UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
T	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2011
	OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 0-8933

APCO OIL AND GAS INTERNATIONAL INC.

(Exact Name of Registrant as Specified in its Charter)

Cayman Islands	98-0199453
(State or Other Jurisdiction of Incorporation or Organization)	(IRS Employer Identification No.)
One Williams Center, Mail Drop 35
Tulsa, Oklahoma	74172
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s Telephone Number, Including Area Code: (918) 573-2164

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Ordinary Shares $.01 Par Value Class A Shares $.01 Par Value	The NASDAQ Stock Market The NASDAQ Stock Market

          The NASDAQ Capital Market)

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes £ No T

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes £ No T

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the 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 T 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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T     No o

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. T

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

Large Accelerated Filer T  Accelerated Filer £   Non-Accelerated Filer £   Smaller reporting company £

                                                                 (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 T

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, was $794,415,099. This value was computed by reference to the closing price of the registrant’s shares on such date. Since the registrant’s shares trade sporadically in The NASDAQ Capital Market, the bid and asked prices and the aggregate market value of shares held by non-affiliates based thereon may not necessarily be representative of the actual market value. Please read Item 5 for more information.

As of February 17, 2012, there were 9,139,648 shares of the registrant’s ordinary shares and 20,301,592 shares of the registrant’s Class A shares outstanding.

Documents Incorporated By Reference

Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s 2012 Annual General Meeting of Shareholders to be held on May 31, 2012, are incorporated into Part III, as specifically set forth in Part III.

APCO OIL AND GAS INTERNATIONAL INC.

FORM 10-K

TABLE OF CONTENTS

	PART I
		Page No.
Items 1 and 2.	Business and Properties
Item 1A.	Forward Looking Statements/Risk Factors and Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
	Risk Factors
Item 1B.	Unresolved Staff Comments
Item 3.	Legal Proceedings
Item 4.	Mine safety Disclosures
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.	Controls and Procedures
Item 9B.	Other Information
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.	Certain Relationships and Related Transactions, and Director Independence
Item 14.	Principal Accounting Fees and Services
	PART IV
Item 15.	Exhibits and Financial Statement Schedules

i

DEFINITIONS

We use the following oil and gas measurements and abbreviations in this report:

- “Bbl” means barrel, or 42 gallons of liquid volume, “Mbbls” means thousand barrels, and “MMbbls” means million barrels.

- “Mbbls/day” means thousand barrels per day.

- “Mcf” means thousand cubic feet, “MMcf” means million cubic feet, and “Bcf” means billion cubic feet.

- “Mcf/d” means thousand cubic feet per day.

- “Boe” means barrel of oil equivalent, a unit of measure used to express all of the Company’s products in one unit of measure based on choleric equivalency of the three products; one barrel of oil is equal to one barrel of oil equivalent, six Mcf of gas are equal to one barrel of oil equivalent, and one ton of LPG is equivalent to 11.735 barrels of oil equivalent.

- “Mboe” means thousand barrels of oil equivalent, and “MMboe” means million barrels of oil equivalent.

- “LPG” means liquefied petroleum gas. More specifically in this report, the Company produces propane and butane at its LPG plant; LPG may also be referred to as plant products.

- “Metric ton” means a unit of mass equal to 1,000 kilograms (2,205 pounds); as used in this report, a metric ton is equal to 11.735 barrels of oil equivalent.

- “2D” means two dimensional seismic imaging of the subsurface.

- “3D” means three dimensional seismic imaging of the subsurface.

- “WTI” means West Texas Intermediate crude oil, a type of crude oil used as a reference for prices of crude oil sold in Argentina.

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PART I

ITEM I and 2.   BUSINESS AND PROPERTIES

(a) General Development of Business

Apco Oil and Gas International Inc. is a Cayman Islands exempted limited company organized on April 6, 1979 as a successor to Apco Argentina Inc., a Delaware corporation organized on July 1, 1970. References in this report to “we,” “us,” “our,” “Apco,” or the “Company” refer to Apco Oil and Gas International Inc. and its consolidated subsidiaries and, unless the context indicates otherwise, its proportionately consolidated interests in various joint ventures.

We are an international oil and gas exploration and production company with a focus on South America. Exploration and production will be referred to as “E&P” in this document. We began E&P activities in Argentina in the late 1960s and entered Colombia in 2009.  As of December 31, 2011, we had interests in eight oil and gas producing concessions and two exploration permits in Argentina, and three exploration and production contracts in Colombia. Our producing operations are located in the Neuquén, Austral, and Northwest basins in Argentina.  We also have exploration activities currently ongoing in both Argentina and Colombia.

WPX Energy, Inc. (“WPX Energy”) owns 68.96 percent of our outstanding shares.  Prior to December 31, 2011, WPX Energy was a wholly-owned subsidiary of The Williams Companies, Inc. (“Williams”). Effective December 31, 2011, all of the common stock of WPX Energy was distributed, on a pro rata basis, to the stockholders of Williams (the “spin-off”), and WPX Energy became a 100% publicly owned company.  After the spin-off, Williams does not own any interest in the equity securities of Apco.

Please read “Security Ownership of Certain Beneficial Owners and Management” in our definitive Proxy Statement, which information is incorporated by reference herein.  Our executive officers are employees of WPX Energy and some of our directors are employees of WPX Energy.  In addition, pursuant to an administrative services agreement, WPX Energy provides certain other services to us, such as risk management, internal audit services, and, for our headquarters office in Tulsa, Oklahoma, office supplies, office space and computer support.  Please read “Certain Relationships and Related Party Transactions” in our definitive Proxy Statement for the 2012 Annual General Meeting of Shareholders, which information is incorporated by reference herein.

(b) Financial Information About Segments

We treat all operations as one operating segment. For additional information, see “Financial Statements and Supplementary Data” in Item 8 of this report.

(c) Narrative Description of Business

Our business model is to create strategic partnerships to share risk and gain operational efficiencies in the exploration, development and production of oil and natural gas. We have historically acquired non-operating interests in the producing properties in which we participate.

Although we place great reliance on our operating partners because we generally have non-operating interests, Apco actively participates in the management of our subsurface resources and reservoirs.  Our branch office in Buenos Aires includes technical, administration and accounting staff, which obtains operational and financial data from our joint venture operators that is used to monitor operations. Our technical staff continuously analyzes and evaluates subsurface data and reservoir performance, provides technical assistance to our joint venture operators, makes recommendations regarding field development and reservoir management, and calculates our estimates of reserves.  When deemed strategically appropriate, we have occasionally chosen to operate properties that are exploratory in nature and are prepared to operate producing properties given the right opportunity.

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In Argentina, we are active in four of the five principal producing basins in the country. Our core assets are located in the Neuquén basin in the provinces of Río Negro and Neuquén in southwestern Argentina, where we have been active for more than 40 years.  In 2009, we expanded our E&P activities into Colombia where we have interests in three exploration blocks.

In general, we conduct our E&P operations in our concessions through participation in various joint venture partnerships.  We also have a significant equity interest in combination with our direct working interest in our core properties.  The following table details the areas and basins where we have E&P operations and our respective direct working and equity interests in those areas:

				Interest
Area	Basin	Province	Country	Working	Equity (1)	Combined
Entre Lomas	Neuquén	Neuquén / Río Negro	Argentina	23.00%	29.79%	52.79%
Bajada del Palo	Neuquén	Neuquén	Argentina	23.00%	29.79%	52.79%
Charco del Palenque	Neuquén	Río Negro	Argentina	23.00%	29.79%	52.79%
Agua Amarga	Neuquén	Río Negro	Argentina	23.00%	29.79%	52.79%
Coirón Amargo	Neuquén	Neuquén	Argentina	45.00%	-
Acambuco	Northwest	Salta	Argentina	1.50%	-
Río Cullen	Austral	Tierra del Fuego	Argentina	25.78%	-
Las Violetas	Austral	Tierra del Fuego	Argentina	25.78%	-
Angostura	Austral	Tierra del Fuego	Argentina	25.78%	-
Sur Río Deseado Este (2)	San Jorge	Santa Cruz	Argentina	16.94%	-
Llanos 32	Llanos	Casanare	Colombia	20.00%	-
Turpial	Middle Magdalena	Boyaca / Antioquia	Colombia	50.00%	-
Llanos 40	Llanos	Casanare	Colombia	50.00%	-

(1)   In addition to our direct working interests in the Entre Lomas, Bajada del Palo, Agua Amarga and Charco del Palenque blocks, Apco and its subsidiaries own 40.72 percent of the shares of Petrolera Entre Lomas S.A. (“Petrolera”) which holds a 73.15 percent direct working interest in the areas, resulting in a 29.79 percent equity interest for Apco. Consequently, Apco’s combined direct working interest and equity interest in the four areas totals 52.79 percent.  We refer to these properties in a group as our “Neuquén basin properties.”

(2)   In the Sur Río Deseado Este concession our 16.94 percent working interest is in an exploitation area with limited oil production and we have an 88 percent working interest in an exploratory area in the northern sector of the concession.

Oil and Gas Producing Activities

All of our production and reserves are located in Argentina as of December 31, 2011. Our core properties in the Neuquén basin predominantly produce crude oil and associated natural gas.  Our other properties in the Northwest and Austral basins predominantly produce natural gas and condensate.  On a Boe basis, 56 percent of our combined consolidated and equity proved reserves are oil and condensate and 44 percent are natural gas as of December 31, 2011.

Our current portfolio of reserves provides us with strong capital investment opportunities for several years into the future. Our goal is to drill existing proved undeveloped reserves, which comprise 39 percent of our total proved reserves, and also drill in unproven areas as a result of exploration and/or field-extension drilling to add to our proved reserves and replace as much of the current year’s production as possible. In recent years, we have complemented our development projects in Argentina by increasing exploration activities in both Argentina and Colombia.

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Oil and Natural Gas Reserves

Summary of Proved Oil and Natural Gas Reserves as of December 31, 2011

Based on Average 2011 Prices

	Oil and Liquids (Mbbls) (1)			Natural Gas (Bcf) (2)			Total Proved (Mboe) (3)
	Interests			Interests			Interests
	Consolidated	Equity	Combined	Consolidated	Equity	Combined	Consolidated	Equity	Combined
Proved Developed	7,291	8,252	15,543	41.0	28.5	69.5	14,124	13,002	27,126
Proved Undeveloped	4,608	4,837	9,445	23.7	22.6	46.3	8,558	8,604	17,162
Total Proved (4)	11,899	13,089	24,988	64.7	51.1	115.8	22,682	21,606	44,288

(1)    Volumes presented in the above table have not been reduced by the provincial production tax that is paid separately and is accounted for as an expense by Apco. For natural gas, the provincial production tax is paid on volumes sold to customers, but generally not on natural gas consumed in operations.  Our effective tax rate is approximately 14 percent.

(2)    A portion of our natural gas reserves are consumed in field operations.  The volume of natural gas reserves for 2011 estimated to be consumed in field operations included as proved natural gas reserves within our consolidated interests are 13.9 Bcf and 15.6 Bcf for our equity interests, or an oil equivalent combined amount of 4,915 Mboe.

(3)    Natural gas is converted to oil equivalent at six Bcf to one million barrels.

(4)    All of our reserves are in Argentina as of December 31, 2011.

Preparation of Reserves Estimates

Our engineering staff in our office in Buenos Aires provides reserves modeling and production forecasts for our concessions. The finance and accounting department provides supporting information such as pricing, costs, tax rates and other information pertinent to developing our discounted cash flows. The entire reserves process is coordinated by management in our head office. Our reserves analysis also includes working closely with joint venture operators to coordinate future investment plans; contracting with a third-party consultant to complete the independent review; ensuring internal controls are appropriate and making any changes required; performing internal overview of data for reasonableness and accuracy; and the final preparation of the year-end reserves report.

Preparing Apco’s year-end reserves is a formal process. It begins soon after finalizing year-end reserves with a review of the existing process to identify where improvements can be made. The internal controls relating to the year-end reserves process are reviewed and updated generally in early summer of each year. Typically in late summer, our reserves engineering and geological technical staff, management, and the third-party engineering consultants meet to begin coordinating the year-end process and review. Throughout the third quarter, the reserves staff, third-party engineering consultants, and joint venture operators exchange data and interpretations to finish year-end reserves estimations. During the fourth quarter, forecasts, interpretations, maps and preliminary estimates of reserves are reviewed with upper management for their comment.

All of our total year-end 2011 proved reserves estimates on a Boe basis were audited by Ralph E. Davis Associates, Inc. (“Davis”).  When compared on a well-by-well basis, some of our estimates were greater and some were less than the estimates of Davis. Any differences were discussed and resolved.  In the opinion of Davis, the estimates of our proved reserves are in the aggregate reasonable by basin and total and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Davis is satisfied with our methods and procedures in preparing the December 31, 2011 reserves estimates and saw nothing of an unusual nature that would cause Davis to take exception with the estimates, in the aggregate, as prepared by us. Davis’ report is included as an exhibit to this Form 10-K.

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The engineer primarily responsible for overseeing preparation of the reserves estimates and the third party reserves audit is our Manager of Engineering.  The Manager’s qualifications include over 20 years of reserves evaluation experience, a Ph.D in Petroleum Engineering from the University of New Mexico at Socorro, New Mexico, and a B.S. in Petroleum Engineering from the University of Buenos Aires, Argentina.

Proved Undeveloped Reserves

Our proved undeveloped reserves for our combined interests as of December 31, 2011 are 17.2 MMboe, compared with 18.0 MMboe as of December 31, 2010.  All locations comprising our remaining proved undeveloped reserves are forecast to be drilled by 2016; 25 percent of these locations are expected to be drilled in 2012.  For many years we have enjoyed a track record of success converting proved undeveloped reserves to proved producing reserves as we have drilled and put on production undeveloped locations, including both step-out and in-fill wells, with a greater than 90 percent success rate. Historically, all of our drilling investments have been financed by internally generated cash flows and cash reserves. During 2011, 3.0 MMboe, or 16 percent of our net proved undeveloped reserves as of December 31, 2010, were converted to proved developed reserves.

Oil and Natural Gas Properties, Wells, Operations, and Acreage

The following table sets forth our productive oil and gas wells and our developed acreage assignable to such wells as of December 31, 2011. We use the terms “gross” to refer to all wells or acreage in which we have a working interest and “net” to refer to our ownership represented by that working interest.  Because of our significant equity interest in our core areas, we also include our share of our equity investee’s net interests.

	Productive Wells
	Oil			Gas			Developed Acreage
	Gross	Net	Equity	Gross	Net	Equity	Gross	Net	Equity	Combined
Neuquén basin	551	127	163	28	6	9	51,519	11,899	15,310	27,209
Austral basin	82	21	-	28	7	-	11,641	3,001	-	3,001
Northwest basin	3	-	-	6	-	-	13,106	197	-	197
San Jorge basin	7	-	-	-	-	-	-	-	-	-
Total Argentina	643	148	163	62	13	9	76,266	15,097	15,310	30,407

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At December 31, 2011, we held the following undeveloped acreage in Argentina and Colombia:

	Undeveloped Acreage
	Gross Acres	Net	Equity	Combined
Neuquén basin	436,110	122,255	100,396	222,651
Austral basin	455,448	117,415	-	117,415
Northwest basin	280,515	4,208	-	4,208
San Jorge basin	75,582	57,736	-	57,736
Total Argentina	1,247,655	301,614	100,396	402,010
Colombia	374,363	153,862	-	153,862
Total Company	1,622,018	455,476	100,396	555,872

Our Neuquén basin properties have various concession terms that currently end between 2016 and 2034.  Approximately six percent, 15 percent and 11 percent of our undeveloped acreage in our Neuquén basin properties is subject to exploration permits that expire in 2012, 2013 and 2017. The permits can be extended various times in exchange for relinquishing certain amounts of the acreage and making additional investment commitments.  Our properties in the Austral, San Jorge and Northwest basins currently have concession terms which end on dates ranging from 2016 to 2036.  Apco and its operating partners will attempt to secure the ten-year extensions from the respective provinces for all of our Argentine concessions for which such extensions have not yet been negotiated. Our acreage in Colombia is held under exploration and production contracts that expire in 2012 and 2014, unless commercial quantities of hydrocarbons are found, in which case a 24-year exploitation period would be granted.

Neuquén Basin Properties

Since 1968, Apco has participated in a joint venture partnership with two Argentine companies, Petrolera and Petrobras Argentina S.A. (“Petrobras Argentina,” formerly Petrobras Energía S.A. and before that, Pecom Energía S.A.) The purpose of the joint venture is the exploration and development of the Entre Lomas oil and gas concession in the provinces of Río Negro and Neuquén in southwest Argentina. In 2007, the partners created two new joint ventures consisting of the same partners with the same interests in order to expand operations into two areas adjacent to Entre Lomas, the Agua Amarga exploration permit in the province of Río Negro, and the Bajada del Palo concession in the province of Neuquén. In 2009, a portion of the Agua Amarga permit was converted to a 25-year exploitation concession called Charco del Palenque.

Although these blocks are separate areas governed by their own concession and exploration permit agreements, the areas are operated and managed by Petrolera as an extension of Entre Lomas to achieve efficiencies through economies of scale. Infrastructure in the Entre Lomas concession has sufficient existing capacity to accommodate production volumes from all the areas during the early stages of exploration and development of Bajada del Palo, Agua Amarga and Charco del Palenque. Pipelines and electric power lines to supply power from our Entre Lomas power generating plant have been extended over relatively short distances to connect storage facilities in the new areas to treating, pumping and transportation facilities in place in the Entre Lomas concession.

The partners' interests in the above mentioned joint ventures as of December 31, 2011 are as follows:

Petrolera (Operator)	73.15%
Apco	23.00%
Petrobras Argentina	3.85%
	100.00%

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In addition to our direct participation interest, we own an effective 29.79 percent equity interest in the areas through our stock ownership in Petrolera, which holds a 73.15 percent direct interest in each of the properties. Our 23 percent direct participation interest combined with our 29.79 percent equity interest gives us an effective 52.79 percent interest in all of the properties operated by Petrolera.

Petrolera Entre Lomas S.A.

Petrolera is an Argentine company with administrative offices in Buenos Aires and Neuquén and a field office with technical staff located on the Entre Lomas concession.  Petrolera has been a partner in the Entre Lomas joint venture since its inception. As of December 31, 2011, Petrolera had 109 employees.  The shareholders of Petrolera and their ownership percentages are as follows:

Petrobras and affiliates	58.88%
Apco and affiliates	40.80%
Other	0.32%
	100.00%

Investment decisions and strategy for development of the properties are agreed upon by the joint venture partners and implemented by Petrolera. Petrolera has a board of 11 directors, five of whom are selected by Apco and six of whom are selected by Petrobras and its affiliates. Petrolera’s operating and financial managers and field personnel are employed exclusively by Petrolera.

Our branch office in Buenos Aires obtains operational and financial data from Petrolera that is used to monitor joint venture operations. The branch provides technical assistance to Petrolera and makes recommendations regarding field development and reservoir management.

Entre Lomas Concession

The Entre Lomas concession is located about 950 miles southwest of the city of Buenos Aires on the eastern slopes of the Andes Mountains. It straddles the provinces of Río Negro and Neuquén approximately 60 miles north of the city of Neuquén. The concession covers a surface area of approximately 183,000 acres and produces oil and gas from several fields, the largest of which is Charco Bayo/Piedras Blancas (“CB/PB”). The concession is equipped with centralized facilities that serve all productive fields.  These facilities include processing, treating, compression, injection, storage, power generation and an automatic custody transfer unit through which all oil production is transported to market.

The most productive formation in the concession is the Sierras Blancas (commonly referred to as the Tordillo formation), but we also produce oil and gas from the Quintuco and the Punta Rosada formations (also known as the Petrolifera). The joint venture extracts propane and butane from gas production in its gas processing plant located in the concession. Secondary recovery projects whereby water is injected into the producing reservoirs to restore pressure and increase the ultimate volume of recoverable hydrocarbons are used extensively in the Entre Lomas concession.

The Entre Lomas concession has a primary term of 25 years that expires in the year 2016 with an option to extend for an additional ten years based on terms to be agreed with the government.  In 2009, the concession contract for the portion of the Entre Lomas concession located in the Neuquén province was extended to January 2026.  This extension agreement does not apply to the portion of the Entre Lomas concession located in Río Negro. The formal process to negotiate the extension with the provincial government of Río Negro began in 2010, and we expect to finish those negotiations in 2012.

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Bajada del Palo Concession

The Bajada del Palo concession has a total surface area of approximately 111,000 acres and produces oil and associated natural gas from three fields.  In 2009, the concession term for the property was extended to September 2025.  Bajada del Palo is located in the province of Neuquén immediately to the south and west of the Entre Lomas concession and to the northwest of the Agua Amarga area.  Its westernmost boundary is near Repsol YPF S.A.’s (“YPF”) Loma de la Lata concession.

The purchase of the Bajada del Palo concession in 2007 was a strategic bolt-on acquisition for us due to the proximity of our other operations with Petrolera and because the primary target formations in Bajada del Palo are the same as those that have been developed and produced for many years in Entre Lomas.  Since acquiring the property we have reactivated the Borde Montuoso field and are actively developing it. We have also acquired 3D seismic information and drilled several exploration wells.  Two of the exploration wells were Tordillo discovery wells on two separate structures in the eastern part of the block. Field development of both discoveries is underway.

During 2011, we drilled two Tordillo development wells on the aforementioned new fields and encountered natural gas in the underlying Lotena formation. Our Borde Montuoso oil field was previously a Lotena formation natural gas field that accumulated 32 Bcf of natural gas before going off- production in 2002.  Also in 2011, a previously drilled well in the western part of the concession known as Aguada del Poncho was reactivated and put on production from the Quintuco formation. 3D seismic acquired in 2010 over the Aguada del Poncho area helped to identify and drill two exploration prospects to the Quintuco formation which were put on production in fourth quarter 2011.

Agua Amarga and Charco del Palenque

The Agua Amarga exploration area was awarded to Petrolera by the province of Río Negro in 2007.  The property has a total surface area of approximately 95,000 acres and is located immediately to the southeast of the Entre Lomas concession.  After completing our 3D seismic and exploration drilling commitments, a portion of the Agua Amarga area covering approximately 18,000 acres was converted to an exploitation concession called Charco del Palenque in 2009.  The concession has a 25-year term and a five-year optional extension period and encompasses an area required to develop four Tordillo discoveries drilled since 2007.  In 2011, the Charco del Palenque concession was extended by 4,900 acres in order to include acreage required to develop our successful exploration well drilled on the Meseta Filosa prospect earlier in the year.

During 2011, approximately 47,000 acres of the exploration permit was converted to the status of “Lote de Evaluación,” or “evaluation lot” with a term of five years in order to perform a long-term production test of our Jarilla Quemada natural gas discovery drilled in 2010.  This status provides sufficient time to construct facilities and determine the potential of this discovery in both the Tordillo and the Molles formations.  The acreage is not subject to relinquishment during this period. The Jarilla Quemada x-1 well has produced oil from the Quintuco formation during 2011.

The remaining acreage from the exploration permit area that has not been converted to an exploitation concession will be subject to relinquishment in May 2012, or we can elect to enter another exploration period in exchange for additional work commitments.

Coirón Amargo

We entered into a farm-in agreement in 2010 that allowed us to acquire, through a “drill to earn” structure, a 45 percent net interest in the Coirón Amargo exploration permit in the Neuquén basin.  The Coirón Amargo block covers approximately 100,000 acres and is adjacent to our core properties in the basin.  ROCH S.A., the operator of our Austral basin properties, is a partner in and the operator of the Coirón Amargo block. Although our participation in Coirón Amargo is outside of our joint ventures with Petrolera, this area leverages our experience gained through exploring and developing in the region for over 40 years.

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Under the agreement, we earned a 45 percent non-operated interest for funding the drilling of two exploration wells during 2010 and two exploration wells in 2011.  The four wells discovered oil and associated natural gas from the Tordillo formation.

The current exploration period for the block expired in November 2011.  We have agreed with the province to convert approximately 26,700 acres into an exploitation concession with a term of 25 years. The remaining portion of the block has been deemed a “high-risk exploration area” that will require exploration commitments of approximately $18 million net to Apco during 2012 and 2013 to investigate unconventional potential from the Vaca Muerta, Molles and Lotena formations in the block.  After the two-year exploration period, we will determine how much of the area will be converted to an exploitation concession and how much acreage, if any, will have to be relinquished.  The agreement with the province has been executed and formal approval of the concession and the exploration period extension is pending approval by executive decree which we expect to be issued in the first quarter of 2012.

Neuquén Exploration

Apco and its partners make extensive use of 3D seismic information to develop and explore in our Neuquén basin properties.  In addition to aiding in the development of existing producing areas, the seismic surveys have two exploratory objectives. The primary exploratory objective is finding lower risk exploration opportunities that target formations known to be productive from structural closures and/or fault traps that exist away from the principal producing structures. The second objective is to evaluate high-risk, deep exploration potential.

Since 2005, on the basis of interpretation of 3D seismic, we have successfully drilled many lower risk wells on structural closures or fault traps away from principal producing structures. The structures on which these wells have been drilled are limited in size compared with the principal producing fields in Entre Lomas and do not present development opportunities of more than a few wells. The geologic model we use for identifying fault traps in the southeast region of the Entre Lomas concession has proven to be an excellent predictor of trapped hydrocarbons. The additions of the Agua Amarga exploration permit, the Bajada del Palo concession and the Coirón Amargo exploration permit were in part based on the interpretation that the trend of faults that have been identified in the southeast region of the Entre Lomas concession continues into these areas, and has since resulted in proved reserve additions due to successful exploration and subsequent development drilling.

We are drilling development wells on the structures where discoveries were made in the blocks. We will continue drilling these new structures in the foreseeable future and investigating other undrilled structures on our properties in this region of the Neuquén basin by applying the geologic model that has yielded these successes. In addition to these activities, we and our partners are in the process of studying and evaluating exploration potential of sedimentary layers deeper than those currently on production in our blocks, including potential for shale production and unconventional natural gas.

Shale and Tight Sands in the Neuquén Basin  

In recent years, oil and gas companies operating in the Neuquén basin have been evaluating the possibility of unconventional sources for hydrocarbon production.  The subsurface formations of interest comprise both shale and what is commonly referred to as “tight sands.”  Our interests in the Neuquén basin include exploitation concessions and exploration permits that are contiguous and comprise approximately 245,000 net acres.  The formations of interest are present in all of the properties in which we participate in the basin.

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In early 2011, we completed a three-well pilot program to stimulate oil production from the Vaca Muerta shale using single-stage fractures in three existing wells, two of which were located in the eastern side of the Bajada del Palo concession and one in the Borde Mocho field in the Entre Lomas concession. The Vaca Muerta formation was not productive after these fracture-stimulations. We concluded from this experience that larger multi-stage fractures are required to increase the probability that Vaca Muerta could be oil productive.

We are applying these lessons in our Coirón Amargo exploration permit. In December 2011, we commenced a three- stage fracture-stimulation of a well we drilled earlier in the year, the CAS x-1. The CAS x-1 well discovered oil in the Tordillo formation but was placed on production from the Vaca Muerta from which it has produced small volumes of oil on an intermittent basis. After completing the fracture, a long term production test of the Vaca Muerta commenced in February 2012.  During an initial two week production test, the well flowed intermittently at an average rate of 241 barrels of oil per day.  The test is expected to resume in the near future.  These results are not conclusive as exploration of the Vaca Muerta in this basin is in the very early stages and the productive behavior of the Vaca Muerta formation is not well understood.

Also during December, we commenced drilling the CAS x-4 in the southeastern portion of the Coirón Amargo exploration permit. This well reached  a total depth of 12,149 feet and a core sample of the Vaca Muerta formation was taken for laboratory analysis. We plan to perform a multi-stage fracture of this well after the core analysis is completed and we have evaluated results of the production test of the CAS x-1 well. In the meantime, completion of the well will proceed in order to test formations underlying Vaca Muerta.

In the Bajada del Palo concession, we and our partners are preparing to conduct a multi-stage fracture of one of the existing wells in the Borde Montuoso field where there have been numerous manifestations of oil when penetrating the Vaca Muerta shale while drilling development wells to the Tordillo. This fracture stimulation is scheduled to commence in February.

Environment and Occupational Health

The Argentine Department of Energy and the government of the provinces in which oil and gas producing concessions are located have environmental control policies and regulations that we must adhere to when conducting oil and gas exploration and exploitation activities.  In response to these requirements, Petrolera implemented and maintains an Environmental Management System needed to comply with ISO 14001: 2004 environmental standards, and OHSAS 18001: 2007 to achieve occupational safety and health standards.  This system encompasses all of the properties that Petrolera operates.  Independent party audits are conducted annually to assure that Petrolera’s certifications remain in compliance.  Other complementary activities related to environment, safety and health are performed in addition to the standards required by the local governing authorities to improve the system.

Northwest Basin Properties

Acambuco Concession

Apco holds a 1.5 percent non-operated interest in the Acambuco concession located in the province of Salta in northwest Argentina on the border with Bolivia. The concession covers an area of 294,000 acres, and is one of the largest gas producing concessions in Argentina. There are two producing fields in this concession, the San Pedrito and Macueta fields, which produce primarily from the Huamampampa formation, a deep fractured quartzite with substantial natural gas reserves in this basin and in southern Bolivia. In Acambuco the Huamampampa is found at depths in excess of 14,000 feet. The concession term expires in 2036.

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Acambuco is in an area where drilling is difficult and costly because of the depths of the primary objectives and the extreme formation pressures encountered during drilling. Wells drilled to the Huamampampa formation in the Acambuco concession have generally required one year to drill with total costs for drilling and completion ranging from $50 to $70 million.

The operator of the Acambuco joint venture is Pan American Energy Investments L.L.C., which holds a 52 percent interest.  The remaining interests are held by three other partners, including a subsidiary of WPX Energy, Northwest Argentina Corporation, which holds a 1.5 percent interest.

Austral Basin Properties

Apco holds a 25.78 percent non-operated interest in a joint venture engaged in E&P activities in three concessions located on the island of Tierra del Fuego. The operator of the concessions is ROCH S.A., a privately owned Argentine oil and gas company.

We refer to the Río Cullen, Las Violetas and Angostura concessions as our “TDF concessions.”  These properties are located in the Austral basin which extends both onshore and offshore from the provinces of Santa Cruz to Tierra del Fuego. The principal producing formation is the Springhill sandstone. Several large offshore producing gas condensate fields with significant reserves are productive in the basin, two of which are in close proximity to our concessions.

The concessions cover a total surface area of approximately 467,000 gross acres, or 120,000 acres net to Apco. Each of the concessions extends three kilometers offshore with their eastern boundaries paralleling the coastline. The most developed of the three concessions is the Las Violetas concession which is the largest onshore concession on the Argentine side of the island of Tierra del Fuego.  The concessions have terms of 25 years that expire in 2016 with an option to extend the concessions for an additional ten-year period based on terms to be agreed with the government.  In February 2011, the province of Tierra del Fuego commenced concession extension negotiations with producers on the island.  We expect to finish those negotiations in 2012.

Operations in the TDF concessions are exempt from Argentine federal income taxes pursuant to Argentine law. This exemption is in effect until the year 2023.

San Jorge Basin Properties

In the Sur Río Deseado Este concession in the province of Santa Cruz we have a 16.94 percent working interest in an exploitation area with limited oil production and an 88 percent working interest in an exploratory area in the northern sector of the concession. In December 2011, we commenced the acquisition of 191 square kilometers of 3D seismic information in the northern sector of the concession.  We plan to drill an exploration well in the area during 2012.

Colombia - Overview

In Colombia, we hold a non-operating interest in three exploration and production contracts totaling 374,000 gross acres in the Llanos and Middle Magdalena basins. All three areas are in the early stages of exploration activity, including initial drilling activities expected to commence in first quarter 2012.

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Llanos Basin

In July 2009, we entered into a farm-in agreement to earn a 20 percent interest in the Llanos 32 exploration and production contract (“Llanos 32”).  The Llanos 32 block covers approximately 100,000 acres in the Llanos basin of western Colombia.  We agreed to fund approximately $5.8 million, or 27 percent, of exploration activities during a three-year period ending in 2012 to earn our 20 percent working interest.  After acquiring 260 square kilometers of 3D seismic information in 2010, the remaining work commitments include the drilling of at least two exploration wells.  Environmental permitting delays experienced in 2011 deferred the commencement of drilling activities until first quarter 2012.

Apco and Ramshorn International Limited (“Ramshorn”), a subsidiary of Nabors Drilling, were awarded the Llanos 40 block in the 2010 licensing round.  We hold a 50 percent working interest in the block and Ramshorn holds 50 percent and is the operator.  The Llanos 40 block covers approximately 163,000 acres and is approximately 175 kilometers to the northeast of our Llanos 32 block.  Our three-year first phase exploration work commitments include reprocessing of seismic information, acquiring at least 300 square kilometers, or approximately 74,000 acres, of 3D seismic and drilling four exploration wells.  We anticipate spending approximately $26 million net to us for these work commitments over three years.  The acquisition of 3D seismic information which we estimate will cost $6 million net to us began in early 2012.

Middle Magdalena Basin

In December 2009, we entered into a farm-in agreement to earn a 50 percent working interest in the Turpial block.  Gran Tierra Energy, an established Colombian exploration and production company, is the operator and also holds a 50% working interest.  Turpial covers approximately 111,000 acres of underexplored area between the Velazquez and Cocorna oil fields in the Middle Magdalena basin.  After acquiring seismic information in 2010, the partners agreed to enter a third phase and committed to drill an exploration well in 2011.  Drilling plans for 2011 have been deferred until the receipt of the environmental permit.  Because the exploration period in the Turpial block expired in September 2011, we requested and received a six-month contract extension (effective from the date of receiving the permit, which has not been received to date) due to the permitting delays.

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Oil and Natural Gas Production, Prices and Costs

The table below summarizes total sales volumes, prices and production costs per unit for our consolidated interests and sales volumes and prices for our equity interests for the periods presented:

	For the Years Ended December 31,
	2011				2010				2009
Sales Volumes (1, 2, 3):
Consolidated interests
Crude oil and condensate (Bbls)		1,359,163				1,338,195				1,330,020
Natural gas (Mcf)		6,301,114				6,306,883				5,849,497
LPG (tons)		11,108				9,893				10,097
Barrels of oil equivalent (Boe)		2,539,701	54	%		2,505,438	55	%		2,423,425	55	%
Equity interests
Crude oil and condensate (Bbls)		1,583,806				1,549,396				1,533,828
Natural gas (Mcf)		2,833,101				2,325,353				1,900,786
LPG (tons)		11,519				10,048				10,420
Barrels of oil equivalent (Boe)		2,191,165	46	%		2,054,864	45	%		1,972,900	45	%
Total volumes
Crude oil and condensate (Bbls)		2,942,969				2,887,591				2,863,848
Natural gas (Mcf)		9,134,215				8,632,236				7,750,283
LPG (tons)		22,267				19,941				20,517
Barrels of oil equivalent (Boe)		4,730,866	100	%		4,560,302	100	%		4,396,325	100	%
Total volumes by basin
Neuquén		3,907,207	83	%		3,641,439	80	%		3,493,189	80	%
Austral		616,746	13	%		685,763	15	%		635,193	14	%
Others		206,913	4	%		233,100	5	%		267,943	6	%
Barrels of oil equivalent (Boe)		4,730,866	100	%		4,560,302	100	%		4,396,325	100	%
Average Sales Prices:
Consolidated interests
Oil (per Bbl)	$	62.21			$	52.22			$	43.46
Natural gas (per Mcf)		2.10				1.90				1.70
LPG (per ton)		314.46				346.61				264.33
Equity interests
Oil (per Bbl)	$	62.39			$	52.54			$	44.04
Natural gas (per Mcf)		2.00				1.75				1.52
LPG (per ton)		302.11				358.83				273.02
Average Production Costs (4) per Boe:
Production and lifting cost	$	10.01			$	7.71			$	6.19
Taxes other than income		8.23				5.80				5.03
DD&A		8.13				6.71				6.35

(1)   Volumes presented in the above table represent those sold to customers and have not been reduced by provincial production tax that is paid separately and is accounted for as an expense by Apco. Our effective tax rate is approximately 14 percent.

(2)   Natural gas production represents only volumes available for sale.

(3)   Natural gas is converted to oil-equivalent at six Mcf to one barrel, and one ton of LPG is equivalent to 11.735 barrels.

(4)   Average production and lifting costs, provincial production taxes, and depreciation costs are calculated using total costs divided by consolidated interest sales volumes expressed in barrels of oil equivalent.

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Drilling and Other Exploratory and Development Activities

The following tables summarize our drilling activity by number and type of well for the periods indicated. We use the terms “gross” to refer to all wells in which we have a working interest and “net consolidated” to refer to our ownership represented by that working interest.  Because of our significant equity interest in our core areas, we also include our share of our equity investee’s net interests.

	2011			2010			2009
	Gross	Net Consolidated	Net Equity	Gross	Net Consolidated	Net Equity	Gross	Net Consolidated	Net Equity
Development:
Productive	30.0	6.9	9.0	39.0	9.2	9.3	26.0	6.0	7.8
Non-Productive	0.0	0.0	0.0	3.0	0.7	0.3	0.0	0.0	0.0
Total	30.0	6.9	9.0	42.0	9.9	9.6	26.0	6.0	7.8
Exploratory:
Productive	7.0	2.1	1.5	3.0	0.7	0.3	6.0	1.4	1.8
Non-Productive	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Total	7.0	2.1	1.5	3.0	0.7	0.3	6.0	1.4	1.8
Total:
Productive	37.0	9.0	10.5	42.0	9.9	9.6	32.0	7.4	9.6
Non-Productive	0.0	0.0	0.0	3.0	0.7	0.3	0.0	0.0	0.0
Total	37.0	9.0	10.5	45.0	10.6	9.9	32.0	7.4	9.6

Present Activities

At December 31, 2011, we had 4 gross development wells and 2 exploration wells (1.6 net consolidated 1.5 net equity) in various stages of drilling or completion. Additional activities include a three-stage hydraulic fracture stimulation of the Vaca Muerta formation in an exploration well drilled earlier in 2011.  We are also in the process of acquiring 191 square kilometers 3D seismic information in the Sur Río Deseado Este block in Argentina and  initiating the acquisition of 305 square kilometers of 3D seismic over our Llanos 40 block in Colombia.

Delivery Commitments

We hold obligations to deliver certain amounts of natural gas. Our properties contain sufficient reserves to fulfill these obligations without risk of non-performance during periods of normal infrastructure and market operations.  These transactions do not represent a material exposure.

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Government Regulations

The Company’s operations in Argentina are subject to various laws, taxes and regulations governing the oil and gas industry. Taxes generally include income taxes, value added taxes, export taxes, and other production taxes such as provincial production taxes and turnover taxes. Labor laws and provincial environmental regulations are also in place.

Our right to conduct E&P activities in Argentina is derived from participation in concessions and exploration permits granted by the Argentine federal government and provincial governments that control sub-surface minerals.  In general, provincial governments have had full jurisdiction over concession contracts since early 2007, when the Argentine federal government transferred to the provincial governments full ownership and administration rights over all hydrocarbon deposits located within the respective territories of the provinces, including all exploration permits and exploitation concessions originally granted by the federal government.

A concession granted by the government gives the concession holders, or the joint venture partners, ownership of hydrocarbons at the moment they are produced through the wellhead. Under this arrangement, the concession holders have the right to freely sell produced hydrocarbons, and have authority over operations including exploration and development plans. Concessions generally have a term of 25 years which can be extended for ten years based on terms to be agreed with the government. Throughout the term of their concessions, the partners are subject to provincial production taxes, turnover taxes, and federal income taxes. These tax rates are fixed by law and are currently 12 to 18.5 percent, two percent, and 35 percent, respectively. Subsequent to the transfer of ownership and administrative rights over hydrocarbon deposits to the provinces, provincial governments have sometimes required higher provincial production tax rates or a net profit interest in blocks awarded by the provinces or in concessions that have been granted the ten-year extension.

In Colombia, our right to conduct E&P activities is derived from participation in exploration and production contracts entered into directly with the Colombian National Hydrocarbons Agency (the “ANH”) with no mandatory participation by Ecopetrol, the state oil company.  The ANH was formed in 2003 in response to declining reserves which was leading Colombia toward becoming a net oil importer.

Exploration and production contracts in Colombia typically run for an initial exploration period of up to six years.  The first phase of work usually requires acquisition of new seismic data.  After the first phase, contracts can be retained for up to five additional years, usually by drilling one well per year.  An exploration and production contract can be relinquished after any completed phase at the option of the investor.

Once a field is declared commercial, the exploitation period is 24 years, which may be extended another ten years under certain circumstances.  The investor retains the rights to all reserves and production from newly discovered fields, subject to a sliding scale of royalty, which is initially eight percent for production up to 5,000 barrels of oil per day (“bopd”) per field up to a maximum of 25 percent for production exceeding 600,000 bopd per field.  In addition, a windfall profit tax applies once a field has cumulatively produced more than five million barrels of oil.  The windfall profit tax is 30 percent of the price per barrel received in excess of certain threshold prices which are periodically set by the ANH and are established by the quality of the oil produced.

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MARKETING

OilMarkets

Crude oil produced in the Entre Lomas region of the Neuquén basin is referred to as Medanito crude oil, a high quality oil generally in strong demand among Argentine refiners for subsequent distribution in the domestic market. During 2011, all of the oil produced in our Neuquén basin properties was sold to Argentine refiners. Production from our Neuquén basin properties is transported to Puerto Rosales, a major industrial port in southern Buenos Aires Province through the Oleoductos del Valle S.A. (“Oldelval”) pipeline system.

In previous years, we exported our oil and condensate production from the TDF concessions to Chile. After the Argentine government levied an export tax on hydrocarbon exports from the island of Tierra del Fuego in early 2007, we began to sell our oil production to domestic refiners in Argentina.

The Argentine domestic refining market is limited, and basically consists of five active refiners. As a result, our oil sales have historically depended on a relatively limited group of customers. The largest of these five companies refines mostly its own crude oil production, while the smallest of the five operates only in the northwest basin of Argentina near our Acambuco concession. Decisions to sell to any of the remaining three refiners are based on advantages presented by the commercial terms negotiated with each customer.

A description of our major customers over the last three years is in Note 5 – Major Customers in Item 8 of this report.  As can be seen in Note 5, we had four customers which individually accounted for greater than ten percent of our operating revenues, but we do not believe that the loss of any of these customers would have a material adverse effect on us.  As previously discussed, crude oil produced in the Entre Lomas region of the Neuquén basin, referred to as Medanito crude oil, is a high quality oil in strong demand among Argentine refiners.  Our crude oil production can be marketed to other refiners or exported (with governmental permission and after the domestic market has been supplied), and we have only sold a significant amount of our production to these customers because we have been able to negotiate competitive prices with each particular customer.

For a full discussion about our oil sales prices, see Management’s Discussion and Analysis (“MD&A”) – “Overview of 2011 – Oil and Natural Gas Marketing” in Item 7 of this report.  For additional discussion about the reduced net backs see “Risk Factors – Risks Associated with Operations in Argentina” included in Item 1A of this report, and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk” included in Item 7A of this report.

Natural Gas Markets

Argentina has highly developed natural gas markets and a sophisticated infrastructure in place to deliver natural gas to export markets or to industrial and residential customers in the domestic market.  However, natural gas markets in Argentina are heavily regulated by the Argentine government. In general, the government sets the volumes producers are required to sell to residential customers at low government-regulated prices. Incremental volumes are sold to industrial and other customers, and pricing varies with seasonal factors and industry category.  We generally sell our natural gas to Argentine customers pursuant to short-term contracts and in the spot market.

The Neuquén basin is served by a substantial gas pipeline network that delivers gas to the Buenos Aires metropolitan and surrounding areas, and the industrial regions of Bahia Blanca and Rosario. Natural gas produced in our Neuquén basin properties is readily marketed due to accessibility to this infrastructure and our properties are well situated in the basin with two major pipelines in close proximity. Natural gas produced in this basin that is not under contract can readily be sold in the spot market.

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Natural gas and condensate produced in Acambuco is being sold primarily to domestic distribution companies and industrial customers in the northern part of Argentina under contracts negotiated by the operator of the concession.

The TDF concessions are equipped with internal gathering lines, oil pipelines, a gas treatment plant, and the San Luis LPG plant located in the Las Violetas concession which produces propane and butane that is exported and sold domestically under contract.  In 2008, our joint venture’s production facilities were connected directly to the San Martín pipeline, giving us a physical outlet for transportation of gas from the island of Tierra del Fuego to continental Argentina, where higher prices are realized.  Natural gas production from the TDF concessions is sold under contract to industrial and residential markets on the island of Tierra del Fuego and to industrial customers on the continent.

Argentina is Latin America’s largest producer of natural gas and the country is dependent on natural gas as a source of fuel.  Argentina relies on natural gas to supply one-half of its energy needs which ranks the country near the top in the world in terms of percentage of natural gas as a source of energy.  Heavy government regulation over gas prices since 2002 has kept natural gas prices artificially low and as a result, exploration efforts in Argentina targeting natural gas slowed dramatically during this period.  Consequently, natural gas reserves in the country have fallen significantly and exploration discoveries and development of existing fields have not added sufficient reserves to replace production, resulting in a shortage of natural gas.

The government has attempted to alleviate this shortage by importing natural gas from neighboring Bolivia and high-priced LNG and subsidizing the cost of the imports. Meanwhile, Argentine producers are supplying domestic consumers at prices significantly below those paid for imported natural gas. Subsidizing these high-priced imports has been a significant drain on the government’s finances. Natural gas remains a highly sought after commodity for residential and industrial use while driving the country’s economy.  For further discussion of natural gas prices and the Argentine government’s regulation of the supply of natural gas in the domestic market in Argentina, see MD&A – “Overviewof 2011 – Oil and Natural Gas Marketing” in Item 7 of this report.

EMPLOYEES

At February 17, 2012, the Company had ­­26 full-time employees.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

We are a Cayman Islands exempted limited company with executive offices located in Tulsa, Oklahoma, a branch office located in Buenos Aires, Argentina and a branch office in Bogotá, Colombia.  All of our production and reserves are currently generated in Argentina.

We  presently have no operating revenues in either the Cayman Islands, Colombia or the United States.  Because all of our operating revenues are generated in Argentina, all of our products are sold either domestically in Argentina or exported from Argentina to neighboring countries.  See Note 5 – Major Customers in Item 8 of this report for a description of sales during the last three years to customers that constitute greater than ten percent of total operating revenues.

With the exception of cash and cash equivalents deposited in banks in the Cayman Islands and the Bahamas, a bank account in Tulsa, Oklahoma, and furniture and equipment in our executive offices, all of our productive assets are located in Argentina.

For risks associated with foreign operations, see also “Risk Factors” in Item 1 of this report and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of this report.

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WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and other documents electronically with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934, as amended (“Exchange Act”).  You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549.  You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  You may also obtain such reports from the SEC’s Internet website at http://www.sec.gov.

Our Internet website is http://www.apcooilandgas.com. We make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Code of Ethics and Board committee charters are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to the Corporate Secretary, Apco Oil and Gas International Inc., 3500 One Williams Center, Tulsa, Oklahoma 74172.

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ITEM 1A.  RISK FACTORS

FORWARD-LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT

FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

·   Amounts and nature of future capital expenditures;

·   Volumes of future oil, gas and LPG production;

·   Expansion and growth of our business and operations;

·   Financial condition and liquidity;

·   Business strategy;

·   Estimates of proved oil and gas reserves;

·   Reserve potential;

·   Development drilling potential;

·   Cash flow from operations or results of operations;

·   Seasonality of natural gas demand; and

·   Oil and natural gas prices and demand for those products.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

·   Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future oil and natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;

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·   Inflation, interest rates, fluctuation in foreign currency exchange rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

·   The strength and financial resources of our competitors;

·   Development of alternative energy sources;

·   The impact of operational and development hazards;

·   Costs of, changes in, or the results of laws, government regulations (including climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities and litigation;

·   Political conditions in Argentina, Colombia and other parts of the world;

·   The failure to renew participation in hydrocarbon concessions granted by the Argentine government on reasonable terms;

·   Risks related to strategy and financing, including restrictions stemming from our loan agreement and the availability and cost of credit;

·   Risks associated with future weather conditions, volcanic activity and earthquakes;

·   Acts of terrorism; and

·   Additional risks described in our filings with the SEC.

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements.  These factors are described in the following section.

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RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report.  Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.

Risks Inherent to the Company’s Industry and Business

Significant capital expenditures are required to replace our reserves.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and cash on hand. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of oil and natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access bank debt, issue debt or equity securities, or access other methods of financing on an economical basis to meet our capital expenditure budget.  As a result, our capital expenditure plans may have to be adjusted.

Failure to replace reserves may negatively affect our business.

The growth of our business depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable.  Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both.  We may not be able to find, develop or acquire additional reserves on an economical basis.  If oil or natural gas prices increase, our costs for additional reserves would also increase, conversely if oil or natural gas prices decrease, it could make it more difficult to fund the replacement of our reserves.

Exploration and development drilling may not result in commercially productive reserves.

Our past success rate for drilling projects should not be considered a predictor of future commercial success.  We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in those wells.  The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project.  Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

·   Increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, skilled labor, capital or transportation;

·   Unexpected drilling conditions or problems;

·   Regulations and regulatory approvals;

·   Changes or anticipated changes in energy prices; and

·   Compliance with environmental and other governmental requirements.

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Estimating reserves and future net revenues involves uncertainties. Negative revisions to reserve estimates, oil and natural gas prices, or assumptions of future oil and natural gas prices may lead to decreased earnings, losses, or impairment of oil and gas assets.

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Reserves that are “proved reserves” are those estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions, but should not be considered as a guarantee of results for future drilling projects.

The process relies on interpretations of available geological, geophysical, engineering and production data.  There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. The reserve data included in this report represent estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct.

Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil and natural gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.

If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. These revisions, as well as revisions in the assumption of future cash flows of these reserves, may also be sufficient to trigger impairment losses on certain properties which would result in a non-cash charge to earnings. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost reserves.

We are uncertain about the productive potential of the Vaca Muerta shale in our core areas in the Neuquén basin.

In recent years, oil and gas companies operating in the Neuquén basin have been evaluating the possibility of unconventional sources for hydrocarbon production.  The subsurface formations of interest comprise both shale and what is commonly referred to as “tight sands.”  Our interests in the Neuquén basin include exploitation concessions and exploration permits that are contiguous and comprise approximately 245,000 net acres.  The formations of interest are present in all of the properties in which we participate.  We are conducting technical studies and investigating the Vaca Muerta through well re-entries and drilling to determine if any unconventional potential exists in our properties.  The seismic data and other technologies we have used to date do not allow us to know conclusively whether natural gas or oil may be economically produced from the Vaca Muerta shale.

Furthermore, unconventional drilling and completion technologies typically require greater expenditures than traditional drilling.  Exploration of the Vaca Muerta is in its infancy when compared with unconventional plays in other countries such as the United States that are more developed and have established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other unconventional formations will be commercially successful when used in unconventional formations in Argentina.

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Our operations are subject to operational hazards and unforeseen interruptions for which they may not be adequately insured.

Our operations are subject to all the risks and hazards typically associated with the development and exploration for, and the production and transportation of oil and natural gas.  These operating risks include, but are not limited to:

·   Earthquakes, volcanic activity, floods, fires, extreme weather conditions, and other natural disasters;

·   Aging infrastructure and mechanical problems;

·   Damages to pipelines and pipeline blockages;

·   Fires, blowouts, cratering, and explosions;

·   Uncontrolled releases of oil, natural gas, or well fluids;

·   Formations with abnormal pressures;

·   Operator error;

·   Damage inadvertently caused by third-party activity, such as operation of construction equipment;

·   Pollution and other environmental risks;

·   Risks related to truck loading and unloading; and

·   Terrorist attacks or threatened attacks on our facilities or those of other energy companies.

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In spite of our precautions, an event such as those described above could cause considerable harm to people or property, and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.

We are not fully insured against all risks inherent to our business, including environmental accidents. The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows.  We also may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates.  In addition, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims.  As a result, we could be exposed to greater losses than anticipated.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities and could exceed current expectations.

Our operations are subject to environmental regulation pursuant to a variety of laws and regulations.  Such laws and regulations impose, among other things, restrictions, liabilities, and obligations in connection with the generation, handling, use, storage, extraction, transportation, treatment, and disposal of hazardous substances and wastes in connection with spills, releases, and emissions of various substances into the environment, and in connection with the operation, maintenance, abandonment, and reclamation of our facilities.

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Compliance with environmental legislation could require significant expenditures including for cleanup costs and damages arising out of contaminated properties.  In addition, the possible failure to comply with environmental legislation and regulations might result in the imposition of fines and penalties.  Subject to any rights to indemnification, we are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown.  In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against environmental liabilities that could expose us to material losses, which may not be covered by insurance.

In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.  Although we do not expect that the costs of complying with current environmental laws will have a material adverse effect on our financial condition or results of operations, no assurance can be given that the costs of complying with environmental laws in the future will not have such an effect. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations.  If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.

Legislative and regulatory responses related to greenhouse gases (“GHG”) and climate change creates the potential for financial risk. Governing bodies have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more laws and regulations to reduce or mitigate GHG emissions.

While it is not clear whether or when any climate change laws or regulations will be passed, any of these actions could result in increased costs to (i) operate and maintain our facilities and (ii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and cash flows. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital.

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations.  If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change.  If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our operations.

Drilling for oil and gas is an inherently risky business.

Drilling for oil and gas is inherently risky because we assess where hydrocarbon reservoirs exist at considerable depths in the subsurface based on interpretation of geophysical, geological and engineering information and data without the benefit of physical contact with the accumulations of trapped oil and gas we believe can be produced. Finding and producing oil and gas requires the existence of a combination of geologic conditions in the subsurface that include the following: hydrocarbons must have been generated in a sedimentary basin, they must have migrated from the source into the subsurface area of interest, tectonic conditions in the area of interest must have created a trap required for the storage and accumulation of migrating hydrocarbons, and the sedimentary layer in which the hydrocarbons could be stored must have sufficient porosity and permeability to allow the flow of oil and gas into the drilled well bore.

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Our oil sales have historically depended on a relatively limited group of customers.  The lack of competition for buyers could result in unfavorable sales terms which, in turn, could adversely affect our financial results.

The Argentine domestic refining market is limited, and basically consists of five active refiners.  As a result, our oil sales have historically depended on a relatively narrow group of customers.  The largest of these five companies refines mostly its own crude oil production, while the smallest of the five operates only in the northwest basin of Argentina.  The lack of competition in this market could result in unfavorable sales terms which, in turn, could adversely affect our financial results.

Competition in the markets in which we operate may adversely affect our results of operations.

We have numerous competitors in our businesses, and additional competitors may enter our markets. Other companies with which we compete may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their assets than we can. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make investments or acquisitions. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our businesses and results of operations.

We are not the operator of all our hydrocarbon interests.  Our reliance on others to operate these interests could adversely affect our business and operating results.

We generally have non-operating interests in our properties and therefore we rely on other companies to operate our properties in Argentina and Colombia.  As the non-operating partner, we have limited ability to control operations or the associated costs of such operations.  The success of those operations is therefore dependent on a number of factors outside our control, including the competence and financial resources of the operators.

Changes in, and volatility of, supply, demand, and prices for crude oil, natural gas and other hydrocarbons have a significant impact on our ability to generate earnings, fund capital requirements, and pay shareholder dividends.

Our revenues, operating results, future rate of growth and the value of our business depends primarily upon the prices we receive for crude oil, natural gas or other hydrocarbons.  Price volatility can impact both the amount we receive for our products and the volume of products we sell.  Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.

The markets for crude oil, natural gas, and other hydrocarbon commodities are likely to continue to be volatile.  Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty, and other factors that are beyond our control, including:

·   Argentine and Colombian governmental actions;

·   Supplies of and demand for electricity, natural gas, petroleum, and related commodities;

·   Exploration discoveries throughout the world;

·  The level of development investment in the oil and gas industry;

·   Turmoil in the Middle East and other producing regions;

·   Terrorist attacks on production or transportation assets;

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·   Weather conditions;

·   Strikes, work stoppages, or protests;

·   The price and availability of other types of fuels;

·   The availability of pipeline capacity;

·   Supply disruptions and transportation disruptions;

·   Governmental regulations and taxes;

·   The overall economic environment;

·   The credit of participants in the markets where hydrocarbon products are bought and sold; and

·   The adoption of regulations or legislation relating to climate change.

Future disruptions in the global credit markets may make equity and debt markets less accessible, create a shortage in the availability of credit, and lead to credit market volatility which could limit our ability to grow.

In 2008, public equity markets experienced significant declines and global credit markets experienced a shortage in overall liquidity, resulting in a disruption in the availability of credit. Future disruptions in the global financial marketplace, including the bankruptcy or restructuring of financial institutions, may make equity and debt markets inaccessible, and the availability and cost of credit could increase in the future. Although we have historically funded capital programs and past property acquisitions with our internally generated cash flow, these developments could impair our ability to make acquisitions, finance growth projects, or proceed with capital expenditures as planned.

Oil and gas investments are inherently risky and there is no guarantee that the fiscal conditions that existed at the time of investment will not be changed by the host country.

Oil and gas investments are attractive when stable fiscal conditions exist over the productive life of an investment.  There is no guarantee that the fiscal conditions that existed at the time of investment will not be changed by the host country, thereby lowering the future economic return that was anticipated when the decision to invest was made.

The vast amount of international oil and gas reserves are controlled by national oil companies and access to oil and gas reserves and resource potential is limited.

Access to oil and gas reserves and resource potential is becoming more limited over time. Known producing oil and gas reserves under production in developed countries are declining, thereby increasing the concentration of oil and gas reserves and resource potential in undeveloped countries that reserve the right to explore and develop such reserves for their national oil companies. This restricts investment opportunities for international oil and gas companies and makes it more difficult to find international oil and gas investment opportunities with economic terms that are attractive.

Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.

Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures and companies’ relationships with their independent registered public accounting firms. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have.

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In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets, liabilities and equity.  Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations and financial condition.

Risks Associated with Operations in Argentina and Colombia

Our right to explore for, drill for, and produce hydrocarbons is generally derived from participation in concessions and/or exploration and production contracts granted by the governments where we do business, which have a finite term, the expiration or termination of which could materially affect our results.

Our right to explore for, drill for, and produce hydrocarbons is generally derived from participation in concessions or exploration and production contracts granted by the governments where we do business. These agreements have finite terms, the expiration or termination of which could materially affect our results.  In Argentina, the terms of the portion of the Entre Lomas concession located in Río Negro province and our three TDF concessions expire in 2016.  The term of a concession can be extended for ten years based on the consent of and terms to be agreed with the government.  However, the government may withhold its consent, or could extend the term of the concession on terms less favorable than those we have today.  See “MD&A – Concession Contracts in Argentina” in Item 7 of this report for additional discussion about concession extensions.

Argentina has a history of economic instability.  Because our operations are predominately located in Argentina, our operations and financial results have been, and could be in the future, adversely affected by economic, market, currency, and political instability in Argentina, as well as measures taken by its government in response to such instability.

Argentina’s economic and political situation continues to evolve, and the Argentine government may enact future regulations or policies that may materially impact, among other items, (i) the realized prices we receive for the commodities we produce and sell as a result of new taxes; (ii) the timing of repatriations of cash to the Cayman Islands; (iii) our asset valuations; (iv) peso-denominated monetary assets and liabilities; and (v) restrictions on imports of materials necessary for our operations.  See “Quantitative and Qualitative Disclosures about Market Risk – Argentine Economic and Political Environment” in Item 7A of this report. 

Strikes, work stoppages, and protests could increase our operating costs, hinder operations, reduce cash flow, and delay growth projects.

Strikes, work stoppages, and protests could arise from the political and economic situations in Argentina and Colombia and these actions could increase our operating costs, hinder operations, reduce cash flow, and delay growth projects.

Oil sales price realizations for oil produced and sold in Argentina are significantly influenced by Argentine governmental actions. Consequently, sharp increases in oil prices benefit oil producers outside of Argentina more than us.

Historically, the price per barrel for Argentine crude oil was based on the spot market price of West Texas Intermediate crude oil (“WTI”) less a discount for differences in gravity and quality. In the wake of the Argentine economic crisis of 2002, and as the price of crude oil increased to record levels over the past several years, politically driven mechanisms were implemented to determine the sale price of oil produced and sold in Argentina.

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To alleviate the impact of higher crude oil prices on their economy, the Argentine government created an oil export tax and enacted strict price controls on gasoline prices to force producers and refiners to negotiate oil sales prices significantly below international market levels.  For further discussion about oil prices, see “MD&A – Overview of 2011 – Oil and Natural Gas Marketing” in Item 7 of this report.

The Argentine government enforces strict price controls over the sale of natural gas.

The government of Argentina enforces strict price controls over the sale of natural gas in the country. These price controls are more strict when gas is destined for residential consumption or to power generators known to primarily serve residential customers.  Price controls are less strict for sales to industrial customers and in certain cases can be freely negotiable with industrial customers.  As a result, natural gas prices for gas sold in Argentina have been significantly below natural gas price levels in neighboring countries since 2002, and below natural gas prices paid by the Argentine government to import natural gas from neighboring countries or for imported LNG.  Regulations in Argentina enable the government, under certain conditions, to nominate a producer’s natural gas for residential sales during peak demand seasons requiring a producer to sell gas at prices below $1.00 per Mcf. Apco and Petrolera, our equity investee, are required to sell natural gas under these conditions.

Insurgency activity in Colombia could disrupt or delay our operations.

A 40-year armed conflict between the Colombian government and armed anti-government insurgent groups and illegal paramilitary groups is ongoing in Colombia.  Insurgents continue to attack civilians and violent guerilla activity continues in many parts of the country.

We have acquired interests in the Middle Magdalena and Llanos basins in Colombia. While neither of the basins is located near the Colombian borders with Ecuador and Venezuela, which have been more prone to recent guerilla activity, the ability of the Colombian government to maintain security in the areas where we have operations may not be successful and guerilla related violence could affect our operations in the future, resulting in losses or interruptions of our activities.

Risks Related to the Control Exercised by WPX Energy that Affect Our Business and Corporate Governance.

WPX Energy effectively controls the outcome of actions requiring the approval of our shareholders and there is a risk that WPX Energy’s interests will not be consistent with the interests of our other shareholders.

WPX Energy beneficially owns approximately 69 percent of our outstanding shares.  In addition, our executive officers are employees of WPX Energy and three of our seven directors are employees of WPX Energy.  Therefore, WPX Energy (a) has the ability to exert substantial influence and actual control over our management policies and affairs, such as our business strategy, purchase or sale of assets, financing, business combinations, and other company transactions, (b) controls the outcome of any matter submitted to our shareholders, including amendments to our memorandum of association and articles of association, and (c) has the ability to elect or remove all of our directors.  There is a risk that the interests of WPX Energy will not be consistent with the interests of our other shareholders.  In general, our shareholders do not have an obligation to consider the interests of other shareholders when voting their shares.

WPX Energy could make it more difficult for us to raise capital by selling shares or for us to use our shares in connection with acquisitions or other business arrangements. WPX Energy could also adversely affect the market price of our shares by selling its shares.  This concentrated ownership also might delay or prevent a change in control and may impede or prevent transactions in which shareholders might otherwise receive a premium for their shares.  Additionally, WPX Energy could engage in businesses that directly or indirectly compete with us without any obligation to offer us those opportunities.

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WPX’s public indenture contains financial and operating restrictions that may limit our access to credit and affect our ability to operate our business.

WPX’s public indenture contains covenants that restrict WPX’s and our ability to incur liens to support indebtedness. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

Substantially all of WPX’s operations are conducted through its subsidiaries. WPX’s cash flows are substantially derived from loans, dividends and distributions paid to it by its subsidiaries. WPX’s cash flows are typically utilized to service debt and pay dividends on the common stock of WPX, with the balance, if any, reinvested in its subsidiaries as loans or contributions to capital. Due to our relationship with WPX, our ability to obtain credit could be affected by WPX credit standing or financial condition.

Because we are a “controlled company” as defined by the rules of The Nasdaq Stock Market, we are not required to comply with certain corporate governance requirements that would otherwise be applicable if we were not a controlled company.

We are a “controlled company” as defined by the rules of The Nasdaq Stock Market because WPX Energy directly owns approximately 69 percent of our shares. Therefore, we are not subject to the requirements of The Nasdaq Stock Market that would otherwise require us to have (a) a majority of independent directors on the Board of Directors, (b) the compensation of executive officers determined by a majority of independent directors or a compensation committee composed solely of independent directors, and (c) a majority of the independent directors or a nominating committee composed solely of independent directors elect or recommend director nominees for selection by the Board of Directors.

Our Board of Directors does not have a compensation committee or any other committees performing similar functions.  Compensation decisions for our executive officers are made by WPX Energy and compensation decisions affecting our directors who are not employees of WPX Energy are made by our Board of Directors.  Please read “Executive Compensation” and “Certain Relationships and Related Transactions, and Director Independence — Transactions with Related Persons — Administrative Services Agreement,” in our definitive Proxy Statement, which information is incorporated by reference herein.

Our executive officers and some of our directors are also officers and/or directors of WPX Energy, and these persons also owe fiduciary duties to that entity.

Although our officers and directors have an obligation to act in our best interest, our executive officers and some of our directors are also officers and/or directors of WPX Energy and/or its other affiliates, and these persons also owe fiduciary duties to those entities.  For example, our Chief Executive Officer and Chairman of our Board of Directors is also an executive officer of WPX Energy.  We also have business relationships with WPX Energy, including an administrative services agreement pursuant to which WPX Energy provides us with certain administrative and management services.

See “Certain Relationships and Related Party Transactions” in our definitive Proxy Statement for the 2012 Annual General Meeting of Shareholders, which information is incorporated by reference herein.

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Our executive officers and certain other persons who provide services to us at our headquarters office are employees of WPX Energy, and we rely on WPX Energy to provide us with certain administrative services.  The loss of any of these persons or administrative services could have a materially adverse effect on our business and results of operations.

Our executive officers and certain other persons who provide services to us pursuant to an administrative services agreement are employees of WPX Energy.  Any service provided under the agreement may be terminated by either us or WPX Energy upon 60 day written notice.  The loss of any of our key executive officers or other management personnel could have a material adverse effect on our business unless and until we find a qualified replacement.  A limited number of persons exist with the requisite experience and skills to serve in our senior management positions and competition for the services of such persons is intense.  We may not be able to locate or employ qualified executives or other key employees at a cost competitive with the amounts paid to WPX Energy for the services of these persons.

WPX Energy also provides certain other services to us, such as risk management, internal audit services, and at our headquarters office in Tulsa, Oklahoma, provides office supplies, office space, and computer support pursuant to the administrative services agreement.  See “Certain Relationships and Related Party Transactions” in our definitive Proxy Statement for the Annual General Meeting of Shareholders, which information is incorporated by reference herein.

If WPX Energy did not provide these services, we would be required to provide these services ourselves or to obtain substitute arrangements with third parties.  Our cost to replace such services may be significantly higher than the cost we currently pay.  In addition, the failure to replace these services in a timely and effective fashion could have a material adverse effect on our business, including our ability to comply with our financial reporting requirements and other rules that apply to public companies.

Risks Related to Ownership by a Newly-formed Entity

As a result of Williams’ spin-off of its exploration and production businesses, which included its share ownership in us, we are controlled by a newly formed entity, WPX Energy, without the history or resources of Williams.

Our former majority shareholder, Williams, spun-off its exploration and production assets (including its approximately 69% share ownership in us) into a separate entity, WPX Energy, effective December 31, 2011, when all of the common stock of WPX Energy was distributed to the stockholders of Williams and WPX Energy became a 100% publicly owned company.  Consequently, Williams does not own any of our equity securities and we no longer have access to the resources of Williams, which could negatively impact our ability to operate.

Risks Related to Regulations that Affect Our Business

Because of the nature of our business, we can be subject to various litigation actions, which, if resolved unfavorably, could result in substantial penalties and/or monetary damages and adversely affect our financial position, results of operations and cash flows.

Periodically, we become a party to the types of legal actions that routinely affect our business, including disputes over provincial production taxes and payments, foreign currency regulations, and environmental claims, among others.  A description of material legal actions in which we are currently involved is included in Note 12 – Contingencies and Commitment in Item 8 of this Report. We cannot predict the outcome of these actions with certainty; therefore, these legal actions could further increase our cost of doing business and adversely affect our financial position, results of operations and cash flows.

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Our operations require us to comply with certain United States and international regulations, violations of which could have a material adverse effect on our consolidated results of operations and consolidated financial condition.

Our operations require us to comply with certain United States and international regulations, including the Foreign Corrupt Practices Act (“FCPA”). Our activities include the risk that unauthorized payments or offers of payments may be made by one of our employees, agents, or joint venture partners that could be in violation of the FCPA, even though these parties are not always subject to our control.  We have internal control policies and procedures and have implemented training and compliance programs with respect to the FCPA.  However, we cannot assure that our policies, procedures and programs will always protect us from reckless or criminal acts.  Violations of the FCPA may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could have a material adverse effect on our business, consolidated results of operations and consolidated financial condition.  We are also subject to the risks that our employees, joint venture partners, and agents may fail to comply with other applicable laws.

Changes in the laws and regulations of the countries where we do business, including tax, environmental and employment laws, and regulations, could have a material effect on financial condition and results of operations.

We are subject to numerous laws and regulations in Argentina and Colombia, which, among others, include those related to taxation, environmental regulations, and employment.  We are also subject to certain laws of the United States.  Regulation of certain aspects of our business that are currently unregulated in the future and changes in the laws or regulations could materially affect our financial condition and results of operations.

Possible changes in tax laws could affect us and our shareholders.

Tax laws and regulations are highly complex and subject to interpretation, and the tax laws, treaties and regulations to which we are subject may change over time. Our tax filings are based upon our interpretation of the tax laws in effect in various countries at the time that the filings were made. If these laws, treaties or regulations change, or if the taxing authorities do not agree with our interpretation of the effects of such laws, treaties and regulations, it could have a material adverse effect on us.  In addition, the manner in which our shareholders are taxed on distributions in connection with our shares could be affected by changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the jurisdictions in which our shareholders reside. Any of the foregoing changes could affect the trading price of our shares.

We have a material weakness in our internal control over financial reporting.  If we fail to establish and maintain proper and effective internal controls, our ability to produce accurate financial statements could be impaired, which could adversely affect our operating results, and investor, supplier and customer confidence in our reported financial information.

As described in “Item 9A. Controls and Procedures,” during the third quarter ended September 30, 2011, management determined that the Company had a material weakness due to the aggregation of four significant deficiencies related to financial statement presentation and disclosure matters.  A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

The Company has concluded that even though significant progress has been made to remediate the material weakness, at December 31, 2011 the material weakness still exists and the internal control over financial reporting was not effective.   Until it is fully remediated, this material weakness could lead to errors in our reported financial results and could have a material adverse effect on our operations, investor, supplier and customer confidence in our reported financial information and the trading price of our common shares.

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Risks Related to Employees

Institutional knowledge residing with current employees might not be adequately preserved.

Certain of our employees who have many years of service have extensive institutional knowledge.  As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience.  In addition, we may not be able to retain or recruit other qualified individuals, and our efforts at knowledge transfer could be inadequate.  If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.

Risks Related to Weather, other Natural Phenomena, and Business Disruption

Our assets and operations can be adversely affected by weather and other natural phenomena.

Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, volcanoes, and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms or insurance has not been available at all.  A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.

In addition, there is a growing belief that emissions of greenhouse gases may be linked to global climate change.  To the extent weather conditions are affected by climate change or demand is impacted by laws or regulations associated with climate change, energy use could increase or decrease depending on the duration and magnitude of the changes, leading to either increased investment or decreased revenues.

Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.

Our assets and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport or distribute oil, natural gas or other commodities. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Risks Related to Dividends and Distributions

Our articles of association provide that we may pay dividends or make distributions out of our profits, the share premium account, or as otherwise permitted by law.

In the event we have no profits for a given period and have accumulated deficits, we can make dividend or other distributions to our shareholders from the share premium account, which is similar to the paid-in capital account under generally accepted accounting principles in the United States (“U.S. GAAP”), as long as the distributions do not render us insolvent.  If we elect to pay dividends at times when we do not otherwise have current profits or accumulated earnings and profits, such dividends could have a material adverse effect on our financial condition.

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ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 3.   LEGAL PROCEEDINGS

In the third quarter of 2011, we received a claim from the Dirección General de Rentas (the “DGR”, or provincial taxation authority) in the province of Chubut, Argentina, for alleged deficiencies in exploitation canon payments applicable to the Cañadón Ramírez concession during the years 2009, 2010 and 2011.  The DGR has claimed that we owe an additional $4.3 million pesos (approximately $1 million U.S. dollars).  In making this assessment, the DGR has failed to acknowledge that we relinquished portions of the original surface area of the concession during those periods. Therefore, we believe this claim has no merit and that the exploitation canon payments made are correct.  We initiated an administrative proceeding with the province to challenge the DGR claim in the fourth quarter of 2011.  In February 2012, the province rejected our motion for reconsideration.  We plan to file an administrative appeal with the Provincial Ministry of Economy.  We sold our interest in Cañadón Ramírez at the end of 2010.

ITEM 4.   MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Market information, Number of Shareholders and Dividends

In order to facilitate the transfer of Williams’ interest in us to WPX Energy in a tax efficient manner, on June 30, 2011 our shareholders authorized our Board of Directors to issue a separate redeemable convertible class of shares, designated Class A Shares, which have, as a class, 85 percent of the voting power with respect to the election and removal of our directors and authorized us to issue one Class A Share to Williams Global Energy (Cayman) Limited (“Williams Global Energy”), a wholly-owned subsidiary of Williams and through which Williams held its interest in us, in exchange for each one of our ordinary shares owned by Williams Global Energy.  Consistent with this approval, on June 30, 2011, we issued 20,301,592 Class A Shares, par value $.01 per share, to Williams Global Energy, in exchange for an equal number of our ordinary shares.  In October 2011, the Class A Shares were transferred from Williams Global Energy to WPX Energy, which now owns 68.96 percent of our outstanding shares.  The Class A Shares and the ordinary shares have identical rights and preferences in all other respects, including with respect to dividend rights.  The Class A Shares will automatically convert into our ordinary shares in the event that neither Williams, nor WPX Energy, beneficially owns, separately or in the aggregate, directly or indirectly, at least 50 percent of the aggregate outstanding Class A Shares and ordinary shares of the Company.

Our ordinary shares are traded on The NASDAQ Capital Market under the symbol “APAGF.”  At the close of business on February 21, 2012, there were 9,139,648 of the Company’s ordinary shares, $0.01 par value, outstanding, held by approximately 499 registered holders, and there were 20,301,592 of the Company’s Class A shares, $0.01 par value, outstanding, held by WPX Energy.

Our articles of association allow us to pay dividends or distributions out of our profits, our share premium account, or as otherwise permitted by law.

The high and low trade sales price ranges and dividends declared by quarter for each of the past two years are as follows:

	2011			2010
Quarter	High	Low	Dividend	High	Low	Dividend
1st	$86.55	$57.58	$.0200	$27.12	$18.00	$.0200
2nd	$93.29	$73.38	$.0200	$30.00	$21.11	$.0200
3rd	$92.25	$67.34	$.0200	$34.61	$21.80	$.0200
4th	$87.30	$67.10	$.0200	$59.00	$33.45	$.0200

* Because the Class A Shares and the ordinary shares have identical rights and preferences with respect to dividend rights, dividends per share are per ordinary and Class A shares beginning in the second quarter, 2011.

The quarterly dividends declared per share were $.02 per share during each of the four quarters of 2011 and 2010, or $.08 for each year. Future dividends are necessarily dependent upon numerous factors, including, among others, earnings, levels of capital spending, funds required for acquisitions, changes in governmental regulations and changes in crude oil and natural gas prices.  The Company reserves the right to change the level of dividend payments or to discontinue or suspend such payments at the discretion of the Board of Directors.

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 We may pay dividends to shareholders only out of our realized or unrealized profits, share premium account or otherwise as permitted by the laws of the Cayman Islands. There are no current applicable Cayman Islands laws, decrees or regulations relating to restrictions on the import or export of capital or exchange controls affecting remittances of dividends, interest and other payments to non-resident holders of the our shares. There are no limitations either under the laws of the Cayman Islands or under our memorandum or articles of association restricting the right of foreigners to hold or vote our shares. There are no existing laws or regulations of the Cayman Islands imposing taxes or containing withholding provisions to which United States holders of our shares are subject. There are no reciprocal tax treaties between the Cayman Islands and the United States.

Performance Graph

Set forth below is a line graph comparing our cumulative total shareholder return on our shares with the cumulative total return of The NASDAQ US and Foreign Securities Index and the NASDAQ US and Foreign Oil & Gas Extraction Index (SIC 1300-1399) for a five-year period commencing December 31, 2006. We will provide shareholders a list of the component companies included in the NASDAQ US and Foreign Oil & Gas Extraction Index upon request.

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ITEM 6.      SELECTED FINANCIAL DATA

The following financial data at December 31, 2011 and 2010, and for each of the three years in the period ended December 31, 2011, should be read in conjunction with MD&A in Item 7 of this report and Financial Statements and Supplementary data in Item 8 of this report. The following financial data at December 31, 2009, 2008 and 2007, and for the years ended December 31, 2008 and 2007, has been prepared from our previous filings on Form 10-K.

(Amounts in thousands except per share amounts)
As of and for the years ended December 31,	2011			2010			2009			2008			2007
Results of Operations
Revenues	$	104,780		$	87,815		$	72,716		$	69,116		$	62,506
Equity income from Argentine investment		20,496			16,158			14,143			16,375			17,403
Net income		31,787			25,834			23,527			23,825			31,385
Amounts attributable to Apco:
Net income		31,746			25,800			23,497			23,793			31,349
Income per share (a)		1.08			0.88			0.80			0.81			1.06
Dividends declared per share (a)		0.08			0.08			0.08			0.35			0.35
Financial Position
Total assets		282,996			248,189			224,191			202,794			190,126
Total liabilities		24,358			18,731			18,354			17,999			18,768
Total equity		258,638			229,458			205,837			184,795			171,358
Market Capitalization (b)		2,405,938			1,692,871			650,651			784,020			810,223
Cash Flow
Cash provided by operating activities		42,184			39,038			28,262			29,236			34,482
Capital expenditures		(35,814	)		(33,829	)		(20,516	)		(32,202	)		(26,747	)
Cash (used) provided by all other investing activities, net		(4,324	)		-			(4,779	)		1,097			(1,097	)
Cash dividends paid		(2,381	)		(2,379	)		(4,352	)		(10,317	)		(10,325	)
Cash (used) provided by all other financing activities, net		2,000			-			-			-			-

(a) All share and per share amounts have been adjusted to reflect the four-for-one share split effected in the fourth quarter of 2007.

(b) Market capitalization is calculated by multiplying the year-end total shares outstanding by the year-end closing share price.

See the table “Oil and Natural Gas Production, Prices and Costs” in Item I of this report and MD&A – Result of Operations in Item 7 of this report for discussion of variations in prices that influence our revenues and net income.

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

General

We are an international oil and gas exploration and production company focused on South America, with operations in Argentina and Colombia. As of December 31, 2011, we had interests in eight oil and gas producing concessions and two exploration permits in Argentina, and three exploration and production contracts in Colombia.

Our interests in Argentina continue to be the core of our business, and we continually seek out properties in Argentina's basins where we have expertise.  We also believe that Colombia offers outstanding opportunities to add properties with excellent technical and economic characteristics to our portfolio.  We consider the investment and promotional climate and the oil and gas tax regime created by the Colombian government over the last several years to be the most attractive in South America.

We are encouraged by the improved commodity price environment in Argentina.  We believe higher prices are necessary to stimulate and encourage both conventional and unconventional exploration activity to help supply the growing energy needs of the country.  However, inflation in Argentina has been a persistent problem for several years and, with only a modest devaluation of the Argentine peso in comparison to inflation rates, we have experienced significant increases in our U.S. dollar cost of operations and capital expenditures.  Consequently, our operating income in 2011 did not increase in line with the upward trend of our oil price realizations.

Net income attributable to Apco for 2011 was $31.7 million compared with $25.8 million for 2010.  Higher average sales prices, greater equity income from Argentine investment and lower exploration expense in 2011 led to the increase in net income compared with 2010.  These favorable variances were partially offset by greater costs and operating expenses.

Our capital expenditures totaled $35.8 million in 2011.  Highlights for 2011 include the following:

·   Increased total consolidated and equity sales volumes on a Boe basis by four percent;

·   Successful development and exploration drilling campaigns in our core Neuquén basin properties;

·   Exploration discoveries in the Bajada del Palo concession;

·   Exploration discovery in the Agua Amarga exploration permit; and

·   Exploration discoveries, completion of farm-in drilling commitments and extension of the Coirón Amargo exploration permit.

Outlook for 2012

We expect oil prices in Argentina to increase moderately in 2012 compared with 2011 year-end prices of around $72 per barrel. After experiencing permitting delays in 2011, exploration drilling in Colombia will commence in the first quarter 2012.  With drilling in Colombia and development efforts beginning in Coirón Amargo, we plan on increased capital expenditures compared with 2011.  Our primary objectives for 2012 are as follows:

·   Obtain the ten-year concession extensions for our properties in Río Negro and Tierra del Fuego;

·   Continue development of existing fields and conventional exploration drilling in our core properties in the Neuquén basin;

·   Investigate the productive potential of the Vaca Muerta and Molles shales in our properties in the Neuquén basin;

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·   Commence development drilling and continue exploration efforts in Coirón Amargo; and

·   Complete 3D seismic acquisitions in Sur Río Deseado Este in southern Argentina and over the Llanos 40 block in Colombia.

Our 2012 oil and gas capital expenditure budget is $58 million.  After taking into consideration the portion of capital expenditures attributable to our equity interest in Petrolera, our combined consolidated and equity capital budget for 2012 is $96 million.  In addition, we plan on spending approximately $8 million for the acquisition of 3D seismic information.  For further discussion about funding our capital budget, see MD&A – Liquidity and Capital Resources.  

Overview of 2011

Change in Control – Separation from Williams

In February 2011, our previous major shareholder, Williams, announced a reorganization plan to separate Williams into two standalone, publicly traded corporations. The plan called for the separation of Williams’ exploration and production business, of which we were a part, via a spin-off to Williams’ shareholders of a corporation that would hold that business, WPX Energy.  Because we are an oil and gas exploration and production company and used the personnel and resources of Williams’ exploration and production business, Williams decided to transfer its entire interest in Apco to WPX Energy.  Our transfer to WPX Energy enables us to continue to benefit from the exploration and production expertise, personnel and experience that has historically been provided to us by Williams.  Effective December 31, 2011, all of the common stock of WPX Energy was distributed to the stockholders of Williams the (“spin-off”) and WPX Energy became a 100% publicly owned company.  After the spin-off, Williams does not own any of our equity securities. WPX Energy is a large-scale, independent exploration and production company with operations primarily in North America.

Neuquén Basin Properties

We and our partners used two rigs throughout 2011 to drill 30 gross development wells and five exploration wells in the Entre Lomas, Bajada del Palo, Charco del Palenque and Agua Amarga areas.  Total gross capital expenditures was approximately $114 million for the year, or $26 million net to our 23 percent direct working interest and $34 million attributable to our equity interest in Petrolera.  We have a 23 percent direct working interest and an effective 29.79 percent equity interest in the wells mentioned above.

The western most portion of our Bajada del Palo concession is known as “Aguada del Poncho.”  Like the southern portion of our Coirón Amargo permit, Aguada del Poncho is situated in the deepest portion of the Neuquén basin near YPF’s Loma de la Lata concession. During 2011, we drilled two successful exploration wells in this area and re-entered an existing well with positive results.  All three of these wells are on production.

Additional activities included exploration efforts to stimulate production from the Vaca Muerta shale in three existing wells in the Bajada del Palo and Entre Lomas concessions.  The Vaca Muerta formation was not productive in these wells.  All costs associated with these three well re-entries have been expensed as exploration costs during 2011.  We will re-enter another existing well in the Bajada del Palo concession and perform a significantly larger fracture of the Vaca Muerta shale in first quarter 2012.

In our Agua Amarga exploration permit, we drilled the Meseta Filosa x-1 exploration well in the central part of the area which resulted in an oil discovery from the Tordillo formation.  As a result of this discovery, the Charco del Palenque exploitation concession was extended by 4,900 acres.

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Coirón Amargo

The Coirón Amargo block covers approximately 100,000 acres and is adjacent to our core properties in the Neuquén basin.  During 2011, we drilled two wells and completed our commitments to earn a 45 percent interest in the block.  Both wells resulted in oil discoveries in the Tordillo formation.  In December 2011, we commenced a multi-stage fracture stimulation of the Vaca Muerta formation in one of the vertical wells drilled earlier in the year.  This well is being tested in the first quarter of 2012.  We also spudded a third well targeting both the Tordillo and Vaca Muerta formations in December.

Since entering our farm-in agreement in early 2010, we have drilled four wells resulting in hydrocarbon discoveries. This achievement is a continuation of our success during recent years where we have used an established geologic model to drill exploration wells in our core properties in the Neuquén basin.

The current exploration period expired in November 2011.  We have agreed with the province to convert 26,700 gross acres into an exploitation concession with a term of 25 years, and the remaining portion of the block has been deemed a “high-risk exploration area” that will require exploration commitments of approximately $18 million net to Apco during 2012 and 2013 to investigate unconventional potential in the block.  After the two year extension of the exploration period, we will determine how much of the remaining area will be converted to an exploitation concession and how much acreage, if any, will have to be relinquished.

Concession Contracts in Argentina

The concession terms for the portion of the Entre Lomas concession located in Río Negro and for our Tierra del Fuego concessions currently end in 2016.  Approximately one half of the Entre Lomas concession, including our largest producing field, is located in the province of Río Negro.  In general, the depletion life of many of our proved wells extends beyond 2016 and through the end of the concession extension period, and consequently, obtaining the ten-year extension should lead to reserve upgrades that will result in a material increase in the volume of proved reserves.

In the second half of 2010, the provinces of Río Negro and Tierra del Fuego approved basic frameworks for the negotiation of the ten-year concession extensions provided by Argentina’s hydrocarbon law.  The operators of the concessions are leading negotiations with the provinces on behalf of the joint venture partners, and significant advances were made with both provinces during 2011.  Similar to the negotiations concluded with the province of Neuquén in 2009, the requirements for extension include the negotiation of a cash bonus payment, an increase to provincial production taxes, and a future expenditure program.  Although we expected to conclude these negotiations in 2011, federal and provincial elections throughout the year postponed the approval of any final extension agreement to 2012.

Colombia

After completing seismic programs in both the Turpial and Llanos 32 blocks in Colombia during 2010, our plans were to commence exploration drilling in both blocks during 2011.  However, our drilling plans have been deferred to 2012 because of considerable government delays to issue environmental and drilling permits as a result of the high levels of exploration activity in Colombia.  We received our drilling permit for the Llanos 32 block in the third quarter, and expect to receive our permit for Turpial in early 2012.  Because the exploration period in the Turpial block expired in September, we requested and received a six-month contract extension (effective from the date of receiving the permit) as a result of the permitting delays.  The drilling location for our first well in Llanos 32 is being constructed and we are scheduled to spud the well in February 2012.  In early 2012, we commenced the acquisition of 305 square kilometers of 3D seismic over our Llanos 40 block estimated to cost $6 million net to our 50 percent interest.

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Oil and Natural Gas Marketing

Oil Prices

Oil prices have a significant impact on our ability to generate earnings, fund capital projects, and pay shareholder dividends.  In general, oil prices are affected by many factors, including changes in market demands, global economic activity, political events, weather, and OPEC production quotas.  More importantly to Apco, oil price realizations for oil produced and sold in Argentina are significantly influenced by Argentine governmental actions as described in the following paragraphs. As a result, we cannot accurately predict future prices, and therefore it is difficult for us to determine what effect increases or decreases in product prices may have on our capital programs, production volumes, or future revenues.

In Argentina, politically driven mechanisms significantly influence the sale price of oil produced and sold in the country. To alleviate the impact of higher crude oil prices on Argentina’s economy and reduce inflation, the Argentine government created an oil export tax and enacted price controls over gasoline prices to force producers and refiners to negotiate oil sales prices significantly below international market levels.

In response to those governmental actions, Argentine producers and refiners had to negotiate domestic oil sale prices that take into consideration both net backs for oil exported from Argentina and the cost of feedstock to refiners in light of gasoline price controls.  Consequently, Apco has not benefited from increases in world oil prices over the past several years like producers outside of Argentina. However, gradual increases in gasoline prices from 2009 through 2011 have enabled producers to negotiate higher oil sales prices with refiners.  The trend of increasing gasoline prices combined with tighter demand for our high-quality crude oil has resulted in higher oil price realizations compared with prior years. Our oil sales price per barrel for our consolidated interests averaged $62.21 for 2011 compared with $52.22 for 2010 and $43.46 in 2009.

Hydrocarbon Subsidy Programs

Low oil prices in Argentina have inhibited oil exploration investments and consequent oil discoveries in Argentina resulting in insufficient replacement of domestic production and a decline in oil reserves in the country over the past several years.  In order to reverse this trend and promote increased oil production and reserves, the Argentine government created various hydrocarbon subsidy programs in 2008 including the “Oil Plus” program.  The programs grant qualifying companies economic benefits in the form of tax-credit certificates which can be applied to the payment of export duties paid on hydrocarbon exports or transferred to third parties at face value.

We did not realize any benefit from the Oil Plus program until 2011.  During 2011, we have recognized approximately $1.1 million net to our consolidated interests related to hydrocarbon subsidy programs (see Other Operating Revenues below), and approximately $1.7 million net to our equity interest (see Investment Income below).  Both we and Petrolera have applied for additional benefits under the Oil Plus program; however, in February 2012, the Argentine government stated its intention to suspend benefits under the Oil Plus program.  Consequently, we cannot predict if either company will be able to recognize any further benefits from this program.

We cannot predict how world oil prices will evolve in 2012 and beyond or what additional actions the Argentine government will take in response to future fluctuations in world oil prices, the drop in the level of the country’s oil reserves or in reaction to changes in the country’s fiscal and trade balances.

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Natural Gas Prices

We sell our natural gas to Argentine customers pursuant to contracts and spot market sales. As a consequence of the growth in Argentina’s economy over the past several years, and stimulated by low natural gas prices resulting from a price freeze implemented by the Argentine government in 2002, demand for natural gas in Argentina has grown significantly. However, the unfavorable price environment for producers has discouraged natural gas exploration activities. Without significant new discoveries of natural gas reserves in Argentina, the supply of natural gas has failed to keep up with increased demand. The result is a natural gas and power supply shortage in the country. Since 2004, the Argentine government has taken several steps to prevent shortages in the domestic market. Natural gas exports to Chile were suspended and the country began importing natural gas from Bolivia at significantly greater prices than sales prices for natural gas produced in Argentina.  In addition, Argentina was forced to import high priced LNG. As described in the following paragraphs, Resolution 599/2007 is designed to supply natural gas in the domestic market and provide a framework for natural gas prices in Argentina.

In 2007, the Argentine Secretary of Energy issued Resolution 599/2007 to regulate the supply of natural gas in the domestic market through a natural gas supply agreement referred to as the “Acuerdo 2007-2011.”  The resolution is intended to provide for equitable sharing of all sectors of the internal natural gas market among producers and establishes a mechanism for doing so based on average natural gas volumes produced from 2002 to 2004. The resolution determines which sectors of the market will have priority during periods of peak demand. During peak periods, the residential market will have first priority.  With respect to the lower-priced residential market, each producer’s share of the residential market will be distributed based on an allocation of its volumes produced during the period 2002 to 2004, while natural gas production in excess of those volumes can be sold to electric power generators at regulated prices, and industrial customers at freely negotiated prices.

Producers that increased natural gas production since 2004 have an advantage compared to those producers whose production decreased over the period because natural gas prices to residential customers remain suppressed at approximately 60 cents per Mcf. The resolution allows producers to choose to participate in the Acuerdo 2007-2011 natural gas supply agreement or not. However, if a producer chooses not to participate, then during periods of peak demand, or when there is a shortage of natural gas in the country, the government can nominate non-participating producers to be the first to supply excess residential volume demand above the base-line demand as projected in the Acuerdo 2007-2011, regardless of the non-participating producer’s contractual commitments.

In general, Resolution 599/2007 has had a slightly positive impact on natural gas sales prices in Acambuco and Tierra del Fuego, but, during peak demand periods, it has lowered natural gas sales prices in Entre Lomas and Bajada del Palo.  Nevertheless, because natural gas revenues from Entre Lomas and Bajada del Palo represent approximately three percent of our total operating revenues on an annual basis, the overall impact of the resolution has not been material to our cash flows or results of operations.  Our average natural gas sale price per Mcf averaged $2.10 in 2011, $1.90 in 2010, and $1.70 during 2009.  In December 2011, the Acuerdo 2007-2011 was temporarily extended until the Secretary of Energy issues another resolution to regulate natural gas markets in Argentina.

The level of gas reserves in Argentina has fallen in recent years in a country that relies on natural gas for more than 50 percent of its energy consumption. Given the government’s tendency to intervene over pricing of a commodity in such high demand, we cannot predict how Argentine natural gas prices will evolve in 2011 and beyond or whether the current Argentine government will continue to maintain tight controls over prices or decide to loosen price controls in response to falling production and reserves.

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Seasonality

Of the products we sell, only natural gas is subject to seasonal demand.  Demand for natural gas in Argentina is reduced during the warmer months of October through April, with generally lower natural gas prices during this off-peak period. During 2011, natural gas sales represented 13 percent of our total operating revenues compared with 14 percent in 2010 and 2009.  Consequently, the fluctuation in natural gas sales between summer and winter is not significant to us.

New Accounting Standards and Emerging Issues

In June 2011, the FASB issued Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5).  ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. The Update requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income.  The new guidance does not change the items reported in other comprehensive income, nor affect how earnings per share is calculated and presented. We currently report net income in the Consolidated Statements of Income and report other comprehensive income in the Consolidated Statement of Changes in Equity. The standard is effective beginning the first quarter of 2012, with a retrospective application to prior periods.

In December 2011, The FASB issued Accounting Standards Update No. 2011-12, “Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12). ASU 2011-12 defers the effective date for only the presentation requirements related to reclassifications in ASU 2011-5. During this deferral period, ASU 2011-12 states that we should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Both ASU’s are effective beginning the first quarter of 2012, with retrospective application to prior periods. We will apply the new guidance for both ASUs beginning in 2012.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions. We believe that these particular estimates and assumptions are critical due to their subjective nature and inherent uncertainties, the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations. We have discussed the following accounting estimates and assumptions as well as related disclosures with our Audit Committee.

Proved reserve estimates. Estimates of our proved reserves included in the unaudited supplemental oil and gas information in this report are prepared in accordance with guidelines established by U.S. GAAP and by the SEC. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the reserve engineers and geologists that prepare the estimate.

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Our proved reserve information is based on estimates prepared by our reserve engineers. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing, and production after the date of an estimate may justify material revisions to the estimate. Our proved reserves are limited to the concession life. Certain of our existing concession terms can be extended for ten years with the consent of and based on terms to be agreed with the Argentine government. The extension of our concessions could materially affect our estimate of proved reserves.

The present value of future net cash flows should not be assumed to be the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, we based the 2011, 2010 and 2009 estimated discounted future net cash flows from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price received for the period January through December with the most current cost information. Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.

Our estimates of proved reserves materially impact depreciation, depletion and amortization expense. If the estimates of proved reserves decline, the rate at which we record depreciation expense increases, reducing net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost reserves. In addition, the decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment.

Impairment of oil and gas properties. We review our proved and unproved properties for impairment on a concession- by- concession basis and recognize an impairment whenever events or circumstances, such as declining oil and gas prices, or unfavorable revisions to our reserve estimates, indicate that a property’s carrying value may not be recoverable. If an impairment is indicated, then a provision is recognized to the extent that the carrying value exceeds the present value of the estimated future net revenues (“fair value”). In estimating future net revenues, we assume costs will escalate annually and apply an oil and gas price forecast that we believe to be reasonable given the pricing environment in Argentina. Due to the volatility of oil and gas prices and governmental regulations in Argentina, it is possible that the our assumptions regarding oil and gas prices may change in the future.  However, at prices equivalent to those at year-end 2011,  we do not expect to recognize any impairments in the near term.  We could, depending upon the results of exploration, determine that some or all of our interests in unproved areas need to be impaired as we drill and evaluate certain of these areas in future periods.  For example, we have $2.6 million of unproved properties related to our operations in Colombia;  if our exploration drilling planned for 2012 is unsuccessful, we may have to recognize an impairment loss related to this asset.

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RESULTS OF OPERATIONS

Period-to-Period Comparisons

The table below presents selected financial data summarizing our results of operations for the most recent three years. Please read in conjunction with the Consolidated Statements of Income.

	For the Years Ended December 31,
			$ Change			% Change					$ Change			% Change
	2011		from 2010			from 2010			2010		from 2009			from 2009			2009
	(Amounts in Thousands)
Operating revenues	$	104,780		16,965			19	%	$	87,815		15,099			21	%	$	72,716
Total costs and operating expenses		83,556		(14,675	)		-21	%		68,881		(13,121	)		-24	%		55,760
Operating income		21,224		2,290			12	%		18,934		1,978			12	%		16,956
Investment income		20,626		4,032			24	%		16,594		2,030			14	%		14,564
Income taxes		10,063		(369	)		-4	%		9,694		(1,701	)		-21	%		7,993
Net Income		31,787								25,834								23,527
Less: Net income attributable to noncontrolling interests		41		(7	)		-21	%		34		(4	)		-13	%		30
Net income attributable to Apco	$	31,746		5,946			23	%	$	25,800		2,303			10	%	$	23,497

Net Income

2011 vs. 2010  Our Net income attributable to Apco for 2011 was $31.7 million, an increase of $5.9 million compared with 2010.  Net income attributable to Apco increased compared with 2010 primarily due to the favorable effects of higher sales prices, greater equity income from Argentine investment and lower exploration expense.  These benefits were partially offset by higher production and lifting costs, greater taxes other than income and higher depreciation expense compared with 2010.

2010 vs. 2009  Our Net income attributable to Apco for 2010 was $25.8 million, an increase of $2.3 million compared with 2009.  Net income attributable to Apco increased compared with 2009 primarily due to the favorable effects of higher sales prices and greater equity income from Argentine investment.  These favorable variances were partially offset by greater exploration expense for the acquisition of seismic information, higher production and lifting costs, increased provincial production taxes and higher income tax expense.

Total Operating Revenues

Operating revenues for 2011 increased by $17 million, or 19 percent compared with 2010.  The following tables and discussion explain the components and variances in Operating revenues.

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Changes in oil, natural gas and LPG sales volumes, prices and revenues from 2009 to 2011 for our consolidated interests accounted for as operating revenues are shown in the following tables.

	Year Ended December 31,
	2011		% Change			2010		% Change			2009
Sales Volumes
Consolidated interests
Oil (Bbls)		1,359,163		2	%		1,338,195		1	%		1,330,020
Natural Gas (Mcf)		6,301,114		0	%		6,306,883		8	%		5,849,497
LPG (tons)		11,108		12	%		9,893		-2	%		10,097
Oil, Natural Gas and LPG (Boe)		2,539,701		1	%		2,505,438		3	%		2,423,425
Average Sales Prices
Consolidated interests
Oil (per Bbl)	$	62.21		19	%	$	52.22		20	%	$	43.46
Natural Gas (per Mcf)		2.10		11	%		1.90		12	%		1.70
LPG (per ton)		314.46		-9	%		346.61		31	%		264.33
Revenues ($ in thousands)
Oil revenues	$	84,553		21	%	$	69,882		21	%	$	57,809
Natural Gas revenues		13,257		10	%		12,000		21	%		9,949
LPG revenues		3,493		2	%		3,429		28	%		2,669
	$	101,303		19	%	$	85,311		21	%	$	70,427

The volume and price changes in the table above caused the following changes to our oil, natural gas and LPG revenues from 2009 to 2011.

	Oil		Gas			LPG			Total
	(Amounts in Thousands)
2009 Sales	$	57,809	$	9,949		$	2,669		$	70,427
Changes due to volumes		427		870			(71	)		1,226
Changes due to prices		11,646		1,180			831			13,658
2010 Sales		69,882		12,000			3,429			85,311
Changes due to volumes		1,304		(12	)		382			1,674
Changes due to prices		13,367		1,269			(318	)		14,318
2011 Sales	$	84,553	$	13,257		$	3,493		$	101,303

Oil Revenues

2011 vs. 2010  During 2011, Oil revenues increased by $14.7 million, or 21 percent compared with 2010, primarily due to higher average oil sales prices with some contribution from increased sales volumes.  For further explanation of oil sales prices in Argentina, see “MD&A – Oil and Natural Gas Marketing – Oil Prices” in Item 7 of this report.

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2010 vs. 2009  During 2010, Oil revenues increased by $12.1 million, or 21 percent compared with 2009, due to higher average oil sales prices with some contribution from increased sales volumes.

Natural Gas Revenues

2011 vs. 2010  Natural gas revenues increased by $1.3 million, or 10 percent compared with 2010.  The increase is due to higher sales prices. For further explanation of natural gas sales prices in Argentina, see “MD&A – Oil and Natural Gas Marketing – Natural Gas Prices,” in Item 7 of this report.

2010 vs. 2009  Natural gas revenues increased by $2.1 million, or 21 percent compared with 2009.  The construction of production facilities and well-connections in our Bajada del Palo and Charco del Palenque concessions drove a seven percent increase in consolidated natural gas sales volumes for the year, resulting in an $870 thousand benefit to revenues.  Average natural gas prices continued to moderately increase resulting in a $1.2 million increase in revenues for the year.

Other Operating Revenues

2011 vs. 2010 Other operating revenues increased by $973 thousand during 2011 compared with 2010.  The increase is related primarily to benefits realized from certain hydrocarbon subsidy programs from the Argentine government. For further explanation regarding the subsidy programs, see “MD&A – Oil and Natural Gas Marketing – Oil Prices – Hydrocarbon Subsidy Programs” in Item 7 of this report.

Total Costs and Operating Expenses

2011 vs. 2010 Total costs and operating expenses increased by $14.7 million, or 21 percent, primarily due to the following items:

·   Production and lifting costsincreased by $6.1 million, or 32 percent due to due to greater operation and maintenance expenses related to our Neuquén basin properties.  These increases were driven primarily by the impact of inflation in Argentina and increased activity that included the addition of an extra pulling unit used for repairing producing wells with down-hole problems that caused those wells to be temporarily shut-in;

·   Taxes other than income increased by $6.4 million primarily due to higher provincial production taxes as a result of higher sales prices and greater operating revenues and a higher effective provincial production rate due to increased sales volumes from concessions with higher rates; 2011 also included the following unusual items: a $966 thousand provincial production tax settlement covering prior periods with the province of Río Negro, a $572 thousand special Colombian equity tax, and an adjustment of $787 thousand related to personal asset tax in Argentina;

·   Depreciation, depletion and amortization expense increased by $3.8 million primarily due to higher depreciation rates (see additional discussion below); and

·   Partially offsetting the increased expenses mentioned above was a $3.0 million decrease in Exploration expense due to lower exploration activity including acquiring less amounts of 3D seismic information.

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2010 vs. 2009 Total costs and operating expenses increased by $13.1 million, or 24 percent, primarily due to the following factors:

·   Production and lifting costsincreased by $4.3 million, or 29 percent due to greater operation and maintenance expenses related to our Neuquén and Austral basin properties.  These increases were driven by the growth in our operations and the impact of inflation in Argentina;

·   Exploration expense increased by $5.1 million due to significant exploration activity in 2010 including expenses related to the acquisition and processing of seismic information in Colombia for $4.9 million and $1.0 million in our Neuquén basin properties.  Exploration activity in 2009 was minimal; and

·   Taxes other than income increased $2.4 million related to higher provincial production taxes as a result of higher sales prices and greater operating revenues.

Depreciation, Depletion and Amortization Expenses (“DD&A”)

The changes in our total volumes, DD&A average rates per unit and DD&A expense of oil and gas properties between 2009 and 2011 are shown in the following table:

	Year Ended December 31,
			Change		% Change					Change		% Change
	2011		from 2010		from 2010			2010		from 2009		from 2009			2009
Consolidated Sales Volumes (Boe)		2,539,701		34,263		1	%		2,505,438		82,013		3	%		2,423,425
DD&A Rate per Boe	$	8.13	$	1.42		21	%	$	6.71	$	0.36		6	%	$	6.35
DD&A Expense (In thousands)	$	20,644	$	3,820		23	%	$	16,824	$	1,446		9	%	$	15,378

The following table details the increases in DD&A of oil and gas properties between 2009 and 2011 due to the changes in volumes and average DD&A rates presented in the table above:

	(Thousands)
2009 DD&A	$	15,378
Changes due to volumes		551
Changes due to rates		895
2010 DD&A		16,824
Changes due to volumes		279
Changes due to rates		3,541
2011 DD&A	$	20,644

2011 vs. 2010  DD&A increased by $3.8 million in 2011 compared with 2010 primarily due to increased DD&A rates and greater volumes.  Our DD&A rate increased in 2011 compared with 2010 because we add less proved reserves per well drilled for calculating DD&A with each year that passes without obtaining the remaining ten-year extensions for certain of our concessions because our proved reserves are limited to the current concession life (see discussion below).  Additionally, our weighted average DD&A rate increased in 2011 due to a greater proportion of sales volumes on a Boe basis from properties with DD&A rates that are higher than the weighted average rate experienced in 2010.

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Our DD&A expense is based on the units-of-production method, which in basic terms multiplies the percentage of estimated proved developed reserves produced each period times the net carrying value of our proved oil and gas properties. Our proved developed reserves are limited to an area’s concession life even though a concession’s term can be extended for ten years based on terms to be agreed with and the consent of the government. We are working to obtain the ten-year concession extensions for our properties in Río Negro and Tierra del Fuego which currently have concession terms ending in 2016.  If any extensions are obtained, we expect to experience a favorable effect on future DD&A rates as wells whose productive lives extend beyond 2016 will result in the addition of proved developed reserves.

Investment Income

2011 vs. 2010  Total investment income increased by $4.0 million compared with 2010 due to greater Equity income from Argentine investment.  The increase in our equity income is due to an increase in the net income of our equity investee, Petrolera.  The comparative increase in Petrolera’s net income is primarily a result of greater revenues driven by higher oil sales prices and benefits received by Petrolera from the Oil Plus program, partially offset by Petrolera’s share of a provincial production tax settlement with the province of Río Negro (for further discussion of these items, see “MD&A – Oil and Natural Gas Marketing – Oil Prices – Hydrocarbon Subsidy Programs” in Item 7 and Note 2 in Item 8 of this report).

2010 vs. 2009  In 2010, our Total investment income increased by $2.0 million, or 14 percent, due to greater Equity income from Argentine investment. The comparative increase in Petrolera’s net income is a result of greater revenues driven by higher oil, natural gas and LPG average sales prices.

Income Taxes

2011 vs. 2010  Although Income taxes increased by $369 thousand compared with 2010, the effective income tax rate on the total provision for 2011 is lower than the effective income tax rate in 2010 primarily due to the greater amounts of exploration activity in Colombia in 2010 which provided no benefit to income tax expense during the period and increased Equity income from Argentine investment which is presented on an after-tax basis.  See Note 8 – Income Taxes in Item 8 of this report for further discussion of income taxes.

2010 vs. 2009  Income taxes increased by $1.7 million compared with 2009 in direct relation to our increase in pre-tax income in Argentina.  The effective income tax rate on the total provision for 2010 is greater than the effective income tax rate in the prior year primarily due to the greater amounts of exploration activity in Colombia which provided no benefit to income tax expense during the period.

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LIQUIDITY AND CAPITAL RESOURCES

Outlook

Oil price realizations in Argentina have been on a steady upward trend since early 2009, reaching an average price of $72 per barrel in December 2011.  Higher oil prices also benefit Petrolera’s cash flows from operations and its ability to pay dividends.  Petrolera’s ability to pay dividends is dependent upon numerous factors, including its cash flows provided by operating activities, levels of capital spending, changes in crude oil and natural gas prices, and debt and interest payments.  Oil price realizations in Argentina continue to be negotiated on a short-term basis, and as such, we cannot accurately predict how they will evolve during 2012.

Inflation in Argentina has been a persistent problem for some time.  The annual inflation rate was 20 percent or higher in 2011; economists in Argentina are predicting similar levels of inflation during 2012.  In contrast, the Argentine peso has not experienced significant devaluation by comparison causing considerable increases in our U.S. dollar cost of operations and capital expenditures.  Consequently, our operating income did not increase in line with the upward trend of our oil price realizations in 2012, and there can be no assurance that our margins will improve in 2012.

We will continue to monitor our capital programs and the quarterly shareholder dividend as necessary to provide us with the financial resources and liquidity needed to continue development drilling in our core properties over the long term, fund new investment opportunities, meet future working capital needs and fund any further cash bonus payments that may be negotiated to obtain concession extensions, if any, while maintaining sufficient liquidity to reasonably protect against unforeseen circumstances requiring the use of funds.

Capital & Exploration Expenditures Budget for 2012

Our 2012 capital plan provides for $58 million for capital expenditures net to our direct working interests.  We plan to participate in the drilling of 50 gross wells in 2012.  In addition, we plan on spending approximately $8 million for the acquisition of seismic information.  After taking into consideration the portion of capital expenditures attributable to our equity interest in Petrolera, our combined consolidated and equity capital expenditure budget for 2012 is $96 million.  Any cash bonus payments that may be negotiated to obtain concession extensions would result in additional capital expenditures.  We expect that we and Petrolera will have sufficient capital resources to fund our investment programs in 2012.  We review our capital spending programs throughout the year in light of any changing economic or price conditions and, if necessary, will adjust our planned investments accordingly. We expect to fund our 2012 capital expenditures with cash on hand and cash flows from operations.

Liquidity

Although we have interests in several oil and gas properties in Argentina, our direct participation in those Neuquén basin properties in which we are partners with Petrolera and dividends from our equity interest in Petrolera are the largest contributors to our net cash provided by operating activities.

We have historically funded capital programs and past property acquisitions with internally generated cash flow. We have not relied on debt or equity as sources of capital due to the turmoil that periodically affects Argentina’s economy which made financing difficult to obtain on reasonable terms. Although we have not typically relied on debt or equity as sources of capital, successful exploration efforts in Argentina or Colombia could lead to development capital needs that are currently beyond our ability to fund from operations.  Consequently, we may have to consider additional bank financing or some form of equity financing in the future.  Such financing may not be available or available on acceptable terms in the future.

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With a cash and cash equivalents balance at December 31, 2011, of $36.9 million, or 13 percent of total assets, and the ability to adjust capital spending as necessary, we believe we have sufficient liquidity and capital resources to effectively manage our business in 2012.  

Our liquidity is affected by restricted cash balances that are pledged as collateral for letters of credit for exploration activities in Colombia.  As of December 31, 2010, a total of $4 million was considered restricted and included in restricted cash.  In first quarter 2011, one of our letters of credit for $4 million was reduced by $1.1 million and extended until September of 2012.  We expect to renew this upon expiration as our drilling efforts continue.  In the second quarter we issued another $5.5 million letter of credit collateralized with cash for another exploration block in Colombia.  Consequently, $8.4 million of cash is considered restricted as of December 31, 2011.  The restricted cash is invested in a short-term money market account with a financial institution.

Cash Flow Analysis

The following table summarizes the change in cash and cash equivalents for the periods shown.

Sources (Uses) of Cash

	Years Ended December 31,
	2011			2010			2009
	(Thousands)
Net cash provided (used) by:
Operating activities	$	42,184		$	39,038		$	28,262
Investing activities		(40,138	)		(33,829	)		(25,295	)
Financing activities		(381	)		(2,379	)		(4,352	)
Increase (decrease) in cash and cash equivalents	$	1,665		$	2,830		$	(1,385	)

Operating Activities

Our net cash provided by operating activities in 2011 increased by $3.1 million compared with 2010 primarily due to higher operating income.

Our net cash provided by operating activities in 2010 increased by $10.8 million compared with 2009 due to higher operating income and greater dividends from our equity investment in Petrolera.

Included in our net cash provided by operating activities are dividends received from our equity investment in Petrolera of $12.8 million in 2011, $14.1 million in 2010 and $5.3 million in 2009.

Investing Activities

During 2011, capital expenditures totaled $35.8 million for development and exploration drilling and related production and surface facilities. Additionally, our cash used as collateral for letters of credit changed by $4.4 million.

During 2010, we spent $33.8 million for capital expenditures, including $31.8 million for development and exploration drilling, and $2.0 million for related production and surface facilities.

During 2009, we spent $20.5 million for capital expenditures, including $17.9  million primarily related to development and exploration drilling, and $2.6 million as acquisition cost related to our entrance into Colombia. Additionally, $4  million was invested as collateral for a letter of credit for investments in Colombia.

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Financing Activities

During 2011, we received $2 million in borrowings from a $10 million unsecured bank line of credit to fund capital expenditures.  In addition, we paid $2.4 million of dividends to our shareholders in 2011, $2.4 million in 2010, and $4.4 million in 2009.

Contractual Obligations

The table below summarizes our contractual obligations. We expect to fund these contractual obligations with cash and cash generated from operating activities.

	Obligations per Period
	2012		2013		2014		Thereafter		Total
	(Amounts in Thousands)
Long-term debt
Principal	$	-	$	500	$	1,000	$	500	$	2,000
Interest		80		70		40		10		200
International oil and gas activities		21,582		18,650		10,000		-		50,232
Other long-term liabilities		-		-		-		4,024		4,024
Total	$	21,662	$	19,220	$	11,040	$	4,534	$	56,456

International oil and gas activities includes estimates for remaining drilling or seismic investments pursuant to exploration permit work obligations.  We expect to fund these expenditures with cash provided by operating activities. See Note 11 – Long-term Liabilities in Item 8 of this report for further discussion about other long-term liabilities which include pension obligations and asset retirement obligations.  For further discussion about our commitments, see Note 12 – Contingencies and Commitments in Item 8 of this report.

Off-Balance Sheet Arrangements

We do not currently use any off-balance sheet arrangements to enhance liquidity and capital resources.

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ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company’s operations are exposed to market risks as a result of changes in commodity prices and foreign currency exchange rates.

Commodity Price Risk

We have historically not used derivatives to hedge price volatility. As previously mentioned in MD&A, oil price realizations for oil produced and sold in Argentina are significantly influenced by Argentine governmental actions. In the current regulatory environment, the combination of hydrocarbon export taxes and strict government controls over Argentine gasoline prices directly impacts net backs for the sale of crude oil in the domestic Argentine market. As a result, our price is impacted more by government controls than changes in world oil prices.  Because our oil prices are negotiated on a short-term basis, we cannot accurately predict our future sales prices, and it is difficult for us to determine what effect increases or decreases in world oil prices may have on our results of operations.

Inflation, Foreign Currency and Operations Risk

The majority of our operations and all of our current production is located in Argentina which has had a history of high levels of inflation and resulting currency devaluation. Therefore, our financial results may be affected by factors such as changes in foreign currency exchange rates, weak economic conditions, or changes in Argentina’s political climate.  During 2002 and 2003, we recorded sizeable foreign currency exchange losses due to the significant devaluation of the Argentine peso that occurred as a consequence of Argentina’s economic problems during 2001 and 2002.  From 2003 to mid-2008, the Argentine government used monetary policies to keep the peso to U.S. dollar exchange rate stable at approximately 3.00:1. Although government policies such as regulated gasoline prices and strict controls over natural gas prices have attempted to reduce inflationary pressures in Argentina, inflation has averaged approximately 20 percent annually for several years.  Since 2009, the peso to US dollar exchange rate has not changed in proportion to these levels of inflation, resulting in significant year-over-year cost increases when measured in US dollars.  At December 31, 2011, the peso to U.S. dollar exchange rate was 4.30:1.

Argentine Economic and Political Environment                                                                                     

Argentina has a history of economic and political instability.  Because our operations are predominately located in Argentina, our operations and financial results have been, and could be in the future, adversely affected by economic, market, currency, and political instability in Argentina, as well as measures taken by its government in response to such instability. Argentina’s economic and political situation continues to evolve, and the Argentine government may enact future regulations or policies that may materially impact, among other items, (i) the realized prices we receive for the commodities we produce and sell as a result of new taxes; (ii) the timing of repatriations of cash to the Cayman Islands; (iii) our asset valuations; (iv) peso-denominated monetary assets and liabilities; and (v) restrictions on imports of materials necessary for our operations.

Cristina Kirchner, wife of former president Nestor Kirchner, was elected president in December 2007.  In October 2011, she was overwhelmingly re-elected to a second term.  Her first term was highlighted by energy policies that controlled prices of hydrocarbons, in particular natural gas prices, subsidies for the import of natural gas at prices far higher than those permitted for the sale of natural gas produced in Argentina, close alliances with labor unions, and a monetary policy designed to support the value of the peso. We cannot predict if current policies in place will continue during her second term.

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Immediately after the elections in October 2011, the Argentine government revised its policy regarding repatriation of hydrocarbon export proceeds collected in currencies other than peso, forcing companies to repatriate all export revenues to Argentina.  Before the October decree, companies that exported hydrocarbons were allowed to collect their export sales proceeds outside of Argentina and only had to repatriate 30 percent of those proceeds (or send US dollars to Argentina and convert to pesos).  Both we and Petrolera export only small volumes of LPG with all oil and natural gas volumes sold in Argentina.  Although hydrocarbon exports from Argentina are not significant, this policy is an indication that the government continues its efforts to support the value of the peso and control movement of capital in and out of the country.  Also in October, the government issued another decree which requires companies to obtain approval from the Dirección General de Rentas (or “DGI,” the Argentine taxing authority) before executing a foreign exchange transaction.  We do not expect that this decree will impact us or Petrolera.  These new regulations do not impact a company’s ability to pay dividends or repatriate funds to its parent company.

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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Management’s Annual Report on Internal Control Over Financial Reporting	54
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting	55
Report of Independent Registered Public Accounting Firm	56
Report of Independent Registered Public Accounting Firm	57
Consolidated Balance Sheets at December 31, 2011 and 2010	58
Consolidated Statements of Income for each year  in the three-year period ended December 31, 2011	59
Consolidated Statements of Changes in Equity for each year in the three-year period ended December 31, 2011	60
Consolidated Statements of Cash Flows for each year in the three-year period ended December 31, 2011	61
Notes to Consolidated Financial Statements	62

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MANAGEMENT’S ANNUAL REPORT ON

 INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a – 15(f) and 15d – 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2011, based on  the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. As we reported in the third quarter of 2011, we previously identified a material weakness related to financial statement presentation and disclosure matters.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

The material weakness identified in the third quarter was principally the result of the lack of technical accounting resources necessary to identify and assess complex accounting matters and appropriately present and disclose such matters in our consolidated financial statements and related footnotes.

In the fourth quarter, we enhanced our internal controls to help identify and assess accounting matters and appropriately present and disclose such matters in our consolidated financial statements and related footnotes.  We did this by retaining the services of a contract technical accounting resource.  Ultimately, we will hire a permanent employee to serve in this role.

Although we believe the steps taken to date will improve our internal controls over financial reporting, we have not made all changes necessary to fully remediate our internal control deficiencies.  Therefore, the material weakness still existed at the end of the period covered by this report.

Based on our assessment, we concluded that, as of December 31, 2011, our internal control over financial reporting was not effective.

Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON INTERNAL CONTROL OVER FINANCIAL REPORTING

To the Board of Directors and Shareholders of

Apco Oil and Gas International Inc.

We have audited Apco Oil and Gas International Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Apco Oil and Gas International Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. The Company has not maintained adequate technical resources as of December 31, 2011, necessary to review the financial statements and footnote disclosures in order to ensure compliance with financial reporting standards.  We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Apco Oil and Gas International Inc. as of December 31, 2011 and 2010, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2011 financial statements and this report does not affect our report dated February 29, 2012, which expressed an unqualified opinion on those financial statements.

In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Apco Oil and Gas International Inc. has not maintained effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma

February 29, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Apco Oil and Gas International Inc.

We have audited the accompanying consolidated balance sheets of Apco Oil and Gas International Inc. as of December 31, 2011 and 2010, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.  We did not audit the financial statements of Apco Austral S.A., a majority owned subsidiary, which statements reflect total assets of $31.0 million and $29.6 million as of December 31, 2011 and 2010, respectively, and total revenues of $14.2 million, $14.2 million and $11.2 million, for each of the three years in the period ended December 31, 2011.  Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Apco Austral S.A., is based solely on the report of the other auditors.

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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apco Oil and Gas International Inc. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Apco Oil and Gas International Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control––Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2012 expressed an adverse opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma

February 29, 2012

56

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Apco Austral S.A.

We have audited the accompanying balance sheets of Apco Austral S.A.  (the "Company") as of December 31, 2011 and 2010, and the related statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our 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, such financial statements present fairly, in all material respects, the financial position of Apco Austral S.A. as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

Buenos Aires City, Argentina

February 22, 2012

/s/ Deloitte & Co. S.R.L

Guillermo D. Cohen

Partner

57

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(Amounts in Thousands Except Share Amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	36,899		$	35,234
Accounts receivable		11,145			11,757
Advances to joint venture partners		1,264			419
Inventory		2,908			2,300
Restricted cash		-			4,000
Other current assets		2,636			2,265
Total current assets		54,852			55,975
Property and Equipment:
Cost, successful efforts method of accounting		256,886			216,891
Accumulated depreciation, depletion and amortization		(131,021	)		(109,986	)
		125,865			106,905
Argentine investment, equity method		90,208			82,652
Deferred income tax asset		1,472			1,236
Restricted cash		8,364			-
Other assets (net of allowance of $554 at December 31, 2011 and $600 at December 31, 2010)		2,235			1,421
Total Assets	$	282,996		$	248,189
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	9,103		$	8,479
Affiliate payables		1,270			297
Accrued liabilities		4,845			3,409
Income taxes payable		2,527			3,248
Dividends payable		589			589
Total current liabilities		18,334			16,022
Long-term debt		2,000			-
Long-term liabilities		4,024			2,709
Contingent liabilites and commitments (Note 12)
Equity:
Shareholders' equity
Share capital, 60,000,000 shares authorized, par value $0.01 per share;
Ordinary shares, 9,139,648 shares issued and outstanding at December 31, 2011; 29,441,240 issued and outstanding at December 31, 2010		91			294
Class A shares, 20,301,592 shares issued and outstanding at December 31, 2011		203			-
Additional paid-in capital		9,106			9,106
Accumulated other comprehensive loss		(1,450	)		(1,224	)
Retained earnings		250,459			221,068
Total shareholders' equity		258,409			229,244
Noncontrolling interests in consolidated subsidiaries		229			214
Total equity		258,638			229,458
Total liabilities and equity	$	282,996		$	248,189

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

58

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED STATEMENTS OF INCOME

	For the Years Ended December 31,
	2011		2010			2009
	(Amounts in Thousands Except Per Share Amounts)
REVENUES:
Oil revenues (Note 6)	$	84,553	$	69,882		$	57,809
Natural gas revenues (Note 6)		13,257		12,000			9,949
LPG revenues		3,493		3,429			2,669
Other		3,477		2,504			2,289
Total operating revenues		104,780		87,815			72,716
COSTS AND OPERATING EXPENSES:
Production and lifting costs		25,432		19,327			14,998
Taxes other than income		20,913		14,543			12,191
Transportation and storage		888		727			807
Selling and administrative (Note 6)		10,907		9,501			8,835
Depreciation, depletion and amortization		20,703		16,887			15,430
Exploration expense		3,103		6,102			994
Foreign exchange losses (gains)		91		(121	)		640
Other expense		1,519		1,915			1,865
Total costs and operating expenses		83,556		68,881			55,760
TOTAL OPERATING INCOME		21,224		18,934			16,956
INVESTMENT INCOME
Interest and other income		130		436			421
Equity income from Argentine investment		20,496		16,158			14,143
Total investment income		20,626		16,594			14,564
Income before income taxes		41,850		35,528			31,520
Income taxes		10,063		9,694			7,993
NET INCOME		31,787		25,834			23,527
Less: Net income attributable to noncontrolling interests		41		34			30
Net Income attributable to Apco Oil and Gas International Inc.	$	31,746	$	25,800		$	23,497
Amounts attributable to Apco Oil and Gas International Inc.:
Earnings per share – basic and diluted:
NET INCOME PER SHARE	$	1.08	$	0.88		$	0.80
Average ordinary and Class A shares outstanding – basic and diluted		29,441		29,441			29,441

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

59

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Shareholders' Equity
	Ordinary Shares			Class A Shares		Additional Paid-in Capital		Accumulated Other Comprehensive Loss			Retained Earnings			Total Shareholders' Equity			Noncontrolling Interests			Total
	(Amounts in Thousands Except Per Share Amounts)
BALANCE, January 1, 2009   (1)	$	294		$	-	$	9,106	$	(1,270	)	$	176,481		$	184,611		$	184		$	184,795
Comprehensive Income:
Net Income		-			-		-		-			23,497			23,497			30			23,527
Pension plan liability adjustment in equity and consolidated interests (net of Argentine taxes of $57)		-			-		-		(120	)		-			(120	)					(120	)
Total Comprehensive Income																					23,407
Dividends declared ($0.35 per share)		-			-		-		-			(2,355	)		(2,355	)		(10	)		(2,365	)
BALANCE, December 31, 2009  (1)		294					9,106		(1,390	)		197,623			205,633			204			205,837
Comprehensive Income:
Net Income		-			-		-		-			25,800			25,800			34			25,834
Pension plan liability adjustment in equity and consolidated interests (net of Argentine taxes of $90)		-			-		-		166			-			166			-			166
Total Comprehensive Income																					26,000
Dividends declared ($0.08 per share)		-			-		-		-			(2,355	)		(2,355	)		(24	)		(2,379	)
BALANCE, December 31, 2010  (1)		294			-		9,106		(1,224	)		221,068			229,244			214			229,458
Comprehensive Income:
Net Income		-					-		-			31,746			31,746			41			31,787
Pension plan liability adjustment in equity and consolidated interests (net of Argentine taxes of $122)		-			-		-		(226	)		-			(226	)		-			(226	)
Total Comprehensive Income																					31,561
Exchange and issuance of 20,301,592 Ordinary shares for Class A shares		(203	)		203		-		-			-
Dividends declared ($0.08 per share)		-			-		-		-			(2,355	)		(2,355	)		(26	)		(2,381	)
BALANCE, December 31, 2011  (1)	$	91		$	203	$	9,106	$	(1,450	)	$	250,459		$	258,409		$	229		$	258,638
(1) The accumulated other comprehensive loss is net of tax and consists entirely of the net unrecognized pension plan liability

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

60

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in Thousands Except Per Share Amounts)	For the Years Ended December 31,
	2011			2010			2009
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	31,787		$	25,834		$	23,527
Adjustments to reconcile to net cash provided by operating activities:
Equity income from Argentine investment		(20,496	)		(16,158	)		(14,143	)
Dividends received from Argentine investment		12,813			14,077			5,306
Deferred income tax (benefit)		(288	)		(158	)		(315	)
Depreciation, depletion and amortization		20,703			16,887			15,430
Changes in accounts receivable		611			(1,773	)		(864	)
Changes in inventory		(608	)		147			212
Changes in other current assets		(1,920	)		164			(180	)
Changes in accounts payable		(2,593	)		933			(3,418	)
Changes in advances to partners		845			(114	)		(154	)
Changes in affiliate payables, net		973			(1	)		(1,376	)
Changes in accrued liabilities		1,435			(437	)		796
Changes in income taxes payable		(721	)		(476	)		3,826
Other, including changes in noncurrent assets and liabilities		(357	)		113			(385	)
Net cash provided by operating activities		42,184			39,038			28,262
CASH FLOW FROM INVESTING ACTIVITIES:
Property plant and equipment:
Capital expenditures *		(35,814	)		(33,829	)		(17,916	)
Purchase of properties		-			-			(2,600	)
Changes in long-term investments		40			-			(779	)
Changes in noncurrent restricted cash		(4,364	)		-			(4,000	)
Net cash used in investing activities		(40,138	)		(33,829	)		(25,295	)
CASH FLOW FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		2,000			-			-
Dividends paid to noncontrolling interest		(26	)		(24	)		(10	)
Dividends paid		(2,355	)		(2,355	)		(4,342	)
Net cash used in financing activities		(381	)		(2,379	)		(4,352	)
Increase (decrease) in cash and cash equivalents		1,665			2,830			(1,385	)
Cash and cash equivalents at beginning of period		35,234			32,404			33,789
Cash and cash equivalents at end of period	$	36,899		$	35,234		$	32,404
Supplemental disclosures of cash flow information:
Cash paid during the year for income taxes	$	10,601		$	6,184		$	4,980
________________________
*  Increases to property plant and equipment, net of asset dispositions	$	(39,995	)	$	(33,948	)	$	(23,568	)
Changes in related accounts payable and accrued liabilities		4,181			119			3,052
Capital expenditures	$	(35,814	)	$	(33,829	)	$	(20,516	)

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

61

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Description of Business

Apco Oil and Gas International Inc. (the "Company" or "Apco") is an international oil and gas exploration and production company with a focus on South America. Apco began exploration and production ("E&P") activities in Argentina in the late 1960s. As of December 31, 2011, the Company had interests in eight oil and gas producing concessions and two exploration permits in Argentina, and three exploration and production contracts in Colombia.  Our producing operations are located in the Neuquén, Austral, and Northwest basins in Argentina.  The Company also has exploration activities currently ongoing in both Argentina and Colombia.  All of the Company’s operating revenues, equity income, and all but $2.9 million of its long-lived assets for which we have carrying values on our balance sheet, are in Argentina.

Relationship with The Williams Companies, Inc. (“Williams”) and WPX Energy, Inc. (WPX Energy, Inc.)

In February 2011, our previous major shareholder, Williams, announced a reorganization plan to separate Williams into two stand-alone, publicly traded corporations. The plan called for the separation of Williams’ exploration and production business, WPX Energy, of which we were a part, via a spin-off to Williams’ shareholders.

In order to facilitate the transfer of Williams’ interest in Apco to WPX Energy in a tax efficient manner, on June 30, 2011 our shareholders authorized our Board of Directors to issue a separate redeemable convertible class of shares, designated Class A Shares, which have, as a class, 85 percent of the voting power with respect to the election and removal of our directors and authorized us to issue one Class A Share to Williams Global Energy (Cayman) Limited (“Williams Global Energy”), a wholly-owned subsidiary of Williams through which Williams held its interest in us, in exchange for each one of our ordinary shares owned by Williams Global Energy.  Consistent with this approval, on June 30, 2011, we issued 20,301,592 Class A Shares, par value $.01 per share, to Williams Global Energy, in exchange for an equal number of our ordinary shares.  In October 2011, the Class A Shares were transferred from Williams Global Energy to WPX Energy, which now owns 68.96 percent of our outstanding shares.  The Class A Shares and the ordinary shares have identical rights and preferences in all other respects, including with respect to dividend rights.  The Class A Shares will automatically convert into our ordinary shares in the event that neither Williams, nor WPX Energy, beneficially owns, separately or in the aggregate, directly or indirectly, at least 50 percent of the aggregate outstanding Class A Shares and ordinary shares of the Company.

Effective December 31, 2011, all of the common stock of WPX Energy was distributed to the stockholders of Williams and WPX Energy became a 100% publicly owned company.  Since the spin-off, Williams has not owned any equity securities of Apco.

We are now managed by employees of WPX Energy, and all of our executive officers and three of our directors are employees of WPX Energy. Pursuant to an administrative services agreement, WPX Energy provides us with management services, office space, insurance, treasury, accounting, tax, legal, corporate communications, information technology, human resources, internal audit and other administrative corporate services.

62

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of Apco Oil and Gas International Inc. (a Cayman Islands exempted limited company) and its subsidiaries, Apco Properties Ltd. (a Cayman Islands company), Apco Austral S.A. (an Argentine corporation), and Apco Argentina S.A. (an Argentine corporation), which as a group are at times referred to in the first person as “we,” “us,” or “our.”

The Company proportionately consolidates its direct interest of the accounts of its joint ventures into its consolidated financial statements.

Our core operations are our 23 percent working interests in the Entre Lomas, Bajada del Palo and Charco del Palenque concessions and the Agua Amarga exploration permit in the Neuquén basin, and a 40.72 percent equity interest in Petrolera Entre Lomas S.A. (Petrolera, a privately owned Argentine corporation), which is accounted for using the equity method (see Note 2).  Petrolera is the operator and owns a 73.15 percent working interest in the same properties.  Consequently, Apco’s combined direct consolidated and indirect equity interests in the properties underlying the joint ventures total 52.79 percent.  The Charco del Palenque concession is the portion of the Agua Amarga exploration permit which was converted to a 25-year exploitation concession in the fourth quarter of 2009.  We sometimes refer to these areas in a group as our “Neuquén basin properties.”

Summary of Significant Accounting Policies

Use of Estimates

Oil and gas operations are high risk in nature. A successful operation requires that a company deal with uncertainties about the subsurface that even a combination of experience, scientific information and careful evaluation cannot always overcome. Because the Company’s assets are located primarily in Argentina, management has historically been required to deal with the impact of inflation, currency devaluation and currency controls. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Our significant estimates and assumptions include: (i) impairment assessments of investments and long-lived assets; (ii) environmental remediation obligations; (iii) realization of deferred income tax assets (iv) oil and natural gas reserves; and (v) asset retirement obligations.

Segments

All of the Company’s producing operations which presently generate revenues are located in Argentina and our only business in Argentina is oil and gas exploration and production. As a result, management views all of the Company’s business and operations to be one segment.

63

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Revenue Recognition

The Company recognizes revenues from sales of oil, gas, and plant products at the time the product is delivered to the purchaser and title has been transferred. We do not require collateral from our purchasers.  Any product produced that has not been delivered is reported as inventory and is valued at the lower of cost or market. When cost is calculated, it includes total per unit operating cost and depreciation. Transportation and storage costs are recorded as expenses when incurred. The Company has had no contract imbalances relating to either oil or gas production.

Government Tax Credit Certificates

Apco is eligible to earn producer export tax credit certificates as a result of our oil and gas producing activities in Argentina.  We qualify for the certificates based on production increases and reserve replacement measures as provided for by applicable law.  We apply for the certificates and receive them at the discretion of the government.  These certificates can be utilized to offset export taxes on hydrocarbon exports from our direct joint venture interests or can be transferred to third parties at face value.  Due to strict government export controls, we export only a limited volume of hydrocarbons through our joint ventures.  Realized and unrealized gains from these certificates are reported in Other operating revenues in our Consolidated Statements of Income.

Value-Added Tax Collections – Tierra del Fuego

The majority of our Other operating revenues ($2.0 million in 2011, $2.4 million in 2010, and $1.7 million in 2009) relates to value-added tax collections related to hydrocarbon sales revenues from our operations in Tierra del Fuego.  For oil, natural gas, and LPG that is produced on the island of Tierra del Fuego and sold domestically to continental Argentina, sellers are allowed to retain the value-added tax collected from buyers as part of the island’s tax exemption rules.  This mechanism effectively increases our realized prices by 21 percent for sales made to the continent. As a result, fluctuations in our Other operating revenues are generally driven by sales revenues from our operations in Tierra del Fuego.

Cash and Cash Equivalents

The Company considers all investments with a maturity of three months or less when acquired to be cash equivalents.  Restricted cash is not considered cash or a cash equivalent due to the restricted nature.

Restricted Cash

At December 31, 2011, we have $8.4 million of restricted cash which is collateral for letters of credit related to exploration blocks in Colombia.  The letters of credit expire in various dates in 2012 and 2013.  We have presented the entire amount as non-current as any letter of credit expirations in 2012 are expected to be renewed and thus will not be available for general corporate purposes.  As of December 31, 2010, a total of $4 million used as collateral for a letter of credit was considered restricted and included in current restricted cash.

Inventory Valuation

Our inventory includes hydrocarbons of $1.1 million in 2011 and $420 thousand in 2010 which are accounted for at production cost, and spare-parts materials of $1.8 million and $1.9 million, which are accounted for at cost.

64

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Property and Equipment

The Company uses the successful-efforts method of accounting for oil and gas exploration and production operations, whereby costs of acquiring non-producing acreage and costs of drilling successful exploration wells and development costs are capitalized. Costs of unsuccessful exploratory drilling are expensed as incurred. Oil and gas properties are depreciated over their concession life using the units of production method based on proved and proved developed reserves. Non oil and gas property is recorded at cost and is depreciated on a straight-line basis, using estimated useful lives of 3 to 15 years. The Company reviews its proved and unproved properties for impairment on a concession by concession basis and recognizes an impairment whenever events or circumstances, such as declining oil and gas prices, indicate that a property’s carrying value may not be recoverable. If an impairment is indicated, then a provision is recognized to the extent that the carrying value exceeds fair value which is generally determined by the present value of the estimated future net revenues. In estimating future net revenues, the Company uses what we believe are market participation assumptions, including an oil and natural gas price forecast that it believes to be reasonable given the pricing environment in Argentina. Due to the volatility of oil and gas prices, it is possible that the Company’s assumptions regarding oil and gas prices may change in the future.

Unproved properties may include concession acquisition costs and exploratory costs. Concession acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining concession contract term and recent drilling results.  Costs of exploratory wells are assessed based on whether we have found economically recoverable hydrocarbon reserves.  We have $4.2 million in exploratory wells in progress as of December 31, 2011.  If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.  We have $2.6 million of unproved properties related to our operations in Colombia; if our exploration drilling planned for 2012 is unsuccessful, we may have to recognize an impairment loss related to this asset.

The Company records an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (ARO).  The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset.  We measure changes in the liability due to passage of time by applying an interest method of allocation.  This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in other operating expense.

Given the uncertainty inherent in the process of estimating future oil and gas reserves and future oil and gas production streams, the estimate of the number of future wells to be plugged and abandoned could change as new information is obtained. A change in the total asset retirement obligation from year to year can result from changes in the estimate of number of wells that will need to be abandoned, changes in the estimate of the cost to abandon a well and accretion of the obligation. For instance, we only recognize ARO obligations for wells expected to be plugged and abandoned through the primary terms of our concessions.  If we are able to extend our concessions, we will recognize additional ARO obligations at that time.

Furthermore, given past uncertainties associated with future levels of inflation in Argentina and devaluation of the peso, any future estimate of the cost to plug and abandon a well is subject to a wide range of outcomes as the estimate is updated as time passes. Finally, adjustments in the total asset retirement obligation included in the Company’s Consolidated Balance Sheets will take into consideration future estimates of inflation and present value factors based on the Company’s credit standing. Given past economic turmoil in Argentina, future inflation rates and interest rates, upon which present value factors are based, as recent history demonstrates, may be subject to large variations over short periods of time.

65

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Net Income per Share

Net income per share is calculated by dividing net income attributable to Apco Oil and Gas International Inc. shareholders by the combined weighted average number of ordinary and Class A shares outstanding.  Basic and diluted net income per share is the same because the Company has not issued any potentially dilutive securities.  The Class A Shares and the ordinary shares have identical rights and preferences with respect to dividends.

Nonmonetary Transactions

The Company accounts for nonmonetary transactions based on the fair values of the assets involved, which is the same basis as that used in monetary transactions.  During 2011, we delivered a volume of our oil production to a third-party refinery to satisfy a portion of our provincial production tax obligation.  The crude oil inventory that was transferred to satisfy this obligation was recognized at fair value.  We recorded approximately $­­3 million in operating revenues and taxes other than income as a result of these transactions in 2011 (none in 2010 or 2009).

Foreign Exchange

The policy followed in the translation of the Company’s financial statements of foreign operations into United States dollars is in accordance with ASC 830-30, “Translation of Financial Statements,” using the United States dollar as the functional currency.  Accordingly, translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar, are included in results of operations as incurred.

Environmental Obligations

The governments of Argentina and Colombia, at both the federal and provincial levels, promulgate and propose new rules and issue updated guidance to existing rules related to environmental obligations.  We therefore accrue environmental remediation costs for oil and natural gas production activities as they are identified and become probable in conjunction with our operations.  At December 31, 2011, we have accrued liabilities of approximately $563 thousand for these estimated costs.

Income Taxes

Deferred income taxes are computed using the liability method and are provided to reflect the future tax consequences of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements.

Taxes Other Than Income

The Company is subject to multiple taxes in Argentina and Colombia, including provincial production taxes, severance taxes, export taxes, shareholder equity taxes and various transaction taxes.

Fair Value

The carrying amount reported in the balance sheet for cash equivalents, accounts receivable and accounts payable is equivalent to fair value due to the frequency and volume of transactions in and the short-term nature of these accounts.  The carrying amount for restricted cash is equivalent to fair value as the funds are invested in a short-term money market account. The fair value of our debt is estimated to approximate the carrying amount as the interest is a floating-rate based on Libor.

66

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Equity Investment Impairment Policy

We evaluate our equity investment for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment.

Judgments and assumptions are inherent in our management’s estimate of our investment’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.

Reclassifications

Prior year provincial production taxes, taxes other than income and certain other expenses have been reclassified to conform to current year presentation of all operating taxes as Taxes other than income.

Accounting Standards Issued but not Yet Adopted

In June 2011, the FASB issued Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5).  ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. The standard requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income.  The new guidance does not change the items reported in other comprehensive income, nor affect how earnings per share is calculated and presented. We currently report net income in the Consolidated Statements of Income and report other comprehensive income in the Consolidated Statement of Changes in Equity. The standard is effective beginning the first quarter of 2012, with a retrospective application to prior periods. We will apply the new presentation beginning in 2012.

In December 2011, The FASB issued Accounting Standards Update No. 2011-12, “Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12). ASU 2011-12 defers the effective date for only the presentation requirements related to reclassifications in ASU 2011-5. During this deferral period, ASU 2011-12 states that we should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Both ASU’s are effective beginning the first quarter of 2012, with retrospective application to prior periods.  We will apply the new guidance for both ASUs beginning in 2012.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(2)   Investment in Argentine Oil and Gas Company

As described in Note 1, the Company uses the equity method to account for its investment in Petrolera, a non-public Argentine corporation. Petrolera’s only business is its operatorship and 73.15 percent interest in the Entre Lomas, Bajada del Palo and Charco del Palenque concessions and the Agua Amarga exploration permit.

Under the equity method of accounting, the Company's share of net income (loss) from Petrolera is reflected as an increase (decrease) in its investment accounts and is also recorded as equity income (loss) from Argentine investment.  Dividends from Petrolera are recorded as reductions of the Company’s investment. At December 31, 2011, cumulative undistributed earnings in Petrolera were $170.2 million.

The Company’s carrying amount of its investment in Petrolera is greater than its proportionate share of Petrolera’s net equity by $717 thousand.  The reasons for this basis difference are: (i) goodwill recognized on its acquisition of additional Petrolera shares in 2002 and 2003; (ii) certain costs expensed by Petrolera but capitalized by the Company; (iii) recognition of a provision for doubtful account associated with a  receivable held by Petrolera; and (iv) a difference from periods prior to 1991 when the Company accounted for its interest in Petrolera under the cost recovery method, which will be recognized upon full recovery of the Company’s investment.

Petrolera’s financial position at December 31, 2011 and 2010 is as follows.  Amounts are stated in thousands:

	December 31,		December 31,
	2011		2010
Current assets	$	66,430	$	65,621
Non current assets		253,239		228,875
Current liabilities		53,549		52,158
Non current liabilities		46,797		41,047

Petrolera’s results of operations for the years ended December 31, 2011, 2010 and 2009 are as follows.  Amounts are stated in thousands:

	2011		2010		2009
Revenues	$	262,026	$	218,146	$	180,575
Expenses other than income taxes		182,373		151,087		124,021
Net income		49,744		39,950		34,286

Petrolera has realized $1.7 million net to our equity interest during 2011 as a result of certain hydrocarbon subsidy programs.  The face value of subsidies transferred or eligible to be utilized as of December 31, 2011, is $2.7 million net to our equity interest.  In February, 2012, the Argentine government stated its intention to suspend benefits from the Oil Plus program. The fair value of hydrocarbon subsidy assets attributable to the Company’s equity interest in Petrolera as of December 31, 2011, was determined to be $0.  The fair value was determined using a valuation model similar to the one described in Note 13.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(3)   Restricted Cash

Restricted cash of $8.4 million as of December 31, 2011, is related to farm-in agreements for exploration blocks in Colombia.  As part of the contractual requirements related to these blocks, Apco issued a $2.9 million letter of credit in January of 2011 and $5.5 million letter of credit in June of 2011.  The $2.9 million letter of credit expires September 14, 2012 and the $5.5 million letter of credit expires on July 1, 2013.  These letters of credit are collateralized by cash.  The restricted cash is invested in a short-term money market account with a financial institution.  As of December 31, 2010, the restricted cash was classified as other current assets.

(4)   Exploratory Well Costs Pending the Determination of Proved Reserves

For the years ended December 31, 2011, 2010, and 2009, the changes in capitalized exploratory drilling costs pending the determination of proved reserves are detailed in the table below.  The balance as of each year end consisted of wells that were in progress for less than one year.

Changes in exploratory well costs pending determination of reserves:
(Amounts in thousands)	2011			2010		2009
Balance, beginning of year	$	101		$	-	$	1,188
Additions		1,200			101		-
Transfers to proved properties		(101	)		-		(1,188	)
Expensed		-			-		-
Total	$	1,200		$	101	$	-

For the years ended December 31, 2011, 2010, and 2009, there were approximately $1.0 million, $0, and $0, respectively, of capitalized exploratory drilling costs net to our equity interest pending the determination of proved reserves.

(5)   Major Customers

Sales to customers with greater than ten percent of total operating revenues consists of the following:

	For the Years Ended December 31,
	2011	2010	2009
Petrobras Argentina S.A.	13.30%	48.98%	45.23%
Esso Petrolera Argentina S.A.	23.55%	22.41%	25.77%
Oil Combustibles S.A.	26.37%	1.45%	0.00%
Shell Cia. Argentina de Petroleo S.A.	16.32%	7.10%	1.28%

Management believes that the credit risk imposed by this concentration is offset by the creditworthiness of these customers and upon expiration, the oil sales contracts with these customers will be extended or replaced.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(6)   Related Party Transactions

As described in Note 1, WPX Energy was separated from Williams through a spin-off effective as of December 31, 2011.  After the spin-off, Williams is no longer a related party to Apco.  Pursuant to an administrative services agreement entered into with WPX Energy on December 31, 2011, WPX Energy provides us with management services, office space, insurance, treasury, accounting, tax, legal, corporate communications, information technology, human resources, internal audit and other administrative corporate services.

The Company incurred expenses in 2011, 2010, and 2009, from Williams and affiliates for management services, overhead allocation, rent, general and administrative expenses (including the costs of compensating employees of Williams who allocate a portion of their time to managing the affairs of the Company), internal audit services, and purchases of materials and supplies.  These charges were incurred by the Company pursuant to an administrative services agreement between the Company and Williams.

The Company sold hydrocarbons to Petrobras Argentina, the majority shareholder of Petrolera, in 2011, 2010, and 2009.

The Company and Northwest Argentina Corporation (“NWA”), a wholly-owned subsidiary of WPX Energy, each own a 1.5 percent interest in the Acambuco concession.  NWA has no employees and its sole asset is its interest in Acambuco.  The Company’s branch office in Argentina provides administrative assistance to NWA. Specifically, the Company pays cash calls and collects revenues on behalf of NWA.

As of December 31, 2011 and 2010, the balances of related party transactions were as follows:

	(Amounts in thousands)
Accounts Receivable	December 31,
	2011		2010
Petrobras Argentina S.A.	$	-	$	2,523
Petrolera Entre Lomas S.A.		552		405
	$	552	$	2,928
Affiliate Receivable
Northwest Argentina Corporation (1)	$	21	$	-
	$	21	$	-
Affiliate Payable
WPX Energy, Inc.	$	489	$	297
Petrolera Entre Lomas S.A.		781		-
	$	1,270	$	297

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

For the years ended December 31, 2011, 2010 and 2009, revenues and expenses derived from related party transactions and with Williams were as follows:

	(Amounts in thousands)
Revenues from hydrocarbons sold	2011		2010		2009
Petrobras Argentina S.A.	$	13,469	$	43,007	$	32,877
Expenses
WPX Energy, Inc.	$	1,314	$	1,261	$	1,389
The Williams Companies, Inc.		177		89		40
	$	1,491	$	1,350	$	1,429
(1) Northwest Argentina Corporation is a wholly-owned subsidiary of WPX Energy, Inc.

(7)   Accrued Liabilities

At December 31, 2011 and 2010 accrued liabilities consisted of the following:

At December 31, 2011 and December 31, 2010 accrued liabilities consisted of the following:
	December 31,		December 31,
(Amounts in thousands)	2011		2010
Taxes other than income	$	2,424	$	1,280
Payroll and other general and adminstrative expenses		1,765		1,365
Accrued oil and gas expenditures		106		55
Other		550		709
	$	4,845	$	3,409

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(8)   Income Taxes

The Company incorporated in the Cayman Islands in 1979. Since then, the Company’s income, to the extent that it is derived from sources outside the U.S., is not subject to U.S. income taxes. Also, the Company has been granted an undertaking from the Cayman Islands government, expiring in 2019, to the effect that the Company will be exempt from tax liabilities resulting from tax laws enacted by the Cayman Islands government subsequent to 1979. The Cayman Islands currently has no applicable income tax or corporation tax. All of the Company’s income during 2011, 2010, and 2009 was generated outside the United States.

We are domiciled in the Cayman Islands where the income tax rate is zero.  However, we are required to pay income taxes in Argentina.  Our effective income tax rate reflected in the Consolidated Statements of Income differs from Argentina’s statutory rate of 35 percent.  This is because the Company currently incurs income taxes only in Argentina where all of its oil and gas income generating activities are presently located. Additionally, equity income from its Argentine investment is recorded by the Company on an after tax basis and income generated from production in Tierra del Fuego in Argentina is not subject to Argentine income tax.

The Company also generates income and incurs expenses outside of Argentina that are not subject to income taxes in Argentina or in any other jurisdiction.  Therefore these amounts do not affect the amount of income taxes paid by the Company.  Such items include interest income resulting from the Company’s cash and cash equivalents deposited in its Cayman Island and Bahamas bank accounts, general and administrative expenses incurred by the Company in its headquarters office in Tulsa, Oklahoma, and foreign exchange gains and losses resulting from changes in the value of the peso which do not affect taxable income in Argentina.  The Company also incurred expenses related to exploration activity in Colombia that provide no benefit to income tax expense until these activities generate sufficient taxable income in Colombia.

The Company recorded expenses for Argentine taxes as presented in the following table.  The Company is not subject to taxes in any other jurisdiction.

	Twelve Months Ended
(Amounts in thousands)	December 31,
	2011			2010			2009
Income taxes:
Current	$	10,351		$	9,852		$	8,308
Deferred		(288	)		(158	)		(315	)
Income tax expense	$	10,063		$	9,694		$	7,993

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Reconciliations from the provision for income taxes from continuing operations at the Argentine statutory rate to the realized provision for income taxes as follows:

(Amounts in thousands)	2011			2010			2009
Provision at statutory rate	$	14,648		$	12,434		$	11,032
Increases (decreases) in taxes resulting from:
Equity income previously taxed in Argentina		(7,174	)		(5,655	)		(4,950	)
Expenses incurred in non-tax jurisdictions		1,465			1,205			1,486
Income received in non-tax jurisdictions		(443	)		(1,020	)		(1,105	)
US dollar remeasurement effect		1,000			613			949
Changes in valuation allowance		523			1,763			256
Other - net		44			354			325
	$	10,063		$	9,694		$	7,993

Income taxes payable at December 31, 2011 and 2010 were $2.5 million and $3.2 million, respectively. The deferred Argentine income tax benefit relates primarily to certain costs capitalized for Argentine tax purposes and the tax effect of accrued benefit plan obligations is included in Accumulated Other Comprehensive Loss.

The deferred tax asset at December 31 for each of the years presented consists of the following.

(Amounts in thousands)
	2011		2010
Deferred tax assets:
Defined contribution retirement plan accrual	$	232	$	211
Other assets		90		86
Property basis difference and asset retirement obligation		376		334
Foreign carryovers		2,544		2,020
Retirement plan obligations		522		421
Other long term liabilites		250		183
Total deferred tax assets		4,014		3,255
Less valuation allowance		2,542		2,019
Net deferred tax assets	$	1,472	$	1,236

The valuation allowance at December 31, 2011 serves to reduce the recognized tax benefit associated with a foreign carryover to an amount that will, more likely than not, be realized.  We do not expect to be able to utilize the $2.5 million of foreign deferred tax assets until such time as we generate sufficient taxable income in Colombia to absorb the carryover losses.

As of December 31, 2011 and December 31, 2010, the Company had no unrecognized tax benefits or reserve for uncertain tax positions.

It is the Company’s policy to recognize tax related interest and penalties as a component of income tax expense.  The statute of limitations for income tax audits in Argentina is six years and the tax years 2004 through 2011 remain open to examination.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(9) Defined Contribution Retirement Plan

In April 2004, the Company formed a defined contribution retirement benefit plan for its Argentine employees.  Assuming the current level of staffing, future annual contributions are expected to range between $50 thousand to $150 thousand and will be charged to expense as earned. In March 2012, the Company will make a contribution of $100 thousand.  This amount was accrued as administrative expense in 2011. The total expense in 2010 was $100 thousand and $96 thousand in 2009.  Plan contributions are based on employees’ current levels of compensation and years of service. Employees vest at a rate of 20 percent per year with full vesting after five years.

(10) Debt and Banking Arrangements

Due to increased exploration and development activities in our core areas and in anticipation of obtaining the ten-year concession extensions for certain of our properties in Argentina, we executed a loan agreement with a financial institution for a $10 million bank line of credit.  Borrowings under this facility are unsecured and bear interest at six-month Libor plus three percent per annum plus a one percent arrangement fee per borrowing and a commitment fee for the unused portion of the loan amount. The funds can be borrowed during a one-year period ending in March 2012, and principal amounts will be repaid in four equal semi-annual installments from each borrowing date after a two and a half year grace period.  This debt agreement contains covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, purchase or sell assets outside the ordinary course of business, and incur additional debt.  As of December 31, 2011, we have borrowed $2 million under this banking agreement.  Aggregate minimum maturities of our long-term debt are as follows: 2012 – $0; $2013 –$500 thousand; $2014 – $1 million; $2015 – $500 thousand.

(11) Long-Term Liabilities

At December 31, 2011 and 2010, long-term liabilities consisted of the following.  Amounts are stated in thousands:

	2011		2010
Long-term liabilities
Retirement plan obligations	$	901	$	774
Asset retirement obligations		2,373		1,411
Other		750		524
	$	4,024	$	2,709

Retirement plan obligations represent the Company’s proportionate share of the obligation arising from the pension plan that covers all employees of Petrolera, the operator of the Entre Lomas concession. The Company’s proportionate share of the projected benefit obligation at December 31, 2011 and 2010, was $2.6 million and $2.3 million, respectively, while the fair value of plan assets (which are invested in money market mutual funds and treasury federal funds) was $1.7 million and $1.6 million, respectively.  The Company expects its contributions in 2012 to be less than $200 thousand.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(12) Contingencies and Commitments

Certain conditions may exist as of the date of financial statements which may result in a loss to the Company but which will only be resolved when one or more future events occur or fail to occur. Contingent liabilities are assessed by the Company’s management based on the opinion of the Company's legal counsel and available evidence. Such contingencies could include outstanding lawsuits or claims for possible damages to third parties in the ordinary course of the Company’s business, as well as third party claims arising from disputes concerning the interpretation of legislation. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount can be estimated, a liability is accrued. If the assessment indicates that a potential loss contingency is not probable, but is reasonably possible, or is probable but it cannot be estimated, then the nature of the contingent liability, together with an estimate of the possibility of occurrence, is disclosed in a note to the financial statements.  Loss contingencies considered remote are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed. However, in some instances in which disclosure is not otherwise required, the Company may disclose contingent liabilities of an unusual nature which, in the judgment of management, may be of interest to the users of the financial statements. As facts concerning contingencies become known to the Company, the Company reassesses its position both with respect to accrued liabilities and other potential exposures.

In November 2004, the Company received a formal notice from the Banco Central de la Republica Argentina (the Central Bank of Argentina or the “BCRA”), of certain proceedings based upon alleged violation of foreign currency regulations. Specifically, the BCRA claimed that between December of 2001 and November of 2002 the Company failed to bring into the country 100 percent of the foreign currency proceeds from its Argentine oil exports. In 1989, the government established guidelines that required most oil companies to bring into Argentina 30 percent of foreign currency proceeds from exports instead of 100 percent of such proceeds as was generally required of exporters in other industries. In 1991, all foreign exchange controls were lifted by the government.

In response to Argentina’s economic crisis of 2001 and 2002, the government reintroduced foreign exchange controls in 2002, and as a result the Company repatriated 30 percent of its proceeds from oil exports during 2002 following the 1989 guidelines. An opinion from Argentina’s Attorney General, however, declared that the benefits granted to the oil and gas industry in 1989 were no longer effective and, therefore, 100 percent of such funds had to be repatriated. This opinion supported the position taken by the Argentine government during 2002. The government then revised its position in 2003 and expressly clarified that oil companies are required to only repatriate 30 percent of such proceeds. The government’s departure from its 2002 position was effective January 1, 2003, leaving some uncertainty in the law with regard to 2002.

The BCRA audited the Company in 2004 and took the position that 100 percent of its foreign currency proceeds from its 2002 exports were required to be returned to the country rather than only 30 percent, as had been returned to the country by the Company in 2002. The difference for the Company totals $6.2 million. In December 2004, the Company filed a formal response disagreeing with the position taken by the BCRA. In addition, without admitting any wrongdoing, the Company brought into the country $6.2 million and exchanged this amount for Argentine pesos using the applicable exchange rates required by the regulation.

In May 2011, the BCRA sent the case file to the National Justice for Economic Crimes.  The Company anticipates that this matter will remain open for some time. Under the pertinent foreign exchange regulations, the BCRA may impose significant fines on the Company; however, historically few fines have been made effective in those cases where the foreign currency proceeds were brought into the country and traded in the exchange market at the adequate exchange rate and the exporters had reasonable grounds to support their behavior.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

As a result, a conclusion cannot be made at this time as to the probability of an outcome or the amount of any loss to the Company that might result from this proceeding.

Commitments

Commitments for international oil and gas activities including drilling and seismic investments for exploration commitments are as follows:

	Thousands
2012	$	21,582
2013		18,650
2014		10,000
Total	$	50,232

We hold an obligation through our operations in Tierra del Fuego to deliver on a firm basis an average of 4.6 MMcf per day of natural gas to a customer until December 2016, and 2.3 MMcf per day of natural gas to a customer until December 2012.

(13) Fair Value Measurements

      Fair value is the amount received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date.  Fair value is a market-based measurement considered from the perspective of a market participant.  We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation.  The fair value hierarchy prioritizes the inputs used to measure fair value.  Level 3 measurements consist of inputs that are not observable or for which there is little, if any, market activity for the asset or liability being measured.  These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value.  Our Level 3 measurements consist of instruments related to benefits from certain hydrocarbon subsidy programs from the Argentine government.

As of December 31, 2011 and 2010, our fair value estimate of financial instruments related to hydrocarbon subsidies is zero.  Our estimate is based on a market approach and considers various market participant assumptions, including various levels of required governmental approval, the likelihood of the export of hydrocarbons to generate export taxes for which the subsidies can be utilized since we are only able to export a limited amount of our production, the legal requirement to transfer the certificates to other parties at nominal value and the expected duration of the government export tax regime and subsidy programs based on current factors.

We realized $1.1 million and $0 for the years ended December 31, 2011 and 2010, respectively, related to these subsidies. In February, 2012, the Argentine government stated that incentives earned through the Oil Plus program have been suspended.  We are waiting for a formal resolution from the government to assess the impact of this suspension on the hydrocarbon subsidy programs.

The Company has formally requested additional tax-credit certificates under this program related to hydrocarbon production through December 31, 2011.  We believe there is significant uncertainty related to realization of any additional future benefits from this program.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Realized and unrealized gains (losses) included in Income before income taxes for the above periods are reported in Other operating revenues in our Consolidated Statements of Income. During the year, Petrolera realized $1.7 million related to these subsidy programs net to our equity interests.  These amounts are included in our Equity income from Argentine investment.

(14) Taxes Other Than Income

During 2011, the province of Río Negro conducted a review of our operations in conjunction with the negotiation of the concession term extension in Entre Lomas.  As a result of its review, the province contested certain deductions in our basis for calculating provincial production taxes during the period from October 2005 to June 2011. We settled this dispute by paying $966 thousand net to our consolidated interest and $1.3 million net to our equity interest in Petrolera. In 2011, we were assessed a $572 thousand special Colombian equity tax.  We also recorded an adjustment of $787 thousand related to personal asset tax in Argentina.

(15) Subsequent Events

In February 2012, our Board of Directors approved a regular quarterly dividend of $0.02 per share.  On February 28, 2012, we requested an additional $6 million loan under our bank line of credit.

(16) Quarterly Financial Data (Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
(Amounts in Thousands Except Per Share Amounts)
2011
Operating revenues	$	23,083	$	24,576	$	26,170	$	30,951
Costs and expenses		17,258		19,026		22,207		25,065
Investment income		4,866		4,510		3,961		7,289
Net income		8,168		7,708		6,082		9,829
Amounts attributable to Apco Oil and Gas International Inc:
Net income		8,160		7,699		6,076		9,811
Net income per ordinary and Class A shares outstanding		0.28		0.26		0.21		0.33
2010
Operating revenues	$	19,818	$	21,810	$	21,686	$	24,501
Costs and expenses		17,465		16,436		16,801		18,179
Investment income		3,897		4,492		3,537		4,668
Net income		4,004		7,126		6,595		8,109
Amounts attributable to Apco Oil and Gas International Inc:
Net income		3,996		7,117		6,589		8,098
Net income per ordinary and Class A shares outstanding		0.14		0.24		0.22		0.28

Net income for the fourth quarter of 2011 includes $1.2 million in Exploration expense for the acquisition of 3D seismic information. We realized $536 thousand before tax in Other revenues and $1.7 million in Equity income from Argentine investment under hydrocarbon subsidy programs during the fourth quarter. 

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

During the fourth quarter 2011, we refined our accounting policies related to government hydrocarbon subsidy programs.  In accordance with our policy, we determined that a $594 thousand pre-tax benefit in Other revenues and a $796 after-tax benefit in Equity income from Argentine investment of fair value estimates recorded during third quarter 2011 should have been $0.  The quarterly financial data above has been recast to reflect the impact of this adjustment on the third quarter 2011.  Amounts recognized under this program are subject to multiple layers of government approvals and general uncertainty related to the governmental and economic climate in Argentina.  In February 2012, the Argentine government stated that incentives earned through the Oil Plus program have been suspended.  The effect of the correction on the nine-months ended September 30, 2011 is to reduce previously reported net income of $23.1 million by $1.2 million to $21.9 million (revised net income of $0.75 per share from $0.79).  The effect of the correction on the three-months ended September 30, 2011 is to reduce previously reported net income of $7.3 million by $1.2 million to $6.1 million (revised net income of $0.21 per share from $0.25).

Net income for the third quarter of 2011 includes an expense of $966 thousand net to our consolidated interests in Taxes other than income and $1.3 million net to our equity interest in Equity income from Argentine investment for a provincial production tax settlement agreement with the province of Río Negro.

Net income for the first quarter of 2011 includes a pre-tax expense of $572 thousand in Taxes other than income for a special Colombian equity tax.  During second quarter, we recast the previously reported first quarter amounts to properly report this item in the correct period.

Net income for the fourth quarter of 2010 includes a $524 thousand unfavorable pre-tax expense in Production and lifting costs and a $442 thousand decrease to our Equity income from Argentine investment due to the recognition of environmental remediation costs in our Neuquén basin properties.

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APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

Oil and Natural Gas Reserves

Proved Oil, Condensate and Plant Products

The following table summarizes changes in quantities and balances of net proved oil, condensate and plant product reserves for each of the years presented. All of our reserves are located in Argentina.  All of our net proved oil reserves as of December 31, 2011, were audited by our independent reserve engineer, Ralph E. Davis Associates, Inc. (“Davis”).

	(Millions of Barrels)
	Interests
	Consolidated	Equity	Combined
December 31, 2008	9.5	10.5	20.0
Revisions of previous estimates:
Engineering revisions	0.7	0.8	1.5
Extensions and discoveries	1.9	2.5	4.4
Contract modifications	1.3	1.7	3.0
Production	(1.6)	(1.7)	(3.2)
December 31, 2009	11.9	13.8	25.8
Proved developed as of December 31, 2009	7.5	8.5	16.1
Proved undeveloped as of December 31, 2009	4.4	5.3	9.7
December 31, 2009	11.9	13.8	25.8
Revisions of previous estimates:
Engineering revisions	0.1	0.3	0.4
Extensions and discoveries	2.1	1.9	4.0
Production	(1.4)	(1.7)	(3.1)
December 31, 2010	12.7	14.4	27.1
Proved developed as of December 31, 2010	7.7	8.9	16.6
Proved undeveloped as of December 31, 2010	5.0	5.5	10.5
December 31, 2010	12.7	14.4	27.1
Revisions of previous estimates:
Engineering revisions	(0.8)	(1.0)	(1.8)
Extensions and discoveries	1.5	1.4	2.9
Production	(1.5)	(1.7)	(3.2)
December 31, 2011	11.9	13.1	25.0
Proved developed as of December 31, 2011	7.3	8.2	15.5
Proved undeveloped as of December 31, 2011	4.6	4.9	9.5

·        Volumes presented in the above table have not been reduced by the approximately 14 percent provincial production tax that is paid separately and is accounted for as an expense by Apco.

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APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

Natural Gas

The following table summarizes changes in quantities and balances of net proved natural gas reserves for each of the years presented.  All of our reserves are located in Argentina.  As of December 31, 2011, all of our net proved natural gas reserves were audited by Davis.

	(Billions of Cubic Feet)
	Interests
	Consolidated	Equity	Combined
December 31, 2008	61.6	23.9	85.5
Revisions of previous estimates:
Engineering revisions	1.9	0.7	2.6
Extensions and discoveries	7.5	9.7	17.2
Contract modifications	4.3	5.6	9.9
Production	(7.5)	(3.8)	(11.3)
December 31, 2009	67.8	36.1	103.9
Proved developed as of December 31, 2009	44.0	23.0	67.0
Proved undeveloped as of December 31, 2009	23.8	13.1	36.9
December 31, 2009	67.8	36.1	103.9
Revisions of previous estimates:
Engineering revisions	(7.4)	2.2	(5.2)
Extensions and discoveries	11.9	13.7	25.6
Production	(7.7)	(3.8)	(11.5)
December 31, 2010	64.6	48.2	112.8
Proved developed as of December 31, 2010	39.8	27.9	67.7
Proved undeveloped as of December 31, 2010	24.8	20.3	45.1
December 31, 2010	64.6	48.2	112.8
Revisions of previous estimates:
Engineering revisions	(1.5)	(4.0)	(5.5)
Extensions and discoveries	9.6	11.5	21.1
Production	(8.0)	(4.6)	(12.6)
December 31, 2011	64.7	51.1	115.8
Proved developed as of December 31, 2011	41.0	28.5	69.5
Proved undeveloped as of December 31, 2011	23.7	22.6	46.3

·   A portion of our natural gas reserves are consumed in field operations. The volume of natural gas reserves for 2009, 2010, and 2011 estimated to be consumed in field operations included as proved natural gas reserves within consolidated interest is 13.8 Bcf, 14.8 Bcf, and 13.9 Bcf, respectively, and within the equity interest is 13.7 Bcf, 16.6 Bcf, and 15.6 Bcf.

·   Volumes presented in the above table have not been reduced by the approximately 14 percent provincial production tax that is paid separately and is accounted for as an expense by Apco. In general, the tax is paid on volumes sold to customers, but not on natural gas consumed in operations.

80

APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

Our total proved reserves for 2011 did not change substantially from 2010 as the benefits of successful development and exploration drilling did not fully offset the combination of revisions of previous estimates and production volumes for the year.  Extensions and discoveries in 2011 of natural gas reserves are primarily a result of positive drilling results and discoveries from the Lotena formation in the Bajada del Palo concession.  For many years, Apco has enjoyed a track record of success converting proved undeveloped reserves to proved producing reserves as we have drilled and put on production undeveloped locations, including both step-out and in-fill wells, with a greater than 90 percent success rate. Historically, all of our drilling investments have been financed by internally generated cash flows and cash reserves. There were no estimates of total proved net oil or gas reserves filed with any other United States Federal authority or agency during any of the years presented.  The new rules and expanded definitions of oil and gas reserves supported by reliable technologies and practices have not had a material impact on our current estimate of reserves.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is based on the estimated quantities of proved reserves. During 2009 we adopted prescribed accounting revisions associated with oil and gas authoritative guidance. Those revisions include using the 12-month average price computed as an un-weighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. For the years-ended December 31, 2011, 2010 and 2009, the average oil prices used in the estimates were $61.95, $52.11 and $43.62 per barrel.

For the years-ended December 31, 2011, 2010 and 2009, the average natural gas prices used in the estimates were $2.30, $1.63 and $1.93 per Mcf.  Future natural gas revenues included in the standardized measure consist of estimated natural gas production volumes, net of natural gas volumes consumed in operations as described in the footnote in the natural gas reserves table above.

Future income tax expenses have been computed considering applicable taxable cash flows and the appropriate statutory tax rate.  The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed.  Conversion of U.S. dollars is made utilizing the rate of exchange at December 31 for each of the years presented.  The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available.  Probable or possible reserves, which may become proved in the future, are not considered.  The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.

Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures.  Such reserve estimates are subject to change as additional information becomes available.  The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

81

APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

Standardized Measure of Discounted Future Net Cash Flows

The following tables summarize the standardized measure of discounted future net cash flows from proved oil and natural gas reserves that could be produced from our concessions in Argentina for each of the years presented:

	(Millions of Dollars)
	Interests
	Consolidated			Equity			Combined
As of December 31, 2009
Future cash inflows	$	616		$	614		$	1,230
Less:
Future production costs		(214	)		(228	)		(442	)
Future development costs		(83	)		(91	)		(174	)
Future income tax expense		(67	)		(73	)		(140	)
Future net cash flows		252			222			474
Less 10 percent annual discount for estimated timing of cash flows		(97	)		(93	)		(190	)
Standardized measure of discounted future net cash flows	$	155		$	129		$	284
As of December 31, 2010
Future cash inflows	$	747		$	787		$	1,534
Less:
Future production costs		(266	)		(278	)		(544	)
Future development costs		(89	)		(92	)		(181	)
Future income tax expense		(98	)		(114	)		(212	)
Future net cash flows		294			303			597
Less 10 percent annual discount for estimated timing of cash flows		(109	)		(117	)		(226	)
Standardized measure of discounted future net cash flows	$	185		$	186		$	371
As of December 31, 2011
Future cash inflows	$	857		$	891		$	1,748
Less:
Future production costs		(325	)		(336	)		(661	)
Future development costs		(121	)		(117	)		(238	)
Future income tax expense		(95	)		(117	)		(212	)
Future net cash flows		316			321			637
Less 10 percent annual discount for estimated timing of cash flows		(123	)		(124	)		(247	)
Standardized measure of discounted future net cash flows	$	193		$	197		$	390

82

APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

Changes in Standardized Measure

The following analysis summarizes the factors that caused the changes in the amount of standardized measure attributable to the estimate of our Argentine proved oil and gas reserves for each of the years presented.

	(Millions of Dollars)
For the Year Ended December 31, 2009	Interests
	Consolidated			Equity			Combined
Standardized measure of discounted future net cash flows beginning of period	$	161		$	131		$	292
Changes during the year:
Revenues, net of production costs		(44	)		(45	)		(89	)
Net changes in prices and production costs		(35	)		(49	)		(84	)
Additions and revisions of previous estimates		69			88			157
Changes in estimated development costs		(1	)		(3	)		(4	)
Development costs incurred during current period		17			21			38
Changes in production rates, timing, and other		(28	)		(29	)		(57	)
Accretion of discount		20			17			37
Net changes in income taxes		(4	)		(2	)		(6	)
Net changes		(6	)		(2	)		(8	)
Standardized measure of discounted future net cash flows end of period	$	155		$	129		$	284
For the Year Ended December 31, 2010	Interests
	Consolidated			Equity			Combined
Standardized measure of discounted future net cash flows beginning of period	$	155		$	129		$	284
Changes during the year:
Revenues, net of production costs		(54	)		(55	)		(109	)
Net changes in prices and production costs		34			43			77
Additions and revisions of previous estimates		30			63			93
Acquisition of reserves		2			-			2
Changes in estimated development costs		(12	)		(15	)		(27	)
Development costs incurred during current period		26			25			51
Changes in production rates, timing, and other		(3	)		(2	)		(5	)
Accretion of discount		20			17			37
Net changes in income taxes		(13	)		(20	)		(33	)
Net changes		30			57			87
Standardized measure of discounted future net cash flows end of period	$	185		$	186		$	371

83

APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

	(Millions of Dollars)
For the Year Ended December 31, 2011	Interests
	Consolidated			Equity			Combined
Standardized measure of discounted future net cash flows beginning of period	$	185		$	186		$	371
Changes during the year:
Revenues, net of production costs		(60	)		(61	)		(121	)
Net changes in prices and production costs		41			46			87
Additions and revisions of previous estimates		22			18			40
Changes in estimated development costs		(31	)		(30	)		(61	)
Development costs incurred during current period		22			25			47
Changes in production rates, timing, and other		(15	)		(17	)		(32	)
Accretion of discount		24			26			50
Net changes in income taxes		5			4			9
Net changes		8			11			19
Standardized measure of discounted future net cash flows end of period	$	193		$	197		$	390

Capitalized Costs Related to Oil and Gas Producing Activities

The table below summarizes total capitalized costs related to oil and gas producing activities for our consolidated and equity interests for each of the years presented.  We do not have significant unproved properties related to our interests.

	(Amounts in thousands)
	Interests
	Consolidated			Equity
For the year ended December 31, 2010
Proved and unproved oil and gas properties	$	215,682		$	220,107
Accumulated depreciation, depletion and amortization		(109,174	)		(128,993	)
Total	$	106,508		$	91,114
For the year ended December 31, 2011
Proved and unproved oil and gas properties	$	255,559		$	253,640
Accumulated depreciation, depletion and amortization		(130,146	)		(153,415	)
Total	$	125,413		$	100,225

 

84

APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

Costs Incurred in Acquisitions, Exploration, and Development

The following table details costs incurred for acquisitions, exploration, and development during 2009, 2010 and 2011. Costs incurred include capitalized and expensed items.

	Interests
(Amounts in Millions)	Consolidated		Equity		Combined
For the year ended December 31, 2009
Acquisition:
Unproved properties	$	2.6	$	-	$	2.6
Exploration		3.4		3.4		6.8
Development		17.9		19.8		37.7
Asset retirement obligations		0.7		0.9		1.6
Total	$	24.6	$	24.1	$	48.7
For the year ended December 31, 2010
Exploration	$	13.3	$	2.7	$	16.0
Development		27.4		26.2		53.6
Asset retirement obligations		(0.7		(0.9		(1.6	)
Total	$	40.0	$	28.0	$	68.0
For the year ended December 31, 2011
Exploration	$	20.3	$	8.0	$	28.3
Development		22.3		25.2		47.5
Asset retirement obligations		0.6		0.8		1.4
Total	$	43.2	$	34.0	$	77.2

85

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a—15(e) and 15d—15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all 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. Because of 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, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, which considered the material weakness described in Management’s Report on Internal Control Over Financial Reporting, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls were not effective at a reasonable assurance level at the end of the period covered by this report.

As discussed in Item 8. Financial Statements and Supplementary Data—Management’s Report on Internal Control Over Financial Reporting, in the third quarter of 2011, we identified a material weakness related to the lack of technical accounting resources necessary to adequately identify and assess complex accounting matters and appropriately present and disclose such matters in our consolidated financial statements and related footnotes.

In the fourth quarter, we enhanced our internal controls in order to address this material weakness by retaining the services of a contract technical accounting resource.  Ultimately, we will hire a permanent employee to serve in this role.

Although we believe the steps taken to date will improve our internal controls over financial reporting, we have not made all changes necessary to fully remediate our internal control deficiencies.  Therefore, the material weakness still existed at the end of the period covered by this report.

Management’s Annual Report on Internal Control over Financial Reporting

See report set forth in Item 8, “Financial Statements and Supplementary Data.”

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

See report set forth in Item 8, “Financial Statements and Supplementary Data.”

Fourth Quarter 2011 Changes in Internal Controls

Other than described above, there have been no changes during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

ITEM 9B. Other Information

None.

86

PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

We have adopted a Code of Ethics that applies to all of our directors, officers, and employees, including our principal executive, financial, and accounting officers, or persons performing similar functions.  The full text of the Code is published on our corporate governance website located at www.apcooilandgas.com.  We intend to disclose future amendments to certain provisions of our Code, or waiver of such provisions granted to executive officers and directors, on the web site within four business day following the date of such amendment or waiver.

The remaining information required by this Item 10 is set forth under the captions “Proposal One: Election of Directors,” “Corporate Governance,” and “Section 16(a) Beneficial Ownership and Reporting Compliance” in our definitive Proxy Statement for the 2012 Annual General Meeting of Shareholders.

ITEM 11.  EXECUTIVE COMPENSATION

The information required by this Item 11 is set forth under the caption “Executive Compensation and Other Information” in our definitive Proxy Statement for the 2012 Annual General Meeting of Shareholders and incorporated herein by reference.

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

The information required by this Item 12 is set forth under the caption “Security Ownership of Certain Beneficial Owners and Management” in our definitive Proxy Statement for the 2012 Annual General Meeting of Shareholders and incorporated herein by reference.

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

The information required by this Item 13 is set forth under the captions “Corporate Governance” and “Certain Relationships and Related Person Transactions” in our definitive Proxy Statement for the 2012 Annual General Meeting of Shareholders and incorporated herein by reference.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item 14 is set forth under the caption “Proposal Two: Selection of Independent Registered Public Accounting Firm” in our definitive Proxy Statement for the 2012 Annual General Meeting of Shareholders and incorporated herein by reference.

87

PART IV

ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) 1

Financial Statements filed in this report are set forth in the Index to Consolidated Financial Statements under Item 8.

(a) 2 and (c)

Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the financial statements and notes thereto.

Separate financial statements and supplementary data of Petrolera, a 50-percent-or-less owned person are filed as Schedule S-1.

(a) 3 and (b)

The following documents are included as exhibits to this report:

Exhibit Number		Description +
3.1	-	Memorandum of Association of Apco Oil and Gas International Inc., as amended, (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 7, 2007).
3.2	-	Articles of Association of Apco Oil and Gas International Inc. as amended, (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 8, 2011).
4.1	-	Specimen Share Certificate of Apco Oil and Gas International Inc. (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q filed with the SEC on August 7, 2009).
10.1	-	Joint Venture Agreement dated April 1, 1968, among Apco Oil Corporation, Perez Companc, and Petrolera (incorporated by reference to Exhibit 13.(b)(4) to our Registration Statement on Form S-1 filed with the SEC on September 26, 1978).
10.2	-	Joint Venture Agreement dated February 29, 1972, among Apco Oil and Gas International Inc., Perez Companc, and Petrolera (incorporated by reference to Exhibit 13.(b)(5) to our Registration Statement on Form S-1 filed with the SEC on September 26, 1978).
10.3	-	Joint Venture Agreement dated March 23, 1977, among Apco Oil and Gas International Inc., Perez Companc, and Petrolera (incorporated by reference to Exhibit 13.(b)(6) to our Registration Statement on Form S-1 filed with the SEC on September 26, 1978).
10.4	-	Memorandum of Agreement dated August 16, 1979, among the Apco Oil and Gas International Inc., Perez Companc, and Petrolera (incorporated by reference to our Annual Report on Form 10-K filed with the SEC on March 28, 1980).
10.5	-	Agreement dated December 7, 1983, between Petrolera and YPF regarding the delivery of propane and butane from the Entre Lomas area (incorporated by reference to our Annual Report on Form 10-K filed with the SEC on April 12, 1983).
10.6	-	Agreement between the Joint Committee dated December 26, 1990, created by the Ministry of Public Works and Services and the Ministry of Energy, YPF, and Petrolera Perez Companc S.A., constituting the conversion to concession and deregulation of the original Entre Lomas contract number 12,507 (incorporated by reference to our Annual Report on Form 10-K filed with the SEC on April 13, 1992).
10.7	-	Share Purchase Agreement dated October 23, 2002, by and among Ms. Maria Carmen Sundblad de Perez Companc, Sudacia S.A., and Apco Oil and Gas International Inc., relating to the purchase by Apco Oil and Gas International Inc. of 27,700 shares of Petrolera (incorporated by reference to Exhibit 10(A) of our Annual Report on Form 10-K filed with the SEC on March 28, 2003).
10.8	-	Share Purchase Agreement dated December 5, 2002, by and between the shareholders of Fimaipu S.A. and Apco Oil and Gas International Inc., relating to the purchase by Apco Oil and Gas International Inc. of all of the shares of Fimaipu S.A. (incorporated by reference to Exhibit 10(B) of our Annual Report on Form 10-K filed with the SEC on March 28, 2003).
10.9	-	English translation of Stock Purchase Agreement dated January 25, 2005, by and between the Tower Fund L.P., Apco Oil and Gas International Inc., Netherfield Corporation, Sucursal Tierra del Fuego, Antartida e Islas del Atlantico Sur, and ROCH S.A., relating to the purchase by Apco Oil and Gas International Inc. of 79,752 shares of Rio Cullen-Las Violetas S.A. (incorporated by reference to Exhibit 10 of our Annual Report on Form 10-K filed with the SEC on March 14, 2005).
#10.10	-	Summary of Non-Management Director Compensation Action dated July 13, 2009 (incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the SEC on August 7, 2009).
10.11	-	English translation of Contrato de Union Transitoria de Empresas Agreement dated January 26, 2009 by and between the Argentine branch of Apco Oil and Gas International Inc., Petrolera Entre Lomas S.A., and Petrobras Energia S.A., relating to the Bajada del Palo concession (incorporated by reference to Exhibit 10.13 of our Annual Report on Form 10-K filed with the SEC on March 16, 2009).
10.12	-	English translation of Memorandum of Agreement dated June 11, 2009 between the Province of Neuquén Argentina, Apco Oil and Gas International Inc., Petrolera Entre Lomas S.A., and Petrobras Argentina S.A., relating to the extension of the terms of the Bajada del Palo and Entre Lomas hydrocarbon concessions located in the Neuquén Province for an additional ten years (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 7, 2009).
#10.13	-	Administrative Services Agreement effective December 31, 2011 between Apco Oil and Gas International Inc. and WPX Energy, Inc. (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the SEC on January 6, 2012).
* 21	-	Subsidiaries of the registrant
*23.1	-	Consent of Independent Petroleum Engineers, Ralph E. Davis Associates, Inc.
*24	-	Power of attorney.
*31.1	-	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
*31.2	-	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
**32	-	Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
*99.1	-	Report of Independent Petroleum Engineers and Geologists, Ralph E. Davis Associates, Inc.
**101.INS	-	XBRL Instance Document**
**101.SCH	-	XBRL Schema Document**
**101.CAL	-	XBRL Calculation Linkbase Document**
**101.LAB	-	XBRL Label Linkbase Document**
**101.PRE	-	XBRL Presentation Linkbase Document**
**101.DEF	-	XBRL Definition Linkbase Document**
+		In July 2009, the registrant’s name was changed from Apco Argentina Inc. to Apco Oil and Gas International Inc.
*		Filed herewith.
**		Furnished herewith.
#		Management contract or compensatory plan or arrangement.

88

SIGNATURES

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

APCO OIL AND GAS INTERNATIONAL INC.

(Registrant)

By:       /s/ Landy L. Fullmer

                 Landy L. Fullmer

Chief Financial Officer, Chief Accounting Officer, and Controller

Date:  February 29, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, 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/ Ralph A. Hill                      Ralph A. Hill	Chief Executive Officer and Chairman of the Board (Principal Executive Officer)	February 29, 2012
/s/ Landy L. Fullmer Landy L. Fullmer	Chief Financial Officer, Chief Accounting Officer, and Controller (Principal Financial Officer and Principal Accounting Officer)	February 29, 2012
/s/ *Keith E. Bailey	Director	February 29, 2012
Keith E. Bailey
/s/ *Rodney J. Sailor	Director	February 29, 2012
Rodney J. Sailor
/s/ *Robert J. LaFortune	Director	February 29, 2012
Robert J. LaFortune
/s/ *Bryan K. Guderian	Director	February 29, 2012
Bryan K. Guderian
/s/ *Piero Ruffinengo	Director	February 29, 2012
Piero Ruffinengo
/s/ *John H. Williams	Director	February 29, 2012
John H. Williams
*By:  /s/ Thomas Bueno		February 29, 2012
Thomas Bueno Attorney-in-Fact

89

INDEX TO EXHIBITS

Exhibit Number		Description +
3.1	-	Memorandum of Association of Apco Oil and Gas International Inc., as amended, (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 7, 2007).
3.2	-	Articles of Association of Apco Oil and Gas International Inc. as amended, (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 8, 2011).
4.1	-	Specimen Share Certificate of Apco Oil and Gas International Inc. (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q filed with the SEC on August 7, 2009).
10.1	-	Joint Venture Agreement dated April 1, 1968, among Apco Oil Corporation, Perez Companc, and Petrolera (incorporated by reference to Exhibit 13.(b)(4) to our Registration Statement on Form S-1 filed with the SEC on September 26, 1978).
10.2	-	Joint Venture Agreement dated February 29, 1972, among Apco Oil and Gas International Inc., Perez Companc, and Petrolera (incorporated by reference to Exhibit 13.(b)(5) to our Registration Statement on Form S-1 filed with the SEC on September 26, 1978).
10.3	-	Joint Venture Agreement dated March 23, 1977, among Apco Oil and Gas International Inc., Perez Companc, and Petrolera (incorporated by reference to Exhibit 13.(b)(6) to our Registration Statement on Form S-1 filed with the SEC on September 26, 1978).
10.4	-	Memorandum of Agreement dated August 16, 1979, among the Apco Oil and Gas International Inc., Perez Companc, and Petrolera (incorporated by reference to our Annual Report on Form 10-K filed with the SEC on March 28, 1980).
10.5	-	Agreement dated December 7, 1983, between Petrolera and YPF regarding the delivery of propane and butane from the Entre Lomas area (incorporated by reference to our Annual Report on Form 10-K filed with the SEC on April 12, 1983).
10.6	-	Agreement between the Joint Committee dated December 26, 1990, created by the Ministry of Public Works and Services and the Ministry of Energy, YPF, and Petrolera Perez Companc S.A., constituting the conversion to concession and deregulation of the original Entre Lomas contract number 12,507 (incorporated by reference to our Annual Report on Form 10-K filed with the SEC on April 13, 1992).
10.7	-	Share Purchase Agreement dated October 23, 2002, by and among Ms. Maria Carmen Sundblad de Perez Companc, Sudacia S.A., and Apco Oil and Gas International Inc., relating to the purchase by Apco Oil and Gas International Inc. of 27,700 shares of Petrolera (incorporated by reference to Exhibit 10(A) of our Annual Report on Form 10-K filed with the SEC on March 28, 2003).
10.8	-	Share Purchase Agreement dated December 5, 2002, by and between the shareholders of Fimaipu S.A. and Apco Oil and Gas International Inc., relating to the purchase by Apco Oil and Gas International Inc. of all of the shares of Fimaipu S.A. (incorporated by reference to Exhibit 10(B) of our Annual Report on Form 10-K filed with the SEC on March 28, 2003).
10.9	-	English translation of Stock Purchase Agreement dated January 25, 2005, by and between the Tower Fund L.P., Apco Oil and Gas International Inc., Netherfield Corporation, Sucursal Tierra del Fuego, Antartida e Islas del Atlantico Sur, and ROCH S.A., relating to the purchase by Apco Oil and Gas International Inc. of 79,752 shares of Rio Cullen-Las Violetas S.A. (incorporated by reference to Exhibit 10 of our Annual Report on Form 10-K filed with the SEC on March 14, 2005).
#10.10	-	Summary of Non-Management Director Compensation Action dated July 13, 2009 (incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the SEC on August 7, 2009).
10.11	-	English translation of Contrato de Union Transitoria de Empresas Agreement dated January 26, 2009 by and between the Argentine branch of Apco Oil and Gas International Inc., Petrolera Entre Lomas S.A., and Petrobras Energia S.A., relating to the Bajada del Palo concession (incorporated by reference to Exhibit 10.13 of our Annual Report on Form 10-K filed with the SEC on March 16, 2009).
10.12	-	English translation of Memorandum of Agreement dated June 11, 2009 between the Province of Neuquén Argentina, Apco Oil and Gas International Inc., Petrolera Entre Lomas S.A., and Petrobras Argentina S.A., relating to the extension of the terms of the Bajada del Palo and Entre Lomas hydrocarbon concessions located in the Neuquén Province for an additional ten years (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 7, 2009).
#10.13	-	Administrative Services Agreement effective December 31, 2011 between Apco Oil and Gas International Inc. and WPX Energy, Inc. (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the SEC on January 6, 2012).
* 21	-	Subsidiaries of the registrant
*23.1	-	Consent of Independent Petroleum Engineers, Ralph E. Davis Associates, Inc.
*24	-	Power of attorney.
*31.1	-	Rule 13a–14(a)/15d-14(a) Certification of the Chief Executive Officer.
*31.2	-	Rule 13a-14(a)/15d-14(a) Certification of the Chief Financial Officer.
**32	-	Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
*99.1	-	Report of Independent Petroleum Engineers and Geologists, Ralph E. Davis Associates, Inc.
**101.INS	-	XBRL Instance Document**
**101.SCH	-	XBRL Schema Document**
**101.CAL	-	XBRL Calculation Linkbase Document**
**101.LAB	-	XBRL Label Linkbase Document**
**101.PRE	-	XBRL Presentation Linkbase Document**
**101.DEF	-	XBRL Definition Linkbase Document**
+		In July 2009, the registrant’s name was changed from Apco Argentina Inc. to Apco Oil and Gas International Inc.
*		Filed herewith.
**		Furnished herewith.
#		Management contract or compensatory plan or arrangement.

90

Schedule S-1

PETROLERA ENTRE LOMAS S.A.

Financial Statements for the fiscal year ended December

31, 2011 with Report of Independent Registered Public

Accounting Firm

PETROLERA ENTRE LOMAS S.A.

TABLE OF CONTENTS TO FINANCIAL STATEMENTS

	CONTENTS	PAGE
●	Report of Independent Registered Public Accounting Firm
●	Financial statements
	-   Balance sheets as of December 31, 2011 and 2010	- 1 -
	-   Statements of income for the years ended December 31, 2011, 2010 and 2009	- 2 -
	-   Statements of shareholders' equity for the years ended December 31, 2011, 2010 and 2009	- 3 -
	-   Statements of cash flows for the years ended December 31, 2011, 2010 and 2009	- 4 -
	-   Notes to financial statements	- 5 -

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PETROLERA ENTRE LOMAS S.A.:

We have audited the accompanying balance sheets of Petrolera Entre Lomas S.A. (an Argentine corporation) as of December 31, 2011 and 2010, and the related statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our 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. We were not engaged to perform an audit of the Company's 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Petrolera Entre Lomas S.A. as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

Buenos Aires, Argentina
February 15, 2012
	PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
	Member of Ernst & Young Global
	ENRIQUE C. GROTZ
	Partner

PETROLERA ENTRE LOMAS S.A.

BALANCE SHEETS AS OF DECEMBER 31, 2011 AND 2010

(stated in thousands of U.S. dollars)

	December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and cash equivalents		26,063			32,272
Accounts receivable (23 and 10,404 with related parties, Note 6)		26,931			28,890
Other receivables (5,191 and nil with related parties, Note 6)		8,639			2,494
Inventories		3,877			1,613
Other assets		920			352
Total current assets		66,430			65,621
NONCURRENT ASSETS
Accounts receivable		524			-
Property, plant and equipment, net (Note 5)		245,631			223,302
Deferred tax asset, net (Note 4)		3,342			1,103
Other assets		3,742			4,470
Total noncurrent assets		253,239			228,875
Total assets		319,669			294,496
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities (705 and 490 with related parties, Note 6)		19,703			19,389
Debt and accrued debt interest (Note 12)		16,356			16,691
Taxes payable and payroll (Note 9)		16,178			15,061
Other liabilities (Note 9)		1,312			1,017
Total current liabilities		53,549			52,158
NONCURRENT LIABILITIES
Debt (Note 12)		32,380			32,187
Other liabilities (Note 9)		14,417			8,860
Total noncurrent liabilities		46,797			41,047
Total liabilities		100,346			93,205
SHAREHOLDERS' EQUITY
Paid-in capital (95,443,572 ordinary shares and 20,414,127 preferred shares authorized, issued and outstanding)		41,289			41,289
Legal reserve		7,829			7,829
Facultative reserve		116,817			101,795
Retained earnings		55,392			52,070
Accumulated other comprehensive loss		(2,004	)		(1,692	)
Total shareholders' equity		219,323			201,291
Total liabilities and shareholders' equity		319,669			294,496

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

- 1 -

PETROLERA ENTRE LOMAS S.A.

STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

(stated i`n thousands of U.S. dollars)

	Year ended December 31,
	2011			2010			2009
REVENUES:
Operating revenues (41,142, 115,938 and 97,153 with related parties, Note 6)		262,026			218,146			180,575
COST AND EXPENSES:
Operating expenses (3,113, 3,114 and 2,822 with related parties, Note 6)		(63,435	)		(51,956	)		(40,744	)
Provincial production tax		(33,062	)		(27,133	)		(21,961	)
Transportation and storage		(2,505	)		(2,254	)		(2,257	)
Selling and administrative		(6,549	)		(5,512	)		(4,420	)
Depreciation of property, plant and equipment		(59,853	)		(50,271	)		(44,129	)
Exploration expense		(4,905	)		(3,883	)		(1,091	)
Taxes other than income tax		(9,645	)		(7,494	)		(6,080	)
Financial losses		(2,456	)		(1,735	)		(1,603	)
Foreign exchange losses		(73	)		(399	)		(836	)
Other income (expense), net (111, nil and nil with related parties, Note 6)		110			(450	)		(900	)
Total cost and expenses		(182,373	)		(151,087	)		(124,021	)
Income before income tax		79,653			67,059			56,554
Income tax (Note 4)		(29,909	)		(27,109	)		(22,268	)
Net income		49,744			39,950			34,286

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

- 2 -

PETROLERA ENTRE LOMAS S.A.

STATEMENTS OF SHAREHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

(stated in thousands of U.S. dollars)

Balance	Capital stock		Legal reserve		Facultative reserve			Accumulated other comprehensive loss			Retained earnings			Total
December 31, 2008		41,289		7,829		75,281			(1,775	)		51,848			174,472
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting		-		-		34,723			-			(34,723	)		-
Pension plan liability adjustment (Note 10)		-		-		-			(147	)		-			(147	)
Dividends		-		-		(19,000	)					-			(19,000	)
Net income		-		-		-			-			34,286			34,286
December 31, 2009		41,289		7,829		91,004			(1,922	)		51,411			189,611
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting		-		-		39,291			-			(39,291	)		-
Pension plan liability adjustment (Note 10)									230						230
Dividends		-		-		(28,500	)		-			-			(28,500	)
Net income		-		-		-			-			39,950			39,950
December 31, 2010		41,289		7,829		101,795			(1,692	)		52,070			201,291
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting		-		-		46,422			-			(46,422	)		-
Pension plan liability adjustment (Note 10)		-		-		-			(312	)		-			(312	)
Dividends		-		-		(31,400	)		-			-			(31,400	)
Net income		-		-		-			-			49,744			49,744
December 31, 2011		41,289		7,829		116,817			(2,004	)		55,392			219,323

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

- 3 -

PETROLERA ENTRE LOMAS S.A.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

(stated in thousands of U.S. dollars)

	Year ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		49,744			39,950			34,286
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation of property and equipment		59,853			50,271			44,129
Deferred income tax		(2,070	)		(699	)		(87	)
Income from sales of property and equipment		-			(60	)		-
Accrued interest on debt		1,628			1,566			1,645
Changes in assets and liabilities, net:
(Increase) decrease in assets:
Accounts receivable		(8,946	)		(9,432	)		8,283
Accounts receivable - Due from related parties		10,381			3,659			(8,378	)
Inventories		(2,264	)		120			398
Other receivables		(954	)		2,891			(738	)
Other receivables - Due from related parties		(5,191	)		-			-
Other assets		(9	)		(3,239	)		(85	)
Increase (decrease) in liabilities:
Accounts payable and accrued liabilities		5,854			6,104			(1,799	)
Accounts payable - Due to related parties		215			113			(139	)
Taxes payable and payroll		1,117			5,213			903
Other liabilities		1,486			(6,079	)		88
Interest on debt paid		(1,663	)		(1,470	)		(1,670	)
Net cash provided by operating activities		109,181			88,908			76,836
CASH FLOWS FROM INVESTING ACTIVITIES
Payments of purchases of property, plant and equipment		(83,883	)		(64,118	)		(51,063	)
Cash provided by sales of property, plant and equipment		-			117			-
Net cash applied on investing activities		(83,883	)		(64,001	)		(51,063	)
CASH FLOWS FROM FINANCING ACTIVITIES
Loans obtained		16,300			13,100			(1,600	)
Loans paid		(16,407	)		(12,907	)		-
Dividends paid		(31,400	)		(34,500	)		(13,000	)
Net cash applied on financing activities		(31,507	)		(34,307	)		(14,600	)
Net (decrease) increase in cash and cash equivalents		(6,209	)		(9,400	)		11,173
Cash and cash equivalents at beginning of year		32,272			41,672			30,499
Cash and cash equivalents at end of year		26,063			32,272			41,672
Supplemental cash flow information:
Interest paid		2,302			1,486			1,813
Income taxes paid		32,031			17,698			16,245

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

- 4 -

PETROLERA ENTRE LOMAS S.A.

NOTES TO FINANCIAL STATEMENTS

(stated in thousands of U.S. dollars, except otherwise indicated)

1. CORPORATE ORGANIZATION

Petrolera Entre Lomas S.A. is an Argentine corporation. As of December 31, 2011 the shareholders of the Company and their participations were as follows:

Petrobras Argentina S.A.	19.21	%
Apco Oil & Gas International Inc.	39.22	%
Apco Argentina S.A.	1.58	%
Petrobras Participaciones, S.L.	39.67	%
Other	0.32	%
	100.00	%

Apco Argentina S.A. is a wholly owned subsidiary of Apco Oil & Gas International Inc.

The Company is operator and participant in Entre Lomas concession (Entre Lomas, an unincorporated joint venture founded in August 12, 1968) located in Rio Negro and Neuquen provinces in southwest Argentina, which is accounted for following the proportional consolidation method.

The concession contract, renegotiated in 1991 and 1994, permitted the concessionaires to freely dispose of their crude oil and natural gas production and extended the concession term through January 21, 2016.

In 2007, the Company acquired a 73.15% participation interest in "Bajada del Palo U.T.E." joint venture, concessionaire of the hydrocarbons explotation of Bajada del Palo Area, located in the province of Neuquen. This concession was extended through September 7, 2015.

The enactment of Law No. 26,197 in 2007 amending Law No. 17,319, provides the legal framework for the provinces to exercise jurisdiction based on original ownership and to manage the oil and gas fields within their territory. Given this power, the province of Neuquen asked for the renegotiation of the concession terms. During 2009, the Company agreed with the province of Neuquen a 10-year extension to the portion of the exploitation concession of the Entre Lomas Area located in such province, and the Bajada del Palo Area up to 2026 and 2025, respectively.

The negotiation for the extension of the concession term of the Entre Lomas Area located in the province of Rio Negro is still pending.

- 5 -

PETROLERA ENTRE LOMAS S.A.

During 2007, an exploration permit was obtained for Agua Amarga Area in the province of Rio Negro. The permit consists of three periods of three, two and one years respectively. Based on the results of the exploration carried out in the Agua Amarga Area, the Company requested the province of Rio Negro the exploitation concession of a portion of the area, which was granted for a 25-year term. The remaining area is still subject to the first exploratory permit which was extended by the province of Rio Negro until May 31, 2012.

On March 3, 2011, a Joint Venture Agreement between Petrolera Entre Lomas S.A., Petrobras Argentina S.A. and Apco Oil and Gas International Inc- Argentine Branch for the joint exploitation of Agua Amarga block was registered within the province of Rio Negro.

The partners' interests in the above mentioned joint ventures as of December 31, 2011 were as follows:

Petrolera Entre Lomas S.A. (Operator)	73.15	%
Apco Oil & Gas International Inc. Argentine Branch	23.00	%
Petrobras Argentina S.A.	3.85	%
	100.00	%

The Company's interest (73.15%) in assets and liabilities related to the mentioned joint ventures, which are proportionally consolidated in these financial statements as of December 2011 and 2010, is as follows:

	2011			2010
Current assets		13,962			11,864
Noncurrent assets		238,882			214,003
Total assets		252,844			225,867
Current liabilities		(31,139	)		(28,676	)
Noncurrent liabilities		(14,772	)		(8,847	)
Total liabilities		(45,911	)		(37,523	)

The Company's interest (73.15%) in costs and expenses related to joint ventures which are proportionally consolidated in these financial statements as of December 2011, 2010 and 2009, is as follows:

	2011			2010			2009
Operating costs		(147,153	)		(120,601	)		(99,812	)
Selling expenses		(5,730	)		(472	)		(2,042	)
Administrative expenses		(363	)		(4,840	)		(4,149	)
Exploration expenses		(4,905	)		(3,883	)		(1,091	)
Other operating expenses, net		(551	)		(702	)		(1,585	)
Financial losses, net		(496	)		(584	)		(335	)
		(159,198	)		(131,082	)		(109,014	)

- 6 -

PETROLERA ENTRE LOMAS S.A.

2. BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The financial statements have been prepared in accordance with U.S. generally accepted accounting principles (US GAAP).

The Company has only one business segment and is engaged in the oil and gas exploration, development and production in the Entre Lomas, Bajada del Palo and Agua Amarga joint ventures. All of the Company's operating revenues and all of its long-lived assets are in Argentina.

Oil and gas operation is high risk in nature. A successful operation requires that a company deal with uncertainties about the subsurface that even a combination of experience, scientific information and careful evaluation cannot always overcome.

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Summary of significant accounting policies

Cash and cash equivalents

Cash and cash equivalents in 2011 and 2010 include highly liquid bank deposits and money market of 26.0 million and 32.3 million, respectively, of which 25.8 million and 31.8 million earned interest with an average rate of 0.73 and 0.53 percent in 2011 and 2010, respectively. The Company considers all investments with an original maturity of three months or less to be cash equivalents. They were valued at quoted prices in active markets (Level 1 of fair value hierarchy).

Other receivables

Mainly includes tax credits and receivables derived from the transfer of tax credit certificates of the Oil Plus Program as mentioned in this Note under section Revenue Recognition.

Inventories

Includes hydrocarbons by 3,144 and 1,135 and material and spare parts by 733 and 478, in 2011 and 2010, respectively, which were accounted for at the lower of cost or market. The cost is determined by the first-in, first-out method.

Other assets

Includes prepaid expenses, long term tax credit and mandatory savings receivable detailed in Note 3.

- 7 -

PETROLERA ENTRE LOMAS S.A.

Property, Plant and Equipment

The Company uses the successful-efforts method of accounting for its oil and gas exploration and production activities. Under this method, exploration costs, excluding the costs of exploratory wells, are charged to expenses as incurred. Drilling costs of exploratory wells, including stratigraphic test wells, are capitalized pending determination of whether proved reserves exist which justify commercial development. If such reserves are not found, the drilling costs are charged to exploratory expense of the year. Drilling costs of productive wells and of dry holes drilled for development of oil and gas reserves are capitalized. Non oil and gas property is recorded at cost.

Wells and other oil and gas equipment are depreciated over their productive lives using the unit of production method, by applying the ratio of oil and gas produced to the proved developed oil and gas reserves. The Company's remaining property and equipment are depreciated by the straight-line method based on their estimated useful lives, resulting in annual rates in a range of 10% to 33%.

Acquisition costs of proved properties are depreciated and depleted by the unit-of-production method, applying the ratio of oil and gas produced to the total proved oil and gas reserves.

The Company reviews its proved properties for impairment and recognizes an impairment whenever events or circumstances, such as declining oil and gas prices, indicate that a property's carrying value may not be recoverable. If an impairment is indicated, then a provision is recognized to the extent that the carrying value exceeds fair value. For the years ended December 31, 2011, 2010 and 2009, there were not impairment indicators identified by the Company.

The oil and gas reserves estimations considered in these financial statements, have been calculated based on technical and economic conditions effective as of each year-end by Petrolera Entre Lomas S.A.'s engineers and are reviewed at least once a year. The Company believes that these estimates are fair and will be adjusted whenever facts or evidence justify it.

As a result of the extension of the concession terms mentioned in Note 1, the present value of the extension cost has been recognized as "Acquisition costs of proved property" as described in Note 5.

Accounting Standards require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset.

The Company's asset retirement obligation is based on estimates of the number of wells expected to be abandoned through the last year of the concessions term and an estimated cost to plug and abandon a well. Both estimates were provided by the Company's engineers and are considered to be the best estimates that can be derived today based on present information. Such estimates are, however, subject to significant change as time passes. Given the uncertainty inherent in the process of estimating oil and gas reserves and future oil and gas production streams, the estimate of the number of wells to be plugged and abandoned could change as new information is obtained.

- 8 -

PETROLERA ENTRE LOMAS S.A.

The Company estimates it will not be required to plug and abandon those wells that will continue to be producing wells upon the termination of the concessions. The estimated asset retirement obligation as of December 31, 2011 and 2010 totaled 10,452 and 5,952. The change in total asset retirement obligation from December 31, 2010 to December 31, 2011 mainly relates to the effect of the passage of time for about 473, and changes in the cost and number of wells planned to be abandoned upon termination of the concessions for about 4,027.

Foreign currency translation

The financial statements have been translated into United States dollars in accordance with ASC 830, Foreign Currency Matters, using the United States dollar as the functional currency.

Fair value of financial instruments

The carrying amount reported in the balance sheet for financial instruments approximates to fair value.

Revenue recognition

The Company recognizes revenues from sales of oil, gas and plant products net of VAT at the time the product is delivered to the purchaser and title has passed. Any product produced that has not been delivered is reported as inventory. When cost is calculated, it includes total per unit operating cost and depreciation. Transportation and storage costs are recorded as expenses when incurred. The Company has had no contract imbalances relating to either oil or gas production.

At the request of the Argentine Government, oil and gas refining companies and oil & gas production companies signed in 2003 an agreement with the intent to maintain the stability of crude oil, gasoline and diesel oil prices (the Agreement).

Under the Agreement crude oil producers and refiners agreed to cap amounts payable for a portion of domestic oil sales contracts at a price of 28.50 per barrel. In addition, producers and refiners also agreed that the excess of the actual price of West Texas Intermediate (WTI), the crude oil type that serves as a reference price for crude oil sales contracts in Argentina, over the 28.50 temporary cap would be payable at such time as WTI fell below 28.50. The debt payable by domestic refiners to producers accrues interest at 7% per annum.

The price stability agreement was renewed until April 30, 2004. However, the decision to not renew the agreement does not terminate the obligation of refiners to reimburse producers for the balances that accumulated from January 2003 through April 2004 if and when the price of WTI falls below 28.50. As of December 31, 2011, the total price credit available to the Company from domestic refiners amounts to 8.9 million and will be recognized in revenues when the price of WTI falls below 28.50 and the Company continues to receive the 28.50 price until its respective price credits are collected. As of December 31, 2011 none of such amounts have been recognized in revenues.

On November 25, 2008, the Argentine government issued Decree No. 2014/2008, creating a program known as Petroleo Plus ("Oil Plus"). The principal purpose of this program is to stimulate the exploration, production and exploitation of oil reserves. According to the Decree, companies that fulfill requirements established by this program will be awarded tax credits that are transferable and that can be applied against taxes levied on exports of crude oil, natural gas and derivatives. Fiscal credits awarded under the Oil Plus Program are subject to verification of an increase in production of oil and the incorporation of new reserves.

- 9 -

PETROLERA ENTRE LOMAS S.A.

The Company does not expect to have enough export duties to apply to its tax credit certificates, having to use them through the transfer to a third party.

Considering the matter mentioned above, the limited market consisting of few export tax payers, a growing amount of oil plus tax certificates, the many levels of governmental approval, the ever-present risk of government non-performance, and the right of return clause included in the transfer agreements, the accounting policy of the Company is to recognize in earning only those certificates transferred and used by third parties.

As of December 31, 2011, the Oil Plus certificates related to the first quarter production of 2011 were transferred and used by third parties. Accordingly, 6.5 million have been recognized in earning as Operating revenues.

Additionally, the Company has also applied and formally requested about 30 million in tax credit certificates under this program, regarding the second, third and fourth quarter's production.

On February 3, 2012, the Argentine Government informed that incentives to oil companies through the Oil Plus Program have been suspended without further details. The Company is waiting for a formal resolution to assess the impact of this suspension on the requested tax credit certificates. As of December 31, 2011 no income was recognized regarding these certificates.

Derivative instruments

The Company does not usually use derivatives to hedge price volatility or for other purposes.

New pronouncements issued but not yet adopted

In May 2011 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, which amends FASB Accounting Standards Codification (ASC) Topic 820, "Fair Value Measurements and Disclosures." The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In June 2011 the FASB issued ASU No. 2011-05, which amends ASC Topic 220, "Comprehensive Income." This ASU requires companies to present items of net income, items of other comprehensive income (OCI) and total comprehensive income in either one continuous statement or two separate but consecutive statements. Companies will no longer be allowed to present OCI in the statement of stockholders' equity, and reclassification adjustments between OCI and net income must be presented separately on the face of the financial statements. The guidance in ASU No. 2011-05 is effective for interim and annual periods beginning after December 15, 2011. The amendment provides only for a change in presentation of financial statements; therefore, adoption will have no impact on the Company's financial position or results of operations.

- 10 -

PETROLERA ENTRE LOMAS S.A.

In September 2011 the FASB issued ASU No. 2011-08, which amends ASC Topic 350-20, "Intangible Assets — Goodwill and Other." The amended guidance provides the option to first assess qualitative factors to determine whether it is more likely than not (a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount. If, after considering the totality of events and circumstances, the qualitative assessment does not indicate that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. The guidance in ASU No. 2011-08 is effective for interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Company does not expect the adoption of this amendment to have a material impact on its financial statements.

3. MANDATORY SAVINGS RECEIVABLE

The Mandatory Savings Law, enacted in 1988, required all taxpayers to pay a five-year refundable mandatory savings deposit.

After a lengthy process before the courts, the Company paid a 6.7 million mandatory savings deposit in twelve installments during the period July 2000 to June 2001. The deposit is denominated in Argentine pesos and its principal should have been refunded 5 years after the last installment was paid, plus interest based on Banco de la Nacion Argentina (Argentine National Bank) savings rate.

The devaluation of the Argentine peso has resulted in a substantial loss in the dollar value of this Argentine peso denominated deposit during 2001 and 2002. As of December 31, 2011, the dollar value of the Company's deposit is 1.8 million. On June 27, 2006 the Company filed a request for reimbursement and, due to the lack of response from administrative authorities, in 2008, presented a judicial claim pursuing the collection of the total amount paid, plus a market interest rate until its effective collection.

As of the date of issuance of these financial statements, the claim is being processed. According to the Company's Management and its legal counsel, a favorable outcome to the Company is regarded as probable since the Company has solid grounds on which to base its position. The deposit is presented in the balance sheet within other noncurrent assets.

4. INCOME TAX

The Company accounts for income taxes under the liability method in accordance with ASC 740 "Accounting for Income Taxes".

Under this method, deferred tax assets and liabilities are established for temporary differences between the financial reporting basis and the tax basis of the Company's assets and liabilities at each year-end.

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PETROLERA ENTRE LOMAS S.A.

The income tax expense is comprised of:

	For the years ended
	2011			2010			2009
Current expense		(31,979	)		(27,808	)		(22,145	)
Prior years income tax amendments		-			-			(210	) (1)
Deferred income tax profit		2,070			699			87
		(29,909	)		(27,109	)		(22,268	)

(1) Amendments to income tax returns for the periods comprised between 2004 and 2008. On August 28, 2009, the Company made use of a tax amnesty implemented by AFIP (Argentine Federal Public Revenue Agency) for the years 2004 through 2007.

Reconciliation of the income tax expense to taxes calculated based on the statutory tax rates is as follows:

	For the years ended
	2011			2010			2009
Pre-tax income		79,653			67,059			56,554
Statutory tax rate		35	%		35	%		35	%
		27,879			23,471			19,794
US dollar remeasurement effect		3,099			3,230			2,884
Tax adjustments and other		(1,069	)		408			(410	)
Income tax expense		29,909			27,109			22,268

The deferred tax assets and liabilities at December 31, 2011 and 2010 are as follows:

	2011		2010
Defined Benefit Pension Plan	2,209		766
Other liabilities	627		249
Asset retirement and other environmental obligations	1,625		1,102
Other, net	53		2
Total deferred tax assets	4,514		2,119
Property, plant and equipment	(1,172	)	(1,016	)
Total deferred tax liabilities	(1,172	)	(1,016	)
Deferred income tax asset, net	3,342		1,103

Uncertain tax positions

No uncertain tax position as defined in ASC 740-10-25-5 (formerly FIN 48) was identified. The Company does not have unrecognized tax benefits that require disclosure in its financial statements accordingly to that rule. The Company tax years 2005 to 2011 remain subject to examination by the Argentine Tax authority.

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PETROLERA ENTRE LOMAS S.A.

5. PROPERTY, PLANT AND EQUIPMENT

The capitalized cost of property, plant and equipment and the related accumulated depreciation as of December 31, 2011 and 2010 were as follows:

	December 31,
	2011			2010
Wells and other oil and gas field equipment		565,235			479,212
Acquisition costs of proved properties		31,687			31,687
Other property, plant and equipment		24,698			28,539
		621,620			539,438
Less accumulated depreciation		(375,989	)		(316,136	)
Total		245,631			223,302

6. RELATED PARTY TRANSACTIONS

As of December 31, 2011 and 2010, the balances from related parties transactions were as follows:

	As of December 31,
	2011		2010
Accounts receivable
Petrobras Argentina S.A.		23		10,404
		23		10,404
Other receivables
APCO Oil & Gas International Inc.- Argentine Branch		318		-
APCO Oil & Gas International Inc		351		-
Petrobras Argentina S.A.		4,522		-
		5,191		-
Accounts payable.
Petrobras Argentina S.A		190		303
Oleoductos del Valle S.A. (1)		515		187
		705		490

(1) Affiliate of Petrobras Argentina S.A.

For the years ended December 31, 2011, 2010 and 2009, revenues and expenses derived from related parties transactions were as follows:

	2011		2010		2009
Revenues from hydrocarbons sold
Petrobras Argentina S.A.		41,142		115,938		97,153
		41,142		115,938		97,153

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PETROLERA ENTRE LOMAS S.A.

	2011		2010		2009
Other income
APCO Oil & Gas International Inc.- Argentine Branch		21		-		-
Petrobras Argentina S.A.		90		-		-
		111		-		-

Operating expenses
APCO Oil & Gas International Inc.- Argentine Branch	7	-	-
Petrobras Argentina S.A.	637	855	570
Oleoductos del Valle S.A. (1)	2,469	2,259	2,252
	3,113	3,114	2,822

(1) Affiliate of Petrobras Argentina S.A.

Director's Compensation totaled 828, 595 and 707 for the years ended December 31, 2011, 2010 and 2009, respectively.

7. MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK

Major Customers

Sales to customers greater than ten percent of total operating revenues consist of the following:

	% for the Years Ended December 31
	2011		2010		2009
Esso Petrolera Argentina S.A.		28.6		28.6		30.8
Oil Combustibles S.A.		27.5		-		-
Shell CAPS		20.0		-		-
Petrobras Argentina S.A.		13.2		53.1		53.8

The balances with Shell CAPSA, Petrobras Argentina S.A., Oil Combustible S.A. and Esso Petrolera Argentina S.A. are 8,377, 23, 5,829 and 8,496 as of December 31, 2011 and nil, 10,404, nil and 7,889 as of December 31, 2010, respectively.

Management believes that the credit risk imposed by this concentration is offset by the creditworthiness of the Company's customers and that upon expiration, the oil sales contracts of the main customers will be extended or replaced.

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PETROLERA ENTRE LOMAS S.A.

8. DEFINED BENEFIT PENSION PLAN

The Company sponsors a defined benefit pension plan which covers all Company employees in payroll as of May 31, 1995. The objective of the plan is to supplement the national social security pension benefits of the employees of the Company. The plan requires from the Company a contribution to a fund. The Company invests in high liquidity, low risk investments with minimal or no risk of loss of capital.

The fund's assets have been contributed to a trust and are mainly invested in cash reserves and Treasury Federal Funds at December 31, 2011 and fixed-term deposits and Treasury Federal Funds at December 31, 2010. The Bank of New York is the trustee and Towers Watson is the servicing agent.

	2011			2010
Projected benefit obligation		8,161			7,418
Accumulated benefit obligation		8,147			7,184
Fair value of plan assets at year end		5,296			4,955
Funded status of the plan (underfunded)		(2,865	)		(2,463	)
Amounts recognized in the statement of financial position consist of:
Accrued benefit liabilities (current and noncurrent)		(2,865	)		(2,463	)
Accumulated other comprehensive income		3,083			2,602
Projected benefit obligation at beginning of the year		7,418			7,551
Service cost		266			176
Interest cost		299			295
Net actuarial (gain)/loss due to plan experience		451			(324	)
Benefit payment from fund		(273	)		(280	)
Projected benefit obligation at year end		8,161			7,418
Fair value of plan assets at beginning of the year		4,955			4,531
Company contributions		612			614
Benefit payments from fund		(273	)		(280	)
Actual return on assets		2			90
Fair value of plan assets		5,296			4,955

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PETROLERA ENTRE LOMAS S.A.

	2011			2010			2009
Component of net periodic benefit cost:
Service cost		266			176			147
Interest cost		299			295			268
Expected return on assets		(194	)		(283	)		(171	)
Amortization of net prior service cost		10			15			15
Amortization of net losses		152			209			154
Net periodic benefit cost		533			412			413
Pension liability adjustment included in other comprehensive income (Note 10)		(481	)		355			(227	)

The prior service cost and actuarial loss included in accumulated other comprehensive income and expected to be recognized in net periodic pension cost during 2012 is 10 and 152, respectively.

	2011			2010
Asset Categories
Cash reserves / fixed-term deposits		57	%		36	%
Treasury Federal Funds		43	%		62	%
Others		0	%		2	%
Total		100	%		100	%

The fair value of the plan assets was measured using quoted prices in active markets (Level 1).

	2011			2010
Assumptions used to determine the benefit obligation and the net benefit cost:
Real Non-Inflationary Rates
Discount rate		4	%		4	%
Expected long-term rates of return on plan assets		4	%		4	%
Rate of compensation increase
up to 35 years of age		5	%		5	%
from 36 up to 49 years of age		1.5	%		1.5	%

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PETROLERA ENTRE LOMAS S.A.

The expected long-term rate of return is based on historical performance of the money market-mutual funds.

Contributions

The Company expects to contribute 614 to its pension plan in 2012.

Estimated Future Benefit Payment

The following benefit payments are expected to be paid.

Year	Benefit
2012		302
2013		302
2014		312
2015		312
2016		385
2017-2021		2,319

The Company uses a December 31 measurement date for its plan.

9. TAXES PAYABLE AND PAYROLL ACCOUNT AND OTHER LIABILITIES

At December 31, 2011 and 2010, taxes payable and payroll account consisted of the following:

	2011		2010
Income tax accrual		9,164		9,811
Provincial production taxes		2,618		2,000
Payroll		2,434		2,002
Other		1,962		1,248
		16,178		15,061

At December 31, 2011 and 2010, current other liabilities consisted of the following:

	2011	2010
Asset retirement and other environmental obligations	494	397
Others	818	620
	1,312	1,017

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PETROLERA ENTRE LOMAS S.A.

At December 31, 2011 and 2010, non-current other liabilities consisted of the following:

	2011		2010
Liability for pension benefit (Note 8)		2,563		2,463
Asset retirement and other environmental obligations		11,749		6,267
Others		105		130
		14,417		8,860

10. COMPREHENSIVE INCOME

Comprehensive income is as follows:

	For the years ended December 31
	2011			2010			2009
Net income		49,744			39,950			34,286
Other comprehensive income (loss):
Pension liability adjustment		(481	)		355			(227	)
Income tax on other comprehensive income (loss)		169			(125	)		80
Other comprehensive income (loss)		(312	)		230			(147	)
Comprehensive income		49,432			40,180			34,139

11. RESTRICTIONS ON RETAINED EARNINGS

Dividends distributed in cash or kind, in excess of taxable income accumulated as of the end of the fiscal year immediately preceding the distribution or payment date, shall be subject to a 35% income tax withholding as single and definitive payment. For the purposes of this tax, accumulated taxable income is defined as net income booked under Argentine GAAP as of the fiscal year-end immediately preceding the effective date of the law plus the taxable income determined as from such year.

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PETROLERA ENTRE LOMAS S.A.

12. DEBT

Company's debt consists of several debt agreements arranged with Banco do Brasil S.A., London Branch and Banco Santander Rio S.A. Detailed information is as follows:

Debt						Principal
agreement date		Interest			Interest	maturity date		Principal
(yyyy-mm-dd)	Bank	rate			payable	(yyyy-mm-dd)		Due
2009-05-15	Banco do Brasil S.A., London Branch	LIBOR + 2.40		%	quarterly		2013-08-12		22,587(1)
2010-05-14	Banco do Brasil S.A., London Branch	LIBOR + 2.50		%	every six months		2013-05-31		3,200
2010-08-17	Banco Santander Rio S.A.		3.85	%	quarterly		2012-07-17		3,200
2010-11-12	Banco do Brasil S.A., London Branch	LIBOR + 2.75		%	every six months		2013-11-15		3,200
2011-02-16	Banco Santander Rio S.A.		3.50	%	quarterly		2013-01-16		6,700
2011-05-17	Banco do Brasil S.A., London Branch	LIBOR + 2.90		%	every six months		2014-05-16		3,200
2011-08-24	Banco do Brasil S.A., London Branch	LIBOR + 2.90		%	every six months		2014-08-07		3,200
2011-11-11	Banco do Brasil S.A., London Branch	LIBOR + 2.95		%	every six months		2014-11-14		3,200
									48,487

(1) Consists of 7 unpaid quarterly installments.

The maturity of debt principal as of year end for the next years is as follows:

2012	16,107
2013	22,780
2014	9,600

As of December 31, 2011, interest and taxes accrued for these loans amount to 1,628, and interest and taxes payable amount to 249.

13. CONTINGENCIES

Certain conditions may exist as of the date of financial statements which may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. Such contingent liabilities are assessed by the Company's management based on the opinion of the Company's legal counsel and the available evidence.

Such contingencies include outstanding lawsuits or claims for possible damages to third parties in the ordinary course of the Company's business, as well as third party claims arising from disputes concerning the interpretation of legislation.

If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount can be estimated, a liability is accrued. If the assessment indicates that a potential loss contingency is not probable, but is reasonably possible, or is probable but it cannot be estimated, then the nature of the contingent liability, together with an estimate of the possibility of occurrence, is disclosed in a note to the financial statements. Loss contingencies considered remote are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.

As of December 31, 2011 no contingent liabilities have been accrued.

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PETROLERA ENTRE LOMAS S.A.

14. EXPLORATORY WELL COSTS

In accordance with the ASC Topic 360 "Property, Plant and Equipment", the Company evaluated existing capitalized exploratory well costs under the provisions of these rules and determined that: a) it found sufficient quantity of reserves during the exploration to justify the completion of the wells as producing wells and b) sufficient progress has been made on assessing the reserves and the economic and operating viability of the projects to which the capitalized exploratory costs relate. Therefore, the Company concluded that as of the balance sheet date, the capitalized exploratory well costs should continue to be capitalized pending the determination of proved reserves.

	2011			2010		2009
Balance, beginning of year		3,918					9,677
Additions		2,059			3,918		1,680
Transfers to proved properties		(2,040	)		-		(11,357	)
Total		3,937			3,918		-

The balance as of December 31, 2011 consisted of one exploratory well whose drilling began in 2010, which is still under evaluation in order to conclude on the commerciality of the area.

15. . SUBSEQUENT EVENTS

Subsequent events have been evaluated through February 15, which is the date these Financial Statements were available to be issued.

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