and 16%. The N sand Interval has a 10 to 15 foot net oil bearing thickness and porosity between 12% and 15%.

The Orito, Nancy Burdine Maxine fields are toward the South-Western sector of the block; production is present in the Cemcella, Mansota and Yurilla fields toward the South-Eastern sector; finally, the Costayaco, Juanambú, Linda, Mary and Toroyaco fields are at the northern limit.

The production from these fields is associated to the various sandy intervals (T, U and N) of the Villeta Formation and the Caballos Formation.

Gravities for oils from Cretaceous deposits vary between 15° and 40° API, with the highest from the Lower Cretaceous (Caballos Formation). Eocene gravity is 29 API.

The Maranta Block remains under explored, with only four wells having been drilled in the block; the Umbria-1, and Umbria-2 wells were drilled in October 2009. The Mirto Field is bounded on the west by a north-south reverse fault and on the east by a down dip water contact in the U reservoir sands.

The Cretaceous Villeta N and U sandstones are the productive oil reservoirs in the Mirto Field.

The gross N reservoir consists of inter-bedded white translucent, medium to fine grained, well sorted, rounded quartsoze sands, mudstones with glauconitic inclusions, siltstones, and minor carbonaceous clasts. In the Mirto-1 well, the gross thickness of the N reservoir is 34 feet, with only the top 8.5 feet assigned oil pay. The porosities range between 13% and 15%. The N pay sands have been perforated from 10,410-10,417 feet TVD and tested oil. The lowest known oil contact in the N reservoir was used for the volumetric calculation for the Villeta N reservoir oil.

The U sands are separated from the N reservoir by a thick 600 feet interval of marine shales and limestones. The U reservoir consists of quartzose sands, fine to medium grained, very light grey, moderately consolidated, well sorted and slightly calcareous with very low shale content.

Occasionally thin glauconitic intervals are present and rare pyretic, carbonaceous inclusions as well. The U sands have average porosities varying from 13.8% to 17.5%, with a maximum porosity of 24%. Net oil pay of 35.5 feet was assigned to U reservoir in the Mirto-1 well. An oil water contact was identified at 11,074.85 feet TVD (-10,005.85 feet TVDSS (True Vertical Depth Sub Sea)). The U sands are present and have similar thickness in all the wells drilled in the area and therefore likely have good lateral continuity.

Seismic Coverage

The Maranta Block has over 600 km of pre-existing 2D seismic acquired between the 1960s and the late 1980s by different companies and during different acquisition campaigns.

Emerald completed the first phase exploratory program for the Maranta Block by acquiring 71 km of new 2D seismic and acquiring 30 square kilometers of 3D seismic over the Mirto structure.

Emerald identified the Mirto prospect, namely the Mirto-1 well, as the first exploratory well in the Maranta Block. The Mirto-2 well is currently in production testing in the N sand, with an average during the testing period of 533 bopd of 15.64º API Gross (106 bopd net to LCTZ). 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.

A new exploratory phase has been negotiated with ANH in two phases of two years each, acquiring 120 km, 2D seismic or to drill a new exploratory well. After this phase is completed, Emerald and we will relinquish 50% of the Maranta Block.

We expect that our capital commitments to Emerald will be approximately $4.85 million in 2012 to cover new wells, production facilities and seismic acquisition in the Block.

Legal and Environmental Licenses

The MADS requires the establishment of an environmental plan to monitor the compliance of the environmental regulations during all the phases of the project. For the Maranta Block an Environmental Impact Study was filed and approved by the MADS and for Mirto 1 and Mirto 2 wells an Environmental Management Plan was filed and approved by the MADS. In addition, for the operation of both fields a series of permits were required, which were approved through two licenses by the MADS.

Mirto is under production through a long-term test authorized by the Colombian Ministry of Mines granted to Emerald, who is the field operator. This test will be used to conduct well pressure testing and to gather other information that will be used to define the potential of this reservoir and to optimize production rates.

Phase 3 of the initial exploration program was completed in the year 2010 with the drilling of the Mirto-2 well. Emerald and the Company have together complied with the exploration obligations on this block in accordance with the contract signed with the ANH. Under the contract terms and conditions, and after completion of this phase, both the Company and Emerald are required to relinquish 50% of the area of the block, as selected by both parties, and there is the option to continue exploration activities in the remaining 50% of the area by committing to additional exploration activities with the ANH, such as new seismic acquisition or drilling a new exploration well. This is a usual procedure and it is in accordance with the standard contract with the ANH. Emerald has identified the 50% area to be relinquished and has received approval from the ANH, which was dated April 11, 2011, on the additional exploration program and has signed the amendment to the contract.

Phase 1 of the subsequent exploratory program requires both Emerald and La Cortez to comply with the acquisition of 120 km of 2D seismic or the drilling of an exploration well on or before August 2012, with Phase 2 of the subsequent exploratory program requiring another acquisition of 120 km of 2D seismic or the drilling of an exploratory well on or before August 2014. Emerald and the Company are in the final stages of determining the activity plan for the year 2012, which is expected to include drilling of at least one more exploration well. Emerald is proposing to the ANH the acceptance of the Agapanto-1 well to be drilled in the first half of 2012 in satisfaction of the commitments under the first phase of the subsequent exploratory program in the Maranta block. This exploratory well is being targeted to the Villeta formation N, U, and T sands, which are producing areas within the Mirto field. In addition to this well, Emerald and the Company are looking at various options, such as running additional seismic and conducting a workover in an existing old well, Umbria-1, to test the potential of the Villeta sandstones. These activities are contingent to the environmental license, a process that is being handled by Emerald, the operator.

On March 22, 2012, Emerald submitted to the ANH the report of the evaluation program and declaration of commerciality of the Mirto field. It is pending ANH approval.

Rio de Oro and Puerto Barco

Location

The Rio de Oro and Puerto Barco exploration and production contracts are located in the Catatumbo Basin in eastern Colombia. These fields initiated production about 50 years ago and produced good quality oil, mainly from the Uribante group (Tibu, Aguardiente and Mercedes cretaceous formations). Most of the production was obtained from the Rio de Oro field. The contracts cover an area of 2,262 hectares in Rio de Oro and 2,406 hectares in Puerto Barco. The contract started in December 2003 and will expire in December 2013.

Access to these fields is through a secondary road from Cucuta and then to the towns Tibu and La Gabarra. From La Gabarra there is a road that connects both fields. However, extensive reconstruction work has to be executed in order to upgrade these roads. It is also possible to access the fields from an existing road in Venezuela; however, doing so would require the Company to obtain special permits from the Venezuelan government.

The climate is tropical with an average temperature of approximately 30 to 35 degrees celsius. The topography is mainly composed of plains and hills. The most important fluvial stream is the Catatumbo River, which is also situated along the border with Venezuela. This river could be used as an alternative transport route to reach the Rio de Oro field.

There is a pipeline that takes the production from the existing Ecopetrol fields at Tibu town to the Barracabermeja refinery in the middle of the country. This pipeline has spare pumping capacity, and it was historically used to pump the production from these fields to the market. However, the production must first be transported 65 km by truck from the field to the receiving station at the Rio Zulia pipeline.

Regional Geology

The Catatumbo Basin is a southwest extension of the Maracaibo Basin. It is a foreland basin type with an area of 7,350 km2 / 1,800,000 acres with 11 oil fields discovered. Its northern and eastern limits are the geographic border with Venezuela; to the south the limit is with outcropping of Cretaceous rocks of the Eastern Cordillera, and to the west the igneous and metamorphic rocks of the Santander massif.

Oil reservoirs in Cenozoic and Cretaceous sandstones and limestones are trapped in faulted anticlines. The Cretaceous and Cenozoic formatuins in this basin represent two distinct tectonic and sedimentary settings. Cretaceous rocks are marine sandstones, shales and limestone that represent deposition in a broad shallow sea that extended across northern Venezuela and continued south through Colombia. Cenozoic rocks are fluvial-deltaic shales and sandstones that were deposited in a foreland basin. Overall, reservoir porosity is best developed in Paleogene sandstones. Traps are wrench controlled, faulted anticlines that resulted from strike-slip convergence.

Oil was sourced from the upper Cretaceous La Luna formation and the lower Cretaceous Uribante Group. Oil generation began in the Late Eocene and continues through today. Seventy percent of the reserves discovered in thia area between 1920 and 1950 and were based on surface exploration (mapping of surface anticlines.).

Most of the remaining hydrocarbon potential in this basin occurs in en-echelon folds associated with the regional left-lateral Chinácota fault system on the western flank of the basin, referred to as the "Catatumbo Flexure" in the northern portion of the basin.

The Catatumbo Basin has been one of the most prolific basins in the country. The main oil fields in the basin are the Rio de Oro, Tibú - Socuavo, Carbonera, Sardinata, Rio Zulia, Petrolea and Puerto Barco. The Catatumbo Basin is a moderately explored basin, which has produced more than 450 million barrels of oil and 500 billion cubic feet of gas since 1920.

When formal exploration work began in 1931, transportation facilities were confined to a mule trail from Puerto Villamizar, on the Cucuta railway, to Petrolea and wet-season launch and barge navigation to Puerto Reyes and Puerto Barco on the Catatumbo River system. A road from the railway to the Petrolea valley was completed in 1938.

The Rio de Oro anticline is the dominant structure in the block. It is located in the easternmost foothills of the Sierra de Perija. It trends slightly east of north and extends from the Rio Catatumbo to the Rio de Oro and some 20 kilometers northward into Venezuela. It is a narrow faulted highly asymmetrical anticline with a nearly vertical east flank and a comparatively gentle west flank. Surface data show two structural highs on the Colombian portion of the anticline, one west of Puerto Barco and the other 4 kilometers south of the Rio de Oro. Sandstones of the Barco formation are exposed near the apex of each high.

There are numerous oil and gas seeps along the crest of the anticline. The structural high west of Puerto Barco was tested by two wells, which drilled into the upper part of the Uribante formation without encountering production, although there were many oil shows in both Tertiary and Cretaceous formations. Eleven wells, nine of which were productive, have been drilled on the Colombian portion of the northern high. Production has been obtained from the Catatumbo formation and from the Rio de Oro member of the Mito Juan formation.

Field Geology

The first well on the concession, Rio de Oro 1, was drilled on the crest of the Rio de Oro anticline in 1920 by Doherty interests, offsetting a small producer drilled on the Venezuelan side of the border in 1915 by the Colon Development Company. An oil-bearing sandstone encountered in the Barco formation at 137 meters flowed strongly but soon dropped off to 50 BOPD and was cased off.

The Rio de Oro 2 and Rio de Oro 3 wells, located on the structural high west of Puerto Barco, were drilled by the Colombian Petroleum Company from April 1935 to October 1937. Both penetrated the upper part of the Uribante formation to total depths of 2048 and 1926 meters respectively, without encountering production. Neither well tested the Tibu formation. No other wells have been drilled on the southern high of the anticline.

The Rio de Oro 4, located on the crest of the northern high of the anticline was completed in 1937 at a depth of 192 meters, in the top of the Mito Juan formation. It showed a potential of 130 BOPD on a half-inch choke from sandstone in the Catatumbo formation.

Since completion of the Rio de Oro 4 well, nine wells have been drilled on the northern high, eight of which were productive. The average depth is 430 meters. Two productive zones in the Catatumbo formation and one in the uppermost Mito Juan formation have been developed. The lower Cretaceous has not been tested. Production is obtained from fine-grained argillaceous sandstones and siltstones, the intergranular permeability of which is so low as to likely require fracturing to stimulate production... Effective thickness of sandstones in the productive zones ranges from 3 to 12 meters.

The productive area of the most extensive zone is approximately 170 hectares (42,000 acres). The average daily potential on a quarter-inch choke is 260 barrels per well with an average gas-oil ratio of 340. The gravity of the oil ranges from 32° to 40° API. The field has no pipeline connection, so would require transportation to nearby failities.

In the Rio de Oro contract, originally signed between Ecopetrol and private parties other than La Cortez,a total of 44 wells have been drilled representing cumulative production of 11 million barrels of oil. In Puerto Barco, four wells have been drilled with cumulative production of 0.8 million barrels of oil.

Seismic Coverage

The prior exploration and development activities were made without seismic information, using only surface geology and wells data. The seismic campaigns were undertaken in 1976 by Ecopetrol, covering all of the regional production and exploration area, with approximately 200 km of 2D seismic.

Legal and Environmental Licenses

The MADS requires the establishment of an environmental plan to monitor the compliance of the environmental regulations during all the phases of the project. For the Puerto Barco field an Environmental Management Plan was filed and approved by the MADS. For Rio de Oro field an Environmental Management Plan was filed and it is pending a Certificate from the Ministry of Interior to continue the licensing process with the MADS. In addition, for the reactivation of the Puerto Barco and Rio de Oro fields and to be in compliance with the local authorities of Norte de Santander where the projects are located, the Local Environmental Corporation (“CORPONOR”) required the establishment of a series of permits, including a water concession permit, a dumping permit, and an air emissions permit, all of which are in force for Puerto Barco and Rio de Oro fields.

In the Rio de Oro field, the remediation of certain historical environmental conditions created prior to our acquisition will be the responsibility of the previous operators. In addition to the contractual responsibility of the 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.

Social and Other Agreements

On October 10 2008, by certification of the Ministry of Interior, the Ministry acknowledged the presence of Ishtoda and Beboquira Barrancas indigenous communities in areas not entitled in the jurisdiction of Tibu, Norte de Santander (outside of the indigenous territory). However, the Ministry concluded that the indigenous community is located in the municipality of Tibu and therefore must be certified by the Incoder (Instituto Colombiano para el Desarrollo Rural).

Also On October 10, 2008, the Interior Ministry stated that it does not consider the Rio de Oro field to include the presence of indigenous communities. This certification is in the process of being renewed.

On November 19, 2008, by certification of the National Rural Land Unit ("UNAT"), the authority established that according to the Geographic Information Systems coordinates the project in Rio de Oro field does not cross or overlap with territory legally entitled to indigenous nor Afro-Colombian communities.

Operations

La Cortez, through its subsidiary Avante Colombia Inc., re-activated certain operating activities in the Puerto Barco Field in different areas. Social activities, such as meetings with the communities to inform about the Company’s plans and activities, have been conducted to ensure the different communities’ support to re-start operations in the field. On August 15, 2011, Phase I (La Gabarra town to the Puerto Barco Field / Timbas Station) road upgrades were initiated. However, due to very heavy rains (a typical rainy season in Colombia) it was impossible to continue doing road maintenance. Despite these problems, additional field information was gathered along with a technical inspection of the wells and production facilities. Certain technical contractors including General Electric, Fepco, SAR Energy and others visited the field to conduct selected tests and to assess the condition of certain wells (surface and subsurface) and facilities. The presence of these companies in this area demonstrates to Ecopetrol the results of the social work of the Company and the ability to conduct operation in critical areas. Based on the inspections, wellhead surface sections of the PB-2K well were replaced, and a plan was defined to test the PB-2K and PB-3K wells. However, due to road conditions it was not possible to install facilities to conduct a proper test in these two wells. Despite this situation, the Company conducted a short test in the PB-2K, successfully inducing this well in a manner sufficient to produce on natural flow and secure a sample. Oil characterization from the sample demonstrated that Puerto Barco Field production from the Aguardiente formation corresponds to high quality oil of 43.3⁰API with very low content of sulphur, salt and heavy metals.

The Company continues to be actively engaged with Ecopetrol regarding opportunities to amend the existing contract terms, though the final outcome of such discussions remains unknown at this point. We believe that the first well intervention in Puerto Barco-2 and Puerto Barco-3 wells has had made a favorable impression on Ecopetrol. A proposal for the modification of the existing contracts in Puerto Barco and Rio de Oro plus a new exploration and productin contract for the entire Rio de Oro block was presented to Ecopetrol on February 1, 2012. We anticipate a reply from Ecopetrol regarding our proposal early in the second quarter of 2012.

See Part I, “Business,” for information regarding contracts relevant to each block and the activities we have carried out on the Putumayo 4, Maranta, Rio de Oro and Puerto Barco blocks.

ITEM 3.

LEGAL PROCEEDINGS

From time to time, we may become involved in various lawsuits and legal proceedings that arise in the ordinary course of business. 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. There are currently no pending legal proceedings that we believe will have individually or in the aggregate, a material adverse effect on our business, financial condition or operating results. As far as we are aware, except as described below, no governmental authority is contemplating any proceeding to which we are a party or to which any of our properties is subject.

On October 25, 2010, the Alabama Securities Commission (“ASC”) issued a Cease and Desist (“C&D”) naming the Company and certain other parties. ASC alleged that securities in the Company’s 2010 private placement of units were sold to Alabama residents in violation of the Alabama securities laws, in that the securities were not sold by a broker dealer or registered representative who was registered in the State of Alabama. The Company has cooperated with the ASC and responded to the requests for information. As of April 15, 2012, the ASC has not taken any further action against the Company. Although there can be no assurance as to the ultimate outcome, based on information currently available, the Company believes the amount, or range, of reasonably possible losses (if any) in connection with this matter will not be material to its financial condition, results of operations or cash flows. The total proceeds received from these Alabama residents associated with the private placement of units were approximately $160,000.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

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 10, 2012, there were 46,467,849 shares of our common stock issued and outstanding, 15,515,203 shares issuable upon exercise of outstanding warrants and 2,634,000 shares issuable upon exercise of outstanding options. On that date, there were 95 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		Low

Fiscal Year Ending December 31, 2010:
First Quarter	$	4.03	$	2.40
Second Quarter		4.02		1.42
Third Quarter		1.90		1.50
Fourth Quarter		1.55		0.94

Fiscal Year Ending December 31, 2011:
First Quarter	$	1.37	$	0.55
Second Quarter		0.63		0.45
Third Quarter		0.46		0.17
Fourth Quarter		0.21		0.11

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.

Recent Sales of Unregistered Securities

Except as previously disclosed in Current Reports on Form 8-K that we have filed, we have not sold any of our equity securities during the period covered by this Report that were not registered under the Securities Act.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Except as described below, 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.

As previously reported, on July 28, 2011, our Chairman of the Board and Interim Chief Financial Officer, Nadine C. Smith, entered into a “Rule 10b5-1 Plan” to purchase shares of our common stock (the “Plan”). The Plan called for Ms. Smith to purchase shares of our common stock daily, commencing on August 1, 2011, at the prevailing market price (subject to a limit of $2.00 per share) over a period of up to twelve weeks, until a maximum of $175,000 worth of shares had been purchased. The purchases under the Plan were intended be carried out within the safe-harbor requirements of Rule 10b-18. The timing, volume, price and other limitations under Rule 10b-18 may have limited the number of shares purchased by Ms. Smith in any given week. Under the Plan, Ms. Smith purchased a total of 152,700 shares of our common stock for an aggregate purchase price of $38,989.50, of which 41,200 shares were purchased in the fourth quarter of 2011 for an average purchase price of $0.1793, as shown below:

Period	a) Total number of shares (or units) purchased		b) Average price paid per share (or unit)		c) Total number of shares (or units) purchased as part of publicly announced plans or programs		d) Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
Month 1 (Oct. 1-Oct. 31, 2011)		41,200	$	0.1793		41,200		-
Month 1 (Nov. 1-Nov. 30, 2011)		-		-		-		-
Month 1 (Dec. 1-Dec. 31, 2011)		-		-		-		-

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 stock¹ 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, 2011, we have granted option awards under the 2008 Equity Incentive Plan exercisable for a net aggregate amount of 2,634,000 shares of our common stock and restricted stock unit awards for 278,872 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.

The following table sets forth information about the Company’s equity compensation plans as of December 31, 2011:

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 (1)		2,912,872	$	1.87		1,087,128

Equity compensation plans not approved by security holders		-		-		-

Total		2,912,872	$	1.87		1,087,128

(1) 2008 Equity Incentive Plan.

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

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, and have established a corporate headquarters in Bogotá, Colombia. We have entered into two initial working interest agreements, with Petronorte and with Emerald, and have acquired a private company, Avante Colombia. We continue to diligently evaluate business opportunities such as potential mergers, farm-ins and farm-outs among others.

We were initially incorporated in the State of Nevada on June 9, 2006 under the name La Cortez Enterprises, Inc. to pursue certain business opportunities in Mexico¹. 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 our development activities, we have sustained losses and expect such losses to continue through at least the end of April 2013. We expect to finance our operations primarily through our existing cash and any future financings. However, there exists substantial doubt about our ability to continue as a going concern, because we will be required to obtain additional capital in the future to continue our operations, and there is no assurance that we 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 our ultimate capital needs and to support our growth. If adequate capital cannot be obtained on a timely basis and on satisfactory terms, our operations would be materially negatively impacted. Therefore, there is substantial doubt as to our ability to continue as a going concern for at least 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. Our ability to complete additional rounds of financing 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 offering terms. In addition, our ability to complete an offering may be dependent on the status of our oil and gas exploration activities, which cannot be predicted. There is no assurance that capital in any form will be available to us, and if available, on terms and conditions that are acceptable.

Our 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 this uncertainty.

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.

Recent Developments

We are exploring a number of options to address our liquidity situation. We have retained an investment banking firm to seek potential deals and assist our Board of Directors on the merits of proposals received. We are in discussions with potential investors regarding possible investments in our equity or debt securities, but to date conditions have not been favorable for such investments on acceptable terms. We have been and continue to be in discussion with various parties regarding potential corporate strategic transactions, such as potential mergers, farm-outs and sales of certain of our assets, and we have solicited and received various proposals. We are actively engaged in discussions with Ecopetrol regarding extension of the terms of the Rio de Oro and Puerto Barco production contracts, as described below under "Rio de Oro and Puerto Barco Fields”. However, at this time, no capital or strategic transaction has been approved by our Board, nor has any agreement been executed, and there can be no assurance that any such transaction will be successfully negotiated or consummated.

Maranta Block – Mirto Field

As of December 31, 2011, proved developed oil reserves in the Mirto field were estimated to be 86,112 bbls and probable reserves were estimated to be 149,592 bbls. Emerald Energy Plc. (“Emerald”), the operator of the Maranta Block, where we expect to hold a 20% working interest, completed drilling operations of the Mirto-2 exploratory well on August 15, 2010, after having conducted a sidetrack on the well to a “measured depth” (“MD”) of 11,590 feet. Mirto-2 production tests initiated on September 23, 2010, for a 5-day period on the Villeta U sand had an average production of 29 BOPD and water cut of 95.9%. The well was put back on an extended production test from October 16, 2010 until December 10, 2010. During that period, the well produced on average 89.08 bopd gross with an average water cut of 88.4%.

A workover job was carried out on the Mirto-2 well on January 2, 2011, in which the Villeta U sand was temporarily isolated and the Villeta N sand was perforated. Perforations were conducted between 10,586.5 and 10,597 feet depth (10.5' feet intervals). The well was put on a production test on January 9, 2011, with the following results: Average oil production over the testing period has been 549 bopd Gross (112 bopd net to La Cortez before royalties) with an average Base Sediment and Water (BS&W) of 1.78% over the same period. Total fluids production averaged approximately 596 bopd.

Emerald submitted a request to Agencia Nacional de Hidrocarburos (“ANH”) to approve the assignment of our 20% participating interest. On July 12, 2011, the Company was informed by Emerald that the request for transfer of the 20% interest was not approved because the ANH determined that the submitted information did not comply with the financial indicators and requirements demanded by the contract signed between the ANH and Emerald. The Company plans to discuss the financial information with the ANH, including the accounting for the derivative warrant instruments liability, and send a new request for the assignment. Non-approval by the ANH does not affect the current joint operating agreement between Emerald and La Cortez.The Maranta Block covers an area of 90,459 acres (36,608 hectares) in the foreland of the Putumayo Basin in Southwest Colombia. Emerald’s contract for this block was signed with the ANH on September 12, 2006.

A workover was conducted in the Mirto-1 well to isolate U reservoir and complete the N sandstone in the Villeta formation. Production commenced on August 23, 2011 keeping an average rate of some 330 bopd without water. This well had showed some electrical problems, with failures of the Electro Submergible Pump (ESP) stopping production in early October 2011, late December 2011 and late January 2012. At the time of this report, the well is producing 332 bopd. Cumulative production from the N sandstone is 55,742 bbls (gross) as of April 9, 2012. Mirto-1 produced from U Villeta sandstone a total of 41,514 bbls (gross) of oil in the period of Oct 1, 2009 until September 17, 2010. The U sandstone was isolated due to high water cut.

With the drilling of the Mirto-2 well, Phase 3 of the exploration program has been completed. Emerald and La Cortez have together complied with the exploration obligations on this block in accordance with the contract signed with the ANH. Under the contract terms and conditions, and after completion of this phase, both La Cortez and Emerald are required to relinquish 50% of the area of the block, as selected by both parties, and there is an option to continue exploration activities in the remaining 50% of the area by committing to additional exploration activity with the ANH, such as new seismic acquisition or drilling a new exploration well. This is a normal procedure and in accordance with the standard contract with the ANH. Emerald presented to the ANH the work commitments to be conducted in the remaining area of the Block. The potion to be relinquished is dependent on the results of the work to be conducted. The work commitment is either new seismic acquisition (120 km of 2D seismic) or the drilling of an exploration well, which has been accepted by the ANH.Emerald has received approval from the ANH, which was dated April 11, 2011, on the additional exploration program and has signed the amendment to the contract.

Phase 1 of the subsequent exploratory program requires both Emerald and La Cortez to complete the acquisition of 120 km of 2D seismic or the drilling of an exploration well on or before August 2012, with Phase 2 of the subsequent exploratory program requiring another acquisition of 120 km of 2D seismic or the drilling of an exploratory well on or before August 2014. Emerald and the Company are in the final stages of determining the activity plan for the year 2012, which will include drilling of at least one more exploration well. Emerald is proposing to the ANH the acceptance of Agapanto-1 well to be drilled in the first half of 2012 as the achiever of the first phase of the subsequent exploratory program in the Maranta Block. This exploratory well is being targeted to the Villeta formation N, U, and T sands, which are producing areas within the Mirto field. In addition to this well, Emerald and the Company are looking at other options such as running additional seismic and conducting a workover in an existing old well Umbria-1 to test the potential of the Villeta sandstones. These activities are contingent on the environmental license, a process that is being handled by the operator Emerald.

Putumayo-4 Block

Petroleos del Norte S.A. (“Petronorte”), a subsidiary of Petrolatina Energy Limited, as operator of the Block, and La Cortez have completed identification of the number and location of indigenous people and communities in the area along with representatives from the Ministry of the Interior. A total of seven communities were identified, and the consultation process with these communities has been initiated.An agreement has been reached with four communities and protocolization process has been completed. No agreement was reached with one community and the preconsultation process is ongoing with two other communities located in the south of the Block. Based on this information, the layout for the seismic acquisition has also been completed, resulting in a 2D seismic acquisition plan of some 105 km in the northern part of the Block, where at least two leads have been determined with the reprocessed seismic. We plan to initiate shooting of the first 105 km 2D seismic campaign in late April 2012, and the second 2D seismic acquisition of approximately 50 km in May 2012, upon completion of the preconsultation process with local communities. The preconsultation process was suspended for a period of seven months from December 2010 to July 2011 because no representative from the Colombian Ministry of Interior was available. This initial seismic phase will involve acquisition of 105 km of 2D seismic.

Petronorte filed a request with the ANH for the assignment of the 50% working interest in the Putumayo-4 Block to La Cortez.The ANH has advised that La Cortez needs to provide additional guarantees for the required investment for the first exploration phase. We are evaluating various options to decide whether to provide the additional guarantee or submit a new request later in 2012.

We and Petronorte are also continuing to work and consult with the local communities to enable us to spud the first exploration well early next year. In addition, an Environmental Impact Study (Estudio de Impacto Ambiental - EIA) is ongoing and, when completed, will be presented to the relevant authorities to obtain the necessary exploration well drilling license.

Under the terms of the contract signed with the ANH, we must complete the acquisition of at least 103 km of seismic, the drilling of an exploratory well and additional work for a value of $1.6 million before August 25, 2012, when the 3-year term of Phase I ends.We and Petronorte have requested the ANH to grant a suspension of the contract for a period of seven months due to problems encountered in the preconsultation process during 2010 and 2011. On February 23, 2012, the ANH approved a seven months and 5 days extension of Phase I.

The Putumayo 4 Block covers 51,333 hectares located in the Putumayo Basin.

Rio de Oro and Puerto Barco Fields

Through our subsidiary, Avante Colombia, as operator of the fields, and with our joint venture partner Vetra Exploración y Producción S.A. (“Vetra”), we continue to conduct social activities in the area covering Rio de Oro and Puerto Barco fields, and we completed a plan to re-initiate production operations on the Puerto Barco field during the third quarter of 2011. This plan included conducting workover activities in some of the existing wells, not only to determine the mechanical conditions, but also to gather geological information. In addition, the plan includes the upgrading of the production facilities as well as the access road. Old seismic has been reprocessed and is being evaluated. We have completed our technical evaluation in the Rio de Oro and Puerto Barco fields. We have also completed the program to re-initiate the Puerto Barco field early in 2013 in conjunction with Vetra. We have met with representatives from the local communities and with several local and regional government officials, and have performed a detailed evaluation of the current road conditions, which will allow us to determine cost and timing for the necessary road improvements.

Our technical evaluation identified several attractive workover opportunities, andas previously anticipated, the 2011 activity was concentrated on the re-establishment of production in the Puerto Barcofield’s PB-2 well. Activities were carried out at the end of the year in this field, and the Company conducted a field evaluation and test of a well. The well test resulted in oil produced at natural flow with 45 degree API gravity oil. No further test was conducted due to lack of production facilities at the site.

We have been in discussions with Ecopetrol with regards to contract terms and condition modifications, and we presented to Ecopetrol a proposal to commit to new investment in the area, which is being evaluated at this time.

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, 2011, Compared with Year Ended December 31, 2010

A summary of our results for years ended December 31, 2011 and 2010 is as follows:

							Percentage Increase /
	2011			2010			(Decrease)

Revenues	$	2,624,469		$	522,896			402	%
Costs and expenses		(17,688,544	)		(10,741,873	)		65	%
Non-operating income, net		7,329,145			5,971,498			23	%
Income tax expense		(39,399	)		(50,891	)		(23	)%
Net income (loss)	$	(7,774,329	)	$	(4,298,370	)		81	%

Revenues

We earned oil and gas revenues of $2,624,469 for the year ended December 31, 2011, compared to $522,896 for the year ended December 31, 2010. Increase was mainly due to higher volume produced, which in 2011 was 35,148 bbls and in 2010 was 7,530 bbls. These revenues were derived from our production operations in the Mirto-1 and Mirto-2 wells.

Costs and Expenses

Our operating costs and expenses for the year ended December 31, 2011 and 2010, consisted of the following:

					Percentage Increase /
	2011		2010		(Decrease)

Operating costs	$	1,072,940	$	1,554,325		(31	)%
Depreciation, depletion, accretion and amortization		1,187,678		297,896		299	%
Impairment of goodwill		5,591,422		-		100	%
Impairment of oil properties		4,201,385		3,563,417		18	%
General and administrative		5,635,119		5,326,235		6	%
Total	$	17,688,544	$	10,741,873		65	%

Operating Costs

Our operating costs for the year ended December 31, 2011, which pertain to our costs incurred in production activities for the Mirto-1 and Mirto-2 wells, amounted to $1,072,940 compared to $1,554,325 in year 2010. Decrease is mainly due to revisions to lease operating expenses received from the operator of the field.

Depreciation, Depletion, Accretion and Amortization Expenses

The increase in our depreciation, depletion, accretion and amortization expenses for the year ended December 31, 2011 as compared to 2010 was mainly due to the higher cost basis subject to depletion related to the impairment charge recorded in 2011.

Impairment Expense

The increase in impairment expenses is explained mainly by our assessment of the fair value of our oil properties and goodwill as of December 31, 2011. Our analysis indicates that the fair value of both was below their carrying values. We incurred a significant increase in impairment expense of oil properties for the year ended December 31, 2011 as compared to 2010. This was primarily due to a larger impairment of costs associated with unproved oil properties added to proved oil property costs during 2011 as compared 2010. For the year ended December 31, 2011 and 2010, we incurred impairment expense of $4,201,385 and $3,563,417, respectively, on our oil properties. Furthermore, as a result of the goodwill impairment assessment as of December 31, 2011, we recorded an impairment loss amounting to $5,591,422. No goodwill was impaired for the year ended December 31, 2010. See “Liquidity and Capital Resources” below for more information on the impairment expenses.

General and Administrative Expenses

We incurred total general and administrative expenses of $5,635,119 for the year ended December 31, 2011 compared to $ 5,326,235 for the year ended December 31, 2010. The increase was primarily due to the equity-based taxeffective January 1, 2011 by the Colombian tax authorities on all Colombian entities for the amount of $779,419, which was partially offset by a decrease in professional fees in the amount of $472,072.

Non-Operating Income, Net

Net non-operating income for the year ended December 31, 2011, was $7,329,145, compared to net non-operating income of $5,971,498 for the year ended December 31, 2010. The increase is primarily due to the recognition of an unrealized gain from the decrease in the fair value of derivative warrant instruments liability of $7,356,543 during the year ended December 31, 2011 compared to an unrealized gain of $5,809,716 during the year ended December 31, 2010. The derivative liability decreased due to the Company’s declining stock price.

Net loss

Net loss for the year ended December 31, 2011, was $7,774,329 compared to a net loss of $4,298,370 for the year ended December 31, 2010. The change is primarily due to an increase in revenues of $2,101,573 as a result of a full year of production in 2011 compared to only a few months of production in 2010; impairment of $4,201,385 of oil properties in 2011 compared to a $3,563,417 impairment charge in 2010; impairment of goodwill of $5,591,422 compared to $0 in 2010; and an unrealized gain on fair value of derivative warrant instruments of $7,356,543 in 2011 compared to an unrealized gain of $5,809,716 in 2010.

Adjusted EBITDA

In evaluating our business, we consider earnings before interest income, interest expense, income taxes, depreciation, depletion, accretion and amortization, impairment of oil properties, impairment of goodwill, stock-based compensation expense, common stock issued for services, and unrealized gains and losses on fair value of derivative warrant instruments (“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 or loss from operations or cash used in operations as presented in our consolidated 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 or loss from operations, or cash used in operations determined under U.S. generally accepted accounting principles (“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 for the years ended December 31, 2011 and 2010 is calculated as follows:

	Year ended December 31,
	2011			2010

Net loss	$	(7,774,329	)	$	(4,298,370	)
Adjustments:
Depreciation, depletion, accretion and amortization		1,187,678			297,896
Income taxes		39,399			50,891
Impairment of goodwill		5,591,422			-
Impairment of oil properties		4,201,385			3,563,417
Unrealized gain on fair value of derivative warrant instruments, net		(7,356,543	)		(5,809,716	)
Common stock issued for services		109,013			297,750
Stock-based compensation expense		564,632			742,548
Interest income		(106,395	)		(161,782	)
Interest expense		133,793			-
Adjusted EBITDA	$	(3,409,945	)	$	(5,317,366	)

Adjusted EBITDA for the year ended December 31, 2011, was a loss of $3.4 million, compared to a loss of $5.3 million for the year ended December 31, 2010. The decrease in the loss was primarilydue to the increase in our revenues for the year ended December 31, 2011 as compared to2010.

Liquidity and Capital Resources

Our cash and cash equivalents balance as of April 10, 2012, was $2,289,010, compared to $4,180,771 at December 31, 2011, and $8,327,020 as of December 31, 2010. The decrease in cash and cash equivalents from December 31, 2011 through April 10, 2012 was due to $1.4 million of cash used in operating activities (partially offset by $0.5 million of cash received from sales of oil) and $1.0 million of cash used in investing activities subsequent to December 31, 2011. The decrease as of December 31, 2011 as compared to December 31, 2010 was due to $5.2 million of cash used in operating activities (partially offset by $2.3 million of cash received from sales of oil) and $1.2 million of cash used in investing activities from December 31, 2010 to December 31, 2011.

Our total cash capital requirements for the remainder of 2012 are anticipated to be approximately $14.2 million. We are currently utilizing cash of approximately $0.46 million per month in our 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.

On March 30, 2012, we made the first required payment of $600,000 in respect of the acquisition of Phase 1 2D seismic on the Putumayo-4 Block, and have agreed to fund an additional $1.32 million for that purpose by the end of April or May, 2012. On the Maranta Block, we expect the operator to make a cash call on us by May-June, 2012 of $1.71 million for the drilling of the Agapanto-1 well and $0.70 million for the construction of production facilities.

Over the reminder of 2012, we expect to use our cash and cash equivalents for the following purposes in addition to the immediate requirements as stated above:

approximately $3.29 million to bear our share of commitments with respect to the Putumayo-4 Block, related to Phase 1 seismic acquisition, permitting activities and exploration activities;

approximately $2.56 million for our share of the costs on the Maranta Block for drilling the Agapanto-1 well, which is located 1.7 km south of Mirto-1 and Mirto-2, the community consultation for the acquisition of additional seismic;

approximately $0.30 million for community and social programs in the Catatumbo area; and

up to an additional $4.32 million to cover our administrative expenses and for general working capital to continue to execute our business plan and build our operations, this amount includes a provision for a potential transaction cost of $ 0.75 million and approximately $ 0.66 million for tax payments.

With our cash and cash equivalents on hand, we will require additional capital by the end of May, 2012. We currently 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.

We may seek to raise additional funds through public or private sale of our equity or debt securities, borrowing funds from private or institutional lenders, the sale of our interests in the Putumayo-4 (Petronorte), Maranta (Emerald), Rio de Oro or Puerto Barco projects, or a sale of the Company. If we raise additional funds through the issuance of debt securities, these securities would have rights that are senior to holders of our common stock and could contain covenants that restrict our operations. Any additional equity financing would likely be substantially dilutive to our stockholders, particularly given the prices at which our common stock has been recently trading. In addition, if we raise additional funds through the sale of equity securities, new investors could have rights superior to our existing stockholders. 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.

If we raise funds through a farm-out or sale of any of our rights in Putumayo-4, Maranta, Rio de Oro or Puerto Barco projects, we may be required to relinquish, on terms that are not favorable to us, our interests in those projects. Our need to raise capital soon may require us to accept terms that may harm our business or be disadvantageous to our current stockholders, particularly in light of the current illiquidity. There can be no assurance that we will be successful in obtaining additional funding, or selling or farming-out assets, in sufficient amounts or on terms acceptable to us, if at all. Additionally, our ability to sell or farm-out our rights under our existing joint operating agreements is subject to rights of first refusal or similar rights of our joint venture partners.

We are exploring a number of options to address our liquidity situation. We continue to have conversations with potential investors regarding possible investments in our equity or debt securities, but to date conditions have not been favorable for such investments on acceptable terms. We have been and continue to be in discussion with various parties regarding potential corporate strategic transactions, such as potential mergers, farm-outs among others, and we have solicited and received various proposals. In this regard, we have retained an investment banking firm to advise our Board of Directors regarding the merits of various proposals. However, at this time no capital or strategic transaction has been approved by our Board, nor has any agreement been executed, and there can be no assurance that any such transaction will be successfully negotiated or consummated.

If adequate capital cannot be obtained on a timely basis and on satisfactory terms, our operations would be materially negatively impacted. Therefore, there is substantial doubt as to our ability to continue as a going concern for at least 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 consolidated financial statements do not include any adjustments relating to the recoverability of the recorded assets or the classification of liabilities that would be necessary that the Company be unable to continue as a going concern.

Our ability to obtain additional financing is dependent on the state of the debt and/or equity markets, and such markets’ reception of the Company and offering terms. In addition, our ability to obtain financing may be dependent on the status of our oil and gas exploration activities, which cannot be predicted. There is no assurance that capital in any form will be available to us, and if available, that it will be on terms and conditions that are acceptable.

For further discussion on substantial doubt about the Company continuing as a going concern, please see Overview and Going Concern section above.

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 be used for other corporate purposes during the life of the guarantee. These funds will be available for use after we fulfill our commitments within the E&P contract, which we estimate will occur in the first quarter of 2013. If we do not fulfill our commitments under the E&P contract, such escrowed funds will be subject to forfeiture.

In accordance with the terms of the Maranta farm-in agreement, we have borne 65% ($1.2 million) of the $1.8 million Mirto-1 completion costs. We made this $1.2 million payment to Emerald on July 27, 2009. Additional Phase 2 costs were paid by us as needed, following cash calls by Emerald, as follows: $948,044 for seismic on the Mirto-1 well (equivalent to 60% share) and $7,167,262 for drilling on the Mirto-1 well (equivalent to 65% share), totaling $8,115,306. With Phase 2 work completed, we will pay 20% of all subsequent costs related to the Maranta Block.

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. Accordingly, 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 the joint venture goes forward.

Since costs on certain of our projects are calculated in Colombian pesos, changes in the exchange rate, among other things, could cause our capital commitments in U.S. dollars to differ from the amounts that we have budgeted. We have not to date engaged in any formal hedging activity with regard to foreign currency risk. However, a foreign exchange gain/loss must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $0.0005 for each one-peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

In the course of our development activities, we have sustained losses and expect such losses to continue through at least April 2013.

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 that 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:

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 that 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 and effects of purchase price allocations.

Property and equipment, net

Oil properties

The Company follows the full cost method of accounting for its oil 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 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, in which case the gain or loss is recognized in the statement of operations.

Depletion of capitalized oil 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 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 un-escalated 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, 2011 and 2010, the Company has properties in the amount of $5,111,473 and $11,897,508, respectively, which 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. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented.

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. DeGolyer and MacNaughton 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. The estimate of the Company’s proved reserves as of December 31, 2011 and 2010 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.

Goodwill

In accordance with guidance of the Financial Accounting Standards Board (“FASB”) ASC - Topic no. 350-10,Goodwill and Other, the Company tests goodwill for impairment in the first quarter of each fiscal year or at any other time when impairment indicators exist by comparing the fair value of the reporting unit, generally based on discounted future cash flows, with its carrying amount including goodwill. Examples of such indicators, which would cause the Company to test goodwill for impairment between annual tests, include a significant change in the business climate, significant unexpected competition, significant deterioration in the Company’s market capitalization or available funding options, and/or a loss of key personnel. If goodwill is determined to be impaired, the loss is measured by the excess of the carrying amount of the reporting unit over its fair value. As a result of the goodwill impairment assessment as of December 31, 2011, the Company recorded an impairment loss amounting to $5,591,422 for the year ended December 31, 2011.

Warrant Derivative Instruments

We account for warrant derivative instruments under the provisions of FASB ASC Topic No. 815 – 40,Derivatives and Hedging - Contracts in Entity’s Own Stock. This FASB ASC Topic’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 cannot 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. We evaluated whether warrants issued during various private placement offerings contained provisions that protect holders from declines in the Company’s stock price or otherwise could result 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 fair value of a “fixed-for-fixed” option as defined under FASB ASC Topic No. 815 – 40.

In accordance with FASB ASC Topic No. 815 – 40, we recognized the warrants that contain these down round provisions as liabilities at their respective fair values on each reporting date. FASB ASC Topic No. 815 – 40 also requires that such instruments be measured at fair value at each reporting period.

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 Give proper title, 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.

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, 2011 and 2010. 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,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 and warrants 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 operations exists, 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.

Fair value of financial instruments

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

Reporting and Functional Currency

The U.S. dollar is the functional currency for the Company’s operations related to its subsidiaries in Colombia. The Company has adopted Accounting Standard Codification (“ASC”) Topic 830,Foreign Currency Matters, which requires that the translation of the applicable foreign currency into U.S. dollars be performed for balance sheet monetary accounts using current exchange rates in effect at the balance sheet date, non-monetary accounts using historical exchange rates in effect at the time the transaction occurs, and for revenue and expense accounts using a weighted average exchange rate during the period reported. Accordingly, the gains or losses resulting from such translation are included in general and administrative expense in the consolidated statements of operations.

New Accounting Pronouncements

In September 2011, the FASB issued ASU No. 2011-08,Intangibles — Goodwill and Other. ASU 2011-08 allows a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill impairment test. If it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the two-step impairment test for that reporting unit would be performed. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption was permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011, if an entity’s financial statements for the most recent annual or interim period have not yet been issued.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

Our audited consolidated financial statements as of and for the years ended December 31, 2011 and 2010 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.

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, 2011. 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 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.

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. Management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Interim Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2011, 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). Based on our evaluation under the framework in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2011. 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 accounting firm pursuant to §989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which exempts smaller reporting companies from the requirement that they include an attestation report of the Company’s registered public accounting firm regarding management’s assessment of internal controls over financial reporting.

Officers’ Certifications

Appearing as exhibits to this Annual Report are “Certifications” of our Chief Executive Officer and Interim 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 formalized internal review procedures in an effort to ensure that our consolidated financial statements accurately reflect our financial condition and results of operations.

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	54	Director and Chairman of the Board, Vice President and Interim Chief Financial Officer	February 7, 2008

Andrés Gutierrez Rivera	53	President, Chief Executive Officer and Director	June 1, 2008

Dirk J. H. Groen	67	Director	August 17, 2011

José Fernando Montoya Carrillo	58	Director	October 15, 2008

Jaime Navas Gaona	73	Director	July 23, 2008

Jaime Ruiz Llano	57	Director	July 1, 2008

Richard G. Stevens	65	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 information on each officer and director of the Company are set forth below.

Nadine C. Smithbecame 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.

From November 2008 to May 2011, Ms. Smith served 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. Ms. Smith has previously served as a founding director of Gran Tierra Energy, Inc., an oil and gas exploration and production company operating in South America, Patterson-UTI Energy Inc., American Retirement Corporation and Loreto Resources Corporation, all public companies. Ms. Smith has been a private investor and business consultant since 1990.

Ms. Smith received a Bachelor of Arts degree in economics from Smith College and a Master of Business Administration degree from Yale University.

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.

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.

Dirk J. H. Groenhas been Chief Executive Officer of Avante since 2006. From 2005 to 2009, Mr. Groen was a member of the Supervisory Board of Getronics N.V., one of the largest information technology companies in the Netherlands, until it was acquired by KPN in 2009. From 2006 to 2010, Mr. Groen was Chairman of the Supervisory Board of Royal Sanders B.V., a company engaged in the production of personal care products. In 2010 Royal Sanders was acquired by a private equity company; Mr. Groen continues to be a member of its Supervisory Board. Mr. Groen is a graduate of Nyenrode Business University in the Netherlands and St. Gall University in Switzerland.

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 Bachelor’s 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.

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.

Mr. Stevens was the lead independent director of Chordiant Software, Inc. until Chordiant's sale in April 2010. 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.

Non-Executive Senior Management

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

Operations and Production Manager – Luis Eduardo Goyeneche: Mr. Goyeneche is an experienced Reservoir Engineer with more than 25 years of oil and gas experience. Most recently, from 2008 to mid-2011, Mr. Goyeneche served as both the Operations Manager and Business Development and Procurement Manager for Columbus Energy Sucursal Colombia, a private oil and gas company backed by private equity firm First Reserve and Nabors Industries, the largest land drilling company in the world. Prior to joining Columbus Energy, Mr. Goyeneche was employed by Hocol, S.A. in various posts from 1986 thru 2008. Positions included Senior Reserve Engineer (1997-2001), Palermo Association Manager (2001-2007) and most recently Appraisal Manager, where he was responsible for the evaluation and development of Hocol, S.A.’s new fields. Mr. Goyeneche has a B.Sc. in Petroleum Engineering from the Universidad de America in Bogotá.

Exploration Manager - 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 Master’s degree in Geology from the National University of Colombia.

Financial Manager – Waldo Maticorena: Mr. Maticorena has over 10 years of experience in auditing multi industry companies including oil and gas and mining. Prior to joining La Cortez, he worked for PricewaterhouseCoopers as Advisory Manager in internal controls in Colombia and Canada. Mr. Maticorena holds a Bachelor’s Degree in Public Accounting from the Ricardo Palma University and an MBA from ESAN, both in Peru.

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 seven 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. The non-independent members of the Board of Directors are Ms. Smith and Mr. Gutierrez by virtue of their positions as executive officers of the Company and Mr. Groen by virtue of his relationship with Avante and Avante's stock ownership in the Company. Ms. Smith is the Chairman of the Board.

Board of Directors

The Board of Directors is comprised of seven directors. As stated above, majority of the Board of Directors are independent.

Management has been delegated the responsibility for meeting defined corporate objectives, implementing approved strategic and operating plans, carrying on the Company's business in the ordinary course, managing cash flow, evaluating new business opportunities, recruiting staff and complying with applicable regulatory requirements. The Board of Directors exercises its supervision over management by reviewing and approving long-term strategic, business and capital plans, material contracts and business transactions, and all debt and equity financing transactions.

Code of Ethics

During the fiscal year ended December 31, 2010, we adopted a Code of Ethics and Business Conduct (“Code of Ethics”) for our employees, officers and directors that complies with SEC regulations. The Code of Ethics is available free of charge on our website atwww.lacortezenergy.com. We intend to timely disclose any amendments to, or waivers from, our code of ethics and business conduct that are required to be publicly disclosed pursuant to rules of the SEC and any securities exchange on which our shares may be listed by filing such amendment or waiver with the SEC.

Committees and Meetings

The Board of Directors has an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. The Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee are each governed by a specific charter, each of which is available on our website at lacortezenergy.com, and all members of these committees are independent directors. In determining the independence of directors, we have referred to the NYSE Amex’s independence standards as well as the SEC requirements for independence of directors on the Audit Committee. Compliance with these requirements is reviewed annually by the Nominating and Corporate Governance Committee.

The Board has at least one regularly scheduled meeting per year. In addition, the Board holds special meetings whenever requested by either the Chairman of the Board, the President, any Vice President or by any two or more directors. The Audit Committee has no less than one meeting per quarter. In addition, special meetings of the Board or any Committee may be called from time to time as determined by the needs of the business.

During fiscal 2011, the Board of Directors held nine meetings, and took action by unanimous written consent in lieu of a meeting one time. During 2011, except as described in the following sentence, each director attended at least 75% of the aggregate of (i) the total number of meetings of the board of directors (held during the period for which he or she has been a director); and (ii) the total number of meetings held by all committees of the board on which he or she served (during the periods that he or she served). Mr. Berger was absent for two of five such meetings, and Mr. Groen was unable to attend the first two meetings immediately after his appointment (out of a total of four such meetings).

Director Attendance at Annual Meetings

Each of our directors is expected to be present at annual meetings of our stockholders absent exigent circumstances that prevent their attendance. Where a director is unable to attend an annual meeting in person but is able to do so by electronic conferencing, we will arrange for the director's participation by means where the director can hear, and be heard by, those present at the meeting. Last year, we did not hold an annual meeting.

Audit Committee

The purpose of the Audit Committee of the Board of Directors is to represent and assist the Board in monitoring (i) accounting, auditing, and financial reporting processes; (ii) the integrity of our financial statements; (iii) our internal controls and procedures designed to promote compliance with accounting standards and applicable laws and regulations; and (iv) the appointment of and evaluating the qualifications and independence of our independent registered public accounting firm. The Audit Committee's specific responsibilities are set forth in its charter, a copy of which is set forth in Appendix C to this Listing Application. The Audit Committee currently consists of Richard G. Stevens (Chairman) and Jaime Ruiz Llano. José Fernando Montoya Carrillo also served on the Audit Committee until his resignation, effective May 20, 2011. Each person who served on the Audit Committee during fiscal 2011 is financially literate under the current listing standards of the NYSE AMEX. and has been determined by the Board of Directors to be independent. The Audit Committee met four times in 2011. The Board also determined that Mr. Stevens qualifies as an “audit committee financial expert” as defined by the SEC rules adopted pursuant to the Sarbanes-Oxley Act of 2002.

All directors comprising the Audit Committee have held various executive management positions in which they were responsible for receiving financial information relating to the entities to which they were executive managers. They had, or developed, an understanding of financial statements generally and how those statements are used to assess the financial position of a company and its operating results. Each member of the Audit Committee also has a significant understanding of the business in which the Company is engaged in and has an appreciation for the relevant accounting principles for the business of the Company. In addition, 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. See “Directors and Executive Officers” for descriptions of the relevant education and experience of each member of the Audit Committee.

At no time since the commencement of the Company's most recently completed financial year was a recommendation of the Audit Committee to nominate or compensate an external auditor not adopted by the Board of Directors.

The Audit Committee is responsible for the oversight of the Company's financial reporting process on behalf of the Board of Directors and such other matters as specified in the Committee's charter or as directed by the Board. 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 (or to nominate the independent registered public accounting firm for stockholder approval), 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 and terms thereof) to be performed by our independent auditors, in accordance with applicable laws, rules and regulations.

AUDIT COMMITTEE REPORT

The Audit Committee of the Company’s Board of Directors is composed of three independent directors and operates under a written charter adopted by the Board of Directors. The Audit Committee is responsible for the selection of the Company’s independent registered public accounting firm.

Management is responsible for the Company’s internal controls, the financial reporting process and preparation of the consolidated financial statements of the Company. The independent registered public accounting firm is responsible for performing an independent audit of the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States) and to issue a report thereon. The Audit Committee’s responsibility is to monitor and oversee these processes. In carrying out its duties, the Committee relies in part on the information provided to it, and on the representations made to it, by management and the independent registered public accounting firm. It should be noted that the Committee members are not professionally engaged in the practice of accounting or auditing.

In this context, the Committee has met and held discussions with management and the independent registered public accounting firm. Management represented to the Audit Committee that the Company’s consolidated financial statements were prepared in accordance with generally accepted accounting principles. The Audit Committee reviewed and discussed the consolidated financial statements with management and the independent registered public accounting firm. The Audit Committee further discussed with the independent registered public accounting firm the matters required to be discussed by Statement on Auditing Standards No. 61 (Communication with Audit Committees), as amended, and as adopted by the Public Company Accounting Oversight Board in Rule 3200T.

The Company’s independent registered public accounting firm also provided to the Audit Committee the written disclosures and letter required by Independence Standards Board Standard No. 1 (Independence Discussions with Audit Committees), and as adopted by the Public Company Accounting Oversight Board, and the Audit Committee discussed with the independent registered public accounting firm that firm’s independence.

Based upon the Audit Committee’s discussions with management and the independent registered public accounting firm and the Audit Committee’s review of the representations of management and the reports and letter of the independent registered public accounting firm provided to the Audit Committee, the Audit Committee recommended to the Board of Directors that the audited consolidated financial statements be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, for filing with the Securities and Exchange Commission.

	Audit Committee:

	Richard G. Stevens (Chairman)
	Jaime Ruiz Llano

	April 16, 2012

Compensation Committee

The purpose of the Compensation Committee of the Board of Directors with respect to compensation of our executive officers and directors is (i) to assist the Board in discharging its responsibilities with respect to compensation of our executive officers and directors, (ii) to evaluate the performance of our executive officers, (iii) to assist the Board in developing succession plans for executive officers and (iv) to administer our stock and incentive compensation plans and recommend changes in such plans to the Board as needed. The Compensation Committee establishes the compensation of senior executives on an annual basis. The Compensation Committee currently consists of José Fernando Montoya Carrillo (Chairman), Dirk J. H. Groen, and Jaime Ruiz Llano.

Alexander Berger served on the Compensation Committee until his resignation effective August 17, 2011, at which time Mr. Groen was appointed to fill the vacancy thereon. Each person who served on the Compensation Committee during fiscal 2011 has been determined by the Board of Directors to be independent under the NYSE Amex listing standards. The Compensation Committee met one time during 2011.

Nominating and Corporate Governance Committee

The purpose of the Nominating and Corporate Governance Committee of the Board of Directors is to assist the Board in identifying qualified individuals to become Board members, in determining the composition of the Board and its committees, in monitoring a process to assess Board effectiveness and in developing and implementing corporate procedures and policies. The Nominating and Corporate Governance Committee currently consists of Jaime Ruiz Llano (Chairman), Dirk J. H. Groen, and Richard G. Stevens. Alexander Berger served on the Nominating and Corporate Governance Committee until his resignation effective August 17, 2011, at which time Mr. Groen was appointed to fill the vacancy thereon. Each person who served on the Nominating and Corporate Governance Committee during fiscal 2011 has been determined by the Board of Directors to be independent under the NYSE Amex listing standards.

The entire Board is responsible for nominating members for election to the Board and for filling vacancies on the Board that may occur between annual meetings of the stockholders. The Nominating and Corporate Governance Committee is responsible for identifying, screening, and recommending candidates to the entire Board for prospective Board membership. When formulating its Board membership recommendations, the Nominating and Corporate Governance Committee also considers any qualified candidate for an open board position timely submitted by our stockholders in accordance with our established procedures.

The Nominating and Corporate Governance Committee will consider stockholder recommendations of candidates when the recommendations are properly submitted. Stockholder recommendations should be submitted to us under the procedures discussed in “Procedures For Security Holder Submission of Nominating Recommendations,” which is available on our website atwww.lacortezenergy.com. Written notice of any nomination must be timely delivered to La Cortez Energy, Inc., Calle 67 #7-35, Oficina 409, Bogota, Colombia, or c/o Gottbetter & Partners, LLP, 488 Madison Avenue, 12th Floor, New York, NY 10025, Attention: Nominating and Corporate Governance Committee, c/o Chief Executive Officer.

The Nominating and Corporate Governance Committee will evaluate and recommend candidates for membership on the Board of Directors consistent with criteria established by the Committee. When considering a potential non-incumbent candidate, the Nominating and Corporate Governance Committee will factor into its determination the following qualities of a candidate: professional experience, including whether the person is a current or former Chief Executive Officer or Chief Financial Officer of a public company, integrity, professional reputation, independence and ability to represent the best interests of our stockholders.

The Nominating and Corporate Governance Committee uses a variety of methods for identifying and evaluating non-incumbent candidates for director. The Nominating and Corporate Governance Committee regularly assesses the appropriate size and composition of the Board, the needs of the Board and the respective committees of the Board and the qualifications of candidates in light of these needs. The Committee will solicit recommendations for nominees from persons that the Committee believes are likely to be familiar with qualified candidates, including members of the Board, our management or a professional search firm. The evaluation of these candidates may be based solely upon information provided to the committee or may also include discussions with persons familiar with the candidate, an interview of the candidate or other actions the committee deems appropriate, including the use of third parties to review candidates. The Nominating and Corporate Governance Committee did not meet during 2011.

Evaluation and Reserves Committee

In October 2008, our Board of Directors, by unanimous consent, established an Evaluation and Reserves Committee. The members of this committee are Messrs. Gutierrez, Montoya and Navas (Chairman). 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.

Stockholder Communication with the Board

Stockholders may communicate with the Board of Directors, members of particular committees or individual directors, by sending a letter to such persons in care of our Chief Executive Officer at our principal executive offices. The Chief Executive Officer has the authority to disregard any inappropriate communications or to take other appropriate actions with respect to any inappropriate communications. If deemed an appropriate communication, the Chief Executive Officer will submit the correspondence to the Chairman of the Board or to any committee or specific director to whom the correspondence is directed. Procedures for sending communications to the Board of Directors can be found on our website at lacortezenergy.com, by clicking on the Company Overview link, then the Corporate Governance link. Please note that all such communications must be accompanied by a statement of the type and amount of our securities that the person holds; any special interest, meaning an interest that is not derived from the proponent's capacity as a shareholder, of the person in the subject matter of the communication; and the address, telephone number and e-mail address, if any, of the person submitting the communication.

Compliance with Section 16(a) of the Exchange Act

Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to the Company under Rule 16a-3(e) under the Exchange Act during its most recent fiscal year and Forms 5 and amendments thereto furnished to the Company with respect to its most recent fiscal year, and any written representation to the Company from the reporting person that no Form 5 is required, no person who, at any time during the fiscal year, was a director, officer, beneficial owner of more than ten percent of the Company’s common stock, or any other person known to the Company to be subject to section 16 of the Exchange Act with respect to the Company, failed to file on a timely basis, as disclosed in the above Forms, reports required by section 16(a) of the Exchange Act during the most recent fiscal year or prior fiscal years, except as described below:

Name	Number of late reports	Number of transactions that were not reported on a timely basis	Failure to file a required Form

Nadine C. Smith	2	3	-
Andrés Gutierrez Rivera	-	-	-
Alexander F. D. Berger	-	-	-
Dirk J. H. Groen	2	2	-
José Fernando Montoya Carrillo	-	-	-
Jaime Navas Gaona	-	-	-
Jaime Ruiz Llano	-	-	-
Richard G. Stevens	-	-	-

On March 31, 2011, Ms. Smith filed a Form 4 reporting two transactions that occurred on March 2, 2010. On May 2, 2011, Ms. Smith filed a Form 4 reporting a transaction that occurred on April 27, 2011. On March 26, 2012, Mr. Groen filed a Form 3 relating to his appointment as a director on August 17, 2011, and a Form 4 reporting two transactions that occurred on November 17, 2011, and December 13, 2011.

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, 2011 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 years ended December 31, 2011 and 2010; (ii) all individuals that served as our principal financial officer or acted in a similar capacity for us at any time during the fiscal years ended December 31, 2011 and 2010; and (iii) all individuals that served as executive officers of ours at any time during the fiscal years ended December 31, 2011 and 2010 that received annual compensation during the fiscal years ended December 31, 2011 and 2010 in excess of $100,000. The Compensation Committee of the Board of Directors is responsible for determining executive compensation.

Summary Compensation Table

Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards ($)		Non- Equity Incentive Plan Compensa- tion ($)		Change in Pension Value and Non- qualified Deferred Compensation Earnings ($)		All Other Compensation ($)		Total ($)

Andrés Gutierrez Rivera, Chief Executive Officer (1)		2011	$	250,000	$	125,000	$	-		-		-		-	$	800-	$	375,800
		2010	$	250,000	$	125,000	$	72,338		-		-		-		-	$	447,338
Nadine C. Smith, Vice President and Interim Chief Financial Officer (2)		2011	$	20,000		-		-		-		-		-		-	$	20,000
		2010		-		-	$	146,624		-		-		-		-	$	146,624

(1)

On September 23, 2010, the Board of Directors approved an award to Mr. Gutierrez of 43,169 restricted stock units (“RSUs”) under the Company’s 2008 Equity Incentive Plan (valued for purposes of this disclosure at the grant date fair value of $1.68 per RSU based on the provisions of ASC Topic 718, “Stock-Based Compensation” (“ASC Topic 718”)). These RSUs vest in 1/3 increments on each of the first three anniversaries of the date of grant. Other compensation in 2011 consists of life insurance premiums paid by the Company for R. Gutierrez’s benefit.

Also in 2010, a bonus was paid to Mr. Gutierrez for 2009, consisting of $62,500 in cash and 43,169 fully vested restricted shares of common stock (valued for purposes of this disclosure at the grant date fair value of $1.20 per share based on the provisions of ASC Topic 718). The Board determined the amount of the bonus as follows: an amount equal to 50% of Mr. Gutierrez’s 2009 base salary, to be paid (a) 50% in cash and (b) as an award of immediately vested restricted common stock having a value equal to 50% of such bonus (calculated at the volume weighted average price per share of the common stock as traded on the OTC Bulletin Board for the three month period ending on the date of the award, discounted by 15%, which the Board determined to be the fair market value as of that date).

No bonus has yet been determined by the Board or paid to Mr. Gutierrez for 2011 and 2010; however, we have accrued $125,000 in each of the years 2011 and 2010 in bonus compensation, totaling to a bonus compensation payable of $250,000 and $125,000 at December 31, 2011 and 2010, respectively. Mr. Gutierrez received a bonus of $72,915 for 2008, which was not paid until 2010 and is not included in the table above

(2)

Ms. Smith received no equity compensation in her capacities as Vice President and Interim Chief Financial Officer until November 2011. Starting in December 2011, we compensated Ms. Smith $20,000 per month, in accordance with a letter agreement effective December 1, 2011. On September 23, 2010, the Board of Directors approved an award to Ms. Smith, in her capacity as director and Chairman of the Board, of 87,500 RSUs under the Company’s 2008 Equity Incentive Plan (valued for purposes of this disclosure at the grant date fair value of $1.68 per RSU based on the provisions of ASC Topic 718). These RSUs vest in 1/3 increments on each of the first three anniversaries of the date of grant.

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. Starting in December 2011, we are compensating Ms. Nadine C. Smith for her services as our interim Chief Financial Officer in accordance with a letter agreement effective December 1, 2011. 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.

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, 2011.

Option Awards
Name	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		1,000,000		-		-		2.20	July 1, 2018

Nadine Smith, Vice President and Interim Chief Financial Officer (1)		175,000		-		-		2.20	July 1, 2018

(1)	Ms. Smith received no equity 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.

Stock Awards
Name	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($) (1)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (#)
Andrés Gutierrez Rivera, Chief Executive Officer (2)		28,779	$	3,166		-		-

Nadine Smith, Vice President and Interim Chief Financial Officer (3)		58,333		6,417		-		-

(1)

Based on the closing market price of the Company’s common stock of $0.11 on December 31, 2011.

(2)

On September 23, 2010, the Board of Directors approved an award to Mr. Gutierrez of 43,169 RSUs under the Corporation’s 2008 Equity Incentive Plan. These RSUs vest in 1/3 increments on each of the first three anniversaries of the date of grant.

(3)

On September 23, 2010, the Board of Directors approved an award to Ms. Smith of 87,500 RSUs under the Corporation’s 2008 Equity Incentive Plan. These RSUs vest in 1/3 increments on each of the first three anniversaries of the date of grant.

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”).

No milestones were established for the years ending December 31, 2008 or 2009. Bonuses were paid to Mr. Gutierrez of $125,000 in cash for 2008 and $62,500 in cash and $62,500 in shares of common stock for 2009. As of December 31, 2011, we had accrued a bonus payable to Mr. Gutierrez in the amount of $250,000 related to Mr. Gutierrez’s performance during fiscal years 2011 and 2010, but no 2011 and 2010 bonus has yet been established by the Board of Directors.

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 of $2.20.

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 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 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.

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.

The Company entered into a letter agreement with Ms. Smith in December 2011, pursuant to which, effective December 1, 2011, we pay Ms. Smith $20,000 per month (prorated for any portion of a month; provided that if the Board of Directors determines to terminate her service as Interim Chief Financial Officer during any calendar month, we must pay her the full $20,000 for that month), payable in arrears, and subject to all required withholdings, until such time as we retain a permanent Chief Financial Officer or either our Board of Directors or Ms. Smith determines to terminate her service to us as Interim Chief Financial Officer.

Compensation of Non-Employee Directors

Our Board of Directors currently consists of five 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 directors⁵. This compensation package provided 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 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 received annual cash compensation of $12,000. The chairman of the Audit Committee also received additional annual compensation of $15,000 and the chairmen of the Compensation, Reserves and Nominating and Corporate Governance Committees of our Board of Directors (when formed) would also each receive additional annual cash compensation of $5,000. Each non-employee director would receive $1,000 for attendance at each committee meeting of the Board of Directors, or $500 for telephonic attendance. Directors were also reimbursed for reasonable out-of-pocket expenses incurred in attending Board of Directors and committee meetings.

On September 23, 2010, Our Board of Directors approved a revised compensation package for our non-employee directors⁶. Each new non-employee director will be granted stock options to purchase 100,000 shares of common stock upon his or her appointment or election to the Board of Directors. These options will have an exercise price equal to the fair market value of the common stock on the date of grant, as reasonably determined by the Board of Directors, will fully vest in equal, one-third installments over three years and shall be subject to such other provisions and terms, consistent with the Corporation’s 2008 Equity Incentive Plan, as are set forth in option agreements relating to the grant. Each non-employee director will receive annual cash compensation of $12,000. The chairman of the Audit Committee will receive additional annual compensation of $30,000; and the chairmen of the Compensation, Reserves and Nominating and Corporate Governance Committees will each receive additional annual cash compensation of $15,000. Each non-employee director will receive $2,000 for attendance at each committee meeting of the Board of Directors, or $1,000 for telephonic attendance. All directors will be reimbursed for reasonable out-of-pocket expenses incurred in attending Board of Directors and committee meetings.

5	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.

6	On September 23, 2010, our Board of Directors approving our non-director compensation plan consisted of Nadine Smith, Andrés Gutierrez, Alexander F. D. Berger, José Fernando Montoya, Jaime Ruiz, Jaime Navas and Richard Stevens.

Amendments to our director compensation package must be approved by Compensation Committee of the Board.

The following table sets forth information regarding compensation accrued to the Company’s non-employee directors for the year ended December 31, 2011.

Director Compensation

Name	Fees earned or paid in cash ($)		Stock awards ($)		Option awards (1) ($)		Non- equity incentive plan compensa- tion ($)		Nonqualified deferred compensation earnings ($)		All other compen- sation ($)		Total ($)

Alexander F. D. Berger		8,567		-		-		-		-		-		8,567
Dirk J. H. Groen		4,433		-		11,804		-		-		-		16,237

José Fernando Montoya Carrillo		36,000		-		-		-		-		-		36,000
Jaime Navas Gaona		33,000		-		-		-		-		-		33,000
Jaime Ruiz Llano		32,000		-		-		-		-		-		32,000
Richard G. Stevens		46,000		-		-		-		-				46,000

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

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 Equity Incentive Plan, the Compensation Committee would have complete authority and discretion to determine the terms of awards under the 2008 Equity Incentive Plan.

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 Directors

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. On December 13, 2011, the Board approved non-incentive stock option grants under the 2008 Equity Incentive Plan to purchase 100,000 shares of its common stock to Dirk J. H. Groen, 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 $0.13 per share.

On September 23, 2010, the Board approved awards to each of its non-employee directors of RSUs under the Corporation’s 2008 Equity Incentive Plan, in the amounts specified next to each director’s name below. These RSUs will vest in 1/3 increments on each of the first three anniversaries of the date of grant.

	Nadine Smith	87,500 shares
	José Montoya	50,000 shares
	Jaime Ruiz	50,000 shares
	Jaime Navas	50,000 shares
	Rick Stevens	50,000 shares
	Alexander Berger	50,000 shares

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 10, 2012 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.

Name and Address of Beneficial Owner	Title of Class	Amount and Nature of Beneficial Ownership(1)			Percent of Class (2)

Nadine C. Smith	Common Stock		3,498,567	(3)		7.4	%

Andrés Gutierrez Rivera	Common Stock		1,132,559	(4)		2.4	%

Dirk J. H. Groen	Common Stock		0	(5)(9)		*	%

José Fernando Montoya Carrillo	Common Stock		416,667	(6)		*	%

Jaime Navas Gaona	Common Stock		116,667	(7)		*	%

Jaime Ruiz Llano	Common Stock		116,667	(7)		*	%

Richard G. Stevens	Common Stock		116,667	(7)		*	%

All directors and executive officers as a group (7 persons)	Common Stock		5,397,794			11.1	%

Avante Petroleum S.A.	Common Stock		16,000,105	(5)(8)		32.4	%

Professional Trading Services SA	Common Stock		2,600,000	(9)(10)		5.5	%

Macquarie Bank Limited	Common Stock		2,571,429	(10)(11)		5.4	%

LW Securities, Ltd.	Common Stock	2,403,114		(10)(12)	5.1		%

* 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 10, 2012 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 46,467,849 shares of our common stock outstanding as of April 10, 2012,

(3)

Includes 389,000 shares of our common stock issuable within 60 days upon the exercise of warrants; 175,000 shares of our common stock issuable within 60 days upon the exercise of vested options granted under our 2008 Equity Incentive Plan; and 29,167 shares of common stock subject to vested RSUs granted under our 2008 Equity Incentive Plan. Does not include 58,333 shares of common stock issuable upon vesting of RSUs granted under our 2008 Equity Incentive Plan, which will vest in two equal installments on September 23, 2012 and 2013.

(4)

Includes 25,000 shares of our common stock issuable within 60 days upon the exercise of warrants; 1,000,000 shares of our common stock issuable within 60 days upon the exercise of vested options granted under our 2008 Equity Incentive Plan; and 14,390 shares of common stock subject to vested RSUs granted under the 2008 Equity Incentive Plan. Does not include 28,779 shares of common stock issuable upon vesting of RSUs granted under the 2008 Equity Incentive Plan, which will vest in two equal installments on September 23, 2012 and 2013.

(5)

Does not include 100,000 shares of our common stock issuable upon the exercise of options granted to Mr. Groen under our 2008 Equity Incentive Plan, which will vest in three equal installments beginning on August 17, 2012. Also does not include the other shares beneficially owned by Avante Petroleum S.A. as indicated in the table above and in footnote 9 below. Mr. Groen is CEO of Avante and may be deemed to beneficially own these shares but disclaims beneficial ownership thereof.

(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 has management control of Adamo International Inc., a Panamanian company, which 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 100,000 shares of our common stock issuable within 60 days upon the exercise of options granted under our 2008 Equity Incentive Plan; and 16,667 shares of common stock issuable under RSUs granted under our 2008 Equity Incentive Plan. Does not include 33,333 shares of common stock subject to vested RSUs granted under our 2008 Equity Incentive Plan, which will vest in two equal installments on September 23, 2012 and 2013.

(7)

Includes 100,000 shares of our common stock issuable within 60 days upon the exercise of vested options granted under our 2008 Equity Incentive Plan; and 16,667 shares of common stock issuable under RSUs granted under our 2008 Equity Incentive Plan. Does not include 33,333 shares of common stock subject to vested RSUs granted under our 2008 Equity Incentive Plan, which will vest in two equal installments on September 23, 2012.

(8)

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

(9)

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

(10)

Based on the most recent information available to us from such holder.

(11)

Includes 857,143 shares of our common stock issuable within 60 days upon the exercise of warrants.

(12)

Includes 756,000 shares of common stock owned of record by LW Securities, Ltd.; 750,000 shares of common stock issuable within 60 days upon the exercise of warrants held of record by LW Securities, Ltd.; 611,400 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. LW Securities, Ltd. disclaims beneficial ownership of 750,000 of shares of common stock and warrants to purchase 750,000 shares of common stock, which are held of record by LW Securities, Ltd. for the benefit of several clients, and with respect to which LW Securities, Ltd. represents that it has no pecuniary interest.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Except as disclosed 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.

In connection with the acquisition of Avante Colombia, La Cortez entered into a Stockholder Agreement with Avante; Nadine Smith, the Company’s Chairman of the Board; and Andrés Gutierrez, the Company’s CEO, dated as of March 2, 2010 (the “Stockholder Agreement”).

Pursuant to the Stockholder Agreement, upon the closing of the SPA, the Company’s Board increased the number of directors constituting the entire Board by one and appointed Avante’s nominee, Alexander Berger, to fill the vacancy on the Board so created, to serve until the next annual meeting of the Company’s shareholders or until his successor is duly elected and qualified or his earlier death, resignation or removal in accordance with the Company’s By-Laws. The Stockholder Agreement provides that Avante shall continue to nominate one individual reasonably satisfactory to the Company at the next and subsequent annual meetings of its shareholders, and at any special meeting of its shareholders at which directors are to be elected (any “Election Meeting”) as long as Avante and/or its affiliates own outstanding shares representing 10% or more of the votes entitled to be cast at the applicable Election Meeting. Avante’s nominee will be subject to election and re-election by the Company’s shareholders as provided in its By-Laws. If Avante’s nominee is not elected by the Company’s shareholders, then Avante shall have the right to designate the same or another person as its nominee at the next Election Meeting, provided that Avante and/or its affiliates own outstanding voting shares representing 10% or more of the votes entitled to be cast at the applicable Election Meeting. Dirk Groen is Avante’s current nominee to the Board of Directors.

The Stockholder Agreement provides that each of Avante, Ms. Smith and Mr. Gutierrez shall vote any shares of the Company’s capital stock owned by such party, or cause any shares of the Company’s capital stock owned by any immediate family member or affiliate of such party to be voted, in favor of Avante’s nominee at any Election Meeting.

In addition, for so long as Avante is entitled to name a nominee for election as a director, as provided in the Stockholder Agreement, Avante shall have the right to appoint one additional non-voting observer to attend meetings of the Board, and said observer shall have the right to visit the Company’s offices, to have interaction with its management and to receive information and documents pertaining to the Company as reasonably requested, subject to the confidentiality provisions of the Stockholder Agreement.

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, 2011 and 2010, are set forth in the table below:

Fee Category	Fiscal year ended December 31, 2011		Fiscal year ended December 31, 2010
Audit fees (1)	$	360,000	$	226,161
Audit-related fees (2)		17,256		95,986
Tax fees (3)		-		-
All other fees (4)		-		-
Total fees	$	377,256	$	322,147

(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 for services that are normally provided in connection with statutory or regulatory filings or engagements.

(2)

Audit-related fees consist 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.” The majority of the 2010 audit related fees were fees in connection with proposed or consummated acquisitions.

(3)	There were no tax fees incurred during the years ended December 31, 2011 and 2010.

(4)	There were no other fees incurred during the years ended December 31, 2011 and 2010.

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 permissible non-audit services (including, in each case, the engagement fees therefore and terms thereof) to be performed by our independent auditors, in accordance with applicable laws, rules and regulations.

Our Audit Committee selected BDO USA, LLP as our independent registered public accountants for purposes of auditing our financial statements for the years ended December 31, 2011 and 2010. In accordance with Audit Committee practice, BDO USA, 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.

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		Conformed By-Laws of the Registrant (2)

10.1	10.1	†	Employment Agreement dated May 13, 2008 by and between the Registrant and Andrés 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)

Exhibit No.	SEC Report Reference Number	Description

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 July 2009 unit offering (10)

10.13	10.2	Form of warrant for July 2009 unit offering (10)

10.14	10.3	Form of registration rights agreement for July 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	10.17	Stock Purchase Agreement between the Registrant and Avante Petroleum SA, dated as of March 2, 2010 (13)

10.18	10.18	Stockholder Agreement among the Registrant, Avante Petroleum SA, Nadine Smith and Andrés Gutierrez, dated as of dated as of March 2, 2010 (13)

10.19	10.19	Share Escrow Agreement among the Registrant, Avante Petroleum SA and Robert Jan Jozef Lijdman, dated as of March 2, 2010 (13)

10.20	10.20	Subscription Agreement between the Registrant and Avante Petroleum SA, dated as of March 2, 2010 (13)

10.21	10.21	Registration Rights Agreement between the Registrant and Avante Petroleum SA, dated as of March 2, 2010 (13)

10.22	10.22	Form of Common Stock Purchase Warrant issued to Avante Petroleum SA (13)

10.23	10.1	Form of subscription agreement for 2009/2010 unit offering (14)

10.24	10.2	Form of warrant for 2009/2010 unit offering (14)

10.25	10.3	Form of registration rights agreement for 2009/2010 unit offering (14)

10.26	*	Joint Operating Agreement between Emerald Energy and La Cortez Energy Colombia, Inc., dated as of February 04, 2010.

Exhibit No.	SEC Report Reference Number		Description

10.27	*		Joint Operating Agreement between Petrotesting Colombia SA and Avante Colombia Ltda. dated as of April 28 2006.

10.26	99.1	†	Letter Agreement between the Registrant and Nadine C. Smith, dated as of December 28, 2011 (15).

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**

99.1	*		Reserves report of DeGolyer and MacNaughton (16)

(1)	Filed with the SEC on February 13, 2008 as an exhibit, numbered as indicated above, to the Registrant’s current report on Form 8-K, which exhibit is incorporated herein by reference.

(2)	Filed with the SEC on April 1, 2011 as an exhibit, numbered as indicated above, to the Registrant’s annual report on Form 10-K, for the year ended December 31, 2010, 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 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 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 on Form 8-K, which exhibit is incorporated herein by reference.

(6)	Filed with the SEC on September 16, 2008 as an exhibit, numbered as indicated above, to the Registrant’s current report 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 on Form 10-Q for the quarter ended September 30, 2008, 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 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 on Form 10-K for the year ended December 31, 2008, 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 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 on Form 10-Q for the quarter ended September 30, 2009, 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 on Form 8-K, which exhibit is incorporated herein by reference.

(13)	Filed with the SEC on April 16, 2010 as an exhibit, numbered as indicated above, to the Registrant’s annual report on Form 10-K for the year ended December 31, 2009, which exhibit is incorporated herein by reference.

(14)	Filed with the SEC on April 23, 2010 as an exhibit, numbered as indicated above, to the Registrant’s current report on Form 8-K, which exhibit is incorporated herein by reference.

(15)	Filed with the SEC on January 4, 2012, as an exhibit, numbered as indicated above, to the Registrant’s current report on Form 8-K, which exhibit is incorporated herein by reference.

(16)

The future net cash flows discounted at 10% of our proved reserves of $2.2 million included in the report of DeGolyer and MacNaughton was calculated on a project basis, which means that it deducted income tax expenses although the Company has enough tax basis and net operating loss carryforwards to more than offset the income tax expenses. The future net cash flows discounted at 10% of our proved reserves of approximately $3.3 million included within the Supplemental Oil and Gas Disclosures (Unaudited), was calculated on a company basis, which means that it does not deduct any income tax expenses because the Company has enough tax basis and net operating loss carryforwards to more than offset the income tax expenses.

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.

†

Management contracts or compensatory plan

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, 2012	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, 2012
Nadine C. Smith	Financial Officer

/s/ Andrés Gutierrez Rivera	President and Chief Executive Officer,	April 16, 2012
Andrés Gutierrez Rivera	Director

/s/ Dirk J. H. Groen	Director	April 16, 2012
Dirk J. H. Groen

/s/ José Fernando Montoya	Director	April 16, 2012
José Fernando Montoya Carrillo

/s/ Jaime Navas Gaona	Director	April 16, 2012
Jaime Navas Gaona

/s/ Jaime Ruiz Llano	Director	April 16, 2012
Jaime Ruiz Llano

/s/ Richard G. Stevens	Director	April 16, 2012
Richard G. Stevens

INDEX TO FINANCIAL STATEMENTS

		Page

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2011 and 2010		F-3

Consolidated Statements of Operations for the years ended December 31, 2011 and 2010		F-4

Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2011 and 2010		F-5

Consolidated Statements of Cash Flows for the years ended December 31, 2011 and 2010		F-6

Notes to Consolidated Financial Statements		F-7

Supplemental Oil and Gas Disclosures (Unaudited)

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, 2011 and 2010 and the related consolidated statements of operations, shareholders’ 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our 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, 2011 and 2010, 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.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has limited operating history, no historical profitability, recorded significant impairments of its oil properties and goodwill, 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 consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ BDO USA, LLP

Houston, Texas

April 16, 2012

F-2

LA CORTEZ ENERGY, INC.

Consolidated Balance Sheets

	December 31,			December 31,
	2011			2010

Assets
Cash and cash equivalents	$	4,180,771		$	8,327,020
Accrued oil receivables		420,397			-
Employee advances and other receivables		12,950			14,603
Prepaid expenses		317,283			119,887
Total current assets		4,931,401			8,461,510
Oil properties, at cost, using the full cost method of accounting:
Proved		19,034,154			11,249,087
Unproved		5,111,473			11,897,508
Accumulated depletion and impairment		(15,774,148	)		(10,476,624	)
		8,371,479			12,669,971
Other property and equipment, net of accumulated depreciation of $254,273 and $175,309, respectively		119,412			181,121
Goodwill		-			5,591,422
Restricted cash		2,718,903			2,777,057
Total assets	$	16,141,195		$	29,681,081

Liabilities and Shareholders' Equity
Liabilities:
Accounts payable	$	766,586		$	1,048,573
Accrued liabilities		728,028			371,927
Other liabilities-current portion		246,040			-
Derivative warrant instruments		100,582			7,457,125
Total current liabilities		1,841,236			8,877,625
Other liabilities - non-current portion		377,901			-
Asset retirement obligation		346,892			127,606
Total liabilities		2,566,029			9,005,231
Commitments and contingencies (Note 12)
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; 46,467,849 and 46,190,910 shares issued and outstanding at December 31, 2011 and 2010, respectively		46,467			46,190
Additional paid-in capital		39,417,707			38,744,339
Accumulated deficit		(25,889,008	)		(18,114,679	)
Total shareholders' equity		13,575,166			20,675,850

Total liabilities and shareholders' equity	$	16,141,195		$	29,681,081

See accompanying notes to these consolidated financial statements.

F-3

LA CORTEZ ENERGY, INC.

Consolidated Statements of Operations

	Years Ended
	December 31,
	2011			2010
Revenues:
Oil revenues	$	2,624,469		$	522,896
Total revenues		2,624,469			522,896

Costs and expenses:
Operating costs		1,072,940			1,554,325
Depreciation, depletion, accretion and amortization		1,187,678			297,896
Impairment of oil properties		4,201,385			3,563,417
Impairment of goodwill		5,591,422			-
General and administrative		5,635,119			5,326,235
Total costs and expenses		17,688,544			10,741,873
Loss from operations		(15,064,075	)		(10,218,977	)

Non-operating income (expense):
Unrealized gain on fair value of derivative warrant instruments, net		7,356,543			5,809,716
Interest and other income		106,395			161,782
Interest expense		(133,793	)		-
Total non-operating income (expense)		7,329,145			5,971,498
Loss before income taxes		(7,734,930	)		(4,247,479	)

Income taxes		(39,399	)		(50,891	)

Net loss	$	(7,774,329	)	$	(4,298,370	)

Basic and diluted loss per share	$	(0.17	)	$	(0.10	)

Basic and diluted weighted-average common shares outstanding		46,327,635			41,821,429

See accompanying notes to these consolidated financial statements.

F-4

LA CORTEZ ENERGY, INC.

Consolidated Statements of Changes in Shareholders’ Equity

For the years ended December 31, 2011 and 2010

					Additional
	Common stock				Paid in		Accumulated
	Shares		Par Value		Capital		Deficit			Total
Balance at December 31, 2009		25,428,815	$	25,429	$	11,396,506	$	(13,816,309	)	$	(2,394,374	)
January 2010, common stock and warrants sold in private placement offering at $1.75 per share, less offering costs totaling $122,802		571,428		571		653,782		-			654,353
March 2010, common stock and warrants sold in private placement offering at $1.75 per share, less offering costs totaling $184,205		857,144		857		903,827		-			904,684
March 2010, common stock and warrants sold in private placement offering to Avante at $1.75 per share		2,857,143		2,857		2,192,906		-			2,195,763
Shares issued for acquisition of Avante		10,285,819		10,286		15,274,714		-			15,285,000
April 2010, common stock and warrants sold in private placement offering at $1.75 per share, less offering costs totaling $716,959		5,905,121		5,905		7,282,591		-			7,288,496
Common stock for services		200,000		200		297,550		-			297,750
Stock based compensation		85,440		85		742,463		-			742,548
Net loss, year ended December 31, 2010								(4,298,370	)		(4,298,370	)
Balance at December 31, 2010		46,190,910		46,190		38,744,339		(18,114,679	)		20,675,850
Common stock for services		137,500		138		108,875		-			109,013
Vested restricted stock unit awards		139,439		139		-		-			139
Stock based compensation		-		-		564,493		-			564,493
Net loss, year ended December 31, 2011		-		-		-		(7,774,329	)		(7,774,329	)
Balance at December 31, 2011		46,467,849	$	46,467	$	39,417,707	$	(25,889,008	)	$	13,575,166

See accompanying notes to these consolidated financial statements.

F-5

LA CORTEZ ENERGY, INC.

Consolidated Statements of Cash Flows

	Years Ended December 31,
	2011			2010
Cash flows from operating activities:
Net loss	$	(7,774,329	)	$	(4,298,370	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion, accretion and amortization		1,187,678			297,896
Impairment of oil properties		4,201,385			3,563,417
Impairment of goodwill		5,591,422			-
Stock-based compensation and vested restricted stock unit awards		564,632			742,548
Unrealized gain on fair value of derivative warrant instruments, net		(7,356,543	)		(5,809,716	)
Common stock for services		109,013			297,750
Changes in operating assets and liabilities:
Accrued oil receivables		(420,397	)		193,488
Employee advances and other receivables		1,653			11,691
Prepaid expenses and other assets		(197,396	)		(50,538	)
Accounts payable		157,593			(762,132	)
Accrued liabilities		356,101			32,146
Other liabilities		623,941			-
Net cash used in operating activities		(2,955,247	)		(5,781,820	)
Cash flows from investing activities:
Acquisition of Avante, net of cash received		-			289,937
Investments in unproved oil properties		(1,231,901	)		(5,239,915	)
Restricted cash		58,154			(104,557	)
Purchases of other property and equipment		(17,255	)		(23,209	)
Net cash used in investing activities		(1,191,002	)		(5,077,744	)
Cash flows from financing activities:
Proceeds from the sale of common stock and derivative warrant instruments		-			17,833,964
Payments for offering costs		-			(1,023,965	)
Net cash provided by financing activities		-			16,809,999
Net change in cash and cash equivalents		(4,146,249	)		5,950,435
Cash and cash equivalents, beginning of year		8,327,020			2,376,585
Cash and cash equivalents, end of year	$	4,180,771		$	8,327,020

Supplemental disclosure of cash flow information:
Cash paid during the period for:
Income taxes	$	37,590		$	21,894
Interest	$	-		$	-
Non-cash investing and financing transactions:
Change in asset retirement obligation estimate	$	206,711		$	71,292
Change in accrued capital expenditures in accounts payable	$	439,580		$	948,305
Asset retirement obligation costs and liabilities	$	-		$	4,799
Issuance of common stock in connection with acquisition of Avante for:
Acquisition of accounts receivable	$	-		$	3,653
Acquisition of prepaid expenses and other current assets	$	-		$	43,001
Acquisition of unproved oil properties	$	-		$	9,808,470
Acquisition of deferred tax asset, net of valuation allowance	$	-		$	1,470,000
Acquisition of goodwill	$	-		$	5,591,422
Acquisition of other property and equipment	$	-		$	48,743
Assumption of accounts payable	$	-		$	240,445
Assumption of accrued liabilities	$	-		$	72,626
Assumption of asset retirement obligation	$	-		$	187,155
Assumption of deferred tax liability	$	-		$	1,470,000

See accompanying notes to these consolidated financial statements.

F-6

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

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

Organization and Basis of Presentation

La Cortez Energy, Inc. (“LCE,” “La Cortez”) together with its 100% owned subsidiaries, La Cortez Energy Colombia, Inc., a Cayman Islands corporation (“LA Cortez Colombia”), La Cortez Energy Colombia, E.U., a Colombia corporation (“Colombia E.U.”) and Avante Colombia S.à.r.l. (“Avante Colombia”) (Collectively the “Company”), 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. As discussed in Note 3 below, LCE acquired Avante Colombia on March 2, 2010.

On September 30, 2010, Avante Colombia changed its name from Avante Colombia S.à.r.l. to Avante Colombia, Inc. and transferred its domicile from Luxembourg to the Cayman Islands.

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 8, 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. On October 1, 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.

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, impairment of oil properties, impairment of goodwill, asset retirement obligations, accrued revenues, effects of purchase price allocations and calculations related to derivative warrant instruments.

Cash and Cash Equivalents

Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed government insured limits. The Company has never experienced any losses related to these balances. All of the Company’s non-interest bearing cash balances were fully insured at December 31, 2011 and 2010 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning 2013, insurance coverage will revert to $250,000 per depositor at each financial institution, and non-interest bearing cash balances may again exceed federally insured limits. Amounts in Colombia were not insured.

The Company had cash and cash equivalents of $4,180,771 and $8,327,020 at December 31, 2011 and 2010, respectively. Included in these amounts, the balances held in bank accounts in Colombia as of December 31, 2011 and 2010 were $686,913 and $394,993, 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, 2011 or 2010.

F-7

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

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, 2011 and 2010 was $78,964 and $89,704, respectively.

Oil Properties

Depletion of capitalized oil properties and estimated future development costs, excluding unproved properties, are based on the units-of-production method based on proved reserves. Net capitalized costs of oil 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. During 2011, the Company recorded an impairment expense on its oil properties of $4,201,385. The impairment was primarily the result of the Company’s exploration experience and management’s assessment of the carrying amount of the exploration, and whether it is likely that costs will be recovered in full from successful development or by sale, and that the period during which the right to explore will expire in the near future. As of December 31, 2011 and 2010, the Company has oil properties in the amount of $5,111,473 and $11,897,508, respectively, which 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. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented.

For the years ended December 31, 2011 and 2010, the Company incurred an impairment of $4,201,385 and $3,563,417, respectively, on its oil properties.

Based on management’s review, 35% and 65% of the unproved oil properties balance as of December 31, 2011 is expected to be added to amortization during the years 2012 and 2013, respectively. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2011 and notes the year in which the associated costs were incurred:

	Year of Acquisition
	2009		2010		2011		Total
Acquisition costs	$	-	$	1,987,648	$	-	$	1,987,648
Development costs		-		-		-		-
Exploration costs		1,599,950		556,867		967,008		3,123,825
Total	$	1,599,950	$	2,544,515	$	967,008	$	5,111,473

As discussed in Note 6, 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.

F-8

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

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. DeGolyer and MacNaughton 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. The estimate of the Company’s proved reserves as of December 31, 2011 and 2010 has been prepared and presented in accordance with SEC rules and accounting standards. These rules 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 reserves report of 2010 was prepared by Ryder Scott Company.

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 firms named above adhere to the same guidelines when preparing their reserve reports. 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.

Goodwill

Goodwill represents the excess of cost over the net tangible assets and identifiable intangible assets of acquired businesses. The Company’s goodwill resulted from the acquisition of 100% of the outstanding stock of Avante Colombia. The cost of the acquisition was allocated to the assets acquired and liabilities assumed based on estimates of their respective fair values at the date of acquisition. The estimates of the fair value of the assets acquired, liabilities assumed and the stock issued for the acquisition were prepared with the assistance of an independent valuations consultant. The excess of the fair value of the reporting unit over the amounts assigned to the assets and liabilities was the fair value of goodwill. As a result, the Company recorded goodwill in the amount of approximately $5.6 million at the date of acquisition, March 2, 2010.

Warrant Derivative Instruments

The Company accounts for warrant derivative instruments under the provisions of FASB ASC Topic No. 815 – 40,Derivatives and Hedging - Contracts in Entity’s Own Stock This FASB ASC Topic’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 cannot 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 warrants issued during various private placement offerings contained provisions that protect holders from declines in the Company’s stock price or otherwise could result 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 fair value of a “fixed-for-fixed” option as defined under FASB ASC Topic No. 815 – 40.

In accordance with FASB ASC Topic No. 815 – 40, the Company recognized the warrants that contain these down round provisions as liabilities at their respective fair values on each reporting date. FASB ASC Topic No. 815 – 40 also requires that such instruments be measured at fair value at each reporting period.

Revenue Recognition

F-9

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Income Taxes

The Company accounts for income taxes under the provisions of FASB ASC Topic No. 740, 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.

Loss per Common Share

The Company accounts for earnings (loss) per share in accordance with FASB ASC Topic No. 260 – 10, 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 operations exists, 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, 2011, the Company had potentially dilutive shares outstanding, including 2,634,000 options to purchase shares of common stock, warrants to purchase 15,515,203 shares of common stock, and restricted stock units issued to key directors and employees that enable grantees to obtain 278,872 shares of common stock. There was no difference between basic and diluted earnings per share for the year ended December 31, 2011as the effect of these potential common shares were anti-dilutive due to the net loss during the year ended December 31, 2011.For the year ended December 31, 2010, the Company had potentially dilutive shares outstanding, including 2,635,000 options to purchase shares of common stock, warrants to purchase 15,515,203 shares of common stock, and restricted stock units issued to key directors and employees that enabled grantees to obtain 422,940 shares of common stock. There was no difference between basic and diluted loss per share for the year ended December 31, 2010 as the effect of these potential common shares were anti-dilutive due to the net loss during the year ended December 31, 2010.

The following is a summary of the Company’s potentially dilutive securities as of and for years ended December 31, 2011 and 2010:

	Years Ended
	December 31,
	2011		2010
Potentially dilutive shares excluded:
Outstanding stock options		2,634,000		2,635,000
Outstanding warrants to purchase common stock		15,515,203		15,515,203
Outstanding and unvested restricted stock units		278,872		422,940
		18,428,075		18,573,143

Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accrued oil receivables, accounts payable and accrued liabilities approximates fair value due to the highly liquid nature of these short-term instruments.

F-10

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Reporting and Functional Currency

Accounting for Uncertainty in Income Taxes

The Company follows the provisions ASC 740-10,Income Taxes, as pertains to accounting for uncertainty in income taxes. The provisions clarify the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement process for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The provisions also provide guidance on derecognition, classification, interest and penalties, accounting in interim periods, and disclosure.

The Company files income tax returns in the United States federal jurisdiction and foreign jurisdictions. The Company is no longer subject to United States federal, and non-U.S. income tax examination by tax authorities for the years prior to 2007. Based on the Company’s evaluation, the Company has concluded that there are no significant uncertain tax positions requiring recognition in its consolidated financial statements.

The Company may from time to time be assessed interest or penalties by major tax jurisdictions. In the event it receives an assessment for interest and/or penalties, it will be classified in the financial statements as tax expense.

Recently Issued Accounting Standards and Developments

In September 2011, the FASB issued Accounting Standards Update ASU No. 2011-08,Intangibles — Goodwill and Other. ASU 2011-08 allows a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill impairment test. If it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the two-step impairment test for that reporting unit would be performed. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption was permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011, if an entity’s financial statements for the most recent annual or interim period have not yet been issued.

Reclassification

Certain reclassifications have been made to the 2010 consolidated financial statements to conform to the 2011 presentation. These reclassifications were not material to the accompanying consolidated financial statements.

(2)

Going Concern

At December 31, 2011, the Company had cash and cash equivalents of $4,180,771 and working capital of $3,090,165. 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 the second quarter of 2012 based upon its current operating plan.

Through December 31, 2011, 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 operating losses and expects such losses to continue through at least the end of April, 2013. In addition, during the fourth quarter of 2011, the Company recorded significant impairments of its oil properties and goodwill. 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.

F-11

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

The Company’s ability to complete additional offerings is dependent on the stock price of the Company, 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.

If the Company is unable to raise sufficient additional funds when needed, it would be required to further reduce operating expenses by, among other things, curtailing significantly or delaying or eliminating part or all of its operations and properties, or it may need to seek protection under the provisions of the U.S. Bankruptcy Code.

As a result, 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 this year. If the Company is unable to obtain additional sufficient funds during this time, the Company might lose its interest in the Petronorte, Emerald, Rio de Oro and Puerto Barco projects described in Note 4 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 would be necessary should the Company be unable to continue as a going concern, and those adjustments would have a material impact on the amounts currently reflected on the Company's financial statements.

(3)

Acquisition of Avante Colombia

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, La Cortez 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 its common stock (the “Purchase Price Shares”).

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 Exploración y Producción S.A. Both production contracts are for a ten-year term expiring at the end of 2013. The acquisition of Avante Colombia will provide new exploration opportunities. The oil and gas properties derived from this acquisition have been classified as unproved on the consolidated financial statements as of December 31, 2011.

Under the terms of the SPA, the Company and Avante have also agreed to pursue certain opportunities in the Catatumbo area on a joint venture basis. If the Company enters into such a joint venture with Avante, then the Company 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 the Company, (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%.

In connection with the Acquisition, on the Closing Date, La Cortez and Avante entered into a Subscription Agreement (the “Avante Subscription Agreement”), pursuant to which Avante purchased 2,857,143 shares of La Cortez’s common stock (the “Avante Shares”) and three-year warrants to purchase 2,857,143 shares of its 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). See Note 7.

Share Escrow

In connection with the Acquisition, La Cortez entered into a Share Escrow Agreement with Avante, and an escrow agent, pursuant to which 1,500,000 of the 10,285,819 Purchase Price Shares were held in escrow to secure certain indemnification obligations of Avante under the SPA. Such escrowed shares were released to Avante after March 2, 2012.

F-12

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Registration Rights Agreement

Pursuant to the SPA, the Company entered into a Registration Rights Agreement with Avante, dated as of March 2, 2010 (the “Avante RRA”). The Avante RRA grants Avante certain “piggyback” registration rights with respect to the Purchase Price Shares, the Avante Shares and the Avante Warrant Shares; provided that in exercising such piggyback registration rights with respect to any proposed registration statement, Avante may not request inclusion in such registration statement of more than 10% of the number of shares of the Company’s common stock outstanding at such time.

The Avante RRA grants Avante one demand registration right covering the Avante Shares and the Avante Warrant Shares, exercisable if (a) the Company fails to either file a registration statement on which Avante can piggyback or to complete a listing of its common stock on a United States or Canadian national securities exchange within 180 days of the final closing of the private placement offering described in Note 7 below (the “PPO”), and (b) a Total Investment Majority (as defined in the Avante RRA) joins in such demand. The Total Investment Majority may include holders of the Company’s securities purchased pursuant to the Avante Subscription Agreement as well as securities purchased pursuant to the PPO and pursuant to warrants purchased pursuant to either, taken together on an aggregate basis.

The Avante RRA provides an additional demand registration, exercisable following the Lock-Up Period, if Avante (or its successors and permitted assignees under the Avante RRA) is an “affiliate” of the Company (within the meaning of Rule 144) at such time. Each of the Avante Warrant Shares, the Avante Shares and the Purchase Price Shares will cease to be registrable under the Avante RRA if and for so long as they may be sold publicly in the United States without being subject to volume limitations (whether pursuant to Rule 144 or otherwise). The Avante RRA contains customary cutback, discontinuation and indemnification provisions. No demand for registration has been received.

Stockholder Agreement

In connection with the Acquisition, La Cortez entered into a Stockholder Agreement with Avante; Nadine Smith, the Company’s Chairman of the Board; and Andrés Gutierrez, the Company’s CEO, dated as of March 2, 2010 (the “Stockholder Agreement”).

Pursuant to the Stockholder Agreement, upon the closing of the SPA, the Company’s Board increased the number of directors constituting the entire Board by one and appointed Avante’s nominee, Alexander Berger, to fill the vacancy on the Board so created, to serve until the next annual meeting of the Company’s shareholders or until his successor is duly elected and qualified or his earlier death, resignation or removal in accordance with the Company’s By-Laws. The Stockholder Agreement provides that Avante shall continue to nominate one individual reasonably satisfactory to the Company at the next and subsequent annual meetings of its shareholders, and at any special meeting of its shareholders at which directors are to be elected (any “Election Meeting”) as long as Avante and/or its affiliates own outstanding shares representing 10% or more of the votes entitled to be cast at the applicable Election Meeting. Avante’s nominee will be subject to election and re-election by the Company’s shareholders as provided in its by-laws. If Avante’s nominee is not elected by the Company’s shareholders, then Avante shall have the right to designate the same or another person as its nominee at the next Election Meeting, provided that Avante and/or its affiliates own outstanding voting shares representing 10% or more of the votes entitled to be cast at the applicable Election Meeting. Dirk Groen is Avante’s current nominee to the Board of Directors.

F-13

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Until September 2, 2011, the Stockholder Agreement provided that in the event that the Company (or its Board) should propose to: (a) merge or consolidate with or into any other corporation (if the holders of the Company’s voting capital stock immediately prior to the transaction would not hold a majority of the voting stock or other voting equity of the surviving entity immediately after completion of the transaction), or sell, assign, lease or otherwise dispose of all or substantially all of the Company’s assets, or recommend to the Company’s shareholders a third-party tender offer for a majority of its outstanding voting capital stock; or (b) acquire a business (whether by merger, stock purchase or asset purchase) in a transaction that would result in the issuance of a number of shares of the Company’s voting capital stock equal to or exceeding thirty percent (30%) of its voting capital stock outstanding after giving effect to the proposed transaction; or (c) appoint a new Chief Executive Officer (any of the foregoing, a “Covered Transaction”), then the Company’s Board would have been required to establish a special committee of the Board pursuant to the By-Laws, which committee would have consisted of Avante’s nominated director (or if there is no Avante nominee then serving on the Board, Avante’s observer), the Company’s Chairman of the Board, and the Company’s Chief Executive Officer (the “Special Committee”). The Covered Transaction would have required the unanimous approval of all of the members of the Special Committee before it could have been submitted to the full Board for consideration; provided, however, that the foregoing requirement would have been subject and subordinate to the fiduciary duties of each director and any other restrictions under applicable law and the listing standards of any exchange on which the Company’s securities were then listed. This provision has expired.

Description of Assets of Avante Colombia

Immediately following the Acquisition, Avante Colombia became La Cortez’s wholly-owned subsidiary.

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

Under the Rio de Oro production contract, Ecopetrol has a 12% production participation, Vetra a 44% working interest and Avante Colombia a 44% working interest, in each case after royalties. Royalties payable are 20% of production as defined within the applicable contract. The operator is Avante Colombia. Production on the field began in 1950 and was stopped in June 1999, as a result of insurgent activity.

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 the Company for 50% of any environmental losses it incurs, up to a maximum of $2.5 million.

Purchase Price Allocation

The results of operations of Avante Colombia have been included in the Company’s consolidated statements of operations since the acquisition date.

The cost of the acquisition was allocated to the assets acquired and liabilities assumed based on estimates of their respective fair values at the date of acquisition, March 2, 2010. The estimates of the fair value of the assets acquired, liabilities assumed and the stock issued for the acquisition were prepared with the assistance of an independent valuations consultant. The following is a summary of the purchase price allocation:

F-14

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Assets acquired
Cash	$	289,937
Accounts receivable		3,653
Prepaid expenses and other current assets		43,001
Unproved oil and gas properties		9,808,470
Deferred tax asset		2,295,000
Valuation allowance		(825,000	)
Goodwill		5,591,422
Other fixed assets		48,743
Total assets acquired		17,255,226

Liabilities assumed
Accounts payable and other current liabilities		313,071
Asset retirement obligation		187,155
Deferred tax liability		1,470,000
Total liabilities assumed		1,970,226

Net assets acquired	$	15,285,000

Purchase price paid through issuance of 10,285,819 shares of common stock	$	15,285,000

Management believed that the goodwill acquired in the acquisition reflected the value associated with the potential to extend the term of the contracts on the acquired properties and to extend the contracts to other productive zones and development areas. These contracts involve Ecopetrol and affect the properties acquired in the Avante acquisition.

The Company performs an annual goodwill impairment test as of March 31 each year in accordance with ASC subtopic 350-20,Goodwill(formerly SFAS No. 142), and updates the test between annual tests if events or circumstances occur that indicate an impairment might exist.

Reporting units are determined based on the organizational structure at the date of the impairment test. A separate goodwill impairment test is performed for each reporting unit on the goodwill that has been allocated to it.

Reporting units are the component business units from the Company’s operating segment where discrete financial information exists for them. Management regularly reviews operating results. Also, for each reporting unit, their economic characteristics are dissimilar from each other. Currently, the Company has only one reporting unit under goodwill impairment testing. The Company recorded $5,591,422 in goodwill in connection with its acquisitions of the Avante Colombia during the year 2010.

The annual test of the potential impairment of goodwill requires a two-step process. Step one of the impairment test involves comparing the estimated fair values of reporting units with their aggregate carrying values, including goodwill. If the carrying amount of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment loss. If the carrying amount is less than fair value, further testing of goodwill impairment is not performed.

Step two of the goodwill impairment test involves comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Under step two, determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The difference between the fair value of the entire reporting unit as determined in step one and the net fair value of all identifiable assets and liabilities represents the implied fair value of goodwill. The goodwill impairment charge, if any, would be the difference between the carrying amount of goodwill and the implied fair value of goodwill upon the completion of step two.

For purposes of the step one analysis, determination of reporting units’ fair value is based on the income approach, which estimates the fair value of the Company’s reporting units based on discounted future cash flows. The Company determined the fair value of each reporting unit using the income approach, which utilizes a discounted cash flow model, as the Company believes that this approach best approximates the reporting unit’s fair value at this time. Judgments and assumptions related to revenue, operating income, future short-term and long-term growth rates, weighted average cost of capital, interest, capital expenditures, cash flows, and market conditions are inherent in developing the discounted cash flow model.

F-15

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

In the fourth quarter of 2011, the Companyrecorded both a goodwill impairment loss of $5,591,422 (eliminating the goodwill attributed to its acquisition of Avante Colombia in 2010), and an impairment expense on its oil properties of $4,201,385. The circumstances leading to the goodwill assessment and subsequent impairment charges are attributed to the impact of changes in the forecasted results of the Company’s business operations, discussions with potential investors regarding possible investments in its securities, its current market capitalization, and as a consequence of proposals from various parties regarding potential corporate strategic transactions.

The following table reflects the unaudited pro forma results of operations as though the Avante Acquisition had occurred on January 1, 2010. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:

	Year Ended
	December 31, 2010
Revenues	$	522,896

Net loss	$	(4,338,318	)

Loss per share - basic and diluted:	$	(0.10	)

Weighted average shares outstanding - basic & diluted		43,540,429

The following table reflects the results of operations of Avante Colombia since the Closing Date that are included in the Company’s consolidated statements of operations for the year ended December 31, 2010:

	Year Ended
	December 31, 2010
Revenues	$	-

Net loss	$	(314,543	)

(4)

Oil Properties

The Company follows the full cost method of accounting for its oil properties, whereby all costs incurred in connection with the acquisition, exploration for and development of oil 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 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, in which case the gain or loss is recognized in the statement of operations.

Depletion of proved oil properties is 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 for impairment. As of December 31, 2011 and 2010, $5,111,473 and $11,897,508, respectively, of the Company’s oil properties were unproved and were not subject to depletion. The depletion rates per barrel of oil equivalent (boe) for the years ended December 31, 2011 and 2010 were $30.70 and $39.56

For the years ended December 31, 2011 and 2010, the Company incurred $4,201,385 and $3,563,417, respectively, of impairment on its proved oil properties. The impairment was primarily the result of the exploration experience and management’s assessment of the carrying amount of the exploration, and whether it is likely that costs will be recovered in full from successful development or by sale, and that the period during which the right to explore will expire in the near future.

F-16

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Maranta Block

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”). for a 20% participating interest (the “Participating Interest”) in the Maranta exploration and production block (“Maranta”), in the Putumayo Basin in Southwest Colombia.

On February 4, 2010, the Company signed a joint operating agreement with Emerald with respect to the Maranta Block, and the Company asked Emerald to submit a request to the Agencia Nacional de Hidrocarburos (“ANH”) to approve the assignment of the Company’s 20% participating interest to the Company. If the ANH does not approve this assignment, Emerald and the Company have agreed to 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.

Emerald filed a request with the ANH for the assignment of the 20% participating interest in the Maranta Block to La Cortez. To qualify as a contractor with ANH, the Company submitted certain legal, operating, technical and financial information to the ANH. On July 12, 2011, the Company was informed by Emerald that the request for transfer of the 20% interest was not approved because the ANH determined that the submitted information did not comply with the financial requirements demanded by the contract signed between the ANH and Emerald. Accordingly, the Company plans to discuss the financial information with the ANH, including the accounting for the derivative warrant instruments liability, and send a new request for the assignment. Non-approval by the ANH does not affect the current joint operating agreement between Emerald and La Cortez.

Emerald, the operator of the Maranta Block, completed drilling operations associated with the Mirto-2 exploratory well during 2010. The costs associated with the Mirto 2 well were classified as proved properties as of December 31, 2010 and were subject to depletion and impairment.

With the drilling of the Mirto-2 well, Phase 3 of the exploration program has been completed. Both Emerald and the Company have complied with the exploration obligations on this block in accordance with the contract signed with the ANH. Under the contract terms and conditions, and after completion of this phase, both the Company and Emerald were required to relinquish 50% of the area of the block, as selected by both parties, and there is the option to continue exploration activities in the remaining 50% of the area by committing to additional exploration activities with the ANH, such as new seismic acquisition or drilling a new exploration well. The area relinquished related to a portion of the Company’s unevaluated properties to which costs had not been specifically allocated to in prior periods or the current year. Phase 1 of the subsequent exploratory program requires both Emerald and La Cortez to comply with the acquisition of certain seismic as stated in the agreement with the ANH or the drilling of an exploration well on or before August 2012, with Phase 2 of the subsequent exploratory program requiring another acquisition of certain seismic as stated in the agreement with the ANH or the drilling of an exploratory well on or before August 2014.

Putumayo-4 Block

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 the Company to a 50% net working interest in the Putumayo 4 block, in the Putumayo Basin (the “Putumayo 4 Block”). According to the MOU, the Company will have the exclusive right to a 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 is the “operator” of the E&P Contract.

Petronorte and the Company have been conducting a community consultation process for the seismic acquisition in the northern part of the Putumayo 4 Block. Several seismic service companies were invited to participate for the acquisition of 2D seismic in the area which is part of the work commitment to the ANH. Additional 2D seismic will also be acquired as part of the additional investment commitment of $1.6 million made to the ANH during the 2008 bidding round.

During 2011, Petronorte sent a letter to the ANH asking for an extension of the Petronorte contract commitments due to delays on the availability of the Colombian Ministry of Interior representative to carry on with the consultation process with communities. Petronorte asked that an additional seven months be added to the original commitment to compensate for the impact on the original schedule. On February 23, 2012, the ANH approved an extension of the contract for seven months and five days through March 28, 2013.

Petronorte also filed a request with the ANH for the assignment of the 50% working interest in the Putumayo 4 Block to the Company. To qualify as a contractor with the ANH, the Company submitted certain legal, operating, technical and financial information, including prior years’ audited financial statements, to be reviewed by the ANH. The ANH has confirmed that the Company needs to guarantee the required investment for this first exploration phase by placing in a trust an amount equal to 50% of its participation, equivalent to $5.4 million. This amount includes the existing guarantee of $2.7 million, which means that the Company would be required to fund the additional amount.

F-17

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Under the MOU and the joint operating agreement with Petronorte, the Company will be responsible for fifty percent (50%) of the costs incurred under the E&P Contract, entitling it 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 the Company 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 the Company for its share of these seismic costs paid by the Company (which is one-sixth (1/6) share) with their revenues from production from the Putumayo 4 Block. The Company expects its capital commitments to Petronorte will be approximately $5.2 million in 2012 for Phase 1 seismic reprocessing, seismic acquisition and permitting activities. If adequate capital cannot be obtained on a timely basis and on satisfactory terms, the expected operations would be materially negatively impacted.

In November 2009, the Company deposited $2.7 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 consolidated balance sheets.

Rio de Oro and Puerto Barco Fields

La Cortez, through its subsidiary Avante Colombia Inc., initiated operating activities in the Puerto Barco field in different areas and social activities such as meetings with the communities to inform them of the Company’s plans and activities. During August of 2011, road upgrades to the area were initiated. However, the road maintenance was suspended due to heavy rains in the region. This work is expected to commence again during the second half of 2012, providing that the Company is able to negotiate a contract extension and adequate financial capital is obtained.

The Company continues to be actively engaged with Ecopetrol regarding opportunities to amend the existing contract terms associated with the Rio de Oro and Puerto Barco fields, though the final outcome of such discussions remains unknown at this point. A proposal for the modification of the existing contracts in the Puerto Barco and Rio de Oro fields, plus a new E & P contract for the entire Rio de Oro block, was presented to Ecopetrol. The Company expects a resolution on this negotiation during the second quarter of 2012.

(5)

Related Party Transactions

Common Stock Sales

On March 2, 2010, as part of a closing of its private placement offering (see Note 7 below), the Company sold 58,000 Units, at a price of $1.75 per Unit, for total consideration of $101,500 to the Company’s Chairman of the Board and Interim Chief Financial Officer, on the same terms as to other investors in the offering.

(6)

Asset Retirement Obligation

ASC 410-20, Asset Retirement and Environmental Obligations, 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 property accounts. During the year ended December 31, 2011 and 2010, revisions were made to the Company’s estimates to reflect the effects of updated anticipated plugging date estimates, mainly arising from estimated production amounts and their effect on reserve estimates.

F-18

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

The following table reflects the changes in the ARO during year ended December 31, 2011:

	Amount
Asset retirement obligation - beginning of year	$	127,606
Current year revision to previous estimates		206,711
Current year accretion		12,575
Asset retirement obligation - end of year	$	346,892

The following table reflects the changes in the ARO during the year ended December 31, 2010:

	Amount
Asset retirement obligation - beginning of year	$	3,860
Liabilities incurred in connection with Avante acquisition		187,155
Current year revision to previous estimates		(71,292	)
Liabilities incurred on properties drilled		4,799
Current year accretion		3,084
Asset retirement obligation - end of year	$	127,606

(7)

Shareholders’ Equity

As of December 31, 2011 and 2010, there were 46,467,849 and 46,190,910 shares respectively, of common stock and no shares of preferred stock issued and outstanding.

The Avante Subscription Agreement

On March 2, 2010 (the “Closing Date”), pursuant to the terms of the Avante Subscription Agreement, Avante purchased 2,857,143 shares of the Company’s common stock and warrants to purchase 2,857,143 shares of its common stock at an exercise price of $3.00 per share, for an aggregate purchase price of $5,000,000 (or $1.75 per unit purchased).

The Avante Warrants are exercisable to purchase a number of shares of the Company’s common stock equal to the number of Avante Shares at an exercise price of $3.00 per share (subject to adjustment upon certain events as provided in the form of the Avante Warrant). The Avante Warrants were fully vested at issuance and are exercisable up to three years after the Closing Date. The Avante Warrants carry weighted-average anti-dilution protection in the event La Cortez subsequently issues shares of its common stock, or securities convertible into shares of its common stock, for a per share price that is less than the exercise price per share at such time. See below under section “December 2009 and January, March and April 2010 Closings of the Private Placement Offering” for a further discussion of these Avante Warrants.

Common Stock Sales

On March 14, 2008, the Company issued a total of 2,400,000 shares of common stock to a limited number of accredited investors and non-U.S. persons in a private placement for total proceeds of $2,400,000 ($2,314,895 net after offering expenses).

On July 23, 2008 the Company offered 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. 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 2008 Unit Offering included in the units and underlying the warrants included in the units.

F-19

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

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 2008 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 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 continue to have “piggyback” registration rights with respect to these shares. There has been no request for a Demand Registration as of December 31, 2011.

On May 11, 2009 the Company offered 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. These units were offered to a limited number of accredited investors and non-U.S persons, in a private placement. 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 2009 Mid-Year 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 2009 Mid-Year 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 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. 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.

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 could result in modification of the exercise price and/or shares to be issued under the respective warrant 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 to the 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.

F-20

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

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 required 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 2009 Mid-Year Unit Offering (the “Registrable Shares”). Shares of common stock underlying the warrants included in the units carried “piggyback” registration rights. The registration rights agreement provided 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 2009 Mid-Year Unit Offering. If the Company was unable to comply with this deadline, the Company was 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. The Company obtained a waiver of these liquidated damages from a majority in interest of the investors in the offering, and the Company has no further obligations under the registration rights agreement, which terminated on July 31, 2011.

December 2009 and January, March and April 2010 Closings of the Private Placement Offering

In December 2009, January 2010, March 2010 and April 2010, the Company closed on a Private Placement Offering (“PPO”). The details of the PPO which occurred during 2010 are as follows: (a) On January 29, 2010, the Company closed on the sale of 571,428 PPO Units; (b) on March 2, 2010, the Company closed on the sale of 857,144 PPO Units in the PPO for gross proceeds of $1.5 million, and (c) on April 19, 2010, the Company conducted the fourth and final closing of its PPO for an additional 5,905,121 PPO Units, for gross proceeds of $10.33 million. Each “PPO Unit” was sold at a price of $1.75 and consists of (i) one share of the Company’s common stock, and (ii) a warrant representing the right to purchase one-half (1/2) of one share of its common stock, for a period of three years commencing on the final closing date of the PPO, at an exercise price of $3.00 per whole share (the “PPO Warrants”).

In the aggregate, in all four closings of the PPO, including the initial closing that occurred on December 29, 2009, which had gross proceeds of $1.0 million, the Company sold 8,762,264 PPO Units, consisting of an aggregate of 8,762,264 shares of its common stock and warrants to purchase an aggregate of 4,381,138 shares of its common stock (after consideration of rounding for partial shares), for total gross proceeds of $15.33 million. With respect to certain subscriptions in the PPO, the Company is obligated to pay placement agents and/or finders (collectively, “PPO Finders”) cash fees of up to ten percent (10%) of the purchase price of each PPO Unit sold in the PPO to investors introduced to the Company by the relevant PPO Finder (the “Introduced Investors”), and to issue each such PPO Finder five year warrants (the “Agent Warrants”) exercisable at no less than $1.75 per share to purchase a number of shares of the Company’s common stock equal to up to ten percent (10%) of the shares of common stock included in the PPO Units sold in the PPO to the Introduced Investors. In addition to their term, the Agent Warrants differ from the PPO Warrants in certain other respects, including without limitation, the Agent Warrants provide for cashless exercise. As a result of the Company’s sales of the PPO Units, the Company was obligated to pay an aggregate of approximately $612,037 of placement agent and/or finder fees and has issued Agent Warrants to purchase an aggregate of 344,022 shares of the Company’s common stock.

The PPO Warrants are subject to weighted-average anti-dilution protection in the event the Company subsequently issues shares of its common stock, or securities convertible into shares of its common stock, for a per share price that is less than the exercise price per share of the PPO Warrants at such time. The PPO Warrants are immediately exercisable.

The Company has entered into a registration rights agreement (the “PPO RRA”) with the investors in the PPO. The PPO RRA provide such investors with “piggyback” registration rights with respect to the PPO Shares and the shares of its common stock issuable upon exercise of the PPO Warrants (collectively, the “Registrable PPO Shares”). The PPO RRA grants the holders of a majority of the Registrable PPO Shares subject to the PPO RRA with the right to demand registration of such shares if the Company fails to either file a registration statement on which they can piggyback or complete a listing of its common stock on a United States or Canadian national securities exchange (or, in the case of the investors in the December 29, 2009 closing, on the TSX Venture Exchange) within 180 days of the final closing of the PPO. As this condition was not satisfied, the demand registration rights are exercisable; however, no demand has been received to date. Registrable PPO Shares are not subject to the PPO RRA if they may be immediately sold under the Securities Act (whether pursuant to Rule 144 thereunder or otherwise).

F-21

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

The Company’s offering and sale of the shares of common stock and PPO Warrants in the PPO were made in reliance on the exemption from the registration requirements of the federal securities laws provided by Section 4(2) of the Securities Act and Regulation D and/or Regulation S promulgated by the SEC thereunder. These securities may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act.

The Company used the net proceeds of the PPO together with the proceeds of its sale of securities pursuant to the Avante Subscription Agreement towards funding its existing oil and gas exploration and production projects (including those of Avante Colombia) and for general working capital purposes.

The Company determined that warrants to purchase a total of 4,010,874 shares of common stock, including warrants to purchase 344,022 shares of common stock issued to agents, issued in the January, March and April 2010 closings of the PPO (“2010 Unit Offerings”) and the warrants to purchase a total of 2,857,143 shares of common stock issued to Avante in connection with the Avante Share Purchase Agreement contained provisions that protect holders from declines in the Company’s stock price or otherwise could result in modification of the exercise price and/or shares to be issued under the respective warrant based on a variable that is not an input to the fair value of a “fixed-for-fixed” option as defined under FASB ASC Topic No. 815 – 40 - 15. As a result, these warrants were not indexed to the Company’s own stock. At the January 2010 closing of the PPO, the fair value of these warrants was determined to be approximately $222,844, which was recorded as a derivative warrant instruments liability. The Company also recorded $571 as par value to common stock and $653,782 to additional paid-in capital as part of the January 2010 Closing of the PPO. At the March 2010 closing of the PPO, the fair value of these warrants was approximately $411,112, which was recorded as a derivative warrant instruments liability. The Company also recorded $857 as par value to common stock and $903,827 to additional paid-in capital as part of the March 2010 closing of the PPO. At the closing of the Avante Share Purchase Agreement (as discussed under the section “Avante Subscription Agreement” above), the fair value of these warrants was approximately $2,804,237, which was recorded as a derivative warrant instruments liability. The Company also recorded $2,857 as par value to common stock and $2,192,906 to additional paid-in capital as part of the closing of the Avante Share Purchase Agreement. At the April 2010 closing of the PPO, the fair value of these warrants was approximately $2,328,510, which was recorded as a derivative warrant instruments liability. The Company also recorded $5,905 as par value to common stock and $7,282,591 to additional paid-in capital as part of the April 2010 Closing of the PPO.

The table below reflects the breakdown of the components of gross proceeds from the Company’s closings during the year ended December 31, 2010:

Par value of common stock issued	$	10,190
Additional paid-in capital		11,033,106
Derivative warrant instruments		5,766,703
Offering expenses		1,023,965
Total gross proceeds	$	17,833,964

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 its 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, 2011, options had been granted under the 2008 Plan exercisable for an aggregate of 2,634,000 shares of common stock (including 184,000 shares issued to consultants) and 503,751 restricted stock units have been granted under the 2008 Plan.

The Company determines the fair value of stock option and restricted stock unit awards granted to employees in accordance with FASB ASC Topic No. 718 – 10, “Compensation - Stock Compensation”, and to non-employees in accordance with FASB ASC Topic No. 505 – 50 “Accounting for Equity Instruments Issued to Non-Employees for Acquiring, or in Conjunction with Selling, Goods or Services”.

F-22

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Stock Option Awards

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, 2009		2,141,667		$	2.11		8.64	$	—
Granted		350,000			1.59
Exercised		—			—
Forfeited		(16,667	)		2.20
Outstanding at December 31, 2010		2,475,000			2.04		7.93		—
Granted		375,000			0.31
Exercised		—			—
Forfeited		(400,000	)		1.44
Outstanding at December 31, 2011		2,450,000		$	1.87		7.22	$	—

Of the above employee options outstanding at December 31, 2011, 1,908,334 options are vested or exercisable. During the years ended December 31, 2011 and 2010, the Company recognized stock-based compensation expense of approximately $350,052 and $582,351, respectively, related to stock options. The weighted-average grant date fair value of these options for the years ended December 31, 2011 and 2010 were $0.21 and $0.83, respectively. As of December 31, 2011, there was approximately $154,000 of total unrecognized compensation cost related to non-vested stock options (all of which is related to employee options), which is expected to be recognized over a weighted-average period of approximately 0.22 years.

The following table summarizes the activity of non-vested employee stock options for the years ended December 31, 2011 and 2010:

	Number of			Weighted-average		Aggregate
	Non-vested			Grant Date		Intrinsic
		Shares			Fair Value		Value
Outstanding at December 31, 2009		1,533,328		$	0.86	$	-
Granted		350,000			0.83
Vested		(708,333	)		0.86
Forfeited		-			-
Outstanding at December 31, 2010		1,174,995			0.85		-
Granted		375,000			0.21
Vested		(774,997	)		0.87
Forfeited		(233,332	)		0.80
Outstanding at December 31, 2011		541,666		$	0.41	$	-

F-23

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

The fair value of the options granted during 2011 and 2010 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. 17 - $1.44
Risk-free interest rate (2)		1.40 – 2.18	%
Dividend yield (3)		0.00	%
Volatility factor (4)		70.31% - 76.18	%
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 the 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.

(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.

A summary of stock option activity during the year ended December 31, 2011 covering options granted to the Company’s non-employees and non-directors 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, 2010		160,000	$	2.00		8.46	$	—
Granted		24,000		0.99		—		—
Exercised		—		—		—		—
Forfeited		—		—		—		—
Expired		—		—		—		—
Outstanding at December 31, 2011		184,000	$	1.87		7.70	$	—

Of the above non-employee options outstanding at December 31, 2011, all are vested or exercisable. During the years ended December 31, 2011 and 2010, the Company recognized stock-based compensation expense of approximately $5,181 and $0, respectively, related to stock options. The weighted-average grant date fair value of these options for the years ended December 31, 2011 and 2010 were $0.36 and $-nil-, respectively. As of December 31, 2011, there was no unrecognized compensation cost.

F-24

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

The following table summarizes the activity of non-vested non-employee stock options for the years ended December 31, 2011 and 2010:

	Number of			Weighted-average		Aggregate
	Non-vested			Grant Date		Intrinsic
	Shares			Fair Value		Value
Outstanding at December 31, 2009		53,332		$	0.77	$	-
Granted		-			-
Vested		(53,332	)		0.77
Forfeited		-			-
Outstanding at December 31, 2010		-			-		-
Granted		24,000			0.36
Vested		(24,000	)		0.36
Forfeited		-			-
Outstanding at December 31, 2011		-		$	-	$	-

The fair value of the options granted during 2011 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)	$	0.70
Risk-free interest rate (2)		2.23	%
Dividend yield (3)		0.00	%
Volatility factor (4)		68% - 71	%
Expected life (5)		5.25 years
Expected forfeiture rate (6)		10	%

(1)

The estimated market value of the stock on the date of grant was based on the 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.

(4)

(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.

Restricted Stock Units

During 2011 and 2010, the Company granted restricted stock units to its directors and key employees under its 2008 Equity Incentive Plan. The restricted stock units vest in one-third increments on each of the three anniversaries from the date of grant.

F-25

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Restricted stock unit activity during the years ended December 31, 2011 and 2010 is as follows:

	Number of Restricted Stock Shares			Weighted- average Grant Price		Weighted- average Remaining Contractual Term (years)
Outstanding at December 31, 2009		—		$	—		—
Granted		422,940			1.68		—
Exercised		—			—		—
Forfeited		—			—		—
Outstanding at December 31, 2010		422,940			1.68		2.73
Granted		10,000			1.08		—
Exercised		—			—		—
Forfeited		(14,629	)		—		—
Outstanding at December 31, 2011		418,311		$	1.66		1.73

As of December 31, 2011, 139,439 of the above restricted stock units were vested, and there was approximately $361,000 of unrecognized compensation cost related to non-vested restricted stock unit compensation arrangements granted under the 2008 Equity Incentive Plan. That cost is expected to be recognized over a weighted-average period of 1.73 years. The Company recognized compensation expense related to these restricted stock units amounting to $209,398 and $57,669 during the years ended December 31, 2011 and 2010, respectively.

The following table summarizes the activity of non-vested restricted stock units to its directors and key employees for the years ended December 31, 2011 and 2010:

	Number of
	Non-vested			Weighted-average		Aggregate
	Restricted Stock			Grant Date		Intrinsic
	Units			Fair Value		Value
Outstanding at December 31, 2009		-		$	-	$	-
Granted		422,940			1.68
Vested		-			-
Forfeited		-			-
Outstanding at December 31, 2010		422,940			1.68		-
Granted		10,000			1.08
Vested		(139,439	)		1.66
Forfeited		(14,629	)		1.68
Outstanding at December 31, 2011		278,872		$	1.66	$	-

Restricted Common Stock issued to Employees

On December 6, 2010, the Company’s Board of Directors authorized the issuance of 85,440 shares of its common stock to its employees as compensation for services rendered to the Company. Management determined the fair value of the stock issued to the employees at $1.20 per share based on the stock price on December 6, 2010. Accordingly, stock-based compensation expense of $102,528 was recognized during the year ended December 31, 2010 related to this issuance of common stock.

Common Stock issued for Services

Effective May 1, 2010, the Company entered into a consulting agreement with a third party for the third party entity to provide investor relations services to the Company for a monthly fee of $15,000 and 25,000 shares of the Company’s common stock during the first twelve months of the agreement, and $10,000 and 20,000 shares of the Company’s common stock thereafter. This agreement expired in May 2011. On April 25, 2011, the Company entered into a consulting agreement with another third party for such third party entity to provide investor relations services to the Company for a monthly fee of $10,000 and 12,500 shares of the Company’s common stock during the term of the agreement covering a period of three months. This agreement expired in July 2011. During the years ended December 31, 2011 and 2010, the Company was required to issue 137,500 shares and 200,000 shares, respectively, of its common stock in relation to the above consulting agreements, using the fair value of the stock at the end of each month. Total compensation expense associated with these shares issued for the years ended December 31, 2011 and 2010 amounted to $109,013 and $297,750, respectively.

F-26

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

(8)

Derivative Warrant Instruments (Liabilities)

In the 2008 Unit Offering, 2009 Unit Offerings, and 2010 Unit Offerings, the Company incurred liabilities for the estimated fair value of derivative warrant instruments in the form of warrants. The estimated fair value of the derivative warrant instruments was calculated using a probability-weighted scenario analysis model as of December 31, 2011 and 2010. Such estimates were revalued at each balance sheet date, with changes in value recorded as unrealized gains or losses in non-operating income (expense) in the Company’s statements of operations.

During the years ended December 31, 2011 and 2010, the fair value of the warrant derivative liabilities decreased by $7,356,543 and $5,809,716, respectively. Such changes were recorded as unrealized gains on fair value of derivative warrant instruments in the accompanying consolidated statements of operations.

Activity for derivative warrant instruments liability during the year ended December 31, 2011 was as follows:

					Decrease in
			Activity		Fair Value of
	December 31,		during the		Derivative			December 31,
	2010		year		Liability			2011
Derivative warrant instruments	$	7,457,125	$	-	$	(7,356,543	)	$	100,582
	$	7,457,125	$	-	$	(7,356,543	)	$	100,582

Activity for derivative warrant instruments liability during the year ended December 31, 2010 was as follows:

					Decrease in
			Activity		Fair Value of
	December 31,		during the		Derivative			December 31,
	2009		year		Liability			2010
Derivative warrant instruments	$	7,500,138	$	5,766,703	$	(5,809,716	)	$	7,457,125
	$	7,500,138	$	5,766,703	$	(5,809,716	)	$	7,457,125

The fair value of the derivative warrant instruments is estimated using a probability-weighted scenario analysis model with the following assumptions as of December 31, 2011 and 2010:

	December 31,			December 31,
	2011			2010
Common stock issuable upon exercise of warrants		15,510,203			15,510,203
Estimated market value of common stock on measurement date	$	0.11	(1)	$	1.11	(1)
Exercise price	$	1.25 to $3.00		$	1.25 to $3.00
Risk free interest rate (2)		0.12% - 0.55	%		0.82% - 2.01	%
Warrant lives in years		1.00 - 3.30			2.00 - 4.30
Expected volatility (3)		79	%		70	%
Expected dividend yields (4)		None			None

(1)

The estimated market value of the stock was measured by management based on the 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 warrant on date of grant.

F-27

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

(3)

(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.

(9)

Fair Value Measurements

As defined in FASB ASC Topic No. 820 – 10, “Fair Value Measurement and Disclosures”, 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. 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, 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 a probability-weighted scenario analysis model (see Note 8).

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, 2011:

	Fair Value Measurements at December 31, 2011
	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, 2011
Derivative warrant instruments	$	-	$	-	$	100,582	$	100,582
Total	$	-	$	-	$	100,582	$	100,582

F-28

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

	Fair Value Measurements at December 31, 2010
	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, 2010
Derivative warrant instruments	$	-	$	-	$	7,457,125	$	7,457,125
Total	$	-	$	-	$	7,457,125	$	7,457,125

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,
	2011			2010
Beginning balance	$	(7,457,125	)	$	(7,500,138	)
Total gains		7,356,543			5,809,716
Settlements		-			-
Additions		-			(5,766,703	)
Transfers		-			-
Ending balance	$	(100,582	)	$	(7,457,125	)

Change in unrealized gains included in earnings relating to derivatives still outstanding as of December 31, 2011 and 2010	$	7,356,543		$	5,809,716

Fair Value on a Non-Recurring Basis

The provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis apply to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired unproved oil property assessments; goodwill impairment; and the initial recognition of asset retirement obligations for which fair value is used.

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, La Cortez has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 6.

The Company’s unproved properties are assessed for impairment periodically. If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved oil property costs to be amortized. During the fourth quarter of 2011, the Company transferred approximately $7.8 million in unproved properties to proved oil properties as a result of this assessment. As a result, approximately $5.1 million remained classified as unproved oil properties as of December 31, 2011. The Company recorded an impairment expense on its oil properties of approximately $4.2 million, which was due to the fact that the unamortized costs for proved oil properties exceeded the cost ceiling limitation (as defined in Note 1).

The transfer of costs from unproved properties to proved properties was primarily the result of (1) the Company’s exploration experience and management’s assessment of the carrying amount of the exploration, and whether it is likely that costs will be recovered in full from successful development or by sale, and (2) the period during which the right to explore will expire in the near future. The estimated fair value of the unproved properties was calculated using a probability-weighted scenario analysis model as of December 31, 2011 and the inputs used by management for the impairment assessments of these unproved properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

F-29

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

As a result of discussions with potential investors regarding possible investments in the Company’s securities and with various parties regarding potential corporate strategic transactions and proposals received from them, the Company performed a goodwill impairment assessment at the reporting unit level as of December 31, 2011 and recorded an impairment loss amounting to approximately $5.6 million during the fourth quarter of 2011. The material assumptions used on the reporting unit for the income approach were a discount rate of approximately 50% and expected future oil prices of $95. The estimated implied fair value of the reporting unit was calculated using a probability-weighted scenario analysis model as of December 31, 2011. The Company considered historical rates, current market conditions and various risks associated with the reporting unit when determining the discount rate to use in its analysis. The inputs used by management for the impairment assessment of goodwill include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

(10)

Sales to Major Customers

The Company, through its 20% interest share in the Maranta field production, sold oil representing 10% or more of total revenues for the years ended December 31, 2011 and 2010 to the customers shown below:

	December 31,			December 31,
	2011			2010
HOCOL S.A.		69	%		50	%
Petrobras International Braspetro BV		19	%		27	%
Comercializadora International Exportecnicas Ltda.		4	%		14	%

In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of the Company’s customers are concentrated in the oil industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. The Company believes that the loss of any of its major purchasers would not have a long-term material adverse effect on its operations.

(11)	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 for the years ended December 31, 2011 and 2010 are as follows:

	2011			2010
U.S.	$	4,443,385		$	3,061,736
Non-U.S.		(12,178,315	)		(7,309,215	)
Net income (loss) before income taxes	$	(7,734,930	)	$	(4,247,479	)

F-30

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

The components of the Company’s deferred tax assets at December 31, 2011 and 2010 are as follows:

	2011			2010
Deferred tax assets and liabilities:
Loss carry-forwards	$	4,891,132		$	3,327,236
Oil properties		7,204,385			5,817,928
Property and equipment		(14,400	)		(18,000	)
Accounts receivable		-			(66,000	)
Stock-based compensation		672,369			486,041
Net deferred tax asset		12,753,486			9,547,205
Net deferred tax liability		(1,470,000	)		(1,470,000	)
Valuation allowance		(11,283,486	)		(8,077,205	)
	$	-		$	-

Income tax benefit differs from the amount computed at the federal statutory rates (approximately 34%) for the year ended December 31, 2011 and 2010 as follows:

	2011			2010
Income tax benefit at statutory rate	$	(2,476,661	)	$	(1,340,433	)
Permanent differences:
Non-taxable book gain under ASC 815-40		(2,574,790	)		(2,033,401	)
Other		39,400			101,782
Goodwill impairment		1,845,169			-
Increase in valuation allowance		3,206,281			3,322,943
Tax expense	$	39,399		$	50,891

As of December 31, 2011, the Company had generated U.S. net operating loss carry-forwards of approximately $6,416,139 which expire between 2028 and 2031, and net loss carry-forwards in certain non-U.S. jurisdictions of approximately $8,016,616 which do not expire.

These net operating loss carry-forwards are available to reduce future taxable income. However, as the Company has had cumulative losses since inception and there is no assurance of future taxable income, valuation allowances have been recorded to fully offset the deferred tax asset at December 31, 2011 and 2010.The following is the analysis of valuation allowances:

	2011		2010
Balance, beginning of year	$	8,077,205	$	3,945,000
Provision/(benefit)		3,206,281		3,322,943
Prior year true-up		-		(15,738	)
Avante acquisition		-		825,000
	$	11,283,486	$	8,077,205

Foreign Taxes

The Company has activities in Colombia through its wholly owned subsidiaries and is subject to Colombia Income tax. Colombia’s current tax rate is 33%. As of December 31, 2011, the Colombia operation has been incurring losses and hence no income tax liability has been accrued. However, Colombia imposes a presumptive tax which is part of its income tax system but is calculated based on net worth of the Company. As of December 31, 2011 and 2010, the Company has recorded income tax expense of $39,399 and $50,891, respectively, for the presumptive tax.

F-31

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Colombian Equity-Based Tax

In 2010, the Colombian government enacted a tax reform act which, among other things, adopted a one-time, net-worth tax for all Colombian entities. For purposes of this tax, the net worth of an entity was assessed on January 1, 2011, and the tax is payable in eight semi-annual installments from 2011 through 2014. Based on the Company’s Colombian entities’ net equity, the Company’s total net-worth gross tax obligation was approximately $1.1 million. The Company recognized the related expense arising from this tax obligation of approximately $779,000 (the present value of all future payments as of January 1, 2011) as a component of general and administrative expenses in the consolidated statement of operations during the year ended December 31, 2011, and recorded $125,866 as interest expense during the year ended December 31, 2011. The present value of this obligation as of December 31, 2011 (using a discount rate of 18%, which approximates the Company’s borrowing rate) is reflected as other liabilities in the Company’s consolidated balance sheet as of December 31, 2011 for the amount of $623,941. Approximately $246,040 of the total obligation is classified as a current liability as of December 31, 2011.

(12)	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 management believes, if determined in a manner adverse to the Company, could have a potential material adverse effect on its financial condition, results of operations or cash flows.

Additionally, the Company 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 the Company could be adversely affected.

The Company’s total cash capital requirements for 2012are anticipated to be approximately $10.5 million. This amount includes the Company’s commitments in the Putumayo-4 Block for approximately $5.2 million, Maranta Block commitments for approximately $4.97 million, and the Puerto Barco and Rio de Oro fields for approximately $0.3 million.

Leases

The Company has signed a three year lease in Bogotá, Colombia. 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”. This lease was renewed for one more year and will expire on July 2, 2012.

For the years ended December 31, 2011 and 2010, the Company recorded rent expense of approximately $131,000 and $125,000, respectively.

Based on an estimated exchange rate of COP 1,850 per US dollar for the year 2012, annual lease payment commitments for the remainder of the lease have been calculated as follows:

		Total Lease Payment
Year		Amount
2012	$	68,000

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.

F-32

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

Supplemental Oil and Gas Disclosures (Unaudited)

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 years ended December 31, 2011 and 2010 are presented below:

	2011		2010
Acquisition costs*	$	-	$	9,808,470
Development costs		-		-
Exploration costs		792,321		4,291,610
Total acquisition, development and exploration costs	$	792,321	$	14,100,080

*In March 2010, the Company acquired Avante Colombia by issuing 10,285,819 shares of its common stock. Avante Colombia owns 50% participation interest in Rio de Oro and Puerto Barco.

Exploration costs consist of seismic and other exploration costs.

Net Proved Oil Reserves

The proved oil reserves of La Cortez have been estimated by an independent petroleum engineer, DeGolyer and MacNaughton (“D&M”), as of December 31, 2011. As of December 31, 2010 and 2009, the independent petroleum engineer was Ryder Scott. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission (“SEC”) rules and accounting standards based on the 12-month un-weighted first-day-of-the-month average price for December 31, 2011. All of the Company’s reserves are located in Colombia.

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

	Oil (Bbls)
	For the year			For the year
	ended			ended
	December 31, 2011			December 31, 2010
Total Proved Reserves:
Beginning balance		92,574			74,230
Discoveries		-			61,249
Production		(35,148	)		(4,741	)
Revisions of previous estimates due to performance		28,686			(38,164	)
Ending balance		86,112			92,574
Proved Developed Reserves:
Beginning balance		92,574			74,230
Ending balance		86,112			92,574

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

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 in accordance with ASU 2010-03 by applying the 12-month un-weighted first-day-of-the-month average price for the year ended December 31, 2011 and 2010. 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 carry forward of prior year net operating losses and future depletion are expected to result in no taxable income over the life of the properties.

F-33

LA CORTEZ ENERGY, INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

	2011			2010
Future production revenues:	$	6,714,000		$	6,705,129
Future costs:
Production		(2,663,000	)		(4,208,482	)
Development		(300,000	)		(1,800,000	)
Future net cash flows		3,751,000			696,647
10% annual discount for estimated timing of cash flows		(493,000	)		9,707
Standardized measure of discounted net cash flows	$	3,258,000		$	706,354

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

	2011			2010
Increase (decrease):
Sales of oil produced, net of production costs	$	(1,551,529	)	$	(317,049	)
Net changes in prices and production costs		1,546,866			442,223
Previously estimated development costs incurred during the period		-			364,542
Changes in future development costs		1,419,835			(2,474,125	)
Revisions of previous quantity estimates due to prices and performance		1,171,568			(441,412	)
Accretion of discount		69,665			80,646
Discoveries, net of future production and development costs associated with these extensions and discoveries		-			2,072,641
Other		(104,759	)		172,433
Net increase (decrease)		2,551,646			(100,101	)
Standardized measure of discounted future net cash flows:
Beginning of year		706,354			806,455
End of year	$	3,258,000		$	706,354

The weighted average oil price used in computing the Company's reserves were $77.97 per bbl and $72.43 bbl at December 31, 2011 and 2010, respectively.

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-34

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.

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.

Foreland:the plain surface right before the skirt of the mountain starts.

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 (CH 4 ), 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.

G-1

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.

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.

G-2

EXHIBIT INDEX

10.26		Joint Operating Agreement between Emerald Energy and La Cortez Energy Colombia Inc., dated as of February 04, 2010.

10.27		Joint Operating Agreement between Petrotesting Colombia SA and Avante Colombia Ltda., dated as of April 28, 2006.

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

99.1		Reserves report of DeGolyer and MacNoughton

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

DevMar Equities (DEVM) Inactive 10-K2011 FY Annual report

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