10-K 1 form10k.htm APCO ARGENTINA 10-K 12-31-2006

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
T	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)

	For the fiscal year ended December 31, 2006

	OR

£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

For the transition period from to

Commission file number 0-8933

APCO ARGENTINA INC.

(Exact Name of Registrant as Specified in its Charter)

Cayman Islands	EIN 98-0199453
(State or other jurisdiction of Incorporation or organization)

One Williams Center, Mail Drop 26-4
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 (Title of Class)	Nasdaq Stock Market, Inc.

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

None

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

Yes £ No T

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

Yes £ No T

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No £

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

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

Large Accelerated Filer £ Accelerated Filer T Non-Accelerated Filer £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £ No T

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates on June 30, 2006, the last business day of the registrant’s most recently completed second fiscal quarter, was $194,788,748. This value was computed by reference to the closing price of the registrant’s stock of $85.25. Since the shares of the registrant’s stock 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 March 1, 2007, there were 7,360,310 shares of the registrant’s ordinary shares outstanding.

Documents Incorporated By Reference

List hereunder the following documents if incorporated by reference and the part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated:

None

DEFINITIONS

The Company uses the following oil and gas measurements and abbreviations in this report:

Bbls - means one barrel

Bcf - means one billion cubic feet

Boe - barrel of oil equivalent, a unit of measure used to express all of the Company’s products in one unit of measure; 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

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

Mbbls- means one thousand barrels

Mbbls/day - means one thousand barrels per day

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

Mmbbls - means one millions barrels

Mcf- means one thousand cubic feet

Mcf/d - means one thousand cubic feet per day

Mmcf- means one million cubic feet

MMcf/d - means one million cubic feet per day

2D - means two dimensional seismic imaging of the sub surface

3D - means three dimensional seismic imaging of the sub surface

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

PART I

ITEM 1.

BUSINESS

(a) General Development of Business

Apco Argentina Inc. (“the Company”) is a Cayman Islands corporation which was organized April 6, 1979 as a successor to Apco Argentina Inc., a Delaware corporation organized July 1, 1970. The business of the Company is oil and gas exploration and production in Argentina. Exploration and production will hereinafter be referred to as “E&P.” The Company’s principal asset is its 52.79 percent interest in a joint venture engaged in E&P activities in the Entre Lomas concession located in the provinces of Río Negro and Neuquén in southwest Argentina. The Company also owns a 1.5 percent interest in a joint venture engaged in E&P activities in the Acambuco concession located in the province of Salta in northwest Argentina, an 81.82 percent interest in a third joint venture engaged in E&P activities in the Cañadón Ramirez concession located in the province of Chubut in southern Argentina, a 25.72 percent interest in a fourth joint venture engaged in E&P activities in the CA-12 “Río Cullen,” CA-13 “Las Violetas,” and CA-14 “Angostura” concessions (the “TDF Concessions”) located on the island of Tierra del Fuego, and a 50 percent interest in the Yacimiento Norte 1/B Block, an exploration permit (the “Capricorn Permit”), also located in the province of Salta.

During 2006, the Company generated net income of $40.1 million compared with $29.8 million and $15.5 million during 2005 and 2004, respectively. This represents the highest annual net income ever generated by the Company. The Company’s record income during 2006 was due to increased product prices and volumes.

Government Regulations

The Company’s operations in Argentina are subject to various laws and regulations governing the oil and gas industry, assessment and collection of income taxes, value added taxes, and other taxes such as royalties and severance, labor laws, and provincial environmental protection regulations.

(b) Financial Information About Segments

None.

(c) Narrative Description of Business

ENTRE LOMAS

The Company participates in a joint venture with Petrolera Entre Lomas S.A. (“Petrolera”) and Petrobras Energía S.A. (“Petrobras Energía”), formerly Pecom Energía S.A. (“Pecom Energía”). Both partners are Argentine companies. The purpose of the joint venture is the exploration and development of the Entre Lomas oil and gas concession in the provinces of Río Negro and Neuquén in southwest Argentina. The Company’s interest in the joint venture totals 52.79 percent, of which 23 percent is a direct participation and 29.79 percent is an indirect participation through the Company’s 40.724 percent stock ownership in Petrolera, the operator of the joint venture. Petrolera owns a 73.15 percent direct interest in the joint venture.

Joint Venture Agreements

On April 1, 1968, Pecom Energía and Petrolera entered into a joint venture agreement with Apco Oil Corporation pursuant to which Petrolera became operator of the Entre Lomas area that had previously been awarded to Pecom Energía. On July 1, 1970, Apco Oil Corporation transferred its interest in the Entre Lomas area to the Company. Similar joint venture agreements among the Company, Pecom Energía, and Petrolera for the development of natural gas and extraction of propane and butane from the Entre Lomas area were entered into February 29, 1972, and March 23, 1977, respectively.

Deregulation

On November 8, 1989, the Argentine government issued decree 1212/89 describing steps necessary to deregulate hydrocarbon production from existing production and development contracts, including Entre Lomas. Originally, the Entre Lomas area was governed by a production service contract. The decree directed YPF, then the national oil company of Argentina, to negotiate with producers to convert such contracts to concessions.

Complete deregulation of the Entre Lomas area was implemented by an agreement with the Argentine government that went into effect January 22, 1991, and amended in February 1994. Pursuant to the agreement, Entre Lomas was converted to a concession giving the joint venture partners ownership of hydrocarbons at the moment they are produced through the wellhead. Under this agreement, the concession holders, or joint venture partners, have the right to freely sell produced hydrocarbons in internal or external markets, and have authority over operation of the concession including future exploration and development plans. The partners, throughout the term of the concession, are subject to provincial royalties (which are, in substance, production taxes), turnover taxes, and federal income taxes. These rates of royalties and taxes are fixed by law, are the same for all oil and gas production concessions in Argentina, and are currently 12 percent, two percent, and 35 percent, respectively. The Entre Lomas concession has a term of 25 years that currently runs to the year 2016 with an option to extend the concession for an additional ten-year period with the consent of the government.

Oil Markets

In 2006, oil produced in the Entre Lomas concession was sold to Argentine refiners. In previous years, oil production has also been exported to Brazil and other countries in the southern cone of Latin America. Entre Lomas production is transported to Puerto Rosales, a major industrial port in southern Buenos Aires Province through the Oleoductos del Valle S.A. (“Oldelval”) pipeline system.

A free market for crude oil produced in Argentina has developed since deregulation of Argentina’s energy industry in 1991. Since this market emerged, the per barrel price for Argentine crude oil has been based on the spot market price of West Texas Intermediate crude oil (“WTI”) less a discount to provide for differences in gravity and quality. This gravity and quality discount averaged $0.53 in 2006.

As the price of crude oil increased to record levels during 2004, politically driven mechanisms for determining the sale price of oil produced and sold in Argentina changed significantly. Today, WTI continues to be the reference price for oil sold in the country, and the aforementioned gravity and quality discounts still apply. However, additional reduction factors have been gradually incorporated into pricing formulas that now act to reduce considerably the sale price net back to Argentine producers such that net back reductions escalate to higher and higher levels as WTI increases. The reduced oil sale price net back received by the Company after deducting both the gravity and quality discount and the additional reduction factors averaged less than 70 percent of WTI during 2006. For example, under current arrangements, if the price of WTI is $60 at the time of sale, the sale price net back to the Company is $41. Please read “Risks Associated with Operations in Argentina”, “Oil Prices”, and “Commodity Price Risk” on pages 15, 19, and 28, respectively, for additional discussion of the net back reduction.

The entire Argentine domestic refining market is small. There are five active refiners that constitute 99 percent of the total market. As a result, the Company’s oil sales have historically depended on a relatively small group of customers. The largest of these five companies refines only its own crude oil production, while the smallest of the five operates only in the northwest basin of Argentina. That leaves only three domestic refiners to which the Company can sell its Entre Lomas production. Decisions to sell to these customers are based on advantages presented by the commercial terms negotiated with each customer. During 2006, the Company sold all of its Entre Lomas oil production, that constitutes more than 90 percent of its total oil production, to a refinery owned by Petrobras Energía. The Company has benefited from competitive pricing with net backs obtained being greater than those currently received for export sales. Refer to Note 6, of Notes to Consolidated Financial Statements, for a description of the Company’s major customers over the last three years.

Gas Markets

The Neuquén basin, in which the Entre Lomas concession is located, is served by a substantial gas pipeline network that delivers gas to the Buenos Aires metropolitan and surrounding areas, the industrial regions of Bahia Blanca and Rosario and by export pipelines to Chile. Entre Lomas is well situated in the basin with two major pipelines in close proximity.

Since deregulation of Argentina’s gas industry in 1994, the joint venture partners have consistently found markets for Entre Lomas gas, including selling in the spot market. Argentina has a very well developed natural gas market because gas consumption represents approximately 50 percent of the country’s total energy consumption. Refer to the section “Liquidity and Capital Resources” on page 19 for a description of the impact of economic reforms implemented in 2002 on natural gas prices in Argentina.

Petrolera

Petrolera is the operator of the Entre Lomas concession. Investment decisions and strategy for development of the concession are agreed upon by the joint venture partners and implemented by Petrolera. Petrolera has a board of 11 directors, five of whom are nominees of the Company and six of whom are nominees of Petrobras and its affiliates. Petrolera’s operating and financial managers and field personnel are employed exclusively by Petrolera. Petrolera’s sole business at present is its role as operator and owner of a 73.15 percent interest in the Entre Lomas concession.

The Company’s 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.

Description of the 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 primarily from the Charco Bayo/Piedras Blancas field (“CB/PB”). Three smaller fields, the Entre Lomas, Lomas de Ocampo and El Caracol fields, located to the northwest of the CB/PB field also produce oil and gas. A fifth field, Borde Mocho, located southwest of the CB/PB field also produces oil and gas.

The most productive producing formation in the concession is the Tordillo. In the CB/PB field the Tordillo has generated over 80 percent of all oil produced in Entre Lomas. The Tordillo also produces associated gas that is both sold and consumed for field operations. The joint venture extracts propane and butane from this gas in its gas processing plant located in the concession. The Tordillo is also the principal producing formation in the Borde Mocho field. Other important formations are the Quintuco, that produces oil and gas from several wells in the CB/PB field and oil in the Entre Lomas, Lomas de Ocampo, El Caracol, and Borde Mocho fields, and the Petrolifera formation (also known as the Punta Rosada formation) that produces gas in the Entre Lomas and Lomas de Ocampo gas fields and some oil in the CB/PB field. Since inception 610 wells have been drilled in the concession, of which at year end, 373 are producing oil wells, 23 are producing gas wells, 143 are active water injection wells, 11 are water producing wells, and 60 wells are either inactive or abandoned.

The CB/PB, El Caracol, and Entre Lomas oil fields are secondary recovery projects whereby water is injected into a producing reservoir in order to restore pressure and increase the ultimate volume of hydrocarbons to be recovered. Injection of water into the Tordillo reservoir has been introduced in the CB/PB field in phases since 1975. Water injection commenced in the El Caracol field in 1989 and in the Entre Lomas field in 1998.

Charco Bayo/Piedras Blancas Field

The CB/PB field produces oil and associated gas principally from the Tordillo formation with some minor production from the Quintuco and Petrolifera (Punta Rosada) formations. Production in the CB/PB field commenced in 1968, with a large part of this complex developed before 1974. Additional development drilling has continued through the present. At year’s end, there were 274 wells producing oil in this field. Secondary recovery was introduced with a successful pilot project in 1975 and has slowly been expanded to include 111 injection wells. The CB/PB field is best described as a mature oil field with remaining development potential. Development of this field has historically been gradual due to the sporadic nature of past major investment programs which, until the Entre Lomas area was converted to a concession, occurred as a result of major renegotiations of the original contract. Since 1991, when Entre Lomas became a concession, drilling activity has been continuous with the number of wells drilled changing both as a consequence of drilling results and fluctuations in the price of oil.

The field’s ultimate development will likely result from a combination of expansion of secondary recovery throughout the entire producing field, infill drilling, continued step out drilling, and recompletion of existing wells with behind pipe reserves. The results of these programs may be enhanced and higher percentage recoveries achieved by improving the efficiency of water injection through various means including modifying existing patterns of water injection, placing idle wells back on production, and the use of polymer injection, which during the last several years has been introduced throughout the field with beneficial results.

Due to the gradual development of this field, recoveries normally attributed to waterfloods after 20 to 30 years, have not been achieved and it is currently estimated that this field has a remaining productive life in excess of 20 years, or well beyond 2016, the year the existing term of the concession ends. The Company believes that the limits of this field have not yet been defined in all directions. As a result, there remain undrilled step out locations in the flanks of the structure and infill locations which should be drilled in order to produce from areas of the field not currently drained by existing wells. The level of development drilling activity in the CB/PB field will, of course, be dependent on an oil price level which can be sustained for a significant period of time and that provides adequate returns for the joint venture partners. During 2006, 18 additional wells were drilled of which 15 were completed as producers and three were in progress at the end of the year. All of the wells in progress at year end were subsequently completed and put on production in early 2007.

In the CB/PB field, the Quintuco formation is mainly gas productive and produces from a few gas wells interspersed among the many Tordillo oil wells located on this structure. Quintuco gas reserves in this field are considered to be fully developed.

El Caracol Field

The El Caracol field is located in the northwestern most part of the concession. This field produces oil from the Quintuco formation. At December 31, 2006, there were 23 wells producing oil in this field. Limited additional development drilling potential may still exist. Secondary recovery commenced in this field in 1989 with favorable results. Ten injection wells are active in this field. During 2006, one development well was drilled and completed as an oil producer.

Entre Lomas Field

The Entre Lomas structure is located in the central part of the concession to the northwest of the CB/PB field. At the depth of the producing formations, this anticline is cut by a fault near its crest. An oil field exists on the southwest or upthrown side of this fault and a gas field exists on the northeast or downthrown side.

Entre Lomas Oil Reservoirs

The Entre Lomas oil field is productive from the Quintuco formation, with some minor production from the Tordillo formation. Secondary recovery commenced in this field in 1998 with favorable results. The field now includes 36 producing wells and 22 water injection wells. It is believed that the downdip limits of this field are well defined. During 2006, one development well was drilled and completed as an oil producer.

Entre Lomas Gas Reservoirs

In 1994, the Entre Lomas partners commenced development of a gas field that is productive from the Petrolifera (Punta Rosada) formation. As of year end, there are ten producing wells in this field. Although the main body of the field now appears to have been defined, additional expansion possibilities exist to the northwest. In 2006, one gas development well was drilled to the Petrolifera (Punta Rosada) formation. It was not productive from the targeted formation, and was completed as an oil producer from the Quintuco formation.

Lomas de Ocampo Field

The Lomas de Ocampo field is located to the northwest of the Entre Lomas gas field on a separate structure that extends toward the northwest in the direction of the El Caracol field. The field now includes 28 wells with development drilling continuing to the northwest. A few wells in this field are capable of gas production from the Petrolifera (Punta Rosada) formation and oil production from the Quintuco formation. Most wells produce oil only from the Quintuco formation. Six field extension wells were drilled in 2006. Of the six wells drilled, all were completed and put on production. Additional development drilling to the west and northwest is planned for 2007.

Borde Mocho Field

The Borde Mocho field is the smallest field in the concession. It is located southwest of the CB/PB field near the concession’s southern boundary. To date 16 wells have been drilled and 15 are producing oil. The discovery well was drilled in 1996. All wells produce from the Tordillo, the main producing formation, and four wells are also productive from the Quintuco formation. It is believed that the limits of this field have been identified to the southeast but that additional limited drilling potential may still exist to the northwest. In 2006, four in fill wells were drilled, three were completed as oil producers, and one was abandoned due to problems that could not be resolved while drilling. Additional development drilling is planned for 2007.

Exploration

Since 1993, the Entre Lomas partners have conducted three campaigns to gather three dimensional (“3D”) seismic information. The most recent survey was completed in late 2003 during which the partners acquired 373 square kilometers of 3D seismic information over the southern portions of the concession. As a result, with the exception of a thin strip of the concession to the northeast of the Entre Lomas structure, the joint venture has 3D seismic images covering the principal producing fields and all of the surrounding acreage believed to be of most interest. The seismic surveys have multiple objectives the first of which is finding lower risk exploration opportunities that target formations known to be productive from structural closures and/or fault traps that exist away from the principal producing field areas. Other objectives are to evaluate for high risk deep exploration potential in sedimentary sequences that exist between the base of the Petrolifera (Punta Rosada) formation and the basement, and utilize 3D seismic images in ways that may help exploit the existing producing fields. Although work continues on the evaluation of exploration potential to objectives below the Petrolifera (Punta Rosada) formation, the primary focus to date has been the identification of lower risk drilling targets to formations known to be productive in the concession in structural closures and/or fault traps that have been identified close to the principal producing fields.

Since 2003, on the basis of interpretation of 3D seismic, five lower risk wells have been drilled on structural closures or fault traps away from the principal producing fields. Although all have been completed and put on production, the structures on which these wells have been drilled are limited in size and do not present development opportunities of more than a few wells. The joint venture partners plan to continue investigating drilling opportunities of this type in the near future.

Los Alamos

The Entre Lomas partners identified the Los Alamos area as a target for lower risk exploration through interpretation of 3D seismic images. In the 1970’s, the Los Alamos #1 well was drilled and found the Tordillo formation to be oil productive and with excellent reservoir characteristics. However, after a short production life the well was shut in due to a rapid increase in water production. Seismic images identified the potential for up dip stratigraphic trapping in the direction of the Piedras Blancas field. As a result, the Los Alamos #2 well was drilled, completed and placed on production in 2003. It was still on production at the end of 2006. Additional studies are required to determine if additional wells should be drilled in this area.

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 must be adhered to when conducting oil and gas exploration and exploitation activities. In response to these requirements, Petrolera implemented and maintains an Environmental Management System in the Entre Lomas concession needed to comply with ISO 14001: 1996 environmental standards, and OHSAS 18001: 1999 occupational health standards. Independent party audits are conducted annually to assure that the Entre Lomas certifications remain in full force. These standards surpass those required by the local governing authorities.

ACAMBUCO

The Company owns a 1.5 percent participation interest in the Acambuco joint venture, an oil and gas exploration and development concession located in Northwest Argentina, in the province of Salta, on the border with Bolivia. The Acambuco concession covers an area of 294,000 acres.

Description of the Concession

The Company has been a participant in the Acambuco area since 1981. The principal objective in Acambuco is the Huamampampa formation, a deep fractured quartzite that has sizable gas exploration and development potential. In Acambuco, Huamampampa is found at depths in excess of 14,000 feet. The Ramos and Aguarague concessions, immediately to the south and east of Acambuco, have major gas fields with significant gas production and reserves from Huamampampa. In 1994, the joint venture partners discovered the San Pedrito gas field whose principal reserves exist in the Huamampampa formation with additional reserves in the Icla and Santa Rosa formations both of which underlie Huamampampa.

The Acambuco joint venture currently consists of Pan American Energy Investments L.L.C. (“PAE”), an affiliate of British Petroleum PLC that owns 52 percent, Oil & Gas Development Ltd., an affiliate of Shell C.A.P.S.A. and YPF S.A. which each hold 22.5 percent interests, and Northwest Argentina Corporation and the Company which each hold interests of 1.5 percent. Northwest Argentina Corporation is a subsidiary of The Williams Companies, Inc.

San Pedrito Field

The first well to produce in the San Pedrito field was drilled in 1996 to a depth of 14,500 feet and discovered gas in the Huamampampa formation. For this initial well, the Company exercised its non-consent option and will participate in future revenues from this well after its partners recover their costs plus the contractual penalty related solely to this well. Since the discovery, three development wells have been drilled and completed as producers. The Company participated in all three development wells.

Macueta Field

In 2000, the joint venture partners drilled the Macueta x-1001 (bis) well on the Macueta structure located just south of the Bolivian border and next to the San Alberto field in Bolivia. This well reached a total depth of 17,500 feet, investigating both the Huamampampa and lcla formations. In 2001, due to lower than expected production test results, the joint venture partners decided to drill a horizontal extension into the crest of the structure. After reaching its objective, the well tested 36 million cubic feet per day of natural gas and 730 barrels per day of condensate. Subsequently the joint venture acquired 3D seismic images over the Macueta structure.

In January 2001, the joint venture re-entered the Macueta x-1002, drilled in the early 1980’s with the purpose of sidetracking this well to a more favorable structural position in the Huamampampa formation. The well experienced mechanical problems during drilling and was unable to reach the intended target. Production test volumes from the horizontal extension were disappointing. The Macueta structure in Acambuco is believed to be the southern extension of the San Alberto structure where a significant gas field estimated to contain several trillion cubic feet of natural gas is producing on the opposite side of the Bolivian border.

In order to produce and sell gas from the Macueta field, investments for the construction of a gas pipeline and modifications to the concession’s gas treatment plant were required. These investments commenced in 2005 and were completed in 2006. The Macueta x-1001 (bis) well was completed in mid-2006 with first production occurring in August. Drilling of the third development well, the Macueta 1003, commenced in the second quarter of 2006. It reached total depth in early 2007, and should be put into production later in 2007.

Other

Acambuco is situated in an overthrust belt where drilling can be difficult and costly not only because of the depths of the primary objectives, but also from the risk of mechanical problems during drilling. Wells drilled to date have required as much as one year to drill and the costs to drill and complete wells drilled to the Huamampampa formation have ranged from $30 to $50 million.

Acambuco Sales and Markets

Sales of both natural gas and condensate from the Acambuco joint venture commenced in March 2001. Acambuco gas and condensate are being sold under contracts negotiated by PAE primarily to domestic distribution companies and industrial customers in the northern part of Argentina.

TIERRA DEL FUEGO

The Company owns 25.72 percent participation interests in a joint venture engaged in E&P activities in the TDF Concessions located on the island of Tierra del Fuego. The interests were acquired in 2005 and gave the Company operations in a fourth Argentine producing sedimentary basin, the Austral basin. The Austral basin 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 the three TDF Concessions. The Río Cullen, Las Violetas, and Angostura concessions cover surface areas of 72,128, 294,132 and 70,504 acres, respectively, totaling approximately 436,764 gross acres, or 112,336 acres net to the Company’s interest. Each of the concessions extends three kilometers offshore with their eastern boundaries paralleling the coastline. The TDF Concessions each have a term of 25 years that runs to 2016 with an option to extend the concessions for an additional ten year period with the consent of the government.

The TDF Concessions joint venture currently consists of the Company, which owns a 25.72 percent interest, Antrim Argentina S.A., an affiliate of Antrim Energy, Inc. that owns 25.78 percent, ROCH S.A., that owns 24.29 percent, San Enrique Petrolera S.A. that owns 12.61 percent, and DPG S.A. that owns 11.54 percent.

Operations in the TDF Concessions are exempt from Argentine federal income taxes pursuant to Argentine law and income generated in the concessions is not subject to Argentine federal taxes as long as the current exemption remains in effect. Effective October 2006, the Argentine government decreed that the Tierra del Fuego federal tax exemption no longer applied to hydrocarbon export taxes. As a result, all oil, gas and LPG produced on and exported from the island of Tierra del Fuego is now subject to federal export taxes.

Description of the Concessions

Río Cullen Concession

The Río Cullen concession covers 72,128 gross acres in the northern part of the Argentine side of the island of Tierra del Fuego. The concession includes two fields, the Río Cullen and Cañadón Piedras fields that account for approximately eight percent of the Company’s total oil and gas production from its TDF Concessions interests. The Río Cullen field produces natural gas and condensate from four active producing wells. The Cañadón Piedras field is an oil field with two active producing wells. The Cañadón Alfa field located offshore and immediately to the north and east of the Río Cullen concession is one of the largest gas fields in Argentina.

Las Violetas Concession

The Las Violetas concession covers 294,132 gross acres and is the largest onshore concession on the Argentine side of the island of Tierra del Fuego. The concession includes nine fields with 25 wells on production at the end of 2006. These fields, including the Los Patos, Los Flamencos, Las Violetas, and San Luis fields are natural gas and condensate producers from the Springhill formation. The Río Chico field produces oil from the Springhill. During 2006, the TDF partners drilled the Las Violetas 105 well that discovered oil north of a fault that serves as the northern boundary of the Las Violetas gas field. In addition, the Los Patos 1005 well drilled in mid 2006 identified a rim of oil beneath the Los Patos gas reservoir. This well was put into production and additional oil rim wells were drilled and put into production by the end of 2006.

At the end of 2006, various wells are shut-in due to production and delivery capacity constraints that should be alleviated as a result of investments planned for 2007. At year end 2006, the Las Violetas concession accounted for approximately 88 percent of the Company’s oil production and 92 percent of the Company’s gas production from its TDF concession interests. The Las Violetas and Angostura concessions are both located adjacent to the San Sebastián field, another of Argentina’s largest gas fields.

Angostura Concession

The least developed of the TDF Concessions is the Angostura concession, which covers 70,504 gross acres on the strip of land between the coast of the San Sebastián Bay and the border between Argentina and Chile. The concession consists of four fields, the Cerro Cortado, Angostura, Gaviota and Las Lagunas fields, each having one active producing well. The concession produces approximately four percent of the Company’s total TDF oil production and a small amount of associated gas from the Springhill formation. This concession is believed to have both exploration and reactivation potential. Structures that are at this time considered leads have been identified with previously acquired 2D seismic. No 3D seismic exists over this area, but a seismic program is already in progress in 2007 as described below. Additionally, well workovers performed in 2006 resulted in better than expected results.

Markets

At this time, oil sold from the TDF Concessions is exported to Chile. The price received is based on the sale price of WTI less a quality and gravity discount that has averaged between $4 and $8 per barrel. Natural gas production from the TDF Concessions is sold under contract and primarily supplies industrial and residential markets in the island of Tierra del Fuego. When purchased, the TDF Concessions were equipped with internal gathering lines, pipeline, gas treatment plant, and the San Luis LPG plant located in the Las Violetas concession that produces propane and butane that is exported and sold domestically under contract.

Seismic, Drilling Program and Production Facilities

After closing the acquisition of the TDF Concessions in early 2005, the joint venture partners commenced a program to acquire 360 square kilometers of 3D seismic information that covered three separate blocks over five producing fields. Four of these fields are located in the Las Violetas concession and one is located in the Río Cullen concession. Interpretation of this information was completed by the end of 2005. No 3D seismic data had been acquired at that time over any part of the Angostura concession. After interpreting the above described 3D seismic, the TDF partners commenced a 19 well drilling program. There were difficulties securing the services of a drilling contractor due to unavailability of rigs, but the first well commenced drilling before the end of 2005. The approximate depth of these wells ranges from 6,000 to 8,000 feet. In total, 19 wells were drilled between November 2005 and October 2006. The contract for the drilling rig used to drill the first 19 wells ended in October of 2006.

The result of the drilling program has been very successful, with several key wells yielding higher than expected production test results. Of the 19 wells drilled, three were not productive. Of the remaining 16 wells, not all are currently on production due to the previously described capacity constraints.

Gas produced from all of the above wells have varying contents of propane and butane that can be extracted and sold to local and export markets. A portion of gas produced is consumed in field operations and in the production of LPG.

With a break in the drilling activity, the joint venture partners commenced a second 3D seismic program in December 2006 to acquire approximately 350 square kilometers of seismic information over portions of the Las Violetas and Angostura concessions. A new rig has been contracted and drilling activity is expected to re-commence in the second quarter of 2007.

Production facilities investments required to get new gas to market were completed during July 2006, raising the production capacity from 14 mmcf per day to 21 mmcf per day. A one year gas sales contract was signed in the second quarter, allowing gross daily gas production to approximately double from second quarter levels with corresponding increases in condensate and gas liquids production. This increased volume of production commenced in August 2006. During December 2006, gross daily oil, gas and LPG production averaged 1,213 bbls, 19.1 mmcf, and 24 metric tons, respectively, compared with 504 bbls, 11.5 mmcf, and 14.1 metric tons, respectively, during February 2005 when the Company acquired its interest in the TDF Concessions. Additional capital will be spent in 2007 on an oil pipeline, storage and crude oil treatment facilities, gas compression, and a gas pipeline that will connect the Las Violetas concession to the San Martín pipeline that transports gas to mainland Argentina. When completed in the second half of 2007, these investments are scheduled to increase total gas deliverability in the Las Violetas concession to 35 mmcf per day and enable the partners to put into production currently shut in oil and gas-condensate wells.

Refer to the section “Tierra del Fuego” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on page 21 for a further discussion about production facilities in the TDF Concessions and for a discussion regarding the challenges of marketing increased gas production in Tierra del Fuego.

CAÑADÓN RAMIREZ

The Company owns an 81.82 percent participation interest in the 92 thousand acre Cañadón Ramirez concession, located in southern Argentina, in the province of Chubut. ROCH S.A., an Argentine Company, owns the remaining interest. This concession produces hydrocarbons from the Golfo San Jorge basin, the oldest oil-producing province in the country. The Cañadón Ramirez concession has a term of 25 years that runs to 2016 with an option to extend the concession for an additional ten year period with the consent of the government.

During 2006, the Company reevaluated previously acquired seismic and identified new drilling prospects to deeper horizons not previously explored in Cañadón Ramirez.

In early 2007, the Company executed a farm-out agreement with CanAmericas Energy (“CanAmericas”). The agreement allows CanAmericas to earn a 49 percent interest by exploring the deeper horizon over an area of mutual interest covering the western half of the concession. The agreement is discussed in more detail in the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on page 21.

CAPRICORN

In April 2003, the Company entered into a farm-in agreement with Netherfield. The agreement entitled the Company to earn a 50 percent interest in an exploration permit granted over the Yacimiento Norte 1/B Block, commonly known as the Capricorn block. The Capricorn block has a surface area of 8,182.87 square kilometers, or approximately 2.1 million acres located in the province of Salta in northern Argentina. There was no exploration activity in Capricorn in 2004. During 2005, the Company and its partner reviewed seismic lines over the southernmost portion of the block in an area near oil production in the adjacent concession. This area was identified as prospective and targeted for future evaluation. Seismic will be acquired over this area in 2007.

The block was originally scheduled to expire in August 2005, but the joint venture partners were able to obtain an extension of the exploration period term through December 31, 2005. After relinquishing 51 percent of the exploration permit’s acreage and committing to drill an exploration well and conduct other exploration activities, the Company and its partners entered the second exploration period in early 2006. The second exploration period ended at the end of 2006 without fulfillment of the required investment commitment due to the inability to contract a drilling rig. The Company applied for and received both provincial and federal government approval for an extension of the permit through December 31, 2009. To obtain this extension, the joint venture partners were required to relinquish additional acreage and to drill an exploration well in 2007 . As of January 2007, the Capricorn permit covers a total surface area of 485,955 square acres.

In October of 2006, the Company and its partners entered into an agreement to farm-out an interest in the permit to Gold Point Energy Corp. (“GP Energy”). Under the terms of the agreement, GP Energy has committed to pay 50 percent of a capital program that will satisfy the investment commitment for the second exploration period. These investments are planned for 2007. GP Energy’s funding of 50 percent of this capital program will earn it a 25 percent working interest in the Martínez del Tineo Oeste prospect area located on the western edge of the Capricorn permit. The agreement is discussed in greater detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on page 22 .

EMPLOYEES

At March 1, 2007, the Company had 13 full-time employees.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

The Company is a Cayman Islands corporation with executive offices located in Tulsa, Oklahoma and a branch office located in Buenos Aires, Argentina. All of the Company’s operations are located in Argentina.

The Company has no operating revenues in either the Cayman Islands or the United States. Because all of the Company’s operations are located in Argentina, all of its products are sold either domestically in Argentina, or exported from Argentina to either Brazil or Chile. Refer to Note 6 of Notes to Consolidated Financial Statements for a description of sales during the last three years to customers that constitute greater than ten percent of total operating revenues.

With exception of cash and cash equivalents deposited in banks in the Cayman Islands, Bahamas, and the United States, and furniture and equipment in its executive offices, all of the Company’s assets are located in Argentina.

Risks associated with foreign operations are discussed elsewhere in this Item 1 and in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk.”

AVAILABLE INFORMATION

The Company files its 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 the Company files 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.

The Company does not maintain an Internet website. However, the Company will provide electronic or paper copies of its 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, free of charge, upon reasonable request. Such requests should be directed to the Corporate Secretary, Apco Argentina Inc., 4700 One Williams Center, Tulsa, Oklahoma, 74172.

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 Securities Exchange Act of 1934, as amended. These statements discuss the Company’s expected future results based on current and pending business operations. The Company makes 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 which address activities, events or developments that the Company expects, believes or anticipates 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,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled,” “will”, or similar expressions. These forward-looking statements include, among others, statements regarding:

amounts and nature of future capital expenditures;

expansion and growth of the Company’s business and operations;

business strategy;

estimates of proved oil and gas reserves;

reserve potential;

development drilling potential;

cash flow from operations; and

oil and 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 document. Many of the factors that will determine these results are beyond the Company’s ability to control or project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

the uncertainties inherent in assessing and estimating reserves and future reserves, market demand, and volatility of prices;

inflation, interest rates, fluctuation in foreign currency exchange rates, and general economic conditions;

the impact of operational and development hazards;

costs of, changes in, or the results of laws, government regulations, environmental liabilities, and litigation;

political conditions in Argentina and other parts of the world;

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

risks associated with weather conditions, earthquakes, and acts of terrorism.

Given the uncertainties and risk factors that could cause the Company’s actual results to differ materially from those contained in any forward-looking statement, the Company cautions investors not to unduly rely on its forward-looking statements. The Company disclaims any obligations to and does 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 the Company’s actual results to differ, the factors listed above and referred to below may cause the Company’s intentions to change from those statements of intention set forth in this report. Such changes in the Company’s intentions may also cause its results to differ. The Company may change its intentions at any time and without notice, based upon changes in such factors, its assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, the Company cautions 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.

RISK FACTORS

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

Risks Inherent to the Company’s Industry and Business

Estimating reserves and future net revenues involves uncertainties and potential negative revisions to reserve estimates, and oil and gas price declines may lead to impairment of oil and gas assets.

Estimates of the Company’s proved reserves included in the unaudited supplemental oil and gas information in this report on Form 10-K are prepared in accordance with guidelines established by GAAP and by the United States Securities and Exchange Commission (“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 third party reserve engineer that prepares the estimate.

The Company’s proved reserve information is based on estimates prepared by its independent reserve engineer. Estimates prepared by others may be higher or lower than the Company’s estimates. 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.

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, the Company based the estimated discounted future net cash flows from the estimate of proved reserves as of December 31, 2006, on prices and costs on the date of the estimate. The WTI price on the date of the estimate was $61.05. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

The Company’s estimates of proved reserves materially impact depreciation, depletion and amortization expense. If negative revisions in the estimated quantities the estimates 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 decline, the rate at which the Company records depreciation, depletion, and amortization expense. The revisions may also be sufficient to trigger impairment losses on certain properties which would result in a further non-cash charge to earnings. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost reserves. In addition, the decline in proved reserve estimates may impact the outcome of the Company’s assessment of its oil and gas producing properties for impairment.

Historic performance of the Company’s exploration and production program is no guarantee of future performance.

The success rate of the Company’s exploration and drilling program in 2006 should not be considered a predictor of future performance. Performance of the Company’s exploration and production activities is affected in part by factors beyond its control (any of which could cause the results of this business to decrease materially), such as:

regulations and regulatory approvals;

availability of capital for drilling projects which may be affected by other risk factors discussed in this report;

cost-effective availability of drilling rigs and necessary equipment;

availability of skilled labor;

availability of cost-effective transportation for products; and

market risks discussed in this report.

The Company’s drilling, production, gathering, processing, and transporting activities involve numerous risks that might result in accidents and other operating risks and hazards.

The Company’s 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 gas. These operating risks include, but are not limited to:

blowouts, cratering, and explosions;

uncontrollable flows of oil, natural gas, or well fluids;

fires;

formations with abnormal pressures;

pollution and other environmental risks; and

natural disasters.

In spite of the Company’s precautions, an event could cause considerable harm to people or property and could have a material adverse effect on the Company’s financial condition and results of operations.

Costs of environmental liabilities and complying with existing and future environmental regulations could exceed the Company’s current expectations.

The Company’s 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, 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 the Company’s facilities.

Compliance with environmental legislation could require significant expenditures including clean up costs and damages arising out of contaminated properties and for the possible failure to comply with environmental legislation and regulations that might result in the imposition of fines and penalties. In connection with certain acquisitions and divestitures, the Company could acquire, or be required to provide indemnification against, environmental liabilities that could expose it to material losses, which may not be covered by insurance. In addition, the steps the Company could be required to take to bring certain facilities into compliance could be prohibitively expensive, and the Company might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. Although the Company does not expect that the costs of complying with current environmental legislation will have a material adverse effect on its financial condition or results of operations, no assurance can be given that the costs of complying with environmental regulation in the future will not have such an effect.

The Company makes assumptions and develops 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, the Company’s assumptions may change. The Company might not be able to obtain or maintain from time to time all required environmental regulatory approvals for certain development projects. If there is a delay in obtaining any required environmental regulatory approvals or if the Company fails to obtain and comply with them, the operation of its facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to its operations.

Because of the natural decline in production from existing wells, the Company’s future success depends on its ability to obtain and successfully develop new reserves.

The production from the Company’s existing wells will naturally decline over time, which could mean that the Company’s cash flows associated with its wells could also decline over time. Maintaining the Company’s current rate of production is dependent upon obtaining new oil and gas properties and successfully exploring, drilling, and producing products from those and existing properties on economically feasible terms. Competition for oil and gas properties is high and exploring for and producing hydrocarbons from these properties is becoming increasingly expensive. Achieving growth is dependent upon the Company’s finding or acquiring additional reserves, as well as successfully developing current reserves, and risks associated with drilling may cause drilling operations to be delayed or cancelled.

The Company has experienced a shortage in the availability of drillings rigs in recent years.

The Company’s ability to develop its reserves is dependent on its ability to contract drilling rigs. In recent years, the Company has experienced a shortage in the availability of drilling rigs due to increased demand for rigs in Argentina. If the Company is unable to contract for drilling rigs on reasonable prices and terms, its results of operations and rate of production could be adversely affected.

The Company’s oil sales have historically depended on a relatively small group of customers. The lack of competition for buyers could result in unfavorable sales terms which, in turn, could adversely affect the Company’s financial results.

The entire Argentine domestic refining market is small. There are five active refiners that constitute 99 percent of the total market. As a result, the Company’s oil sales have historically depended on a relatively small group of customers. The largest of these five companies refines only its own crude oil production, while the smallest of the five operates only in the northwest basin of Argentina. That leaves only three domestic refiners to which the Company can sell its Entre Lomas production. During 2006, the Company sold all of its Entre Lomas oil production, which constitutes more than 90 percent of its total oil production, to a refinery owned by Petrobras Energía. The lack of competition in this market could result in unfavorable sales terms which, in turn, could adversely affect the Company’s financial results.

The Company is not the operator of all its hydrocarbon interests. The reliance on others to operate these interests could adversely affect the Company’s business and operating results.

The Company relies on Petrolera as the operator of the Entre Lomas concession, which comprised approximately 86 percent of the Company’s total hydrocarbon production in 2006. The Company also relies on Pan American Energy and ROCH as the operators of the Acambuco concession and the TDF Concessions, respectively. As the non operating partner, the Company has 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 the Company’s control, including the competence and financial resources of the operators.

Changes in, and volatility of, supply, demand, and prices for crude oil, natural gas and other hydrocarbons has a significant impact on the Company’s ability to generate earnings, fund capital requirements, and pay shareholder dividends

Historically, the markets for crude oil, natural gas, and other hydrocarbons have been volatile and they 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 the Company’s control, including:

worldwide and domestic 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 level of market demand;

the price and availability of other types of fuels;

the availability of pipeline capacity;

supply disruptions and transportation disruptions;

the price and level of foreign imports;

domestic and foreign governmental regulations and taxes;

adherence by Organization of Petroleum Exporting Countries (“OPEC”) member nations to production quotas, and future decisions by OPEC to either increase or decrease quotas

Argentine governmental actions;

the overall economic environment; and

the credit of participants in the markets where hydrocarbon products are bought and sold.

Risks Associated with Operations in Argentina

The right of the Company to explore for, drill for, and produce hydrocarbons in Argentina are generally derived from participation in concessions granted by the Argentine government, which have a finite term, the expiration or termination of which could materially affect the Company’s results.

The right of the Company to explore for, drill for, and produce hydrocarbons in Argentina is generally derived from participation in concessions granted by the government, which have a finite term, the expiration or termination of which could materially affect the Company’s results. For example, the term of the Entre Lomas concession, which comprised approximately 86 percent of the Company’s total hydrocarbon production in 2006, currently runs to the year 2016. The term of a concession can be extended for 10 years with the consent of the Argentine government. However, the government may withhold its consent at its sole discretion, or could extend the term of the concession on terms less favorable than those the Company has today.

In addition, the Company estimates its asset retirement obligation based on the number of wells it expects to abandon through the end of the term of its concessions. If the government grants the Company an extension to a concession term, the estimate of its asset retirement obligation will increase by the number of wells that have an expected productive life beyond the end of the current concession term but are expected to cease production during the extension period.

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

Refer to the section “Argentine Economic and Political Environment” on pages 28 and 29 for a description of Argentina’s economic crisis of 2002 and the governments reaction to that crisis. Reference is also made to the discussion under the caption “Requirements to Offer Products in Domestic Market” on page 24. Some of those actions had an adverse effect on the Company’s results.

Argentina’s economic and political situation continues to evolve and the Argentine government may enact future regulations or policies that, when finalized and adopted, may materially impact, among other items, (i) the realized prices the Company receives for the commodities it produces and sells as a result of new taxes; (ii) the timing of repatriations of cash to the Cayman Islands; (iii) the Company’s asset valuations; and (iv) peso-denominated monetary assets and liabilities. Reference is made to Item 7A., “Quantitative and Qualitative Disclosures about Market Risk.”

Strikes, work stoppages, and protests could increase the Company’s operating costs, hinder operations, reduce cash flow, and delay growth projects.

Strikes, work stoppages, and protests could arise from the delicate political and economic situation in Argentina and these actions could increase the Company’s operating costs, hinder operations, reduce cash flow, and delay growth projects.

Price reduction formulas in agreements to sell crude oil to refiners reduce considerably the increases in the sale price net back to the Company as the price of crude oil increases. Consequently, recent sharp increases in oil prices have benefited oil producers outside of Argentina more than the Company.

Since Argentina’s economic crisis of 2002, the Argentine government has maintained that, in order to prevent excessive levels of inflation, it would do what it could to shield the Argentine consumer from rising fuel prices. Therefore, in order to maintain stability in Argentine gasoline and diesel prices and avoid inflationary pressures on the economy, the Argentine government, through the implementation of an oil export tax that has been raised on multiple occasions, has encouraged producers and refiners to take actions needed to alleviate the impact of higher crude oil prices on Argentina’s economy. As a result, producers and refiners, including the Company and Petrolera, have enacted reduction factors in price formulas that reduce considerably the increase in the sale price net back to Argentine producers as the price of crude oil increases. Consequently, recent sharp increases in oil prices have benefited oil producers outside of Argentina more than the Company.

Risks Related to Regulations that Affect the Company’s Business

The cost and outcome of legal and administrative claims and proceedings against the Company and its subsidiaries could adversely affect the Company’s results and operations.

The Company is party to certain proceedings based upon alleged violation of foreign currency regulations as described in Note 11 of Notes to Consolidated Financial Statements under “Item 8. Financial Statements and Supplementary Data.” The process is in the early stages and the Company anticipates that this matter will remain open for some time. Under the pertinent foreign exchange regulations, the central bank of Argentina may impose significant fines on the Company. The result of an adverse decision could adversely affect the Company. In addition, the cost and outcome of any future legal or administrative claims could adversely affect the Company.

Changes in Argentine laws and regulations to which the Company is subject, including tax, environmental and employment laws, and regulations, could have a material affect on its operations and results.

The Company is subject to numerous laws and regulations in Argentina, which, among others, include those related to taxation, environmental regulations, and employment. Regulation of certain aspects of the Company’s business that are currently unregulated in the future and changes in the laws or regulations could materially affect the Company’s results and operations.

Risks Related to Employees

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

Certain of the Company’s employees who have many years of service have extensive institutional knowledge. As these employees reach retirement age, the Company may not be able to replace them with employees of comparable knowledge and experience. Other qualified individuals could leave the Company or refuse its offers of employment if the Company’s recruiting and retention efforts are unsuccessful. The Company’s efforts at knowledge transfer could be inadequate.

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

The Company’s assets and operations can be affected by weather and other natural phenomena.

The Company’s assets and operations can be adversely affected by hurricanes, earthquakes, tornadoes, and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for the Company to realize the historic rates of return associated with these assets and operations.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

See Item 1 (c) for a description of properties and refer to “Unaudited Supplemental Oil and Gas Information” on pages 46 and 47 for tables that present estimates of the Company’s net proved reserves.

ITEM 3.

LEGAL PROCEEDINGS

The information called for by this item is provided in Note 11 of Notes to Consolidated Financial Statements under Part II, Item 8 Financial Statements and Supplementary Data, which information is incorporated by reference into this item.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

PART II

ITEM 5.

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

Market information, Number of Shareholders and Dividends

The Company’s ordinary shares are traded sporadically on the NASDAQ Capital Market under the symbol “APAGF.” At the close of business on March 1, 2007, there were 809 record holders of the Company’s ordinary shares, $0.01 par value. The high and low trade closing sales price ranges and dividends declared by quarter for each of the past two years are as follows:

	2006						2005
Quarter	High		Low		Dividend		High		Low		Dividend
1^st	$	89.00	$	52.23	$	.30	$	38.02	$	37.74	$	.16¼
2^nd	$	85.25	$	77.00	$	.30	$	37.50	$	37.06	$	.16¼
3^rd	$	84.05	$	91.50	$	.35	$	41.91	$	41.47	$	. 25
4^th	$	87.75	$	80.50	$	.35	$	49.40	$	48.95	$	. 25

Beginning in the third quarter of 2005, the Company increased quarterly shareholder dividends on three separate occasions as indicated in the above table. The current quarterly dividend is 35 cents per share. Future dividends are necessarily dependent upon numerous factors, including, among others, earnings, levels, levels of capital spending, funds required for acquisitions, changes in governmental regulations and changes in crude oil and natural gas prices. The Company reserves the right to change the level of dividend payments or to discontinue or suspend such payments at the discretion of the board of directors.

The Company has been advised that: the Company may not pay dividends to shareholders out of its share capital or share premium account; 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 Company’s ordinary shares; there are no limitations either under the laws of the Cayman Islands or under the Company’s memorandum or articles of association restricting the right of foreigners to hold or vote the Company’s ordinary shares; there are no existing laws or regulations of the Cayman Islands imposing taxes or containing withholding provisions to which United States holders of the Company’s ordinary shares are subject; and there are no reciprocal tax treaties between the Cayman Islands and the United States.

Performance Graph

Set forth below is a line graph comparing the Company’s cumulative total shareholder return on its ordinary shares with the cumulative total return of the NASDAQ Stock Market (U.S. and foreign) and the NASDAQ Oil & Gas Extraction Index (SIC 1300-1399, U.S. and foreign companies) for a five-year period commencing December 31, 2001. The industry index was prepared by the Center for Research in Security Prices, Graduate School of Business, The University of Chicago. The Company will undertake to provide shareholders a list of the component companies included in the NASDAQ Oil and Gas Extraction Index upon request.

ITEM 6.

SELECTED FINANCIAL DATA

The following historical financial information presented below is derived from the Company’s audited financial statements.

(Amounts in thousands except per share amounts)	2006		2005		2004		2003		2002
Revenues	$	57,952	$	41,739	$	29,628	$	26,603	$	20,092
Equity Income from Argentine investments		22,391		18,304		11,657		9,009		3,514
Net Income		40,062		29,846		15,506		12,429		7,278
Income per Ordinary Share, Basic and Diluted		5.44		4.06		2.11		1.69		.99
Dividends Declared per Ordinary Share		1.30		.83		.65		.65		.65
Total Assets at December 31,		164,244		132,713		104,931		92,116		85,722
Total Liabilities at December 31,		14,241		12,408		8,021		5,845		7,009
Stockholders’ Equity at December 31,		150,003		120,305		96,910		86,271		78,713

Refer to the table “Volume, Price and Cost Statistics” on page 51 for variations in prices that influence the Company’s revenues and net income.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

LIQUIDITY AND CAPITAL RESOURCES

Cash Flow

Internally generated cash flow from the Company’s interests in the Entre Lomas concession is the Company’s primary source of liquidity. In the past, both during calm periods and turbulent periods in Argentina’s economy, the Entre Lomas concession has had the ability to finance development and exploration expenditures with internally generated cash flow. Historically, the Company has not relied on other sources of capital such as debt or equity, in part due to the Company’s focus on development of the Entre Lomas concession, but also due to the turmoil that has periodically affected Argentina’s economy making financing difficult to obtain at reasonable terms.

Although the Company has interests in several oil and gas properties in Argentina, including the purchase of the interest in the TDF Concessions that was completed in February 2005, its direct participation in the Entre Lomas concession and its equity interest in Petrolera generate most of its cash flow.

During 2006, the Company generated cash flow from operating activities of $41.2 million that included $15.5 million in dividends from its Argentine investment in Petrolera. These amounts compare with net cash provided by operating activities of $31.1 million and $18.8 million, and dividends from Argentine investments of $12.6 million and $8.6 million for the years 2005 and 2004, respectively.

Of the $41.2 million of operating cash flow generated during 2006, $18.2 million was used for the Company’s capital program for the continuing development and exploration of the Entre Lomas, Acambuco, and the TDF Concessions, and $8.8 million was paid to the Company’s shareholders in the form of dividends. The Company ended 2006 with cash, cash equivalents, and short-term investments of $49.7 million, representing an increase of $14.9 million during the year.

Net Income

Oil Prices

Volatility of oil prices has a significant impact on the Company’s ability to generate earnings, fund capital requirements, and pay shareholder dividends.

For some time, oil prices have been increasing in response to a combination of events that include oil workers strikes and civil unrest in major oil producing countries, the war in Iraq, and improving economic conditions throughout the world, in particular accelerating economic growth in China and India. During 2004 and 2005, weather related events and the realization that the world’s excess productive capacity had almost disappeared pushed commodities markets to raise the price of oil from $30 per barrel to record levels above $60. During 2006, the price of West Texas Intermediate (“WTI”), the crude oil type that serves as the reference price for crude oil sales contracts in Argentina, oscillated in a range from $60 to $70 per barrel while, at times, exceeding $70. The lack of hurricane activity in the Gulf of Mexico during the 2006 hurricane season alleviated supply concerns in commodities markets that resulted in a softening of oil prices during the second half of 2006, and the year ended with a WTI spot price of $61.05 per barrel. Additionally, a relatively warm winter season in 2006 and thus far in 2007 has further reduced oil prices, as the WTI price per barrel has ranged between $50 and $60 in 2007. Drilling activity worldwide increased sharply in 2005 and 2006 in response to favorable oil prices which could lead to future supply increases. Economic growth could be negatively impacted by sustained higher oil prices, which could result in decreased demand. In spite of these two factors, market forecasts indicate that prices may remain at current levels or higher for the foreseeable future.

Since Argentina’s economic crisis of 2002, the Argentine government has maintained that, in order to prevent excessive levels of inflation, it would do what it could to shield the Argentine consumer from rising fuel prices. Therefore, in order to maintain stability in Argentine gasoline and diesel prices and minimize inflationary pressures on the economy, the Argentine government, through the implementation of an oil export tax and strict price controls over gasoline prices, has encouraged producers and refiners to take actions needed to alleviate the impact of higher crude oil prices on Argentina’s economy. As a result, producers and refiners, including the Company and Petrolera, have enacted reduction factors in price formulas that reduce considerably the increases in the sale price net back to Argentine producers as the price of oil increases. Consequently, increases in oil prices have benefited oil producers outside of Argentina more than the Company. Nevertheless, the Company has experienced healthy oil price increases as described in the following paragraph.

As reflected in the statistical table on page 51, although the price of crude oil has been above $60 per barrel during 2006 and exceeded $70 at various times, the Company’s per barrel crude oil sales price during 2006, including its equity interests, averaged $43.29 compared with $37.89 during 2005, and $31.30 in 2004.

Although the level of oil prices achieved in 2006 has had a positive impact on the Company’s net income and cash flow, given the past volatility of world oil prices and their sensitivity to political events and possible reactions of OPEC, there is no assurance that oil prices will remain at these levels in 2007 and beyond. Many factors affect oil markets, including among others, major exploration discoveries throughout the world, the level of development investments in the oil and gas industry, fluctuations in market demand, adherence by OPEC member nations to production quotas, and future decisions by OPEC to either increase or decrease quotas. Furthermore, the Company’s future oil prices could be negatively impacted by Argentine governmental actions.

Natural Gas Prices

The Company sells its gas to Argentine customers pursuant to peso denominated contracts with occasional spot market sales. As described in the following paragraph, gas prices in Argentina have been on the rise since 2004. The statistical table on page 51 reflects that the Company’s average natural gas sale price per mcf, including its equity interests, averaged $1.36 in 2006 compared with $1.06 during 2005. In addition, the average natural gas sale price per mcf for 2004 was $0.75.

Events in Argentina in 2004 caused gas prices to increase. As a consequence of a resurgence of growth in Argentina’s economy in 2003 and 2004 and stimulated by low gas prices resulting from a natural gas price freeze implemented by the Argentine government in 2002, demand for natural gas in Argentina has grown. The unfavorable gas price environment for producers also acted to discourage gas development activities. Without significant development of gas reserves in Argentina, supplies of gas in the country failed to keep up with increased demand for gas. The result was a natural gas and power supply shortage during 2004 that has continued into 2006. Since the beginning of 2004, the Argentine government has taken several steps in an effort to prevent possible shortages. Gas exports to Chile were curtailed and the country entered into agreements to import natural gas from Bolivia. During the first half of 2004, the Argentine government approved measures that enabled natural gas producers in the country to sell directly to large industrial users through contracts and prices negotiated directly between the parties in accordance with price increases permitted by the Secretary of Energy. This has resulted in a gradual increasing trend in natural gas prices since the beginning of 2004 that has continued into 2006. As described in the previous paragraph, this increasing trend is evident in the gas prices the Company has realized since the beginning of 2004. Furthermore, Argentina recently agreed to raise the price of imported gas purchased from Bolivia to prices exceeding $5.00 per mcf, or significantly greater than sales prices for gas produced in Argentina. Gas prices to residential customers remain frozen at less than 50 cents per mcf.

Product Volumes

During 2006, oil sales volumes, net to the Company’s consolidated and equity interests, totaled 2.403 mmbbls, an increase of ten percent when compared with 2.184 mmbbls during 2005. Approximately 85 percent of the increase is due to favorable results generated by the 2006 Entre Lomas development drilling campaign, while the remaining 15 percent of the increase represents sales volumes contributed by the TDF Concessions. In order to provide additional perspective regarding current oil sales volumes, the Company’s comparable oil sales volumes for the years 2004 and 2003, net to the Company’s consolidated and equity interests, totaled 1.981 million bbls and 1.927 million bbls, respectively.

In 2006, gas sales volumes, net to the Company’s consolidated and equity interests, totaled 6.7 billion cubic feet (“bcf”), an increase of six percent when compared with 6.3 bcf during 2005. This increase was lower than expected as strong production increases from the TDF Concessions and from Acambuco were offset by lower gas sales volumes in Entre Lomas. As mentioned previously, the one gas development well drilled in 2006 on the Entre Lomas concession was not productive from the targeted formation, and the well was completed as an oil producer. Production from the TDF Concessions increased 131 percent compared to 2005 volumes as production facilities investments were completed during July 2006, raising the gross production capacity from 14 mmcf per day to 21 mmcf per day, and a one year gas sales contract effective in August allowed gross daily gas production to approximately double from second quarter levels. Acambuco volumes increased 62 percent compared to 2005 as the Macueta x-1001 (bis) well was completed and put into production in mid-2006.

LPG sales volumes, net to the Company’s consolidated and equity interest, totaled 20 thousand tons, an increase of four percent when compared with 19.3 thousand tons during 2005.

Refer to the statistical table presented on page 51 for an analysis of volumes between consolidated and equity interests for the last three years.

Oil Market Concentration

The Company’s sales to a refinery owned by Petrobras Energía represent 74 percent of its total operating revenues. In Argentina today there are currently five active refiners operating in the country that constitute 99 percent of the total market. The largest of these five refines only its own upstream production, while the smallest of the five operates only in the northwest basin of Argentina. That leaves only three domestic refiners to which the Company can sell its Entre Lomas production which constitutes over 90 percent of its total oil production. Decisions to sell to these customers are based on advantages presented by the commercial terms negotiated with each customer. The Company has the option to broaden its customer base by exporting its crude oil and has done so in previous years. However, this would have disadvantaged the Company during 2006 because net backs obtained by selling oil in Argentina are currently greater than those that can be received for export sales. In addition, because of the Company’s limited size and the volume of oil required to fill an oil tanker, the Company must join other sellers to export. Today, producers of Medanito crude oil, a term used to describe crude oil produced in the Entre Lomas region of the Neuquén basin, are selling to Argentine refiners. Refer to Note 6, of Notes to Consolidated Financial Statements, for a description of the Company’s major customers over the last three years.

The discounts from WTI negotiated with Petrobras Energía throughout 2006 were competitive with those received by other producers of Medanito crude oil in the Neuquén basin.

Seasonality

Of the products sold by the Company, 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 2006, natural gas sales represented 10 percent of the Company’s total operating revenues compared with eight and six percent during 2005 and 2004, respectively. Consequently, the fluctuation in natural gas sales between summer and winter is not significant for the Company.

Entre Lomas

During 2006, the Entre Lomas joint venture partners executed another successful drilling campaign, drilling 31 of 36 wells planned for the year. Only one well was not put on production due to mechanical problems during drilling. The drilling campaign was not completed by year end due to some wells taking longer than expected to drill, and delays caused by one of two drilling rigs temporarily leaving the concession. However, drilling with two rigs re-commenced in December 2006, and the remaining five wells from the 2006 program were drilled in early 2007. Employing two drilling rigs from January to July enabled gross daily oil production to average 11,990 barrels during 2006, compared with 11,164 in 2005 and 10,346 in 2004. Investments planned for 2007 consist of drilling 40 wells, including one gas well and one exploration well. The Entre Lomas concession is the primary property in which the Company participates. It contributes 86 percent of the Company’s total hydrocarbon production. Refer to pages 2 through 6 for a description of the Entre Lomas concession.

Tierra del Fuego

As described on pages 7 and 8 under the caption “Tierra del Fuego,” the Company and its partners embarked on a 19 well drilling program that commenced in November of 2005 and was completed in October 2006. This program cost $16.2 million, or $4.2 million net to the Company. The acquisition of the interest in the TDF Concessions was made on the basis that there exists considerable development potential in existing producing fields and exploration potential. To date, the Company’s investment program has focused primarily on development of existing producing fields. As a result, most of the wells drilled to date have been development wells required to determine the areal extent of producing fields and the gas and condensate reserve potential in each field. Drilling development wells in the Springhill formation carries with it certain risks because the areal extent of development of reservoir quality Springhill is uncertain due to the potential for variations in thickness and petrophysical quality of the Springhill formation over short distances.

Despite the risks mentioned above, the result of the drilling program has been very successful, with several key wells yielding higher than expected initial production rates. Of the 19 wells drilled, three were not productive. Of the remaining 16 wells, not all are currently on production due to capacity constraints. The contract for the drilling rig used to drill the first 19 wells ended in October of 2006. A new rig has been contracted and drilling activity is expected to re-commence in the second quarter of 2007.

In addition to the 17 wells drilled during 2006, the TDF partners carried out investments required to alleviate the previously referred to capacity constraints. Production facilities investments required to get new gas to market were completed during July 2006, raising the production capacity from 14 mmcf per day to 21 mmcf per day in the Las Violetas concession. A one year gas sales contract was signed in the second quarter, allowing gross daily gas production to approximately double from second quarter levels with corresponding increases in condensate and gas liquids production. This increased volume of production commenced in August 2006. During December 2006, gross daily oil, gas, and LPG production averaged 1,213 bbls, 19.1 mmcf, and 24 metric tons, respectively, compared with 504 bbls, 11.5 mmcf, and 14.1 metric tons during February 2005 when the Company acquired its interest in the TDF Concessions, representing an increase of 141, 66, and 70 percent, respectively.

Marketing gas volumes above 21 mmcf per day will present challenges due to the remoteness of the island of Tierra del Fuego which is located long distances from major gas markets in Argentina, its connection to those markets by the San Martín gas pipeline that currently has limited excess capacity, limited local gas markets on Tierra del Fuego due to low population and industrial and economic activity on the island, and competition with larger gas fields in offshore Tierra del Fuego that have important gas reserves and production that are currently under development. Additionally, an available market for gas produced in the TDF Concession is Chile where there is a strong demand for gas in a country with limited hydrocarbon resources, but there currently exist restrictions imposed by the Argentine government that limit the export of gas produced in Argentina.

However, due to sustained economic growth and lack of natural gas supply in continental Argentina, we believe that sufficient demand exists to market more gas volumes and therefore additional capital will be spent in 2007 on gas compression and a gas pipeline that will connect the Las Violetas concession to the San Martín pipeline that transports gas to mainland Argentina. Once completed, these investments are scheduled to increase total gas deliverability in the Las Violetas concession to 35 mmcf per day. Investments are also planned for an oil pipeline, and storage and crude oil treatment facilities that will enable the partners to put into production currently shut in oil and gas-condensate wells.

Cañadón Ramirez

During 2004, the Company and its partner acquired 130 square kilometers of 3D seismic information. Interpretation of this seismic data identified several potentially drillable prospects. Late in 2005, the Company drilled the LMN a-12 well on the Los Monos structure to a depth of 4,921 feet. The well was completed in the Bajo Barreales formation and put on production in January 2006 with an initial daily production rate of 14 barrels. In January 2006, the Company drilled the LMN a-13, also on the Los Monos structure to a depth of 4,823 feet. This well was found to be not productive.

During 2006, the Company reevaluated previously acquired seismic and identified new drilling prospects to deeper horizons not previously explored in Cañadón Ramirez.

In early 2007, the Company and its partner executed a farm-out agreement with CanAmericas Energy (“CanAmericas”). The agreement allows CanAmericas to earn a 49 percent interest by exploring the deeper horizons over an area of mutual interest covering the western half of the concession. In order to earn their interest, CanAmericas will fund up to $4.5 million of an initial work program to acquire 160 square kilometers of 3D seismic and drill three wells in 2007, and a second work program to drill three wells in 2008. The seismic acquisition commenced in the first quarter of 2007.

Capricorn

As previously described, the Company has had an interest in the exploration permit over the Yacimiento Norte 1/B Block, commonly known as the Capricorn block, since 2003. Since that time, the Company and its partner have conducted various studies to evaluate the exploration potential of the block. The block was originally scheduled to expire in August 2005, but the joint venture partners were able to obtain an extension of the exploration period term through December 31, 2005. After relinquishing 51 percent of the exploration permit’s acreage and committing to drill an exploration well and conduct other exploration activities, the Company and its partners entered the second exploration period in early 2006. The second exploration period ended at the end of 2006 without fulfillment of the required investment commitment due to the inability to contract a drilling rig. The Company applied for and received both provincial and federal government approval for an extension of the permit through December 31, 2009. To obtain this extension, the joint venture partners were required to relinquish additional acreage and to drill an exploration well in 2007. As of January 2007, the Capricorn permit covers a total surface area of 485,955 square acres.

In October of 2006, the Company and its partners entered into an agreement to farm-out an interest in the Capricorn permit to Gold Point Energy Corp. (“GP Energy”). Under the terms of the agreement, GP Energy has committed to pay 50 percent of a capital program that will satisfy the investment commitment for the second exploration period. These investments consist of the acquisition of 60 square kilometers of 3D seismic estimated to cost $1 million, and the drilling of an exploration well on the Martínez del Tineo Oeste prospect, estimated to cost $2 million. GP Energy’s funding of 50 percent of this capital program will earn it a 25 percent working interest in the Martínez del Tineo Oeste prospect area located on the western edge of the Capricorn permit. Following the drilling of the Martínez del Tineo Oeste Prospect, GP Energy will also have the option to earn a 25 percent interest in the entire block by funding 50 percent of the cost of acquiring up to 300 square kilometers of 3D seismic and 50 percent of the cost of two additional exploration wells.

Acquisition of the 60 square kilometers of 3D seismic was recently completed and is currently being processed and interpreted. The Martínez del Tineo Oeste prospect exploration well is expected to be drilled in 2007. The Company will contribute 25 percent of the drilling and seismic costs, and will retain a 37.5 percent interest in the defined prospect area. The company will continue to have a 50 percent interest over the remainder of the Capricorn permit until such time as GP Energy exercises its option to invest additional funds and earn an interest over the remainder of the permit.

Sur de Rio Deseado Este Concession

In 2005, the Company entered into an agreement in which it agreed to advance $750 thousand for the drilling of a development well and the implementation of a pilot program to inject heated water into the producing formation of the primary producing field in this concession. Today, this concession produces a small volume of oil. It is believed that the limited volume of production is the result of emulsion problems in the producing reservoir and possible formation damage due to previous inappropriate well drilling techniques. By the end of 2005, the Company had advanced $375 thousand for expenditures to implement the aforementioned pilot waterflood in exchange for which the Company has the right to earn, at its option, a five percent participation interest. The Company also has an option to make additional investments that will entitle it to earn additional five percent interests up to a maximum of 25 percent. In February 2006, the Company advanced an additional $375 thousand for the drilling of the aforementioned development well. This well was completed and is now under observation. The Company has been observing production results of the waterflood pilot before deciding whether or not to exercise its right to earn a 10 percent interest, make another payment of $375 thousand for the drilling of a second well, or relinquish its right to the 10 percent interest it has earned to date.

Capital Program - 2006

The Company’s capital expenditures for 2006, net to its consolidated interests, totaled $18.2 million. After taking into consideration the portion of capital expenditures attributable to its equity interest in Petrolera, the Company’s combined consolidated and equity capital expenditures for 2006 totaled $31.1 million.

In 2006, the Company participated in the drilling of 31 wells in the Entre Lomas concession. Of these wells, 28 were completed and put into production and three were in progress at the end of the year. All three of the wells in progress at year end were subsequently completed and put on production in January 2007. Entre Lomas capital spending also included well recompletions and production facilities investments.

In Acambuco, drilling of the Macueta x-1001 (bis) well was completed in mid-2006, and the next Macueta development well, the Macueta 1003, was spud in the third quarter. In addition, the Acambuco partners completed the construction of a gas pipeline which began transporting Macueta field gas production to the Piquirenda treatment plant enabling the sale of this new source of gas production.

In Cañadón Ramirez the Company participated in the drilling of one well in 2006, the LMNa-13. This well was found to be not productive and was charged to expense in the first quarter of 2006.

In the TDF Concessions, the Company invested $4.7 million net to its interest in the participation of drilling of 17 wells. As three of those wells were found to be not productive, approximately $487,000 of that amount was charged to exploration expense. The Company also invested $1.3 million net to its interest on production facilities upgrades required to get new gas to market, raising the gross production capacity in the Las Violetas concession from 14 mmcf per day to 21 mmcf per day.

Investment Budget for 2007

During 2007, the Company expects to participate in the drilling of 40 wells in the Entre Lomas concession including one gas well and one exploration well. The 2007 Entre Lomas investment program also includes conversions of wells to injection, production facility investments, well recompletions, a continuation of the ongoing polymer injection program, and a well workover program. The Entre Lomas investment program is expected to total $30.5 million net to the Company, or $13.3 million net to the Company’s consolidated interest plus $17.2 million net to its equity interest.

In Acambuco, the Company expects to participate in investments for additional plant, flowlines, and equipment for the continued development of the Macueta field. The Macueta 1003 well that commenced drilling in 2006 will be completed and tested, and is expected to go into production later in 2007. The largest component of the 2007 investment plan consists of exploration drilling on the Cerro Tuyunti structure, a third drillable prospect in the Acambuco concession which has been identified based on interpretation of 3D seismic information. The Company’s 1.5 percent share of the Acambuco 2007 investment program is expected to be $1.5 million.

In Tierra del Fuego, the Company will participate in completing the acquisition of approximately 350 square kilometers of 3D seismic, estimated to cost $1.3 million net to the company. Expenditures for seismic acquisition will be expensed as incurred. A second drilling campaign will commence in 2007, with 12 wells planned to be drilled by year end for an estimated expenditure of $3.1 million net to the Company’s interest. In addition, approximately $11 million, or $2.8 million net to the Company, expects to be invested in oil transportation, storage and treatment facilities, gas compression, and a gas pipeline that will connect Las Violetas gas production to the San Martín pipeline that transports gas to mainland Argentina. When completed in the second half of 2007, these investments are scheduled to increase total gas deliverability in the Las Violetas concession to 35 mmcf per day and enable the partners to put into production currently shut in oil and gas-condensate wells.

As previously mentioned, in Cañadón Ramirez the Company and its partner executed a farm-out agreement which allows CanAmericas to earn a 49 percent interest by funding an initial work program consisting of the acquisition of 160 square kilometers of 3D seismic and the drilling of three wells in 2007, and a second work program to drill three wells in 2008. In accordance with the farm-out agreement, the Company does not expect to bear any of the costs related to the 2007 work program.

In Capricorn, the Company plans to spend $800,000 for its share of drilling the Martínez del Tineo Oeste prospect exploration well, and acquiring 3D seismic along the southern border of the permit.

Increasing Costs

Although the Company has benefited from increasing commodity prices since 2004, the cost of development wells, including the cost for drilling rigs, mud, cement, wireline services and tangible costs such as casing and surface equipment, has also increased sharply over the same period. Since 2004, the cost of drilling a typical well in the Entre Lomas concession has increased from $841,000 to $1.3 million in 2007. The Company has also experienced significant increases in labor and oil field services accounted for as operating expense. The continuing trend of increasing costs, coupled with a flattening of oil prices, may negatively affect future operating margins realized by the Company.

Requirement to Offer Products in Domestic Market

In the recent past, the Argentine government has expressed concerns regarding the availability and supply of gasoline, diesel fuel, and refined hydrocarbon products in Argentina’s domestic markets. As a result of these concerns and with the objective of assuring that domestic supplies fully satisfy Argentina’s demand for such products, Argentina’s Secretary of Energy issued a resolution in December 2004 requiring that before oil produced in Argentina can be exported, Argentine oil producers must first provide evidence they have offered their oil production for sale to Argentine refiners. Subsequently, the Secretary of Energy issued a similar resolution covering LPG products. The resolution covering oil exports has, to date, not impacted the Company. The Company has been selling 100 percent of its Entre Lomas oil production in local markets since 2003 and plans to continue doing so for the foreseeable future. Acambuco condensate production is sold to the sole Argentine refiner located in northwestern Argentina. As described previously, oil and condensate produced in the TDF Concessions is exported to Chile. Since the implementation of the new resolution, the TDF joint venture partners have been able to continue exporting after complying with the resolution’s requirements. The second resolution covering LPG products has also not impacted the Company to date. In both the Entre Lomas and TDF Concessions, where the Company exports a portion of its LPG production, it has been able to continue exporting LPG products after complying with the resolution’s requirements.

Export Taxes in Tierra del Fuego

In 1972, Argentine law No. 19,640 established that imports and exports to and from the province of Tierra del Fuego were tax exempted. Due to the Argentine economic and financial crisis of 2001 and 2002, law No. 25,561 (the “Emergency Law”) was issued in January 2002, creating a tax on the export of gas, oil, and their derivatives for an initial period of five years. As the Emergency Law was a general law with no specific reference to law No. 19.640, the tax exemption for Tierra del Fuego was considered unmodified.

On October 11, 2006, the Argentine Ministry of Economy and Production issued resolution 776-2006, which states that it is the Ministry’s interpretation that the export tax created by Emergency Law 25,561 of 2002 applies to hydrocarbon export sales generated from the tax-free district of Tierra del Fuego. On October 18, a second resolution, No. 56/2006, was issued by the National Customs Authority to clarify that in accordance with the Ministry’s interpretation as stated in resolution 776-2006, the export tax should be collected retroactively to when the original export tax was levied in early 2002.

The Company’s position is that operations in the TDF Concessions remain exempt from Argentine federal income taxes pursuant to Argentine law No. 19,640, and income generated in the concessions is not subject to Argentine federal taxes as long as the current exemption remains in effect. The Company began paying this tax with October sales.

Regarding the retroactivity of the export tax, the Company filed a suit for protection against resolution No. 56/2006 and requested an injunction to prevent collection of the export tax on a retroactive basis. In February 2007, the court granted the injunction pending the outcome of the suit filed by the Company. Other companies with oil and gas interests on the island of Tierra del Fuego have taken similar actions.

Effective January 15, 2007, the Argentine government issued Law 26,217 extending the oil and gas export tax beyond the initial five year period and expressly clarifying that the export tax is applicable to hydrocarbon exports from the island of Tierra del Fuego. The Company is currently exporting all of its oil and condensate production from its interest in the TDF Concessions.

This process is in the early stages and it is anticipated by the Company that this matter will remain open for some time. As a result, it is premature to reach a conclusion as to the potential for probability of an adverse outcome or the amount of any loss to the Company that might result from this proceeding.

Growth Opportunities

Since 2002, the Company has deployed cash resources to increase its presence in Argentina by purchasing additional interests in the Entre Lomas and Cañadón Ramirez joint ventures, farming into the Capricorn permit and acquiring its interest in the TDF Concessions. The Company’s management, as part of a continuing strategy for growth, continues to seek additional ways to deploy its financial resources for investing in exploration and reserve acquisition opportunities both in and outside of Argentina. As described on pages 21 and 22, in 2006, the Company entered into farm-out agreements that will result in exploration investments in both the Cañadón Ramirez concession and the Capricorn permit.

RESULTS OF OPERATIONS

Refer to Consolidated Statements of Income on page 35.

2006 vs. 2005

The following represents a comparison of results of operations between the years 2006 and 2005.

During 2006, the Company generated net income of $40.1 million. This represents an improvement of $10.3 million compared with net income of $29.8 million during 2005. The increase in net income is due primarily to higher operating revenues and equity income from Argentine investments.

Operating revenues improved by $16.2 million. This increase is due primarily to higher oil, gas, and plant product prices combined with volume increases for all three products. Oil, natural gas, and plant product prices for the Company’s consolidated interests accounted for as operating revenues averaged $43.88 per bbl, $1.30 per mcf, and $413.36 per ton, respectively, during 2006, compared with $37.56 per bbl, $1.11 per mcf, and $381.33 per ton, respectively, during 2005. Oil, natural gas, and LPG sales volumes for the Company’s consolidated interests accounted for as operating revenues totaled 1,104 mbbls, 4.3 bcf, and 9.6 thousand tons, respectively, during 2006, compared with 946 mbbls, 2.9 bcf, and 7.9 thousand tons, respectively, during 2005. Due to proportionately consolidating the Company’s 25.72 percent interest in the TDF Concessions beginning January 1, 2006, operating revenues include revenues associated with 76 mbbls, 1.2 bcf, and 1.6 thousand tons of sales volumes. Comparable TDF Concessions’ sales volumes are not included in 2005 operating revenues.

The price and volume comparisons in the previous paragraph differ from the comparisons described in the prior sections on pages 18, 19 and 20 titled “Oil Prices,” “Natural Gas Prices,” and “Product Volumes.” The comparisons in the previous paragraph relate to product prices and sales volumes included in the Company’s operating revenues. The comparisons in the prior sections compare prices and volumes for the Company’s combined consolidated and equity interests.

Equity income from Argentine investments increased by $4.1 million compared with 2005. The increase is due primarily to greater Petrolera operating revenues that resulted from favorable price and volume variations similar to those experienced by the Company. Petrolera’s sole business is its interest and operatorship of the Entre Lomas concession, and as a result, its operating revenues and expenses are derived from essentially the same operations as the Company. Equity income from Argentine investments in 2005 includes income of $571 thousand generated by the Company’s equity participation in RCLV S.A that was acquired in February 2005. The Company’s participation in RCLV S.A. was converted to a direct concession interest and has been accounted for as a consolidated direct interest since January 1, 2006.

Interest and other income increased by $924 thousand primarily due to larger cash balances invested plus increased interest yields on the Company’s cash equivalents and short-term investments held during 2006.

The above favorable variances in operating revenues, equity income and interest and other income were partially offset by increases in operating expense, provincial production taxes, depreciation, depletion, and amortization, selling and general administrative expenses, and Argentine income taxes.

Operating expense increased by $1.5 million compared with 2005. The increase is due to a combination of factors, the most significant of which are increased labor costs resulting from wage increases negotiated with labor unions, an increase in workover activity, increased rates charged by field service companies for workovers and well maintenance, and greater costs associated with rod pump operation and maintenance. In 2006, the Company’s share of TDF Concessions’ operating expense was reflected as such in its statement of income. In 2005, the Company’s share of the TDF Concessions’ operating expense was a component of equity income.

Depreciation, depletion and amortization rose by $2.8 million compared with 2005. The increase is primarily due to larger production volumes in both the Entre Lomas and Acambuco concessions combined with greater capital additions. In 2006, due to the previously described change in accounting for the TDF Concessions, the Company began directly recording depreciation associated with its interest in the TDF Concessions. As a result, the TDF Concessions’ depreciation expense accounted for the remainder of the increase.

Provincial production taxes and Argentine income taxes rose by $1.6 million and $1.8 million, respectively. The increase in provincial production taxes is directly associated with the previously described improvement in operating revenues. The increase in Argentine income taxes is directly associated with the previously described improvement in net income.

Selling and administrative expense increased by $841 thousand compared with 2005. The increase is primarily due to higher personnel costs, greater travel expenses, and increases in personnel charges for services rendered to the Company by employees of The Williams Companies, Inc.

Argentine taxes other than income rose by $724 thousand compared to 2005. The increase was due to higher production taxes caused by increased volumes in Entre Lomas and the payment of export taxes commencing in October 2006 levied on export sales from the TDF Concessions.

2005 vs. 2004

The following represents a comparison of results of operations between the years 2005 and 2004.

During 2005, the Company generated net income of $29.8 million. This represents an improvement of $14.3 million compared with net income of $15.5 million during 2004. The increase in net income is due primarily to higher operating revenues and equity income from Argentine investments.

Operating revenues improved by $12.1 million. This increase is due primarily to higher oil, gas and plant product prices combined with volume increases for all three products. The increase would have been $10 million, or 32 percent, except that operating revenues in 2004 included a charge of $1.1 million associated with the Company’s 2004 hedging activities and a charge of $954 thousand to write off the receivable that had accumulated during 2003 and 2004 associated with the 2003 price stabilization agreement between Argentine oil producers and refiners. Oil, natural gas, and plant product prices for the Company’s consolidated interests accounted for as operating revenues averaged $37.56 per bbl, $1.11 per mcf, and $381.33 per ton, respectively, during 2005, compared with $31.21 per bbl, $.74 per mcf, and $335.33 per ton, respectively, during 2004. Oil, natural gas, and LPG sales volumes for the Company’s consolidated interests accounted for as operating revenues totaled 946 mbbls, 2.9 bcf, and 7.9 thousand tons, respectively, during 2005, compared with 876 mbbls, 2.6 bcf, and 7.1 thousand tons, respectively, during 2004.

The price and volume comparisons in the previous paragraph differ from the comparisons described in the prior sections on pages 18, 19, and 20 titled “Oil Prices,” “Natural Gas Prices,” and “Product Volumes.” The comparisons in the previous paragraph relate to product prices and sales volumes included in the Company’s operating revenues. The comparisons in the prior sections compare prices and volumes for the Company’s combined consolidated and equity interests.

Equity income from Argentine investments increased by $6.6 million compared with 2004. The increase is due primarily to greater Petrolera operating revenues that resulted from favorable price and volume variations similar to those experienced by the Company. Equity income from Argentine investments for 2004 included a charge of $1 million that reflected a write off by Petrolera of the receivable it had accumulated pursuant to the aforementioned price stabilization agreement of 2003. Petrolera’s sole business is its interest and operatorship of the Entre Lomas concession, and as a result, its operating revenues and expenses are derived from essentially the same operations as the Company. Equity income from Argentine investments in 2005 includes income of $571 thousand generated by the Company’s equity participation in RCLV S.A that was acquired in February 2005. This income includes an equity charge of $1 million pertaining to the Company’s equity share of 3D seismic information that was acquired in the TDF Concessions during the first half of 2005.

Exploration expense fell by $1.3 million compared with 2004. In 2004, the Company charged as expense the costs of drilling the unsuccessful El Tigre x-1 well in the Puesto Galdame block and fees associated with 3D seismic data acquired in the Cañadón Ramirez concession.

Interest and other income increased by $814 thousand primarily due to increased interest yields on the Company’s cash equivalents and short-term investments held during 2005.

The above favorable variances in operating revenues, equity income and exploration expense were partially offset by increases in operating expense, provincial production taxes, and Argentine income taxes.

Operating expense increased by $772 thousand compared with 2004. The increase is due to a combination of factors, the most significant of which are increased labor costs resulting from wage increases negotiated with labor unions, increased rates charged by field service companies for workovers and well maintenance, a rise in the cost of high voltage electricity generated for field operations, and greater costs associated with rod pump operation and maintenance. The increase in other expenses relates to fees incurred in connection with the acquisition of the Company’s TDF Concessions interests.

Provincial production taxes and Argentine income taxes rose by $1.2 million and $3.1 million, respectively. The increase in provincial production taxes is directly associated with the previously described improvement in operating revenues. The increase in Argentine income taxes is directly associated with the previously described improvement in net income.

Critical Accounting Policies and Estimates

Management’s discussion and analysis of its financial condition and results of operation are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of these consolidated financial statements 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. The Company’s independent reserve engineer bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions. Note 1 to the Company’s consolidated financial statements, contained elsewhere in this report on Form 10-K, contains a comprehensive summary of the Company’s significant accounting policies. The following is a discussion of the Company’s most critical accounting policies, and judgments and uncertainties that are inherent in the Company’s application of GAAP:

Proved reserve estimates. Estimates of the Company’s proved reserves included in the unaudited supplemental oil and gas information in this report on Form 10-K are prepared in accordance with guidelines established by GAAP and by the United States Securities and Exchange Commission (“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 third party reserve engineer that prepares the estimate.

The Company’s proved reserve information is based on estimates prepared by its independent reserve engineer. Estimates prepared by others may be higher or lower than the Company’s estimates. 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.

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, the Company based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

The Company’s estimates of proved reserves materially impact depreciation, depletion and amortization expense. If the estimates of proved reserves decline, the rate at which the Company records depreciation, and amortization 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 the Company’s assessment of its oil and gas producing properties for impairment.

Revenue recognition. Revenue is a key component of the Company’s results of operations and also determines the timing of certain expenses, such as severance taxes and royalties. The Company’s policy is to recognize revenues when oil and gas are delivered to the purchaser.

Impairment of oil and gas properties. The Company reviews its proved properties for impairment on a concession by concession basis and recognizes an impairment whenever events or circumstances, such as declining oil and gas prices, indicate that a property’s carrying value may not be recoverable. If an impairment is indicated, then a provision is recognized to the extent that the carrying value exceeds the present value of the estimated future net revenues (“fair value”). In estimating future net revenues, the Company assumes costs will escalate annually and applies an oil and gas price forecast that it believes to be reasonable after reviewing long-term forecasts of professional energy consultants. Due to the volatility of oil and gas prices, it is possible that the Company’s assumptions regarding oil and gas prices may change in the future. The most important consideration for the Company in testing for impairment is oil and gas prices. As of December 31, 2006, the estimated future net revenues for each of the Company’s proved properties exceeds each of their respective carrying values.

Asset Retirement Obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company’s asset retirement obligation is based on an estimate of the number of wells expected to be abandoned through the last year of the Entre Lomas concession term, and an estimated cost to plug and abandon a well as discussed with field service companies that would be expected to perform such services. Both estimates are provided by operations 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 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. Furthermore, given the current economic situation in Argentina and uncertainties associated with future levels of inflation in the country and devaluation of the peso, any future estimate of the cost to plug and abandon a well is subject to a wide range of outcomes as the estimate is updated as time passes. Finally, adjustments in the total asset retirement obligation included in the Company’s Balance Sheets will take into consideration future estimates of inflation and present value factors based on the Company’s credit standing. Given the recent 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.

Argentina economic and currency measures. The Argentine economic and political situation continues to evolve and the Argentine government may enact future regulations or policies that, when finalized and adopted, may materially impact, among other items, (i) the realized prices the Company receives for the commodities it produces and sells as a result of new taxes; (ii) the timing of repatriations of cash to the Cayman Islands; (iii) the Company’s asset valuations; and (iv) peso-denominated monetary assets and liabilities.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

The Company produces and sells crude oil and natural gas, and the Company’s financial results can be significantly impacted by fluctuations in commodity prices due to changing market forces. Based on current levels of oil production, a variation of plus or minus $1 per barrel in oil prices, without considering the effects of hedging, would on an annual basis cause fluctuations in the Company’s operating revenue, equity income, and net income to vary depending on the level of WTI. This is due to the reduction factors that were incorporated in oil sales pricing formulas in 2004 that reduce considerably the sale price net back to the Company such that net back reductions escalate to higher and higher levels as WTI increases. For example, a fluctuation in the price of WTI from $36 to $37 would on an annual basis cause a fluctuation in the Company’s operating revenue, equity income and net income of approximately $987 thousand, $621 thousand, and $1.2 million, respectively. However, a fluctuation in the price of WTI from $60 to $61 would on an annual basis cause a fluctuation in the Company’s operating revenue, equity income and net income of approximately $599 thousand, $347 thousand and $714 thousand, respectively.

The Company has historically not used derivatives to hedge price volatility, except for one occasion in 2004.

Foreign Currency and Operations Risk

The Company’s operations are located in Argentina. Therefore, the Company’s financial results may be affected by factors such as changes in foreign currency exchange risks, weak economic conditions, or changes in Argentina’s political climate. During 2002 and 2003, the Company recorded sizeable foreign currency exchange losses due to the significant devaluation of the Argentine peso that occurred as a consequence of Argentina’s economic problems during 2001 and 2002 described in the following paragraphs.

Argentine Economic and Political Environment

During the decade of the 1990’s, Argentina’s government pursued free market policies, including the privatization of state owned companies, deregulation of the oil and gas industry, tax reforms to equalize tax rates for domestic and foreign investors, liberalization of import and export laws and the lifting of exchange controls. The cornerstone of these reforms was the 1991 convertibility law that established an exchange rate of one Argentine peso to one US dollar. These policies were successful as evidenced by the elimination of inflation and substantial economic growth during the early to mid 1990’s. However, throughout the decade, the Argentine government failed to balance its fiscal budget, incurring repeated significant fiscal deficits that by the end of 2001 resulted in the accumulation of $140 billion of debt.

Late in 2001, the country was unable to obtain additional funding from the International Monetary Fund. Economic instability increased resulting in substantial withdrawals of cash from the Argentine banking system that occurred over a short period of time.

In January 2002, the government defaulted on a significant portion of Argentina’s $140 billion of debt and the national Congress passed Emergency Law 25,561, which among other things, overturned the convertibility plan. The government eventually adopted a floating rate of exchange in February 2002. Two specific provisions of the Emergency Law directly impact the Company. First, a tax on the value of hydrocarbon exports was established effective April 1, 2002. The second provision was the requirement that domestic commercial transactions, or contracts for sales in Argentina that were previously denominated in US dollars were converted to pesos (“pesofication”) by liquidating those sales in Argentina at an exchange rate to be negotiated between sellers and buyers. Furthermore, the government placed a price freeze on natural gas prices at the wellhead. With the price of natural gas pesofied and frozen, the US dollar equivalent price for natural gas in Argentina fell in direct proportion to the level of devaluation described in the next paragraph.

The abandonment of the convertibility plan and the decision to allow the peso to float in international exchange markets resulted in a strong devaluation of the peso. By September 30, 2002, the peso to U.S. dollar exchange rate had increased from 1:1 to 3.74:1. However, since the end of the third quarter 2002 Argentina’s economy has shown signs of stabilization. Argentina’s economic condition has improved considerably over the last four years. As a commodity exporter, the country has benefited from increases in the price of its agricultural and natural resource exports such as crude oil, generating surpluses in both Argentina’s international trade balance and the government’s fiscal balance. The government, when possible, has taken advantage of this environment by increasing certain taxes, such as the oil export tax that has been in effect since 2002 in order to increase its total tax revenues and improve its fiscal balance.

Over the last four years Argentina has been recovering from its economic crisis and its economy has grown at an annual rate of nine percent. Argentine economists are expecting economic growth of six percent for 2007. Of course, the growth experienced by Argentina during the last four years comes on the heels of the severe economic contraction that occurred from 1999 through 2002. Nevertheless, the resurgence of economic growth is a positive indicator for the future. At December 31, 2006 the peso to US dollar exchange rate was 3.06:1.

During 2005, the Argentine government presented an exchange offer to holders of $ 82 billion of the country’s defaulted debt. The offer was largely accepted by bond holders and as a consequence, the country’s debt was reduced.

Argentina’s mid term elections were held in October 2005. The result of this election has strengthened the position of the current President Nestor Kirchner whose Justicialista party gained seats in both houses of Congress. The next Presidential elections are scheduled for 2007.

In January 2006, Argentina paid off its $10 billion debt with the International Monetary Fund.

Although Argentina’s economy has improved considerably since the economic crisis of 2002, reducing inflation and unemployment, the country still finds itself in a delicate economic situation with remaining high levels of external indebtedness.

MANAGEMENT’S REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company 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) and for the assessment of the effectiveness of internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and board of directors regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles.

All internal controls systems, no matter how well designed have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. 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.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management’s assessment included an evaluation of the design of the Company’s internal control over financial reporting and testing of the operational effectiveness of the Company’s internal control over financial reporting. Based on its assessment, management believes that, as of December 31, 2006, the Company’s internal control over financial reporting is effective based on those criteria.

Ernst & Young, LLP, the Company’s independent registered public accounting firm, has issued an audit report on management’s assessment of the Company’s internal control over financial reporting. A copy of this report is included in this Annual Report on Form 10-K.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of Apco Argentina Inc.

We have audited management’s assessment, included in the accompanying “Management’s Report on Internal Control Over Financial Reporting,” that Apco Argentina Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Apco Argentina 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Apco Argentina Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Apco Argentina Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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 Argentina Inc. as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006 of Apco Argentina Inc. and our report dated March 12, 2007 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma

March 12, 2007

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	33
Consolidated Balance Sheets December 31, 2006 and 2005	34
Consolidated Statements of Income for the Three Years Ended December 31, 2006	35
Consolidated Statements of Stockholders’ Equity for the Three Years Ended December 31, 2006	36
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2006.	37
Notes to Consolidated Financial Statements	38

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of Apco Argentina Inc.

We have audited the accompanying consolidated balance sheets of Apco Argentina Inc. as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. 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.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apco Argentina Inc. at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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), the effectiveness of Apco Argentina Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 12 , 2007, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma

March 12, 2007

APCO ARGENTINA INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2006			2005
	(Amounts in Thousands Except Share Amounts)
ASSETS
Current Assets:
Cash and cash equivalents	$	49,662		$	28,670
Short-term investments		-			6,125
Accounts receivable		7,464			5,737
Inventory		1,309			447
Other current assets		1,679			1,556
Total Current Assets		60,114			42,535
Property and Equipment:
Cost, successful efforts method of accounting		101,598			79,537
Accumulated depreciation, depletion and amortization		(55,901	)		(46,837	)
		45,697			32,700
Argentine investments, equity method		57,382			56,935
Deferred Argentine income tax asset		29			350
Other assets		1,022			193
	$	164,244		$	132,713
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	3,973		$	2,807
Affiliate payable		308			817
Accrued liabilities		2,065			1,366
Argentine income taxes payable		3,415			3,593
Dividends payable		2,576			1,840
Total Current Liabilities		12,337			10,423
Long-term liabilities		1,753			1,850
Minority interest in subsidiaries		151			135
Stockholders’ Equity:
Ordinary shares, par value $.01 per share; 15,000,000 shares authorized; 7,360,311 shares outstanding in 2006 and 2005		74			74
Additional paid-in capital		9,326			9,326
Accumulated other comprehensive loss		(1,345	)		(549	)
Retained earnings		141,948			111,454
Total Stockholders’ Equity		150,003			120,305
	$	164,244		$	132,713

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

APCO ARGENTINA INC.

CONSOLIDATED STATEMENTS OF INCOME

	For the Years Ended December 31,
	2006		2005		2004

	(Amounts in Thousands Except Per Share Amounts)
REVENUES:
Operating revenues	$	57,952	$	41,739	$	29,628
COST AND EXPENSES:
Operating expense		8,302		6,769		5,997
Provincial production tax		6,430		4,833		3,595
Transportation and storage		936		507		449
Selling and administrative		3,816		2,975		2,699
Depreciation, depletion and amortization		8,445		5,608		5,440
Exploration expense		1,163		486		1,843
Argentine taxes other than income		2,318		1,594		1,396
Foreign exchange (gains) losses		67		13		(96	)
Other (income) expense, net		1,087		634		(57	)
		32,564		23,419		21,266
TOTAL OPERATING INCOME		25,388		18,320		8,362
INVESTMENT INCOME
Interest and other income		2,015		1,091		277
Equity income from Argentine investments		22,391		18,304		11,657
		24,406		19,395		11,934
Minority Interest Expense		46		8		--
Income before Argentine income taxes		49,748		37,707		20,296
Argentine income taxes		9,686		7,861		4,790

NET INCOME	$	40,062	$	29,846	$	15,506
Earnings per ordinary share - basic and diluted:
NET INCOME PER SHARE	$	5.44	$	4.06	$	2.11
Average ordinary shares outstanding - basic and diluted		7,360		7,360		7,360

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

APCO ARGENTINA INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Ordinary Shares		Additional Paid-in Capital		Accumulated Other Comprehensive Loss			Retained Earnings			Total

	(Amounts in Thousands Except Per Share Amounts)

BALANCE, January 1, 2004	$	74	$	9,326	$	(87	)	$	76,958		$	86,271
Comprehensive Income:
Net income		—		—		—			15,506			15,506
Minimum pension liability of equity and consolidated interests (net of Argentine taxes of $45)		—		—		(83	)		—			(83	)
Total Comprehensive Income												15,423
Dividends declared ($0.65 per share)		—		—		—			(4,784	)		(4,784	)
BALANCE, December 31, 2004		74		9,326		(170	)		87,680			96,910
Comprehensive Income:
Net income		—		—		—			29,846			29,846
Minimum pension liability of equity and consolidated interests (net of Argentine taxes of $100)		—		—		(379	)		—			(379	)
Total Comprehensive Income												29,467
Dividends declared ($0.83 per share)		—		—		—			(6,072	)		(6,072	)
BALANCE, December 31, 2005		74		9,326		(549	)		111,454			120,305
Comprehensive Income:
Net income		—		—		—			40,062			40,062
Minimum pension liability of equity and consolidated interests (net of Argentine taxes of $239)		—		—		(443	)		—			(443	)
Total Comprehensive Income												39,619
Cumulative adjustment in equity investee’s other comprehensive income		—		—		(270	)		—			(270	)
Equity and consolidated interests in adjustment to initially apply SFAS No. 158 (net of Argentine taxes of $44)		—		—		(83	)		—			(83	)
Dividends declared ($1.30 per share)		—		—		—			(9,568	)		(9,568	)
BALANCE, December 31, 2006	$	74	$	9,326	$	(1,345	)	$	141,948		$	150,003

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

APCO ARGENTINA INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2006			2005			2004
	(Amounts in Thousands)
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	40,062		$	29,846		$	15,506
Adjustments to reconcile net income to cash provided by operating activities:
Equity income from Argentine investments		(22,390	)		(18,304	)		(11,657	)
Dividends from Argentine investments		15,500			12,628			8,568
Deferred income tax benefit		319			(230	)		(232	)
Depreciation, depletion and amortization		8,445			5,608			5,440
Gain on sale of minority interest		—			(280	)		—
Write off of price credit receivable		—			—			954
Changes in accounts receivable		(342	)		(1,407	)		(1,697	)
Changes in inventory		(403	)		(124	)		(180	)
Changes in other current assets		(103	)		(1,011	)		(470	)
Changes in accounts payable		768			992			705
Changes in affiliate payable		(511	)		372			(12	)
Change in cash overdrafts		—			(275	)		275
Changes in Argentine income taxes payable		(178	)		1,799			746
Changes in accrued liabilities		474			(73	)		413
Changes in dividends payable		—			644			—
Minority interest in consolidated subsidiaries		43			8			—
Changes in other assets, other liabilities and other		(451	)		913			491
Net cash provided by operating activities		41,233			31,106			18,850
CASH FLOW FROM INVESTING ACTIVITIES:
Property plant and equipment:
Capital expenditures		(17,513	)		(10,407	)		(5,246	)
Purchase of equity investments		—			(6,630	)		—
Proceeds from sale of minority interest		—			407			—
Short term investments:
Purchase of short-term investments		(14,000	)		(15,356	)		(7,430	)
Proceeds from short term investments		20,127			10,538			6,123
NET CHANGE FROM INVESTING ACTIVITIES		(11,386	)		(21,448	)		(6,553	)
CASH FLOW USED IN FINANCING ACTIVITIES:
Dividends paid to minority interest		(23	)		—			—
Dividends paid		(8,832	)		(6,072	)		(4,784	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		20,992			3,586			7,513
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		28,670			25,084			17,571
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	49,662		$	28,670		$	25,084
Supplemental disclosures of cash flow information:
Cash paid during the year for Argentine income taxes	$	7,136		$	5,315		$	4,474

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

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)

Basis of Presentation and Summary of Accounting Policies

General Information and Principles of Consolidation

The consolidated financial statements include the accounts of Apco Argentina Inc. (a Cayman Islands corporation) and its subsidiaries, Apco Properties Ltd. (a Cayman Islands Corporation), Apco Austral S.A. (an Argentine corporation), and Apco Argentina S.A. (an Argentine corporation), all of which are herein collectively referred to as “the Company.” The Company is engaged exclusively in joint ventures in oil and gas exploration, development and production in Argentina. Its principal businesses are a 23 percent participation in the Entre Lomas concession (Entre Lomas, an unincorporated joint venture), which is accounted for using the proportional consolidation method, and a 40.724 percent 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 owns a 73.15 percent interest in the Entre Lomas concession. In February 2005, the company purchased participation interests in the CA-12 “Rio Cullen,” CA-13 “Las Violetas,” and CA-14 “Angostura” hydrocarbon exploitation concessions that, as a group are referred to herein as the “TDF Concessions.” The result of the purchase is that the Company acquired 25.72 percent effective participation interest in the TDF Concessions. Effective January 1, 2006, the Company began accounting for its interests in the TDF Concessions by proportional consolidation into Apco Austral S.A., a subsidiary, which is now consolidated into the Company’s financial statements. The Company also owns a 1.5 percent interest in the Acambuco concession, an 81.82 percent interest in the Cañadón Ramirez concession and a 50 percent interest in the Capricorn Exploration Permit. All of the Company’s operating revenues and equity income, and all of its long-lived assets are in Argentina. A wholly owned subsidiary of The Williams Companies, Inc. (“Williams”) currently owns 68.96 percent of the outstanding ordinary shares of the Company. Oil and gas operations are high risk in nature. A successful operation requires that a company deal with uncertainties about the subsurface that even a combination of experience, scientific information and careful evaluation cannot always overcome. Because the Company’s assets are located in Argentina, management has historically been required to deal with the impact of inflation, currency devaluation and currency controls. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain prior year amounts have been reclassified to conform to current year presentation.

Segments

The Company reports segment information in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 131, "Disclosures about Segments of an Enterprise and Related Information," which establishes annual and interim reporting standards for an enterprise's business segments and related disclosures about its products, services, geographical areas and major customers. All of the Company’s operations and long-lived assets are located in Argentina and its only business in Argentina is oil and gas exploration and production. As a result, management views all of the Company’s business and operations to be one segment.

Revenue Recognition

The Company recognizes revenues from sales of oil, gas, and plant products at the time the product is delivered to the purchaser and title has been transferred. Any product produced that has not been delivered is reported as inventory and is valued at the lower of cost or market. When cost is calculated, it includes total per unit operating cost and depreciation. Transportation and storage costs are recorded as expenses when incurred. The Company has had no contract imbalances relating to either oi1 or gas production.

Property and Equipment

The Company uses the successful-efforts method of accounting for oil and gas exploration and production operations, whereby costs of acquiring non-producing acreage and costs of drilling successful exploration wells and development costs are capitalized. Costs of unsuccessful exploratory drilling are expensed as incurred. Oil and gas properties are depreciated over their productive lives using the units of production method based on proved producing reserves. Non oil and gas property is recorded at cost and is depreciated on a straight-line basis, using estimated useful lives of 3 to 15 years. The Company reviews its proved properties for impairment on a property by property basis and recognizes an impairment whenever events or circumstances, such as declining oil and gas prices, indicate that a property’s carrying value may not be recoverable. If an impairment is indicated, then a provision is recognized to the extent that the carrying value exceeds the present value of the estimated future net revenues (“fair value”). In estimating future net revenues, the Company assumes costs will escalate annually and applies an oil and gas price forecast that it believes to be reasonable after reviewing long-term forecasts of professional energy consultants. Due to the volatility of oil and gas prices, it is possible that the Company’s assumptions regarding oil and gas prices may change in the future. For the years ended December 31, 2006 and 2005, the Company did not record any impairment charges as the estimated future net revenues exceeded the carrying value of its properties.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Asset Retirement Obligation

The Company accounts for asset retirements and well abandonment in accordance with SFAS No. 143 “Accounting for Asset Retirement Obligations.” Pursuant to this standard, the Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company’s asset retirement obligation is based on an engineering analysis that projects, through the last year of the Company’s concession term, the number of wells that would require plugging and abandoning and the estimated cost to abandon a well as discussed with field service companies that would be expected to perform such services. Both estimates are provided by operations 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 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. Furthermore, given past uncertainties associated with future levels of inflation in Argentina and devaluation of the peso, any future estimate of the cost to plug and abandon a well is subject to a wide range of outcomes as the estimate is updated as time passes. Finally, adjustments in the total asset retirement obligation included in the Company’s Consolidated Balance Sheets will take into consideration future estimates of inflation and present value factors based on the Company’s credit standing. Given past economic turmoil in Argentina, future inflation rates and interest rates, upon which present value factors are based, as recent history demonstrates, may be subject to large variations over short periods of time. 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.

Net Income per Ordinary Share

Net income per ordinary share is based on the weighted average number of ordinary shares outstanding. Basic and diluted net income per ordinary share are the same, as the Company has not issued any potentially dilutive securities such as stock options.

Foreign Exchange

The general policy followed in the translation of the Company’s financial statements of foreign operations into United States dollars is in accordance with SFAS No. 52, “Foreign Currency Translation,” using the United States dollar as the functional currency. Accordingly, translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar, are included in results of operations as incurred.

Income Taxes

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

Fair Value

The carrying amount reported in the balance sheet for cash equivalents, accounts receivable and accounts payable is equivalent to fair value.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Recent Accounting Standards

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation clarifies the accounting for uncertainty in income taxes under FASB Statement No. 109, “Accounting for Income Taxes.” The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit, determined on a cumulative probability basis, that is greater than 50 percent likely of being realized upon ultimate settlement.

FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying the Interpretation must be reported as an adjustment to the opening balance of retained earnings in the year of adoption. We adopted FIN 48 beginning January 1, 2007, as required.

In June 2006, the FASB ratified EITF No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF 06-3). EITF 06-3 addresses the income statement presentation of any tax collected from customers and remitted to a government authority and concludes the presentation of taxes on either a gross basis or a net basis is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22 “Disclosure of Accounting Policies.” This is effective for interim and annual reporting periods beginning after December 15, 2006 and will require the financial statement disclosure of any significant taxes recognized on a gross basis. We are reviewing the presentation in our Consolidated Financial Statements and will apply the disclosure provisions of EITF 06-3 with our first quarter 2007 filing.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and is generally applied prospectively. We will assess the impact of SFAS No. 157 on our Consolidated Financial Statements.

In September 2006, the FASB issued FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1). This FSP addresses the planned major maintenance of assets and prohibits the use of the “accrue-in-advance” method of accounting for these activities in annual and interim reporting periods. The FSP continues to allow the direct expense, built-in overhaul and deferral methods. FSP AUG AIR-1 requires disclosure of the method of accounting for planned major maintenance activities as well as information related to the change from the “accrue-in-advance” method to another method. This FSP is effective for the first fiscal year beginning after December 15, 2006 and should be applied retrospectively. We adopted this FSP in January 2007 and do not anticipate the adoption of FSP AUG AIR-1 to have a material impact on our Consolidated Financial Statements.

(2)

Entre Lomas Joint Venture

As discussed in Note 1, the Company owns a 23 percent direct interest in Entre Lomas. It also owns a 29.79 percent indirect interest by virtue of its 40.724 percent stock ownership in Petrolera, the operator of the joint venture, which owns 73.15 percent of the joint venture. Consequently, the Company’s combined direct and indirect interests in the Entre Lomas joint venture total 52.79 percent. The joint venture is engaged in the exploration, development and production of oil and gas in the Entre Lomas concession located in the provinces of Río Negro and Neuquén in southern Argentina.

(3)

Investment in Argentine Oil and Gas Companies

As described in Note 1, the Company uses the equity method to account for its investment in Petrolera, a non-public Argentine corporation.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Under the equity method of accounting, the Company's share of net income (loss) from Petrolera is reflected as an increase (decrease) in its investment accounts and is also recorded as equity income (loss) from Argentine investments. Dividends from Petrolera are recorded as reductions of the Company’s investment.

Summarized financial position and results of operations of Petrolera are as follows:

Financial position at December 31, 2006 and 2005 is as follows. Amounts are stated in thousands:

	2006		2005

Current assets	$	49,406	$	41,160
Non current assets	$	118,937	$	106,562
Current liabilities	$	25,195	$	21,751
Non current liabilities	$	5,718	$	4,684

Results of operations for the years ended December 31, 2006, 2005 and 2004 are as follows. Amounts are stated in thousands:

	2006		2005		2004

Revenues	$	155,401	$	127,164	$	93,914
Expenses	$	68,002	$	57,164	$	46,735
Net income	$	54,871	$	43,460	$	28,570

(4)

Cash Equivalents

Cash equivalents include highly liquid bank deposits of $42.7 million and $23.1 million as of December 31, 2006 and 2005, respectively, with interest rates ranging from 3.88 - 5.94 percent in 2006 and 1.47 - 4.18 percent in 2005. The Company considers all investments with a maturity of three months or less to be cash equivalents.

(5)

Short-Term Investments

Short-term investments include only bank time deposits with a maturity greater than three months. At December 31, 2006 and 2005, the balance of such deposits was zero and $6.1 million, respectively.

(6)

Major Customers

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

	For the Years Ended December 31,
	2006			2005			2004
Petrobras Energía S.A..		88.3	%		88.4	%		90.1	%

Management believes that the credit risk imposed by this concentration is offset by the creditworthiness of the Company’s customer and upon expiration, the oil sales contract with this customer will be extended or replaced.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(7)

Related Party Transactions

The Company incurred charges of $699,000, $597,000, and $843,000 in 2006, 2005, and 2004, respectively, from Williams and affiliates for management services, overhead allocation, general and administrative expenses and purchases of materials and supplies. These charges were incurred by the Company pursuant to an administrative services agreement between the Company and Williams. Accounts payable to Williams and affiliates outstanding at December 31, 2006 and December 31, 2005, were approximately $308,000 and $817,000 respectively. The Company is dependent on Williams as it relates to certain employees performing services for the Company, and certain other costs such as rent, reproduction, office supplies, computer support, etc. Williams directly charges the Company monthly for the time associated costs of employees based on an allocation of time dedicated to the affairs of the Company, and directly charges the Company for such items as insurance, and internal audit services. The Company also incurs an executive support charge, included in the amounts above, primarily for the time spent by certain employees of Williams that serve as executive officers or directors of the Company.

(8)

Income and Other Argentine Taxes

The Company incorporated in the Cayman Islands in 1979. Since then, the Company’s income, to the extent that it is derived from sources outside the U.S., generally is not subject to U.S. income taxes. Also, the Company has been granted an undertaking from the Cayman Islands government, expiring in 2019, to the effect that the Company will be exempt from tax liabilities resulting from tax laws enacted by the Cayman Islands government subsequent to 1979. The Cayman Islands currently has no applicable income tax or corporation tax and, consequently, the Company believes its earnings are not subject to U.S. income taxes or Cayman Islands income or corporation taxes. All of the Company’s income during 2006, 2005, and 2004 was generated outside the United States.

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

	For the years ended December 31,
	2006		2005			2004

Income taxes
Current	$	9,367	$	8,091		$	5,022
Deferred		319		(230	)		(232	)
Income tax expense		9,686		7,861			4,790
Other taxes		2,318		1,594			1,396
	$	12,004	$	9,455		$	6,186

Argentine income taxes payable at December 31, 2006 and 2005 were $3.4 million and $3.6 million, respectively. The deferred Argentine income tax provision relates primarily to certain costs capitalized for U.S. reporting purposes that are expensed for Argentine local reporting and tax purposes. The deferred tax asset at December 31 for each of the years presented consists of the following. Amounts are stated in thousands:

	2006		2005

Deferred tax assets:
Defined contribution retirement plan accrual		113		96
Retirement plan obligations		402		278
Total deferred tax assets	$	515	$	374
Deferred tax liabilities:
Property basis difference and asset retirement obligation	$	486	$	24
Total deferred tax liabilities		486		24

Overall net deferred tax asset	$	29	$	350

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The effective income tax rate reflected in the Consolidated Statements of Income differs from Argentina’s statutory rate of 35 percent because the Company incurs income taxes only in Argentina, the country where all of its income generating activities are located. As a result, differences between the Company’s consolidated effective rate and the statutory rate of 35 percent are caused primarily by income and expense generated and incurred outside of Argentina and after tax equity results that do not affect the amount of income taxes paid by the Company. Such items include interest income resulting from the Company’s cash equivalents and short term deposits deposited in its Cayman Island and Bahamas banks, general and administrative expenses incurred by the Company in its headquarters office in Tulsa, Oklahoma, equity income from Argentine investments that is recorded by the Company on an after tax basis, and foreign exchange losses resulting from the devaluation of the peso which are not deductible in Argentina.

Tax Disputes - Obligatory Savings Deposit

In August 1993, the Dirección General Impositiva (“DGI”), the Argentine taxing authority, made a claim against Petrolera for a delinquent Obligatory Savings Deposit pertaining to the Entre Lomas joint venture operations, which including interest and indexation for inflation, amounted to 9.2 million Argentine pesos. The Entre Lomas partners did not pay the deposit because of the tax exemption provision included in the original Entre Lomas contract 12,507. After a lengthy judicial process, the Entre Lomas joint venture partners paid the 9.2 million Argentine peso obligatory savings deposit in twelve equal installments during the period July 2000 through June 2001. At the time of payment, the US dollar to Argentine peso exchange rate was 1:1 and the payment was equivalent to $9.2 million, or $2.1 million net to the Company’s direct participation in the Entre Lomas joint venture and $2.7 million net to the Company’s equity interest in Petrolera. The devaluation of the Argentine peso in 2001 and 2002 resulted in a substantial loss in the dollar value of deposit that was recognized by the Company as foreign exchange losses in those years. The U.S. dollar value of the deposit as of December 31, 2006, pertaining to the Company’s 23 percent direct interest in Entre Lomas is $763 thousand and $990 thousand pertaining to its equity interest in Petrolera. Originally, a request for reimbursement of the deposit was made in June 2005. It was subsequently determined that the due date for reimbursement of the deposit is five years from the date the joint venture partners paid the last installment, or June 30, 2006. On June 27, 2006, Petrolera filed a request for reimbursement on behalf of the joint venture partners. As of the date of this report, Petrolera has not yet received an official written response from the DGI, but there has been ongoing contact with the Division of Refunds and Tax Adjustments and the request for reimbursement is being processed. The amount pertaining to the Company’s 23 percent direct interest in Entre Lomas is recorded in other assets.

Export Tax in Tierra del Fuego

In 1972, Argentine law No. 19,640 established that imports and exports to and from the province of Tierra del Fuego were tax exempted. Due to the Argentine economic and financial crisis of 2001 and 2002, law No. 25,561 (the “Emergency Law”) was issued in January 2002, creating a tax on the export of gas, oil and their derivatives for an initial period of five years. As the Emergency Law was a general law with no specific reference to law No. 19.640, the tax exemption for Tierra del Fuego was considered unmodified.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(9)	Defined Contribution Retirement Plan

In April 2004, the Company formed a defined contribution retirement benefit plan for its Argentine employees that required an initial contribution of $207 thousand to recognize prior years service. Assuming the current level of staffing, it is expected that future annual contributions will range between $50 to $70 thousand and will be charged to expense as disbursed. In March 2007, the Company will make a contribution of $59 thousand. This amount was accrued as administrative expense in 2006. The total amount expensed in 2005 was $58 thousand. Plan contributions are based on employees’ current levels of compensation and years of service. Employees vest at a rate of 20 percent per year with full vesting after five years.

(10)

Long-Term Liabilities

At December 31, 2006 and 2005, long-term liabilities consisted of the following. Amounts are stated in Thousands:

	2006		2005
Long-term liabilities
Retirement plan obligations	$	1,048	$	783
Asset retirement obligations		705		1,067
	$	1,753	$	1,850

Retirement plan obligations represent the Company’s proportionate share of the obligation arising from the pension plan that covers all employees of Petrolera, the operator of the Entre Lomas concession. Petrolera, as plan sponsor, has adopted SFAS No. 158 “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” as of December 31, 2006. The effect of the adoption of SFAS No. 158 by Petrolera is not material to the Company’s financial statements. As a result of Petrolera’s adoption of SFAS No. 158, the Company recorded its equity and consolidated interest in the SFAS No. 158 adjustment to its accumulated other comprehensive loss.

(11)

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

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

In November of 2004, the Company received a formal notice from the Banco Central de la Republica Argentina (the Central Bank of Argentina or the “BCRA”), of certain proceedings based upon alleged violation of foreign currency regulations. Specifically, the BCRA claimed that between December of 2001 and November of 2002 the Company failed to bring into the country 100 percent of the foreign currency proceeds from its Argentine oil exports. In 1989, the government established guidelines that required most oil companies to bring into Argentina 30 percent of foreign currency proceeds from exports instead of 100 percent of such proceeds as was generally required of exporters in other industries. In 1991, all foreign exchange controls were lifted by the government. In response to Argentina’s economic crisis of 2001 and 2002, the government reintroduced foreign exchange controls in 2002 and as a result during 2002 the Company repatriated 30 percent of its proceeds from oil exports following the 1989 guidelines. An opinion from Argentina’s Attorney General, however, declared that the benefits granted to the oil and gas industry in 1989 were no longer effective and, therefore, 100 percent of such funds had to be repatriated. This opinion supported the position taken by the Argentine government during 2002. The government then revised its position in 2003 and expressly clarified that oil companies are required to only repatriate 30 percent of such proceeds. The government’s departure from its 2002 position was effective January 1, 2003, leaving some uncertainty in the law with regard to 2002.

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

To date, this process has not advanced beyond what is described in the previous paragraphs. It is anticipated by the Company that this matter will remain open for some time. Under the pertinent foreign exchange regulations, the BCRA may impose significant fines on the Company; however, historically few fines have been made effective in those cases where the foreign currency proceeds were brought into the country and traded in the exchange market at the adequate exchange rate and the exporters had reasonable grounds to support their behavior. As a result, it is premature to reach a conclusion as to the probability of an outcome or the amount of any loss to the Company that might result from this proceeding. There have been no new developments with regard to this matter since the Company filed its formal response in December 2004.

(12)

Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(Amounts in Thousands Except Per Share Amounts)
2006
Operating revenues	$	13,020	$	14,580	$	15,926	$	14,426
Costs and operating expenses		7,436		7,989		7,880		9,259
Equity income from Argentine investments		5,266		5,854		6,280		4,991
Net income		8,976		10,322		12,134		8,630
Net income per ordinary share		1.22		1.40		1.65		1.17
2005
Operating revenues	$	8,881	$	9,980	$	11,267	$	11,611
Costs and operating expenses		5,476		5,465		6,081		6,397
Equity income from Argentine investments		3,362		4,287		5,440		5,215
Net income		5,229		7,001		8,597		9,019
Net income per ordinary share		.71		.95		1.17		1.23

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Oil and Gas Reserves

The following table summarizes, for each of the years presented, changes in quantities, and balances of net proved oil, condensate and plant product reserves for all the Company’s interests in Argentina as estimated by the Company’s independent reserve engineers:

Proved Oil, Condensate and Plant Products

	(Millions of Barrels)
	Consolidated Interests			Equity Interests

December 31, 2003		10.4			13.2
Revisions of previous estimates:
Engineering revisions		—			(0.1	)
Extensions and discoveries		0.6			0.7
Production		(1.0	)		(1.2	)
December 31, 2004		10.0			12.6
Proved developed as of December 31, 2004		6.0			7.5
Proved undeveloped as of December 31, 2004		4.0			5.1
December 31, 2004		10.0			12.6
Revisions of previous estimates:
Engineering revisions		0.4			1.0
Extensions and discoveries		0.5			0.6
Acquisition of reserves		—			0.5
Production		(1.0	)		(1.4	)
December 31, 2005		9.9			13.3
Proved developed as of December 31, 2005		5.5			7.3
Proved undeveloped as of December 31, 2005		4.4			6.0
December 31, 2005		9.9			13.3
Revisions of previous estimates:
Engineering revisions		0.1			—
Extensions and discoveries		0.7			0.4
Reclassification from equity interest to consolidated interest		0.9			(0.9	)
Production		(1.2	)		(1.4	)
December 31, 2006		10.4			11.4
Proved developed as of December 31, 2006		6.1			7.0
Proved undeveloped as of December 31, 2006		4.3			4.4

Effective January 1, 2006, the Company converted its interest in RCLV S.A. to a direct participation interest in the TDF Concessions. The conversion changed the classification of the Company’s TDF Concessions’ oil and gas reserves from equity interest reserves to consolidated interest reserves. This change is reflected in the above table in the line item “Reclassification from equity interest to consolidated interest.”

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The following table summarizes, for each of the years presented, changes in quantities, and balances of net proved natural gas reserves for all the Company’s interests in Argentina as estimated by the Company’s independent reserve engineers:

Natural Gas

	(Billions of Cubic Feet)
	Consolidated Interests			Equity Interests

December 31, 2003		34.0			29.3
Revisions of previous estimates:
Engineering revisions		3.3			3.9
Extension and discoveries		1.6			0.6
Production		(3.8	)		(3.8	)
December 31, 2004		35.1			30.0
Proved developed as of December 31, 2004		29.8			24.8
Proved undeveloped as of December 31, 2004		5.3			5.2
December 31, 2004		35.1			30.0
Revisions of previous estimates:
Engineering revisions		0.2			10.7
Extensions and discoveries		2.4			3.2
Acquisition of reserves		—			8.8
Production		(4.2	)		(5.4	)
December 31, 2005		33.5			47.3
Proved developed as of December 31, 2005		25.7			27.5
Proved undeveloped as of December 31, 2005		7.8			19.8
December 31, 2005		33.5			47.3
Revisions of previous estimates:
Engineering revisions		3.0			2.4
Extensions and discoveries		5.1			0.3
Reclassification from equity interest to consolidated interest		18.1			(18.1	)
Production		(5.6	)		(4.0	)
December 31, 2006		54.1			27.9
Proved developed as of December 31, 2006		34.9			22.0
Proved undeveloped as of December 31, 2006		19.2			5.9

A portion of the Company’s natural gas reserves are consumed in field operations. The volume of natural gas reserves for 2004, 2005, and 2006 estimated to be consumed in field operations included as proved natural gas reserves within consolidated interest is 12.4 bcf, 11.5 bcf, and 17.6 bcf, respectively, and within the equity interest is 16.1 bcf, 19.8 bcf, and 15.5 bcf.

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.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Standardized Measure of Discounted Future Net Cash Flows

The following table summarizes for each of the years presented, the standardized measure of discounted future net cash flows from proved oil and gas reserves that could be produced from all of the concessions in which the Company holds interests in Argentina:

	(Millions of Dollars) (5)

	Consolidated Interests			Equity Interests
As of December 31, 2006
Future cash inflows (1,2,6)	$	512		$	514
Future production and development costs (3,6)		(243	)		(255	)
Future income tax expenses (4)		(86	)		(84	)
Future net cash flows		183			175
10% annual discount for estimated timing of cashflows		(63	)		(60	)
Standardized measure of discounted future net cash flows	$	120		$	115

As of December 31, 2005
Future cash inflows (1,2,6)	$	434		$	604
Future production and development costs (3,6)		(179	)		(246	)
Future income tax expenses (4)		(83	)		(104	)
Future net cash flows		172			254
10% annual discount for estimated timing of cash flows		(61	)		(90	)
Standardized measure of discounted future net cash flows	$	111		$	164

As of December 31, 2004
Future cash inflows (1,2,6)	$	344		$	425
Future production and development costs (3,6)		(137	)		(168	)
Future income tax expenses (4)		(66	)		(83	)
Future net cash flows		141			174
10% annual discount for estimated timing of cash flows		(51	)		(63	)
Standardized measure of discounted future net cash flows	$	90		$	111

(1)	Estimates are made of quantities and timing of future production of oil and gas reserves.

(2)

Estimates of gross revenues from sales are made using prices in effect at December 31 for each year presented. The year-end per barrel oil price for 2006 was $41.90, as compared with $39.90 and $28.24 for 2005 and 2004 respectively. Gas prices for all years are based on gas sales contracts in effect during the respective years.

(3)	Estimated production, transportation, marketing and development costs are based on the current cost of similar services and include all future capital expenditures.

(4)	Estimated taxes consider all taxes to which the Company is subject in Argentina.

(5)	Conversion of U.S. dollars is made utilizing the rate of exchange at December 31 for each of the years presented.

(6)

Values for natural gas consumed in field operations are included both as revenues in future cash inflows and as gas consumption expense in future production and development costs. For the years 2004, 2005 and 2006, the amounts attributable to gas consumption values included in Consolidated Interests are $12 million, $18 million and $26 million, respectively, and in Equity Interest are $16 million, $29 million and $26 million, respectively.

Discounted future net cash flows presented herein may not be reliable due to the difficulty of estimating remaining recoverable reserves. Estimates of oil and gas reserves and rates of future production are inherently imprecise and change over time, as new information becomes available. As a result, subsequent revisions of the quantity and valuation of proved reserves may be significant.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Changes in Standardized Measure

The following analysis summarizes for each of the years presented the factors that caused the increases (decreases) in the amount of standardized measure attributable to the estimate of the Company’s Argentine proved oil and gas reserves.

Total including Equity Interests.

	(Millions of Dollars)
	2006			2005			2004

Revenues, net of production costs	$	(103	)	$	(79	)	$	(58	)
Net changes in prices and production costs		(6	)		105			44
Additions and revisions of previous estimates		43			49			25
Acquisition of reserves		—			25			—
Changes in estimated development costs		(44	)		(41	)		(1	)
Development costs incurred during current period		29			23			12
Net changes in Argentine taxes		(3	)		(36	)		(19	)
Changes in production rates, timing, and other		6			—			—
Accretion of discount		38			28			25
Net increase in standardized measure	$	(40	)	$	74		$	28

Drilling Activity

For 2006, the Company participated in the drilling of 50 gross wells, 22 net wells (13 pertaining to the Company’s consolidated interest, nine to its equity interests). In 2005, the Company participated in the drilling of 40 gross wells, 21 net wells (nine pertaining to the Company’s consolidated interests, 12 to its equity interests). During 2004, the Company participated in the drilling of 26 gross wells, 14 net wells (six pertaining to the Company’s consolidated interests, eight to its equity interests). Over the three-year period, all of the 116 gross wells drilled, 57 net wells (28 pertaining to the Company’s consolidated interests, 29 to its equity interests), were field step out wells, or extended reach development wells.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Well Count and Acreage

The total gross and net well count from all acreage in which the Company has an interest is as follows:

For the year ended December 31, 2006

	Gross		Net Consolidated Interests		Net Equity Interests

Oil		398		92		111
Gas		42		9		7
Injection or water		145		33		43
Inactive or abandoned		359		78		21
Total		944		212		182

For the year ended December 31, 2005

	Gross		Net Consolidated Interests		Net Equity Interests

Oil		379		81		111
Gas		44		5		11
Injection or water		141		32		42
Inactive or abandoned		310		16		57
Total		874		134		221

The Company currently holds interests in six concessions with a total surface area of 1,086,531 gross acres, 307,759 acres net to the Company (253,394 net acres pertaining to its consolidated interests, 543,65 net acres to its equity interest in Petrolera). Developed acreage in the three concessions totals 63,869 gross acres, 25,769 acres net to the Company (12,673 net acres pertaining to its consolidated interest, 13,097 net acres to its equity interest in Petrolera). Undeveloped acreage in the three concessions totals 1,022,662 gross acres, 281,989 acres net to the Company (240,721 net acres pertaining to its consolidated interests, 41,268 net acres to its equity interest in Petrolera).

Capitalized Costs Related to Oil and Gas Producing Activities

Total capitalized costs related to oil and gas producing activities for the Company’s consolidated interests are as follows:

(Amounts in Thousands)	2006			2005

Proved oil and gas properties	$	101,091		$	79,080
Accumulated depreciation, depletion and amortization		(55,486	)		(46,469	)
Net capitalized costs	$	45,605		$	32,611

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Total capitalized costs related to oil and gas producing activities for the Company’s equity interests are as follows:

(Amounts in Thousands)	2006			2005

Proved oil and gas properties	$	110,662		$	99,378
Accumulated depreciation, depletion and amortization		(67,696	)		(60,108	)
Net capitalized costs	$	42,966		$	39,270

Volume, Price and Cost Statistics

The following table shows total sales volumes of crude oil and condensate, natural gas and LPG average sales prices and production costs for the three years.

	2006		2005		2004

Volumes Consolidated Interests
Crude Oil and Condensate (bbls)		1,103,888		945,546		876,868
Gas (mcf)		4,258,743		2,924,651		2,649,436
LPG (tons)		9,608		7,856		7,139
Volumes Equity Interest in Petrolera
Crude Oil and Condensate (bbls)		1,299,073		1,238,436		1,104,543
Gas (mcf)		2,437,900		3,421,368		2,246,521
LPG (tons)		10,343		11,469		9,264
Total Volumes
Crude Oil and Condensate (bbls)		2,402,961		2,183,983		1,981,402
Gas (mcf)		6,696,643		6,346,019		4,895,957
LPG (tons)		19,951		19,326		16,403
Average Sales Prices - Consolidated Interests
Oil and condensate (per bbl)	$	43.88	$	37.56	$	31.21
Gas (mcf)		1.30		1.11		.74
LPG (per ton)		413.36		381.33		335.33
Average Sales Prices - Equity Interests
Oil and condensate (per bbl)	$	42.78	$	38.15	$	31.36
Gas (mcf)		1.47		1.03		.76
LPG (per ton)		410.58		381.48		335.33
Average Sales Prices - Total
Oil (per bbl)	$	43.29	$	37.89	$	31.30
Gas (mcf)		1.36		1.06		.75
LPG (per ton)		411.92		381.42		335.33
Average Production Costs
Oil, gas and LPG (per boe)	$	4.52	$	4.29	$	4.24
Average Depreciation Costs
Oil, gas and LPG (per boe)	$	4.28	$	3.58	$	3.67

Volumes presented in the above table represent those sold to customers and have not been reduced by the 12 percent provincial production tax, which is paid separately and is accounted for as an expense by the Company. In calculating provincial production tax payments, the Argentine producers are entitled to deduct gathering, storage, treating and compression costs.

Average production and depreciation costs are calculated using total costs divided by production volumes expressed in barrels of oil equivalent (boe). One barrel of oil is equal to one barrel of oil equivalent, six mcf of gas are equivalent to one barrel of oil equivalent, and one ton of LPG is equivalent to 11.735 barrels of oil equivalent.

APCO ARGENTINA INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Costs Incurred in Acquisitions, Exploration, and Development

The following table details total expenditures for acquisitions, exploration, and development made by the Company during the current and two previous years:

	(Millions of U.S. Dollars)
	Consolidated Interests		Equity Interests
For the year ended December 31, 2006
Exploration	$	—	$	—
Development		18		13
Workovers		2		2
Total	$	20	$	15
For the year ended December 31, 2005
Acquisition	$	—	$	7
Exploration		—		1
Development		10		13
Workovers		1		2
	$	11	$	23
For the year ended December 31, 2004
Exploration		2		—
Development		5		7
Workovers		1		2
Total	$	8	$	9

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d)-(e) of the Securities Exchange Act) (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 the Company’s management, including the Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

The Company’s management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our Disclosure Controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. The Company monitors its Disclosure Controls and makes modifications as necessary; the Company’s intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

Management’s Report on Internal Control over Financial Reporting

See “Management’s Report on Internal Control over Financial Reporting” set forth on page 30.

ITEM 9B.

Other Information

There have been no events that occurred in the fourth quarter of 2006 that would need to be reported on Form 8-K that have not been previously reported. The Company’s board of directors has set June 28, 2007 as the date for the 2007 annual general meeting of shareholders. More information about the time and location of the meeting will be provided to shareholders at a later date. Shareholder proposals intended for inclusion in the Company’s proxy statement for its 2007 annual general meeting pursuant to Rule 14a-8 under the Securities Exchange Act of 1934 must be directed to the Corporate Secretary, Apco Argentina Inc., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172 and must be received by April 16, 2007. In order for proposals of shareholders made outside of Rule 14a-8 under the Exchange Act to be considered “timely” within the meaning of Rule 14(a)-4(c) under the Exchange Act, such proposals must also be received by the Corporate Secretary at the above address by April 16, 2007.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Directors and Executive Officers

The Company’s articles of association provide for a board of directors of not less than three and not more than nine persons. The articles of association also provide that at each annual general meeting of shareholders one-third of the directors, or if their number is not three or a multiple of three, then the number nearest one-third, shall retire from office. The directors to retire in every year are those who have been longest in office since their last election and retiring directors are eligible to be re-elected as directors. Between persons who become directors on the same day those to retire are determined by lot unless they otherwise agree among themselves as to who will retire. Directors appointed by the board of directors to fill a vacancy or as an addition to the existing directors hold office until the next following annual meeting of shareholders and are not taken into account in determining the directors who are to retire by rotation as described above. Messrs. Keith E. Bailey, Ralph A. Hill, and John H. Williams were last elected as directors at the annual general meeting of shareholders held in 2005. Messrs. Robert J. LaFortune and Rodney J. Sailor were last elected as directors at the annual general meeting of shareholders held in 2006. The number of directors constituting the total number of members is currently fixed at seven and if this number remains the same by the next annual general meeting of shareholders, the terms of Messrs. Bryan K. Guderian and Piero Ruffinengo will expire at such meeting. Executive officers of the Company are elected by the board of directors and hold office until relieved of such office by action of the board of directors.

The following table sets forth certain information with respect to the Company’s executive officers and members of the board of directors.

Name	Age	Position

Ralph A. Hill	47	Chairman of the Board, Chief Executive Officer and Director
Landy L. Fullmer	54	Chief Financial Officer, Chief Accounting Officer, Controller and Vice President
Thomas Bueno	55	President and Chief Operating Officer
Keith E. Bailey	64	Director
Bryan K. Guderian	47	Director
Robert J. LaFortune	80	Director
Piero Ruffinengo	62	Director
Rodney J. Sailor	48	Director
John H. Williams	88	Director

Business Experience

Mr. Hill has served as a director of the Company, chairman of the board of directors, and chief executive officer since 2002 and as senior vice president and general manager of several subsidiaries in the petroleum services and exploration and production units of Williams since 1998. He has also held various management positions with the Williams Energy Services business unit of Williams since 1993. Mr. Hill has served as a director of Petrolera Entre Lomas S.A. since April 2003.

Mr. Fullmer has served as the Company’s chief financial officer since 2003 and as chief accounting officer and controller of the Company since September 2005. Since 1996, he has served as the director of accounting/controller for the Exploration and Production unit of Williams.

Mr. Bueno has served as president and chief operating officer of the Company since April 2002. He served as controller, and chief accounting officer from 1991 to September 2005. He served as a director of the Company from 1998 to April 2002 and as general manager from 1999 to 2003. Mr. Bueno has been employed by Williams since 1984 and has held various positions with the Company since 1985. He has served as a director of Petrolera Entre Lomas S.A. since 1991.

Mr. Bailey has served as a director of the Company since May 2002. He has served as a director of Mark West Energy Partners, L.P. since January 2005, as a director of People’s Energy since February 2005 and, as a director of AEGIS Insurance Services Inc. since 2001, and as a director of Integrys Energy Group, Inc. since February 2007. He served as a director of People’s Energy from 2005 to February 2007, when People’s Energy merged with Integrys Energy Group, Inc. He served as chairman of the board of directors and chief executive officer of Williams from 1994 to 2002, as president from 1992 to 1994 and as executive vice president from 1986 to 1992. Mr. Bailey previously served as a director of the Company from 1987 to 1998 and as the Company’s chairman of the board from 1992 to 1996. He served as a director of Petrolera Entre Lomas S.A. from 1988 to 1999.

Mr. Guderian has served as a director of the Company since April 2002. He has also served as vice president of Williams’ Exploration and Production unit since 1998 and as a director of Petrolera Entre Lomas S.A. since 2003.

Mr. LaFortune has served as a director of the Company since 1998. He is self-employed and manages, evaluates and analyzes personal investments. Mr. LaFortune is also a director of the Bank of Oklahoma Financial Corporation and serves on the credit and community reinvestment act committees of that company’s board of directors and formerly served on the audit committee. He is the former Mayor of the City of Tulsa and also served as a director of Williams from 1978 to 1999, including six years as chairman of the audit committee.

Mr. Sailor has served as a director of the Company since September 2006. He has served as vice president and treasurer of Williams since July 2005. Mr. Sailor served as assistant treasurer of Williams from 2001 to 2005 and was responsible for capital structuring and capital markets transactions, management of Williams’ liquidity position, and oversight of Williams’ balance sheet restructuring program. Mr. Sailor served as vice president of strategic international development and Latin America for the former telecommunications business unit of Williams from 1999 to 2001. He held various positions at Williams involving international finance, corporate finance, strategic planning and development, and accounting from 1985 to 1999.

Mr. Williams has served as a director of the Company since 1992. Mr. Williams is engaged in personal investments and has been for more than five years. He was chairman of the board and chief executive officer of Williams prior to retiring in 1978. Mr. Williams is a director of Unit Corporation and an honorary director of Willbros Group, Inc. and Williams. He formerly served as a director of Petrolera Entre Lomas S.A.

Mr. Ruffinengo has served as a director of the Company since April 2002. He has been engaged in the private practice of law in Salt Lake City, Utah since 1984. He served the Company as a consultant from 1984 through 1999. Mr. Ruffinengo has served as a director of Petrolera Entre Lomas S.A. since 2004 and previously served as a director of that company from April 2002 to April 2003 and from the early 1970’s through 1999.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s officers and directors and persons who own more than ten percent of a registered class of the Company’s equity securities, to file with the SEC and the Nasdaq Stock Market reports of ownership of Company securities and changes in reported ownership. Officers, directors and greater than ten percent shareholders are required by SEC rules to furnish the Company with copies of all Section 16(a) reports they file. Based solely on a review of the reports furnished to the Company, or written representations from reporting persons that all reportable transactions were reported, the Company believes that during the fiscal year ended December 31, 2006 the Company’s officers, directors and greater than ten percent owners timely filed all reports they were required to file under Section 16(a).

Code of Ethics

The Company adopted a Code of Ethics that applies to the Company’s directors, officers and employees. The Code of Ethics is consistent with the criteria for codes of ethics and conduct established by the rules of the U.S. Securities and Exchange Commission and the listing standards of the Nasdaq Stock Market. A copy of the code is filed as an exhibit to this report.

Corporate Governance

Audit Committee

The Company’s board of directors has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act of 1934. The members of the audit committee include Messrs. Bailey, LaFortune, Ruffinengo and Williams. The board of directors has determined that each of these persons meets the independence and other qualification requirements of the rules of the Nasdaq Stock Market. In addition, the board of directors has determined that Messrs. Bailey and LaFortune each qualify as an “audit committee financial expert” as defined by the rules of U.S. Securities and Exchange Commission. Biographical information for each of these persons is set forth above under the caption “Business Experience.” For more information about the audit committee, please read “Certain Relationships and Related Transactions, and Director Independence --- Corporate Governance” and “Principal Accountant Fees and Services.”

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The Company is managed by the employees of Williams and each of our executive officers are employees of Williams. Each of the Company’s executive officers is compensated directly by Williams rather than by the Company. All decisions as to the compensation of the Company’s executive officers are made by Williams. Therefore, the Company does not have any policies or programs relating to compensation of its executive officers and does not make any decisions relating to such compensation. A full discussion of the policies and programs of Williams will be set forth in the proxy statement for Williams’ 2007 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading “Investors — SEC Filings.” Williams charges the Company, pursuant to an administrative services agreement, an annual flat fee for the services of Williams’ employees, other than Mr. Bueno, who dedicate a significant amount of time to the affairs of the Company. Williams also charges the Company, pursuant to the terms of the same agreement, a fee for Mr. Bueno’s services based on both his actual total compensation and an estimated percentage of his time that is dedicated to performing services for the Company. Please read “Certain Relationships and Related Transactions, and Director Independence — Transactions with Related Persons — Administrative Services Agreement” for more information regarding this arrangement.

Executive Compensation

In 2006, the Company incurred an allocated charge of $119,732 for Mr. Bueno's salary and $74,542 for his cash incentive bonus. In 2005, the Company incurred an allocated charge of $111,138 for Mr. Bueno's salary and $60,198 for his cash incentive bonus. In 2004, the Company incurred an allocated charge of $103,865 for Mr. Bueno's salary and $63,948 for his cash incentive bonus. Each year the Company also incurs a charge for Mr. Bueno’s benefits, including without limitation his pension and welfare benefits, which charge is equal to 33 percent of the aggregate allocated charge incurred by the Company for Mr. Bueno’s salary and cash incentive bonus in that year. This benefits charge was $39,907 in 2006, $36,676 in 2005, and $34,618 in 2004.

Further information regarding the compensation of our principal executive officer, Ralph A. Hill, who also serves as a senior vice president of Williams, will be set forth in the proxy statement for Williams' 2007 annual meeting of stockholders which will be available upon its filing on the SEC's website at http://www.sec.gov and on Williams' website at http:/www.williams.com under the heading "Investors--SEC Filings." Further information regarding the portion of Mr. Hill's compensation and that of Landy L. Fullmer, who serves as the Company’s chief financial officer, allocable to us may be found in this filing under the heading "Certain Relationships and Related Transactions, and Director Independence — Transactions with Related Persons — Administrative Services Agreement."

Compensation Committee Interlocks and Insider Participation

The board of directors of the Company does not maintain a compensation committee. The executive officers of the Company during 2006 were employees of Williams and compensation decisions with respect to those individuals were determined by Williams.

Compensation of Directors

Directors who are employees of Williams or an affiliate of the Company or Williams receive no compensation for service on the Company’s board of directors. Each non-management director receives an annual retainer of $14,000 and an additional fee for attending board meetings of $1,000 per meeting. The annual retainer is paid in quarterly installments following the end of each calendar quarter and a non-management director must be a board member during a given calendar quarter in order to be eligible to receive a quarterly payment for that quarter. Additionally, each non-management director who serves on the audit committee or nominating committee receives a fee for attending each meeting of one of those committees of $1,000 per meeting. The chairmen of the audit committee and the nominating committee each receive a fee of $2,000 for each committee meeting that they attend. Directors are also reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of the board of directors or committees thereof or otherwise by reason of their being a director.

For their service non-management directors received the following compensation in 2006:

Name	Fees earned or paid in cash		All Other Compensation		Total

Keith E. Bailey	$	19,000	$	0	$	19,000
Robert J. LaFortune	$	28,000	$	0	$	28,000
Piero Ruffinengo	$	21,000	$	0	$	21,000
John H. Williams	$	26,000	$	0	$	26,000

Compensation Committee Report

The Company’s board of directors does not have a compensation committee. The board of directors has reviewed and discussed the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.

	The Board of Directors:
	Keith E. Bailey, Bryan K. Guderian, Ralph A. Hill,
	Robert J. LaFortune, Piero Ruffinengo,
	Rod J. Sailor, John H. Williams

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the beneficial ownership of the Company’s ordinary shares that are owned, as of March 1, 2007, by:

each person known by the Company to be a beneficial owner of more than 5 percent of ordinary shares;

each director of the Company;

each of the named executive officers of the Company; and

all directors and executive officers of the Company as a group.

The amounts and percentage of securities beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all securities shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner	Number of Ordinary Shares Beneficially Owned		Percent of Class

The Williams Companies, Inc.	5,075,398	(1)(2)	68.96%
Williams Global Energy (Cayman) Limited	5,075,398	(2)	68.96
Lehman Brothers Holdings Inc.	659,798	(3)	9.0
Brown Advisory Holdings Incorporated	435,535	(4)	5.9
Keith E. Bailey	—		*
Thomas Bueno	5		*
Landy L. Fullmer	—		*
Bryan K. Guderian	—		*
Ralph A. Hill	—		*
Robert J. LaFortune	5		*
Piero Ruffinengo	—		*
Rodney J. Sailor	—		*
John H. Williams	10		*
All directors and executive officers as a group (9 persons)	20		*

* Less than one percent.

(1)	Includes 5,075,398 Ordinary Shares held of record by Williams Global Energy (Cayman) Limited.

(2)

Williams Global Energy (Cayman) Limited (“Williams Global Energy”) is an indirect wholly-owned subsidiary of Williams International Company, which is a direct wholly-owned subsidiary of The Williams Companies, Inc. (“Williams”). As a result, Williams may be deemed to be the beneficial owner of the shares held by Williams Global Energy under the rules and regulations of the SEC. The address of both of these companies is One Williams Center, Tulsa, Oklahoma 74172.

(3)

According to a Schedule 13G/A, filed by Lehman Brothers Holdings Inc. (“Holdings”) with the SEC on February 7, 2007, Holdings may be deemed the beneficial owner of 659,798 ordinary shares owned by Lehman Brothers Inc. (“LBI”). LBI, a broker dealer, is a wholly owned subsidiary of Holdings. The address of LBI and Holdings is 745 Seventh Avenue, New York, New York 10019.

(4)

According to a Schedule 13G filed by Brown Advisory Holdings Incorporated (“BAHI”) with the SEC on February 13, 2007, BAHI is a parent holding company of Brown Advisory Securities, LLC (“Brown LLC”), a broker dealer. Clients of Brown LLC own 435,535 ordinary shares of the Company and have the right to receive, or the power to direct the receipt of, dividends from, or the proceeds from, the sale of such securities.

The following table sets forth, as of March 1, 2007, the number of shares of Common Stock of The Williams Companies, Inc., beneficially owned by each of the Company’s directors and executive officers at the end of the last fiscal year and by such directors and executive officers as a group:

Name of Beneficial Owner	Shares of Common Stock Owned Directly or Indirectly (1)(2)		Shares Underlying Options Exercisable Within 60 Days (3)		Total		Percentage of Class
Keith E. Bailey		31,848		381,243		413,091		*
Thomas Bueno		29,762		17,223		46,985		*
Landy L. Fullmer		19,460		43,047		62,507		*
Bryan K. Guderian		0		46,459		46,459		*
Ralph A. Hill		122,815		223,129		345,944		*
Robert J. LaFortune		57,937		0		57,937		*
Piero Ruffinengo		0		0		0		*
Rodney J. Sailor		24,250		54,465		78,715		*
John H. Williams		1,011,558		0		1,011,558		*
All directors and executive officers as a group (9 persons)		1,297,630		765,566		2,063,196		*

* Less than one percent.

(1)

Includes shares held under the terms of incentive and investment plans as follows: Mr. Bueno, 9,955 shares in The Williams Companies Investment Plus Plan and 12,014 restricted stock units; Mr. Fullmer, 18,670 shares in The Williams Companies Investment Plus Plan and 440 restricted stock units; Mr. Hill, 26,191 shares in The Williams Companies Investment Plus Plan and 96,624 restricted stock units; Mr. Sailor, 9,994 shares in The Williams Companies Investment Plus Plan and 14,256 restricted stock units. Restricted stock units, formerly referred to as deferred stock, includes both time-based and performance-based units and do not have voting or investment power. Shares held in The Williams Companies Investment Plus Plan have voting and investment power.

(2)	Includes 994,610 shares held in trust by Mr. Williams; 30,108 shares held in trust by Mr. Bailey and 1,740 shares held in trust by his spouse; and 55,346 shares held in trust by Mr. LaFortune.

(3)	The shares indicated represent stock options granted under Williams’ current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of March 1, 2007. Shares subject to options cannot be voted.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons

Administrative Services Agreement

Williams owns 69 percent of the Company’s ordinary shares. The Company incurred charges of $699,000, $597,000, and $843,000 in fiscal years 2006, 2005, and 2004, respectively, from Williams and its affiliates for management services, overhead allocation, general and administrative expenses (including the costs of compensating employees of Williams who allocate a portion of their time to managing the affairs of the Company), insurance, internal audit services, and purchases of materials and supplies. These charges were incurred by the Company pursuant to an administrative services agreement between the Company and Williams.

The Company is managed by employees of Williams and all of its executive officers, including Mr. Hill, our chairman of the board and chief executive officer, and Mr. Fullmer, our chief financial officer and chief accounting officer, are employees of Williams who are compensated directly by Williams rather than by the Company. Pursuant to the administrative services agreement, Williams charges the Company an executive support charge, which charge is incurred by the Company primarily for the time spent by employees of Williams, other than Mr. Bueno, in managing the affairs of the Company. In 2004, 2005, and 2006 the Company paid an annual aggregate charge of $100,000 for the services of these persons. In addition, Williams also charges the Company, pursuant to the terms of the same agreement, a fee for Mr. Bueno’s services based on both his actual total compensation and an estimated percentage of his time that is dedicated to performing services for the Company. Please read “Executive Compensation - Executive Compensation” for further information regarding the amounts paid by the Company for Mr. Bueno’s services. The Company is also dependent upon Williams to cover certain other costs such as rent, reproduction, office supplies, computer support, etc for which it reimburses Williams.

Accounts payable to Williams and its affiliates outstanding at December 31, 2006, December 31, 2005, and December 31, 2004 pursuant to the administrative services agreement were approximately $308,000, $817,000, and $446,000 respectively.

Northwest Argentina Corporation

For convenience, the Company paid $375,000 on behalf of Northwest Argentina Corporation (“NWA”) in July 2006 for NWA’s share of the anticipated settlement of a lawsuit related to an oil and gas concession located in Argentina, in which NWA and the Company each own a 1.5 percent interest. NWA is a wholly owned subsidiary of Williams and Williams reimbursed the Company for the amount advanced.

The Company also regularly collects revenues and pays cash calls on behalf of NWA with respect to NWA’s interest in the concession described above and is reimbursed with cash distributions the Company receives from the concession on behalf of NWA. For the period from January 1, 2006 through February 28, 2007, $679 thousand was the largest aggregate amount for which the Company was indebted to NWA as a result of these transactions. For the same period, $771 thousand was the largest aggregate amount for which NWA was indebted to the Company. As of February 28, 2007, NWA was indebted to the Company for $131 thousand as a result of this arrangement.

Review, Approval or Ratification of Transactions with Related Persons

The charter of the audit committee of the Company’s board of directors provides that the committee will review, on an ongoing basis and approve all related party transactions required to be disclosed pursuant to Item 404(a) of the SEC’s Regulation S-K (“Related Party Transactions”). The audit committee’s charter further provides that (i) the committee consider whether a Related Party Transaction is bona fide in the best interest of the Company and (ii) the members of the committee reviewing and taking action on a Related Party Transaction observe any relevant and applicable provisions of the Company’s articles of association and exercise the powers vested in them for the purpose in which they were conferred and not for a collateral purpose.

Corporate Governance

The Company is a “controlled company” as defined by the rules of the Nasdaq Stock Market because a subsidiary of Williams owns approximately 69 percent of the Company’s ordinary shares. Therefore, the Company is not subject to the requirements of the Nasdaq Stock Market that would otherwise require the Company to have (1) a majority of independent directors on the board, (2) a compensation committee composed solely of independent directors, (3) a nominating committee composed solely of independent directors, (4) compensation of the company’s executive officers determined by a majority of the independent directors or a compensation committee composed solely of independent directors, and (5) director nominees selected, or recommended for the board’s selection, either by a majority of the independent directors or a nominating committee composed solely of independent directors. Notwithstanding the foregoing, the board of directors has established a nominating committee. The board of directors also has a standing audit committee. The board of directors does not have a compensation committee or any other committees performing similar functions. Compensation decisions for the Company’s executive officers are made by Williams. The board of directors has determined that it is more appropriate for compensation decisions affecting the Company’s directors who are not employees of Williams or the Company’s other affiliates to be made by all of the members of the board of directors.

The following indicates committee membership as of March 1, 2007.

	Audit Committee	Nominating Committee
Keith E. Bailey	ü	ü
Robert J. LaFortune	●	ü
Piero Ruffinengo	ü	ü
John H. Williams	ü	●

● = Chairperson

ü = Committee Member

The board of directors annually reviews the independence of directors and makes a determination that each director expected to be independent qualifies as an “independent director” as defined by the rules of the Nasdaq Stock Market, including a determination that the director does not have a relationship, which, in the opinion of the board of directors, would interfere with the exercise of independent judgment in carrying out the responsibilities as director. The board of directors has determined that each of Messrs. Bailey, LaFortune, Ruffinengo, and Williams is an “independent director” under the current rules of the Nasdaq Stock Market. The board of directors considered the fact that Williams reimbursed Mr. Bailey, prior to his appointment to the audit committee, an amount for fees in connection with the winding up of certain loans from Williams. The board of directors also considered the fact that Mr. Bailey serves as a director of Aegis Insurance Services Inc. (“Aegis”), which participates in the insurance coverage programs of Williams and certain of its affiliates, including the Company. The board of directors noted that, since the reimbursements were insignificant in amount, and because Mr. Bailey does not serve as an executive officer and is not a stockholder of Aegis, these relationships would not interfere with the exercise of independent judgment in carrying out responsibilities as a director. In addition, the board of directors has determined that each of these persons meets the heightened independence requirements of the Nasdaq Stock Market for audit committee members. Although the board of directors does not require that members of the nominating committee be independent, the board of directors has determined that that its current members are independent as defined by the rules of the Nasdaq Stock Market. Messrs. Guderian, Hill, Sailor, and Randy Barnard (who left the board of directors in September 2006), as employees of Williams, are not independent directors under these standards.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Fees for professional services provided by Ernst & Young LLP (“E&Y”), the Company’s independent registered public accounting firm, for each of the last two fiscal years in each of the following categories are:

	2006		2005
Audit Fees:	$	250,995	$	231,364
Audit-Related Fees:		1,200		3,470
Tax Fees:		---		---
All Other Fees:		---		---
Total	$	252,195	$	234,834

Audit fees consisted of professional services for the audit of the Company’s financial statements, the audit of the Company’s assessment of internal controls over financial reporting, and review of financial statements included in quarterly reports on Form 10-Qs, or for services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements. Audit-related fees generally include fees for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements. More specifically, these services consisted principally of consultation concerning financial accounting and reporting standards.

The audit committee of the Company’s board of directors has established a policy regarding pre-approval of all audit and non-audit services provided by E&Y. On an ongoing basis, the Company’s management presents specific projects and categories of service to the audit committee for which advance approval is requested. The audit committee reviews those requests and advises management if the audit committee approves the engagement of E&Y. On a quarterly basis, management reports to the audit committee regarding the services rendered by, including the fees of, the independent accountant in the previous quarter and on a cumulative basis for the fiscal year. The audit committee may also delegate the ability to pre-approve permissible services, excluding services related to the Company’s internal control over financial reporting, to any two committee members, provided that any such pre-approvals are reported on at a subsequent audit committee meeting. In 2006, 100 percent of E&Y’s fees were pre-approved by the audit committee. The audit committee’s pre-approval policy with respect to audit and non-audit services is provided as an exhibit to this report.

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)

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 exhibits listed below are filed as part of this annual report:

Exhibit Number		Description
*(3)	-	Memorandum of Association of Apco Argentina Inc. as amended, as filed with Form 10-Q, No. 0-8933, dated November 8, 2006.

*(3)	-	Articles of Association of Apco Argentina Inc., as amended as filed with Form 10-Q, No. 0-8933, dated November 8, 2006.

*(10)	-	Agreement dated March 13, 1968, between Perez Companc and YPF for the Exploration, Exploitation and Development of the “Entre Lomas” area, Contract Number 12,507 as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)	-	Translation dated November 18, 1970, of agreement dated March 13, 1968, between Perez Companc and YPF as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)	-	Joint Venture Agreement dated April 1, 1968, among Apco Oil Corporation, Perez Companc and Petrolera as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)	-	Joint Venture Agreement dated February 29, 1972, among the Company, Perez Companc and Petrolera as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)	-	Joint Venture Agreement dated March 23, 1977, among the Company, Perez Companc and Petrolera as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)	-	Contract dated December 1977, amending the March 13, 1968 Agreement between Perez Companc and YPF as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)	-	Memorandum of Agreement dated August 16, 1979, among the Company, Perez Companc and Petrolera as filed with Form 10-K, No. 0-8933, dated March 28, 1980.

*(10)	-	Agreement dated December 7, 1983, between Petrolera and YPF regarding the delivery of propane and butane from the Entre Lomas area, as filed with Form 10-K, No. 0-8933, dated April 12, 1983.

*(10)	-	Contract for the exploration, exploitation and development of the “Entre Lomas” area, dated July 8, 1982, between Yacimientos Petroliferos Fiscales Sociedad Del Estado and Petrolera Perez Companc, Inc. relating to the extension of Contract No. 12,507, as filed with Form 10-K, No. 0-8933, dated April 12, 1983.

*(10)	-	Additional clause number 3 dated December 18, 1985, to the agreement between Perez Companc and YPF covering the Entre Lomas area dated March 13, 1968, and attached translation as filed with Form 10-K, No. 0-8933, dated April 11, 1988.

Exhibit Number		Description
*(10)	-	Agreement between the Joint Committee created by the Ministry of Public Works and Services and the Ministry of Energy, YPF and Petrolera Perez Companc S.A. dated December 26, 1990, constituting the conversion to concession and deregulation of the original Entre Lomas contract number 12,507 as filed with Form 10-K, No. 0-8933, dated April 13, 1992.

*(10)	-	Share purchase agreement by and among Ms. Maria Carmen Sundblad de Perez Companc, Sudacia S.A. and Apco Argentina Inc. dated October 23, 2002, relating to the purchase by the Company of 27,700 shares of Petrolera Perez Companc S.A. as filed with Form 10-K, No. 0-8933, dated March 28, 2003.

*(10)	-	Share purchase agreement by and between the shareholders of Fimaipu S.A. and Apco Argentina Inc. dated December 5, 2002, relating to the purchase by the Company of all of the shares of Fimaipu S.A. as filed with Form 10-K, No. 0-8933, dated March 28, 2003.

*(10)	-	Administrative Services Agreement by and between The Williams Companies, Inc. and Apco Argentina Inc. dated January 1, 2004, as filed with Form 10-Q, No. 0-8933, dated August 12, 2004.

*(10)	-	English translation of stock purchase agreement by and between the Tower Fund L.P., Apco Argentina Inc., Netherfield Corporation, Sucursal Tierra del Fuego, Antartida e Islas del Atlantico Sur and ROCH S.A. dated February 25, 2005 relating to the purchase by the Company of 79,752 shares of Rio Cullen-Las Violetas S.A. dated February 25, 2005 as filed with Form 10-K, No. 0-8933, dated March 14, 2005.

*(14)	-	Apco Argentina Inc. Code of Ethics as filed with Form 10-K, No. 0-8933, dated March 30, 2004.

(21)	-	Subsidiaries of the registrant.

(23)	-	Consent of Independent Petroleum Engineers.

(24)	-	Power of attorney together with certified resolution.

(31.1)	-	Certification of the Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2)	-	Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32)	-	Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(99)	-	Pre-approval policy with respect to audit and non-audit services of the audit committee of the board of directors of Apco Argentina Inc.

*	-	Exhibits so marked have been filed with the Securities and Exchange Commission as part of the filing indicated and are incorporated herein by reference.

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 ARGENTINA INC.
	(Registrant)
Dated: March 13, 2007	By:	/s/ Thomas Bueno
		Thomas Bueno
		Attorney-in-fact

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.

/s/ *Ralph A. Hill		March 13, 2007
Ralph A. Hill, Chief Executive Officer and Chairman of the Board

/s/ *Landy L. Fullmer		March 13, 2007
Landy L. Fullmer, Chief Financial Officer, Chief Accounting Officer, and Controller

/s/ *Keith E. Bailey		March 13, 2007
Keith E. Bailey, Director

/s/ *Rodney J. Sailor		March 13, 2007
Rodney J. Sailor, Director

/s/ *Robert J. LaFortune		March 13, 2007
Robert J. LaFortune, Director

/s/ *Bryan K. Guderian		March 13, 2007
Bryan K. Guderian, Director

/s/ *Piero Ruffinengo		March 13, 2007
Piero Ruffinengo, Director

/s/ *John H. Williams		March 13, 2007
John H. Williams, Director

*By: /s/ Thomas Bueno		March 13, 2007
Thomas Bueno, Attorney-in-Fact

INDEX TO EXHIBITS

Exhibit Number	Page Number	Description
*(3)		Memorandum of Association of Apco Argentina Inc. as amended, as filed with Form 10-Q, No. 0-8933, dated November 8, 2006.

*(3)		Articles of Association of Apco Argentina Inc., as amended as filed with Form 10-Q, No. 0-8933, dated November 8, 2006.

*(10)		Agreement dated March 13, 1968, between Perez Companc and YPF for the Exploration, Exploitation and Development of the “Entre Lomas” area, Contract Number 12,507 as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)		Translation dated November 18, 1970, of agreement dated March 13, 1968, between Perez Companc and YPF as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)		Joint Venture Agreement dated April 1, 1968, among Apco Oil Corporation, Perez Companc and Petrolera as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)		Joint Venture Agreement dated February 29, 1972, among the Company, Perez Companc and Petrolera as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)		Joint Venture Agreement dated March 23, 1977, among the Company, Perez Companc and Petrolera as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)		Contract dated December 1977, amending the March 13, 1968 Agreement between Perez Companc and YPF as filed with Form S-1, Registration No. 2-62187 dated September 26, 1978.

*(10)		Memorandum of Agreement dated August 16, 1979, among the Company, Perez Companc and Petrolera as filed with Form 10-K, No. 0-8933, dated March 28, 1980.

*(10)		Agreement dated December 7, 1983, between Petrolera and YPF regarding the delivery of propane and butane from the Entre Lomas area, as filed with Form 10-K, No. 0-8933, dated April 12, 1983.

*(10)		Contract for the exploration, exploitation and development of the “Entre Lomas” area, dated July 8, 1982, between Yacimientos Petroliferos Fiscales Sociedad Del Estado and Petrolera Perez Companc, Inc. relating to the extension of Contract No. 12,507, as filed with Form 10-K, No. 0-8933, dated April 12, 1983.

*(10)		Additional clause number 3 dated December 18, 1985, to the agreement between Perez Companc and YPF covering the Entre Lomas area dated March 13, 1968, and attached translation as filed with Form 10-K, No. 0-8933, dated April 11, 1988.

*(10)		Agreement between the Joint Committee created by the Ministry of Public Works and Services and the Ministry of Energy, YPF and Petrolera Perez Companc S.A. dated December 26, 1990, constituting the conversion to concession and deregulation of the original Entre Lomas contract number 12,507 as filed with Form 10-K, No. 0-8933, dated April 13, 1992.

*(10)		Share purchase agreement by and among Ms. Maria Carmen Sundblad de Perez Companc, Sudacia S.A. and Apco Argentina Inc. dated October 23, 2002, relating to the purchase by the Company of 27,700 shares of Petrolera Perez Companc S.A. as filed with Form 10-K, No. 0-8933, dated March 28, 2003.

Exhibit Number	Page Number	Description
*(10)		Share purchase agreement by and between the shareholders of Fimaipu S.A. and Apco Argentina Inc. dated December 5, 2002, relating to the purchase by the Company of all of the shares of Fimaipu S.A. as filed with Form 10-K, No. 0-8933, dated March 28, 2003.

*(10)		Administrative Services Agreement by and between The Williams Companies, Inc. and Apco Argentina Inc. dated January 1, 2004, as filed with Form 10-Q, No. 0-8933, dated August 12, 2004.

*(10)		English translation of stock purchase agreement by and between the Tower Fund L.P., Apco Argentina Inc., Netherfield Corporation, Sucursal Tierra del Fuego, Antartida e Islas del Atlantico Sur and ROCH S.A. dated February 25, 2005 relating to the purchase by the Company of 79,752 shares of Rio Cullen-Las Violetas S.A. dated February 25, 2005 as filed with Form 10-K, No. 0-8933, dated March 14, 2005.

*(14)		Apco Argentina Inc. Code of Ethics as filed with Form 10-K, No. 0-8933, dated March 30, 2004.

(21)		Subsidiaries of the registrant.

(23)		Consent of Independent Petroleum Engineers.

(24)		Power of attorney together with certified resolution.

(31.1)		Certification of the Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2)		Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32)		Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(99)		Pre-approval policy with respect to audit and non-audit services of the audit committee of the board of directors of Apco Argentina Inc.

*		Exhibits so marked have been filed with the Securities and Exchange Commission as part of the filing indicated and are incorporated herein by reference.

Schedule S-1

PETROLERA ENTRE LOMAS S.A.

Financial Statements for the fiscal year

ended December 31, 2006

with Report of Independent Registered Public Accounting Firm

PETROLERA ENTRE LOMAS S.A.

TABLE OF CONTENTS TO FINANCIAL STATEMENTS

CONTENTS		PAGE

Ÿ Report of Independent Registered Public Accounting Firm		-

Ÿ Financial statements

- Balance sheets as of December 31, 2006 and 2005		- 1 -

- Statements of income for the years ended December 31, 2006, 2005 and 2004		- 2 -

- Statements of shareholders’ equity for the years ended December 31, 2006, 2005 and 2004		- 3 -

- Statements of cash flows for the years ended December 31, 2006, 2005 and 2004		- 4 -

- Notes to financial statements		- 5 -

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PETROLERA ENTRE LOMAS S.A.:

We have audited the accompanying balance sheets of Petrolera Entre Lomas S.A. (an Argentine corporation) as of December 31, 2006 and 2005, and the related statements of income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2006. 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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

Buenos Aires, Argentina	PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
February 14, 2007	(member of Ernst & Young Global)



	DANIEL G. MINENNA
	Partner

BALANCE SHEETS AS OF DECEMBER 31, 2006 AND 2005

(stated in thousands of U.S. dollars)

	December 31,
	2006			2005
ASSETS

CURRENT ASSETS

Cash and cash equivalents	$	26,671		$	18,733
Accounts receivable ($16,757 and $16,389 with related parties, note 6)		17,815			17,440
Other receivables		3,174			3,113
Inventories		1,487			1,290
Other assets		259			584
Total current assets		49,406			41,160

NONCURRENT ASSETS

Property and equipment, net (Note 5)		117,846			105,651
Other receivables		-			500
Other assets		1,091			411
Total noncurrent assets		118,937			106,562
Total assets	$	168,343		$	147,722

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES

Accounts payable and accrued liabilities ($477 and $334 with related parties, note 6)	$	7,965		$	7,624
Taxes payable and payroll (Note 9)		16,857			13,280
Other payables		373			847
Total current liabilities		25,195			21,751

NONCURRENT LIABILITIES

Other liabilities (Note 9)		5,718			4,684
Total liabilities		30,913			26,435

SHAREHOLDERS’ EQUITY

Paid-in Capital (95,443,572 ordinary shares and 20,414,127 preferred shares authorized, issued and outstanding, note 12)		41,289			41,289
Legal reserve		4,017			1,843
Facultative reserve		24,013			20,701
Retained earnings		69,973			58,588
Accumulated other comprehensive loss		(1,862	)		(1,134	)
Total shareholders’ equity		137,430			121,287
Total liabilities and shareholders’ equity	$	168,343		$	147,722

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

STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

(stated in thousands of U.S. dollars)

	Year ended December 31,
	2006			2005			2004
REVENUES:
Operating revenues ($142,935, $117,451 and $85,085 with related parties, note 6)	$	155,401		$	127,164		$	93,914

COST AND EXPENSES:

Operating expenses ($3,640, $2,598 and $2,198 with related parties, note 6)		(21,401	)		(17,245	)		(15,663	)
Provincial production tax		(17,290	)		(14,792	)		(11,007	)
Transportation and storage		(1,920	)		(1,608	)		(1,390	)
Selling and administrative		(3,059	)		(2,657	)		(2,147	)
Depreciation of property and equipment		(18,598	)		(16,206	)		(12,962	)
Exploration expense		(430	)		(839	)		(263	)
Taxes other than income		(4,267	)		(3,603	)		(2,475	)
Financial losses		(228	)		(680	)		(1,689	)
Foreign exchange gains (losses)		(157	)		16			(15	)
Other income (expense), net		(652	)		450			876
Total cost and expenses		(68,002	)		(57,164	)		(46,735	)

Income before income tax		87,399			70,000			47,179

Income tax (Note 4)		(32,528	)		(26,540	)		(18,609	)
Net income	$	54,871		$	43,460		$	28,570

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

STATEMENTS OF SHAREHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

(stated in thousands of U.S. dollars)

Balance	Capital stock		Legal reserve		Facultative reserve			Accumulated other comprehensive loss			Retained earnings			Total

December 31, 2003		2,050		305		-			(277	)		97,036			99,114

- Minimum pension liability (Note 10)		-		-		-			(264	)		-			(264	)
- Dividends		-		-		-			-			(21,000	)		(21,000	)
- Net income		-		-		-			-			28,570			28,570

December 31, 2004	$	2,050	$	305	$	-		$	(541	)	$	104,606		$	106,420

- Allocation of unappropriated retained earnings, as approved by Shareholders’ meeting		39,239		1,538		37,701			-			(78,478	)		-
- Minimum pension liability (Note 10)		-		-		-			(593	)		-			(593	)
- Dividends		-		-		(17,000	)		-			(11,000	)		(28,000	)
- Net income		-		-		-			-			43,460			43,460
December 31, 2005	$	41,289	$	1,843	$	20,701		$	(1,134	)	$	58,588		$	121,287

- Allocation of unappropriated retained earnings, as approved by Shareholders’ meeting		-		2,174		41,312			-			(43,486	)		-
- Minimum pension liability adjustment (Note 10)		-		-		-			(613	)		-			(613	)
- Statement 158 transition adjustment (Note 10)		-		-		-			(115	)		-			(115	)
- Dividends		-		-		(38,000	)		-			-			(38,000	)
- Net income		-		-		-			-			54,871			54,871
December 31, 2006	$	41,289	$	4,017	$	24,013		$	(1,862	)	$	69,973		$	137,430

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

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

(stated in thousands of U.S. dollars)

	Year ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES

Net income	$	54,871		$	43,460		$	28,570

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation of property and equipment		18,598			16,206			12,962
Deferred income tax		611			(363	)		(44	)

Changes in assets and liabilities, net:
(Increase) decrease in assets:
Accounts receivable		(7	)		21			(413	)
Due from related parties		(368	)		(6,391	)		2,650
Inventories		(197	)		(284	)		(461	)
Other receivables		(60	)		90			122
Other assets		(355	)		15			(14	)
Increase (decrease) in liabilities:
Accounts payable and accrued liabilities		198			2,485			2,104
Due to related parties		143			68			5
Taxes payable and payroll		3,577			3,273			1,471
Other liabilities		(280	)		(372	)		1,437
Net cash provided by operating activities		76,731			58,208			48,389

CASH FLOWS FROM INVESTING ACTIVITIES

Purchase of property and equipment		(30,793	)		(30,117	)		(16,544	)

CASH FLOWS FROM FINANCING ACTIVITIES

Dividends paid		(38,000	)		(28,000	)		(21,000	)

Net increase in cash and cash equivalents		7,938			91			10,845

Cash and cash equivalents at beginning of year		18,733			18,642			7,797

Cash and cash equivalents at end of year	$	26,671		$	18,733		$	18,642

Supplemental cash flow information:
Interest paid	$	35		$	1,183		$	36
Income taxes paid	$	24,864		$	23,522		$	16,626

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

NOTES TO FINANCIAL STATEMENTS

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

1.	CORPORATE ORGANIZATION

Petrolera Entre Lomas S.A. is an Argentine corporation. As of December 31, 2006, 2005 and 2004 the shareholders of the Company and their participations were as follows:

Petrobras Energía S.A.	19.21	%
Apco Argentina Inc.	39.22	%
Apco Argentina S.A.	1.58	%
Petrobras Participacoes, S.L.	39.67	%
Other	0.32	%
	100.00	%

Apco Argentina S.A. is a wholly owned subsidiary of Apco Argentina Inc.

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, renegotiated in 1991 and 1994, permits the concessionaires to freely dispose of their crude oil and natural gas production and extends the concession term through January 21, 2016, with the option to extend the concession for an additional ten-year period with the consent of the government.

The partners’ interests in the Entre Lomas concession as of December 31, 2006, 2005 and 2004 were as follows:

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

2.	BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

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

The Company has only one business segment and is engaged exclusively in the oil and gas exploration, development and production in the Entre Lomas joint venture. 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 U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of 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.

Summary of significant accounting policies

Cash and cash equivalents

Cash and cash equivalents include highly liquid bank deposits of $26.7 million and $18.7 million of which $26.4 million and $18.7 million earned interest with an average rate of 5.20 and 4.00 percent in 2006 and 2005, respectively. The Company considers all investments with a maturity at three months or less when purchased to be cash equivalents.

Other receivables

Mainly includes obligatory saving receivable detailed in note 3.

Inventories

Includes hydrocarbons and material and spare parts, which were accounted for at the lower of cost or market. The cost is determined by the first-in, first-out method.

Other assets

Includes prepaid expenses.

As of December 31, 2005 also included listed government trading securities accounted for at fair value.

Property and Equipment

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

Asset life retirement obligations are also considered in the Property and Equipment account, as discussed below.

Late in 2005, the company drilled an exploratory well that was capitalized as of December 31, 2005 amounting $0.6 million. During the first quarter of 2006, the exploratory well that was in progress at the end of 2005 was completed and put on production.

As of December 31, 2006 there was no capitalized exploratory drilling costs for which the determination of proved reserves was pending.

Oil and gas properties are depreciated over their productive lives using the units 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%.

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, 2006, 2005 and 2004, the Company did not experience any impairment indicators.

Effective January 1, 2002, the Company early adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”. This Statement requires 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.

As part of the adoption of SFAS 143, an engineering analysis was obtained which projected through the last year of the Entre Lomas concession term the number of wells that would require plugging and abandoning and the estimated cost to abandon a well. The Company estimates that there is no probability that it will be required to plug and abandon those wells that will continue to be producing wells upon the termination of the concession. The estimated asset retirement obligation as of December 31, 2006 and 2005 totaled $2,343 and $2,417. The change in total asset retirement obligation from December 31, 2005 to December 31, 2006 mainly relates to changes in assumptions used for cessation of production by well.

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 Entre Lomas concession term and an estimated cost to plug and abandon a well as discussed with field service companies that would be expected to perform such services. 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.

Foreign currency translation

The financial statements have been translated into United States dollars in accordance with SFAS No. 52, Foreign Currency Translation, 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.

Income taxes

Revenue recognition

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

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

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

The price stability agreement was renewed until April 30, 2004. However, the decision to not renew the agreement does not terminate the obligation of refiners to reimburse producers for the balances that accumulated from January 2003 through April 2004 if and when the price of WTI falls below $28.50. As of December 31, 2006, the total price credit available to the Company from domestic refiners amounts to $6.7 million and will be recognized in revenues when the price of WTI falls below $28.50 and the Company continues to receive the $28.50 price until its respective price credits are collected. As of December 31, 2006 none of such amounts have been recognized in revenues.

Derivative instruments

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

Recently issued accounting pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (“Statement 158”). Statement 158 requires plan sponsors of defined benefit pension and other postretirement benefit plans (collectively, “postretirement benefit plans”) to recognize the funded status of their postretirement benefit plans in the statement of financial position, measure the fair value of plan assets and benefit obligations as of the date of the Company’s fiscal year end statement of financial position, and provide additional disclosures. On December 31, 2006, the Company adopted the recognition and disclosure provisions of Statement 158. The adoption of Statement 158 did not have material effect on the Company’s financial position at December 31, 2006 or results of operations for the year then ended. Statement 158 did not have an effect on the Company’s financial position at December 31, 2005. Statement 158's provisions regarding the change in the measurement date of postretirement benefit plans are not applicable as the Company already uses a measurement date of December 31 for its pension plan. See Note 8 for further discussion of the effect of adopting Statement 158 on the Company’s financial statements.

The FASB issued in September 2006 Statement No. 157 “Fair Value Measurements” which provides enhanced guidance for using fair value to measure assets and liabilities. The standard also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. The standard applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. The standard does not expand the use of fair value in any new circumstances. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.

In July 2006, the FASB issued Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109, Accounting for Income Taxes”, which creates a single model to address uncertainty in tax positions. FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. Regarding its disclosure requirements, FIN 48 includes a tabular rollforward of the beginning and ending aggregate unrecognized tax benefits as well as specific detail related to tax uncertainties for which it is reasonably possible the amount of unrecognized tax benefit will significantly increase or decrease within twelve months. FIN 48 applies to all tax positions related to income taxes subject to FASB Statement No. 109, “Accounting for Income Taxes”, (FAS 109) and is effective for fiscal years beginning after December 15, 2006. Differences between the amounts recognized in the statements of financial position prior to the adoption of FIN 48 and the amounts reported after adoption should be accounted for as a cumulative effect adjustment reported in the beginning balance of retained earnings.

Finally, it should be mentioned that the FASB ratified the consensuses reached by the Emerging Issues Task Force (EITF) at its June 15, 2006 meeting in connection with Issue No. 06-3, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net)”

The Task Force reached a consensus that Issue 06-3 was applicable to all taxes that are externally imposed on a revenue producing transaction between a seller and a customer. The Task Force also concluded that, for taxes within the scope of the issue, a company may adopt a policy of presenting taxes either gross within revenue or net. That is, it may include charges to customers for taxes within revenues and the charge for the taxes from the taxing authority within cost of sales, or, alternatively, it may net the charge to the customer and the charge from the taxing authority. If taxes subject to this Issue are significant, a company is required to disclose its accounting policy for presenting taxes and the amounts of such taxes that are recognized on a gross basis.

At the June 2006 meeting, the Task Force considered the comment letters received and clarified the scope of Issue 06-3 to include any tax assessed by a governmental authority that is imposed concurrent with a revenue producing transaction between a seller and a customer. The Task Force also clarified that the accounting policy to present taxes gross (included in revenues and costs) or net (excluded from revenues) should be based on the type of tax imposed such that similar taxes are presented in a consistent manner. The guidance in this consensus is effective for the first interim reporting period beginning after December 15, 2006, with early application of this guidance permitted. The required disclosures should be made for all periods presented. The consensus will not require a change in the presentation of taxes subject to its scope. If a company wishes to change its historical presentation for such taxes, such a change must be justified as preferable and would be subject to the requirements of FASB Statement No. 154, “Accounting Changes and Error Corrections”.

In the opinion of the Company’s management, the adoption of provisions of the accounting pronouncements described above will not have material effect on the Company’s financial position or result of operations.

3.	OBLIGATORY SAVINGS RECEIVABLE

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

After a lengthy process before the courts, the Company paid a $6.7 million obligatory 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, 2006, the dollar value of the Company’s deposit is $2.4 million. On June 27, 2006 the Company filed a request for reimbursement. As of the date of issuance of these financial statements, an official written response from the Argentine taxing authority (DGI) has not yet been received. The deposit is presented in the balance sheet within other current receivables.

4.	INCOME TAX

The Company accounts for income taxes under the liability method in accordance with SFAS No. 109 “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 provision for income taxes is comprised of:

	For the years ended
	2006			2005			2004

Current expense	$	(31,917	)	$	(26,903	)	$	(18,653	)

Deferred benefit (expense)	$	(611	)	$	363		$	44
	$	(32,528	)	$	(26,540	)	$	(18,609	)

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

	For the years ended
	2006			2005			2004

Pre-tax income	$	87,399		$	70,000		$	47,179

Statutory tax rate		35	%		35	%		35	%

	$	30,590		$	24,500		$	16,513

US dollar remeasurement effect		1,938			2,040			2,109

Tax adjustments and other		-			-			(13	)
Income tax provision	$	32,528		$	26,540		$	18,609

The deferred tax assets and liabilities at December 31, 2006 and 2005 are as follows:

	2006			2005
Deferred tax assets

Defined Benefit Pension Plan	$	1,167		$	854
Other, net		12			11
Total deferred tax assets	$	1,179		$	865

Deferred tax liabilities -- Property and equipment		(1,291	)		(366	)
Net deferred income tax asset (liability)	$	(112	)	$	499

Current deferred income tax asset (liability)		-			-
Noncurrent deferred income tax asset (liability)		(112	)		499
Net deferred income tax asset (liability)	$	(112	)	$	499

5.	PROPERTY AND EQUIPMENT

The capitalized cost of property and equipment and the related accumulated depreciation as of December 31, 2006 and 2005 were as follows:

	December 31,
	2006			2005

Wells and other oil and gas field equipment	$	271,211		$	243,556
Other property and equipment		12,545			9,407
		283,756			252,963

Less accumulated depreciation	$	(165,910	)	$	(147,312	)
Total	$	117,846		$	105,651

6.	RELATED PARTY TRANSACTIONS

As of December 31, 2006 and 2005, the balances from related parties transactions were as follows:

	As of December 31,
Accounts receivable	2006		2005

Petrobras Energía S.A.	$	16,757	$	16,389

Accounts payable

Petrobras Energía S.A.	$	303	$	204
Oleoductos del Valle S.A. (1)		174		130
	$	477	$	334

(1)

Affiliate of Petrobras Energía S.A.

For the years ended December 31, 2006, 2005 and 2004, revenues and expenses derived from related parties transactions were as follows:

	2006		2005		2004
Revenues from hydrocarbons sold

Petrobras Energía S.A. (1)	$	142,935	$	117,451	$	85,085

(1)

For the year ended December 31, 2004, includes $81,936, related to oil & gas sale revenues performed with EG3, which was merged with and into Petrobras Energía S.A. during the first quarter of 2005.

	2006		2005		2004
Expenses

Petrobras Energía S.A. (1)	$	823	$	981	$	799
Oleoductos del Valle S.A. (2)		2,817		1,617		1,399
	$	3,640	$	2,598	$	2,198

(1)

For the year ended December 31, 2004, includes $165 related to purchases and operating expenses performed with EG3, which was merged with and into Petrobras Energía S.A. during the first quarter of 2005.

(2)

Affiliate of Petrobras Energía S.A.

Director’s Compensation totaled $391, $360 and $339 for the years ended December 31, 2006, 2005 and 2004, respectively.

7.	MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK

Major Customers

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

	% for the Years Ended December 31,
	2006		2005		2004

Petrobras Energía S.A. (1)		92.0		92.4		90.6

(1)

For the year ended December 31, 2004, relates to oil & gas sale revenues performed with EG3, which was merged with and into Petrobras Energía S.A. during the first quarter of 2005.

Management believes that the credit risk imposed by this concentration is offset by the creditworthiness of the Company’s customer and that upon expiration, the oil sales contracts of this customer 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, while no contribution is required from employees. The Company invests in high liquidity, low risk investments with minimal or no risk of loss of capital.

The fund's assets have been contributed to a trust and are mainly invested on money market-mutual funds at December 31, 2006. The Bank of New York is the trustee and Watson Wyatt is the servicing agent.

The plan was amended in 1999, resulting in an increase of benefits to the employees. According with the provisions of SFAS 87 the Company capitalized the effect of the amendment amortizing such asset according to the future service period of those employees active at the date of the amendment who are expected to receive benefits under the plan.

The incremental effects of adopting the provisions of Statement 158 on the Company’s statement of financial position as of December 31, 2006 are presented in the following table. The adoption of Statement 158 had no effect on the Company’s statement of income for the year ended December 31, 2006, or for any prior period presented, and it will not effect the Company’s operating results in future periods. Had the Company not been required to adopt Statement 158 at December 31, 2006, it would have recognized an additional minimum liability pursuant to the provisions of Statement 87. The effect of recognizing the additional minimum liability is included in table below in the column labeled “Prior to Application of Statement 158”.

	As of December 31, 2006
	Prior to adopting Statement 158		Effect of adopting Statement 158			As reported at December 31, 2006

Intangible asset		131		131			-
Accrued pension liability		3,285		(46	)		3,332
Deferred income taxes		144		62			82
Acumulated other comprehensive loss		2,749		115			2,864

	2006			2005

Projected benefit obligation	$	6,565		$	5,300

Accumulated benefit obligation	$	6,518		$	5,201

Fair value of plan assets at year end	$	3,233		$	2,808

Funded status of the plan (underfunded)	$	(3,332	)	$	(2,492	)

Amounts recognized in the statement of financial position consist of:

Accrued benefit cost	$	(3,332	)	$	(2,393	)

Intangible assets		-			154

Accumulated other comprehensive income	$	2,864			1,745

Net amount recognized	$	(468	)	$	(494	)

Included in accumulated other comprehensive income as of December 31, 2006 are the following amounts that have not yet been recognized in net periodic cost: unrecognized prior service cost of $131 and unrecognized actuarial losses of $2,733. The prior service cost and actuarial loss included in accumulated other comprehensive income and expected to be recognized in net periodic pension cost during 2007 is $17 and $149, respectively.

Net Periodic Benefit Cost	$	581		$	391

Employer contributions	$	607		$	351

Benefit paid	$	311		$	205

Pension liability adjustment included in other comprehensive income, net of tax	$	728		$	593

Asset Categories

Money market - mutual funds		100	%		100	%
Total		100	%		100	%

Assumptions used to determine the benefit obligation and the net benefit cost:

Discount rate	6	%	6	%

Expected long-term rates of return on plan assets	5	%	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 money market-mutual funds.

Contributions

The Company expects to contribute $614 to its pension plan in 2007.

Estimated Future Benefit Payment

The following benefit payments are expected to be paid.

Year	Benefit

2007	$	390
2008	$	392
2009	$	411
2010	$	426
2011	$	425
2012-2016	$	2,363

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

9.	TAXES PAYABLE AND PAYROLL ACCOUNT AND NON-CURRENT OTHER LIABILITIES

At December 31, 2006 and 2005, taxes payable and payroll account consisted of the following:

	2006		2005

Income tax accrual	$	13,085	$	10,613
Provincial production taxes		2,000		1,394
Payroll		793		641
Other		979		632
	$	16,857	$	13,280

At December 31, 2006 and 2005, non-current other liabilities consisted of the following:

	2006		2005

Liability for pension benefit	$	3,332	$	2,336
Asset retirement liability		2,274		2,348
Deferred tax		112		-
	$	5,718	$	4,684

10.

COMPREHENSIVE INCOME

Comprehensive income is as follows:

	For the years ended December 31,
	2006			2005			2004

Net income	$	54,871		$	43,460		$	28,570

Other comprehensive loss:
- Pension liability adjustment		(943	)		(913	)		(406	)
- Statement 158 transition adjustment		(177	)		-			-
- Income tax benefit on other comprehensive loss		392			320			142
Other comprehensive loss		(728	)		(593	)		(264	)
Comprehensive income	$	54,143		$	42,867		$	28,306

11.

RESTRICTIONS ON RETAINED EARNINGS

According to effective legal regulations, 5% of net income of the year must be appropriated to increase the legal reserve until reaching 20% of capital stock.

In addition, 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.

12.

CAPITAL INCREASE AND AMENDMENT TO BYLAWS

The Regular and Special Shareholders’ Meeting held on March 15, 2005, approved the amendment to section 4 of the bylaws to increase capital stock from 500,000 to 115,857,699, represented by 95,443,572 shares of common stock and 20,414,127 shares of preferred stock with a face value of 1 per share.

In addition, to adjust bylaws to the provisions of General Resolution No. 1/2005, the shareholders’ meeting mentioned in the previous paragraph approved the amendment to section 9 of the bylaws to extend to three years the term to require directors’ guarantees, as from the time in which they cease holding office.

On May 9, 2006, the amendment to bylaws regarding the increase in capital stock and the extension of the term of directors’ guarantees was registered with the Public Registry of Commerce. The shares representing the total capital stock were issued and delivered to shareholders proportionately to their respective shareholdings, this abrogating the securities previously outstanding.

13.

CONTINGENCIES

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

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

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

During 2004, the Company received notices from the Neuquén and Río Negro Provinces alleging incorrect computation of the provincial production taxes determined for such Provinces. As of December 31, 2004, the Company accrued as current liabilities the amounts that it considered were probable to be paid for these claims by $1.3 million.

After several negotiations, in June and July 2005 the Company paid the total amount claimed by the provincial authorities for $1.3 million.

As of December 31, 2006 the Company has accrued as current liabilities $0.7 million that it considered are probable to be paid in connection with claims related to Río Negro provincial taxes.

14.

SUBSEQUENT EVENT

Subsequent to year-end, the Board of Directors meeting of January 23, 2007, established the distribution of $1 million cash dividends.