UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2012
	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 x

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 x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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 x     No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 ¨   Accelerated Filer x   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 x

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates on June 29, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, was $164,951,024. 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 16, 2013, 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 2013 Annual General Meeting of Shareholders to be held on May 7, 2013, 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	1
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	15
	Risk Factors	16
Item 1B.	Unresolved Staff Comments	26
Item 3.	Legal Proceedings	26
Item 4.	Mine safety Disclosures	26
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	29
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 8.	Financial Statements and Supplementary Data	46
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	76
Item 9A.	Controls and Procedures	76
Item 9B.	Other Information	76
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	77
Item 11.	Executive Compensation	77
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	77
Item 13.	Certain Relationships and Related Transactions, and Director Independence	77
Item 14.	Principal Accounting Fees and Services	77
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	78

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DEFINITIONS

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

- "API gravity", or API, is a standard industry measure of gravity (i.e. density) of liquid petroleum product.

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

- "Bopd" means barrels of oil per day.

- “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 caloric 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.

- "Brent" is a major trading classification of light crude oil sourced from the North sea. Brent is a leading global price benchmark for Atlantic basin crude oil, and is sometimes used as a reference price for crude oil sold in Colombia.

- “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 1 and 2.   BUSINESS AND PROPERTIES

(a) General Development of Business

Apco Oil and Gas International Inc. is a Cayman Islands exempted limited company that was 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, 2012, we had interests in nine 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, San Jorge and Northwest basins in Argentina and in the Llanos basin in Colombia.  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.  Please read “Security Ownership of Certain Beneficial Owners and Management” in our definitive Proxy Statement for the 2013 Annual General Meeting of Shareholders (our "2013 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 2013 Proxy Statement, 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 exploration, 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.

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.

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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	Contract	Province	Country	Working	Equity	Combined
Entre Lomas (1)	Neuquén	Concession	Neuquén / Río Negro	Argentina	23.00%	29.79%	52.79%
Bajada del Palo (1)	Neuquén	Concession	Neuquén	Argentina	23.00%	29.79%	52.79%
Charco del Palenque (1)	Neuquén	Concession	Río Negro	Argentina	23.00%	29.79%	52.79%
Agua Amarga (1)	Neuquén	Exploration permit	Río Negro	Argentina	23.00%	29.79%	52.79%
Coirón Amargo (1,2)	Neuquén	Concession	Neuquén	Argentina	45.00%	—
Coirón Amargo (1,2)	Neuquén	Exploration permit	Neuquén	Argentina	45.00%	—
Acambuco	Northwest	Concession	Salta	Argentina	1.50%	—
Río Cullen	Austral	Concession	Tierra del Fuego	Argentina	25.78%	—
Las Violetas	Austral	Concession	Tierra del Fuego	Argentina	25.78%	—
Angostura	Austral	Concession	Tierra del Fuego	Argentina	25.78%	—
Sur Río Deseado Este (3)	San Jorge	Concession	Santa Cruz	Argentina	78.00%	—
Llanos 32	Llanos	Exploration and production	Casanare	Colombia	20.00%	—
Turpial	Middle Magdalena	Exploration and production	Boyaca / Antioquia	Colombia	100.00%	—
Llanos 40	Llanos	Exploration and production	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 our properties in the province of Neuquén in a group as our “Neuquén basin properties.”

(2) In 2012, we received formal approval to convert approximately 26,700 of the 100,000 gross acres of the Coirón Amargo exploration permit to a concession.

(3) During 2012 we reduced our working interest in an exploratory area in the northern sector of the Sur Río Deseado Este concession from 88 percent to 78 percent pursuant to a farm-out agreement. Per the agreement, our working interest will be reduced to 44 percent after the farm-in party drills two wells to earn an additional interest. We also have a 16.94 percent working interest in an exploitation area on the block with limited oil production.

Oil and Gas Producing Activities

Nearly all of our production and proved reserves are located in Argentina as of December 31, 2012. Approximately one and a half percent of our proved reserves are in Colombia. 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, 62 percent of our combined consolidated and equity proved reserves are oil and condensate and 38 percent are natural gas as of December 31, 2012.

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. Successful exploration efforts in 2012 have resulted in a new development project in the Llanos basin in Colombia.

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Oil and Natural Gas Reserves

Summary of Proved Oil and Natural Gas Reserves as of December 31, 2012

Based on Average 2012 Prices

	Oil and Liquids (Mbbls) (1)			Natural Gas (Bcf) (1,2)			Total Proved (Mboe) (1,3)
	Interests			Interests			Interests
	Consolidated	Equity	Combined	Consolidated	Equity	Combined	Consolidated	Equity	Combined
Proved Developed	6,586	7,012	13,598	31.1	20.8	51.9	11,772	10,470	22,242
Proved Undeveloped	4,670	4,380	9,050	15.0	14.7	29.7	7,168	6,833	14,001
Total Proved (4)	11,256	11,392	22,648	46.1	35.5	81.6	18,940	17,303	36,243

(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 provincial tax rate is approximately 14 percent. Volumes in Colombia are presented net of royalties of eight percent.

(2) A portion of our natural gas reserves are consumed in field operations.  The volume of natural gas reserves for 2012 estimated to be consumed in field operations included as proved natural gas reserves is 8.7 Bcf for our consolidated interests and 9.2 Bcf for our equity interests, or an oil equivalent combined amount of 3,000 Mboe.

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

(4) As of December 31, 2012, 98.5 percent of our reserves are in Argentina and one and a half percent is in Colombia.

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 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.

As of December 31, 2012, Ralph E. Davis Associates, Inc. (“Davis”), has audited all of our proved reserves attributable to our Argentine properties as prepared by us, or 98.5 percent of our total proved reserves, and has estimated reserves attributable to our Colombian properties which represent 1.5 percent of our total estimate of proved reserves. Under Davis' review and evaluation process, any significant difference in the estimation of reserves were discussed and resolved.  In the opinion of Davis, the estimates of our proved reserves are in the aggregate reasonable by basin and total. Our estimate of proved reserves has been determined using methods and procedures widely accepted within the industry and that are believed to be appropriate for the purpose of estimating our proved reserves included in this report. The Davis audit was performed in accordance with methods and procedures 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, 2012 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’s report is included as an exhibit to this Form 10-K.

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

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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, 2012 are 14.0 MMboe, compared with 17.2 MMboe as of December 31, 2011.  All 144 locations of our remaining proved undeveloped reserves are forecast to be drilled by 2017; 25 percent of these locations, or 37 wells, are expected to be drilled in 2013.  We expect to drill 41, 40, and 26 proved undeveloped locations during 2014, 2015 and 2016. For many years we have enjoyed a successful track record of 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. During 2012, 2.7 MMboe, or 16 percent of our net proved undeveloped reserves as of December 31, 2011, were converted to proved developed reserves.

During 2012, our progress toward converting proved undeveloped reserves to proved developed reserves included the drilling and completion of 24 gross proved undeveloped wells at a total net cost to us of approximatly $48 million net to our combined consolidated and equity interests. As the year progressed and slower than expected progress was made toward obtaining our two pending ten-year concession extensions, we and our partners drilled only half of the proved undeveloped locations originally planned to be drilled in one of the concessions and none of the proved undeveloped locations originally planned to be drilled in the other concession. As time elapses without obtaining the extensions there remains less time each year to recover invested capital. For additional discussion about our remaining concession extensions, see "Management’s Discussion and Analysis of Financial Condition and Results of Operations ('MD&A') – Overview of 2012 – Concession Contracts in Argentina” in Item 7 of this report.

The following table describes the change in estimates of proved undeveloped reserves from December 31, 2011, to December 31, 2012.

	Mmboe
Proved undeveloped reserves, December 31, 2011	17.2
Proved undeveloped reserves converted to proved producing	(2.7	)
Proved undeveloped reserves added due to extensions and discoveries	4.3
Revisions of previous estimates	(4.8	)
Proved undeveloped reserves, December 31, 2012	14.0

The reduction in previous estimates is the result of reducing our development assumptions and forecast of future well production volumes in natural gas fields due to performance and drilling that did not meet expectations and the reclassification to unproved reserves of proved undeveloped reserves in the provinces of Río Negro and Tierra del Fuego where we have not yet been successful in obtaining our ten-year concession extensions.

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

The following table presents our productive oil and gas wells and our developed acreage assignable to such wells as of December 31, 2012. 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	581	135	171	31	8	8	52,841	12,235	15,663	27,898
Austral basin	62	16	—	60	16	—	11,641	3,001	—	3,001
Northwest basin	3	—	—	6	—	—	13,106	197	—	197
San Jorge basin	7	1	—	—	—	—	—	—	—	—
Total Argentina	653	152	171	97	24	8	77,588	15,433	15,663	31,096
Colombia (Llanos)	2	0.4	—	—	—	—	82	16	—	—
Total Company	655	152	171	97	24	8	77,670	15,449	15,663	31,096

At December 31, 2012, we held the following undeveloped acreage in Argentina and Colombia:

	Undeveloped Acreage
	Gross Acres	Net	Equity	Combined
Neuquén basin	436,659	122,350	100,601	222,951
Austral basin	455,448	117,415	—	117,415
Northwest basin	280,515	4,208	—	4,208
San Jorge basin	75,582	51,413	—	51,413
Total Argentina	1,248,204	295,386	100,601	395,987
Colombia	374,281	203,994	—	203,994
Total Company	1,622,485	499,380	100,601	599,981

Our Neuquén basin properties have various concession terms that currently end between 2016 and 2034.  Approximately 15 percent, 6 percent and 11 percent of our undeveloped acreage in our Neuquén basin properties is subject to exploration permits that expire in 2013, 2014 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 are negotiating to secure the remaining ten-year extensions for those concessions for which such extensions have not yet been granted. Our acreage in Colombia is held under exploration and production contracts that expire in 2013, 2014, and 2015 unless sufficient commercial quantities of hydrocarbons are found to be granted a 24-year exploitation period.

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”). The original purpose of the joint venture was 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.

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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 capacity to accommodate production volumes from all the areas. 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' working interests in the above-mentioned joint ventures as of December 31, 2012 are as follows:

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

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 a 52.79 percent effective 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, 2012, 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”) located in the province of Río Negro. The concession is equipped with centralized facilities that serve all productive fields.  These facilities, most of which are located in the province of Río Negro, 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. 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

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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. We expect to finish the formal process to negotiate the extension with the provincial government of Río Negro in 2013.

Bajada del Palo Concession

The Bajada del Palo concession has a total surface area of approximately 111,000 acres and produces oil and natural gas from four 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 western boundary is near Repsol YPF S.A.’s (“YPF”) Loma de la Lata concession.

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 in 2007 we have reactivated the Borde Montuoso field and are directing significant development activity to the field. The 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.  In addition, successful exploration efforts have led to discoveries in new fields in both the eastern and western part of the concession. Field development of these discoveries is underway.

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 the area around our successful exploration well drilled on the Meseta Filosa prospect. In 2012, we entered another exploration period for Agua Amarga that expires in 2014 in exchange for drilling two more wells.

In 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 since 2011, and we expect to begin natural gas production from this well in the second quarter of 2013.

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 extensive experience gained through exploring and developing in the region.

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.

In early 2012, we received formal provincial approval 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 requires 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 or extended through additional commitments.  We spent approximately $9 million for these commitments during 2012.

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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, including the Vaca Muerta shale, are present in all of the properties in which we participate in the basin. For a full discussion about our unconventional activities in the Neuquén basin during 2012, see "MD&A – Overview of 2012 – Neuquén Basin Properties” in Item 7 of this report.  

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 intended 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.

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 $70 to $100 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. 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. We refer to the Río Cullen, Las Violetas and Angostura concessions as our “TDF concessions.”  

The TDF 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 for an additional ten-year period based on terms to be agreed with the government.  In 2012, we and our partners reached agreements with the provincial government to extend the term of our concessions.  The ten-year extensions for all three concessions run through August 17, 2026.  The agreements have been signed by us and our partners and representatives of the province.  The agreements will become effective upon legislative approval.

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When we purchased our interests in Tierra del Fuego, our operations on the island were exempt from Argentine federal income taxes pursuant to Argentine law. As of May 16, 2012, income generated from production in the province is no longer exempt from income taxes and duties based on Executive Decree 751/2012.

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. We also have a larger interest in an exploratory area in the northern sector of the concession. Pursuant to a farm-out agreement executed in 2012, we reduced our working interest in the exploratory area from 88 percent to 78 percent. Per the terms of the farm-out agreement, our new partner will fund the drilling of two wells which we expect to drill in 2013, and our interest will be reduced to 44 percent. In 2012, we acquired 191 square kilometers of 3D seismic information in this exploratory area.  

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 have ongoing exploration activities. During 2012, we drilled our first discovery wells and continued acquiring 3D seismic information for future drilling as described below.

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 operator of the block is P1 Energy, a Canadian junior exploration and production company. The Llanos 32 block covers approximately 100,000 acres in the Llanos basin of western Colombia.  The first phase exploration commitments for the block included the acquisition of 3D seismic information and the drilling of two exploration wells. After acquiring 260 square kilometers of 3D seismic information in 2010, environmental permitting delays experienced in 2011 deferred drilling activities until 2012.

The two commitment wells were drilled on Llanos 32 during 2012 and resulted in exploration discoveries. For a full discussion of these results, see "MD&A – Overview of 2012 – Colombian Properties” in Item 7 of this report. These investments completed our obligations to earn our interest. The joint venture partners have entered a second exploration phase and committed to drill two more exploration wells by the end of August 2015.

Apco and Ramshorn International Limited (“Ramshorn”), a subsidiary of Nabors Drilling, were awarded the Llanos 40 block in the 2010 licensing round.  In 2012, Ramshorn was purchased by Parex Resources, Inc., a Canadian junior exploration and production company. We hold a 50 percent working interest in the block and Parex 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.  During 2012, we completed the acquisition of 305 square kilometers of 3D seismic information, and in 2013 we will complete our seismic interpretation, choose drilling locations and request drilling permits in anticipation of spudding our first of four wells to be drilled in succession during 2014 targeting the Carbonera and Mirador formations.

Middle Magdalena Basin

In December 2009, we entered into a farm-in agreement to earn a 50 percent working interest in the Turpial block.  Turpial covers approximately 111,000 acres of under-explored area between the Velazquez and Cocorna oil fields in the Middle Magdalena basin.  After acquiring seismic information in 2010, the partners entered a third phase and committed to drill an exploration well.  

In the fourth quarter of 2012, we drilled the committed exploration well on the block. Prior to spudding the Turpial-1 well, our partner decided to commence the relinquishment of its interest in the block but agreed to pay its 50 percent share of costs to total depth.  Initial log interpretations were favorable and we continued under sole risk provisions to case and cement the well for testing.  At the end of 2012, we entered another one-year exploration phase by committing to drill an additional well, and have made plans to test the Turpial-1 well. We have applied to become operator of the block and currently hold a 100 percent working interest pending government approval of the transfer of our partner's interest to us.

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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,
	2012				2011				2010
Sales Volumes (1, 2, 3):
Consolidated interests
Crude oil and condensate (Bbls)	1,515,361				1,359,163				1,338,195
Natural gas (Mcf)	6,037,501				6,301,114				6,306,883
LPG (tons)	10,920				11,108				9,893
Barrels of oil equivalent (Boe)	2,649,757		54	%	2,539,701		54	%	2,505,438		55	%
Equity interests
Crude oil and condensate (Bbls)	1,614,457				1,583,806				1,549,396
Natural gas (Mcf)	2,837,649				2,833,101				2,325,353
LPG (tons)	11,477				11,519				10,048
Barrels of oil equivalent (Boe)	2,222,081		46	%	2,191,165		46	%	2,054,858		45	%
Total volumes
Crude oil and condensate (Bbls)	3,129,818				2,942,969				2,887,591
Natural gas (Mcf)	8,875,150				9,134,215				8,632,236
LPG (tons)	22,397				22,627				19,941
Barrels of oil equivalent (Boe)	4,871,838		100	%	4,730,866		100	%	4,560,302		100	%
Total volumes by basin
Neuquén	4,011,651		82	%	3,907,207		83	%	3,641,439		80	%
Austral	609,424		13	%	616,746		13	%	685,763		15	%
Llanos	78,755		2	%	—		—	%	—		—	%
Others	172,008		3	%	206,913		4	%	233,100		5	%
Barrels of oil equivalent (Boe)	4,871,838		100	%	4,730,866		100	%	4,560,302		100	%
Average Sales Prices:
Consolidated interests
Oil (per Bbl)	$	74.90			$	62.21			$	52.22
Natural gas (per Mcf)	2.56				2.10				1.90
LPG (per ton)	254.76				314.46				346.61
Equity interests
Oil (per Bbl)	$	74.78			$	62.39			$	52.54
Natural gas (per Mcf)	2.81				2.00				1.75
LPG (per ton)	251.72				302.11				358.83
Average Production Costs (4) per Boe:
Production and lifting cost	$	11.71			$	10.01			$	7.71
Taxes other than income	8.82				8.23				5.80
DD&A	10.10				8.13				6.71

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(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.

Drilling and Other Exploratory and Development Activities

The following table summarizes 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.

	2012			2011			2010
	Gross	Net Consolidated	Net Equity	Gross	Net Consolidated	Net Equity	Gross	Net Consolidated	Net Equity
Development:
Productive	32.0	7.9	9.0	30.0	6.9	9.0	39.0	9.2	9.3
Non-Productive	—	—	—	—	—	—	3.0	0.7	0.3
Total	32.0	7.9	9.0	30.0	6.9	9.0	42.0	9.9	9.6
Exploratory:
Productive	5.0	1.3	0.6	7.0	2.1	1.5	3.0	0.7	0.3
Non-Productive	—	—	—	—	—	—	—	—	—
Total	5.0	1.3	0.6	7.0	2.1	1.5	3.0	0.7	0.3
Total:
Productive	37.0	9.2	9.6	37.0	9.0	10.5	42.0	9.9	9.6
Non-Productive	—	—	—	—	—	—	3.0	0.7	0.3
Total	37.0	9.2	9.6	37.0	9.0	10.5	45.0	10.6	9.9

Present Activities

At December 31, 2012, we had two gross development wells and five exploration wells (3.0 net consolidated 0.9 net equity) in various stages of drilling that had not been completed as of year end.

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.

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.

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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 terms of 25 years that can be extended for ten years based on terms to be agreed with the government. Throughout the term of a concession, 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, three 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 and a commitment to drill an agreed number of wells to established target formations.  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 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.

MARKETING

OilMarkets

Our crude oil production in Argentina is sold to local refineries. More than 80 percent of our oil is produced in the Entre Lomas region of the Neuquén basin and 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. 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.

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.

In Colombia, our crude oil production is sold to Colombian refiners or exported. Although Colombia has a significant pipeline system, sufficient pipeline capacity is a challenge for the industry as the transportation infrastructure has not evolved at the same rapid pace of production increases in the country over the past several years. As a result of the limited transportation infrastructure, we use trucks to deliver our production to access points established by our purchasers.

A description of our major customers over the last three years is in Note 6 – Major Customers to our consolidated financial statements in Item 8 of this report.  As can be seen in Note 6, 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

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adverse effect on us.  As discussed above, 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).

For a full discussion about our oil sales prices, see "MD&A – 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” in Item 1A of this report and “Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk” 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.

Natural gas and condensate produced in Acambuco is 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 – Oil and Natural Gas Marketing” in Item 7 of this report.

EMPLOYEES

At February 22, 2013, the Company had 28 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 productive assets that generate operating revenues are in Argentina and Colombia, and we have cash and cash equivalents deposited in banks in the Cayman

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Islands, Panama and the Bahamas, a bank account in Tulsa, Oklahoma, and furniture and equipment in our executive offices. Approximatly 98.5 percent of our production and reserves are currently generated in Argentina.

We  presently have no operating revenues in either the Cayman Islands or the United States. Nearly all of our products are sold either domestically in Argentina or exported from Argentina to neighboring countries.  See Note 6 – Major Customers to our consolidated financial statements 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.

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

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 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;

• 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;

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• 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 below.

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.  

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: 

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• 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.

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 shorten the economic lives of certain fields if 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. 

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.

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

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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, or impairment of our operations, resulting in 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 tothe protection of the environment, which may expose us to significant costsand 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.

Compliance with environmental legislation could require significant expenditures for, among other things, 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 of 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

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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.  

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.

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 ofoperations.

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 the majority of 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.

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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;

• 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. 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.

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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 financialresults and disclosures in the future, which might change the way analysts measureour 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.

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.

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 – Overview of 2012 – Concession Contracts in Argentina” in Item 7 of this report for additional discussion about concession extensions.

The Argentine government could take action with regard to our concessions before their contract terms expire.

During the first quarter of 2012, the Argentine government asserted that exploration and production companies operating in Argentina had not invested sufficiently to overcome domestic production declines, thereby leading to reduced levels of oil and natural gas production as well as reductions in oil and natural proved reserves.  On that basis, the federal government expropriated a majority interest in YPF, the largest oil producing company in Argentina.  If the government subjectively determines that we have not sufficiently invested in our properties, they could take action with regard to our concessions before their contract terms expire.  See “Quantitative and Qualitative Disclosures about Market Risk – Economic and Political Environment” in Item 7A of this report.

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. 

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Because of Argentina's current regulations restricting the purchase of foreign exchange, dividends from our investment in Petrolera may not be a reliable source of funding for our operations outside of Argentina which could limit our ability to grow.

 Since the presidential election in late 2011, the Argentine government has increasingly used foreign-exchange, price, trade, and capital controls to manage the economic challenges faced by the country. Because of Argentina's current regulations restricting the purchase of foreign exchange (US dollars), the receipt of dividends abroad from our investment in Petrolera may not be a reliable source of funding for our operations outside of Argentina which could limit our ability to grow.

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.

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 2012 – 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. We are required to sell natural gas under these conditions.

The crude oil transportation system in Colombia may not have sufficient capacity to deliver our production volumes to market on favorable economic terms.

In Colombia, our crude oil production is sold to Colombian refiners or exported. Although Colombia has a significant pipeline system, sufficient pipeline capacity is a challenge for the industry as the transportation infrastructure has not evolved at the same rapid pace as production over the past several years. If the pipeline infrastructure is not expanded, or if we or other producers have significant oil discoveries, there may not be sufficient capacity to deliver our production to market on favorable economic terms.

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 guerrilla 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 guerrilla activity, the ability of the Colombian government to maintain security in the areas where we have operations may not be successful and guerrilla related violence could affect our operations in the future, resulting in losses or interruptions of our activities.

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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.

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-Person Transactions — Transactions with Related Persons — Administrative Services Agreement,” in our 2013 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, Chief Financial Officer and Chairman of our Board of Directors is each also an executive officer of WPX Energy.  We also have business relationships with WPX Energy, including an

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administrative services agreement pursuant to which WPX Energy provides us with certain administrative and management services.

See “Certain Relationships and Related-Person Transactions” in our 2013 Proxy Statement, which information is incorporated by reference herein.

Our executive officers and certain other persons who provide services to us at our executive offices 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 executive office in Tulsa, Oklahoma, provides office supplies, office space, and computer support pursuant to the administrative services agreement.  See “Certain Relationships and Related-Person Transactions” in our 2013 Proxy Statement, 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 percent 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 percent 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 14 – Contingencies and Commitments to our consolidated financial statements 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.

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.

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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.

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, 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.

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Our assets 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.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 3.   LEGAL PROCEEDINGS

The additional information called for by this item is provided in Note 14 – Contingencies and Commitments to our consolidated financial statement in Item 8 of this report, which information is incorporated by reference into this item.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERSAND 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 28, 2013, there were 9,139,648 of the Company’s ordinary shares, $0.01 par value, outstanding, held by approximately 462 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:

	2012			2011
Quarter	High	Low	Dividend	High	Low	Dividend
1st	$83.35	$65.20	$0.02	$86.55	$57.58	$0.02
2nd	$68.28	$17.24	$—	$93.29	$73.38	$0.02
3rd	$23.30	$15.17	$—	$92.25	$67.34	$0.02
4th	$16.37	$8.88	$—	$87.30	$67.10	$0.02

* 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 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. The quarterly dividends declared per share were $.02 per share during each of the four quarters of 2011, or $.08 for the year, and $.02 per share during the first quarter of 2012. In the second quarter of 2012, our Board of Directors suspended paying a regular quarterly dividend. 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.  

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.

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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, 2007. 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, 2012 and 2011, and for each of the three years in the period ended December 31, 2012, 2011, and 2010 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, 2010, 2009 and 2008, and for the years ended December 31, 2009 and 2008, 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,	2012			2011			2010			2009			2008
Results of Operations
Revenues	$	133,263		$	104,780		$	87,815		$	72,716		$	69,116
Equity income from Argentine investment	26,378			20,496			16,158			14,143			16,375
Net income	39,113			31,787			25,834			23,527			23,825
Amounts attributable to Apco:
Net income	39,061			31,746			25,800			23,497			23,793
Income per share	1.33			1.08			0.88			0.80			0.81
Dividends declared per share	0.02			0.08			0.08			0.08			0.35
Financial Position
Total assets	336,707			282,996			248,189			224,191			202,794
Total long-term liabilities	11,595			6,024			2,709			3,047			2,568
Total liabilities	39,731			24,358			18,731			18,354			17,999
Total equity	296,976			258,638			229,458			205,837			184,795
Market Capitalization (a)	362,422			2,405,938			1,692,871			650,651			784,020
Cash Flow
Cash provided by operating activities	42,798			42,184			39,038			28,262			29,236
Capital expenditures	(54,413		)	(35,814		)	(33,829		)	(20,516		)	(32,202		)
Cash (used) provided by all other investing activities, net	2,602			(4,324		)	—			(4,779		)	1,097
Cash dividends paid	(1,217		)	(2,381		)	(2,379		)	(4,352		)	(10,317		)
Cash (used) provided by all other financing activities, net	6,000			2,000			—			—			—

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

See “Business and Properties -- Oil and Natural Gas Production, Prices and Costs” in Item I of this report and "MD&A – Results 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 ANDRESULTS 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, 2012, we had interests in nine 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, San Jorge and Northwest basins in Argentina and in the Llanos basin in Colombia.  Although we have interests in several oil and gas properties in Argentina, our primary focus is exploitation of our properties in the Neuquén basin in which we are partners with Petrolera Entre Lomas. We complement our legacy producing assets with exploration activities in both Argentina and Colombia.

Our interests in Argentina have been the core of our business for several decades, and we continually seek out properties in Argentina's basins where we have expertise in order to grow our business.  We also believe that Colombia offers 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 past decade to be the most attractive in South America.

Net income attributable to Apco for 2012 was $39.1 million compared with $31.7 million for 2011.  Higher average sales prices were the primary contributor to increased operating revenues and greater equity income from Argentine investment compared with 2011.  Also making a contribution to higher net income was a year-over-year volume increase of three percent for our combined consolidated and equity interests. These favorable variances were partially offset by greater costs and operating expenses.

Although we have benefited from the improved commodity price environment in Argentina during 2012, the business and political environment in Argentina continues to be a significant risk to our business and results of operations.  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.  Increased governmental intervention that supports the value of the Argentine peso and foreign-exchange and capital controls present greater risks to future income levels expressed in US dollars and the timing and value of repatriations of cash from our Argentine operations.

Our capital expenditures totaled $54.4 million in 2012.  In addition to our net income mentioned above, operational highlights for 2012 include the following:

• Our first two wells drilled in Colombia resulted in exploration discoveries in the Llanos basin, with positive impacts to revenues and proved reserves for 2012;

• Exploration discoveries in the Charco del Palenque concession;

• Successful development drilling campaign in our core Neuquén basin properties;

• Increased total consolidated and equity sales volumes on a Boe basis by three percent representing the tenth consecutive year of volume growth; and

• Continued exploration efforts to produce from the Vaca Muerta shale.

Outlook for 2013

We expect our oil prices to remain at current levels of around $75 per barrel since the spread between the realized price in Argentina and the international price of oil has diminished during 2012. Exploration drilling in Colombia will continue with three wells planned for the year.  With comparable levels of exploration drilling in Colombia and Coirón Amargo, combined with expected concession extensions, we plan on increased capital expenditures compared with 2012.  Our primary objectives for 2013 are as follows:

• Conclude formal negotiations with the province of Río Negro and obtain remaining approvals for the ten-year concession extensions for our properties in Tierra del Fuego;

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

• Continue investigating the productive potential of the Vaca Muerta and Molles shales in our properties in the Neuquén basin;

• Commence exploration drilling in Sur Río Deseado Este in southern Argentina; and

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• Continue exploration drilling on Block 32 and perform testing operations on our Turpial-1 well in Colombia.

Our 2013 oil and gas capital expenditure budget for our consolidated interests is $66 million.  For further discussion about our capital budget, see "MD&A – Liquidity and Capital Resources" in Item 7 of this report.  

Overview of 2012

Business Environment in Argentina

The business environment in Argentina continues to be a significant challenge to our business.  Since the presidential election in late 2011, the government has increasingly used price controls, foreign-exchange, trade, and capital controls to manage the economic challenges faced by the country.  

During 2012, the government has issued numerous decrees to regulate investments and profits and exert its influence in private sector operations in the energy industry.  In the second quarter, executive decree 751/2012 removed all exemptions from taxes and duties previously provided to oil and gas companies operating in the province of Tierra del Fuego through Law 19,640.  As a result of this decree, our operating revenues have decreased due to the loss of our right to retain value-added tax collections associated with the sales of hydrocarbons to the continent and our operations in this province are prospectively subject to Argentine federal income taxes since the issuance of the decree in May.

Law 26,741 enacted by the Argentine congress on May 4, 2012, authorized the expropriation of YPF and declared the oil and gas industry a matter of public interest.  In July, the government issued executive decree 1277/2012, which introduces important changes to the rules governing Argentina’s oil and gas industry.  The decree repeals certain articles of deregulation decrees passed during 1989 relating to free marketability of hydrocarbons at negotiated prices, the deregulation of the oil and gas industry, freedom to import and export hydrocarbons and the ability to keep proceeds from export sales in foreign bank accounts. The repeal of these articles appears to formalize certain rules such as price controls and the repatriation of export sales proceeds which has been informally required by the government over the last several years.

In addition the decree creates a governmental strategic planning commission charged with developing investment plans for the country to increase production and reserves and to make Argentina more energy self sufficient. The decree also requires oil and gas companies, refiners and transporters of hydrocarbon products to submit annual investment plans for approval by the commission. The decree empowers the commission to issue fines and sanctions, including concession removal, for companies that do not comply with its requirements.  Finally, the commission is also charged with responsibility for assuring the reasonableness of hydrocarbon prices in the domestic market and that such prices allow companies to generate a reasonable profit margin.

Regulations to implement the decree are pending. Until such regulations are published, we cannot fully assess the impact of this decree on our operations and profitability. The text of this decree authorizes the federal government to enforce stricter controls over the oil and gas industry.  Reaction by the provincial governments and the oil and gas industry may impact the manner in which the implementing regulations are written.

These events could discourage the influx of needed capital into Argentina for oil and gas exploration and development, especially the continued exploration of Argentina’s unconventional potential.

Although we cannot predict the impact of these events on our business, we have historically reinvested most of our earnings into the exploration and development of our properties in Argentina with positive results to both oil and natural gas production and proved reserves. For further discussion see, “Quantitative and Qualitative Disclosures about Market Risk – Economic and Political Environment” in Item 7A of this report.

Neuquén Basin Properties

We and our partners used two rigs throughout 2012 to execute our development and exploration drilling campaigns in the Entre Lomas, Bajada del Palo, Charco del Palenque and Agua Amarga areas.  Total gross capital expenditures were approximately $136 million for the year, or $31 million net to our 23 percent direct working interest and $41 million attributable to our equity interest in Petrolera.  During 2012, we completed and put on production five wells that commenced drilling in 2011.  For our 2012 drilling program, 26 development wells and four exploration wells were spud during the year, 27 of those wells were completed and put on production, and three wells were in various stages of drilling or completion at the end of the year. We have a 23 percent direct working interest and an effective 29.79 percent equity interest in the wells mentioned above.

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During 2012, we continued exploration efforts to produce from the Vaca Muerta shale.  In the Bajada del Palo concession, we performed a fracture stimulation of the shale in an existing well, and we drilled another well in the western part of the concession known as Aguada del Poncho, performing a large fracture stimulation at the interface of the Quintuco and Vaca Muerta formations. The new well was put on production from the Vaca Muerta. We also completed a three-stage fracture stimulation in a well in the southern part of the Coirón Amargo block.  

Although the fracture stimulations in these three wells resulted in production from the Vaca Muerta, these wells have produced relatively modest volumes of oil and, subject to additional evaluation, we have preliminarily concluded that horizontal drilling with significantly larger fracture stimulations will be required to properly evaluate and ultimately exploit the Vaca Muerta shale as a resource play.  Companies such as Shell, EOG and YPF are currently drilling horizontal wells in the Vaca Muerta formation. Results to date are inconclusive as the exploration of the Vaca Muerta in this basin is in the early stages and its productive behavior is not well understood. The proper investigation and development of the Vaca Muerta will require both improved political and economic conditions in Argentina to attract much-needed capital and a larger presence of drilling and oil field service companies to help lower the cost of horizontal drilling and fracturing.

Of the hundreds of drilled wells in which Apco has participated since it first entered Argentina, very few wells have been completed and placed on production in Vaca Muerta. Some of these wells have, however, accumulated significant volumes of oil as a result of having encountered Vaca Muerta in areas of natural fractures. During 2013, we plan to perform a fracture of the Vaca Muerta in a well drilled in 2012 in Coirón Amargo, and drill three additional wells targeting the formation in areas where natural fracture systems may be present.

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.  Similar to the negotiations that were 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.  

Provincial elections were held in the province of Río Negro in late 2011. A new governor was elected and because of the transition to a new government during the first half of 2012, there was no progress on the extension negotiations during this period. As the year progressed, the governor proposed a new framework for negotiations of the ten-year extensions with oil and gas producers in the province. The proposed framework was approved by the provincial congress at the end of 2012. Extension negotiations are expected to resume in the first half of 2013, and we expect to obtain all required approvals during 2013.

In the third quarter of 2012, we and our partners in Tierra del Fuego signed agreements with the provincial government to approve the ten-year extensions. One agreement extends the concession term for the Las Violetas concession. A second agreement extends the concession terms for the Río Cullen and Angostura concessions. The ten year extensions for all three concessions run through August 17, 2026.  Nearly eight months have passed since the executed agreement was submitted to the legislature for approval. This time period is longer than expected and as a result we can provide no assurance that the agreement will receive the required approval.

Colombian Properties

As previously highlighted, our first two wells drilled in Colombia resulted in exploration discoveries in the Llanos basin, with positive impacts to revenues and proved reserves during 2012. The Maniceño No. 1 well drilled in the Llanos 32 block discovered light oil from the Mirador formation and was put on production in July.  As of year-end, the well had produced approximately 429 thousand gross barrels, or 78.9 thousand net, and was producing 1,350 gross barrels of oil per day after six months of production. A second exploration well, the Samaria Norte No. 1, successfully tested 12.1 degree API gravity oil and

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is waiting on approval to be put on production from the Guadalupe formation. Apco has a 20 percent working interest in the Llanos 32 block.

In the fourth quarter of 2012 we drilled the committed exploration well on the Turpial block. Prior to spudding the Turpial-1 well, our partner decided to commence the relinquishment of its interest in the block but agreed to pay its 50 percent share of costs to total depth.  Initial log interpretations were favorable and Apco continued under sole risk provisions to case and cement the well for testing.  At the end of 2012, Apco entered another one-year exploration phase by committing to drill an additional well, and has made plans to test the Turpial-1 well. Apco has applied to become operator of the block and currently holds a 100 percent working interest pending government approval of the transfer of our partner's interest to us.

In the Llanos 40 block where Apco has a 50 percent interest, we acquired 3D seismic data early in the first half of the year and interpretation of the data is underway.  We have committed to drill four exploration wells in the area by the end of 2014, and we expect to begin building locations on the first two prospects during 2013.

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 international product prices may have on our capital programs, production volumes, or future revenues.

In Argentina, politically driven mechanisms significantly influence the sales 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 prices significantly below international market levels. In Colombia, oil price realizations are based on international reference prices (such as WTI or Brent) less transportation costs to deliver the crude to market.

In response to those governmental actions, Argentine producers and refiners had to negotiate domestic oil 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 did not benefit 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 2012 have enabled producers to negotiate higher oil 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 price per barrel for our consolidated interests averaged $74.90 for 2012 compared with $62.21 for 2011 and $52.22 in 2010. Because our production from our Colombian properties accounted for only five percent of our consolidated oil volumes sold in 2012, the impact of higher price realizations in Colombia was not material for 2012.

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 recognized approximately $1.1 million net to our consolidated interests related to hydrocarbon subsidy programs (see "–Results of Operations – Other Operating Revenues" below), and approximately $1.7 million net to our equity interest (see "–Results of Operations – 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 and temporarily ceased paying subsidies to producers.  Consequently, we did not realize any benefit from this program in 2012. Despite the government's stated intention to suspend benefits under these programs, they have allowed companies producing relatively smaller amounts of production to apply for subsidies. In February 2013, the government allowed a related-party of ours to

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utilize approximately $2.1 million of tax certificates that had originally been granted to Apco. We continue to apply for additional subsidies under this program, but we cannot predict if either Apco or Petrolera will be able to recognize any further benefits from this program.

We cannot accurately predict how world oil prices will evolve in 2013 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.

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.

The Argentine government regulates the supply of natural gas and provides a framework for natural gas prices in the domestic market through Resolution 599/2007 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. In December 2011, the Acuerdo 2007-2011 was extended until the Secretary of Energy issues another resolution to regulate natural gas markets in Argentina.

Through the "Gas Plus" program, the government has created a mechanism for producers to obtain government approval to negotiate higher prices with industrial customers if the producer has explored and found new reserves. We receive some benefits related to this program. Our average natural gas sale price per Mcf averaged $2.56 in 2012, $2.10 in 2011, and $1.90 during 2010.  

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 2013 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.

In order to reverse the trend of declining reserves, in February 2013, the government issued resolution 1/2013 which creates a new incentive mechanism to realize higher natural gas prices. The decree creates a program called the "Programa de Estímulo a la Inyección Excedente de Gas Natural" which is intended to provide incentives for exploration drilling for certain projects. Our preliminary understanding of the resolution is that it allows each natural gas producer to negotiate a base decline curve for its existing deliveries and to commit investments and production deliveries above that curve. The resulting incremental deliveries are eligible for a price differential payment from the government to effectively raise a company's realized price up to $7.50 per Mmbtu during a five year period. Additionally, failure to meet committed deliveries would result in significant penalties. Companies have a very limited window to participate in this new program because the new investment projects must be presented for approval by June 30, 2013. We are evaluating if Apco will be able to benefit from this program in the future.

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 2012, natural gas sales represented 12 percent of our total operating revenues compared with 13 percent in 2011 and 14 percent in 2010.  Consequently, the fluctuation in natural gas sales between summer and winter is not significant to us.

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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.

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 2012, 2011 and 2010 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 long-lived assets. We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that the carrying value of an asset (or asset group) may not be recoverable. Our assessments use judgments and assumptions that include the undiscounted future cash flows, discounted future cash flows, estimated fair values, and the current and future economic environment in which the asset is operated. Typical indicators of a possible impairment include declining oil and gas prices, unfavorable revisions to our reserve estimates, drilling results, or future drilling plans.

In our review of unproved properties as of December 31, 2012, we determined that a portion of an exploratory well that had been drilled but is pending the determination of proved reserves was impaired due to substantial doubt about the economic viability of a particular formation of interest in the well. Only a portion of the well was impaired because we concluded that sufficient progress is being made to assess the reserves from higher formations in the well. As a result, we recognized approximately $830 thousand of impairment charges in the fourth quarter of 2012. Depending upon the results of certain future exploration activities, we could determine that additional unproved properties need to be impaired as we drill and evaluate those areas.  For example, we have $2.6 million of unproved-property-acquisition cost related to our operations in Colombia and $4.6 million in exploratory wells pending the determination of proved reserves.  If our exploration activity planned for 2013 is unsuccessful, we may have to recognize an impairment loss related to these assets.

In addition to the unproved properties described above for which an impairment charge was recorded, one of our proved properties was reviewed for which no impairment was required. This review assessed impairment using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of reserves quantities, estimates of future commodity prices, contractual rights, drilling plans and expected capital costs. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements. For the property for which impairment charges were not recorded, we estimate that approximately $8.0 million could be at risk for future impairments if we do not make sufficient economic discoveries to justify the conversion of an exploration area into a concession and are forced to relinquish a portion of our property.

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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,
	2012		$ Change from 2011		% Change from 2011		2011		$ Change from 2010		% Change from 2010		2010
	(Amounts in Thousands)
Operating revenues	$	133,263	28,483		27	%	$	104,780	16,965		19	%	$	87,815
Total costs and operating expenses	107,192		(23,636	)	-28	%	83,556		(14,675	)	-21	%	68,881
Operating income	26,071		4,847		23	%	21,224		2,290		12	%	18,934
Investment income	26,108		5,482		27	%	20,626		4,032		24	%	16,594
Income taxes	13,066		(3,003	)	-30	%	10,063		(369	)	-4	%	9,694
Net Income	39,113						31,787						25,834
Less: Net income attributable to
noncontrolling interests	52		(11	)	-27	%	41		(7	)	-21	%	34
Net income attributable to Apco	$	39,061	7,315		23	%	$	31,746	5,946		23	%	$	25,800

Net Income

2012 vs. 2011Our Net income attributable to Apco for 2012 was $39.1 million, an increase of $7.3 million compared with 2011.  Net income attributable to Apco increased compared with 2011 primarily due to the favorable effects of higher sales prices and greater sales volumes on a barrel of equivalent basis, and greater equity income from Argentine investment.  These benefits were partially offset by higher production and lifting costs, increased exploration expenses, greater taxes other than income, and higher depreciation expense compared with 2011.

2011 vs. 2010Our 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.

Total Operating Revenues

Operating revenues for 2012 increased by $28.5 million, or 27 percent, compared with 2011.  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 2010 to 2012 for our consolidated interests accounted for as operating revenues are shown in the following tables. 

	Year Ended December 31,
	2012		% Change		2011		% Change		2010
Sales Volumes
Consolidated interests
Oil (Bbls)	1,515,361		11	%	1,359,163		2	%	1,338,195
Natural Gas (Mcf)	6,037,501		-4	%	6,301,114		0	%	6,306,883
LPG (tons)	10,920		-2	%	11,108		12	%	9,893
Oil, Natural Gas and LPG (Boe)	2,649,757		4	%	2,539,701		1	%	2,505,438
Average Sales Prices
Consolidated interests
Oil (per Bbl)	$	74.90	20	%	$	62.21	19	%	$	52.22
Natural Gas (per Mcf)	2.56		22	%	2.10		11	%	1.90
LPG (per ton)	254.76		-19	%	314.46		-9	%	346.61
Revenues ($ in thousands)
Oil revenues	$	113,498	34	%	$	84,553	21	%	$	69,882
Natural Gas revenues	15,447		17	%	13,257		10	%	12,000
LPG revenues	2,782		-20	%	3,493		2	%	3,429
	$	131,727	30	%	$	101,303	19	%	$	85,311

The volume and price changes in the table above caused the following changes to our oil, natural gas and LPG revenues from 2010 to 2012.

	Oil		Gas			LPG			Total
	(Amounts in Thousands)
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
Changes due to volumes	11,699		(674		)	(48		)	10,977
Changes due to prices	17,246		2,864			(663		)	19,447
2012 Sales	$	113,498	$	15,447		$	2,782		$	131,727

Oil Revenues

2012 vs. 2011During 2011, Oil revenues increased by $28.9 million, or 34 percent, compared with 2011, due to higher average oil sales prices combined with an 11 percent increase in oil sales volumes.  For further explanation of oil sales prices, see “MD&A – Oil and Natural Gas Marketing – Oil Prices” in Item 7 of this report. The increase in oil sales volumes is a result of initial production from our properties in Colombia and higher volumes from our Neuquén basin properties.

2011 vs. 2010During 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.  

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Natural Gas Revenues

2012 vs. 2011  Natural gas revenues increased by $2.2 million, or 17 percent compared with 2011.  The increase is due to higher sales prices, partially offset by lower sales volumes. 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.

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.

Other Operating Revenues

2012 vs. 2011  Other operating revenues decreased by $1.9 million during 2012 compared with 2011.  The decrease is related primarily to the Argentine government's removal of certain tax benefits related to the island of Tierra del Fuego. Prior to May 16, 2012, oil, natural gas, and LPG produced on the island of Tierra del Fuego and sold domestically to continental Argentina was exempt from the requirement to remit the value-added tax collected from buyers as part of the island’s tax-exemption rules.  This mechanism effectively increased our realized prices by 21 percent for sales made to the continent. The government removed this exemption during 2012 and we therefore will no longer realize this benefit. In addition, we did not recognize any benefits in 2012 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.

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.

Total Costs and Operating Expenses

2012 vs. 2011Total costs and operating expenses increased by $23.6 million, or 28 percent, primarily due to the following items:

• Production and lifting costs increased by $5.6 million, or 22 percent, due to the growth of our operations in the Neuquén basin and the impact of inflation on operation and maintenance expenses, and the commencement of production from our Colombian properties in the second half of 2012;

• Transportation and storage increased by $1.4 million primarily due to trucking expense to deliver our oil production to market in Colombia;

• Selling and administrative expense increased by $2.9 million due to increased staffing, the effect of inflation on salary and related benefits expense and other administrative costs in our Argentine branch, greater costs from our operators in Argentina, and higher corporate administrative expenses;

• Depreciation, depletion and amortization expense increased by $6.2 million primarily due to higher depreciation rates and the impact of production from Colombia (see additional discussion below); and

• Exploration expense increased by $8.0 million primarily due to greater exploration activity including 3D seismic acquisition costs in the Llanos 40 block in Colombia and in the Sur Río Deseado Este concession in Argentina and for impairment charges related to exploration drilling;

• Foreign exchange loss (gains) increased by $209 thousand compared with 2011. During 2012, a loss of $798 thousand from our Argentine operations was offset by a gain of $498 thousand from our Colombian operations. In future periods, we expect to experience greater foreign exchange losses as a result of an expected increase in net monetary assets denominated in Argentine pesos combined with a devaluation of the Argentine peso; and

• Partially offsetting the increased expenses mentioned above was a $3.2 million decrease in Other expense primarily due to a gain from a farm-out agreement in the Sur Río Deseado Este concession realized in the second quarter of 2012.

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

• Production and lifting costs increased 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 3D seismic information.

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 2010 to 2012 are shown in the following table:

	Year Ended December 31,
	2012		Change from 2011		% Change from 2011		2011		Change from 2010		% Change from 2010		2010
Consolidated Sales Volumes (Boe)	2,649,757		110,057		5	%	2,539,701		34,264		1	%	2,505,438
DD&A Rate per Boe	$	10.10	$	1.97	25	%	$	8.13	$	1.42	21	%	$	6.71
DD&A Expense (In thousands)	$	26,760	$	6,116	30	%	$	20,644	$	3,820	23	%	$	16,824

The following table details the increases in DD&A of oil and gas properties between 2010 to 2012 due to the changes in volumes and average DD&A rates presented in the table above:

	(Thousands)
2010 DD&A	$	16,824
Changes due to volumes	278
Changes due to rates	3,541
2011 DD&A	20,644
Changes due to volumes	1,111
Changes due to rates	5,005
2012 DD&A	$	26,760

2012 vs. 2011Total DD&A (including straight-line) increased by $6.2 million in 2012 compared with 2011 primarily due to increased DD&A rates and greater volumes.  Our DD&A rate increased because in the Río Negro province, where our largest producing field with the largest proved reserves is located, we have been adding less proved reserves per well drilled for calculating DD&A with each year that passes without obtaining the remaining ten-year extension as our proved reserves are limited to the current concession life.  Furthermore, as we develop our most mature fields, proved reserves added per well decrease over time. Additionally, our weighted average DD&A rate increased in 2012 due to a greater proportion of sales volumes on a barrel of oil equivalent basis from properties with DD&A rates that are higher than the weighted average rate experienced in 2011.

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We are working to obtain the ten-year concession extension for our properties in Río Negro, and are waiting on legislative approval for our extensions in Tierra del Fuego.  We expect to experience a favorable effect on future DD&A rates if the extensions are obtained, as wells whose productive lives extend beyond 2016 will result in the addition of proved developed reserves.

Investment Income

2012 vs. 2011  Total investment income increased by $5.5 million compared with 2011 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.

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 of this report).

Income Taxes

2012 vs. 2011  Income taxes increased by $3.0 million compared with 2011 due to higher operating income in Argentina.  See Note 10 – Income Taxes to our consolidated financial statements in Item 8 of this report for further discussion of income taxes.

2011 vs. 2010Although 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.  

LIQUIDITY AND CAPITAL RESOURCES

Outlook

Our cash flow from operations is highly sensitive to fluctuations in our oil price realizations. Oil price realizations in Argentina have increased gradually since 2009 from approximately $40 per barrel. Since the beginning of 2012, oil prices have stabilized and averaged approximately $75 per barrel for the year. We derive more than 80 percent of our total revenues from the sale of oil. Since the international price of oil has decreased significantly during 2012 and the spread between the price being realized in Argentina and the international price of oil has diminished considerably, we expect our oil prices to remain at current levels or trend downward. Oil price realizations in Argentina continue to be negotiated on a short-term basis.

Dividends received from our equity investee, Petrolera, are a significant contributor to our cash flow generated by operating activities and Petrolera’s cash flows from operations and its ability to pay dividends are also highly sensitive to fluctuations in oil price realizations.  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, debt and interest payments, and the Argentine government’s foreign exchange control policies.

Inflation in Argentina has been a persistent problem for some time.  In contrast, the Argentine peso has not experienced a commensurate level of devaluation resulting in considerable increases in our U.S. dollar cost of operations and capital expenditures.  Consequently, there is no assurance that operating income generated in Argentina will remain at current levels given that oil prices in Argentina have stabilized during the year, inflation continues at robust levels and the peso has not been allowed to adjust to market conditions.

Since the fourth quarter of 2011, the Argentine government has implemented various regulations restricting access to foreign exchange markets, or the purchase of foreign currency through the Central Bank of Argentina at the official rate of exchange for the purpose of depositing funds in foreign accounts. These restrictions require both Central Bank and AFIP (“Argentina’s Taxing Authority”) approvals that are not currently being given. As a result, the current movement of funds out of

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Argentina through the Central Bank at the official exchange rate has been obstructed. However, the purchase of foreign currency for the repayment of debt is not limited. Under current regulatory conditions, it is possible that future dividends paid by Petrolera could be paid in pesos in Argentina. For a more detailed explanation see “Quantitative and Qualitative Disclosures about Market Risks – Inflation, Foreign Currency and Operations Risk” in Item 7A of this report.

We will continue to monitor our capital programs as necessary to provide Apco 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 2013

Our 2013 capital plan provides for $66 million of capital expenditures net to our direct working interests.  We plan to participate in the drilling of 48 gross wells in 2013.  In addition, we plan on spending approximately $2 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 2013 is $109 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 2013.  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 2013 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. Additionally, in the third quarter of 2012 we began producing oil from our operations in Colombia, creating a source of cash flow outside of Argentina. Although we generally fund our capital programs with internally generated cash flow, successful exploration efforts in Argentina or Colombia could lead to development-capital needs that are currently beyond our ability to fund from operations.

As a result of the current exchange control restrictions that have obstructed the ability to move funds out of Argentina at the official rate of exchange, Apco and Petrolera have increased capital spending in Argentina to the extent possible and Petrolera has accelerated repayments of its loans denominated in foreign currency (US dollars). Consequently, we received fewer dividends from our investment in Petrolera during 2012 compared with 2011. We continue to operate our business under the assumption that the receipt of dividends abroad from our investment in Petrolera will contribute to the funding of our operations outside of Argentina. However, because of the current regulatory environment, the receipt of dividends abroad from our investment in Petrolera may not be a reliable source of funding for our operations outside of Argentina in the near term, and consequently we may need other sources of funding, including drawing down our existing cash reserves, to meet our plans and exploration commitments outside of Argentina.

With a cash and cash equivalents balance at December 31, 2012, of $32.7 million, or 10 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 2013.  

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, 2012, a total of $8.9 million was considered restricted and included in restricted cash.  We expect our restricted cash to be reduced by $3.7 million in the first half of 2013 due to fulfilling certain exploration commitments. The restricted cash is invested in a short-term money market account with a financial institution.

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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,
	2012			2011			2010
	(Thousands)
Net cash provided (used) by:
Operating activities	$	42,798		$	42,184		$	39,038
Investing activities	(51,811		)	(40,138		)	(33,829		)
Financing activities	4,783			(381		)	(2,379		)
(Decrease) increase in cash and cash equivalents	$	(4,230	)	$	1,665		$	2,830

Operating Activities

Our net cash provided by operating activities in 2012 increased by $614 thousand compared with 2011 due to higher operating income which was offset by lower dividends from our equity investment in Petrolera.

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

Included in our net cash provided by operating activities are dividends received from our equity investment in Petrolera of $7.8 million in 2012, $12.8 million in 2011 and $14.1 million in 2010. See additional discussion of dividends from our Argentine investment in “Liquidity and Capital Resources” above.

Investing Activities

During 2012, capital expenditures totaled $54.4 million, most of which was invested in drilling in our Neuquén basin properties including Coirón Amargo, and exploration drilling in Colombia. Additionally, our cash used as collateral for letters of credit changed by $555 thousand. We also received $3.1 million during the second quarter of 2012 from the execution of a farm-out agreement related to our exploration acreage in the Sur Río Deseado Este concession.

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.

Financing Activities

We received $6.0 million during 2012 and $2.0 million in 2011 in borrowings from an unsecured bank line of credit to fund capital expenditures.  In addition, we paid $1.2 million of dividends to our shareholders in 2012, $2.4 million in 2011, and $2.4 million in 2010.

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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
	2013		2014		2015		Thereafter		Total
	(Amounts in Thousands)
Long-term debt
Principal	$	500	$	2,500	$	3,500	$	1,500	$	8,000
Interest	299		254		119		13		685
International oil and gas activities	21,553		13,500		—		—		35,053
Other long-term liabilities	—		—		—		4,095		4,095
Total	$	22,352	$	16,254	$	3,619	$	5,608	$	47,833

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 13 – Long-term Liabilities to our consolidated financial statements 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 14 – Contingencies and Commitments to our consolidated financial statements 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. Oil sales 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 price realizations 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.

Furthermore, although our oil prices in Argentina are negotiated and denominated in US dollars, we are paid in pesos.  This could make our oil price realizations sensitive to currency devaluation depending on the manner in which any possible devaluation is implemented by the government.

Inflation, Foreign Currency and Operations Risk

The majority of our operations are located in Argentina.  Historically Argentina has struggled through extended periods of inflation that have eventually led to a sudden devaluation of the Argentine peso similar to what occurred during the Argentine economic crisis of 2001 and 2002.

Since the economic crisis of 2001 and 2002, when the value of the peso was suddenly reduced from an exchange rate of one peso to one US dollar to an exchange rate of three pesos to one US dollar, the Argentine economy has generally grown at strong rates ranging from two to ten percent annually. However, actual inflation escalated during this same period at rates ranging from 15 to 30 percent annually over the last several years. As a result of government efforts to support the value of the peso in this environment, the peso’s value has not declined in proportion to the level of actual inflation thereby substantially increasing the cost of living in Argentina and the US dollar cost of our operations and capital expenditures in the country. Because the peso has not been permitted to devalue in proportion to the actual inflation experienced in the country, there has been, in the recent past, capital flight out of Argentina due to a lack of confidence in the value of the peso at the official exchange rate.

In October of 2011 and July of 2012, the government implemented regulations restricting access to foreign exchange markets, including the purchase of foreign currency (US dollars) through the Central Bank of Argentina at the official rate of exchange. These regulations were augmented by formal and informal restrictions including approvals from both the Central Bank and AFIP which are not currently being given.  As a result, movement of funds out of Argentina through the Central Bank at the official exchange rate has been obstructed. The purchase of foreign currency for transactions such as the repayment of debt is not limited. Companies that are generating free cash flow find themselves accumulating local currency in Argentina.

An alternative way for companies to send money out of Argentina exists and consists of purchasing marketable securities in Argentina with pesos and selling them abroad in foreign currency. As of December 31, 2012, the implicit exchange rate derived from this type of transaction was approximatly 39 percent above the official exchange rate. The resulting spread between such implicit exchange rate and the official rate of exchange could be an indicator that an official devaluation of the Argentine peso may be required at some point. A devaluation of the Argentine peso could result in foreign exchange losses to the extent of net monetary assets held by us in Argentine pesos that are translated on the balance sheet at the closing exchange rate.  A devaluation could also lower our product price realizations and reduce our peso-denominated costs.

At December 31, 2011, the peso to US dollar official rate of exchange rate was 4.30:1.  At December 31, 2012, the official exchange rate was 4.92:1 and our net monetary assets denominated in Argentine pesos was $6 million.  Additionally, Petrolera had a balance of net monetary assets denominated in pesos of approximately $7.6 million as of December 31, 2012.

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

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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; (ii) the timing of repatriations of cash to the Cayman Islands; (iii) our asset valuations; (iv) the dollar value of peso-denominated monetary assets and liabilities; and (v) restrictions on imports of materials necessary for our operations.

In October 2011, President Cristina Kirchner was re-elected for 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. Additionally, the government has taken various measures to assert greater state control over different areas of the country’s economy, including nationalizing an airline and private pension funds.

Since the presidential election in late 2011, the government has increasingly used foreign-exchange, trade, price and capital controls to manage the economic challenges faced by the country.  During 2012, the government has issued numerous decrees to regulate investments and profits and exert its influence in private sector operations in the energy industry, including the expropriation of 51 percent of the shares of YPF from Repsol. These actions have created an unpredictable political and business environment in the country.

The stated objective of the Argentine government is to increase both conventional and unconventional oil and natural gas production in Argentina through increased investments by YPF, now majority owned by the Argentine government. YPF has announced an aggressive multi-year investment plan designed to achieve that objective and various potential joint venture partnerships to help fund this program.  As a result of these actions and events, and in spite of the YPF announcement, the share price of YPF and many other public companies with oil and gas interests in Argentina have fallen off precipitously, as have the shares of Apco.

Although we cannot predict the impact of these events on our business, we have historically reinvested most of our earnings into the exploration and development of our properties in Argentina with positive results to both oil and natural gas production and proved reserves.

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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	47
Report of Independent Registered Public Accounting Firm	48
Report of Independent Registered Public Accounting Firm	49
Report of Independent Registered Public Accounting Firm	50
Consolidated Balance Sheets at December 31, 2012 and 2011	51
Consolidated Statements of Income and Comprehensive Income for each year in the three-year period ended December 31, 2012	52
Consolidated Statements of Changes in Equity for each year in the three-year period ended December 31, 2012	53
Consolidated Statements of Cash Flows for each year in the three-year period ended December 31, 2012	54
Notes to Consolidated Financial Statements	55

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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 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, 2012, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2012, our internal control over financial reporting was 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

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, 2012, 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.

In our opinion, Apco Oil and Gas International Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

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, 2012 and 2011, and the related consolidated statements of income and comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2012, of Apco Oil and Gas International Inc. and our report dated March 7, 2013, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma

March 7, 2013

48

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, 2012 and 2011, and the related consolidated statements of income and comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2012. 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 $31.6 million and $31.0 million as of December 31, 2012 and 2011, respectively, and total revenues of $15.0 million, $14.2 million, and $14.2 million, for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2013, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma

March 7, 2013

49

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, 2012 and 2011, and the related statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the results of its operations and its cash flows for each of the three years period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

Buenos Aires City, Argentina

February 28, 2013

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

Diego O. DeVivo

Partner

50

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2012			2011
	(Amounts in Thousands Except Share Amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	32,669		$	36,899
Accounts receivable	19,208			11,145
Inventory	4,074			2,908
Restricted cash	3,749			—
Other current assets	4,877			3,900
Total current assets	64,577			54,852
Property and Equipment:
Cost, successful efforts method of accounting	313,323			256,886
Accumulated depreciation, depletion and amortization	(157,907		)	(131,021		)
	155,416			125,865
Argentine investment, equity method	108,710			90,208
Deferred income tax asset	1,254			1,472
Restricted cash	5,170			8,364
Other assets (net of allowance of $486 at December 31, 2012 and $554 at December 31, 2011)	1,580			2,235
Total Assets	$	336,707		$	282,996
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	13,983		$	9,103
Affiliate payables	1,764			1,270
Accrued liabilities	7,742			4,845
Income taxes payable	4,647			2,527
Dividends payable	—			589
Total current liabilities	28,136			18,334
Long-term debt	7,500			2,000
Long-term liabilities	4,095			4,024
Contingent liabilities and commitments (Note 14)
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	91			91
Class A shares, 20,301,592 shares issued and outstanding	203			203
Additional paid-in capital	9,106			9,106
Accumulated other comprehensive loss	(1,597		)	(1,450		)
Retained earnings	288,931			250,459
Total shareholders' equity	296,734			258,409
Noncontrolling interests in consolidated subsidiaries	242			229
Total equity	296,976			258,638
Total liabilities and equity	$	336,707		$	282,996

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

51

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	For the Years Ended December 31,
	2012			2011			2010
	(Amounts in Thousands Except Per Share Amounts)
REVENUES:
Oil revenues (Note 7)	$	113,498		$	84,553		$	69,882
Natural gas revenues (Note 7)	15,447			13,257			12,000
LPG revenues	2,782			3,493			3,429
Other	1,536			3,477			2,504
Total operating revenues	133,263			104,780			87,815
COSTS AND OPERATING EXPENSES:
Production and lifting costs	31,020			25,432			19,327
Taxes other than income	23,379			20,913			14,543
Transportation and storage	2,268			888			727
Selling and administrative (Note 7)	13,846			10,907			9,501
Depreciation, depletion and amortization	26,904			20,703			16,887
Exploration expense	11,152			3,103			6,102
Foreign exchange losses (gains)	300			91			(121		)
Other expense	(1,677		)	1,519			1,915
Total costs and operating expenses	107,192			83,556			68,881
TOTAL OPERATING INCOME	26,071			21,224			18,934
INVESTMENT INCOME
Interest and other income	(270		)	130			436
Equity income from Argentine investment	26,378			20,496			16,158
Total investment income	26,108			20,626			16,594
Income before income taxes	52,179			41,850			35,528
Income taxes	13,066			10,063			9,694
NET INCOME	39,113			31,787			25,834
Less: Net income attributable to noncontrolling interests	52			41			34
Net Income attributable to Apco Oil and Gas International Inc.	$	39,061		$	31,746		$	25,800
OTHER COMPREHENSIVE INCOME:
Pension plan liability adjustment in consolidated and equity interests (net of Argentine taxes of $80 in 2012, $122 in 2011, and $90 in 2010)	(147		)	(226		)	166
Comprehensive income attributable to Apco Oil and Gas International Inc.	$	38,914		$	31,520		$	25,966
Amounts attributable to Apco Oil and Gas International Inc.:
Earnings per share – basic and diluted:
NET INCOME PER SHARE	$	1.33		$	1.08		$	0.88
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.

52

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, 2010   (1)	$	294		$	—	$	9,106	$	(1,390	)	$	197,623		$	205,633		$	204		$	205,837
Comprehensive Income:
Net Income	—					—		—			25,800			25,800			34			25,834
Other Comprehensive income (loss)	—			—		—		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
Other Comprehensive income (loss)	—			—		—		(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
Comprehensive Income:
Net Income	—					—		—			39,061			39,061			52			39,113
Other Comprehensive income (loss)	—			—		—		(147		)	—			(147		)	—			(147		)
Total Comprehensive Income																				38,966
Dividends declared ($0.02 per share)	—			—		—		—			(589		)	(589		)	(39		)	(628		)
BALANCE, December 31, 2012  (1)	$	91		$	203	$	9,106	$	(1,597	)	$	288,931		$	296,734		$	242		$	296,976

(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.

53

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in Thousands)	For the Years Ended December 31,
	2012			2011			2010
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	39,113		$	31,787		$	25,834
Adjustments to reconcile to net cash provided by operating activities:
Equity income from Argentine investment	(26,378		)	(20,496		)	(16,158		)
Dividends received from Argentine investment	7,794			12,813			14,077
Deferred income tax (benefit)	(1		)	(288		)	(158		)
Depreciation, depletion and amortization	26,904			20,703			16,887
Provision for loss on property, plant & equipment	2,787			—			—
Changes in accounts receivable	(8,063		)	611			(1,773		)
Changes in inventory	(1,184		)	(608		)	147
Changes in other current assets	(977		)	(1,075		)	50
Changes in accounts payable	791			(2,593		)	933
Changes in affiliate payables	494			973			(1		)
Changes in accrued liabilities	1,397			1,435			(437		)
Changes in income taxes payable	2,120			(721		)	(476		)
Gain on sale properties	(2,809		)	—			—
Other, including changes in noncurrent assets and liabilities	810			(357		)	113
Net cash provided by operating activities	42,798			42,184			39,038
CASH FLOW FROM INVESTING ACTIVITIES:
Property plant and equipment:
Capital expenditures *	(54,413		)	(35,814		)	(33,829		)
Sale of properties	3,087			—			—
Changes in long-term investments	70			40			—
Changes in restricted cash	(555		)	(4,364		)	—
Net cash used in investing activities	(51,811		)	(40,138		)	(33,829		)
CASH FLOW FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	6,000			2,000			—
Dividends paid to noncontrolling interest	(39		)	(26		)	(24		)
Dividends paid	(1,178		)	(2,355		)	(2,355		)
Net cash used in financing activities	4,783			(381		)	(2,379		)
Increase (decrease) in cash and cash equivalents	(4,230		)	1,665			2,830
Cash and cash equivalents at beginning of period	36,899			35,234			32,404
Cash and cash equivalents at end of period	$	32,669		$	36,899		$	35,234
Supplemental disclosures of cash flow information:
Interest paid	$	193		$	—		$	—
Cash paid during the year for income taxes	$	10,195		$	10,601		$	6,184
________________________
*  Increases to property plant and equipment, net of asset dispositions	$	(56,437	)	$	(39,995	)	$	(33,948	)
Provision for loss on PP&E	(2,787		)	—			—
Recovery of unproved costs	(278		)	—			—
Changes in related accounts payable and accrued liabilities	5,089			4,181			119
Capital expenditures	$	(54,413	)	$	(35,814	)	$	(33,829	)

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

54

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., a Cayman Islands exempted limited company (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, 2012, the Company had interests in nine 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, San Jorge and Northwest basins in Argentina and in the Llanos basin in Colombia.  The Company also has exploration activities currently ongoing in both Argentina and Colombia. 

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 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.

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of Apco 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.  In the Neuquén basin we also participate in the Coirón Amargo block in which we hold a 45 percent interest. We sometimes refer to these areas in a group as our “Neuquén basin properties.”

55

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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 our 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

Our only business is oil and natural gas exploration and production in South America. As a result, management views our business and operations to be one segment. Our one segment presentation is reflective of the consolidated-level focus by our chief operating decision-maker. We have presented geographic information related to our revenues and long-lived assets as presented below:

	Revenues (a)						Long-lived Assets
(amounts in millions)	For the period ended December 31,						As of December 31,
	2012		2011		2010		2012		2011
Argentina	$	126.3	$	104.8	$	87.8	$	143.0	$	122.9
Colombia	7.0		—		—		12.4		2.9
Total	$	133.3	$	104.8	$	87.8	$	155.4	$	125.8

(a) Revenues are attributed to countries based on the location of the customer

Revenue Recognition

We recognize 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. We have not had any 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 and Comprehensive Income. We did not realize any benefit from these certificates until 2011.  During 2011, we recognized approximately $1.1 million net to our consolidated interests and approximately $1.7 million net to our equity interest.  In February 2012, the Argentine government stated its intention to suspend benefits under its hydrocarbon subsidy programs and temporarily ceased paying subsidies to producers.  Consequently, we did not realize any benefit from this program in 2012.

56

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Value-Added Tax Collections – Tierra del Fuego

The majority of our Other operating revenues ($933 thousand in 2012, $2.0 million in 2011, and $2.4 million in 2010) relates to value-added tax collections related to hydrocarbon sales revenues from our operations in Tierra del Fuego.  Prior to May 16, 2012, oil, natural gas, and LPG produced on the island of Tierra del Fuego and sold domestically to continental Argentina was exempt from the requirement to remit the value-added tax collected from buyers as part of the island’s tax exemption rules.  This mechanism effectively increased our realized prices by 21 percent for sales made to the continent. The government removed this exemption during 2012 and we will no longer realize this benefit.

Cash and Cash Equivalents

We consider 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, 2012, we have $8.9 million of restricted cash which is collateral for letters of credit related to exploration blocks in Colombia.  The letters of credit expire on various dates of 2013, 2014 and 2015.  As of December 31, 2011, a total of $8.4 million was used as collateral for letters of credit and was considered restricted and included in noncurrent restricted cash.

Inventory Valuation

Our inventory includes hydrocarbons of $1.1 million in 2012 and $1.1 million in 2011, which are accounted for at production cost, and spare-parts materials of $3.0 million in 2012 and $1.8 million in 2011, which are accounted for at the lower of cost or market.

Property and Equipment

We use 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. We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that the carrying value of an asset (or asset group) may not be recoverable. An asset group is the unit of accounting for a long-lived asset or assets to be held and used, which represents the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities. Typical indicators of a possible impairment include declining oil and gas prices, unfavorable revisions to our reserve estimates, drilling results, or future drilling plans. 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, we use what we believe are market participation assumptions, including an oil and natural gas price forecast that we believe to be reasonable given the pricing environment where we do business. Due to the volatility of oil and gas prices, it is possible that our 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.  As of December 31, 2012, we have $2.6 million of unproved property acquisition cost related to our operations in Colombia and $4.6 million in exploratory wells in progress pending the determination of proved reserves. If our exploration activity planned for 2013 is unsuccessful, we may have to recognize an impairment loss related to these assets.

We record 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.

57

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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 our Consolidated Balance Sheets will take into consideration future estimates of inflation and present value factors based on our 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.

Net Income per Share

Net income per share is calculated by dividing net income attributable to Apco's 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

We account for nonmonetary transactions based on the fair values of the assets involved, which is the same basis as that used in monetary transactions.  During 2012 and 2011, we delivered a volume of our oil and natural gas production to third parties to satisfy a portion of our provincial production tax obligation.  The crude oil inventory and natural gas that was transferred to satisfy these obligations were recognized at fair value.  We recorded approximately $1.9 million in operating revenues and taxes other than income as a result of these transactions in 2012 and $3.0 million in 2011 (none in 2010).

Foreign Exchange

The policy followed in the translation of our 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.  We have accrued liabilities of approximately $953 thousand and $563 thousand for these undiscounted estimated costs at December 31, 2012 and December 31, 2011 respectively.

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

We are 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

58

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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.

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.

(2) Investment in Argentine Oil and Gas Company

As described in Note 1, we use the equity method to account for our 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, our share of net income (loss) from Petrolera is reflected as an increase (decrease) in our investment accounts and is also recorded as equity income (loss) from Argentine investment.  Dividends from Petrolera are recorded as reductions of our investment. At December 31, 2012, cumulative undistributed earnings of Petrolera were $215.5 million.

The carrying amount of our investment in Petrolera is greater than our 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 us; (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 we accounted for our interest in Petrolera under the cost recovery method, which will be recognized upon full recovery of our investment.

Petrolera’s financial position at December 31, 2012 and 2011 is as follows.  Amounts are stated in thousands:

	December 31, 2012		December 31, 2011
	(in thousands)
Current assets	$	84,435	$	65,697
Non current assets	282,497		253,972
Current liabilities	72,164		53,549
Non current liabilities	30,105		46,797

Included in Petrolera’s current assets as of December 31, 2012, is approximately $34.0 million of cash denominated in Argentine pesos.

Petrolera’s results of operations for the years ended December 31, 2012, 2011 and 2010 are as follows.  Amounts are stated in thousands:

	2012		2011		2010
Revenues	$	320,189	$	262,026	$	218,146
Expenses other than income taxes	214,109		182,373		151,087
Net income	64,646		49,744		39,950

59

The comparative increase in Petrolera’s net income for 2012 is primarily a result of greater revenues driven by higher oil sales prices and volumes.  During 2012, we received $7.8 million in dividends from Petrolera compared with $12.8 million during 2011.  As a result of the current exchange control restrictions that have blocked the ability to move funds out of Argentina at the official rate of exchange, Petrolera has increased capital spending to the extent possible and accelerated repayment of its loans denominated in foreign currency (US dollars).

(3) Restricted Cash

Restricted cash is $8.9 million as of December 31, 2012, and is related to our Colombian operations.  As part of the contractual requirements of our blocks, the government requires letters of credit to guarantee exploration investment commitments. These letters of credit are collateralized by cash.  We consider our cash that is used as collateral to be restricted. We issued $3.7 million in letters of credit that expire on various dates in 2013 and have been classified as current assets. We also issued $5.2 million in letters of credit that expire on various dates in 2014 and 2015 and have been classified as noncurrent assets. The restricted cash is invested in a short-term money market account with a financial institution.  As of December 31, 2011, all restricted cash was classified as noncurrent.

(4) Exploration Expense

	Twelve months ended
	December 31,
	2012	2011	2010
	(in thousands)
Geologic and geophysical costs	8,365	2,046	6,102
Dry hole costs	2,787	1,057	—
Total exploration expense	11,152	3,103	6,102

Our geologic and geophysical costs primarily consist of the acquisition cost of 3D or 2D seismic information. Our dry hole costs are related to the impairment of exploratory wells or unsuccessful well re-completions of an exploratory nature.

(5) Exploratory Wells and Exploratory Well Costs Pending the Determination of Proved Reserves

We have $6.1 million in exploratory wells in progress as of December 31, 2012.  If the exploratory wells are determined to be productive, the appropriate related costs will be transferred to proved oil and gas properties.  Included in the balance of exploratory wells in progress are certain exploratory wells that have been drilled but are pending the determination of proved reserves. For the years ended December 31, 2012, 2011, and 2010, 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:

	2012			2011			2010
	(in thousands)
Balance, beginning of year	$	1,200		$	101		$	—
Additions	4,649			1,200			101
Transfers to proved properties	—			(101		)	—
Expensed	(1,200		)	—			—
Total	$	4,649		$	1,200		$	101

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Not included in the table above, we had capitalized exploratory drilling costs net to our equity interest (which is presented on an after tax basis) pending the determination of proved reserves of approximately $795 thousand, $1.0 million, and $0.0 million for the years ended December 31, 2012, 2011, and 2010 respectively. The entire balance as of December 31, 2011 of $1.0 million was expensed during 2012.

(6) Major Customers

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

	For the Years Ended December 31,
	2012	2011	2010
Petrobras Argentina S.A.	1.82%	13.30%	48.98%
Esso Petrolera Argentina S.A.	12.83%	23.55%	22.41%
Oil Combustibles S.A.	29.59%	26.37%	1.45%
Shell Cia. Argentina de Petroleo S.A.	22.87%	16.32%	7.10%
YPF S.A.	12.27%	—%	—%

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

(7) 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.

We incurred expenses in 2011 and 2010 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 Apco), internal audit services, and purchases of materials and supplies.  These charges were incurred by us pursuant to an administrative services agreement between Apco and Williams.

We sold hydrocarbons to Petrobras Argentina, the majority shareholder of Petrolera, in 2012, 2011, and 2010.

Apco 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.  Apco's branch office in Argentina provides administrative assistance to NWA. Specifically, we pay cash calls and collects revenues on behalf of NWA.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

As of December 31, 2012 and 2011, the balances of related party transactions were as follows:

Accounts Receivable	December 31,
	2012		2011
	(in thousands)
Petrobras Argentina S.A.	$	245	$	—
Petrolera Entre Lomas S.A.	564		552
	$	809	$	552
Affiliate Receivable
Northwest Argentina Corporation (1)	$	12	$	21
	$	12	$	21
Affiliate Payable
WPX Energy, Inc.	$	303	$	489
Petrolera Entre Lomas S.A.	1,461		781
	$	1,764	$	1,270

(1) Northwest Argentina Corporation is a wholly-owned subsidiary of WPX Energy, Inc.

For the years ended December 31, 2012, 2011, and 2010, revenues and expenses derived from related party transactions and with Williams were as follows:

Revenues from hydrocarbons sold	2012			2011			2010
	(in thousands)
Petrolera Entre Lomas S.A.	$	4,182		$	3,372		$	2,773
Petrobras Argentina S.A.	2,427			13,469			43,007
	$6,609			$16,841			$45,780
Expenses
WPX Energy, Inc.	$	1,825		$	1,314		$	1,261
Northwest Argentina Corporation	(127		)	(167		)	—
The Williams Companies, Inc.	—			177			89
	$	1,698		$	1,324		$	1,350

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(8) Current Assets

At December 31, 2012 and 2011 other current assets consisted of the following:

	December 31, 2012		December 31, 2011
	(in Thousands)
Prepaid Expense	$	1,415	$	355
Value added tax advances	2,327		1,657
Advances with joint venture partners	356		1,264
Interest receivable	105		139
Other current assets	674		485
	$	4,877	$	3,900

(9) Accrued Liabilities

At December 31, 2012 and 2011 accrued liabilities consisted of the following:

	December 31, 2012		December 31, 2011
	(in Thousands)
Taxes other than income	$	2,870	$	2,424
Payroll and other general and administrative expenses	2,205		1,765
Advances from joint venture partners	1,425		—
Current portion of long-term debt	500		—
Other	742		656
	$	7,742	$	4,845

(10) Income Taxes

Apco was incorporated in the Cayman Islands in 1979. Since then, our income, to the extent that it is derived from sources outside the U.S., is not subject to U.S. income taxes. Also, we have been granted an undertaking from the Cayman Islands government, expiring in 2019, to the effect that Apco 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 our income during 2012, 2011, and 2010 was generated outside the United States.

We are domiciled in the Cayman Islands where the income tax rate is zero.  However, we are subject to income taxes in Argentina and in Colombia.  We currently pay income tax only in Argentina where most of our oil and gas income generating activities are presently located. Equity income from our investment in Petrolera is recorded by the Company on an after tax basis. As of May 16, 2012 income generated from production in the province of Tierra del Fuego in Argentina is no longer exempt from income taxes based on Executive Decree 751/2012, which removed the exemption from taxes and duties previously provided by Law 19,640. We have incurred tax losses related to exploration and production activity in Colombia. We have not recorded any benefit to income tax expense for these losses since there is uncertainty about when, if ever, our activities in Colombia will generate sufficient taxable income in Colombia to realize the benefit from these tax losses.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

We also generate income and incur 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 us.  Such items include interest income resulting from our cash and cash equivalents deposited in our Cayman Island and Bahamas bank accounts, general and administrative expenses incurred by us under our Administrative Services Agreement with WPX Energy, and foreign exchange gains and losses resulting from changes in the value of the peso which do not affect taxable income in Argentina.  

We recorded expenses for income taxes as presented in the following table.  

	Twelve months ended
	December 31,
	2012			2011			2010
	(in Thousands)
Income taxes:
Current	$	13,067		$	10,351		$	9,852
Deferred	(1		)	(288		)	(158		)
Income tax expense	$	13,066		$	10,063		$	9,694

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

	2012			2011			2010
	(in Thousands)
Provision at Argentine statutory rate	$	18,263		$	14,648		$	12,434
Increases (decreases) in taxes resulting from:
Equity income previously taxed in Argentina	(9,232		)	(7,174		)	(5,655		)
Expenses incurred in non-tax jurisdictions	1,719			1,465			1,205
Income received in non-tax jurisdictions	(336		)	(443		)	(1,020		)
US dollar remeasurement effect	982			1,000			613
Changes in valuation allowance	1,261			523			1,763
Other - net	409			44			354
	$	13,066		$	10,063		$	9,694

Income taxes payableat December 31, 2012 and 2011 were $4.6 million and $2.5 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 that is included in Accumulated Other Comprehensive Loss.

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

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

	2012			2011
	(in Thousands)
Deferred tax assets:
Defined contribution retirement plan accrual	$	270		$	232
Other assets	(37		)	90
Property basis difference and asset retirement obligation	2,535			2,545
Foreign carryovers	1,465			375
Retirement plan obligations	529			522
Other long term liabilities	295			250
Total deferred tax assets	5,057			4,014
Less valuation allowance	3,803			2,542
Net deferred tax assets	$	1,254		$	1,472

We have recorded a valuation allowance based on our assessment of the positive and negative evidence for our ability to realize the deferred tax assets attributable to our operations in Colombia.  

As of December 31, 2012 and December 31, 2011, 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 interest and other expense, respectively.  The statute of limitations for income tax audits in Argentina is six years and the tax years 2006 through 2012 remain open to examination.

(11) 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 $250 thousand and will be charged to expense as earned. In February 2013, the Company made a contribution of $203 thousand.  This amount was accrued as administrative expense in 2012. The total expense in 2011 was $100 thousand and $100 thousand in 2010.  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.

(12) Debt and Banking Arrangements

We have borrowed $8 million under our banking agreement. Our ability to draw funds from the line of credit under this agreement ended in March 2012. Borrowings under this facility are unsecured and bear interest at six-month Libor plus three percent per annum. 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.  Aggregate minimum maturities of our long-term debt are as follows:

	(in Thousands)
2013	500
2014	2,500
2015	3,500
2016	1,500
Total	$	8,000

65

(13) Long-Term Liabilities

At December 31, 2012 and 2011, long-term liabilities consisted of the following. 

	2012		2011
Long-term liabilities
Retirement plan obligations	$	999	$	901
Asset retirement obligations	2,261		2,373
Other	835		750
	$	4,095	$	4,024

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, 2012 and 2011, was $2.7 million and $2.6 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 $1.7 million, respectively.  The Company expects its contributions in 2012 to be less than $200 thousand.

(14) Contingencies and Commitments

In the third quarter of 2012, we and our partners in Tierra del Fuego reached agreements with the provincial government to extend the term of our concessions by the ten years provided for in Hydrocarbon Law 17,319. The ten-year extensions for all three concessions run through August 17, 2026. The agreements have been signed by us and our partners and representatives of the province. The agreements will become effective upon legislative approval. Nearly eight months have passed since the executed agreement was submitted to the legislature for approval. This time period is longer than expected and as a result we can provide no assurance that the agreement will receive the required approval.

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 and 2010. The DGR has claimed that we owe an additional $4.3 million pesos (approximately $874 thousand U.S. dollars). In making this assessment, the DGR 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 filed an administrative appeal with the Provincial Ministry of Economy in March 2012. We sold our interest in Cañadón Ramírez at the end of 2010. As of December 31, 2012 we have not been notified of any decision related to our appeal.

Commitments

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

	(in Thousands)
2013	$	21,553
2014	13,500
Total	$	35,053

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.

(15) Subsequent Events

As described in Note 1, Apco is eligible to earn producer export tax credit certificates through a government hydrocarbon subsidy program as a result of our oil and gas producing activities in Argentina. 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.

66

In February 2013, the government allowed a related-party of ours to utilize approximately $2.1 million of certificates that had originally been granted to Apco. We apply for the certificates and receive them at the discretion of the government.

(16) Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(Amounts in Thousands Except Per Share Amounts)
2012
Operating revenues	$	30,076	$	32,967	$	34,966	$	35,254
Costs and expenses	25,026		23,249		27,552		31,365
Investment income	8,338		7,163		6,363		4,244
Net income	10,092		12,695		10,244		6,082
Amounts attributable to Apco Oil and Gas International Inc:
Net income	10,076		12,680		10,231		6,074
Net income per ordinary and Class A shares outstanding	0.34		0.43		0.35		0.21
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

Net income for the fourth quarter of 2012 includes the following items related to our Colombian operations: $4.6 million in Operating revenues, $1.1 million of DD&A, and $652 thousand of Transportation and storage. During the fourth quarter, greater production and lifting costs and depreciation, depletion and amortization expense related to our Neuquén basin properties lowered both our operating income and Equity income from Argentine investment. The fourth quarter also included dry hole impairment costs of $830 thousand in Exploration expense related to our consolidated interests.

Net income for the third quarter of 2012 includes $2.4 million in Operating revenues related to the start-up of production and sales from our Colombian operations. The third quarter also included dry hole impairment costs of $1.9 million in Exploration expense related to our consolidated interests, and the same wells resulted in a negative impact net to our equity interest (shown on an after-tax basis) of $1.7 million in Equity income from Argentine investment.

Net income for the second quarter of 2012 includes $3.0 million in Exploration expense for the acquisition of 3D seismic information primarily in Colombia, and a gain of approximately $2.8 million in Other expense from a farm-out agreement in the Sur Río Deseado Este concession.

Net income for the first quarter of 2012 includes $5.0 million in Exploration expense for the acquisition of 3D seismic information in Colombia and Argentina.

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. 

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

67

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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.

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APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

Oil and Natural Gas Reserves

Proved Oil, Condensate andPlant 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. Prior to December 31, 2012, all of our reserves were located in Argentina.  As of December 31, 2012, 98 percent of our oil reserves were in Argentina, and our independent reserve engineer, Ralph E. Davis Associates, Inc. (“Davis”), audited our estimates of those reserves as prepared by us; two percent of our oil reserves as of December 31, 2012, are attributable to our Colombian properties and were estimated by Davis.

	(Millions of Barrels)
	Interests
	Consolidated		Equity		Combined
December 31, 2009	11.9		13.9		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
December 31, 2011	11.9		13.1		25.0
Revisions of previous estimates:
Engineering revisions	(1.1	)	(1.1	)	(2.2	)
Extensions and discoveries	2.0		1.1		3.1
Production	(1.6	)	(1.7	)	(3.3	)
December 31, 2012	11.2		11.4		22.6
Proved developed as of December 31, 2012	6.5		7.0		13.5
Proved undeveloped as of December 31, 2012	4.7		4.4		9.1

• 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 for its Argentine properties. Volumes attributable to our Colombian properties are presented net of royalties of 8 percent.

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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 natural gas reserves are located in Argentina.  As of December 31, 2012, all of our net proved natural gas reserves were prepared by us and audited by Davis. 

	(Billions of Cubic Feet)
	Interests
	Consolidated		Equity		Combined
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
December 31, 2011	64.7		51.1		115.8
Revisions of previous estimates:
Engineering revisions	(16.7	)	(18.6	)	(35.3	)
Extensions and discoveries	5.7		7.4		13.1
Production	(7.6	)	(4.4	)	(12.0	)
December 31, 2012	46.1		35.5		81.6
Proved developed as of December 31, 2012	31.1		20.8		51.9
Proved undeveloped as of December 31, 2012	15.0		14.7		29.7

• A portion of our natural gas reserves are consumed in field operations. The volume of natural gas reserves for 2010, 2011, and 2012 estimated to be consumed in field operations included as proved natural gas reserves within consolidated interest is 14.8 Bcf, 13.9 Bcf, and 8.7 Bcf, respectively, and within the equity interest is 16.6 Bcf, 15.6 Bcf, and 9.2 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.

Our total proved reserves for 2012 decreased from 2011 as the benefits of successful development and exploration drilling were more than offset by the combination of revisions of previous estimates and production volumes for the year.  The revisions of previous estimates were the result of reducing our development assumptions and forecasts of well production volumes in

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APCO OIL AND GAS INTERNATIONAL INC.

UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

natural gas fields where performance and drilling results have not met expectations and also due to the reclassification to unproved of proved undeveloped reserves in the provinces of Río Negro and Tierra del Fuego where we have not yet been successful in obtaining our ten year concession extensions. For additional discussion about our remaining concession extensions see "MD&A - Overview of 2012 - Concession Contracts in Argentina" in Item 7 of this report.

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.  

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. Prices are based on 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, 2012, 2011 and 2010, the average oil prices used in the estimates were $74.42, $61.95 and $52.11 per barrel.

For the years ended December 31, 2012, 2011 and 2010, the average natural gas prices used in the estimates were $2.62, $2.30 and$1.63 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.

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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 properties or each of the years presented:

	(Millions of Dollars)
	Interests
	Consolidated			Equity			Combined
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
As of December 31, 2012
Future cash inflows	$	928		$	892		$	1,820
Less:
Future production costs	(371		)	(356		)	(727		)
Future development costs	(131		)	(115		)	(246		)
Future income tax expense	(92		)	(104		)	(196		)
Future net cash flows	334			317			651
Less 10 percent annual discount for estimated timing of cash flows	(127		)	(118		)	(245		)
Standardized measure of discounted future net cash flows	$	207		$	199		$	406

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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 proved oil and gas reserves for each of the years presented.

	(Millions of Dollars)
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		)	(19		)	(32		)
Net changes	30			57			87
Standardized measure of discounted future net cash flows end of period	$	185		$	186		$	371
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

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	(Millions of Dollars)
For the Year Ended December 31, 2012	Interests
	Consolidated			Equity			Combined
Standardized measure of discounted future net cash flows beginning of period	$	193		$	197		$	390
Changes during the year:
Revenues, net of production costs	(75		)	(78		)	(153		)
Net changes in prices and production costs	41			49			90
Additions and revisions of previous estimates	12			(14		)	(2		)
Changes in estimated development costs	(16		)	(17		)	(33		)
Development costs incurred during current period	35			35			70
Changes in production rates, timing, and other	(13		)	(12		)	(25		)
Accretion of discount	25			27			52
Net changes in income taxes	5			12			17
Net changes	14			2			16
Standardized measure of discounted future net cash flows end of period	$	207		$	199		$	406

• Net changes from additions and revisions of previous estimates includes positive changes of $32 million within consolidated interests and $25 million within equity interests, offset by negative changes from revisions of $20 million net to consolidated interests and $39 million net to our equity interests.

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.   

	(Amounts in thousands)
	Interests
	Consolidated			Equity
For the year ended December 31, 2011
Proved oil and gas properties	$	248,522		$	252,034
Unproved oil and gas properties	7,037			1,606
Accumulated depreciation, depletion and amortization	(130,146		)	(153,415		)
Total	$	125,413		$	100,225
For the year ended December 31, 2012
Proved oil and gas properties	$	303,052		$	291,876
Unproved oil and gas properties	8,686			1,223
Accumulated depreciation, depletion and amortization	(156,888		)	(180,869		)
Total	$	154,850		$	112,230

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Costs Incurred in Acquisitions, Exploration, and Development

The following table details costs incurred for acquisitions, exploration, and development during 2010, 2011 and 2012. Costs incurred include capitalized and expensed items.

	Interests
(Amounts in Millions)	Consolidated			Equity			Combined
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
For the year ended December 31, 2012
Exploration	$	31.1		$	5.0		$	36.1
Development	35.1			35.4			70.5
Asset retirement obligations	0.4			0.1			0.5
Total	$	66.6		$	40.5		$	107.1

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL 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 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, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

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 2012 Changes in Internal Controls

As previously reported in Management's Report on Internal Control Over Financial Reporting in our 2011 Form 10-K, in the third quarter of 2011, we identified a material weakness related to the lack of technical accounting resources to help identify and assess accounting matters and appropriately present and disclose such matters in our consolidated financial statements and related footnotes. We subsequently adopted a plan to remediate the material weakness. In the third quarter of 2012, we amended the plan to include the implementation of new controls and procedures related to the preparation and review of financial and non-financial disclosures and financial statement consolidation, presentation and review. In the fourth quarter of 2012, we completed the evaluation of these new controls and procedures and concluded that the steps we have taken to strengthen our internal controls over financial reporting would prevent or detect a material misstatement. Therefore, the previously reported material weakness no longer existed at the end of the period covered by this report.

In the fourth quarter, the Company separated the Chief Financial Officer and the Chief Accounting Officer and Controller roles and appointed two new individuals to these positions. Historically, these positions had been combined in a single role. Management believes separating these roles strengthens our internal controls and our disclosure controls and procedures.

Other than described above, there have been no changes during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. Other Information

None.

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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 2013 Proxy Statement and incorporated herein by reference.

ITEM 11.  EXECUTIVE COMPENSATION

The information required by this Item 11 is set forth under the caption “Executive Compensation and Other Information” in our 2013 Proxy Statement and incorporated herein by reference.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ANDRELATED 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 2013 Proxy Statement 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 2013 Proxy Statement 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 2013 Proxy Statement and incorporated herein by reference.

77

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).

78

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.

79

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/ Benjamin A. Holman     Benjamin A. Holman
Chief Accounting Officer and Controller

Date:  March 7, 2013

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)	March 7, 2013
/s/ Rodney J. Sailor Rodney J. Sailor	Chief Financial Officer, (Principal Financial Officer)	March 7, 2013
/s/ Benjamin A. Holman Benjamin A. Holman	Chief Accounting Officer, Controller (Principal Accounting Officer)	March 7, 2013
/s/ *Keith E. Bailey	Director	March 7, 2013
Keith E. Bailey
/s/ *Robert J. LaFortune	Director	March 7, 2013
Robert J. LaFortune
/s/ *Bryan K. Guderian	Director	March 7, 2013
Bryan K. Guderian
/s/ *Piero Ruffinengo	Director	March 7, 2013
Piero Ruffinengo
/s/ *John H. Williams	Director	March 7, 2013
John H. Williams
*By:  /s/ Thomas Bueno	President	March 7, 2013
Thomas Bueno Attorney-in-Fact

80

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).

81

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.

82

Schedule S-1

PETROLERA ENTRE LOMAS S.A.

Financial Statements for the fiscal year ended December

31, 2012 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, 2012 and 2011	- 1 -
	-   Statements of income for the years ended December 31, 2012, 2011 and 2010	- 2 -
	-   Statements of comprehensive income for the years ended December 31, 2012, 2011 and 2010	- 3 -
	-   Statements of shareholders' equity for the years ended December 31, 2012, 2011 and 2010	- 4 -
	-   Statements of cash flows for the years ended December 31, 2012, 2011 and 2010	- 5 -
	-   Notes to financial statements	- 6 -

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, 2012 and 2011, and the related statements of income, comprehensive income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

Buenos Aires, Argentina
February 13, 2013
	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, 2012 AND 2011

(stated in thousands of U.S. dollars)

	December 31,
	2012	2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	36,692	26,063
Accounts receivable (2,025 and 23 with related parties, Note 6)	34,453	26,931
Other receivables (1,020 and 5,191 with related parties, Note 6)	9,575	8,639
Inventories	2,843	3,144
Other assets	872	920
Total current assets	84,435	65,697
NONCURRENT ASSETS
Accounts receivable	371	524
Other receivables	239	274
Property, plant and equipment, net (Note 5)	275,054	246,364
Deferred tax asset, net (Note 4)	4,295	3,342
Other assets	2,538	3,468
Total noncurrent assets	282,497	253,972
Total assets	366,932	319,669
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities (1,728 and 705 with related parties, Note 6)	29,176	19,703
Debt and accrued debt interest (Note 11)	16,295	16,356
Taxes payable and payroll (Note 9)	25,156	16,178
Other liabilities (Note 9)	1,537	1,312
Total current liabilities	72,164	53,549
NONCURRENT LIABILITIES
Debt (Note 11)	12,800	32,380
Other liabilities (Note 9)	17,305	14,417
Total noncurrent liabilities	30,105	46,797
Total liabilities	102,269	100,346
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	153,006	116,817
Retained earnings	62,539	53,388
Total shareholders' equity	264,663	219,323
Total liabilities and shareholders' equity	366,932	319,669

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, 2012, 2011 AND 2010

(stated in thousands of U.S. dollars)

	Year ended December 31,
	2012		2011		2010
REVENUES:
Operating revenues (6,266, 41,142 and 115,938 with related parties, Note 6)	320,189		262,026		218,146
COST AND EXPENSES:
Operating expenses (4,088, 3,113 and 3,114 with related parties, Note 6)	(74,207	)	(63,435	)	(51,956	)
Provincial production tax	(40,553	)	(33,062	)	(27,133	)
Transportation and storage	(3,043	)	(2,505	)	(2,254	)
Selling and administrative	(7,046	)	(6,549	)	(5,512	)
Depreciation of property, plant and equipment	(67,285	)	(59,853	)	(50,271	)
Exploration expense	(7,772	)	(4,905	)	(3,883	)
Taxes other than income tax	(12,652	)	(9,645	)	(7,494	)
Financial losses	9		(2,456	)	(1,735	)
Foreign exchange losses	(1,639	)	(73	)	(399	)
Other income (expense), net (65, 111 and nil with related parties, Note 6)	79		110		(450	)
Total cost and expenses	(214,109	)	(182,373	)	(151,087	)
Income before income tax	106,080		79,653		67,059
Income tax (Note 4)	(41,434	)	(29,909	)	(27,109	)
Net income	64,646		49,744		39,950

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

- 2 -

PETROLERA ENTRE LOMAS S.A.

STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010

(stated in thousands of U.S. dollars)

	For the years ended December 31
	2012		2011		2010
Net income	64,646		49,744		39,950
Other comprehensive income (loss), before tax:
Defined benefit pension plan	(317	)	(481	)	355
Other comprehensive income (loss), before tax	(317	)	(481	)	355
Income tax (expense) benefit related to items of other comprehensive income	111		169		(125	)
Other comprehensive income (loss), net of tax	(206	)	(312	)	230
Comprehensive income	64,440		49,432		40,180

PETROLERA ENTRE LOMAS S.A.

STATEMENTS OF SHAREHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010

(stated in thousands of U.S. dollars)

Balance	Capital stock	Legal reserve	Facultative reserve		Retained earnings		Total
December 31, 2009	41,289	7,829	91,004		49,489		189,611
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting	—	—	39,291		(39,291	)	—
Dividends	—	—	(28,500	)	—		(28,500	)
Comprehensive income	—	—	—		40,180		40,180
December 31, 2010	41,289	7,829	101,795		50,378		201,291
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting	—	—	46,422		(46,422	)	—
Dividends	—	—	(31,400	)	—		(31,400	)
Comprehensive income	—	—	—		49,432		49,432
December 31, 2011	41,289	7,829	116,817		53,388		219,323
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting	—	—	55,289		(55,289	)	—
Dividends	—	—	(19,100	)	—		(19,100	)
Comprehensive income	—	—	—		64,440		64,440
December 31, 2012	41,289	7,829	153,006		62,539		264,663

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, 2012, 2011 AND 2010

(stated in thousands of U.S. dollars)

	Year ended December 31,
	2012		2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	64,646		49,744			39,950
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation of property and equipment	67,285		59,853			50,271
Deferred income tax	(842	)	(2,070	)		(699	)
Income from sales of property and equipment	—		—			(60	)
Effect of exchange rate changes on cash and cash equivalents	5,705		—			—
Accrued interest on debt	1,491		1,628			1,566
Changes in assets and liabilities, net:
(Increase) decrease in assets:
Accounts receivable	(5,367	)	(8,946	)		(9,432	)
Accounts receivable - Due from related parties	(2,002	)	10,381			3,659
Inventories	301		(2,009	)		198
Other receivables	(5,183	)	(954	)		2,891
Other receivables - Due from related parties	4,171		(5,191	)		—
Other assets	978		(9	)		(3,239	)
Increase (decrease) in liabilities:
Accounts payable and accrued liabilities	8,450		5,854			6,104
Accounts payable - Due to related parties	1,023		215			113
Taxes payable and payroll	8,978		1,117			5,213
Other liabilities	1,484		1,486			(6,079	)
Interest on debt paid	(1,525	)	(1,663	)		(1,470	)
Net cash provided by operating activities	149,593		109,436			88,986
CASH FLOWS FROM INVESTING ACTIVITIES
Payments of purchases of property, plant and equipment	(94,552	)	(84,138	)		(64,196	)
Cash provided by sales of property, plant and equipment	—		—			117
Net cash applied on investing activities	(94,552	)	(84,138	)		(64,079	)
CASH FLOWS FROM FINANCING ACTIVITIES
Loans obtained	3,200		16,300			13,100
Loans paid	(22,807	)	(16,407	)		(12,907	)
Dividends paid	(19,100	)	(31,400	)		(34,500	)
Net cash applied on financing activities	(38,707	)	(31,507	)		(34,307	)
Net (decrease) increase in cash and cash equivalents	16,334		(6,209	)		(9,400	)
Effect of exchange rate changes on cash and cash equivalents	(5,705	)
Cash and cash equivalents at beginning of year	26,063		32,272		41,672	41,672
Cash and cash equivalents at end of year	36,692		26,063			32,272
Supplemental cash flow information:
Interest paid	1,537		2,302			1,486
Income taxes paid	32,658		32,031			17,698

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. (“PELSA”) is an Argentine corporation. As of December 31, 2012 and 2011

the shareholders of the Company and their participations were as follows:

	2012		2011
Petrobras Argentina S.A.	58.88	%	19.21	%
Petrobras Participaciones, S.L.	—	%	39.67	%
Apco Oil & Gas International Inc.	39.22	%	39.22	%
Apco Argentina S.A.	1.58	%	1.58	%
Other	0.32	%	0.32	%
	100.00	%	100.00	%

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

On May 31, 2012, Petrobras Argentina S.A. bought from its parent company Petrobras Participaciones

S.L. 39.67% of the interest held in Petrolera Entre Lomas S.A. After this transaction, Petrobras

Argentina S.A. holds 58.88% of PELSA’s shares.

The Company is operator and participant in Entre Lomas concession (Entre Lomas, an unincorporated

joint venture founded in August 12, 1968) located in Río Negro and Neuquén provinces in southwest

Argentina, which is accounted for following the proportional consolidation method. The concession

contract was signed in 1991 and the concession term was extended 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 exploitation of Bajada del Palo Area, located in the province of

Neuquén. 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 Neuquén asked for the renegotiation of the

concession terms. During 2009, the Company agreed with the province of Neuquén 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 Río Negro is still pending.

In December 2012, the province of Río Negro enacted Law No. 4,818 setting forth the terms and

conditions for renegotiating oil and gas concessions. PELSA is currently preparing the documentation

required by the relevant enforcement agency for its filing within the terms established by section 8 of the

above mentioned law.

- 5 -

During 2007, an exploration permit was obtained for Agua Amarga Area in the province of Río Negro.

The permit consists of three periods of three, two and one years respectively. The first exploratory

permit was extended by the province of Río Negro until May 31, 2012. Based on the results of the

exploration carried out in the Agua Amarga Area, the Company requested the province of Río Negro the

exploitation concession of a portion of the area, which was granted for a 25-year term. Subsequently,

the Work Plan for the second exploration term of the Agua Amarga area was submitted before the

relevant enforcement agency’s liaison committee. The plan was accepted through Provincial Decree

No. 1,582/2012, granting PELSA a second exploration term in the area, thus keeping the total surface

currently covered by the permit for two additional years.

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 Río Negro.

The partners’ interests in the above mentioned joint ventures as of December 31, 2012 and 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 2012 and 2011, is as follows:

	2012		2011
Current assets	22,748		13,229
Noncurrent assets	269,235		239,615
Total assets	291,983		252,844
Current liabilities	(50,770	)	(31,139	)
Noncurrent liabilities	(17,780	)	(14,772	)
Total liabilities	(68,550	)	(45,911	)

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 2012, 2011 and 2010, is as follows:

	2012		2011		2010
Operating costs	(164,042	)	(147,153	)	(120,601	)
Administrative expenses	(6,801	)	(5,730	)	(4,840	)
Selling expenses	(368	)	(363	)	(472	)
Exploration expenses	(7,772	)	(4,905	)	(3,883	)
Other operating expenses, net	(718	)	(551	)	(702	)
Financial losses, net	509		(496	)	(584	)
	(179,192	)	(159,198	)	(131,082	)

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).

- 6 -

PETROLERA ENTRE LOMAS S.A.

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.

The financial statements as of December 31, 2011 and 2010, include certain reclassifications in the

disclosure of some accounts for the purpose of adjusting its comparative presentation thereof with the

reclassifications made as of December 31, 2012.

Summary of significant accounting policies

Cash and cash equivalents

Cash and cash equivalents in 2012 and 2011 include highly liquid bank deposits and other short term

investment of 36.7 million and 26.0 million, respectively, of which 31.3 million and 25.8 million earned

interest with an average rate of 13.42 and 0.73 percent in 2012 and 2011, 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 advances to suppliers. In addition, as of December 31, 2011, it includes

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 2,843 and 3,144 in 2012 and 2011, respectively and have been valued at current production cost as of the end of each year.

Other assets

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

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. No 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

- 7 -

PETROLERA ENTRE LOMAS S.A.

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, 2012, 2011 and 2010, 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 by independent oil and gas auditors 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.

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, 2012 and 2011 totaled 12,401 and 10,452. The change in total asset retirement

obligation from December 31, 2011 to December 31, 2012 mainly relates to the effect of the passage of

time for about 634, and changes in the cost and number of wells planned to be abandoned upon

termination of the concessions for about 1,315.

Property plant and equipment includes as of December 31, 2012 and 2011, material and spare parts by

4,449 and 733, respectively, which were accounted for at the lower of cost or market. The cost is

determined by the first-in first-out method.

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.

- 8 -

PETROLERA ENTRE LOMAS S.A.

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, 2012 and 2011, the total price credit available to the Company from domestic refiners

amounts to 9.2 million and 8.9 million, respectively, 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, 2012 and 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 Petróleo 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.

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 earnings as

Operating revenues.

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. During 2012,

no earnings have been recognized as Operating revenues as a result of this program.

Derivative instruments

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

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, 2012, the dollar value of the Company's deposit is 1.5 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. On September 2012, prior to passing sentence, tax authorities’ representatives requested that the fees payable to court be paid for 3% of the claimed amount. Such amount was paid by PELSA on November 12, 2012. 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

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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.

The income tax expense is comprised of:

	For the years ended
	2012		2011		2010
Current expense	(42,276	)	(31,979	)	(27,808	)
Deferred income tax profit	842		2,070		699
	(41,434	)	(29,909	)	(27,109	)

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

	For the years ended
	2012		2011		2010
Pre-tax income	106,080		79,653		67,059
Statutory tax rate	35	%	35	%	35	%
	37,128		27,879		23,471
US dollar remeasurement effect	4,212		3,099		3,230
Tax adjustments and other	94		(1,069	)	408
Income tax expense	41,434		29,909		27,109

The deferred tax assets and liabilities at December 31, 2012 and 2011 are as follows:

	2012		2011
Defined Benefit Pension Plan	2,255		2,209
Asset retirement and other environmental obligations	3,355		2,252
Other, net	(49	)	53
Total deferred tax assets	5,561		4,514
Property, plant and equipment	(1,266	)	(1,172	)
Total deferred tax liabilities	(1,266	)	(1,172	)
Deferred income tax asset, net	4,295		3,342

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 2006 to 2012 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, 2012 and 2011 were as follows:

	December 31,
	2012		2011
Wells and other oil and gas field equipment	655,262		565,235
Acquisition costs of proved properties	31,687		31,687
Other property, plant and equipment	31,379		25,431
	718,328		622,353
Less accumulated depreciation	(443,274	)	(375,989	)
Total	275,054		246,364

6. RELATED PARTY TRANSACTIONS

As of December 31, 2012 and 2011, the balances from related parties transactions were as follows:

	As of December 31,
	2012	2011
Accounts receivable
Petrobras Argentina S.A.	2,025	23
	2,025	23
Other receivables
APCO Oil & Gas International Inc.- Argentine Branch	565	318
APCO Oil & Gas International Inc	—	351
Petrobras Argentina S.A.	455	4,522
	1,020	5,191
Accounts payable.
APCO Oil & Gas International Inc. - Argentine Branch	880	—
Petrobras Argentina S.A	596	190
Oleoductos del Valle S.A. (1)	252	515
	1,728	705

(1) Affiliate of Petrobras Argentina S.A.

For the years ended December 31, 2012, 2011 and 2010, revenues and expenses derived from related parties transactions were as follows:

	2012	2011	2010
Revenues from hydrocarbons sold
Petrobras Argentina S.A.	6,266	41,142	115,938
	6,266	41,142	115,938

	2012	2011	2010
Other income
APCO Oil & Gas International Inc.- Argentine Branch	28	21	—
Petrobras Argentina S.A.	37	90	—
	65	111	—

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PETROLERA ENTRE LOMAS S.A.

Purchases and operating expenses
APCO Oil & Gas International Inc.- Argentine Branch	—	7	—
Petrobras Argentina S.A.	1,423	637	855
Oleoductos del Valle S.A. (1)	2,665	2,469	2,259
	4,088	3,113	3,114

(1) Affiliate of Petrobras Argentina S.A.

Director's Compensation totaled $729, $828 and $595 for the years ended December 31, 2012, 2011 and 2010, 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
	2012	2011	2010
Oil Combustibles S.A.	31.4	27.5	—
Shell CAPSA	30.0	20.0	—
Esso Petrolera Argentina S.A.	16.4	28.6	28.6
YPF S.A.	13.4	—	—
Petrobras Argentina S.A.	2.0	13.2	53.1

The balances with Oil Combustibles S.A., Shell CAPSA, Esso Petrolera Argentina S.A., YPF S.A.and Petrobras Argentina S.A. are $670, $19,$619, nil, $7,586 and $2,025 as of December 31, 2012 and $5,829, $8,377, $8,496, nil, and $23 as of December 31, 2011, 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.

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, 2012 and 2011. The Bank of New York is the trustee and Towers Watson is the servicing agent.

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PETROLERA ENTRE LOMAS S.A.

	2012		2011
Projected benefit obligation	8,731		8,161
Accumulated benefit obligation	6,277		8,147
Fair value of plan assets at year end	5,552		5,296
Funded status of the plan (underfunded)	(3,179	)	(2,865	)
Amounts recognized in the statement of financial position consist of:
Accrued benefit liabilities (current and noncurrent)	(3,179	)	(2,865	)
Accumulated other comprehensive income	3,400		3,083
Projected benefit obligation at beginning of the year	8,161		7,418
Service cost	212		266
Interest cost	325		299
Net actuarial (gain)/loss due to plan experience	316		451
Benefit payment from fund	(283	)	(273	)
Projected benefit obligation at year end	8,731		8,161
Fair value of plan assets at beginning of the year	5,296		4,955
Company contributions	552		612
Benefit payments from fund	(283	)	(273	)
Actual return on assets	(13	)	2
Fair value of plan assets	5,552		5,296

	2012		2011		2010
Component of net periodic benefit cost:
Service cost	212		266		176
Interest cost	325		299		295
Expected return on assets	(213	)	(194	)	(283	)
Amortization of net prior service cost	58		10		15
Amortization of net losses	166		152		209
Net periodic benefit cost	548		533		412
Pension liability adjustment included in other comprehensive income	(317	)	(481	)	355

The prior service cost and actuarial loss included in accumulated other comprehensive income and expected to be recognized in net periodic pension cost during 2013 is 58 and 166, respectively.

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PETROLERA ENTRE LOMAS S.A.

	2012		2011
Asset Categories
Cash reserves	16	%	57	%
Treasury Federal Funds	84	%	43	%
Total	100	%	100	%

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

	2012		2011
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	%

The expected long-term rate of return is based on historical performance of the investments.

Contributions

The Company expects to contribute 395 to its pension plan in 2013.

Estimated Future Benefit Payment

The following benefit payments are expected to be paid.

Year	Benefit
2013	371
2014	450
2015	472
2016	470
2017-2021	2,651

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

9. TAXES PAYABLE AND PAYROLL ACCOUNT AND OTHER LIABILITIES

At December 31, 2012 and 2011, taxes payable and payroll account consisted of the following:

	2012	2011
Income tax accrual, net	16,874	9,164
Provincial production taxes	3,625	2,618
Payroll	2,685	2,434
Other	1,972	1,962
	25,156	16,178

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PETROLERA ENTRE LOMAS S.A.

At December 31, 2012 and 2011, current other liabilities consisted of the following:

	2012	2011
Asset retirement and other environmental obligations	557	494
Liability for pension benefit (Note 8)	371	302
Others	609	516
	1,537	1,312

At December 31, 2012 and 2011, non-current other liabilities consisted of the following:

	2012	2011
Liability for pension benefit (Note 8)	2,808	2,563
Asset retirement and other environmental obligations	14,419	11,749
Others	78	105
	17,305	14,417

10. 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.

11. DEBT

Company’s debt consists of several debt agreements arranged with Banco do Brasil S.A., London

Branch and Banco Santander Río S.A. Detailed information as of December 31, 2012 and 2011 is as

follows:

Debt agreement date (yyyy-mm-dd)	Bank	Interest rate		Interest payable	Principal maturity date (yyyy-mm-dd)	Principal Due 2012		Principal Due 2011
2009-05-15	Banco do Brasil S.A., London Branch	LIBOR + 2.40		quarterly	2013-08-12	9,680	(1)	22,587	(3)
2010-05-14	Banco do Brasil S.A., London Branch	LIBOR + 2.50		every six months	2013-05-31	3,200		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		3,200
2011-02-16	Banco Santander Rio S.A.	3.50	%	quarterly	2013-01-16	—	(2)	3,200
2011-05-17	Banco do Brasil S.A., London Branch	LIBOR + 2.90		every six months	2014-05-16	3,200		6,700
2011-08-24	Banco do Brasil S.A., London Branch	LIBOR + 2.90		every six months	2014-08-07	3,200		3,200
2011-11-11	Banco do Brasil S.A., London Branch	LIBOR + 2.95		every six months	2014-11-14	3,200		3,200
2012-02-09	Banco do Brasil S.A., London Branch	LIBOR + 3.55		every six months	2015-02-03	3,200
						28,880		48,487

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PETROLERA ENTRE LOMAS S.A.

(1) Consists of 3 unpaid quarterly installments as of December 31, 2012. Principal and interest due in February 2013 were prepaid on January 15, 2013

(2) The loan was paid in July 2012.

(3) Consist of 7 unpaid quarterly installments as of December 31, 2011.

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

2013	16,080
2014	9,600
2015	3,200

As of December 31, 2012 and 2011, interest and taxes accrued for these loans amount to 1,491, and 1,628, respectively, interest and taxes payable amount to 215 and 249, respectively.

12. 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, 2012 no contingent liabilities have been accrued.

13. 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.

	2012		2011		2010
Balance, beginning of year	3,937		3,918		—
Additions	2,997		2,059		3,918
Transfers to proved properties	(3,937	)	(2,040	)	—
Total	2,997		3,937		3,918

The balance as of December 31, 2011 consisted of two exploratory wells whose drilling began in 2012, which are still under evaluation in order to conclude on the determination of proved reserves.

14. SUBSEQUENT EVENTS

Subsequent events have been evaluated through February 13, which is the date these Financial Statements were available to be issued.

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