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, 2013
	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 28, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, was $105,367,607. 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 26, 2014, 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 2014 Annual General Meeting of Shareholders to be held on April 24, 2014, 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.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	25
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosures	25
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	28
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 8.	Financial Statements and Supplementary Data	45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	77
Item 9A.	Controls and Procedures	77
Item 9B.	Other Information	77
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	78
Item 11.	Executive Compensation	78
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78
Item 13.	Certain Relationships and Related Transactions, and Director Independence	78
Item 14.	Principal Accountant Fees and Services	78
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	79

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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 sometimes used as a reference for prices of crude oil sold in Argentina and Colombia.

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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, 2013, 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 2014 Annual General Meeting of Shareholders (our "2014 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 2014 Proxy Statement, which information is incorporated by reference herein. In 2013, WPX began efforts to dispose of its interests in Apco.

(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 and production contracts.

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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	44.00%	—
Llanos 32	Llanos	Exploration and production	Casanare	Colombia	20.00%	—
Turpial	Middle Magdalena	Exploration and production	Boyaca / Antioquia	Colombia	50.00%	—
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 2013, we reduced our working interest in an exploratory area in the northern sector of the Sur Río Deseado Este concession from 78 percent to 44 percent pursuant to a farm-out agreement. 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, 2013. Approximately one 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, 56 percent of our combined consolidated and equity proved reserves are oil and condensate and 44 percent are natural gas as of December 31, 2013.

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 37 percent of our total proved reserves, and also drill in unproven areas as a result of exploration and/or field-extension drilling to add to our proved reserves and replace as much of the current year’s production as possible. In recent years, we have complemented our development projects in Argentina by increasing exploration activities in both Argentina and Colombia.

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Oil and Natural Gas Reserves

Summary of Proved Oil and Natural Gas Reserves as of December 31, 2013

Based on Average 2013 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	5,564	5,771	11,335	36.1	18.7	54.8	11,579	8,887	20,466
Proved undeveloped	3,600	3,236	6,836	19.6	11.3	30.9	6,868	5,117	11,985
Total proved (4)	9,164	9,007	18,171	55.7	30.0	85.7	18,447	14,004	32,451

(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 2013 estimated to be consumed in field operations included as proved natural gas reserves is 9.1 Bcf for our consolidated interests and 7.3 Bcf for our equity interests, or an oil equivalent combined amount of 2,700 Mboe.

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

(4) As of December 31, 2013, 99 percent of our reserves are in Argentina and one 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, 2013, Ralph E. Davis Associates, Inc. (“Davis”) has audited all of our proved reserves attributable to our Argentine properties as prepared by us, or 99 percent of our total proved reserves, and has estimated reserves attributable to our Colombian properties which represent one 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, 2013 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

The following table summarizes the change in estimates of proved undeveloped reserves from December 31, 2012, to December 31, 2013.

	Mmboe
Proved undeveloped reserves, December 31, 2012	14.0
Proved undeveloped reserves converted to proved developed	(3.0	)
Proved undeveloped reserves added due to extensions, discoveries and contract modifications	2.0
Revisions of previous estimates	(1.0	)
Proved undeveloped reserves, December 31, 2013	12.0

During 2013, our progress toward converting proved undeveloped reserves to proved developed reserves included the drilling and completion of 26 gross proved undeveloped wells at a total cost to us of approximately $53 million net to our combined consolidated and equity interests. All of our remaining proved undeveloped locations are forecast to be spud within the next five years according to our development plan. We expect to increase proved undeveloped drilling during the next several years as a result of obtaining the ten-year concession extensions related to our Tierra del Fuego properties, and more development drilling activity in Coirón Amargo. For many years we have effectively converted proved undeveloped reserves to proved developed reserves as we have drilled and put on production undeveloped locations, including both step-out and in-fill wells. During 2013, 3 MMboe, or 21 percent of our net proved undeveloped reserves as of December 31, 2012, were converted to proved developed reserves.

The reduction in previous estimates is the result of the reclassification to unproved reserves of proved undeveloped reserves in the province of Río Negro where we have not yet obtained our ten-year concession extension, and reducing our development assumptions and forecast of future well production volumes in certain fields in our Neuquén Basin properties due to performance and drilling that did not meet expectations during 2013. 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 2013 – Concession Contracts in Argentina” in Item 7 of this report.

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, 2013. 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
Basin	Gross	Net	Equity	Gross	Net	Equity	Gross	Net	Equity	Combined
Neuquén	596	139	175	33	8	10	53,747	12,459	15,915	28,374
Austral	62	16	—	60	16	—	11,641	3,001	—	3,001
Northwest	3	—	—	6	—	—	13,106	197	—	197
San Jorge	7	1	—	—	—	—	12,103	2,050	—	2,050
Total Argentina	668	156	175	99	24	10	90,597	17,707	15,915	33,622
Middle Magdalena	1	0.5	—	—	—	—	—	—	—	—
Llanos	3	0.6	—	—	—	—	82	16	—	—
Total Apco	672	157	175	99	24	10	90,679	17,723	15,915	33,622

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At December 31, 2013, we held the following undeveloped acreage in Argentina and Colombia:

	Undeveloped Acreage
	Gross Acres	Net	Equity	Combined
Neuquén basin	435,752	122,127	100,351	222,478
Austral basin	455,448	117,415	—	117,415
Northwest basin	280,515	4,208	—	4,208
San Jorge basin	63,479	27,864	—	27,864
Total Argentina	1,235,194	271,614	100,351	371,965
Colombia	374,281	153,846	—	153,846
Total Apco	1,609,475	425,460	100,351	525,811

Our Neuquén basin properties have various concession terms that currently end between 2016 and 2034.  Apco and its operating partner are negotiating to secure the remaining ten-year extension for one concession which would extend the term to 2026. Approximately 21 percent and 11 percent of our undeveloped acreage in our Neuquén basin properties is subject to exploration permits that expire in 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 2021 to 2036.  Our acreage in Colombia is held under exploration and production contracts with exploration periods that expire in 2014 and 2015 that can be extended if 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.

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 newer 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, 2013, 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

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inception. As of December 31, 2013, Petrolera had 112 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, Punta Rosada and Vaca Muerta 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 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 2014.

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 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, we are developing new fields in the eastern and western part of the concession.

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.  A portion of the Agua Amarga area covering approximately 22,900 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. During 2013, we drilled two additional wells to fulfill our exploration investment commitments in the remaining permit area.

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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. During 2013, the Jarilla Quemada x-1 well began natural gas production, and we drilled an appraisal well that is also productive from the Tordillo and Molles formations.

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.

In early 2012, we received 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 to investigate unconventional potential from the Vaca Muerta, Molles and Lotena formations in the block.  During 2013, we spent approximately $6.5 million for these commitments, and the exploration period was extended until November 2014. We estimate that we will spend approximately $3 million in remaining commitments for 2014. At the end of the exploration period, we will determine how much of the area will be converted to an exploitation concession and how much acreage, if any, will be relinquished or extended through additional commitments.  

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, Molles, Lajas and Precuyo formations, 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 2013, see "MD&A – Overview of 2013 – 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.

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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.  In 2013, we received provincial approval to extend the term of our concessions by ten years. The terms for all three concessions run through August 2026. 

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, our partner funded the drilling of two exploration wells during 2013 and our interest in the exploratory area was reduced to 44 percent. The wells are scheduled to be tested during the first half of 2014.

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 2013, we continued exploration and appraisal drilling and continued acquiring 3D seismic information for future drilling as described below.

Llanos Basin

In 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 Verano Energy (previously 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.  Two exploration wells were drilled on Llanos 32 during 2012 and resulted in exploration discoveries in the Mirador and Guadalupe formations. During 2013, we participated in the drilling of two additional wells and the acquisition of 3D seismic information in the southern part of the block. For a full discussion of these activities, see "MD&A – Overview of 2013 – Colombian Properties” in Item 7 of this report. We expect to continue exploring and evaluating the block through 2015. We plan to drill three exploration wells in Llanos 32 during 2014.

Apco was awarded a 50 percent interest in the Llanos 40 block in the 2010 licensing round. Parex Resources, Inc., a Canadian junior exploration and production company, also 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.  During 2013, we completed the interpretation of 3D seismic information acquired in 2012 and began location construction for spudding our first of four wells to be drilled in succession during 2014 targeting the Carbonera and Mirador formations.   

Middle Magdalena Basin

We entered the Turpial block in 2009.  Turpial covers approximately 111,000 acres of under-explored area between the Velazquez and Cocorna oil fields in the Middle Magdalena basin. During 2013, we executed a farm-out agreement under which we will assign a portion of our working interest in the Turpial block of Colombia subject to governmental approval. The terms of the agreement include a reimbursement of past seismic and drilling costs incurred by us for approximately $8.4 million and a carry of current and future exploration investments. A committed exploration well planned for 2013 has been delayed until first quarter 2014.

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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,
	2013				2012				2011
Sales Volumes (1, 2, 3):
Consolidated interests
Crude oil and condensate (Bbls)	1,451,996				1,515,361				1,359,163
Natural gas (Mcf)	5,818,796				6,037,501				6,301,114
LPG (tons)	9,663				10,920				11,108
Barrels of oil equivalent (Boe)	2,535,191		55	%	2,649,757		54	%	2,539,701		54	%
Equity interests
Crude oil and condensate (Bbls)	1,471,758				1,614,457				1,583,806
Natural gas (Mcf)	2,679,410				2,837,649				2,833,101
LPG (tons)	11,024				11,477				11,519
Barrels of oil equivalent (Boe)	2,047,693		45	%	2,222,081		46	%	2,191,165		46	%
Total volumes
Crude oil and condensate (Bbls)	2,923,754				3,129,818				2,942,969
Natural gas (Mcf)	8,498,206				8,875,150				9,134,215
LPG (tons)	20,687				22,397				22,627
Barrels of oil equivalent (Boe)	4,582,884		100	%	4,871,838		100	%	4,730,866		100	%
Total volumes by basin
Neuquén	3,716,936		81	%	4,011,651		82	%	3,907,207		83	%
Austral	614,181		13	%	609,424		13	%	616,746		13	%
Llanos	121,714		3	%	78,755		2	%	—		—	%
Others	130,053		2	%	172,008		3	%	206,913		4	%
Barrels of oil equivalent (Boe)	4,582,884		100	%	4,871,838		100	%	4,730,866		100	%
Average Sales Prices:
Consolidated interests
Oil (per Bbl)	$	78.14			$	74.90			$	62.21
Natural gas (per Mcf)	3.01				2.56				2.10
LPG (per ton)	210.39				254.76				314.46
Equity interests
Oil (per Bbl)	$	77.36			$	74.78			$	62.39
Natural gas (per Mcf)	3.32				2.81				2.00
LPG (per ton)	194.93				251.72				302.11
Average Production Costs (4) per Boe:
Production and lifting cost	$	14.19			$	11.71			$	10.01
Taxes other than income	9.29				8.82				8.23
DD&A	12.98				10.10				8.13

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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.

	2013			2012			2011
	Gross	Net Consolidated	Net Equity	Gross	Net Consolidated	Net Equity	Gross	Net Consolidated	Net Equity
Development:
Productive	26.0	6.4	6.9	32.0	7.9	9.0	30.0	6.9	9.0
Non-Productive	—	—	—	—	—	—	—	—	—
Total	26.0	6.4	6.9	32.0	7.9	9.0	30.0	6.9	9.0
Exploratory:
Productive	3.0	1.0	0.6	5.0	1.3	0.6	7.0	2.1	1.5
Non-Productive	2.0	0.7	—	—	—	—	—	—	—
Total	5.0	1.7	0.6	5.0	1.3	0.6	7.0	2.1	1.5
Total:
Productive	29.0	7.4	7.5	37.0	9.2	9.6	37.0	9.0	10.5
Non-Productive	2.0	0.7	—	—	—	—	—	—	—
Total	31.0	8.1	7.5	37.0	9.2	9.6	37.0	9.0	10.5

Present Activities

At December 31, 2013, we had three gross development wells and four exploration wells (2.3 net consolidated 0.6 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

Our 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, dividend taxes, and other production taxes such as provincial production taxes and turnover taxes. Labor laws and provincial environmental regulations are also in place.

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

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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. Approximately 90 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 six active refiners. As a result, our oil sales have historically depended on a relatively limited group of customers. The largest of these companies refines mostly its own crude oil production, while the smallest 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 pace of production 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 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).

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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. 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 production in the country has 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

As of February 27, 2014, we had 28 full-time employees.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

We are a Cayman Islands exempted limited company with executive offices in Tulsa, Oklahoma, a branch office 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 Islands, Panama and the Bahamas, a bank account in Tulsa, Oklahoma, and furniture and equipment in our executive offices. Approximatly 99 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

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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.

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

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

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

• Aging infrastructure and mechanical problems;

• Damages to pipelines and pipeline blockages;

• Fires, blowouts, cratering, and explosions;

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

• Formations with abnormal pressures;

• Operator error;

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

• Pollution and other environmental risks;

• Risks related to truck loading and unloading; and

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

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, 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

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

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

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

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations.  If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change.  

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 six active refiners.  As a result, our oil sales have historically depended on a relatively narrow group of customers.  The largest of these companies refines mostly its own crude oil production, while the smallest 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 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 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 2013 – 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. 

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

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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 2013 – 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 a portion of our natural gas volumes 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.

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.

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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 six 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.  In 2013, WPX began efforts to dispose of its interests in Apco. 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 2014 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 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 2014 Proxy Statement, which information is incorporated by reference herein.

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Our executive officers and certain other persons who provide services to us at our 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 2014 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.

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

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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.

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.

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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 STOCKHOLDER 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 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, 2014, there were 9,139,648 of the Company’s ordinary shares, $0.01 par value, outstanding, held by approximately 443 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:

	2013			2012
Quarter	High	Low	Dividend	High	Low	Dividend
1st	$15.44	$12.22	$—	$83.35	$65.20	$0.02
2nd	$13.67	$8.82	$—	$68.28	$17.24	$—
3rd	$17.64	$11.50	$—	$23.30	$15.17	$—
4th	$16.50	$13.32	$—	$16.37	$8.88	$—

* 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 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, 2008. 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, 2013 and 2012, and for each of the three years in the period ended December 31, 2013, 2012, and 2011 should be read in conjunction with "MD&A" in Item 7 of this report and Financial Statements and Supplementary data in Item 8 of this report. The following financial data at December 31, 2011, 2010 and 2009, and for the years ended December 31, 2010 and 2009, 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,	2013			2012			2011			2010			2009
Results of Operations
Revenues	$	149,023		$	133,263		$	104,780		$	87,815		$	72,716
Equity income from Argentine investment	19,807			26,378			20,496			16,158			14,143
Net income	18,534			39,113			31,787			25,834			23,527
Amounts attributable to Apco:
Net income	18,496			39,061			31,746			25,800			23,497
Income per share	0.63			1.33			1.08			0.88			0.80
Dividends declared per share	—			0.02			0.08			0.08			0.08
Financial Position
Total assets	375,254			336,707			282,996			248,189			224,191
Total long-term liabilities	22,569			11,595			6,024			2,709			3,047
Total liabilities	59,796			39,731			24,358			18,731			18,354
Total equity	315,458			296,976			258,638			229,458			205,837
Market Capitalization (a)	458,989			362,422			2,405,938			1,692,871			650,651
Cash Flow
Cash provided by operating activities	59,519			44,810			43,965			39,038			29,236
Capital expenditures	(49,894		)	(54,413		)	(36,871		)	(33,829		)	(32,202		)
Cash (used) provided by all other investing activities, net	12,059			2,602			(4,324		)	—			1,097
Cash dividends paid	(25		)	(1,217		)	(2,381		)	(2,379		)	(10,317		)
Cash (used) provided by all other financing activities, net	(500		)	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, 2013, 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 among the most attractive in South America. After several years of positioning Apco for opportunities in Colombia, including initial successful exploration drilling in 2012, 2014 will be the most significant year for exploration drilling in all of our blocks.

Net income attributable to Apco for 2013 was $18.5 million compared with $39.1 million for 2012.  The decrease in net income for 2013 compared with 2012 is primarily a result of higher income tax expense including $14.1 million from non-cash deferred income tax expense related to new tax legislation enacted by the Argentine government in the third quarter of 2013. For additional discussion about the government's regulations and their impact to Apco, see Note 10 - Income Taxes to our consolidated financial statements in Item 8 of this report and "Quantitative and Qualitative Disclosures about Market Risk - Economic and Political Environment" in Item 7A of this report.

The unfavorable change in net income for 2013 compared with 2012 was also impacted by lower sales volumes caused by rig availability and prolonged concession extension negotiations, higher operating costs and expenses, and lower equity income. Partially offsetting these changes to net income were benefits realized from the Oil Plus hydrocarbon subsidy program in Argentina and higher oil and natural gas sales prices in 2013.

Although we have benefited from the improved commodity price environment in Argentina during 2013, 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 we have experienced significant increases in our U.S. dollar cost of operations and capital expenditures.  During 2013, the value of the Argentine peso declined by 33 percent against the U.S. dollar with estimated inflation in the country of approximately 28 percent. Subsequent to December 31, 2013, the value of the peso has declined an additional 21 percent as of February 28, 2014. In addition, although our oil prices in Argentina are negotiated and denominated in U.S. dollars, we are paid in pesos, making our oil price realizations sensitive to currency devaluation. Government intervention, foreign-exchange and capital controls, the collection of revenues in pesos, and continued peso devaluation present significant risks to future income levels expressed in U.S. dollars and the timing and value of repatriations of cash from our Argentine operations. Furthermore, at the balance sheet date our net monetary assets and liabilities denominated in pesos are remeasured into our functional currency, which is the U.S. dollar, at the official exchange rate. In Argentina, a parallel market rate exists and was approximately 37 percent greater than the official exchange rate at December 31, 2013. For further discussion about our net monetary assets and liabilities denominated in pesos and the potential impact of changes in exchange rates, see, “Quantitative and Qualitative Disclosures about Market Risk – Inflation, Foreign Currency and Operations Risk – Economic and Political Environment” in Item 7A of this report.

Overview

Operational Update

Our 2013 capital expenditures totaled approximately $50 million in 2013, including the drilling and completion of 31 gross wells, compared with $66 million originally planned for the year to drill 48 gross wells. Our development and exploration drilling program for 2013 experienced delays compared to our planned activity primarily due to constrained rig availability and prolonged concession extension negotiations. Consequently, growth in production volumes from drilling activity only partially offset normal production declines during 2013 compared with the 2012. In comparison, we participated in the drilling of 37 wells in 2012 and 2011.

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In Argentina, the stated objective of the government is to increase oil and natural gas production through increased investments by YPF S.A. ("YPF"), now majority owned by the Argentine government. YPF announced an aggressive multi-year investment plan to achieve that objective and various joint venture partnerships to help fund its planned investments. In addition, in 2013 the government announced the creation of a trust fund of up to $2.0 billion for financing energy investments by entities owned by the government. Following these measures, YPF has contracted a significant amount of the drilling equipment and related services available during 2013. As a result, we experienced significant delays in obtaining equipment to drill planned wells in our Coirón Amargo, Tierra del Fuego and Sur Río Deseado properties this year. The lack of readily available drilling equipment continues to hamper our ability to stem production declines from our mature properties in the near term.

In our Neuquén basin properties, we participated in the drilling of 25 development wells and three exploration wells during 2013. At the end of the year, an additional four wells spud in 2013 were in various stages of drilling or completion. Our exploration drilling resulted in a natural gas discovery in the western part of the Bajada del Palo concession known as Aguada del Poncho, an oil discovery in the Agua Amarga permit and a well in Coirón Amargo which we considered to be impaired. Two of the wells in progress at year-end are targeting the Vaca Muerta formation and we plan to complete those wells in 2014.   

In Colombia, we drilled two wells in the Llanos 32 block during the year. The first well, the Bandola #1, was drilled near the Maniceño discovery drilled in 2012 and was completed and put on production from the Mirador formation in the second quarter. The second well, the Llanita #1, was drilled on a prospect in the southern half of the block and was determined to be unproductive. After drilling the Samaria Norte No. 1 well at the end of 2012, we put the well on production in the fourth quarter 2013. The well produced 12.1 degree API gravity oil from the Guadalupe formation. The combination of low net-backs for heavy crude oil, high operating costs and declining forward oil prices resulted in a $3 million impairment recorded in fourth quarter 2013 (see Note 5 of Notes to Consolidated Financial Statements). In Block 32 we also participated in the acquisition of approximately 98 square kilometers of 3D seismic information. For 2014 we plan to drill three exploration wells on the block in the area covered by our newly acquired seismic information. We have a 20 percent working interest in Llanos 32.

In the Llanos 40 block of Colombia where we have a 50 percent working interest, we built drilling locations and drilled the first well of a four-well exploration drilling campaign in January of 2014. We completed the well for testing and commenced drilling a second well.

In the second quarter of 2013, we executed a farm-out agreement under which we will assign a portion of our working interest in the Turpial block of Colombia subject to governmental approval. The terms of the agreement include a reimbursement of past seismic and drilling costs incurred by us for approximately $8.4 million and a carry of current and future exploration investments. In 2013, we completed and tested the Turpiales-1 exploration well spud in 2012. The well is capable of production and we are evaluating the viability of a long-term production test for this well. A committed exploration well originally scheduled for 2013 has been delayed until first quarter 2014. We committed to drill another exploration well by third quarter 2014.

Concession Contracts in Argentina

The primary term for the portion of the Entre Lomas concession located in Río Negro currently ends in 2016. Approximately one half of the Entre Lomas concession, including our largest producing field, is located in the province of Río Negro.  Formal negotiations with the province of Río Negro for the extension of the concession began in May 2013 and we expect to obtain all required approvals during 2014. The requirements for extension generally include the negotiation of a cash bonus payment, an increase to provincial production taxes, and a future expenditure program.  

In July of 2013, we received provincial approval to extend the term of our concessions in Tierra del Fuego by ten years.  The ten-year extensions for all three concessions run through August 2026. 

In October, we received a one-year extension of the exploration permit for the southern part of the Coirón Amargo area. The permit is scheduled to expire in November 2014.

Outlook

Our oil price realizations in December 2013 were approximately $82 per barrel. Given the devaluation experienced in early 2014, our oil price realizations for our Medanito production in the Neuquén basin have been renegotiated to levels ranging from $71.40 in January to $79.89 in April, and we expect our realizations to increase to recent levels for the remainder of the year and average about $79 per barrel for 2014. We plan to participate in the drilling of 54 gross wells in 2014. The

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increase in drilling activity planned for 2014 is primarily due to obtaining the ten-year concession extensions related to our Tierra del Fuego properties and greater exploration drilling in Colombia, including nine exploration wells.  We anticipate our total capital expenditures in 2014 will be approximately $67 million.  For further discussion about our capital budget, see "MD&A – Liquidity and Capital Resources" in Item 7 of this report.  Our primary objectives for 2014 are as follows: 

• Continue development drilling in our core properties in the Neuquén basin, including five conventional horizontal wells;

• Contract and mobilize a rig necessary to commence development drilling in our properties in Tierra del Fuego;

• Continue investigating the productive potential of the Vaca Muerta and Molles shales in our properties in the Neuquén basin through exploration drilling and well re-completions;

• Conclude formal negotiations with the province of Río Negro for the ten-year concession extensions for our Entre Lomas concession;

• Complete and test exploration wells drilled in the Sur Río Deseado Este concession in southern Argentina; and

• Continue exploration drilling in Colombia, including three wells on Llanos 32, four wells on Llanos 40 and two wells on the Turpial block.

Potential risks or obstacles that could impact the execution of our plan include:

• Changes in the political and regulatory environments where we do business, including economic, market, currency, and political instability in Argentina;

• Lower than anticipated commodity price realizations;

• Increase in the cost of, or shortages or delays in the availability of drilling rigs and related equipment and labor;

• Further delays to extend our participation in the Entre Lomas concession in the province of Río Negro; and

• Lower than expected levels of cash flow from operations.

Oil and Natural Gas Marketing

Oil Prices

Oil prices have a significant impact on our ability to generate earnings and fund capital projects.  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 high crude oil prices on Argentina’s economy and manage inflation, the Argentine government maintains an oil export tax and price controls over gasoline 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.

Gradual increases in gasoline prices over the past several years 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 $78.14 for 2013 compared with $74.90 for 2012 and $62.21 in 2011. The favorable impact of higher price realizations in Colombia was not material to our consolidated average price for 2013 and 2012.

After the approximate 21 percent devaluation of the Argentine peso experienced in early 2014, the Argentine government participated in negotiations between producers and refiners to adjust oil prices in the short term to lower the cost of hydrocarbon products in peso values. Subsequent to the devaluation, oil price realizations for our Medanito production from the Neuquén basin were agreed to be $71.40 for January and February, $75.74 for March, and $79.89 for April. We expect prices will stabilize throughout the remainder of the year; however, we cannot accurately predict how world oil prices will evolve in 2014 and beyond or what additional actions the Argentine government will take in response to future fluctuations in world oil prices, the drop in the level of the country’s oil reserves or in reaction to changes in the country’s fiscal and trade balances.

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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 who incur export duties.

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).  In February 2012, the Argentine government suspended 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. In 2013, the government allowed companies producing relatively smaller amounts of production to apply for subsidies. During 2013, third parties were allowed to utilize approximately $15 million of tax certificates that had originally been granted to Apco. We have qualified and applied for additional subsidies under this program, but we cannot predict if Apco will be able to recognize any further benefits from this program.

In order to reverse the trend of declining reserves, and provide incentives for gas development, in 2013 the government proposed a mechanism to realize higher natural gas prices. The program allows producers 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. We have requested to participate in this program, but the government has not initiated this program to date.

Natural Gas Prices

Similar to the case of oil prices in Argentina, natural gas price realizations are significantly influenced by Argentine governmental actions. The Argentine government regulates the supply of natural gas and provides the framework for natural gas prices in the domestic market. The framework is intended to provide equitable sharing of all sectors of the internal natural gas market among producers and establishes a mechanism for doing so based on historical production. Government regulation 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 allocated per the regulations, 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. 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.

Our average natural gas sale price per Mcf averaged $3.01 in 2013, $2.56 in 2012, and $2.10 during 2011. These prices are an average of our natural gas sold to Argentine customers pursuant to contracts and spot market sales.

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 2014 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.

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 2013, natural gas sales represented 12 percent of our total operating revenues compared with 12 percent in 2012 and 13 percent in 2011.  Consequently, the fluctuation in natural gas sales between summer and winter is not significant to us.

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

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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. One 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 concession 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 2013, 2012 and 2011 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.

Due to high operating costs and a downward revision in reserves from a producing property in Colombia, we assessed the property using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of reserves quantities, estimates of future commodity prices (primarily oil using a forward NYMEX curve adjusted for quality and locational basis differentials), expected operating and capital costs, and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates. The assessment identified that the property's carrying value was in excess of the undiscounted cash flows and the calculated fair values. As a result, we recognized $3.3 million of impairment charges in 2013. See Note 15 of Notes to Consolidated Financial Statements for additional discussion and significant inputs into the fair value determination.

In addition to the long-lived assets described above for which an impairment charge was recorded, certain other properties were reviewed for which no impairment was required. These reviews included other producing properties and utilized inputs generally consistent with those described above. Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. 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 $7.0 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.

Depending upon the results of certain future exploration activities, we could determine that certain unproved properties need to be impaired as we drill and evaluate those areas.  We have $5.7 million of costs for exploratory wells pending the determination of proved reserves.  If our exploration activity planned for 2014 is unsuccessful, we may have to recognize an impairment loss related to these assets. See Note 4 of Notes to Consolidated Financial Statements for additional discussion about our exploratory wells pending the determination of proved reserves.

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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,
	2013		$ Change from 2012		% Change from 2012		2012		$ Change from 2011		% Change from 2011		2011
	(Amounts in Thousands)
Operating revenues	$	149,023	15,760		12	%	$	133,263	28,483		27	%	$	104,780
Total costs and operating expenses	120,621		(13,429	)	-13	%	107,192		(23,636	)	-28	%	83,556
Operating income	28,402		2,331		9	%	26,071		4,847		23	%	21,224
Investment income	20,713		(5,395	)	-21	%	26,108		5,482		27	%	20,626
Income taxes	30,581		(17,515	)	-134	%	13,066		(3,003	)	-30	%	10,063
Net Income	18,534						39,113						31,787
Less: Net income attributable to
noncontrolling interests	38		14		27	%	52		(11	)	-27	%	41
Net income attributable to Apco	$	18,496	(20,565	)	-53	%	$	39,061	7,315		23	%	$	31,746

Net Income

2013 vs. 2012Our Net income attributable to Apco for 2013 was $18.5 million, a decrease of $20.6 million compared with 2012.  The decrease in Net income attributable to Apco compared with 2012 is primarily a result of higher income tax expense including $14.1 million for a non-cash deferred income tax expense related to new tax legislation enacted by the Argentine government in the third quarter of 2013. For additional discussion about the government's regulations and their impact to Apco, see Note 10 - Income Taxes to our consolidated financial statements in Item 8 of this report and "Quantitative and Qualitative Disclosures about Market Risk - Economic and Political Environment" in Item 7A of this report. The unfavorable change in net income was also impacted by lower sales volumes, higher operating costs and expenses, a non-cash impairment charge and lower equity income. Partially offsetting these changes to net income were benefits realized from the Oil Plus hydrocarbon subsidy program in Argentina and higher oil and natural gas sales prices in 2013.

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.

Total Operating Revenues

Operating revenues for 2013 increased by $15.8 million compared with 2012. The increase in revenues during 2013 included the positive impact of $15.2 million in Other revenues related to benefits from the Oil Plus hydrocarbon subsidy program in Argentina. Absent the impact of these benefits, we estimate that Total revenues - including Other revenues - would have been flat compared with 2012. 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 2011 to 2013 for our consolidated interests accounted for as operating revenues are shown in the following tables. 

	Year Ended December 31,
	2013		% Change		2012		% Change		2011
Sales Volumes
Consolidated interests
Oil (Bbls)	1,451,996		-4	%	1,515,361		11	%	1,359,163
Natural Gas (Mcf)	5,818,796		-4	%	6,037,501		-4	%	6,301,114
LPG (tons)	9,663		-12	%	10,920		-2	%	11,108
Oil, Natural Gas and LPG (Boe)	2,535,191		-4	%	2,649,757		4	%	2,539,701
Average Sales Prices
Consolidated interests
Oil (per Bbl)	$	78.14	4	%	$	74.90	20	%	$	62.21
Natural Gas (per Mcf)	3.01		17	%	2.56		22	%	2.10
LPG (per ton)	210.39		-17	%	254.76		-19	%	314.46
Revenues ($ in thousands)
Oil revenues	$	113,459	0	%	$	113,498	34	%	$	84,553
Natural Gas revenues	17,501		13	%	15,447		17	%	13,257
LPG revenues	2,033		-27	%	2,782		-20	%	3,493
	$	132,993	1	%	$	131,727	30	%	$	101,303

The volume and price changes in the table above caused the following changes to our oil, natural gas and LPG revenues from 2011 to 2013.

	Oil			Gas			LPG			Total
	(Amounts in Thousands)
2011 Sales	$	84,553		$	13,257		$	3,493		$	101,303
Changes due to volumes	11,699			(675		)	(48		)	10,976
Changes due to prices	17,246			2,864			(663		)	19,447
2012 Sales	113,498			15,447			2,782			131,727
Changes due to volumes	(4,951		)	(658		)	(264		)	(5,873		)
Changes due to prices	4,912			2,712			(485		)	7,139
2013 Sales	$	113,459		$	17,501		$	2,033		$	132,993

Oil Revenues

2013 vs. 2012During 2013, Oil revenues were flat compared with 2012. For 2013, the benefit of higher average oil sales prices was offset by a 4 percent decrease in volumes compared with 2012.  For further explanation of oil sales prices, see “MD&A – Oil and Natural Gas Marketing – Oil Prices” in Item 7 of this report. The decline in volumes is attributable to our Argentine operations and was caused by the combination of delayed investment activities from rig availability and prolonged concession extension negotiations and the performance of new wells.

2012 vs. 2011During 2012, Oil revenues increased by $28.9 million, or 34 percent compared with 2011, due to higher higher average oil sales prices combined with an 11 percent increase in oil sales volumes. 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.

Natural Gas Revenues

2013 vs. 2012  Natural gas revenues increased by $2.1 million, or 13 percent compared with 2012.  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.

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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.

Other Operating Revenues

2013 vs. 2012  Other operating revenues increased by $14.5 million during 2013 compared with 2012 primarily due to the the utilization of $15.2 million for government tax credit certificates in Argentina from the Oil Plus hydrocarbon subsidy program. Although we qualify for additional tax credit certificates, we cannot predict if Apco will be able to realize any additional benefits from the program in the future. For further explanation regarding the hydrocarbon subsidy program, see Note 1 - Description of Business, Basis of Presentation and Summary of Significant Accounting Policies - Other Revenues - Government Tax Credit Certificates and Note 15 - Fair Value Measurements to our consolidated financial statements in Item 8 of this report and see “MD&A – Oil and Natural Gas Marketing – Oil Prices – Hydrocarbon Subsidy Programs” in Item 7 of this report.

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 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 no longer realize this benefit. In addition, we did not recognize any benefits in 2012 from the Oil Plus hydrocarbon subsidy programs from the Argentine government.

Total Costs and Operating Expenses

2013 vs. 2012Total costs and operating expenses increased by $13.4 million, or 13 percent, primarily due to greater production and lifting costs and depreciation, depletion and amortization expense, and higher foreign exchange losses, partially offset by lower exploration expense.  Notable variances for the comparable periods include the following: 

• Production and lifting costs increased by $5 million or 16 percent, due to the impact of inflation in Argentina on our operations, increased costs associated with the growth of our operations in Coirón Amargo, and the impact of our Colombian operations which did not begin to incur operating costs until production began in the third quarter of 2012, partially offset by lower production volumes;

• Depreciation, depletion and amortization expense increased by $6.3 million due primarily to higher depreciation rates and the impact of our Colombian operations which did not begin to incur depletion expense until production began in the third quarter of 2012 (see additional discussion below);

• Exploration expense decreased by $4.3 million primarily due to lower 3D seismic acquisition costs in Argentina;

• Foreign exchange loss (gains) increased by $3.0 million compared with 2012 primarily due to the combination of higher cash balances denominated in pesos and a 33 percent devaluation of the Argentine peso in 2013; and

• Other operating expense increased by $2.3 million compared with 2012. Significant items in Other expense include an impairment of $3.3 million related to heavy-oil producing properties in Colombia during 2013. Additionally, 2013 and 2012 benefited from gains of $3.6 million and $2.8 million, respectively, recognized in other income attributable to farm-outs of part of our working interests in properties in Colombia and Argentina.

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 our 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;

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

• Exploration expense increased by $8 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 Argentina operations was offset by a gain of $498 thousand from our Colombian operations; and

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

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 2011 to 2013 are shown in the following table: 

	Year Ended December 31,
	2013		Change from 2012			% Change from 2012			2012		Change from 2011		% Change from 2011			2011
Consolidated Sales Volumes (Boe)	2,535,191		(114,566		)	(4	)%		2,649,757		110,056		4	%		2,539,701
DD&A Rate per Boe	$	12.98	$	2.88		29	%		$	10.10	$	1.98	24	%		$	8.13
DD&A Expense (In thousands)	$	32,907	$	6,147		23	%	(1)	$	26,760	$	6,116	30	%	(1)	$	20,644

⁽¹⁾ Percentage totals may not sum due to rounding

The following table details the increases in DD&A of oil and gas properties between 2011 to 2013 due to the changes in volumes and average DD&A rates presented in the table above:

	(Thousands)
2011 DD&A	$	20,644
Changes due to volumes	1,111
Changes due to rates	5,005
2012 DD&A	26,760
Changes due to volumes	(1,485		)
Changes due to rates	7,632
2013 DD&A	$	32,907

2013 vs. 2012Total DD&A (including straight-line) increased by $6.3 million in 2013 compared with 2012 primarily due to the impact of 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 the same periods of 2012. Additionally, our DD&A rates have increased as a result of a reduction in proved developed reserves experienced in the fourth quarters of 2013 and 2012 due to downward revisions of previous estimates. The increase in DD&A expense includes a full year's impact of expense related to our Colombian operations of $4.5 million during 2013 compared with $1.5 million of DD&A expense during 2012 when production began in the third quarter.

In July of 2013, we received the provincial approval for our concession extensions in Tierra del Fuego. Incremental proved reserves resulting from these extensions were included in our oil and gas depreciation calculation beginning in the third quarter of 2013, resulting in a favorable impact on the rate of depreciation for those properties compared with recent periods. We continue working to obtain the ten-year concession extension for our property in Río Negro. We expect to experience a favorable effect on future DD&A rates beginning in periods when the extension is obtained as wells whose productive lives extend beyond 2016 will result in the addition of proved developed reserves.

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Investment Income

2013 vs. 2012Total investment income decreased by $5.4 million compared with 2012 due primarily to lower Equity income from Argentine investment.  The decrease in our equity income for 2013 is due to lower net income of our equity investee, Petrolera. The comparative decrease in Petrolera’s net income is primarily a result of lower revenues driven by lower sales volumes coupled with increases in production and lifting costs, greater depreciation, depletion and amortization expense and higher foreign exchange losses. Total oil sales volumes related to our equity interests in Petrolera decreased by 7 percent in 2013 compared with 2012. The decrease in volumes for the year is due to a 9 percent decline in production volumes during 2013 compared with 2012.

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.

Income Taxes

2013 vs. 2012  Income taxes increased by $17.5 million compared with 2012 primarily due to new tax legislation in Argentina. In September 2013, the Argentine government enacted certain tax reform legislation related to capital gains and dividends. Included in the tax reform is the removal of the income tax exemption on income derived from the sale of shares, titles, bonds and other securities that has been provided to non-Argentine residents since 1991. Effective immediately, the sale of such securities is subject to an effective 13.5 percent capital gain tax on the gross proceeds. As a result of the Argentine tax reform, we recorded a $14.1 million deferred tax expense for the new capital gain tax associated with our equity investment in Petrolera. The new capital gain tax related to our equity interest in the shares of Petrolera will increase our effective tax rate in future periods, and our accrual for deferred income tax expense will increase by 13.5 percent of the amount of undistributed earnings from our investment in Petrolera. Undistributed earnings are the difference between our equity income and dividends received from our investment in Petrolera. For additional discussion about the government's regulations and their impact to Apco, see Note 10 - Income Taxes to our consolidated financial statements in Item 8 of this report.

2012 vs. 2011  Income taxes increased by $3 million compared with 2011 due to higher operating income in Argentina.  

LIQUIDITY AND CAPITAL RESOURCES

Outlook

Our cash flow from operations is highly sensitive to fluctuations in our oil price realizations. We derive more than 80 percent of our total product revenues from the sale of oil. Oil price realizations for crude produced and sold in Argentina are significantly influenced by Argentine governmental actions. Oil prices in Argentina reached approximately $80 per barrel by the end of 2013. Oil price realizations in Argentina continue to be negotiated on a short-term basis.

Inflation in Argentina has been persistent for several years.  The Argentine peso has not experienced a commensurate level of devaluation. This has resulted in considerable increases in our U.S. dollar cost of operations and capital expenditures. During 2013, the peso declined by 33 percent, with a significant amount of the devaluation impacting the second half of the year. Through February 2014, the peso declined by an additional 21 percent. As a result, the Argentine government participated in negotiations between producers and refiners to adjust oil prices in the short term to lower the cost of hydrocarbon products in peso values. Oil price realizations were agreed to be $71.40 for January and February, $75.74 for March, and $79.89 for April. We expect prices to stabilize throughout the remainder of the year. The decrease in oil prices will impact our operating margins and should lower operating income in Argentina from January through April for both Apco and Petrolera. The ultimate net impact of peso devaluation on our results of operations will depend on the actual devaluation and inflation in future periods.

In addition, dividends received from our equity investee, Petrolera, are also a significant contributor to our cash flow generated by operating activities. 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.

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

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exchange to deposit funds in foreign accounts. These restrictions require both Central Bank and AFIP (Argentina’s taxing authority) approvals. As a result, the current movement of funds out of Argentina through the Central Bank at the official exchange rate has been restricted. For example, Petrolera declared a dividend of $16.4 million pesos net to Apco (or approximately $3.2 million US dollars) in the first quarter of 2013. In the second quarter of 2013, Petrolera received permission to pay the dividend in installments.

In September 2013, the Argentine government enacted certain tax reform legislation related to dividends and capital gains. Effective upon publication, the tax reform imposes a ten percent tax on dividends, profit distributions and remittances by permanent establishments (or branches) made to Argentine individuals and foreign shareholders. This new tax will apply to our dividends received from Petrolera, branch remittances, and any dividends made by our subsidiaries. The tax reform also includes an effective 13.5 percent income tax for foreign parties (non-Argentine residents) on income derived from the sale of shares, titles, bonds and other securities. For additional discussion about the government's regulations, see Note 10 - Income Taxes to our consolidated financial statements in Item 8 of this report and "Quantitative and Qualitative Disclosures about Market Risk - Economic and Political Environment" in Item 7A of this report.

In the second quarter of 2013, we executed a farm-out agreement under which we will assign a portion of our working interest in one of our Colombian properties subject to governmental approval. The terms of the agreement include a reimbursement of past seismic and drilling costs incurred by us for approximately $8.4 million and a carry of future exploration investments.

Capital & Exploration Expenditures Budget for 2014

Our 2014 capital plan provides for $67 million of capital expenditures net to our direct working interests.  We plan to participate in the drilling of 54 gross wells in 2014.  In addition, we plan on spending approximately $1 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 2014 is $110 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 2014.  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 2014 capital expenditures with cash on hand and cash flows from operations.

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. 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.

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 historically 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.

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, we have received fewer dividends from our investment in Petrolera during 2013 and 2012 compared with prior years.  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 or farm-outs, to meet our plans and exploration commitments outside of Argentina.

Of our total cash and cash equivalents balance of $48.6 million as of December 31, 2013, approximately $15.8 million was held in Argentine peso accounts measured at the official exchange rate of 6.52:1. The remaining amount of our cash, or $32.8 million, was held in U.S. dollar accounts primarily outside of Argentina. See the effect of exchange rate changes on cash and cash equivalents during the three year period ended December 31, 2013, in our Consolidated Statement of Cash Flows in Item

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8 of this report. Although the devaluation experienced in early 2014 will have a negative impact on the U.S. dollar value of our cash held in Argentine pesos, the ultimate foreign currency gains or losses included in our results of operations will depend on the impact of changes in exchange rates on our net monetary assets denominated in pesos.

Our liquidity is also affected by restricted cash balances that are pledged as collateral for standby letters of credit for exploration activities in Colombia.  As of December 31, 2013, a total of $5.5 million was considered restricted and included in restricted cash.  We expect our restricted cash to be reduced by $5.0 million in 2014 due to fulfilling certain exploration commitments. The restricted cash is invested in a short-term money market account with a financial institution.

Cash Flow Analysis

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

Sources (Uses) of Cash

	Years Ended December 31,
	2013			2012			2011
	(Thousands)
Net cash provided (used) by:
Operating activities	$	59,519		$	44,810		$	43,965
Investing activities	(37,835		)	(51,811		)	(41,195		)
Financing activities	(525		)	4,783			(381		)

Operating Activities

Our net cash provided by operating activities in 2013 increased by $15 million compared with 2012 due primarily to the positive impact of our Colombian operations, the realization of benefits from the Oil Plus program and a decrease in exploration activity.  These positive variances were partially offset by lower dividends from our Argentine investment.

Our net cash provided by operating activities in 2012 increased by $1 million compared with 2011 due to higher operating income which was offset by lower dividends from our equity investment in Petrolera.

Included in our net cash provided by operating activities are dividends received from our equity investment in Petrolera of $3.3 million in 2013, $7.8 million in 2012 and $12.8 million in 2011. See additional discussion of dividends from our Argentine investment in “-Financial Condition” and “-Liquidity.”

Investing Activities

During 2013, capital expenditures totaled $49.9 million, most of which was invested in drilling in our Neuquén basin properties and Colombia. We received proceeds of $8.4 million related to a farm-out in Colombia during 2013, compared with proceeds of $3.1 million related to a farm-out in Argentina during 2012. Additionally, we received $3.4 million during 2013 as a return of collateral previously used for letters of credit, compared with $555 thousand used as collateral during 2012.

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 $36.9 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.

Financing Activities

We repaid $0.5 million of our bank debt during 2013 and received $6.0 million in 2012 in borrowings from an unsecured bank line of credit to fund capital expenditures.  In addition, we paid no dividends to our shareholders in 2013, $1.2 million in 2012, and $2.4 million in 2011.

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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
	2014		2015		2016		Thereafter		Total
	(Amounts in thousands)
Long-term debt
Principal	$	2,500	$	3,500	$	1,500	$	—	$	7,500
Interest	236		110		12		—		358
International oil and gas activities	17,700		—		—		—		17,700
Other long-term liabilities	—		—		—		5,211		5,211
Total	$	20,436	$	3,610	$	1,512	$	5,211	$	30,769

International oil and gas activities includes estimates for remaining drilling 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

Our 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. For example, after the approximate 23 percent devaluation of the Argentine peso experienced in January 2014, the Argentine government participated in negotiations between producers and refiners to adjust oil prices in the short term to lower the cost of hydrocarbon products in peso values. Oil price realizations for our Medanito production from the Neuquén basin were agreed to be $71.40 for January and February, $75.74 for March, and $79.89 for April. We expect our prices will approximate the April price throughout the remainder of the year; however, we cannot accurately predict what additional actions the Argentine government will take in response to the value of its currency, 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.

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. Prior to 2013, the peso was not allowed to devalue in proportion to the actual inflation experienced in the country, resulting in capital flight out of Argentina due to a lack of confidence in the value of the peso at the official exchange rate. In addition, the Central Bank of Argentina´s foreign reserves have declined from $43 billion dollars as of December 31, 2012, to an estimated $29 billion as of December 31, 2013.

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 require approvals from both the Central Bank and AFIP which are difficult to obtain.  As a result, movement of funds out of Argentina through the Central Bank at the official exchange rate has been restricted. The purchase of foreign currency for transactions such as the repayment of debt is not restricted. 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, 2013, the implicit exchange rate derived from this type of transaction was approximatly 37 percent above the official exchange rate. The resulting spread between such implicit exchange rate and the official rate of exchange was an indicator that an official devaluation of the Argentine peso may occur.

At December 31, 2012, the peso to US dollar official rate of exchange rate was 4.92:1.  At December 31, 2013, the official exchange rate was 6.52:1, representing a devaluation of 33 percent during 2013.  Subsequent to December 31, 2013, the value of the Argentine peso has declined 21 percent from 6.52:1 to 7.88:1 as of February 28, 2014. The devaluation of the peso

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experienced in early 2014 would imply estimated foreign exchange losses of approximately $1.0 million in our operating income based on our net monetary assets denominated in pesos of $6.0 million at December 31, 2013, and $0.4 million related to our equity income from the re-measurement of net monetary assets denominated in Argentine pesos held by Petrolera of $6.3 million at year end.  Additional losses could be incurred on unsettled transactions from the date of the financial statements to the transaction date. As described above, the devaluation has resulted in the negotiation of lower product price realizations. The devaluation should also reduce our peso-denominated costs when translated to US dollars during the period. In addition, the spread between the implicit exchange rate mentioned above and the official rate of exchange was 36 percent as of February 17. Although we cannot predict the outcome of any further peso devaluation, a devaluation could have a negative impact on our results of operations.

Economic and Political Environment

Argentina has a history of economic and political instability.  Because our operations are predominately located in Argentina, our operations and financial results have been, and could be in the future, adversely affected by economic, market, currency, and political instability in Argentina, as well as measures taken by its government in response to such instability.  Argentina’s economic and political situation continues to evolve, and the Argentine government may enact future regulations or policies that may materially impact, among other items, (i) the realized prices we receive for the commodities we produce and sell; (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 September 2013, the Argentine government enacted certain tax reform legislation related to dividends and capital gains. The tax reform imposes a ten percent tax on dividends, profit distributions and remittances by permanent establishments (including branches) made to Argentine individuals and foreign shareholders. The ten percent dividend tax will apply to Apco on dividends received from Petrolera, branch remittances, and any dividends paid by our subsidiaries. The dividend tax will be accrued when dividends are distributed in future periods. The tax reform also removes the income tax exemption on income derived from the sale of shares, titles, bonds and other securities that has been provided to non-Argentine residents since 1991. Effective since September, the sale of such securities is subject to an effective 13.5 percent capital gain tax. For additional discussion about the impact to Apco related to these new regulations, see Note 10 - Income Taxes to the consolidated financial statements, and "MD&A - Results of Operations" in Items 8 and 7 of this report.

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 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 created an unpredictable political and business environment in the country. During 2013, the government has attempted to freeze supermarket and gasoline prices.

Midterm legislative elections were held in October 2013. Following the elections, the president's political party maintains its control of a simple majority of both legislative houses. However, the president's party won proportionately less votes than in previous elections, and the president lacks the two-thirds majority needed to amend the constitution to permit the president to run for reelection to a third term. The president's current term expires at the end of 2015.

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. In addition, in 2013 the government announced the creation of a trust fund of up to $2.0 billion for financing oil and gas companies in which the government has an equity interest.

During 2013, YPF created partnerships with Chevron and Dow Chemicals to increase unconventional investments. YPF and Chevron announced a partnership in which Chevron will invest $1.2 billion using new capital to acquire an interest in Vaca Muerta production from certain producing assets including the Loma la Lata Norte and Loma Campana concessions. Included in the joint venture are plans for Chevron to drill 100 wells to the Vaca Muerta formation. Subsequent to the Chevron announcement, the government issued Decree 929 which allows oil companies to export 20 percent of production free from

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export tax after the fifth year for projects whose investments exceed $1 billion during the first five years. YPF and Dow Chemicals will also target Vaca Muerta in the Neuquén basin. In February 2014, YPF announced the acquisition of Apache's operations in Argentina for $852 million.

Since midterm elections in October, there have been several indications that Argentina policy making environment may be shifting toward moderation for the oil and gas industry. Export taxes for domestic oil production have been reduced and natural gas prices have been increased in an attempt to attract new investments and stem production declines. Argentina is forecasted to become a net oil importer in the near term. Government controlled YPF plans large investments to increase domestic production and has heavily relied on joint ventures to evaluate its shale potential as previously discussed. A more stable regulatory environment will assist YPF to pursue these objectives. In February 2014, the government and Repsol agreed to a settlement of their dispute over the April 2012 seizure of Repsol's 51 percent stake in YPF.  The resolution of this issue as a positive step for Argentina and its oil and gas sector.

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	46
Report of Independent Registered Public Accounting Firm	47
Report of Independent Registered Public Accounting Firm	48
Report of Independent Registered Public Accounting Firm	49
Consolidated Balance Sheets at December 31, 2013 and 2012	50
Consolidated Statements of Income and Comprehensive Income for each year in the three-year period ended December 31, 2013	51
Consolidated Statements of Changes in Equity for each year in the three-year period ended December 31, 2013	52
Consolidated Statements of Cash Flows for each year in the three-year period ended December 31, 2013	53
Notes to Consolidated Financial Statements	54

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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, 2013, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (1992). Based on our assessment, we concluded that, as of December 31, 2013, 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.

46

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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (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, 2013, 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, 2013 and 2012, 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, 2013, of Apco Oil and Gas International Inc. and our report dated March 6, 2014, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma

March 6, 2014

47

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, 2013 and 2012, 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, 2013. 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 constituting 9% in 2013 and 9% in 2012 and total revenues constituting 11% in 2013, 11% in 2012, and 14% in 2011 of related consolidated totals. 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, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated March 6, 2014, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma

March 6, 2014

48

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, 2013 and 2012, and the related statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013 and 2012, and the results of its operations, the changes in its shareholders' equity and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

Buenos Aires City, Argentina

February 28, 2014

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

Diego O. DeVivo

Partner

49

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2013			2012
	(Amounts in thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	48,566		$	32,669
Accounts receivable	17,209			19,208
Inventory	5,295			4,074
Restricted cash	5,040			3,749
Other current assets	11,232			4,877
Total current assets	87,342			64,577
Property and Equipment:
Cost, successful efforts method of accounting	352,011			313,323
Accumulated depreciation, depletion and amortization	(190,716		)	(157,907		)
	161,295			155,416
Argentine investment, equity method	125,244			108,710
Deferred income tax asset	—			1,254
Restricted cash	470			5,170
Other assets (net of allowance of $369 at December 31, 2013 and $486 at December 31, 2012)	903			1,580
Total Assets	$	375,254		$	336,707
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	16,935		$	13,983
Affiliate payables	877			716
Accrued liabilities	12,331			8,790
Income taxes payable	7,084			4,647
Total current liabilities	37,227			28,136
Long-term debt	5,000			7,500
Deferred income tax liability	12,358			—
Long-term liabilities	5,211			4,095
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	(1,624		)	(1,597		)
Retained earnings	307,427			288,931
Total shareholders' equity	315,203			296,734
Noncontrolling interests in consolidated subsidiaries	255			242
Total equity	315,458			296,976
Total liabilities and equity	$	375,254		$	336,707

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

50

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	For the Years Ended December 31,
	2013			2012			2011
	(Amounts in thousands except per share amounts)
REVENUES:
Oil revenues (Note 7)	$	113,459		$	113,498		$	84,553
Natural gas revenues (Note 7)	17,501			15,447			13,257
LPG revenues	2,033			2,782			3,493
Other	16,030			1,536			3,477
Total operating revenues	149,023			133,263			104,780
COSTS AND OPERATING EXPENSES:
Production and lifting costs	35,979			31,020			25,432
Taxes other than income	23,556			23,379			20,913
Transportation and storage	2,592			2,268			888
Selling and administrative (Note 7)	14,479			13,846			10,907
Depreciation, depletion and amortization	33,174			26,904			20,703
Exploration expense	6,885			11,152			3,103
Foreign exchange losses	3,303			300			91
Other expense (income)	653			(1,677		)	1,519
Total costs and operating expenses	120,621			107,192			83,556
TOTAL OPERATING INCOME	28,402			26,071			21,224
INVESTMENT INCOME
Interest and other income	906			(270		)	130
Equity income from Argentine investment	19,807			26,378			20,496
Total investment income	20,713			26,108			20,626
Income before income taxes	49,115			52,179			41,850
Income taxes	30,581			13,066			10,063
NET INCOME	18,534			39,113			31,787
Less: Net income attributable to noncontrolling interests	38			52			41
Net Income attributable to Apco Oil and Gas International Inc.	$	18,496		$	39,061		$	31,746
OTHER COMPREHENSIVE INCOME:
Pension plan liability adjustment in consolidated and equity interests (net of Argentine taxes of $15 in 2013, $80 in 2012, and $122 in 2011)	(27		)	(147		)	(226		)
Comprehensive income attributable to Apco Oil and Gas International Inc.	$	18,469		$	38,914		$	31,520
Amounts attributable to Apco Oil and Gas International Inc.:
Earnings per share – basic and diluted:
NET INCOME PER SHARE	$	0.63		$	1.33		$	1.08
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.

51

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, 2011   (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 ($0.08 per share)	—			—		—		—			(589		)	(589		)	(39		)	(628		)
BALANCE, December 31, 2012  (1)	91			203		9,106		(1,597		)	288,931			296,734			242			296,976
Comprehensive Income:
Net Income	—					—		—			18,496			18,496			38			18,534
Other Comprehensive income (loss)	—			—		—		(27		)	—			(27		)	—			(27		)
Total Comprehensive Income																				18,507
Dividends declared ($0.02 per share)	—			—		—		—			—			—			(25		)	(25		)
BALANCE, December 31, 2013  (1)	$	91		$	203	$	9,106	$	(1,624	)	$	307,427		$	315,203		$	255		$	315,458

(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.

52

APCO OIL AND GAS INTERNATIONAL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)	For the Years Ended December 31,
	2013			2012			2011
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	18,534			$	39,113		$	31,787
Adjustments to reconcile to net cash provided by operating activities:
Equity income from Argentine investment	(19,807		)	(26,378		)	(20,496		)
Dividends received from Argentine investment	3,257			7,794			12,813
Deferred income tax (benefit)	13,230			(1		)	(288		)
Depreciation, depletion and amortization	33,174			26,904			20,703
Provision for loss on property, plant & equipment	7,053			2,787			1,057
Recovery of costs on sale of properties	(3,642		)	(2,809		)	—
Changes in accounts receivable	1,999			(8,063		)	611
Changes in inventory	(1,250		)	(1,184		)	(608		)
Changes in other current assets	(6,382		)	(977		)	(1,075		)
Changes in accounts payable	2,334			791			(2,593		)
Changes in affiliate payables	161			(554		)	973
Changes in accrued liabilities	2,541			2,445			1,435
Changes in income taxes payable	2,437			2,120			(721		)
Effect of exchange rate changes on cash and cash equivalents, and changes in other assets and liabilities	5,880			2,822			367
Net cash provided by operating activities	59,519			44,810			43,965
CASH FLOW FROM INVESTING ACTIVITIES:
Property plant and equipment:
Capital expenditures *	(49,894		)	(54,413		)	(36,871		)
Sale of properties	8,440			3,087			—
Changes in long-term investments	210			70			40
Changes in restricted cash	3,409			(555		)	(4,364		)
Net cash used in investing activities	(37,835		)	(51,811		)	(41,195		)
CASH FLOW FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	—			6,000			2,000
Repayments of long-term debt	(500		)	—			—
Dividends paid to noncontrolling interest	(25		)	(39		)	(26		)
Dividends paid	—			(1,178		)	(2,355		)
Net cash used in financing activities	(525		)	4,783			(381		)
Effect of exchange rate changes on cash and cash equivalents	(5,262		)	(2,012		)	(724		)
Increase (decrease) in cash and cash equivalents	15,897			(4,230		)	1,665
Cash and cash equivalents at beginning of period	32,669			36,899			35,234
Cash and cash equivalents at end of period	$	48,566		$	32,669		$	36,899
Supplemental disclosures of cash flow information:
Interest paid	$	340		$	193		$	—
Cash paid during the year for income taxes	$	13,390		$	10,195		$	10,601
________________________
*  Increases to property plant and equipment, net of asset dispositions	$	(38,688	)	$	(56,437	)	$	(39,995	)
Provision for loss on PP&E	(7,389		)	(2,787		)	(1,057		)
Recovery of unproved costs	(4,798		)	(278		)	—
Changes in related accounts payable and accrued liabilities	981			5,089			4,181
Capital expenditures	$	(49,894	)	$	(54,413	)	$	(36,871	)

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

53

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. ("Apco") is 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.

Apco began E&P activities in Argentina in the late 1960s, and as of December 31, 2013, had interests in nine oil and gas producing concessions and two exploration permits in Argentina. E&P activities in Colombia began in 2009 where we have three exploration and production contracts.  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. 

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.”

Relationship with WPX Energy, Inc.

WPX Energy, Inc. (“WPX”), an independent exploration and production company with operations primarily in North America, owns 68.96 percent of our aggregate Class A and ordinary shares.  On June 30, 2011 our shareholders authorized our Board of Directors to issue a separate 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. 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 ordinary shares in the event that WPX, does not own, 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. In 2013, WPX began efforts to dispose of its interests in Apco.

We are managed by employees of WPX, and all of our executive officers and three of our directors are employees of WPX. Pursuant to an administrative services agreement, WPX provides us with administrative, legal, and management services, as well as office space.  We have branch offices in Buenos Aires, Argentina and Bogotá, Colombia. These offices are staffed by employees of Apco and/or contractors retained by us.

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of Apco Oil and Gas International Inc. (a Cayman Islands exempted limited company) and its subsidiaries, Apco Properties Ltd. (a Cayman Islands limited 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.” We also sometimes refer to Apco as the “Company.”

Our consolidated financial statements include the proportional consolidation of our direct interests of the accounts of our joint ventures in Argentina, and our proportionate share of revenues, operating costs and capital expenditures for our operations in Colombia. All intercompany balances and transactions between Apco and its subsidiaries have been eliminated in consolidation. As mentioned above, we account for our 40.72 percent equity interest in Petrolera under the equity method.

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

54

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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.

Reclassifications

Certain prior period amounts have been reclassified to conform with current period presentation.

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)	Years Ended December 31,						As of December 31,
	2013		2012		2011		2013		2012
Argentina	$	137.6	$	126.3	$	104.8	$	155.6	$	143.0
Colombia	11.4		7.0		—		5.7		12.4
Total	$	149.0	$	133.3	$	104.8	$	161.3	$	155.4

(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.

Other Revenues - 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, where the government created various hydrocarbon subsidy programs to promote increased oil production and reserves. The programs grant qualifying companies economic benefits in the form of tax credit certificates that can be utilized to offset export taxes on hydrocarbon exports or can be transferred to third parties at face value. Realized and unrealized gains from these certificates are reported in Other revenues in our Consolidated Statements of Income and Comprehensive Income. See Note 15 for additional discussion about these programs.

Value-Added Tax Collections – Tierra del Fuego

A portion of our Other operating revenues (zero in 2013, $933 thousand in 2012, and $2.0 million in 2011) relates to value-added tax collections related to hydrocarbon sales revenues from our operations in Tierra del Fuego.  Prior to May of 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. We have not realized any revenues from this benefit since the removal of the exemption in 2012.

55

APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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. Included in the balance of cash and cash equivalents is $15.8 million and $11.3 million of cash denominated in Argentine pesos as of December 31, 2013, and 2012, respectively. These cash balances were measured in U.S. dollars using peso to U.S. dollar exchange rates of 6.52:1 and 4.92:1 as of December 31, 2013, and 2012, respectively. See the effect of exchange rate changes on cash balances held in foreign currencies in the Consolidated Statements of Cash Flows.

Accounts Receivable

Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.

Inventory Valuation

Our inventory includes hydrocarbons produced but not sold of $1.3 million in 2013 and $1.1 million in 2012, which are accounted for at production cost, and spare-parts materials of $4.0 million in 2013 and $3.0 million in 2012, 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. Our proved reserves are limited to the concession life even though a concession’s term may be extended for 10 years based on terms to be agreed with the Argentine government.  In July of 2013, the terms for our concessions in Tierra del Fuego were extended to August 2026.  Incremental proved reserves resulting from these extensions were included in our oil and gas depreciation calculation beginning in the third quarter of 2013, resulting in a lower rate of depreciation for the remaining net book value compared with recent periods. Non oil and gas property is recorded at cost and is depreciated on a straight-line basis, using estimated useful lives of three 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. See discussion in Note 5 and Note 15 about impairments of producing properties.

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.  If our exploration activity planned for 2014 is unsuccessful, we may have to recognize an impairment loss related to these assets. See discussion in Note 4 about our exploratory wells pending the determination of proved reserves and exploratory wells in progress, and Note 5 about farm-out agreements that have resulted in a recovery of all or a portion of unproved capital costs related to certain unproved areas in Argentina and Colombia.

We record an asset and a liability when incurred 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in other operating expense.

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

Furthermore, given past uncertainties associated with future levels of inflation in Argentina and devaluation of the peso, any future estimate of the cost to plug and abandon a well is subject to a wide range of outcomes as the estimate is updated as time passes. Finally, adjustments in the total asset retirement obligation included in 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.  

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 the three-year period ended December 31, 2013, 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 $1.0 million, $1.9 million, and $3.0 million in operating revenues and taxes other than income as a result of these transactions in 2013, 2012 and 2011, respectively.

Foreign Exchange

The United States dollar is our functional currency.  Accordingly, re-measurement gains and losses that arise from exchange rate fluctuations applicable to transactions and accounts 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.  The existence of these rules may give rise to loss contingencies for future environmental remediation. We 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 $568 thousand and $953 thousand for these undiscounted estimated costs at December 31, 2013, and December 31, 2012, respectively.

Income Taxes

We file income tax returns in Argentina and Colombia on a separate legal entity basis for each of our subsidiaries subject to income tax. Our income tax provisions are calculated on a separate return basis for our subsidiaries. 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, dividend taxes, and various transaction taxes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Equity Investment Impairment Policy

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

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

(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, 2013, cumulative undistributed earnings of Petrolera were $255.6 million.

The carrying amount of our investment in Petrolera is greater than our proportionate share of Petrolera’s net equity by $895 thousand.  The reasons for this basis difference are: (i) goodwill recognized on our 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 was as follows:

	December 31, 2013		December 31, 2012
	(Thousands)
Current assets	$	78,076	$	84,435
Non current assets	305,862		282,497
Current liabilities	55,239		72,164
Non current liabilities	23,947		30,105

Included in Petrolera’s current assets as of December 31, 2013, is approximately $27.4 million of cash denominated in Argentine pesos.

Petrolera’s results of operations were as follows:

	2013		2012		2011
	(Thousands)
Revenues	$	308,149	$	320,189	$	262,026
Expenses other than income taxes	221,363		214,109		182,373
Net income	48,110		64,646		49,744

The comparative decrease in Petrolera’s net income for 2013 is primarily a result of lower revenues driven by lower volumes and greater operating costs. 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

58

Argentina at the official rate of exchange to deposit funds in foreign accounts. These restrictions require both Central Bank and AFIP (Argentina’s taxing authority) approvals which are difficult to obtain. As a result, the current movement of funds out of Argentina through the Central Bank at the official exchange rate has been restricted. Consequently, we received $3.3 million in dividends from Petrolera during 2013, compared with $7.8 million in 2012 and $12.8 million in 2011.  

(3) Restricted Cash

Restricted cash is $5.5 million and $8.9 million as of December 31, 2013 and 2012 respectively, 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. The restricted cash is invested in a short-term money market account with a financial institution. 

(4) Exploratory Well Costs Pending the Determination of Proved Reserves and Exploratory Wells in Progress

The amount of exploratory wells pending the determination of proved reserves was approximately $5.7 million as of December 31, 2013. For the years ended December 31, 2013, 2012, and 2011, the changes in capitalized exploratory drilling costs pending the determination of proved reserves are detailed in the table below.  

Changes in exploratory well costs pending determination of reserves:

	Years Ended December 31,
	2013			2012			2011
	(Thousands)
Balance, beginning of year	$	4,649		$	1,200		$	101
Additions	3,265			4,649			1,200
Transfers to proved properties	—			—			(101		)
Recovery of unproved costs through farm-out agreement	(2,262		)	—			—
Expensed	—			(1,200		)	—
Total	$	5,652		$	4,649		$	1,200

The balance as of December 31, 2013, includes costs of $3.0 million for one well that has been capitalized for greater than one year. The balance as of December 31, 2012 and 2011, respectively included no costs that were capitalized greater than one year. We have firm plans and contractual commitments including the drilling of additional exploratory wells and well completions during 2014 to assess the reserves related to this well and their potential development. Activities performed during 2013 to evaluate the well included the conclusion of an in-depth technical analysis of the core sample taken from the well during drilling and a workover of the well resulting in a positive test of natural gas.

In addition to the wells that have completed drilling and are pending the determination of proved reserves, we had exploratory wells in progress of approximately $3.6 million as of December 31, 2013, compared with $1.4 million at December 31, 2012 and zero as of December 31, 2011. If exploratory wells are determined to be productive, the related costs will be transferred to proved oil and gas properties.  If proved reserves are not found, the costs incurred for exploration wells will be charged to exploration expense.

In addition to the wells in the table above, we had capitalized exploratory drilling costs net to our equity interest (which is presented on an after tax basis) of approximately zero, $0.8 million, and $1.0 million for the years ended December 31, 2013, 2012, and 2011 respectively. The entire balance as of December 31, 2011, of $1.0 million was expensed during 2012.

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(5) Exploration Expenses, Farm-out Agreements and Impairments

The following table presents a summary of exploration expenses.

	Years Ended December 31,
	2013		2012		2011
	(Thousands)
Geologic and geophysical costs	$	3,089	$	8,365	$	2,046
Dry hole costs	3,796		2,787		1,057
Total exploration expense	$	6,885	$	11,152	$	3,103

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 or expensing of unsuccessful exploratory wells or well re-completions of an exploratory nature.

Farm-out Agreements and Impairments

The following table presents a summary of significant gains on sale from farm-out agreements and losses reflected in impairment of producing properties within Other expense (income).

	Years Ended December 31,
	2013			2012			2011
	(Thousands)
Gain on farm-out agreements	$	(3,642	)	$	(2,809	)	$	—
Impairment of producing properties	3,257			—			—
Effect of gains on farm-out agreements and impairments of producing properties on Other expense (income)	$	(385	)	$	(2,809	)	$	—

During 2013, we executed a farm-out agreement under which we assigned a portion of our working interest in one of our Colombian properties subject to governmental approval.  Terms of the agreement include a reimbursement of past seismic and drilling costs incurred by us for $8.4 million and a carry of future exploration investments.  We recorded a credit to unproved capitalized costs associated with the farm-out of approximately $4.8 million, and a gain of $3.6 million reflected in Other expense (income) related to costs recorded in prior periods as Exploration expense.

During 2012, we executed a farm-out agreement under which we assigned up to 44 percent of our working interest in an exploratory area within the Sur Río Deseado Este concession.  Terms of this agreement include a reimbursement of past investments in the area incurred by Apco for $3.1 million. We recorded a credit to unproved capitalized costs associated with the farm-out of approximately $278 thousand, and a gain of approximately $2.8 million reflected in Other expense (income) related to costs recorded in prior periods as Exploration expense.

Due to high operating costs, declining forward oil prices and a downward revision in reserves from a producing property in Colombia, we performed an impairment assessment of the property's carrying value. Accordingly, we recorded a $3.3 million impairment charge in Other expense (income) during fourth quarter 2013. Our impairment analysis included an assessment of undiscounted and discounted future cash flows, which considered information obtained from drilling, production and reserve quantities (see Note 15).

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(6) Major Customers

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

	For the Years Ended December 31,
	2013	2012	2011
Shell Cia. Argentina de Petroleo S.A.	30.95%	22.87%	16.32%
Oil Combustibles S.A.	24.49%	29.59%	26.37%
YPF S.A.	16.54%	12.27%	—%
Petrobras Argentina S.A.	2.30%	1.82%	13.30%
Esso Petrolera Argentina S.A.	—%	12.83%	23.55%

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

WPX Energy separated from The Williams Companies, Inc ("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 provides us with administrative, legal, and management services, as well as office space.

We incurred expenses in 2011 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 2013, 2012, and 2011.

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 collect revenue on behalf of NWA.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The balances of related party transactions were as follows:

	December 31,
Current:	2013		2012
Accounts Receivable	(Thousands)
Due from Petrobras Argentina S.A.	$	293	$	245
Due from Petrolera Entre Lomas S.A.	982		564
Due from Northwest Argentina Corporation	7		12
	$	1,282	$	821
Affiliate Payable
Due to WPX Energy, Inc.	$	463	$	303
Due to Petrolera Entre Lomas S.A.	414		413
	$	877	$	716
Accrued Liabilities
JV Advances due to Petrolera Entre Lomas S.A.	$	998	$	1,048

For the years ended December 31, 2013, 2012, and 2011, revenues and expenses derived from related party transactions and with Williams were as follows:

Revenues from hydrocarbons sold	2013			2012			2011
	(in thousands)
Petrolera Entre Lomas S.A.	$	3,248		$	4,182		$	3,372
Petrobras Argentina S.A.	3,062			2,427			13,469
	$	6,310		$	6,609		$	16,841
Expenses
WPX Energy, Inc.	$	2,062		$	1,825		$	1,314
Northwest Argentina Corporation	(107		)	(127		)	(167		)
Williams	—			—			177
	$	1,955		$	1,698		$	1,324

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(8) Current Assets

Other current assets consisted of the following:

	December 31, 2013		December 31, 2012
	(Thousands)
Prepaid expense	$	1,557	$	1,415
Value added tax advances	2,165		2,327
Hydrocarbon subsidy receivable	2,790		—
Advances with joint venture partners	3,589		356
Other current assets	1,131		779
	$	11,232	$	4,877

(9) Accrued Liabilities

Accrued liabilities consisted of the following:

	December 31, 2013		December 31, 2012
	(Thousands)
Taxes other than income	$	3,621	$	2,870
Payroll and other general and administrative expenses	2,577		2,205
Advances from joint venture partners	3,220		2,473
Current portion of long-term debt	2,500		500
Other	413		742
	$	12,331	$	8,790

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(10) Income Taxes

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

	Years Ended December 31,
	2013		2012			2011
	(Thousands)
Income taxes:
Current	$	17,351	$	13,067		$	10,351
Deferred	13,230		(1		)	(288		)
Income tax expense	$	30,581	$	13,066		$	10,063

Apco was incorporated in the Cayman Islands in 1979. Since then, our income, to the extent that it is derived from sources outside the United States, is not subject to United States 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. All of our income during 2013, 2012, and 2011 was generated outside the United States. We are subject to income taxes in Argentina and 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 on an after-tax basis.

In September 2013, the Argentine government enacted certain tax reform legislation related to capital gains and dividends. The tax reform removes the income tax exemption on income derived from the sale of shares, titles, bonds and other securities that has been provided to non-Argentine residents since 1991. Effective immediately, upon enactment, the sale of such securities is subject to a 13.5 percent capital gain tax on the gross proceeds. U.S. GAAP requires the recognition of deferred income taxes on the excess of the amount of financial reporting basis over the tax basis of equity investments, such as our investment in the shares of Petrolera. As a result of the Argentine tax reform, we recorded $14.1 million of deferred tax expense in 2013 for the new Argentine capital gain tax associated with our equity investment in Petrolera. Of the total amount of deferred tax expense recorded resulting from the new law, $11.9 million relates to the basis difference that existed in our equity investment in Petrolera as of December 31, 2012.

The tax reform also imposes a ten percent tax on dividends, profit distributions and remittances by permanent establishments (including branches) made to Argentine individuals and foreign shareholders. The ten percent dividend tax will apply to Apco on dividends received from Petrolera, branch remittances, and any dividends paid by our subsidiaries. The new dividend tax will be accrued when dividends are distributed in future periods.

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

	Years Ended December 31,
	2013			2012			2011
	(Thousands)
Provision at Argentine statutory rate	$	17,191		$	18,263		$	14,648
Increases (decreases) in taxes resulting from:
Equity income previously taxed in Argentina	(6,932		)	(9,232		)	(7,174		)
Non taxable income and expense	2,776			1,383			1,022
Enactment of taxes on capital gains in Argentina	14,083			—			—
US dollar remeasurement effect	2,094			982			1,000
Changes in valuation allowance	404			1,261			523
Other - net	965			409			44
	$	30,581		$	13,066		$	10,063

Income taxes payableat December 31, 2013 and 2012 were $7.1 million and $4.6 million, respectively.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The deferred tax liability (asset) at December 31 for each of the years presented consists of the following:

	December 31,
	2013		2012
	(Thousands)
Deferred tax liabilities:
Argentine investment, equity method	$	14,083	$	—
Total deferred tax liabilities	14,083		—
Deferred tax assets:
Defined contribution retirement plan accrual	$	252	$	270
Property and equipment	3,576		2,535
Loss carryovers	1,537		1,465
Retirement plan obligations	520		529
Other	47		258
Total deferred tax assets	5,932		5,057
Less valuation allowance	4,207		3,803
Total net deferred tax assets	1,725		1,254
Net deferred tax liability (asset)	$	12,358	$	(1,254	)

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.  We have historically incurred losses related to exploration and production activity in Colombia. We have not recorded any benefit for deferred tax assets in Colombia since it is likely that our future activities in Colombia will not generate sufficient taxable income to recognize the benefit of the deferred tax assets.

As of December 31, 2013 and December 31, 2012, we had no unrecognized tax benefits or reserve for uncertain tax positions.

It is our 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 2007 through 2013 remain open to examination.

(11) Defined Contribution Retirement Plan

In April 2004, Apco 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 March 2014, we will make a contribution of $135 thousand to the plan.  This amount was accrued as administrative expense in 2013. The total expense in 2012 was $203 thousand and $100 thousand in 2011.  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 $7.5 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. We recorded interest expense of $344 thousand, $416 thousand and $82 thousand in the periods ended December 31, 2013, 2012 and 2011, respectively. 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.  We are in compliance with all debt covenants as of December 31, 2013. We record the current portion, the amount payable in the next twelve months, of the long-term debt in the Accrued liabilities in our balance sheet. Aggregate minimum maturities of our long-term debt are as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

	(Thousands)
2014	$	2,500
2015	3,500
2016	1,500
Total	$	7,500

(13) Long-Term Liabilities

Long-term liabilities consisted of the following:

	December 31, 2013		December 31, 2012
Long-term liabilities	(in Thousands)
Retirement plan obligations	$	1,105	$	999
Asset retirement obligations	3,625		2,261
Other	481		835
	$	5,211	$	4,095

Retirement plan obligations represent our proportionate share of the obligation arising from the pension plan that covers all employees of Petrolera, the operator of the Entre Lomas concession. Apco’s proportionate share of the projected benefit obligation at December 31, 2013 and 2012, was $2.9 million and $2.7 million, respectively, while the fair value of plan assets (which are invested in money market mutual funds and treasury federal funds) was $1.8 million and $1.7 million, respectively.  We expect our contributions in 2013 to be less than $200 thousand.

(14) Contingencies and Commitments

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 claims that we owe an additional $4.3 million pesos (approximately $659 thousand U.S. dollars as of December 31, 2013). 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. In September 2013, the provincial tax agency of Chubut granted our appeal and submitted the claim files to the provincial Ministry of Economy and Public Credit for review and final decision.

Commitments

Commitments for international oil and gas activities primarily for drilling investments for exploration are as follows:

	(Thousands)
2014	$	17,700
2015	—
Total	$	17,700

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(15) Fair Value Measurements

Fair value is the amount received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date.  Fair value is a market-based measurement considered from the perspective of a market participant.  We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation.  These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information.

The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair value hierarchy are: Level 1, in which inputs are based on quoted prices for identical assets and liabilities; Level 2, in which inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable; and, Level 3, which includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured.  

The carrying amount reported in the balance sheet for cash equivalents, accounts receivable and accounts payable is equivalent to fair value due to the frequency and volume of transactions in and the short-term nature of these accounts.  The carrying amount for restricted cash is equivalent to fair value as the funds are invested in a short-term money market account. The fair value of our debt is estimated to approximate the carrying amount as the interest is a floating rate based on Libor. For each year in the three-year period ended December 31, 2013, we did not have any Level 1 or Level 2 fair value balances.  

Included in our Level 3 measurements are financial instruments related to benefits from the Argentine government hydrocarbon subsidy program known as Oil Plus. We are eligible to earn producer export tax credit certificates based on production and reserve replacement measurements as provided by government regulations. We apply for the certificates and receive them at the discretion of the government. The certificates can be utilized to offset export taxes on hydrocarbon exports from our direct joint venture interests or can be assigned to third parties at face value. We consider certificates assigned to third parties to be financial instruments.

Our estimate of fair value for financial instruments related to Oil Plus is based on a market approach and considers various market participant assumptions, including numerous levels of governmental approval, the likelihood of the export of hydrocarbons to generate export taxes for which the subsidies can be utilized since we are only able to export a limited amount of our production, the legal requirement to transfer the certificates to other parties at nominal value and the expected duration of the government export tax regime and subsidy programs based on current factors. For these Level 3 fair value balances, the inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. The fair value estimate of our remaining and un-utilized financial instruments related to hydrocarbon subsidies was zero in each of the years ended December 31, 2013, 2012 and 2011.

Notwithstanding an asset fair value of zero for these financial instruments, we record revenues for the amount of certificates when utilized by third parties. In early 2013, the government altered its regulations to allow smaller producing companies to receive benefits from the program. As a result, prior to December 31, 2013, certain third parties were allowed to utilize tax certificates that had originally been granted to us and we realized revenues of $15.2 million during 2013.  In February 2012, the Argentine government suspended benefits under the Oil Plus program and ceased granting subsidies to producers, therefore we realized no benefit from this program in 2012. During 2011, we recognized approximately $1.1 million in revenues net to our consolidated interests and approximately $1.7 million net to our equity interest. Realized and unrealized gains from the benefits of these programs included in Income before income taxes are reported in Other revenues in our Consolidated Statements of Income and Comprehensive Income. 

Our Level 3 measurements also include certain assets that have been measured at fair value on a nonrecurring basis. As previously noted in this report, we evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such assets may not be recoverable. During 2013, we considered the high operating costs, declining forward oil prices and a downward revision in reserves for a producing property in Colombia to be indicators of potential impairment. As a result, we assessed the carrying value of the property for impairment using estimates of future cash flows. Significant judgments and assumptions in the assessment include estimates of proved, probable and possible reserves quantities, estimates of future oil prices using a forward NYMEX curve adjusted for

quality and locational basis differentials, an expectation for market participant drilling plans, expected operating and capital costs, and an applicable discount rate commensurate with the risk of the underlying cash flow estimates. The assessment

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

identified that the property's carrying value was in excess of the calculated fair value. As a result, we recognized $3.3 million of impairment charges in 2013. The fair value for the property was estimated to be zero as of December 31, 2013. Significant assumptions in valuing the property included proved reserves of approximately 147 thousand net barrels of oil, forward weighted average prices averaging approximately $61 per barrel (adjusted for quality and location differences), and a discount rate of 15 percent.

(16) Subsequent Events

Subsequent to December 31, 2013, the value of the Argentine peso has declined approximately 21 percent from 6.52:1 to 7.88:1 as of February 28, 2014. The devaluation of the peso experienced through February 2014 would imply estimated foreign exchange losses of approximately $1.0 million in our operating income based on our net monetary assets denominated in pesos of $6.0 million at December 31, 2013, and $0.4 million related to our equity income from the translation of net monetary assets denominated in Argentine pesos held by Petrolera of $6.3 million at year end.  Additional losses could be incurred on unsettled transactions from the date of the financial statements to the transaction date. We believe that it is not practicable to determine those losses, if any. The devaluation has resulted in the negotiation of lower product price realizations. In February 2014, the Argentine government participated in negotiations between producers and refiners to adjust oil prices in the short term to lower the cost of hydrocarbon products in peso values. Oil price realizations for our Medanito production from the Neuquén basin were agreed to be $71.40 for January and February, $75.74 for March, and $79.89 for April.

(17) Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
(Amounts in thousands except per share amounts)
2013
Operating revenues	$	35,279	$	41,790	$	33,672		$	38,282
Costs and expenses	27,271		29,855		27,651			35,844
Investment income	5,465		6,122		4,482			4,644
Net income	9,943		13,532		(6,030		)	1,089
Amounts attributable to Apco Oil and Gas International Inc:
Net income	9,933		13,520		(6,038		)	1,081
Net income per ordinary and Class A shares outstanding	0.34		0.46		(0.21		)	0.04
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

Net income for the fourth quarter of 2013 includes the following items:

•$5.0 million of revenues related to benefits from the Oil Plus subsidy program in Argentina (see Note 15).

•$2.2 million in dry hole costs for exploratory wells considered to be impaired (see Note 5).

•$3.3 million of impairment costs of producing properties in Colombia (see Note 5 and Note 15).

•$1.3 million costs for foreign exchange losses.

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APCO OIL AND GAS INTERNATIONAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

•$6.0 million income tax expense.

Net loss for the third quarter of 2013 includes the following items:

•$1.5 million of revenues related to benefits from the Oil Plus subsidy program in Argentina (see Note 15).

•$0.8 million costs for foreign exchange losses.

•$13.7 million deferred tax expense due to the Argentine tax reform enacted during the quarter, including a new capital gain tax associated with our equity investment in Petrolera (see Note 10).

Net income for the second quarter of 2013 includes the following items:

•$5.8 million of revenues related to benefits from the Oil Plus subsidy program in Argentina (see Note 15).

•$3.6 million gain on a farm-out agreement of part of our working interests in a property in Colombia (see Note 5).

Net income for the first quarter of 2013 includes the following items:

•$2.9 million of revenues related to benefits from the Oil Plus hydrocarbon program in Argentina (see Note 15).

Net income for the fourth quarter of 2012 includes the following items:

•$4.6 million in revenues related to our Colombian operations.

•$1.1 million of DD&A costs and transportation of $652 thousand from Colombian operations.

•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.

•Dry hole impairment costs of $830 thousand related to our consolidated interests.

Net income for the third quarter of 2012 includes the following items:

•$2.4 million in revenues related to the start-up of production and sales from our Colombian operations.

•Dry hole impairment costs of $1.9 million related to our consolidated interests, and $1.7 million related to our equity interest recorded in investment income.

Net income for the second quarter of 2012 includes the following items:

•Exploration costs of $3.0 million for the acquisition of 3D seismic information primarily in Colombia.

•$2.8 million gain on farm-out agreement in the Sur Río Deseado Este concession of Argentina (see Note 5).

Net income for the first quarter of 2012 includes the following items:

• $5.0 million for the acquisition of 3D seismic information in Colombia and Argentina.

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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. As of December 31, 2013, 99 percent of our oil reserves are in Argentina and our independent reservoir engineer, Ralph E. Davis Associates, Inc. (“Davis”), audited our estimates of those reserves as prepared by us; one percent of our oil reserves are attributable to our Colombian properties and were estimated by Davis. Prior to December 31, 2012, all of our reserves were located in Argentina.  

	(Millions of Barrels)
	Interests
	Consolidated		Equity		Combined
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
December 31, 2012	11.2		11.4		22.6
Revisions of previous estimates:
Engineering revisions	(1.5	)	(0.8	)	(2.3	)
Extensions and discoveries	0.2		—		0.2
Contract modifications	0.8		—		0.8
Production	(1.5	)	(1.6	)	(3.1	)
December 31, 2013	9.2		9.0		18.2
Proved developed as of December 31, 2013	5.6		5.8		11.4
Proved undeveloped as of December 31, 2013	3.6		3.2		6.8

• 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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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, 2013, 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, 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
December 31, 2012	46.1		35.5		81.6
Revisions of previous estimates:
Engineering revisions	(1.7	)	(2.1	)	(3.8	)
Extensions and discoveries	0.7		0.9		1.6
Contract modifications	17.8		—		17.8
Production	(7.2	)	(4.3	)	(11.5	)
December 31, 2013	55.7		30.0		85.7
Proved developed as of December 31, 2013	36.1		18.7		54.8
Proved undeveloped as of December 31, 2013	19.6		11.3		30.9

• A portion of our natural gas reserves are consumed in field operations. The volume of natural gas reserves for 2011, 2012, and 2013 estimated to be consumed in field operations included as proved natural gas reserves within consolidated interest is 13.9 Bcf, 8.7 Bcf, and 9.1 Bcf, respectively, and within the equity interest is 15.6 Bcf, 9.2 Bcf, and 7.3 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 2013 on a barrel of equivalent basis decreased from 2012 as additions from development and exploration drilling and contract modifications due to concession extensions in were more than offset by the combination of

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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 certain fields in the Neuquén basis where performance and drilling results did not meet expectations during 2013 and also due to the reclassification to unproved of proved undeveloped reserves in the province of Río Negro where we have not yet obtained our ten year concession extensions. For additional discussion about concession extensions obtained during 2013 and our remaining concession extensions see "MD&A - Overview of 2013 - 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, 2013, 2012 and 2011, the average oil prices used in the estimates were $76.37, $74.42 and $61.95 per barrel.

For the years ended December 31, 2013, 2012 and 2011, the average natural gas prices used in the estimates were $2.94, $2.62 and $2.30 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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UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

Standardized Measure of Discounted Future Net Cash Flows

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

	(Millions of Dollars)
	Interests
	Consolidated			Equity			Combined
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
As of December 31, 2013
Future cash inflows	$	823		$	733		$	1,556
Less:
Future production costs	(346		)	(297		)	(643		)
Future development costs	(129		)	(108		)	(237		)
Future income tax expense	(65		)	(95		)	(160		)
Future net cash flows	283			233			516
Less 10 percent annual discount for estimated timing of cash flows	(108		)	(84		)	(192		)
Standardized measure of discounted future net cash flows	$	175		$	149		$	324

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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, 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
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.

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UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION

	(Millions of Dollars)
For the Year Ended December 31, 2013	Interests
	Consolidated			Equity			Combined
Standardized measure of discounted future net cash flows beginning of period	$	207		$	199		$	406
Changes during the year:
Revenues, net of production costs	(75		)	(71		)	(146		)
Net changes in prices and production costs	(4		)	17			13
Additions and revisions of previous estimates	(4		)	(34		)	(38		)
Changes in estimated development costs	(26		)	(15		)	(41		)
Development costs incurred during current period	36			34			70
Changes in production rates, timing, and other	(15		)	(24		)	(39		)
Accretion of discount	27			27			54
Net changes in income taxes	26			18			44
Net changes	(35		)	(48		)	(83		)
Standardized measure of discounted future net cash flows end of period	$	172		$	151		$	323

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, 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
For the year ended December 31, 2013
Proved oil and gas properties	$	341,090		$	329,641
Unproved oil and gas properties	9,247			2,577
Accumulated depreciation, depletion and amortization	(189,420		)	(209,588		)
Total	$	160,917		$	122,630

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Costs Incurred in Acquisitions, Exploration, and Development

The following table details costs incurred for acquisitions, exploration, and development during 2011, 2012 and 2013. Costs incurred include capitalized and expensed items.

	Interests
(Amounts in Millions)	Consolidated		Equity			Combined
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
For the year ended December 31, 2013
Exploration	$	15.6	$	3.3		$	18.9
Development	35.5		33.8			69.3
Asset retirement obligations	0.8		(0.2		)	0.6
Total	$	51.9	$	36.9		$	88.8

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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 is also 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 2013 Changes in Internal Controls

There have been no changes during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. Other Information

None.

77

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 2014 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 2014 Proxy Statement and incorporated herein by reference.

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

The information required by this Item 12 is set forth under the caption “Security Ownership of Certain Beneficial Owners and Management” in our 2014 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 2014 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 2014 Proxy Statement and incorporated herein by reference.

78

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).

79

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	-	Amended and Restated Administrative Services Agreement, dated May 7, 2013, between Apco Oil and Gas International Inc. and WPX Energy, Inc. (incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the SEC on May 7, 2013).
* 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.

80

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 6, 2014

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/ Bryan K. Guderian Bryan K. Guderian	Chief Executive Officer (Principal Executive Officer)	March 6, 2014
/s/ Rodney J. Sailor Rodney J. Sailor	Chief Financial Officer, (Principal Financial Officer)	March 6, 2014
/s/ Benjamin A. Holman Benjamin A. Holman	Chief Accounting Officer, Controller (Principal Accounting Officer)	March 6, 2014
/s/ *Keith E. Bailey	Director	March 6, 2014
Keith E. Bailey
/s/ *James J. Bender	Chairman of the Board	March 6, 2014
James J. Bender
/s/ *Robert J. LaFortune	Director	March 6, 2014
Robert J. LaFortune
/s/ *Piero Ruffinengo	Director	March 6, 2014
Piero Ruffinengo
*By:  /s/ Michael Kyle	President	March 6, 2014
Michael Kyle Attorney-in-Fact

81

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).

82

10.13	-	Amended and Restated Administrative Services Agreement, dated May 7, 2013, between Apco Oil and Gas International Inc. and WPX Energy, Inc. (incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the SEC on May 7, 2013).
* 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.

83

Schedule S-1

PETROLERA ENTRE LOMAS S.A.

Financial Statements for the fiscal year ended December

31, 2013 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, 2013 and 2012	- 1 -
	-   Statements of income for the years ended December 31, 2013, 2012 and 2011	- 2 -
	-   Statements of comprehensive income for the years ended December 31, 2013, 2012 and 2011	- 3 -
	-   Statements of shareholders' equity for the years ended December 31, 2013, 2012 and 2011	- 4 -
	-   Statements of cash flows for the years ended December 31, 2013, 2012 and 2011	- 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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

Buenos Aires, Argentina
February 14, 2014
	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, 2013 AND 2012

(stated in thousands of U.S. dollars)

	December 31,
	2013		2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	29,514		36,692
Accounts receivable (3,795 and 2,025 with related parties, Note 6)	37,589		34,453
Other receivables (1,230 and 1,020 with related parties, Note 6)	7,735		9,575
Inventories	2,554		2,843
Other assets	684		872
Total current assets	78,076		84,435
NONCURRENT ASSETS
Accounts receivable	211		371
Other receivables	181		239
Property, plant and equipment, net (Note 5)	300,541		275,054
Deferred tax asset, net (Note 4)	3,027		4,295
Other assets	1,902		2,538
Total noncurrent assets	305,862		282,497
Total assets	383,938		366,932
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities (2,171 and 1,728 with related parties, Note 6)	26,709		29,176
Debt and accrued debt interest (Note 11)	9,733		16,295
Taxes payable and payroll (Note 9)	17,047		25,156
Other liabilities (Note 9)	1,750		1,537
Total current liabilities	55,239		72,164
NONCURRENT LIABILITIES
Debt (Note 11)	3,200		12,800
Other liabilities (Note 9)	20,747		17,305
Total noncurrent liabilities	23,947		30,105
Total liabilities	79,186		102,269
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	212,666		153,006
Accumulated other comprehensive loss	(2,248	)	(2,210	)
Retained Earnings	45,216		64,749
Total shareholders' equity	304,752		264,663
Total liabilities and shareholders' equity	383,938		366,932

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, 2013, 2012 AND 2011

(stated in thousands of U.S. dollars)

	Year ended December 31,
	2013		2012		2011
REVENUES:
Operating revenues (14,666, 6,266, and 41,142 with related parties, Note 6)	308,149		320,189		262,026
COST AND EXPENSES:
Operating expenses (4,088, 3,113 and 3,114 with related parties, Note 6)	(80,628	)	(74,207	)	(63,435	)
Provincial production tax	(41,888	)	(40,553	)	(33,062	)
Transportation and storage	(2,771	)	(3,043	)	(2,505	)
Selling and administrative	(7,463	)	(7,046	)	(6,549	)
Depreciation of property, plant and equipment	(70,802	)	(67,285	)	(59,853	)
Exploration expense	(1,846	)	(7,772	)	(4,905	)
Taxes other than income tax	(14,375	)	(12,652	)	(9,645	)
Financial results	3,171		9		(2,456	)
Foreign exchange losses	(5,612	)	(1,639	)	(73	)
Other income (expense), net (58, 65, and 111 with related parties, Note 6)	851		79		110
Total cost and expenses	(221,363	)	(214,109	)	(182,373	)
Income before income tax	86,786		106,080		79,653
Income tax (Note 4)	(38,676	)	(41,434	)	(29,909	)
Net income	48,110		64,646		49,744

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, 2013, 2012 AND 2011

(stated in thousands of U.S. dollars)

	For the years ended December 31
	2013		2012		2011
Net income	48,110		64,646		49,744
Other comprehensive income (loss), before tax:
Defined benefit pension plan	(58	)	(317	)	(481	)
Other comprehensive income (loss), before tax	(58	)	(317	)	(481	)
Income tax (expense) benefit related to items of other comprehensive income	20		111		169
Other comprehensive income (loss), net of tax	(38	)	(206	)	(312	)
Comprehensive income	48,072		64,440		49,432

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

- 3 -

PETROLERA ENTRE LOMAS S.A.

STATEMENTS OF SHAREHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

(stated in thousands of U.S. dollars)

Balance	Capital stock	Legal reserve	Facultative reserve		Accumulated other comprehensive loss		Retained earnings		Total
December 31, 2010	41,289	7,829	101,795		(1,692	)	52,070		201,291
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting	—	—	46,422				(46,422	)	—
Dividends	—	—	(31,400	)			—		(31,400	)
Other comprehensive income	—	—	—		(312	)	—		(312	)
Net income	—	—	—		—		49,744		49,744
December 31, 2011	41,289	7,829	116,817		(2,004	)	55,392		219,323
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting	—	—	55,289				(55,289	)	—
Dividends	—	—	(19,100	)			—		(19,100	)
Other comprehensive income	—	—	—		(206	)	—		(206	)
Net income	—	—	—		—		64,646		64,646
December 31, 2012	41,289	7,829	153,006		(2,210	)	64,749		264,663
Allocation of unappropiated retained earnings, as approved by Shareholders' meeting	—	—	67,643				(67,643	)	—
Dividends	—	—	(7,983	)			—		(7,983	)
Comprehensive income	—	—	—		(38	)	—		(38	)
Net income					—		48,110		48,110
December 31, 2013	41,289	7,829	212,666		(2,248	)	45,216		304,752

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

- 4 -

PETROLERA ENTRE LOMAS S.A.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

(stated in thousands of U.S. dollars)

	Year ended December 31,
	2013		2012		2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	48,110		64,646		49,744
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation of property and equipment	70,802		67,285		59,853
Deferred income tax	1,288		(842	)	(2,070	)
Income from sales of property and equipment	(225	)	—		—
Effect of exchange rate changes on cash and cash equivalents	7,596		5,705		—
Accrued interest on debt	778		1,491		1,628
Changes in assets and liabilities, net:
(Increase) decrease in assets:
Accounts receivable	(1,206	)	(5,367	)	(8,946	)
Accounts receivable - Due from related parties	(1,770	)	(2,002	)	10,381
Inventories	289		301		(2,009	)
Other receivables	2,088		(5,183	)	(954	)
Other receivables - Due from related parties	(210	)	4,171		(5,191	)
Other assets	824		978		(9	)
Increase (decrease) in liabilities:
Accounts payable and accrued liabilities	(2,910	)	8,450		5,854
Accounts payable - Due to related parties	443		1,023		215
Taxes payable and payroll	(8,109	)	8,978		1,117
Other liabilities	51		1,484		1,486
Interest on debt paid	(860	)	(1,525	)	(1,663	)
Net cash provided by operating activities	116,979		149,593		109,436
CASH FLOWS FROM INVESTING ACTIVITIES
Payments of purchases of property, plant and equipment	(92,727	)	(94,552	)	(84,138	)
Cash provided by sales of property, plant and equipment	229		—		—
Net cash applied on investing activities	(92,498	)	(94,552	)	(84,138	)
CASH FLOWS FROM FINANCING ACTIVITIES
Loans obtained	—		3,200		16,300
Loans paid	(16,080	)	(22,807	)	(16,407	)
Dividends paid	(7,983	)	(19,100	)	(31,400	)
Net cash applied on financing activities	(24,063	)	(38,707	)	(31,507	)
Net (decrease) increase in cash and cash equivalents	418		16,334		(6,209	)
Effect of exchange rate changes on cash and cash equivalents	(7,596	)	(5,705	)	—
Cash and cash equivalents at beginning of year	36,692		26,063		32,272
Cash and cash equivalents at end of year	29,514		36,692		26,063
Supplemental cash flow information:
Interest paid	927		1,537		2,302
Income taxes paid	43,045		32,658		32,031

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

- 5 -

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, 2013 and 2012

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

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

Joint ventures - Entre Lomas and Bajada del Palo Concessions

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 renegotiated in 1991 and 1994 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. On July 23, 2009, the province of Neuquén notified the Company of Provincial Decree No. 1,117/09 granting a 10-year extension to the portion of the exploitation concession of the Entre Lomas Block 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 ongoing.

On December 20, 2012, the province of Río Negro passed Law No. 4,818, whereby it established the terms and conditions for renegotiating oil and gas concessions. Such law was enacted on December 28, 2012 (Decree No. 1,978/2012) and published in the Official Bulletin No. 5,108 on January 10, 2013. The Official Bulletin No. 5,127 of the province of Río Negro, dated March 18, 2013, published a communication including the calling made by the Argentine Department of Energy to interested companies that own oil and gas exploitation concessions in the province, granted by the Argentine government, to renegotiate the terms and conditions of their concessions pursuant to Provincial Law No. 4,818 and the Bidding Terms and Conditions approved thereof.

On March 25, 2013, the related Bidding Terms and Conditions were acquired and on May 2, the information required thereof was filed by the Company.

In July, August and September 2013, the Company complied with the requests for additional information made by the Oil and Gas Department of the province of Río Negro. This Department also audited the area related to facilities and the environment, before authorizing the formal beginning of the renegotiation stage.

- 6 -

PETROLERA ENTRE LOMAS S.A.

Several meetings were held with the enforcement authority to define a plan to invest in the exploration and development of reserves and the adaptation of facilities arising from the aforementioned audits. Such plan should define the scope and term for such investment commitments, which are being agreed upon with the enforcement authority.

In addition, along with the DPA (Provincial Department of Water Affairs), the Company defined improvement works to be conducted in pipelines and locations to minimize spillage risks, as part of the above mentioned renegotiation process.

Agua Amarga Concession

During the fiscal year ended December 31, 2007, PELSA obtained the permit to explore Agua Amarga Block located in the province of Río Negro. Such permit comprises three periods of three, two and one year, respectively. The agreement was formalized through Provincial Decree No. 557/07 and it was executed on May 17, 2007. Based on the results of the exploration carried out in Agua Amarga Block as from the beginning of the related permit, the Company requested that the province of Río Negro grant the exploitation concession of the plot of land Charco del Palenque, which it did on October 28, 2009, by means of Provincial Decree No. 874/2009 and its amendment No. 922/2009 dated November 13, 2009, for a 25-year term.

Subsequently, the Company requested that the boundaries of this Exploitation Lot be changed to include the recent discovery called “Meseta Filosa” and its potential development area. Río Negro’s provincial oversight authorities accepted including this sector in the previously-granted concession of Charco del Palenque, which was formalized through Provincial Decree 1,665/2011 dated November 8, 2011, published in Official Bulletin No. 4,991 dated December 1, 2011.

A report was also sent to the oversight authorities to request that the “Jarilla Quemada” discovery, made in 2010, be defined an “Evaluation Lot”, the marketability of which as a gas field is currently under assessment. This classification of the area was granted through Provincial Production Ministry Resolution No. 406/2011 dated October 5, 2011. According to this resolution, PELSA will have five years in which to continue with the tasks required to reach the definition regarding the area’s marketability. The facilities required to start up the discovery well (JQ.x-1) were built, and approved by ENARGAS (Argentine Gas Regulatory Agency). Gas sales began on May 21, 2013, under the “Gas Plus” program which grants a differential sales price under Resolution No. 227/2013 issued by the Department of Energy on April 30, 2013.

Furthermore, the First Exploring Permit over the rest of the area, authorized through Provincial Decree No. 79/2011 and published on April 25 2011, expired on May 31, 2012. Then, a work plan for the Agua Amarga Second Exploring Permit was submitted to the Argentine Regulation Authority Liaison Committee. The aforementioned work plan was authorized through Provincial Decree No. 1,582/2012, therefore granting PELSA the second exploratory period in Agua Amarga Block and extending the permit for a further two 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, 2013 and 2012 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 2013 and 2012, is as follows:

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PETROLERA ENTRE LOMAS S.A.

	2013		2012
Current assets	23,411		22,748
Noncurrent assets	295,424		269,235
Total assets	318,835		291,983
Current liabilities	(52,061	)	(50,770	)
Noncurrent liabilities	(21,233	)	(17,780	)
Total liabilities	(73,294	)	(68,550	)

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 2013, 2012 and 2011, is as follows:

	2013		2012		2011
Operating costs	(174,600	)	(164,042	)	(147,153	)
Administrative expenses	(6,916	)	(6,801	)	(5,730	)
Selling expenses	(330	)	(358	)	(363	)
Exploration expenses	(1,846	)	(7,772	)	(4,905	)
Other operating expenses, net	(439	)	(718	)	(551	)
Financial losses, net	1,520		509		(496	)
	(182,611	)	(179,182	)	(159,198	)

2. BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

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

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

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

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

Summary of significant accounting policies

Cash and cash equivalents

Cash and cash equivalents in 2013 and 2012 include highly liquid bank deposits and other short term investment of 29,5 million and 36.7 million, respectively, of which 25 million and 31.3 million earned interest with an average rate of 17.70 and 13.42 percent in 2013 and 2012, 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 and related party receivables.

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PETROLERA ENTRE LOMAS S.A.

Inventories

Includes hydrocarbons that 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 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, 2013, 2012 and 2011, there were no 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, which 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, 2013 and 2012 totalled 16,353 and 12,401. The change in total asset retirement obligation from December 31, 2012 to December 31, 2013 mainly relates to the effect of the passage of time for about 706, and changes in the cost and number of wells planned to be abandoned upon termination of the concessions for about 3,246.

Property plant and equipment includes as of December 31, 2013 and 2012, materials and spare parts by 6,181 and 4,449, respectively, which were accounted for at the lower of cost or market. The cost is determined by the first-in first-out method.

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PETROLERA ENTRE LOMAS S.A.

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 in order to maintain the stability of crude oil, gasoline and diesel oil prices (the Agreement).

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

The 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, 2013 and 2012, the total price credit available to the Company from domestic refiners amounts to

9.7 million and 9.2 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, 2013 and 2012 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 used to transfer its tax certificates to third parties since it did not have enough export duties derived from their own activities.

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 risk of government non-performance, and the right of return clause included in the transfer agreements, the accounting policy of the Company was to recognize in earning only those certificates transferred and used by third parties.

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

On February 3, 2012, the Argentine Government informed that incentives to oil companies through the Oil Plus Program have been suspended without further details. No tax certificates are pending to be used at December 31, 2013 and 2012, and no earnings have been recognized as Operating revenues as a result of this program during the years then ended.

On November 8, 2013, the Strategic Planning and Coordination Committee of the Argentine Hydrocarbon Investment

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PETROLERA ENTRE LOMAS S.A.

Plan (the Committee), through resolution No. 60/2013, sets forth the plan to foster natural gas injection for companies that have had an average injection of natural gas below 3.5Mm3/d during the six months immediately preceding the effective date of the resolution. This plan establishes a range price for the additional injection of natural gas between USD 4 and USD 7.5 per million BTU based on the total injection volume reached in a determined period.

Pursuant to that resolution, companies can apply for the plan, through a request sent to the Committee. The Company decided to enroll to the plan and the request is still being analyzed by enforcement authorities. The Company decided to enroll to the plan and the request is still being analyzed by enforcement authorities.

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 Nación 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, 2013, the dollar value of the Company’s deposit is 1.2 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 awaiting 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 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
	2013		2012		2011
Current expense	(37,388	)	(42,276	)	(31,979	)
Deferred income tax profit	(1,288	)	842		2,070
	(38,676	)	(41,434	)	(29,909	)

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

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PETROLERA ENTRE LOMAS S.A.

	For the years ended
	2013		2012		2011
Pre-tax income	86,786		106,080		79,653
Statutory tax rate	35	%	35	%	35	%
	30,375		37,128		27,879
US dollar remeasurement effect	7,818		4,212		3,099
Tax adjustments and other	483		94		(1,069	)
Income tax expense	38,676		41,434		29,909

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

	2013		2012
Defined Benefit Pension Plan	2,094		2,255
Asset retirement and other environmental obligations	4,926		3,355
Other, net	—		(49	)
Total deferred tax assets	7,020		5,561
Property, plant and equipment	(3,993	)	(1,266	)
Total deferred tax liabilities	(3,993	)	(1,266	)
Deferred income tax asset, net	3,027		4,295

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 2007 to 2013 remain subject to examination by the Argentine Tax authority.

5. PROPERTY, PLANT AND EQUIPMENT

The capitalized cost of property, plant and equipment and the related accumulated depreciation as of December 31, 2013 and 2013 were as follows:

	December 31,
	2013		2012
Wells and other oil and gas field equipment	737,678		655,262
Acquisition costs of proved properties	31,687		31,687
Other property, plant and equipment	44,835		31,379
	814,200		718,328
Less accumulated depreciation	(513,659	)	(443,274	)
Total	300,541		275,054

6. RELATED PARTY TRANSACTIONS

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PETROLERA ENTRE LOMAS S.A.

As of December 31, 2013 and 2012, the balances from related parties transactions were as follows:

	As of December 31,
	2013	2012
Accounts receivable
Petrobras Argentina S.A.	3,795	2,025
	3,795	2,025
Other receivables
APCO Oil & Gas International Inc.- Argentine Branch	169	154
APCO Oil & Gas International Inc	414	411
Petrobras Argentina S.A.	647	455
Yacimiento Entre Lomas	232	347
Agua Amarga U.T.E.	414	—
Bajado del Palo U.T.E.	3,775	877
	5,651	2,244
Accounts payable.
APCO Oil & Gas International Inc. - Argentine Branch	1,079	880
Petrobras Argentina S.A	881	596
Oleoductos del Valle S.A. (1)	211	252
	2,171	848

(1) Affiliate of Petrobras Argentina S.A.

Other liabilities
Yacimiento Entre Lomas	189	0
Agua Amarga U.T.E.	0	407
	189	407

For the years ended December 31, 2013, 2012 and 2011, revenues and expenses derived from related parties transactions were as follows:

	2013	2012	2011
Revenues from hydrocarbons sold
Petrobras Argentina S.A.	14,666	6,266	41,142
	14,666	6,266	41,142

Other income
APCO Oil & Gas International Inc.- Argentine Branch	31	28	21
Petrobras Argentina S.A.	27	37	90
	58	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.	1,911	1,423	637
Oleoductos del Valle S.A. (1)	2,447	2,665	2,469
	4,358	4,088	3,113

(1) Affiliate of Petrobras Argentina S.A.

Director's Compensation totaled $729, $729 and $828 for the years ended December 31, 2013, 2012 and 2011, 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
	2013	2012	2011
Shell CAPSA	42.2	30.0	20.0
Oil Combustibles S.A.	25.4	31.4	27.5
YPF S.A.	17.6	13.4	—
Axion Energy Argentina S.A. (1)	5.3	16.4	28.6
Petrobras Argentina S.A.	4.8	2.0	13.2

(1) Former ESSO Petrolera Argentina S.A.

The balances with Shell CAPSA, Oil Combustible S.A., YPF S.A., Axion Energy Argentina S.A. (former ESSO Petrolera Argentina S.A.), and Petrobras Argentina S.A. are 10,375, 10,904, 6,094, 3,532 and 3,795 as of December 31, 2013 and 19,619, 670, 7,586, nil and 2,025 as of December 31, 2012, 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.

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PETROLERA ENTRE LOMAS S.A.

The fund's assets have been contributed to a trust and are mainly invested in cash reserves and Treasury Federal Funds at December 31, 2013 and 2012. The Bank of New York is the trustee and Towers Watson is the servicing agent.

	2013		2012
Projected benefit obligation	9,067		8,731
Accumulated benefit obligation	8,440		6,277
Fair value of plan assets at year end	5,554		5,552
Funded status of the plan (underfunded)	(3,513	)	(3,179	)
Amounts recognized in the statement of financial position consist of:
Accrued benefit liabilities (current and noncurrent)	(3,513	)	(3,179	)
Accumulated other comprehensive income	3,458		3,400
Projected benefit obligation at beginning of the year	8,731		8,161
Service cost	251		212
Interest cost	354		325
Net actuarial (gain)/loss due to plan experience	33		316
Benefit payment from fund	(302	)	(283	)
Projected benefit obligation at year end	9,067		8,731
Fair value of plan assets at beginning of the year	5,552		5,296
Company contributions	302		552
Benefit payments from fund	(302	)	(283	)
Actual return on assets	2		(13	)
Fair value of plan assets	5,554		5,552

	2013		2012		2011
Component of net periodic benefit cost:
Service cost	251		212		266
Interest cost	354		325		299
Expected return on assets	(221	)	(213	)	(194	)
Amortization of net prior service cost	—		58		10
Amortization of net losses	195		166		152
Net periodic benefit cost	579		548		533
Pension liability adjustment included in other comprehensive income	(58	)	(317	)	(481	)

The prior service cost and actuarial loss included in accumulated other comprehensive income and expected to be recognized in net periodic pension cost during 2014 is 201.

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PETROLERA ENTRE LOMAS S.A.

	2013		2012
Asset Categories
Cash reserves	35	%	16	%
Treasury Federal Funds	65	%	84	%
Total	100	%	100	%

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

	2013		2012
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 2014.

Estimated Future Benefit Payment

The following benefit payments are expected to be paid.

Year	Benefit
2014	346
2015	419
2016	418
2017	451
2018	449
2019-2023	2,749

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

9. TAXES PAYABLE AND PAYROLL ACCOUNT AND OTHER LIABILITIES

At December 31, 2013 and 2012, taxes payable and payroll account consisted of the following:

	2013	2012
Income tax accrual, net	8,105	16,874
Provincial production taxes	3,548	3,625
Payroll	3,029	2,685
Other	2,365	1,972
	17,047	25,156

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PETROLERA ENTRE LOMAS S.A.

At December 31, 2013 and 2012, current other liabilities consisted of the following:

	2012	2012
Asset retirement and other environmental obligations	630	557
Liability for pension benefit (Note 8)	346	371
Others	774	609
	1,750	1,537

At December 31, 2013 and 2012, non-current other liabilities consisted of the following:

	2013	2012
Liability for pension benefit (Note 8)	3,167	2,808
Asset retirement and other environmental obligations	17,531	14,419
Others	49	78
	20,747	17,305

10. RESTRICTIONS ON RETAINED EARNINGS

Under the Business Associations Law No. 19,550, 5% of net income for the year is to be appropriated to legal reserve until such reserve equals 20% of Capital Stock, which was accomplished by the Company.

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.

On September 12, 2013, the Congress approved an amendment to the Income Tax Law aiming to charge a 10% withholding from dividends to be issued by local companies to their foreign shareholders.

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, 2013 and 2012 is as

follows:

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PETROLERA ENTRE LOMAS S.A.

Debt agreement date (yyyy-mm-dd)	Bank	Interest rate	Interest payable	Principal maturity date (yyyy-mm-dd)	Principal Due 2013	Principal Due 2012
2009-05-15	Banco do Brasil S.A., London Branch	LIBOR + 2.40	quarterly	2013-08-12	—	9,680
2010-05-14	Banco do Brasil S.A., London Branch	LIBOR + 2.50	every six months	2013-05-31	—	3,200
2010-11-12	Banco do Brasil S.A., London Branch	LIBOR + 2.75	every six months	2013-11-15	—	3,200
2011-05-17	Banco do Brasil S.A., London Branch	LIBOR + 2.90	every six months	2014-05-16	3,200	3,200
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	3,200
					12,800	28,880

As of December 31, 2013 and 2012, interest and taxes payable amount to 133 and 215, respectively. Interest and taxes accrued for these loans during the years 2013 and 2012 amount to 778 and 1,491, 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, 2013 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.

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PETROLERA ENTRE LOMAS S.A.

	2013		2012		2011
Balance, beginning of year	2,997		3,937		3,918
Additions	9,021		2,997		2,059
Transfers to proved properties	(5,703	)	(3,937	)	(2,040	)
Total	6,315		2,997		3,937

The balance as of December 31, 2013 consisted of one exploratory well whose drilling finished on 2013, awaiting for further investments to conclude on proved reserves assessment.

14. SUBSEQUENT EVENTS

Subsequent to December 31, 2013, there was a significant appreciation of the foreign currency, which sums up to approximately 23% as of the date of these financial statements in the official foreign exchange market compared to the quotation at December 31, 2013. The exchange differences derived from this situation will be included in the results of the operations of the Company in the following fiscal year.

Subsequent events have been evaluated through February 14, 2014 which is the date these Financial Statements were available to be issued.

19